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TABLE OF CONTENTS
INDEX TO FINANCIAL STATEMENTS
As filed with the Securities and Exchange Commission on January 6, 2017
Registration No. 333-
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM S-1
REGISTRATION STATEMENT
UNDER
THE SECURITIES ACT OF 1933
Kimbell Royalty Partners, LP
(Exact name of registrant as specified in its charter)
|
Delaware
(State or other jurisdiction of incorporation or organization) |
1311
(Primary Standard Industrial Classification Code Number) |
47-5505475
(I.R.S. Employer Identification No.) |
777 Taylor Street, Suite 810
Fort Worth, Texas 76102
(817) 945-9700
(Address, including zip code, and telephone number, including area code, of registrant's principal executive offices)
R. Davis Ravnaas
President and Chief Financial Officer
Kimbell Royalty Partners, LP
777 Taylor Street, Suite 810
Fort Worth, Texas 76102
(817) 945-9700
(Name, address, including zip code, and telephone number, including area code, of agent for service)
Approximate date of commencement of proposed sale to the public:
As soon as practicable after this registration statement becomes effective.
If any of the securities being registered on this Form are to be offered on a delayed or continuous basis pursuant to Rule 415 under the Securities Act of 1933, check the following box. o
If this Form is filed to register additional securities for an offering pursuant to Rule 462(b) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. o
If this Form is a post-effective amendment filed pursuant to Rule 462(c) under the Securities Act, please check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. o
If this Form is a post-effective amendment filed pursuant to Rule 462(d) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. o
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of "large accelerated filer," "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act.
| Large accelerated filer o | Accelerated filer o |
Non-accelerated filer
ý
(Do not check if a smaller reporting company) |
Smaller reporting company o |
CALCULATION OF REGISTRATION FEE
|
|
||||
|
Title of Each Class of Securities
to be Registered |
Proposed Maximum
Aggregate Offering Price (1)(2) |
Amount of
Registration Fee |
||
|---|---|---|---|---|
|
Common units representing limited partner interests |
$100,000,000 | $11,590.00 | ||
|
|
||||
- (1)
-
Includes
common units issuable upon exercise of the underwriters' option to purchase additional common units.
- (2)
- Estimated solely for the purpose of calculating the registration fee pursuant to Rule 457(o).
The registrant hereby amends this registration statement on such date or dates as may be necessary to delay its effective date until the registrant shall file a further amendment which specifically states that this registration statement shall thereafter become effective in accordance with Section 8(a) of the Securities Act of 1933 or until the registration statement shall become effective on such date as the Securities and Exchange Commission, acting pursuant to said Section 8(a), may determine.
The information in this prospectus is not complete and may be changed. We may not sell these securities until the registration statement filed with the Securities and Exchange Commission is effective. The prospectus is not an offer to sell these securities nor a solicitation of an offer to buy these securities in any jurisdiction where the offer and sale is not permitted.
Subject to Completion, dated January 6, 2017
PROSPECTUS
Kimbell Royalty Partners, LP
Common Units
Representing Limited Partner Interests
This is the initial public offering of our common units representing limited partner interests. We are offering common units in this offering. Prior to this offering, there has been no public market for our common units. We currently expect the initial public offering price to be between $ and $ per common unit. We have been approved to list our common units on the New York Stock Exchange, subject to official notice of issuance, under the symbol "KRP." We are an "emerging growth company" as that term is used in the Jumpstart Our Business Startups Act.
Investing in our common units involves a high degree of risk. Before buying any common units, you should carefully read the discussion of material risks of investing in our common units in "Risk Factors" beginning on page 31. These risks include the following:
- •
-
We may not have sufficient available cash to pay any quarterly distribution on our common units.
- •
-
The amount of our quarterly cash distributions, if any, may vary significantly both quarterly and annually and
will be directly dependent on the performance of our business. We will not have a minimum quarterly distribution or employ structures intended to consistently maintain or increase distributions over
time and could pay no distribution with respect to any particular quarter.
- •
-
All of our revenues are derived from royalty payments that are based on the price at which oil, natural gas and
natural gas liquids produced from the acreage underlying our interests is sold, and we do not currently hedge these commodity prices. The volatility of these prices due to factors beyond our control
greatly affects our business, financial condition, results of operations and cash available for distribution.
- •
-
We depend on unaffiliated operators for all of the exploration, development and production on the properties in
which we own mineral and royalty interests. Substantially all of our revenue is derived from royalty payments made by these operators. A reduction in the expected number of wells to be drilled on the
acreage underlying our interests by these operators or the failure of these operators to adequately and efficiently develop and operate the underlying acreage could materially adversely affect our
results of operations and cash available for distribution.
- •
-
We do not intend to retain cash from our operations for replacement capital expenditures. Unless we replenish
our oil and natural gas reserves, our cash generated from operations and our ability to pay distributions to our unitholders could be materially adversely
affected.
- •
-
Our general partner and its affiliates, including our Sponsors and their respective affiliates, have conflicts
of interest with us and limited duties to us and our unitholders, and they may favor their own interests to the detriment of us and our unitholders. Additionally, we have no control over the business
decisions and operations of our Sponsors and their respective affiliates, which are under no obligation to adopt a business strategy that favors us.
- •
-
Neither we, our general partner nor our subsidiaries have any employees, and we rely solely on Kimbell Operating
Company, LLC to manage and operate, or arrange for the management and operation of, our business. The management team of Kimbell Operating Company, LLC, which includes the individuals
who will manage us, will also provide substantially similar services to other entities and thus will not be solely focused on our business.
- •
-
Our partnership agreement replaces fiduciary duties applicable to a corporation with contractual duties and
restricts the remedies available to holders of our common units for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty.
- •
-
Holders of our common units have limited voting rights and are not entitled to elect our general partner or its
directors.
- •
-
Our tax treatment depends on our status as a partnership for federal income tax purposes, as well as our not
being subject to a material amount of entity-level taxation by individual states. If the Internal Revenue Service were to treat us as a corporation for federal income tax purposes or we were to become
subject to entity-level taxation for state tax purposes, then our cash available for distribution to you could be substantially reduced.
- •
- Even if you do not receive any cash distributions from us, you will be required to pay taxes on your share of our taxable income.
Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved of these securities or determined if this prospectus is truthful or complete. Any representation to the contrary is a criminal offense.
|
|
Per
Common Unit |
Total | |||||
|---|---|---|---|---|---|---|---|
|
Initial public offering price |
$ | $ | |||||
|
Underwriting discount (1) |
$ | $ | |||||
|
Proceeds to Kimbell Royalty Partners, LP (before expenses) |
$ | $ | |||||
- (1)
- Excludes an aggregate structuring fee equal to % of the gross proceeds of this offering payable to Raymond James & Associates, Inc. Please read "Underwriting."
The underwriters may purchase up to an additional common units from us at the public offering price, less the underwriting discount, within 30 days from the date of this prospectus solely to cover over-allotments.
The underwriters expect to deliver the common units to purchasers on or about , 2017 through the book-entry facilities of The Depository Trust Company.
Joint Book-Running Managers
| RAYMOND JAMES | RBC CAPITAL MARKETS | STIFEL |
Co-Managers
| STEPHENS INC. | WUNDERLICH |
Prospectus dated , 2017
i
ii
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We and the underwriters have not authorized anyone to provide any information or to make any representations other than those contained in this prospectus or in any free writing prospectuses we have prepared. We and the underwriters take no responsibility for, and can provide no assurance as to the reliability of, any other information that others may give you. Neither the delivery of this prospectus nor sale of our common units means that information contained in this prospectus is correct after the date of this prospectus. This prospectus is not an offer to sell or solicitation of an offer to buy our common units in any circumstances under which the offer or solicitation is unlawful.
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PRESENTATION OF FINANCIAL AND OPERATING DATA
Unless otherwise indicated, the historical financial information presented in this prospectus is that of our predecessor, Rivercrest Royalties, LLC. The pro forma financial information in this prospectus is derived from the unaudited condensed combined pro forma financial statements included elsewhere in this prospectus which reflect, among other things, the financial statements of our predecessor and the acquisition of assets to be contributed to us by the Kimbell Art Foundation, Trunk Bay Royalty Partners, Ltd., Oil Nut Bay Royalties, LP, Gorda Sound Royalties, LP and Bitter End Royalties, LP, RCPTX, Ltd., and French Capital Partners, Ltd., which make up a portion of the Contributing Parties. Please read the unaudited condensed combined pro forma financial statements included elsewhere in this prospectus.
In addition, unless otherwise indicated, the reserve and operational data presented in this prospectus is with respect to all the assets that will be contributed to us by the Contributing Parties. Please read "Summary—Formation Transactions."
This prospectus includes industry data and forecasts that we obtained from internal company sources, publicly available information and industry publications and surveys. Our internal research and forecasts are based on management's understanding of industry conditions, and such information has not been verified by independent sources. Industry publications, surveys and forecasts generally state that the information contained therein has been obtained from sources believed to be reliable. There can be no assurance as to the accuracy or completeness of the information presented herein derived from third party sources. Statements as to the industry or operator estimates and future activity are based on independent industry publications, government publications, third-party forecasts, public statements by the operators of our properties, management's estimates and assumptions about our markets and our internal research. While we are not aware of any misstatements regarding such estimates or the market, industry, or similar data presented herein, such estimates and data involve risks and uncertainties and are subject to change based on various factors, including those discussed under the headings "Risk Factors" and "Forward-Looking Statements" in this prospectus, most of which are not within our control.
v
This summary highlights selected information contained elsewhere in this prospectus. It does not contain all the information you should consider before investing in our common units. You should carefully read the entire prospectus, including "Risk Factors" and the historical and unaudited pro forma condensed combined financial statements and related notes included elsewhere in this prospectus, before making an investment decision. The information presented in this prospectus assumes an initial public offering price of $ per common unit (the mid-point of the price range set forth on the cover page of this prospectus), and unless otherwise indicated, that the underwriters do not exercise their option to purchase additional common units.
Unless the context otherwise requires, references in this prospectus to "Kimbell Royalty Partners, LP," "our partnership," "we," "our," "us" or like terms refer to Kimbell Royalty Partners, LP and its subsidiaries. References to "our general partner" refer to Kimbell Royalty GP, LLC. References to "our Sponsors" refer to affiliates of our founders, Ben J. Fortson, Robert D. Ravnaas, Brett G. Taylor and Mitch S. Wynne, respectively. References to "Kimbell Holdings" refer to Kimbell GP Holdings, LLC, a jointly owned subsidiary of our Sponsors and the parent of our general partner. References to the "Contributing Parties" refer to all entities and individuals, including affiliates of our Sponsors, that are contributing, directly or indirectly, certain mineral and royalty interests to us. References to "our predecessor" refer to Rivercrest Royalties, LLC, our predecessor for accounting purposes. References to "Kimbell Operating" refer to Kimbell Operating Company, LLC, a wholly owned subsidiary of our general partner, which will enter into separate service agreements with certain entities controlled by Benny D. Duncan and Messrs. R. Ravnaas, Taylor and Wynne as described herein.
We are a Delaware limited partnership formed to own and acquire mineral and royalty interests in oil and natural gas properties throughout the United States. As an owner of mineral and royalty interests, we are entitled to a portion of the revenues received from the production of oil, natural gas and associated natural gas liquids from the acreage underlying our interests, net of post-production expenses and taxes. We are not obligated to fund drilling and completion costs, lease operating expenses or plugging and abandonment costs at the end of a well's productive life. Our primary business objective is to provide increasing cash distributions to unitholders resulting from acquisitions from our Sponsors, the Contributing Parties and third parties and from organic growth through the continued development by working interest owners of the properties in which we own an interest.
As of December 31, 2015, we owned mineral and royalty interests in approximately 3.7 million gross acres and overriding royalty interests in approximately 0.9 million gross acres, with approximately 44% of our aggregate acres located in the Permian Basin. We refer to these non-cost-bearing interests collectively as our "mineral and royalty interests." As of December 31, 2015, over 95% of the acreage subject to our mineral and royalty interests was leased to working interest owners (including 100% of our overriding royalty interests), and substantially all of those leases were held by production. Our mineral and royalty interests are located in 20 states and in nearly every major onshore basin across the continental United States and include ownership in over 48,000 gross producing wells, including over 29,000 wells in the Permian Basin. For the six months ended June 30, 2016, approximately 52.6% of our production was from the Permian Basin, Eagle Ford, Terryville/Cotton Valley/Haynesville and the Bakken/Williston Basin, which are some of the most active areas in the country. The geographic breadth
1
of our assets gives us exposure to potential production and reserves from new and existing plays. Over the long term, we expect working interest owners will continue to develop our acreage through infill drilling, horizontal drilling, hydraulic fracturing, recompletions and secondary and tertiary recovery methods. As an owner of mineral and royalty interests, we benefit from the continued development of the properties in which we own an interest without the need for investment of additional capital by us.
Certain members of our management team have completed over 160 acquisitions of mineral and royalty interests and have significant experience in identifying, evaluating and completing strategic acquisitions. Mr. R. Ravnaas, our Chief Executive Officer, and our directors Messrs. Fortson, Taylor and Wynne, who we refer to collectively as our founders, began actively acquiring mineral and royalty interests in 1998 when they began to jointly acquire mineral and royalty interests in conventional onshore U.S. basins. They initially focused on mineral and royalty interests in the Permian Basin, and later expanded their acquisition efforts to several other basins. Beginning in 2000, this group expanded to include nearly all the Contributing Parties. Our founders have focused on acquiring properties characterized by long-life, shallow decline production and significant oil and natural gas reserves.
For the 15-year period ended December 31, 2015, the net oil and net natural gas production from our assets, including acquisitions, has grown at a compound annual growth rate of 16.8% and 19.2%, respectively. The chart below shows the compound annual growth rate of production from our mineral and royalty interests for such period:
Net Production Growth (Including Acquisitions) (2001-2015)
Note: Net oil and net natural gas production information was gathered from state reporting records. Natural gas liquids, which are not reported by the states, are excluded from the chart.
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For the 15-year period ended December 31, 2015, the net oil and net natural gas production from our assets has grown organically (assuming we had acquired all of our interests on January 1, 2001 and made no additional acquisitions) at a compound annual growth rate of 3.2% and 1.0%, respectively. The chart below shows the compound annual growth rate attributable to our combined mineral and royalty interests as if we had acquired all of such interests on January 1, 2001 and made no additional acquisitions.
Organic Net Production Growth (2001-2015)
Note: Net oil and net natural gas production information was gathered from state reporting records. Natural gas liquids, which are not reported by the states, are excluded from the chart.
As of December 31, 2015, the estimated proved oil, natural gas and natural gas liquids reserves attributable to our interests in our underlying acreage were 18,120 MBoe (52.4% liquids, consisting of 79.7% oil and 20.3% natural gas liquids) based on a reserve report prepared by Ryder Scott Company, L.P., an independent petroleum engineering firm ("Ryder Scott"). Of these reserves, 70.4% were classified as proved developed producing ("PDP") reserves, 0.8% were classified as proved developed non-producing ("PDNP") reserves and 28.8% were classified as proved undeveloped ("PUD") reserves. The properties underlying our mineral and royalty interests typically have low estimated decline rates. Our PDP reserves have an average estimated initial five-year decline rate of 10%. PUD reserves included in this estimate are from 759 gross proved undeveloped locations. For the six months ended June 30, 2016, our average daily net production was 3,317 Boe/d.
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For the year ended December 31, 2015, on a pro forma basis, our revenues were derived 63.0% from oil sales, 30.0% from natural gas sales and 7.0% from natural gas liquid sales. Our revenues are derived from royalty payments we receive from the operators of our properties based on the sale of oil and natural gas production, as well as the sale of natural gas liquids that are extracted from natural gas during processing. As of December 31, 2015, we had over 700 operators on our acreage, with our top ten operators (Occidental Permian Ltd., Newfield Exploration Company, Range Resources Corporation/Memorial Resource Development Corp., Aera Energy LLC (a joint venture of Royal Dutch Shell plc and ExxonMobil Corporation), XTO Energy, Inc., Jonah Energy LLC, Campbell Development Group, LLC, EOG Resources, Inc., Chesapeake Energy Corporation and Devon Energy Corporation) together accounting for approximately 46.9% of our combined discounted future net income (discounted at 10%). Our revenues may vary significantly from period to period as a result of changes in volumes of production sold or changes in commodity prices. Oil, natural gas and natural gas liquids prices have historically been volatile, and we do not currently hedge our exposure to changes in commodity prices.
We believe that one of our key strengths is our management team's extensive experience in acquiring and managing mineral and royalty interests. Our management team and board of directors, which includes our founders, have a long history of creating value. We expect our business model to allow us to integrate significant acquisitions into our existing organizational structure quickly and cost-efficiently. In particular, Messrs. R. Ravnaas, Taylor and Wynne average over 30 years sourcing, engineering, evaluating, acquiring and managing mineral and royalty interests. In connection with this offering, we will enter into a management services agreement with Kimbell Operating, which will enter into separate service agreements with certain entities controlled by Messrs. R. Ravnaas, Taylor and Wynne, pursuant to which they will identify, evaluate and recommend to us acquisition opportunities and negotiate the terms of such acquisitions. Please read "Certain Relationships and Related Party Transactions—Agreements and Transactions with Affiliates in Connection with this Offering—Management Services Agreements."
Upon completion of this offering, our Sponsors will indirectly own and control our general partner, and the Contributing Parties will own an aggregate of approximately % of our outstanding common units (excluding any common units purchased by officers and directors of our general partner under our directed unit program). The Contributing Parties, including affiliates of our Sponsors, will retain a diverse portfolio of mineral and royalty interests with production and reserve characteristics similar to the assets we will own at the closing of this offering. In connection with this offering and pursuant to the contribution agreement that we have entered into with our Sponsors and the Contributing Parties, certain of the Contributing Parties have granted us a right of first offer for a period of three years after the closing of this offering with respect to certain mineral and royalty interests in the Permian Basin, the Bakken/Williston Basin and the Marcellus Shale. We believe the Contributing Parties, including affiliates of our Sponsors, will be incentivized through their direct or indirect ownership of common units to offer us the opportunity to acquire additional mineral and royalty interests from them in the future. Such Contributing Parties, however, have no obligation to sell any assets to us or to accept any offer that we may make for such assets, and we may decide not to acquire such assets even if such Contributing Parties offer them to us. In addition, under the contribution agreement, we have a right to participate, at our option and on substantially the same or better terms, in up to 50% of any acquisitions, other than de minimis acquisitions, for which Messrs. R. Ravnaas, Taylor and Wynne provide, directly or indirectly, any oil and gas diligence, reserve engineering or other business services. Please read "Certain Relationships and Related Party
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Transactions—Agreements and Transactions with Affiliates in Connection with this Offering—Contribution Agreement."
We categorize our assets into two groups: mineral interests and overriding royalty interests.
Mineral Interests
Mineral interests are real property interests that are typically perpetual and grant ownership to all of the oil and natural gas lying below the surface of the property, as well as the right to explore, drill and produce oil and natural gas on that property or to lease such rights to a third party. Mineral owners typically grant oil and gas leases to operators for an initial three-year term with an upfront cash payment to the mineral owners known as a lease bonus. Under the lease, the mineral owner retains a royalty interest entitling it to a cost-free percentage (usually ranging from 20-25%) of production or revenue from production. The lease can be extended beyond the initial term with continuous drilling, production or other operating activities. When production or drilling ceases on the leased property, the lease is typically terminated, subject to certain exceptions, and all mineral rights revert back to the mineral owner who can then lease the exploration and development rights to another party. We also own royalty interests that have been carved out of mineral interests and are known as nonparticipating royalty interests. Nonparticipating royalty interests are typically perpetual and have rights similar to mineral interests, including the right to a cost-free percentage of production revenues for minerals extracted from the acreage, without the associated executive right to lease and the right to receive lease bonuses.
We combine our mineral and nonparticipating royalty assets into one category because they share many of the same characteristics due to the nature of the underlying interest. For example, we receive similar royalties from operators with respect to our mineral interests or nonparticipating royalty interests as long as such interests are subject to an oil and gas lease. As of December 31, 2015, over 95% of the acreage subject to our mineral and nonparticipating royalty interests was leased. When evaluating our business, our management team does not distinguish between mineral and nonparticipating royalty interests on leased acreage due to the similarity of the royalties received by the interests.
Overriding Royalty Interests
In addition to mineral interests, we also own overriding royalty interests, which are royalty interests that burden the working interests of a lease and represent the right to receive a fixed, cost-free percentage of production or revenue from production from a lease. Overriding royalty interests, or ORRIs, typically remain in effect until the associated lease expires, and because substantially all of the underlying leases are perpetual so long as production in paying quantities perpetuates the leasehold, substantially all of our overriding royalty interests are likewise perpetual.
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The following table summarizes our ownership in U.S. basins and producing regions:
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Gross Acreage as of
December 31, 2015 |
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|---|---|---|---|---|---|---|---|---|---|---|
|
|
Average Daily
Production for Six Months Ended June 30, 2016 (2) (Boe/d) |
|||||||||
| Basin or Producing Region |
Mineral
Interests (1) |
ORRIs | ||||||||
|
Permian Basin (3) |
1,764,954 | 232,723 | 934 | |||||||
|
Mid-Continent |
336,481 | 139,513 | 200 | |||||||
|
Terryville/Cotton Valley/Haynesville |
261,762 | 41,812 | 267 | |||||||
|
Eagle Ford |
180,367 | 72,970 | 469 | |||||||
|
Barnett Shale/Fort Worth Basin (4) |
216,367 | 54,888 | 422 | |||||||
|
Bakken/Williston Basin (5) |
82,704 | 31,554 | 73 | |||||||
|
San Juan Basin |
28,852 | 47,233 | 229 | |||||||
|
Onshore California |
7,666 | 9,286 | 109 | |||||||
|
DJ Basin/Rockies/Niobrara |
3,967 | 3,182 | 360 | |||||||
|
Illinois Basin |
6,351 | 13,304 | 52 | |||||||
|
Other Western (onshore) Gulf Basin |
539,625 | 71,435 | 158 | |||||||
|
Other TX/LA/MS Salt Basin |
144,186 | 22,616 | 9 | |||||||
|
Other |
93,857 | 133,093 | 33 | |||||||
| | | | | | | | | | | |
|
Total |
3,667,139 | 873,609 | 3,317 | |||||||
| | | | | | | | | | | |
| | | | | | | | | | | |
| | | | | | | | | | | |
- (1)
-
Includes
both mineral and nonparticipating royalty interests.
- (2)
-
"Btu-equivalent"
production volumes are presented on an oil-equivalent basis using a conversion factor of six Mcf of natural gas per barrel of "oil
equivalent," which is based on approximate energy equivalency and does not reflect the price or value relationship between oil and natural gas. Please read "Business—Oil and Natural Gas
Data—Proved Reserves—Summary of Estimated Proved Reserves."
- (3)
-
Includes
mineral interests and overriding royalty interests in approximately 740,244 gross acres and 149,173 gross acres, respectively, in the Wolfcamp/Bone
Spring.
- (4)
-
Includes
mineral interests and overriding royalty interests in approximately 198,229 gross acres and 50,217 gross acres, respectively, in the Barnett Shale.
- (5)
- Includes mineral interests and overriding royalty interests in approximately 74,504 gross acres and 29,813 gross acres, respectively, in the Bakken/Three Forks.
- •
- Permian Basin. The Permian Basin extends from southeastern New Mexico into west Texas and is currently one of the most active drilling regions in the United States. It includes three geologic provinces: the Midland Basin to the east, the Delaware Basin to the west, and the Central Basin in between. The Permian Basin consists of mature legacy onshore oil and liquids-rich natural gas reservoirs and has been actively drilled over the past 90 years. The extensive operating history, favorable operating environment, mature infrastructure, long reserve life, multiple producing horizons, horizontal development potential and liquids-rich reserves make the Permian Basin one of the most prolific oil-producing regions in the United States. Our acreage underlies prospective areas for the Wolfcamp play in the Midland and Delaware Basins, the Spraberry formation in the Midland Basin, and the Bone Springs formation in the Delaware Basin, which are among the most active plays in the country.
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- •
-
Mid-Continent.
The Mid-Continent is a broad area containing hundreds of fields in
Arkansas, Kansas, Louisiana, New Mexico, Oklahoma, Nebraska and Texas and including the Granite Wash, Cleveland and the Mississippi Lime formations. The Anadarko Basin is a structural basin centered
in the western part of Oklahoma and the Texas Panhandle, extending into southwestern Kansas and southeastern Colorado. A key feature of the Anadarko Basin is the stacked geologic horizons including
the Cana-Woodford and Springer shale in the SCOOP and STACK.
- •
-
Terryville/Cotton
Valley/Haynesville.
We own a substantial position in the core of the Terryville Field. Our mineral interests are leased and operated by
Range Resources Corporation/Memorial Resource Development Corp. Producing since 1954, the Terryville Field is one of the most prolific natural gas fields in North America. Redevelopment of the field
with horizontal drilling and modern completion techniques has resulted in high recoveries relative to drilling and completion costs, high initial production rates with high liquids yields, and long
reserve life with multiple stacked producing zones.
- •
-
Eagle
Ford.
The Eagle Ford shale formation stretches across South Texas and includes some of the most economic and productive areas in the
United States. The Eagle Ford contains significant amounts of hydrocarbons and is considered the source rock, or the original source, for much of the oil and natural gas contained in the Austin Chalk
Basin. The Eagle Ford shale formation has benefitted from improvements in horizontal drilling and hydraulic fracturing.
- •
-
Barnett Shale/Fort Worth
Basin.
The Fort Worth Basin is a major petroleum producing geological system that is primarily located in north central Texas and
southwestern Oklahoma. This area is best known for the Barnett Shale, which was one of the first shale plays to utilize horizontal drilling and hydraulic fracturing, and is one of the most productive
sources of shale gas. In addition to the Barnett Shale, this area is also known for the Marble Falls, Mississippi Lime, Bend Conglomerate and Caddo plays.
- •
-
Bakken/Williston
Basin.
The Williston Basin stretches through North Dakota, the northwest part of South Dakota, and eastern Montana and is best known for
the Bakken/Three Forks shale formations. The Bakken ranks as one of the largest oil developments in the United States in the past 40 years. Development of the Bakken became commercial on a
large scale over the past ten years with the advent of horizontal drilling and hydraulic fracturing.
- •
-
San Juan
Basin.
The San Juan Basin is located in the Four Corners region of the southwestern United States, stretching over 4,600 square miles
and encompassing much of northwestern New Mexico, southwestern Colorado and parts of Arizona and Utah. Most gas production in the basin comes from the Fruitland Coalbed Methane Play, with the
remainder derived from the Mesaverde and Dakota tight gas plays. The San Juan Basin is the most productive coalbed methane basin in North America.
- •
-
Onshore
California.
The majority of our mineral and royalty interests in California are in the Ventura Basin. The Ventura Basin has been active
since the early 1900s and is one of the largest oil fields in California. The Ventura Basin contains multiple stacked formations throughout its depths, and a considerable inventory of existing
re-development opportunities, as well as new play discovery potential.
- •
- DJ Basin/Rockies/Niobrara. The Denver-Julesburg Basin, also known as the DJ Basin, is a geologic basin centered in eastern Colorado stretching into southeast Wyoming, western
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- •
-
Illinois
Basin.
The Illinois Basin extends across most of Illinois, Indiana, Kentucky and parts of Tennessee. The Illinois Basin is a mature area
dominated by conventional oil production with some coalbed methane production. The Bridgeport, Cypress, Aux Vasses, Ste. Genevieve, Ullin, Fort Payne and New Albany are some of the formations with a
current commercial focus in the Illinois Basin.
- •
- Other. Our other assets are primarily located in the Western Gulf (onshore) Basin and the Louisiana-Mississippi Salt Basins. The Western Gulf region ranges from South Texas through southeastern Louisiana and includes a variety of conventional and unconventional plays. The Louisiana-Mississippi Salt Basins range from northern Louisiana and southern Arkansas through south central Mississippi, southern Alabama and the Florida Panhandle.
Nebraska and western Kansas. The area includes the Wattenberg Gas Field, one of the largest natural gas deposits in the United States, and the Niobrara formation. The Niobrara includes three separate zones and stretches from the DJ Basin up into the Powder River Basin in Wyoming. Development in this area is currently focused on horizontal drilling in the Niobrara and Codell formations.
Our primary business objective is to provide increasing cash distributions to unitholders resulting from acquisitions from our Sponsors, the Contributing Parties and third parties and from organic growth through the continued development by working interest owners of the properties in which we own an interest. We intend to accomplish this objective by executing the following strategies:
- •
-
Acquire additional mineral and royalty interests from our Sponsors and
the Contributing Parties.
Following the completion of this offering, the Contributing Parties, including affiliates of our Sponsors,
will continue to own significant mineral and royalty interests in oil and gas properties. We believe our Sponsors and the Contributing Parties view our partnership as part of their growth strategy. In
addition, we believe their direct or indirect ownership in us will incentivize them to offer us additional mineral and royalty interests from their existing asset portfolios in the future. In
connection with this offering and pursuant to the contribution agreement, certain of the Contributing Parties have granted us a right of first offer for a period of three years after the closing of
this offering with respect to certain mineral and royalty interests in the Permian Basin, the Bakken/Williston Basin and the Marcellus Shale. These mineral and royalty interests include ownership in
over 4,000 gross producing wells in 10 states. Such Contributing Parties, however, have no obligation to sell any assets to us or to accept any offer that we may make for such assets, and we may
decide not to acquire such assets even if such Contributing Parties offer them to us. Please read "Certain Relationships and Related Party Transactions—Agreements and Transactions with
Affiliates in Connection with this Offering—Contribution Agreement."
- •
- Acquire additional mineral and royalty interests from third parties and leverage our relationships with our Sponsors and the Contributing Parties to grow our business. We intend to make opportunistic acquisitions of mineral and royalty interests that have substantial resource and organic growth potential and meet our acquisition criteria, which include (i) mineral and royalty interests in high-quality producing acreage that enhance our asset base, (ii) significant amounts of recoverable oil and natural gas in
8
- •
-
Benefit from reserve, production and cash flow growth through organic
production growth and development of our mineral and royalty interests to grow distributions.
Our initial assets consist of diversified
mineral and royalty interests. For the six months ended June 30, 2016, approximately 52.6% of our production was from the Permian Basin, Eagle Ford, Terryville/Cotton Valley/Haynesville and the
Bakken/Williston Basin, which are some of the most active areas in the country. Over the long term, we expect working interest owners will continue to develop our acreage through infill drilling,
horizontal drilling, hydraulic fracturing, recompletions and secondary and tertiary recovery methods. As an owner of mineral and royalty interests, we are entitled to a portion of the revenues
received from the production of oil, natural gas and associated natural gas liquids from the acreage underlying our interests, net of post-production expenses and taxes. We are not obligated to fund
drilling and completion costs, lease operating expenses or plugging and abandonment costs at the end of a well's productive life. As such, we benefit from the continued development of the properties
we own a mineral or royalty interest in without the need for investment of additional capital by us, which we expect to increase our distributions over time.
- •
- Maintain a conservative capital structure and prudently manage our business for the long term. We are committed to maintaining a conservative capital structure that will afford us the financial flexibility to execute our business strategies on an ongoing basis. The limited liability company agreement of our general partner will contain provisions that prohibit certain actions without a supermajority vote of at least 66 2 / 3 % of the members of the board of directors of our general partner. Among the actions requiring a supermajority vote will be the incurrence of borrowings in excess of 2.5 times our Debt to EBITDAX Ratio for the preceding four quarters and the issuance of any partnership
place with geologic support for future production and reserve growth and (iii) a geographic footprint complementary to our diverse portfolio.
Our Sponsors and their affiliates have significant experience in identifying, evaluating and completing strategic acquisitions of mineral and royalty interests. In connection with the closing of this offering, we will enter into a management services agreement with Kimbell Operating, which will enter into separate service agreements with certain entities controlled by Messrs. R. Ravnaas, Taylor and Wynne, pursuant to which they will identify, evaluate and recommend to us acquisition opportunities and negotiate the terms of such acquisitions. We believe that these individuals' knowledge of the oil and natural gas industry, relationships within the industry and experience in identifying, evaluating and completing acquisitions will provide us opportunities to grow through strategic and accretive acquisitions that complement or expand our asset portfolio.
We also may have opportunities to acquire mineral or royalty interests from third parties jointly with our Sponsors and the Contributing Parties. In connection with this offering and pursuant to the contribution agreement that we have entered into with our Sponsors and the Contributing Parties, we have a right to participate, at our option and on substantially the same or better terms, in up to 50% of any acquisitions, other than de minimis acquisitions, for which Messrs. R. Ravnaas, Taylor and Wynne provide, directly or indirectly, any oil and gas diligence, reserve engineering or other business services. We believe this arrangement will give us access to third-party acquisition opportunities we might not otherwise be in a position to pursue. Please read "Certain Relationships and Related Party Transactions—Agreements and Transactions with Affiliates in Connection with this Offering—Contribution Agreement."
9
interests that rank senior in right of distributions or liquidation to our common units. Please read "The Partnership Agreement—Certain Provisions of the Agreement Governing our General Partner." We expect to enter into a $50.0 million secured revolving credit facility with an accordion feature permitting aggregate commitments under the facility to be increased up to $100.0 million (subject to the satisfaction of certain conditions and the procurement of additional commitments from new or existing lenders), which will be minimally drawn at the closing of this offering. We initially expect to use borrowings under the secured revolving credit facility for general partnership purposes, including the repayment of certain transaction expenses at the closing of this offering. We believe that this liquidity, along with internally generated cash from operations and access to the public capital markets, will provide us with the financial flexibility to grow our production, reserves and cash generated from operations through strategic acquisitions of mineral and royalty interests and the continued development of our existing assets.
We believe that the following competitive strengths will allow us to successfully execute our business strategies and achieve our primary business objective:
- •
-
Significant diversified portfolio of mineral and royalty interests in
mature producing basins and exposure to undeveloped opportunities.
We have a diversified, low decline asset base with exposure to
high-quality conventional and unconventional plays. As of December 31, 2015, we owned mineral and royalty interests in approximately 3.7 million gross acres and overriding royalty
interests in approximately 0.9 million gross acres, with approximately 44% of our aggregate acres located in the Permian Basin. As of December 31, 2015, over 95% of the acreage subject
to our mineral and royalty interests was leased to working interest owners (including 100% of our overriding royalty interests), and substantially all of those leases were held by production. As of
December 31, 2015, the estimated proved oil, natural gas and natural gas liquids reserves attributable to our interests in our underlying acreage were 18,120 MBoe (52.4% liquids, consisting of
79.7% oil and 20.3% natural gas liquids) based on the reserve report prepared by Ryder Scott. Of these reserves, 70.4% were classified as PDP reserves, 0.8% were classified as PDNP reserves and 28.8%
were classified as PUD reserves. PUD reserves included in this estimate are from 759 gross proved undeveloped locations. The geographic breadth of our assets gives us exposure to potential production
and reserves from new and existing plays without further required investment on our behalf. We believe that we will continue to benefit from these cost-free additions to production and reserves for
the foreseeable future as a result of technological advances and continuing interest by third-party producers in development activities on our acreage.
- •
- Exposure to many of the leading resource plays in the United States. We expect the operators of our properties to continue to drill new wells and to complete drilled but uncompleted wells on our acreage, which we believe should substantially offset the natural production declines from our existing wells. We believe that our operators have significant drilling inventory remaining on the acreage underlying our mineral or royalty interest in multiple resource plays. Our mineral and royalty interests are located in 20 states and in nearly every major onshore basin across the continental United States and include ownership in over 48,000 gross producing wells, including over 29,000 wells in the Permian Basin. For the six months ended June 30, 2016, approximately 52.6% of our production was from the Permian Basin, Eagle Ford, Terryville/Cotton
10
- •
-
Financial flexibility to fund
expansion.
Our conservative capital structure after this offering will permit us to maintain financial flexibility to allow us to
opportunistically purchase strategic mineral and royalty interests, subject to the supermajority vote provisions of the limited liability company agreement of our general partner. We expect to enter
into a $50.0 million secured revolving credit facility with an accordion feature permitting aggregate commitments under the facility to be increased up to $100.0 million (subject to the
satisfaction of certain conditions and the procurement of additional commitments from new or existing lenders), which will be minimally drawn at the closing of this offering. Please read "Management's
Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Indebtedness—New Revolving Credit Agreement" for further
information. We believe that we will be able to expand our asset base through acquisitions utilizing our credit facility, internally generated cash from operations and access to the public capital
markets.
- •
- Experienced and proven management team with a track record of making acquisitions. The members of our management team and board of directors have an average of over 30 years of oil and gas experience. Our management team and board of directors, which includes our founders, have a long history of buying mineral and royalty interests in high-quality producing acreage throughout the United States. Certain members of our management team have managed a significant investment program, investing in over 160 acquisitions. We believe we have a proven competitive advantage in our ability to source, engineer, evaluate, acquire and manage mineral and royalty interests in high-quality producing acreage.
Valley/Haynesville and the Bakken/Williston Basin, which are some of the most active areas in the country.
We are managed and operated by the board of directors and executive officers of our general partner, Kimbell Royalty GP, LLC, a wholly owned subsidiary of Kimbell Holdings, which is a jointly owned subsidiary of our Sponsors. As a result of controlling our general partner, our Sponsors will have the right to appoint all members of the board of directors of our general partner, including at least three directors meeting the independence standards established by the New York Stock Exchange (the "NYSE"). All three of our independent directors will be appointed by the time our common units are first listed for trading on the NYSE. Our unitholders will not be entitled to elect our general partner or its directors or otherwise directly participate in our management or operations.
In connection with the closing of this offering, we will enter into a management services agreement with Kimbell Operating, which will enter into separate service agreements with certain entities controlled by Messrs. Duncan, R. Ravnaas, Taylor and Wynne, pursuant to which they and Kimbell Operating will provide management, administrative and operational services to us. In addition, under each of their respective service agreements, Messrs. R. Ravnaas, Taylor and Wynne will identify, evaluate and recommend to us acquisition opportunities and negotiate the terms of such acquisitions. Neither we, our general partner nor our subsidiaries will have any employees. Although certain of the employees that conduct our business will be employed by Kimbell Operating, we sometimes refer to these individuals in this prospectus as our employees. In addition, certain of the executive officers and directors of our general partner currently serve as executive officers or directors of our Sponsors, the Contributing Parties and
11
Kimbell Operating. Please read "Management" and "Certain Relationships and Related Party Transactions."
Summary of Conflicts of Interest and Duties
Under our partnership agreement, our general partner has a duty to manage us in a manner it believes is in, or not adverse to, our best interests. However, because our general partner is an indirect wholly owned subsidiary of our Sponsors, the officers and directors of our general partner also have a duty to manage the business of our general partner in a manner that is beneficial to Kimbell Holdings and its parents, our Sponsors. In addition, certain of our executive officers and directors will provide management, administrative and operational services to us pursuant to service agreements with Kimbell Operating. Our partnership agreement does not limit our Sponsors' or their respective affiliates' ability to compete with us and, subject to the 50% participation right included in the contribution agreement that we have entered into with our Sponsors and the Contributing Parties, neither our Sponsors nor the Contributing Parties have any obligation to present business opportunities to us. Pursuant to the limited liability company agreement of Kimbell Holdings, the right of each of Messrs. Fortson, R. Ravnaas, Taylor and Wynne (and their designated successors) to serve as a director of our general partner is conditioned upon the applicable person not competing with us, our general partner, and our and its respective subsidiaries. As a result of these relationships, conflicts of interest may arise in the future between us and our unitholders, on the one hand, and our general partner and its affiliates, including our Sponsors, on the other hand. For a more detailed description of the conflicts of interest and duties of our general partner, please read "Risk Factors—Risks Inherent in an Investment in Us" and "Conflicts of Interest and Duties."
Delaware law provides that Delaware limited partnerships may, in their partnership agreements, expand, restrict or eliminate the fiduciary duties owed by our general partner to limited partners and the partnership. Our partnership agreement contains various provisions replacing the fiduciary duties that would otherwise be owed by our general partner with contractual standards governing the duties of our general partner and contractual methods of resolving conflicts of interest. The effect of these provisions is to restrict the remedies available to unitholders for actions taken by our general partner that might otherwise constitute breaches of its fiduciary duties. Our partnership agreement also provides that affiliates of our general partner, including Kimbell Operating and our Sponsors and their respective affiliates, are not restricted from competing with us (subject to the non-competition provision of the limited liability company agreement of Kimbell Holdings). By purchasing a common unit, the purchaser agrees to be bound by the terms of our partnership agreement, and pursuant to the terms of our partnership agreement, each holder of common units consents to various actions and potential conflicts of interest contemplated in our partnership agreement that might otherwise be considered a breach of fiduciary or other duties under Delaware law. Please read "Conflicts of Interest and Duties—Duties of Our General Partner" for a description of the fiduciary duties imposed on our general partner by Delaware law, the replacement of those duties with contractual standards under our partnership agreement and certain legal rights and remedies available to holders of our common units. For a description of our other relationships with our affiliates, please read "Certain Relationships and Related Party Transactions."
Emerging Growth Company Status
We are an "emerging growth company" as defined in the Jumpstart Our Business Startups Act ("JOBS Act"). For as long as we are an emerging growth company, we may take advantage of
12
specified exemptions from reporting and other regulatory requirements that are otherwise generally applicable to other public companies. These exemptions include:
- •
-
an exemption from providing an auditor's attestation report on the effectiveness of our system of internal control over financial
reporting pursuant to Section 404(b) of the Sarbanes-Oxley Act of 2002 (the "Sarbanes-Oxley Act");
- •
-
an exemption from compliance with any new requirements adopted by the Public Company Accounting Oversight Board ("PCAOB"), requiring
mandatory audit firm rotation or supplement to the auditor's report in which the auditor would be required to provide additional information about the audit and the financial statements of the issuer;
- •
-
an exemption from compliance with any other new auditing standards adopted by the PCAOB after April 5, 2012, unless the
Securities and Exchange Commission ("SEC") determines otherwise; and
- •
- reduced disclosure of executive compensation.
In addition, Section 102 of the JOBS Act also provides that an emerging growth company can use the extended transition period provided in Section 7(a)(2)(B) of the Securities Act of 1933, as amended (the "Securities Act"), for complying with new or revised accounting standards. This permits an emerging growth company to delay the adoption of certain accounting standards until those standards would otherwise apply to private companies. However, we are choosing to "opt out" of such extended transition period and, as a result, we will comply with new or revised accounting standards on the relevant dates on which adoption of such standards is required for non-emerging growth companies. Our decision to opt out of the extended transition period for complying with new or revised accounting standards is irrevocable.
We will cease to be an "emerging growth company" upon the earliest of (i) the last day of the first fiscal year when we have $1.0 billion or more in annual revenues; (ii) the date on which we have issued more than $1.0 billion of non-convertible debt over a three-year period; (iii) the last day of the fiscal year following the fifth anniversary of our initial public offering; or (iv) the date on which we have qualified as a "large accelerated filer," which refers to when we (w) have an aggregate worldwide market value of voting and non-voting common units held by our non-affiliates of $700 million or more, as of the last business day of our most recently completed second fiscal quarter, (x) have been subject to the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended (the "Exchange Act"), for a period of at least 12 calendar months, (y) have filed at least one annual report pursuant to Section 13(a) or 15(d) of the Exchange Act and (z) are no longer be eligible to use the requirements for "smaller reporting companies," as defined in the Exchange Act, for our annual and quarterly reports.
An investment in our common units involves a high degree of risk. You should carefully consider the risks described in "Risk Factors" and the other information in this prospectus before deciding whether to invest in our common units. If any of these risks were to occur, our financial condition, results of operations, cash flows and ability to make distributions to our unitholders would be adversely affected, and you could lose all or part of your investment.
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Risks Related to Our Business
- •
-
We may not have sufficient available cash to pay any quarterly distribution on our common units.
- •
-
The assumptions underlying the forecast of cash available for distribution that we include in "Cash Distribution Policy and
Restrictions on Distributions—Estimated Cash Available for Distribution for the Twelve Months Ending December 31, 2017" are inherently uncertain and are subject to significant
business, economic, financial, regulatory, environmental and competitive risks and uncertainties that could cause actual results to differ materially from those forecasted.
- •
-
The amount of our quarterly cash distributions, if any, may vary significantly both quarterly and annually and will be directly
dependent on the performance of our business. We will not have a minimum quarterly distribution or employ structures intended to consistently maintain or increase distributions over time and could pay
no distribution with respect to any particular quarter.
- •
-
All of our revenues are derived from royalty payments that are based on the price at which oil, natural gas and natural gas liquids
produced from the acreage underlying our interests is sold, and we do not currently hedge these commodity prices. The volatility of these prices due to factors beyond our control greatly affects our
business, financial condition, results of operations and cash available for distribution.
- •
-
We depend on unaffiliated operators for all of the exploration, development and production on the properties in which we own mineral
and royalty interests. Substantially all of our revenue is derived from royalty payments made by these operators. A reduction in the expected number of wells to be drilled on the acreage underlying
our interests by these operators or the failure of these operators to adequately and efficiently develop and operate the underlying acreage could materially adversely affect our results of operations
and cash available for distribution.
- •
- We do not intend to retain cash from our operations for replacement capital expenditures. Unless we replenish our oil and natural gas reserves, our cash generated from operations and our ability to pay distributions to our unitholders could be materially adversely affected.
Risks Inherent in an Investment in Us
- •
-
Our general partner and its affiliates, including our Sponsors and their respective affiliates, have conflicts of interest with us and
limited duties to us and our unitholders, and they may favor their own interests to the detriment of us and our unitholders. Additionally, we have no control over the business decisions and operations
of our Sponsors and their respective affiliates, which are under no obligation to adopt a business strategy that favors us.
- •
- Neither we, our general partner nor our subsidiaries have any employees, and we rely solely on Kimbell Operating to manage and operate, or arrange for the management and operation of, our business. The management team of Kimbell Operating, which includes the individuals who will manage us, will also provide substantially similar services to other entities and thus will not be solely focused on our business.
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- •
-
Our partnership agreement replaces fiduciary duties applicable to a corporation with contractual duties and restricts the remedies
available to holders of our common units for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty.
- •
-
Holders of our common units have limited voting rights and are not entitled to elect our general partner or its directors, which could
reduce the price at which our common units will trade.
- •
-
Even if holders of our common units are dissatisfied, they cannot initially remove our general partner without its consent.
- •
-
Our partnership agreement restricts the voting rights of unitholders owning 20% or more of our common units (other than our general
partner and its affiliates, the Contributing Parties and their respective affiliates and permitted transferees).
- •
-
Cost reimbursements due to our general partner and its affiliates for services provided to us or on our behalf will reduce cash
available for distribution to our unitholders. Our partnership agreement does not set a limit on the amount of expenses for which our general partner and its affiliates may be reimbursed. The amount
and timing of such reimbursements will be determined by our general partner.
- •
-
We may issue additional common units and other equity interests without unitholder approval, which would dilute existing unitholder
ownership interests.
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-
There is no existing market for our common units, and a trading market that will provide you with adequate liquidity may not develop.
The price of our common units may fluctuate significantly, and unitholders could lose all or part of their investment.
- •
- For as long as we are an emerging growth company, we will not be required to comply with certain disclosure requirements that apply to other public companies.
Tax Risks to Common Unitholders
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-
Our tax treatment depends on our status as a partnership for federal income tax purposes, as well as our not being subject to a
material amount of entity-level taxation by individual states. If the Internal Revenue Service ("IRS") were to treat us as a corporation for federal income tax purposes or we were to become subject to
entity-level taxation for state tax purposes, then our cash available for distribution to you could be substantially reduced.
- •
-
If the IRS were to contest the federal income tax positions we take, it may adversely impact the market for our common units, and the
costs of any such contest would reduce cash available for distribution to our unitholders.
- •
- Even if you do not receive any cash distributions from us, you will be required to pay taxes on your share of our taxable income.
15
At or prior to the closing of this offering, among other things, the following transactions will occur:
- •
-
the Contributing Parties will contribute, directly or indirectly, certain mineral and royalty interests to us;
- •
-
we will issue an aggregate common units, representing
a % limited partner interest in us, to the
Contributing Parties;
- •
-
our general partner will maintain its non-economic general partner interest;
- •
-
we will issue and sell common units to the public in this offering, representing
a % limited partner
interest in us;
- •
-
we will pay the underwriting discount and structuring fee in connection with this offering and use the net proceeds from this offering
in the manner described under "Use of Proceeds";
- •
-
we expect to enter into a new $50.0 million secured revolving credit facility and to borrow approximately $1.5 million at the
closing of this offering to fund certain transaction expenses, as described in "Management's Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital
Resources—Indebtedness—New Revolving Credit Agreement"; and
- •
- we will enter into a management services agreement with Kimbell Operating, which will enter into separate service agreements with certain entities controlled by Messrs. Duncan, R. Ravnaas, Taylor and Wynne, pursuant to which they and Kimbell Operating will provide management, administrative and operational services to us.
We refer to these transactions collectively as the "formation transactions."
The aggregate number of common units to be issued to the Contributing Parties includes common units that will be issued at the expiration of the underwriters' option to purchase additional common units, assuming that the underwriters do not exercise the option. Any exercise of the underwriters' option to purchase additional common units would reduce the common units shown as issued to the Contributing Parties by the number to be purchased by the underwriters in connection with such exercise. To the extent the underwriters exercise their option to purchase additional common units, we will issue such units to the public and distribute the net proceeds to the Contributing Parties. Any common units not purchased by the underwriters pursuant to their option will be issued to the Contributing Parties at the expiration of the option period for no additional consideration. We will use any net proceeds from the exercise of the underwriters' option to make a distribution to the Contributing Parties.
Our principal executive offices are located at 777 Taylor Street, Suite 810, Fort Worth, Texas 76102 and our telephone number is (817) 945-9700. Our website address will be . We intend to make our periodic reports and other information filed with or furnished to the SEC available, free of charge, through our website, as soon as reasonably practicable after those reports and other information are electronically filed with or furnished to
16
the SEC. Information on our website is not incorporated by reference into this prospectus and does not constitute a part of this prospectus.
Organizational Structure After the Formation Transactions
The following chart illustrates our organizational structure after giving effect to this offering and the other formation transactions described above:
- (1)
-
The
Sponsors are affiliates of our founders, Messrs. Fortson, R. Ravnaas, Taylor and Wynne.
- (2)
-
The
Contributing Parties include entities and individuals, including affiliates of our Sponsors, that are contributing, directly or indirectly, certain
mineral and royalty interests to us.
- (3)
- Kimbell Operating will enter into separate service agreements with certain entities controlled by Messrs. Duncan, R. Ravnaas, Taylor and Wynne for the provision of certain management, administrative and operational services. In addition, the entities controlled by Messrs. R. Ravnaas, Taylor and Wynne will provide certain acquisition services to us. Please read "Certain Relationships and Related Party Transactions—Agreements and Transactions with Affiliates in Connection with this Offering—Management Services Agreements."
17
|
Common units offered to the
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common units ( common units if the underwriters exercise in full their option to purchase additional common units from us). | |
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Option to purchase additional
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We have granted the underwriters a 30-day option to purchase up to an additional common units. |
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Units outstanding after this
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common units. If and to the extent the underwriters do not exercise their option to purchase additional common units, in whole or in part, we will issue up to an additional common units to the Contributing Parties at the expiration of the option for no additional consideration. To the extent the underwriters exercise their option to purchase additional common units, we will issue such units to the public and distribute the net proceeds to the Contributing Parties. Any common units not purchased by the underwriters pursuant to their option will be issued to the Contributing Parties at the expiration of the option period for no additional consideration. Accordingly, the exercise of the underwriters' option will not affect the total number of common units outstanding. |
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In addition, our general partner will own a non-economic general partner interest in us. |
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Use of proceeds |
We will receive net proceeds of approximately $ million from this offering (based on an assumed initial offering price of $ per common unit, the mid-point of the price range set forth on the cover page of this prospectus), after deducting the estimated underwriting discount and structuring fee payable by us in connection with this offering. We intend to use the net proceeds of this offering to make a distribution to the Contributing Parties. |
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If the underwriters exercise their option to purchase additional common units in full, the additional net proceeds to us would be approximately $ million, after deducting the estimated underwriting discount and structuring fee. We will use any net proceeds from the exercise of the underwriters' option to purchase additional common units from us to make an additional cash distribution to the Contributing Parties. Please read "Use of Proceeds." |
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It is our intent, subject to market conditions, to finance acquisitions of mineral and royalty interests that increase our asset base largely through external sources, such as borrowings under our secured revolving credit facility and the issuance of equity and debt securities, although the board of directors of our general partner may choose to reserve a portion of cash generated from operations to finance such acquisitions as well. The limited liability company agreement of our general partner will contain provisions that prohibit certain actions without a supermajority vote of at least 66 2 / 3 % of the members of the board of directors of our general partner. Among the actions requiring a supermajority vote will be the reservation of a portion of cash generated from operations to finance such acquisitions. We do not currently intend to maintain excess distribution coverage for the purpose of maintaining stability or growth in our quarterly distribution or otherwise reserve cash for distributions, or to incur debt to pay quarterly distributions, although the board of directors of our general partner may change this policy. |
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Because our partnership agreement will require us to distribute an amount equal to all available cash we generate each quarter, our unitholders will have direct exposure to fluctuations in the amount of cash generated by our business. We expect that the amount of our quarterly distributions, if any, will fluctuate based on variations in, among other factors, (i) the performance of the operators of our properties, (ii) earnings caused by, among other things, fluctuations in the price of oil, natural gas and natural gas liquids, changes to working capital or capital expenditures and (iii) cash reserves deemed appropriate by the board of directors of our general partner. Such variations in the amount of our quarterly distributions may be significant and could result in our not making any distribution for any particular quarter. We will not have a minimum quarterly distribution or employ structures intended to consistently maintain or increase distributions over time. |
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Based upon our forecast for the twelve months ending December 31, 2017, and assuming the board of directors of our general partner declares distributions in accordance with our initial cash distribution policy, we expect that our aggregate distributions for the twelve months ending December 31, 2017 will be approximately $ million, or $ per common unit. Please read "Cash Distribution Policy and Restrictions on Distributions—Estimated Cash Available for Distribution for the Twelve Months Ending December 31, 2017." Unanticipated events may occur which could materially adversely affect the actual results we achieve during the forecast period. Consequently, our actual results of operations, cash reserve requirements and financial condition during the forecast period may vary from the forecast, and such variations may be material. Prospective investors are cautioned not to place undue reliance on our forecast and should make their own independent assessment of our future results of operations and financial condition. In addition, the board of directors of our general partner may be required to, or may elect to, eliminate our distributions for various reasons, including reduced prices or demand for oil and natural gas. Please read "Risk Factors." |
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For a calculation of our ability to pay distributions to unitholders based on our pro forma results of operations for the year ended December 31, 2015 and the twelve months ended September 30, 2016, please read "Cash Distribution Policy and Restrictions on Distributions—Unaudited Pro Forma Cash Available for Distribution for the Year Ended December 31, 2015 and the Twelve Months Ended September 30, 2016." Our pro forma cash available for distribution generated during the year ended December 31, 2015 and the twelve months ended September 30, 2016 would have been $16.3 million and $10.9 million, respectively. However, the pro forma cash available for distribution information for the year ended December 31, 2015 and the twelve months ended September 30, 2016 that we include in this prospectus does not necessarily reflect the actual cash that would have been available for distribution with respect to each of these periods. |
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Subordinated units |
None. |
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Incentive distribution rights |
None. |
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Issuance of additional units |
Our partnership agreement authorizes us to issue an unlimited number of additional units without the approval of our unitholders. Please read "Units Eligible for Future Sale" and "The Partnership Agreement—Issuance of Additional Partnership Interests." |
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Limited voting rights |
Our general partner will manage and operate us. Unlike the holders of common stock in a corporation, our unitholders will have only limited voting rights on matters affecting our business. Our unitholders will have no right to elect our general partner or its directors on an annual or other continuing basis. Our general partner may not be removed except by a vote of the unitholders holding at least 66 2 / 3 % of the outstanding units, including any units owned by our general partner and its affiliates, voting together as a single class. Upon the completion of this offering, affiliates of our Sponsors will own an aggregate of % of our common units (or % of our common units, if the underwriters exercise their option to purchase additional common units in full) (excluding any common units purchased by officers and directors of our general partner under our directed unit program), and our Sponsors will indirectly own and control our general partner. Please read "The Partnership Agreement—Voting Rights." |
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Limited call right |
If at any time our general partner and its affiliates (including our Sponsors and their respective affiliates) own more than 80% of the outstanding common units, our general partner will have the right, but not the obligation, to purchase all of the remaining common units at a price equal to the greater of (1) the average of the daily closing price of our common units over the 20 trading days preceding the date three days before notice of exercise of the call right is first mailed and (2) the highest per-unit price paid by our general partner or any of its affiliates for common units during the 90-day period preceding the date such notice is first mailed. Please read "The Partnership Agreement—Limited Call Right." |
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|
Estimated ratio of taxable income to distributions |
We estimate that if you own the common units you purchase in this offering through the record date for distributions for the period ending December 31, , you will be allocated, on a cumulative basis, an amount of federal taxable income for that period that will be less than % of the cash expected to be distributed to you with respect to that period. Because of the nature of our business and the expected variability of our quarterly distributions, however, the ratio of our taxable income to distributions may vary significantly from one year to another. Please read "Material U.S. Federal Income Tax Consequences—Tax Consequences of Unit Ownership" for the basis of this estimate. |
22
|
Material federal income tax consequences |
For a discussion of the material federal income tax consequences that may be relevant to certain unitholders who are individual citizens or residents of the United States, please read "Material U.S. Federal Income Tax Consequences." |
|
|
Directed unit program |
The underwriters have reserved up to 10% of the common units being offered by this prospectus for sale at the initial public offering price to directors and officers of our general partner, the Contributing Parties and their affiliates, individuals providing services to us and certain other persons associated with us. Any purchases they do make will reduce the number of common units available to the general public. Please read "Underwriting—Directed Unit Program." |
|
|
Exchange listing |
We have been approved to list our common units on the NYSE, subject to official notice of issuance, under the symbol "KRP." |
23
Summary Historical and Unaudited Pro Forma Condensed Combined Financial Data
Kimbell Royalty Partners, LP was formed in October 2015. In this prospectus, we present the historical financial statements of Rivercrest Royalties, LLC, our predecessor for accounting purposes. We refer to this entity as "our predecessor." The following table presents summary historical financial data of our predecessor and summary unaudited pro forma financial data of Kimbell Royalty Partners, LP as of the dates and for the years indicated.
The summary historical financial data of our predecessor presented as of and for the years ended December 31, 2015 and 2014 are derived from the audited historical financial statements of our predecessor included elsewhere in this prospectus. The summary historical financial data presented as of September 30, 2016 and for the nine months ended September 30, 2016 and 2015 are derived from the unaudited historical financial statements of our predecessor included elsewhere in this prospectus.
The summary unaudited pro forma financial data presented as of and for the nine months ended September 30, 2016 and 2015 and for the year ended December 31, 2015 are derived from our unaudited pro forma financial statements included elsewhere in this prospectus and give effect to the following transactions, which we refer to as the "pro forma formation transactions":
- •
-
The assignment by our predecessor and associated entities to certain of their affiliates of certain non-operated working interests and
net profits interests that will not be contributed to us;
- •
-
Our acquisition of assets to be contributed by our predecessor and the Kimbell Art Foundation, Trunk Bay Royalty Partners, Ltd., Oil
Nut Bay Royalties, LP, Gorda Sound Royalties, LP and Bitter End Royalties, LP, RCPTX, Ltd., and French Capital Partners, Ltd. (but not by the other Contributing Parties);
- •
-
The issuance by us of an aggregate of common units to all the Contributing Parties;
- •
-
The issuance by us of common units to the public in this offering at an assumed initial public
offering price of
$ per common unit, which is the mid-point of the range set forth on the cover of the prospectus;
- •
-
The use of the net proceeds from this offering as set forth in "Use of Proceeds";
- •
-
Our expected entrance into a new $50.0 million secured revolving credit facility with an accordion feature permitting aggregate
commitments under the facility to be increased up to $100.0 million (subject to the satisfaction of certain conditions and the procurement of additional commitments from new or existing
lenders), pursuant to which we expect to borrow approximately $1.5 million at the closing of this offering to fund certain transaction expenses; and
- •
- Our entrance into a management services agreement with Kimbell Operating, which will enter into separate service agreements with certain entities controlled by Messrs. Duncan, R. Ravnaas, Taylor and Wynne.
The unaudited pro forma condensed combined balance sheet as of September 30, 2016 assumes the events described above occurred as of September 30, 2016. The unaudited pro
24
forma condensed combined statements of operations for the nine months ended September 30, 2016 and the year ended December 31, 2015 assume the events described above occurred as of January 1, 2015.
We have not given pro forma effect to our acquisition of assets to be contributed by the Contributing Parties other than our predecessor, the Kimbell Art Foundation, Trunk Bay Royalty Partners, Ltd., Oil Nut Bay Royalties, LP, Gorda Sound Royalties, LP and Bitter End Royalties, LP, RCPTX, Ltd., and French Capital Partners, Ltd., which excluded assets represent approximately 25% of our future undiscounted cash flows, based on the reserve report prepared by Ryder Scott as of December 31, 2015.
We have not given pro forma effect to incremental general and administrative expenses of approximately $1.5 million that we expect to incur annually as a result of operating as a publicly traded partnership, such as expenses associated with SEC reporting requirements, including annual and quarterly reports to unitholders, tax return and Schedule K-1 preparation and distribution expenses, Sarbanes-Oxley Act compliance expenses, expenses associated with listing on the NYSE, independent auditor fees, independent reserve engineer fees, legal fees, investor relations expenses, registrar and transfer agent fees, director and officer insurance expenses and director and officer compensation expenses.
For a detailed discussion of the summary historical financial data contained in the following table, please read "Management's Discussion and Analysis of Financial Condition and Results of Operations." The following table should also be read in conjunction with "Use of Proceeds" and the audited historical financial statements of our predecessor and our pro forma condensed combined financial statements included elsewhere in this prospectus. Among other things, the historical financial statements include more detailed information regarding the basis of presentation for the information in the following table.
The following table presents Adjusted EBITDA, a financial measure that is not presented in accordance with U.S. generally accepted accounting principles ("GAAP"). We use Adjusted EBITDA in our business as we believe it is an important supplemental measure of our operating performance and liquidity. For a definition of and a reconciliation of Adjusted EBITDA to net income and net cash provided by operating activities, its most directly comparable financial measures in accordance with GAAP, please read "—Non-GAAP Financial Measures." For a discussion of how we use Adjusted EBITDA to evaluate our operating performance and liquidity, please read "Management's Discussion and Analysis of Financial Condition and Results of Operations—Adjusted EBITDA."
25
|
|
Kimbell Royalty
Partners, LP Pro Forma |
Predecessor Historical | |||||||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
|
|
|
|
Nine
Months Ended September 30, |
|
|
||||||||||||||
|
|
Nine
Months Ended September 30, 2016 |
|
Year Ended
December 31, |
||||||||||||||||
|
|
Year Ended
December 31, 2015 |
||||||||||||||||||
|
|
2016 | 2015 | 2015 | 2014 | |||||||||||||||
|
Statement of Operations Data: |
|||||||||||||||||||
|
Revenue: |
|||||||||||||||||||
|
Oil, natural gas and NGL revenues |
$ | 15,354,458 | $ | 26,691,028 | $ | 2,572,477 | $ | 3,670,930 | $ | 4,684,923 | $ | 7,219,822 | |||||||
|
Cost and expenses: |
|||||||||||||||||||
|
Production and ad valorem taxes |
1,284,194 | 2,199,404 | 203,567 | 214,150 | 426,885 | 568,327 | |||||||||||||
|
Depreciation, depletion and accretion expense |
9,586,455 | 18,164,181 | 1,244,023 | 2,969,502 | 4,008,730 | 4,044,802 | |||||||||||||
|
Impairment of oil and natural gas properties |
4,982,739 | 27,749,669 | 4,992,897 | 25,796,352 | 28,673,166 | 7,416,747 | |||||||||||||
|
Marketing and other deductions |
1,247,964 | 1,271,104 | 570,521 | 590,637 | 747,264 | 526,727 | |||||||||||||
|
General and administrative expenses |
3,659,341 | 5,079,796 | 1,252,001 | 1,127,926 | 1,789,884 | 1,757,377 | |||||||||||||
| | | | | | | | | | | | | | | | | | | | |
|
Total costs and expenses |
20,760,693 | 54,464,154 | 8,263,009 | 30,698,567 | 35,645,929 | 14,313,980 | |||||||||||||
|
Operating loss |
(5,406,235 | ) | (27,773,126 | ) | (5,690,532 | ) | (27,027,637 | ) | (30,961,006 | ) | (7,094,158 | ) | |||||||
|
Interest expense |
227,737 | 308,343 | 314,081 | 282,372 | 385,119 | 302,118 | |||||||||||||
| | | | | | | | | | | | | | | | | | | | |
|
Loss before income taxes |
(5,633,972 | ) | (28,081,469 | ) | (6,004,613 | ) | (27,310,009 | ) | (31,346,125 | ) | (7,396,276 | ) | |||||||
|
State income taxes |
— | — | 13,401 | 11,557 | (32,199 | ) | 16,970 | ||||||||||||
| | | | | | | | | | | | | | | | | | | | |
|
Net income (loss) |
$ | (5,633,972 | ) | $ | (28,081,469 | ) | $ | (6,018,014 | ) | $ | (27,321,566 | ) | $ | (31,313,926 | ) | $ | (7,413,246 | ) | |
| | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | |
|
Statement of Cash Flows Data: |
|||||||||||||||||||
|
Net cash provided by (used in): |
|||||||||||||||||||
|
Operating activities |
$ | 956,793 | $ | 2,317,594 | $ | 2,713,133 | $ | 4,038,018 | |||||||||||
|
Investing activities |
$ | (93,899 | ) | $ | (503,989 | ) | $ | (538,640 | ) | $ | (53,463,030 | ) | |||||||
|
Financing activities |
$ | (563,000 | ) | $ | (1,762,973 | ) | $ | (2,062,818 | ) | $ | 39,645,738 | ||||||||
|
Other Financial Data: |
|||||||||||||||||||
|
Adjusted EBITDA (1) |
$ | $ | $ | 1,000,183 | $ | 2,192,012 | $ | 2,325,949 | $ | 4,518,656 | |||||||||
|
Selected Balance Sheet Data: |
|||||||||||||||||||
|
Cash and cash equivalents |
$ | $ | 679,635 | $ | 318,698 | $ | 379,741 | $ | 268,066 | ||||||||||
|
Total assets |
$ | $ | 20,784,733 | $ | 30,753,412 | $ | 27,905,790 | $ | 58,753,888 | ||||||||||
|
Long-term debt |
$ | $ | $ | 10,898,860 | $ | 10,998,860 | $ | 11,448,860 | $ | 9,003,860 | |||||||||
|
Total liabilities |
$ | $ | 12,109,530 | $ | 12,672,894 | $ | 13,666,368 | $ | 10,556,272 | ||||||||||
|
Members' equity |
$ | $ | 8,675,203 | $ | 18,080,518 | $ | 14,239,422 | $ | 48,197,616 | ||||||||||
- (1)
- For more information, please read "—Non-GAAP Financial Measures."
Adjusted EBITDA
Adjusted EBITDA is used as a supplemental non-GAAP financial measure by management and external users of our financial statements, such as industry analysts, investors, lenders and rating agencies. We believe Adjusted EBITDA is useful because it allows us to more effectively evaluate our operating performance and compare the results of our operations period to period
26
without regard to our financing methods or capital structure. In addition, management uses Adjusted EBITDA to evaluate cash flow available to pay distributions to our unitholders.
We define Adjusted EBITDA as net income (loss) plus interest expense, net of capitalized interest, non-cash unit-based compensation, impairment of oil and natural gas properties, income taxes and depreciation, depletion and accretion expense. Adjusted EBITDA is not a measure of net income (loss) or net cash provided by operating activities as determined by GAAP. We exclude the items listed above from net income (loss) in arriving at Adjusted EBITDA because these amounts can vary substantially from company to company within our industry depending upon accounting methods and book values of assets, capital structures and the method by which the assets were acquired. Certain items excluded from Adjusted EBITDA are significant components in understanding and assessing a company's financial performance, such as a company's cost of capital and tax structure, as well as historic costs of depreciable assets, none of which are components of Adjusted EBITDA.
Adjusted EBITDA should not be considered an alternative to net income, oil, natural gas and natural gas liquids revenues, net cash provided by operating activities or any other measure of financial performance or liquidity presented in accordance with GAAP. Our computations of Adjusted EBITDA may not be comparable to other similarly titled measures of other companies.
The following tables present a reconciliation of Adjusted EBITDA to net income and net cash provided by operating activities, our most directly comparable GAAP financial measures for the periods indicated.
27
|
|
Predecessor Historical | ||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
|
|
Nine
Months Ended September 30, |
Year Ended
December 31, |
|||||||||||
|
|
2016 | 2015 | 2015 | 2014 | |||||||||
|
Reconciliation of net cash provided by operating activities to Adjusted EBITDA: |
|||||||||||||
|
Net cash provided by operating activities |
$ | 956,793 | $ | 2,317,594 | $ | 2,713,133 | $ | 4,038,018 | |||||
|
Interest expense |
314,081 | 282,372 | 385,119 | 302,118 | |||||||||
|
State income taxes |
13,401 | 11,557 | (32,199 | ) | 16,970 | ||||||||
|
Impairment of oil and natural gas properties |
(4,992,897 | ) | (25,796,352 | ) | (28,673,166 | ) | (7,416,747 | ) | |||||
|
Amortization of loan origination costs |
(34,245 | ) | (30,724 | ) | (40,965 | ) | (34,916 | ) | |||||
|
Amortization of tenant improvement allowance |
25,777 | — | 14,321 | — | |||||||||
|
Unit-based compensation |
(453,795 | ) | (453,795 | ) | (605,059 | ) | (151,265 | ) | |||||
|
Changes in operating assets and liabilities: |
|||||||||||||
|
Oil, natural gas and NGL revenues receivable |
(11,258 | ) | (377,448 | ) | (464,877 | ) | 373,644 | ||||||
|
Other receivables |
(1,246,269 | ) | 600,579 | 1,371,540 | — | ||||||||
|
Other current assets |
— | — | (6,441 | ) | (72,742 | ) | |||||||
|
Accounts payable |
1,071,453 | (568,430 | ) | (1,604,999 | ) | (77,152 | ) | ||||||
|
Other current liabilities |
(89,550 | ) | (43,488 | ) | (8,683 | ) | (27,284 | ) | |||||
| | | | | | | | | | | | | | |
|
EBITDA |
$ | (4,446,509 | ) | $ | (24,058,135 | ) | $ | (26,952,276 | ) | $ | (3,049,356 | ) | |
|
Add: |
|||||||||||||
|
Impairment of oil and natural gas properties |
4,992,897 | 25,796,352 | 28,673,166 | 7,416,747 | |||||||||
|
Unit-based compensation |
453,795 | 453,795 | 605,059 | 151,265 | |||||||||
| | | | | | | | | | | | | | |
|
Adjusted EBITDA |
$ | 1,000,183 | $ | 2,192,012 | $ | 2,325,949 | $ | 4,518,656 | |||||
| | | | | | | | | | | | | | |
| | | | | | | | | | | | | | |
| | | | | | | | | | | | | | |
28
The following table presents our estimated proved oil and natural gas reserves as of December 31, 2015 based on the reserve report prepared by Ryder Scott. The reserve report was prepared in accordance with the rules and regulations of the SEC. You should refer to "Risk Factors—Risks Related to Our Business—"Our estimated reserves are based on many assumptions that may prove to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves" and the other risks set forth in "Risk Factors," "Business—Oil and Natural Gas Data—Proved Reserves," "Business—Oil and Natural Gas Production Prices and Production Costs—Production and Price History" and "Management's Discussion and Analysis of Financial Condition and Results of Operations" in evaluating the material presented below.
|
|
December 31,
2015 (1) |
|||
|---|---|---|---|---|
|
Estimated proved developed reserves: |
||||
|
Oil (MBbls) |
5,336 | |||
|
Natural gas (MMcf) |
35,910 | |||
|
Natural gas liquids (MBbls) |
1,575 | |||
|
Total (MBoe)(6:1) (2) |
12,896 | |||
|
Estimated proved undeveloped reserves: |
||||
|
Oil (MBbls) |
2,237 | |||
|
Natural gas (MMcf) |
15,808 | |||
|
Natural gas liquids (MBbls) |
352 | |||
|
Total (MBoe)(6:1) (2) |
5,224 | |||
|
Estimated proved reserves: |
||||
|
Oil (MBbls) |
7,573 | |||
|
Natural gas (MMcf) |
51,718 | |||
|
Natural gas liquids (MBbls) |
1,927 | |||
|
Total (MBoe)(6:1) (2) |
18,120 | |||
|
Percent proved developed |
71 | % | ||
- (1)
-
Estimates
of reserves as of December 31, 2015 were prepared using an average price equal to the unweighted arithmetic average of hydrocarbon prices
received on a field-by-field basis on the first day of each month within the year ended December 31, 2015, in accordance with SEC guidelines applicable to reserve estimates as of the end of
such period. The unweighted arithmetic average first day of the month prices were $50.28 per Bbl for oil and $2.59 per MMBtu for natural gas at December 31, 2015. The price per Bbl for natural
gas liquids was modeled as a percentage of oil price, which was derived from historical accounting data. Reserve estimates do not include any value for probable or possible reserves that may exist,
nor do they include any value for undeveloped acreage. The reserve estimates represent our net revenue interest in our properties. Although we believe these estimates are reasonable, actual future
production, cash flows, taxes, development expenditures, production costs and quantities of recoverable oil and natural gas reserves may vary substantially from these estimates.
- (2)
- Estimated proved reserves are presented on an oil-equivalent basis using a conversion of six Mcf per barrel of "oil equivalent." This conversion is based on energy equivalence and not price or value equivalence. If a price equivalent conversion based on the twelve-month average prices for the year ended December 31, 2015 was used, the conversion factor would be approximately 19.4 Mcf per Bbl of oil. In this prospectus, we supplementally provide "value-equivalent" production information or volumes presented on an oil-equivalent basis using a conversion factor of 20 Mcf of natural gas per barrel of "oil equivalent," which is the conversion factor we use in our business. For a discussion of the 20-to-1 conversion factor, please read footnote 3 to the Mineral Interests table under "Business—Our Properties—Material Basins and Producing Regions—Mineral Interests."
29
The following table sets forth information regarding production of oil and natural gas and certain price and cost information of our predecessor for each of the periods indicated:
|
|
Nine Months
Ended September 30, 2016 |
Year Ended
December 31, 2015 |
Year Ended
December 31, 2014 |
|||||||
|---|---|---|---|---|---|---|---|---|---|---|
|
Predecessor Production Data: |
||||||||||
|
Oil and condensate (Bbls) |
41,548 | 59,321 | 50,570 | |||||||
|
Natural gas (Mcf) |
343,078 | 548,386 | 515,130 | |||||||
|
Natural gas liquids (Bbls) |
17,458 | 22,351 | 17,991 | |||||||
|
Total (Boe)(6:1) (1) |
116,186 | 173,070 | 154,416 | |||||||
|
Average daily production (Boe/d)(6:1) |
424 | 474 | 423 | |||||||
|
Predecessor Average Realized Prices: |
||||||||||
|
Oil and condensate (per Bbl) |
$ | 38.11 | $ | 49.79 | $ | 87.25 | ||||
|
Natural gas (per Mcf) |
$ | 2.14 | $ | 2.44 | $ | 4.22 | ||||
|
Natural gas liquids (per Bbl) |
$ | 14.56 | $ | 17.56 | $ | 35.26 | ||||
|
Predecessor Average Unit Cost per Boe (6:1) |
||||||||||
|
Production and ad valorem taxes |
$ | 1.75 | $ | 2.47 | $ | 3.68 | ||||
- (1)
- "Btu-equivalent" production volumes are presented on an oil-equivalent basis using a conversion factor of six Mcf of natural gas per barrel of "oil equivalent," which is based on approximate energy equivalency and does not reflect the price or value relationship between oil and natural gas. In this prospectus, we supplementally provide "value-equivalent" production information or volumes presented on an oil-equivalent basis using a conversion factor of 20 Mcf of natural gas per barrel of "oil equivalent," which is the conversion factor we use in our business. For a discussion of the 20-to-1 conversion factor, please read footnote 3 to the Mineral Interests table under "Business—Our Properties—Material Basins and Producing Regions—Mineral Interests."
30
Limited partner interests are inherently different from the capital stock of a corporation, although many of the business risks to which we are subject are similar to those that would be faced by a corporation engaged in a similar business. You should carefully consider the following risk factors together with all of the other information included in this prospectus in evaluating an investment in our common units.
If any of the following risks were to occur, our business, financial condition, results of operations and cash available for distribution could be materially adversely affected. In that case, we might not be able to pay distributions on our common units, the trading price of our common units could decline, and you could lose all or part of your investment.
We may not have sufficient available cash to pay any quarterly distribution on our common units.
We may not have sufficient available cash each quarter to enable us to pay any distributions to our common unitholders. Our expected aggregate annual distribution amount for the twelve months ending December 31, 2017 is based on the price and production assumptions set forth in "Cash Distribution Policy and Restrictions on Distributions—Estimated Cash Available for Distribution for the Twelve Months Ending December 31, 2017—Assumptions and Considerations." If our price or production assumptions prove to be inaccurate, our actual distributions for the twelve months ending December 31, 2017 may be significantly lower than our forecasted distributions and we may not be able to pay a distribution at all. Substantially all of the cash we have to distribute each quarter depends upon the amount of oil, natural gas and natural gas liquids revenues we generate, which is dependent upon the prices that the operators of our properties realize from the sale of oil and natural gas production. In addition, the actual amount of our available cash we will have to distribute each quarter will be reduced by replacement capital expenditures we make, payments in respect of our debt instruments and other contractual obligations, general and administrative expenses and fixed charges and reserves for future operating or capital needs that the board of directors may determine are appropriate.
For a description of additional restrictions and factors that may affect our ability to pay cash distributions, please read "Cash Distribution Policy and Restrictions on Distributions."
The assumptions underlying the forecast of cash available for distribution that we include in "Cash Distribution Policy and Restrictions on Distributions—Estimated Cash Available for Distribution for the Twelve Months Ending December 31, 2017" are inherently uncertain and are subject to significant business, economic, financial, regulatory, environmental and competitive risks and uncertainties that could cause actual results to differ materially from those forecasted.
The forecast of cash available for distribution set forth in "Cash Distribution Policy and Restrictions on Distributions—Estimated Cash Available for Distribution for the Twelve Months Ending December 31, 2017" includes our forecast of results of operations, Adjusted EBITDA and cash available for distribution for the twelve months ending December 31, 2017. We estimate that our total cash available for distribution for the twelve months ending December 31, 2017 will be approximately $24.6 million, as compared to approximately $16.3 million for the year ended December 31, 2015 and approximately $10.9 million for the twelve months ended
31
September 30, 2016, respectively, on a pro forma basis. The forecast has been prepared by our management. Neither our independent registered public accounting firm nor any other independent registered public accounting firm has compiled, examined or performed any procedures with respect to the forecast, expressed any opinion or given any other form of assurance on such information or its achievability or assumed any responsibility for the forecast. The assumptions underlying the forecast are inherently uncertain and are subject to significant business, economic, financial, regulatory, environmental and competitive risks and uncertainties that could cause actual results to differ materially from those forecasted. If the forecasted results are not achieved, we would not be able to pay the forecasted annual distribution, in which event the market price of our common units may decline materially. Our actual results may differ materially from the forecasted results presented in this prospectus. Investors should review the forecast of our results of operations for the twelve months ending December 31, 2017 together with the other information included elsewhere in this prospectus, including "Risk Factors" and "Management's Discussion and Analysis of Financial Condition and Results of Operations." The pro forma available cash information for the year ended December 31, 2015 and for the twelve months ended September 30, 2016 do not reflect the actual cash that we would have generated over the course of those periods.
The amount of cash we have available for distribution to holders of our units depends primarily on our cash flow and not solely on profitability, which may prevent us from paying cash distributions during periods when we record net income.
The amount of cash we have available for distribution depends primarily upon our cash flow and not solely on profitability, which will be affected by non-cash items. For example, we may have significant capital expenditures in the future. While these items may not affect our profitability in a quarter, they would reduce the amount of cash available for distribution with respect to such quarter. As a result, we may pay cash distributions during periods in which we record net losses for financial accounting purposes and may be unable to pay cash distributions during periods in which we record net income.
Our business is difficult to evaluate because we have a limited financial history.
Kimbell Royalty Partners, LP was formed in October 2015. Our predecessor, Rivercrest Royalties, LLC, was formed in October 2013. We do not have historical financial statements with respect to our mineral and royalty interests for periods prior to their acquisition by the Contributing Parties. As a result, with respect to some of our assets, there is only limited historical financial information available upon which to base your evaluation of our performance.
The amount of our quarterly cash distributions, if any, may vary significantly both quarterly and annually and will be directly dependent on the performance of our business. We will not have a minimum quarterly distribution or employ structures intended to consistently maintain or increase distributions over time and could pay no distribution with respect to any particular quarter.
Investors who are looking for an investment that will pay regular and predictable quarterly distributions should not invest in our common units. Our future business performance may be volatile, and our cash flows may be unstable. Please read "—All of our revenues are derived from royalty payments that are based on the price at which oil, natural gas and natural gas liquids produced from the acreage underlying our interests is sold, and we do not currently hedge these commodity prices. The volatility of these prices due to factors beyond our control
32
greatly affects our business, financial condition, results of operations and cash available for distribution." We will not have a minimum quarterly distribution or employ structures intended to consistently maintain or increase distributions over time. Because our quarterly distributions will significantly correlate to the cash we generate each quarter after payment of our fixed and variable expenses, future quarterly distributions paid to our unitholders will vary significantly from quarter to quarter and may be zero. Please read "Cash Distribution Policy and Restrictions on Distributions."
Our partnership agreement requires that we distribute all of our available cash, which could limit our ability to grow and make acquisitions.
Our partnership agreement requires that we distribute all of our available cash each quarter. As a result, we will have limited cash available to reinvest in our business or to fund acquisitions, and we will rely primarily upon external financing sources, including commercial bank borrowings and the issuance of debt and equity securities, to fund our acquisitions and growth capital expenditures. As such, to the extent we are unable to finance growth externally, our distribution policy will significantly impair our ability to grow.
To the extent we issue additional units in connection with any acquisitions or growth capital expenditures or as in-kind distributions, the payment of distributions on those additional units may increase the risk that we will be unable to maintain or increase our per unit distribution level. There are no limitations in our partnership agreement on our ability to issue additional units, including units ranking senior in right of distributions or liquidation to our common units. The incurrence of commercial borrowings or other debt to finance our growth strategy would result in increased interest expense, which, in turn, would reduce the available cash that we have to distribute to our unitholders. Please read "Cash Distribution Policy and Restrictions on Distributions."
The limited liability company agreement of our general partner will contain restrictive covenants, governance and other provisions that may restrict our ability to pursue our business strategies.
The limited liability company agreement of our general partner, which will be controlled by our Sponsors, will contain provisions that prohibit certain actions without a supermajority vote of at least 66 2 / 3 % of the members of the board of directors of our general partner, including:
- •
-
the incurrence of borrowings in excess of 2.5 times our Debt to EBITDAX Ratio for the preceding four quarters;
- •
-
the reservation of a portion of cash generated from operations to finance acquisitions;
- •
-
modifications to the definition of "Available Cash" in our partnership agreement; and
- •
- the issuance of any partnership interests that rank senior in right of distributions and liquidation to our common units.
Please read "The Partnership Agreement—Certain Provisions of the Agreement Governing our General Partner."
Upon the closing of this offering, the board of directors of our general partner will have nine members. Therefore, the vote of four directors would be sufficient to prevent us from
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undertaking the items discussed above. These restrictions may limit our ability to obtain future financings and acquire additional oil and gas properties. We may also be prevented from taking advantage of business opportunities that arise because of the limitations that these restrictions impose on us. Our inability to execute financings or acquire additional properties may materially adversely affect our results of operations and cash available for distribution.
All of our revenues are derived from royalty payments that are based on the price at which oil, natural gas and natural gas liquids produced from the acreage underlying our interests is sold, and we do not currently hedge these commodity prices. The volatility of these prices due to factors beyond our control greatly affects our business, financial condition, results of operations and cash available for distribution.
Our revenues, operating results, cash available for distribution and the carrying value of our oil and natural gas properties depend significantly upon the prevailing prices for oil, natural gas and natural gas liquids. Historically, oil, natural gas and natural gas liquids prices have been volatile and are subject to fluctuations in response to changes in supply and demand, market uncertainty and a variety of additional factors that are beyond our control, including:
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the domestic and foreign supply of and demand for oil, natural gas and natural gas liquids;
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the level of prices and expectations about future prices of oil, natural gas and natural gas liquids;
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the level of global oil and natural gas exploration and production;
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the cost of exploring for, developing, producing and delivering oil and natural gas;
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the price and quantity of foreign imports;
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the level of U.S. domestic production;
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political and economic conditions in oil producing regions, including the Middle East, Africa, South America and Russia;
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the ability of members of the Organization of Petroleum Exporting Countries to agree to and maintain oil price and production
controls;
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the ability of Iran to increase the export of oil and natural gas upon the relaxation of international sanctions;
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speculative trading in crude oil, natural gas and natural gas liquids derivative contracts;
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the level of consumer product demand;
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weather conditions and other natural disasters;
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risks associated with operating drilling rigs;
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- technological advances affecting energy consumption;
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domestic and foreign governmental regulations and taxes;
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the continued threat of terrorism and the impact of military and other action;
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the proximity, cost, availability and capacity of oil and natural gas pipelines and other transportation facilities;
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the price and availability of alternative fuels; and
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- overall domestic and global economic conditions.
These factors and the volatility of the energy markets make it extremely difficult to predict future oil and natural gas price movements with any certainty. For example, during the past five years, the posted price for West Texas Intermediate light sweet crude oil, which we refer to as West Texas Intermediate ("WTI"), has ranged from a low of $26.19 per Bbl in February 2016 to a high of $113.93 per Bbl in April 2011, and the Henry Hub spot market price of natural gas has ranged from a low of $1.49 per MMBtu in March 2016 to a high of $7.63 per MMBtu in February 2014. On September 30, 2016, the WTI posted price for crude oil was $48.24 per Bbl and the Henry Hub spot market price of natural gas was $2.84 per MMBtu. Additionally, natural gas liquids prices have declined from approximately $29.46 Boe in January 2015 to $28.65 Boe in August 2016. The reduction in prices has been caused by many factors, including increases in oil and natural gas production and reserves from unconventional (shale) reservoirs, without an offsetting increase in demand, as well as actions by the Organization of Petroleum Exporting Countries to maintain or raise production levels. The International Energy Agency forecasts continued low global demand growth in 2017. This environment could cause prices to remain at current levels or to fall to lower levels. Any substantial decline in the price of oil, natural gas and natural gas liquids or prolonged period of low commodity prices will materially adversely affect our business, financial condition, results of operations and cash available for distribution.
If commodity prices decrease to a level such that our future undiscounted cash flows from our properties are less than their carrying value for a significant period of time, we will be required to take write-downs of the carrying values of our properties.
Accounting rules require that we periodically review the carrying value of our properties for possible impairment. Based on specific market factors and circumstances at the time of prospective impairment reviews, and the continuing evaluation of development plans, production data, economics and other factors, we may be required to write down the carrying value of our properties. The net capitalized costs of proved oil and natural gas properties are subject to a full cost ceiling limitation for which the costs are not allowed to exceed their related estimated future net revenues discounted at 10%. To the extent capitalized costs of evaluated oil and natural gas properties, net of accumulated depreciation, depletion, amortization and impairment, exceed estimated discounted future net revenues of proved oil and natural gas reserves, the excess capitalized costs are charged to expense. The risk that we will be required to recognize impairments of our oil and natural gas properties increases during periods of low commodity prices. In addition, impairments would occur if we were to experience sufficient downward adjustments to our estimated proved reserves or the present value of estimated future net revenues. An impairment recognized in one period may not be reversed in a subsequent period even if higher oil and gas prices increase the cost center ceiling applicable to the subsequent period. During the nine months ended September 30, 2016 and the years ended December 31, 2015 and December 31, 2014, our predecessor recorded non-cash impairment charges of approximately $5.0 million, $28.7 million and $7.4 million, respectively, primarily
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due to changes in reserve values resulting from the drop in commodity prices and other factors. We may incur impairment charges in the future, which could materially adversely affect our results of operations for the periods in which such charges are taken.
We do not currently enter into hedging arrangements with respect to the oil and natural gas production from our properties, and we will be exposed to the impact of decreases in the price of oil, natural gas and natural gas liquids.
We have not entered into hedging arrangements to establish, in advance, a price for the sale of the oil, natural gas and natural gas liquids produced from our properties, and we may not enter into such arrangements in the future. As a result, although we may realize the benefit of any short-term increase in the price of oil, natural gas and natural gas liquids, we will not be protected against decreases in the price of oil, natural gas and natural gas liquids or prolonged periods of low commodity prices, which could materially adversely affect our business, results of operation and cash available for distribution.
In the future, we may enter into hedging transactions, which may not be effective in reducing the volatility of our cash flows.
In the future, we may enter into hedging transactions with the intent of reducing volatility in our cash flows due to fluctuations in the price of oil, natural gas and natural gas liquids. However, these hedging activities may not be as effective as we intend in reducing the volatility of our cash flows and, if entered into, are subject to the risks that the terms of the derivative instruments will be imperfect, a counterparty may not perform its obligations under a derivative contract, there may be a change in the expected differential between the underlying commodity price in the derivative instrument and the actual price received, our hedging policies and procedures may not be properly followed and the steps we take to monitor our derivative financial instruments may not detect and prevent violations of our risk management policies and procedures, particularly if deception or other intentional misconduct is involved. Further, we may be limited in receiving the full benefit of increases in oil, natural gas and natural gas liquids prices as a result of these hedging transactions. The occurrence of any of these risks could prevent us from realizing the benefit of a derivative contract.
We depend on unaffiliated operators for all of the exploration, development and production on the properties in which we own mineral and royalty interests. Substantially all of our revenue is derived from royalty payments made by these operators. A reduction in the expected number of wells to be drilled on the acreage underlying our interests by these operators or the failure of these operators to adequately and efficiently develop and operate the underlying acreage could materially adversely affect our results of operations and cash available for distribution.
Because we depend on our third party operators for all of the exploration, development and production on our properties, we have no control over the operations related to our properties. As of December 31, 2015, we received revenue from over 700 operators. On a pro forma basis for the year ended December 31, 2015 and for the nine months ended September 30, 2016, we received approximately 53.3% and 49.0% of our revenue from the top ten operators of our properties, respectively. If these operators do not adequately and efficiently perform operations or act in ways that are beneficial to us, our production and revenues could decline. The operators of our properties are often not obligated to undertake any development activities. In the absence of a specific contractual obligation, any development and production activities will be subject to their sole discretion (subject, however, to certain implied obligations to develop
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imposed by state law). The operators of our properties could determine to drill and complete fewer wells on our acreage than we currently expect. The success and timing of drilling and development activities on our properties, and whether the operators elect to drill any additional wells on our acreage, depends on a number of factors that will be largely outside of our control, including:
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the capital costs required for drilling activities by the operators of our properties, which could be significantly more than
anticipated;
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the ability of the operators of our properties to access capital;
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prevailing commodity prices;
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the availability of suitable drilling equipment, production and transportation infrastructure and qualified operating personnel;
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the operators' expertise, operating efficiency and financial resources;
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approval of other participants in drilling wells;
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the operators' expected return on investment in wells drilled on our acreage as compared to opportunities in other areas;
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the selection of technology;
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the selection of counterparties for the marketing and sale of production; and
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- the rate of production of the reserves.
The operators may elect not to undertake development activities, or may undertake these activities in an unanticipated fashion, which may result in significant fluctuations in our oil, natural gas and natural gas liquids revenues and cash available for distribution. Additionally, if an operator were to experience financial difficulty, the operator might not be able to pay its royalty payments or continue its operations, which could have a material adverse impact on us. Sustained reductions in production by the operators of our properties may also materially adversely affect our results of operations and cash available for distribution.
The development of our proved undeveloped reserves may take longer and may require higher levels of capital expenditures from the operators of our properties than we or they currently anticipate.
As of December 31, 2015, 28.8% of our total estimated proved reserves were proved undeveloped reserves and may not be ultimately developed or produced by the operators of our properties. Recovery of proved undeveloped reserves requires significant capital expenditures and successful drilling operations by the operators of our properties. The reserve data included in the reserve report of our independent petroleum engineer assume that substantial capital expenditures by the operators of our properties are required to develop such reserves. We typically do not have access to the estimated costs of development of these reserves or the scheduled development plans of our operators. We take into consideration the estimated costs of development or the scheduled development plans from any development provisions in the relevant lease agreement and the historical drilling activity, rig locations, production data and
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permit trends, as well as investor presentations and other public statements of our operators. The development of such reserves may take longer and may require higher levels of capital expenditures from the operators than we anticipate. Delays in the development of our reserves, increases in costs to drill and develop such reserves or decreases or continued volatility in commodity prices will reduce the future net revenues of our estimated proved undeveloped reserves and may result in some projects becoming uneconomical for the operators of our properties. In addition, delays in the development of reserves could force us to reclassify certain of our proved reserves as unproved reserves.
We may not be able to terminate our leases if any of the operators of the properties in which we own mineral interests declare bankruptcy, and we may experience delays and be unable to replace operators that do not make royalty payments.
A failure on the part of the operators of the properties in which we own mineral interests to make royalty payments typically gives us the right to terminate the lease, repossess the property and enforce payment obligations under the lease. If we repossessed any of the properties in which we own mineral interests, we would seek a replacement operator. However, we might not be able to find a replacement operator and, if we did, we might not be able to enter into a new lease on favorable terms within a reasonable period of time. In addition, the outgoing operator could be subject to bankruptcy proceedings that could prevent the execution of a new lease or the assignment of the existing lease to another operator. In addition, if we enter into a new lease, the replacement operator may not achieve the same levels of production or sell oil, natural gas or natural gas liquids at the same price as the operator it replaced.
Our future success depends on replacing reserves through acquisitions and the exploration and development activities of the operators of our properties.
Our future success depends upon our ability to acquire additional oil and natural gas reserves that are economically recoverable. Our proved reserves will generally decline as reserves are depleted, except to the extent that successful exploration or development activities are conducted on our properties or we acquire properties containing proved reserves, or both. Aside from acquisitions, we have no control over the exploration and development of our properties. In addition, we do not currently intend to retain cash from our operations for capital expenditures necessary to replace our existing oil and gas reserves or otherwise maintain an asset base. To increase reserves and production, we would need the operators of our properties to undertake replacement activities or use third parties to accomplish these activities.
Our failure to successfully identify, complete and integrate acquisitions of properties or businesses would slow our growth and could materially adversely affect our results of operations and cash available for distribution.
We depend in part on acquisitions to grow our reserves, production and cash generated from operations. Our decision to acquire a property will depend in part on the evaluation of data obtained from production reports and engineering studies, geophysical and geological analyses and seismic data, and other information, the results of which are often inconclusive and subject to various interpretations. The successful acquisition of properties requires an assessment of several factors, including:
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recoverable reserves;
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- future oil, natural gas and natural gas liquids prices and their applicable differentials;
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development plans;
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operating costs; and
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- potential environmental and other liabilities.
The accuracy of these assessments is inherently uncertain and we may not be able to identify attractive acquisition opportunities. In connection with these assessments, we perform a review of the subject properties that we believe to be generally consistent with industry practices, given the nature of our interests. Our review will not reveal all existing or potential problems nor will it permit us to become sufficiently familiar with the properties to assess fully their deficiencies and capabilities. Inspections are often not performed on every well, and environmental problems, such as groundwater contamination, are not necessarily observable even when an inspection is undertaken. Even when problems are identified, the seller may be unwilling or unable to provide effective contractual protection against all or part of the problems. Even if we do identify attractive acquisition opportunities, we may not be able to complete the acquisition or do so on commercially acceptable terms. Unless our operators further develop our existing properties, we will depend on acquisitions to grow our reserves, production and cash flow.
There is intense competition for acquisition opportunities in our industry. Competition for acquisitions may increase the cost of, or cause us to refrain from, completing acquisitions. Our ability to complete acquisitions is dependent upon, among other things, our ability to obtain debt and equity financing and, in some cases, regulatory approvals. Further, these acquisitions may be in geographic regions in which we do not currently hold assets, which could result in unforeseen operating difficulties. In addition, if we acquire interests in new states, we may be subject to additional and unfamiliar legal and regulatory requirements. Compliance with regulatory requirements may impose substantial additional obligations on us and our management, cause us to expend additional time and resources in compliance activities and increase our exposure to penalties or fines for non-compliance with such additional legal requirements. Further, the success of any completed acquisition will depend on our ability to integrate effectively the acquired business into our existing business. The process of integrating acquired businesses may involve unforeseen difficulties and may require a disproportionate amount of our managerial and financial resources. In addition, possible future acquisitions may be larger and for purchase prices significantly higher than those paid for earlier acquisitions.
No assurance can be given that we will be able to identify suitable acquisition opportunities, negotiate acceptable terms, obtain financing for acquisitions on acceptable terms or successfully acquire identified targets. Our failure to minimize any unforeseen difficulties could materially adversely affect our financial condition and cash available for distribution. The inability to effectively manage these acquisitions could reduce our focus on subsequent acquisitions, which, in turn, could negatively impact our growth and cash available for distribution.
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Any acquisitions of additional mineral and royalty interests that we complete will be subject to substantial risks.
Even if we do make acquisitions that we believe will increase our cash generated from operations, these acquisitions may nevertheless result in a decrease in our cash distributions per unit. Any acquisition involves potential risks, including, among other things:
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the validity of our assumptions about estimated proved reserves, future production, prices, revenues, capital expenditures and
production costs;
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a decrease in our liquidity by using a significant portion of our cash generated from operations or borrowing capacity to finance
acquisitions;
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a significant increase in our interest expense or financial leverage if we incur debt to finance acquisitions;
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the assumption of unknown liabilities, losses, or costs for which we are not indemnified or for which any indemnity we receive is
inadequate;
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mistaken assumptions about the overall cost of equity or debt;
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our ability to obtain satisfactory title to the assets we acquire;
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an inability to hire, train, or retain qualified personnel to manage and operate our growing business and assets; and
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- the occurrence of other significant changes, such as impairment of oil and natural gas properties, goodwill or other intangible assets, asset devaluation, or restructuring charges.
If we are unable to make acquisitions on economically acceptable terms from our Sponsors, the Contributing Parties or third parties, our future growth will be limited.
Our ability to grow depends in part on our ability to make acquisitions that increase our cash generated from our mineral and royalty interests. The acquisition component of our strategy is based, in large part, on our expectation of ongoing acquisitions from industry participants, including our Sponsors and the Contributing Parties. While we believe the Contributing Parties, including affiliates of our Sponsors, will be incentivized through their direct and indirect ownership of common units to offer us the opportunity to acquire additional mineral and royalty interests, including with respect to certain assets for which certain of the Contributing Parties have granted us a right of first offer for a period of three years after the closing of this offering, should they choose to sell such assets, there can be no assurance that any such offer will be made, and there can be no assurance we will reach agreement on the terms with respect to the assets or any other acquisition opportunities offered to us by any of our Sponsors and the Contributing Parties or be able to obtain financing for such acquisition opportunities. Furthermore, many factors could impair our access to future acquisitions, including a change in control of any of our Sponsors and the Contributing Parties. A material decrease in the sale of oil and natural gas properties by any of our Sponsors and the Contributing Parties or by third parties would limit our opportunities for future acquisitions and could materially adversely affect our business, results of operations, financial condition and ability to pay quarterly cash distributions to our unitholders.
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Project areas on our properties, which are in various stages of development, may not yield oil or natural gas in commercially viable quantities.
Project areas on our properties are in various stages of development, ranging from project areas with current drilling or production activity to project areas that have limited drilling or production history. If the wells in the process of being completed do not produce sufficient revenues or if dry holes are drilled, our financial condition, results of operations and cash available for distribution may be materially adversely affected.
Our estimated reserves are based on many assumptions that may prove to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.
It is not possible to measure underground accumulations of oil or natural gas in an exact way. Oil and natural gas reserve engineering requires subjective estimates of underground accumulations of oil and natural gas and assumptions concerning future oil and natural gas prices, production levels, ultimate recoveries and operating and development costs. As a result, estimated quantities of proved reserves, projections of future production rates and the timing of development expenditures may prove to be incorrect.
Our historical estimates of proved reserves and related valuations as of December 31, 2015 were prepared by Ryder Scott, an independent petroleum engineering firm, which conducted a well-by-well review of all our properties for the period covered by its reserve report using information provided by us. Over time, we may make material changes to reserve estimates taking into account the results of actual drilling, testing and production and changes in prices. Some of our reserve estimates were made without the benefit of a lengthy production history, which are less reliable than estimates based on a lengthy production history. In estimating our reserves, we and our reserve engineers make certain assumptions that may prove to be incorrect, including assumptions regarding future oil and natural gas prices, production levels and operating and development costs. Any significant variance from these assumptions to actual figures could greatly affect our estimates of reserves, the economically recoverable quantities of oil and natural gas attributable to any particular group of properties, the classifications of reserves based on risk of recovery and estimates of future net cash flows. Numerous changes over time to the assumptions on which our reserve estimates are based, as described above, often result in the actual quantities of oil and natural gas that are ultimately recovered being different from our reserve estimates.
The present value of future net cash flows from our proved reserves is not necessarily the same as the current market value of our estimated reserves. In accordance with rules established by the SEC and the Financial Accounting Standards Board (the "FASB"), we base the estimated discounted future net cash flows from our proved reserves on the twelve-month average oil and gas index prices, calculated as the unweighted arithmetic average for the first-day-of-the-month price for each month, and costs in effect on the date of the estimate, holding the prices and costs constant throughout the life of the properties. Actual future prices and costs may differ materially from those used in the present value estimate, and future net present value estimates using then current prices and costs may be significantly less than the current estimate. In addition, the 10% discount factor we use when calculating discounted future net cash flows may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the oil and natural gas industry in general.
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SEC rules could limit our ability to book additional proved undeveloped reserves in the future.
SEC rules require that, subject to limited exceptions, proved undeveloped reserves may only be booked if they relate to wells scheduled to be drilled within five years after the date of booking. This requirement has limited and may continue to limit our ability to book additional proved undeveloped reserves as the operators of our properties pursue their drilling programs. Moreover, we may be required to write down our proved undeveloped reserves if those wells are not drilled within the required five-year timeframe. Furthermore, we typically do not have access to the drilling schedules of our operators and make our determinations about their estimated drilling schedules from any development provisions in the relevant lease agreement and the historical drilling activity, rig locations, production data and permit trends, as well as investor presentations and other public statements of our operators.
Restrictions in our secured revolving credit facility and future debt agreements could limit our growth and our ability to engage in certain activities, including our ability to pay distributions to our unitholders.
Upon completion of this offering, we expect to enter into a $50.0 million secured revolving credit facility with an accordion feature permitting aggregate commitments under the facility to be increased up to $100.0 million (subject to the satisfaction of certain conditions and the procurement of additional commitments from new or existing lenders). Our secured revolving credit facility will be secured by substantially all of our assets. We expect our secured revolving credit facility will contain various covenants and restrictive provisions that will limit our ability to, among other things:
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incur or guarantee additional debt;
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make distributions on, or redeem or repurchase, common units, including if an event of default or borrowing base deficiency exists;
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make certain investments and acquisitions;
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incur certain liens or permit them to exist;
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enter into certain types of transactions with affiliates;
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merge or consolidate with another company; and
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- transfer, sell or otherwise dispose of assets.
We expect our secured revolving credit facility will also contain covenants requiring us to maintain the following financial ratios or to reduce our indebtedness if we are unable to comply with such ratios: (i) a Debt to EBITDAX Ratio (as more fully defined in the secured revolving credit facility) of not more than 4.0 to 1.0; and (ii) a ratio of current assets to current liabilities of not less than 1.0 to 1.0. Our ability to meet those financial ratios and tests can be affected by events beyond our control. These restrictions may also limit our ability to obtain future financings to withstand a future downturn in our business or the economy in general, or to otherwise conduct necessary corporate activities. We may also be prevented from taking advantage of business opportunities that arise because of the limitations that the restrictive covenants under our secured revolving credit facility will impose on us.
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A failure to comply with the provisions of our secured revolving credit facility could result in an event of default, which could enable the lenders to declare, subject to the terms and conditions of our secured revolving credit facility, any outstanding principal of that debt, together with accrued and unpaid interest, to be immediately due and payable. If the payment of the debt is accelerated, cash flows from our operations may be insufficient to repay such debt in full, and our unitholders could experience a partial or total loss of their investment. We expect our secured revolving credit facility will contain events of default customary for transactions of this nature, including the occurrence of a change of control. Please read "Management's Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Indebtedness—New Revolving Credit Agreement."
Any significant reduction in our borrowing base under our new secured revolving credit facility as a result of the periodic borrowing base redeterminations or otherwise may negatively impact our ability to fund our operations.
We further anticipate that our secured revolving credit facility will limit the amounts we can borrow up to a borrowing base amount, which the lenders, in their sole discretion, determine on a semi-annual basis based upon projected revenues from the oil and natural gas properties securing our loan. The borrowing base will be determined based on our oil and gas properties and the oil and gas properties of our wholly owned subsidiaries. We expect to have non-wholly owned subsidiaries whose assets are not subject to a lien and not included in borrowing base valuations. The lenders can unilaterally adjust the borrowing base and the borrowings permitted to be outstanding under our secured revolving credit facility. Any increase in the borrowing base requires the consent of the lenders holding 100% of the commitments. If the requisite number of lenders do not agree to an increase, then the borrowing base will be the lowest borrowing base acceptable to such lenders. Decreases in the available borrowing amount could result from declines in oil and natural gas prices, operating difficulties or increased costs, declines in reserves, lending requirements or regulations or certain other circumstances. Outstanding borrowings in excess of the borrowing base must be repaid, or we must pledge other oil and natural gas properties as additional collateral after applicable grace periods. We do not expect to have any substantial unpledged properties, and we may not have the financial resources in the future to make mandatory principal prepayments required under our secured revolving credit facility.
Our debt levels may limit our flexibility to obtain additional financing and pursue other business opportunities.
Our existing and future indebtedness could have important consequences to us, including:
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our ability to obtain additional financing, if necessary, for working capital, capital expenditures, acquisitions or other purposes
may be impaired or such financing may not be available on terms acceptable to us;
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covenants in our existing and future credit and debt arrangements will require us to meet financial tests that may affect our
flexibility in planning for and reacting to changes in our business, including possible acquisition opportunities;
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our access to the capital markets may be limited;
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- our borrowing costs may increase;
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we will need a substantial portion of our cash flow to make principal and interest payments on our indebtedness, reducing the funds
that would otherwise be available for operations, future business opportunities and distributions to unitholders; and
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- our debt level will make us more vulnerable than our competitors with less debt to competitive pressures or a downturn in our business or the economy generally.
Our ability to service our indebtedness will depend upon, among other things, our future financial and operating performance, which will be affected by prevailing economic conditions and financial, business, regulatory and other factors, some of which are beyond our control. If our operating results are not sufficient to service our current or future indebtedness, we will be forced to take actions such as reducing distributions, reducing or delaying business activities, acquisitions, investments and/or capital expenditures, selling assets, restructuring or refinancing our indebtedness, or seeking additional equity capital or bankruptcy protection. We may not be able to effect any of these remedies on satisfactory terms or at all.
We do not intend to retain cash from our operations for replacement capital expenditures. Unless we replenish our oil and natural gas reserves, our cash generated from operations and our ability to pay distributions to our unitholders could be materially adversely affected.
Producing oil and natural gas wells are characterized by declining production rates that vary depending upon reservoir characteristics and other factors. Our future oil and natural gas reserves and the operators' production thereof and our cash generated from operations and ability to pay distributions are highly dependent on the successful development and exploitation of our current reserves. Based on our reserve report as of December 31, 2015, the average estimated five-year decline rate for our existing proved developed producing reserves is 10%. However, the production decline rates of our properties may be significantly higher than currently estimated if the wells on our properties do not produce as expected. We may also not be able to acquire additional reserves to replace the current and future production of our properties at economically acceptable terms, which could materially adversely affect our business, financial condition, results of operations and cash available for distribution.
We are unlikely to be able to sustain or increase distributions without making accretive acquisitions or capital expenditures that maintain or grow our asset base. We will need to make substantial capital expenditures to maintain and grow our asset base, which will reduce our cash available for distribution. We do not intend to retain cash from our operations for replacement capital expenditures primarily due to our expectation that the continued development of our properties and completion of drilled but uncompleted wells by working interest owners will substantially offset the natural production declines from our existing wells. Please read "Cash Distribution Policy and Restrictions on Distributions."
Over a longer period of time, if we do not set aside sufficient cash reserves or make sufficient expenditures to maintain or grow our asset base, we would expect to reduce our distributions. With our reserves decreasing, if we do not reduce our distributions, then a portion of the distributions may be considered a return of part of your investment in us as opposed to a return on your investment.
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A deterioration in general economic, business or industry conditions would materially adversely affect our results of operations, financial condition and cash available for distribution.
In recent years, concerns over global economic conditions, energy costs, geopolitical issues, inflation, the availability and cost of credit, and slow economic growth in the United States have contributed to economic uncertainty and diminished expectations for the global economy. Meanwhile, continued hostilities in the Middle East and the occurrence or threat of terrorist attacks in the United States or other countries could adversely affect the economies of the United States and other countries. Concerns about global economic growth have had a significant adverse impact on global financial markets and commodity prices. With current global economic growth slowing, demand for oil, natural gas and natural gas liquid production has, in turn, softened. An oversupply of crude oil in 2015 led to a severe decline in worldwide oil prices. If the economic climate in the United States or abroad deteriorates further, worldwide demand for petroleum products could further diminish, which could impact the price at which oil, natural gas and natural gas liquids from our properties are sold, affect the ability of vendors, suppliers and customers associated with our properties to continue operations and ultimately materially adversely impact our results of operations, financial condition and cash available for distribution.
Conservation measures and technological advances could reduce demand for oil and natural gas.
Fuel conservation measures, alternative fuel requirements, increasing consumer demand for alternatives to oil and natural gas, technological advances in fuel economy and energy-generation devices could reduce demand for oil and natural gas. The impact of the changing demand for oil and natural gas services and products may materially adversely affect our business, financial condition, results of operations and cash available for distribution.
Competition in the oil and natural gas industry is intense, which may adversely affect our operators' ability to succeed.
The oil and natural gas industry is intensely competitive, and the operators of our properties compete with other companies that may have greater resources. Many of these companies explore for and produce oil and natural gas, carry on midstream and refining operations, and market petroleum and other products on a regional, national or worldwide basis. In addition, these companies may have a greater ability to continue exploration activities during periods of low oil and natural gas market prices. Our operators' larger competitors may be able to absorb the burden of present and future federal, state, local and other laws and regulations more easily than our operators can, which would adversely affect our operators' competitive position. Our operators may have fewer financial and human resources than many companies in our operators' industry, and may be at a disadvantage in bidding for exploratory prospects and producing oil and natural gas properties.
We rely on a few key individuals whose absence or loss could materially adversely affect our business.
Many key responsibilities within our business have been assigned to a small number of individuals. We rely on our founders for their knowledge of the oil and natural gas industry, relationships within the industry and experience in identifying, evaluating and completing acquisitions. In connection with the closing of this offering, we will enter into a management services agreement with Kimbell Operating, which will enter into separate service agreements
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with certain entities controlled by Messrs. Duncan, R. Ravnaas, Taylor and Wynne, pursuant to which they and Kimbell Operating will provide management, administrative and operational services to us. In addition, under each of their respective service agreements, Messrs. R. Ravnaas, Taylor and Wynne will identify, evaluate and recommend to us acquisition opportunities and negotiate the terms of such acquisitions. The loss of their services, or the services of one or more members of our executive team or those providing services to us pursuant to a contract, could materially adversely affect our business. Further, we do not maintain "key person" life insurance policies on any of our executive team or other key personnel. As a result, we are not insured against any losses resulting from the death of these key individuals.
Increased costs of capital could materially adversely affect our business.
Our business, ability to make acquisitions and operating results could be harmed by factors such as the availability, terms and cost of capital or increases in interest rates. Changes in any one or more of these factors could cause our cost of doing business to increase, limit our access to capital, limit our ability to pursue acquisition opportunities, and place us at a competitive disadvantage. A significant reduction in the availability of credit could materially and adversely affect our ability to achieve our planned growth and operating results.
Loss of our or our operators' information and computer systems could materially adversely affect our business.
We are dependent on our and our operators' information systems and computer-based programs. If any of such programs or systems were to fail for any reason, including as a result of a cyber-attack, or create erroneous information in our or our operators' hardware or software network infrastructure, possible consequences include loss of communication links and inability to automatically process commercial transactions or engage in similar automated or computerized business activities. We also rely on a third party service provider to perform some of our data entry functions. If the programs or systems used by our third party service provider are not adequately functioning, we could experience loss of important data. Any of the foregoing consequences could materially adversely affect our business.
A terrorist attack or armed conflict could harm our business.
Terrorist activities, anti-terrorist activities and other armed conflicts involving the United States or other countries may adversely affect the United States and global economies. If any of these events occur, the resulting political instability and societal disruption could reduce overall demand for oil and natural gas, potentially putting downward pressure on demand for our operators' services and causing a reduction in our revenues. Oil and natural gas facilities, including those of our operators, could be direct targets of terrorist attacks, and if infrastructure integral to our operators is destroyed or damaged, they may experience a significant disruption in their operations. Any such disruption could materially adversely affect our financial condition, results of operations and cash available for distribution.
Title to the properties in which we have an interest may be impaired by title defects.
We may not elect to incur the expense of retaining lawyers to examine the title to the mineral interest. Rather, we may rely upon the judgment of oil and gas lease brokers or landmen who perform the fieldwork in examining records in the appropriate governmental office before attempting to acquire a lease in a specific mineral interest. The existence of a material title deficiency can render an interest worthless and can materially adversely affect our results of
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operations, financial condition and cash available for distribution. No assurance can be given that we will not suffer a monetary loss from title defects or title failure. Additionally, undeveloped acreage has greater risk of title defects than developed acreage. If there are any title defects or defects in assignment of leasehold rights in properties in which we hold an interest, we will suffer a financial loss.
The Contributing Parties will have limited indemnity obligations to us for liabilities arising out of the ownership and operation of our assets prior to the closing of this offering, including title defects.
In connection with this offering, we have entered into a contribution agreement with the Contributing Parties that will govern, among other things, their obligation to indemnify us for certain liabilities associated with the entities and assets being contributed to us in connection with this offering. Under the contribution agreement, the Contributing Parties will be required, severally but not jointly, to indemnify us (i) for a period of one year following the closing of this offering, for breaches of specified representations and warranties related to, among other things, (x) their authority to enter into the transactions contemplated by the contribution agreement and (y) the capitalization of the entities that will be contributed to us; and (ii) for any federal, state and local income tax liabilities attributable to the ownership and operation of the mineral and royalty interests and the associated entities prior to the closing of this offering until 30 days after the applicable statute of limitations. In addition, pursuant to the contribution agreement, the Contributing Parties will, severally but not jointly, indemnify us for losses arising from certain liens and title defects created during their ownership of the entities and assets contributed to us in connection with this offering.
Except as otherwise described above, the Contributing Parties are not required to indemnify us for breaches of any other representations and warranties under the contribution agreement, including breaches related to other title matters, consents and permits or compliance with environmental laws, and such other representations and warranties will not survive the closing of this offering. Moreover, the representations, warranties and indemnities provided by the Contributing Parties are subject to significant limitations, including indemnity caps, and may not protect us against all liabilities or other problems associated with the entities and assets being contributed to us in connection with this offering. For example, the existence of a material title deficiency covering a material amount of our assets can render a lease worthless and could materially adversely affect our financial condition, results of operations and cash available for distribution. We do not obtain title insurance covering mineral leaseholds, and our failure to cure any title defects may delay or prevent us from realizing the benefits of ownership of the mineral interest, which may adversely impact our ability in the future to increase production and reserves. Additionally, undeveloped acreage has greater risk of title defects than developed acreage. If there are any title defects, or defects in the assignment of leasehold rights in properties in which we hold an interest, our business, results of operations and cash available for distribution may be adversely affected.
The indemnities that the Contributing Parties have agreed to provide under the contribution agreement may be inadequate to fully compensate us for losses we may suffer or incur as a result of liabilities arising out of the ownership and operation of our assets prior to the closing of this offering. Even if we are insured or indemnified against such risks, we may be responsible for costs or penalties to the extent our insurers or indemnitors do not fulfill their obligations to us, and the payment of any such costs or penalties could be significant. The occurrence of any losses that are neither indemnified for under the contribution agreement nor covered under our insurance plans could materially adversely affect our financial condition, results of operations
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and cash available for distribution. Please read "Certain Relationships and Related Party Transactions—Agreements and Transactions with Affiliates in Connection with this Offering—Contribution Agreement—Indemnification."
The potential drilling locations identified by the operators of our properties are susceptible to uncertainties that could materially alter the occurrence or timing of their drilling.
The ability of the operators of our properties to drill and develop identified potential drilling locations depends on a number of uncertainties, including the availability of capital, construction of infrastructure, inclement weather, regulatory changes and approvals, oil and natural gas prices, costs, drilling results and the availability of water. Further, the potential drilling locations identified by the operators of our properties are in various stages of evaluation, ranging from locations that are ready to drill to locations that will require substantial additional interpretation. The use of technologies and the study of producing fields in the same area will not enable the operators of our properties to know conclusively prior to drilling whether oil or natural gas will be present or, if present, whether oil or natural gas will be present in sufficient quantities to be economically viable. Even if sufficient amounts of oil or natural gas exist, the operators of our properties may damage the potentially productive hydrocarbon-bearing formation or experience mechanical difficulties while drilling or completing the well, possibly resulting in a reduction in production from the well or abandonment of the well. If the operators of our properties drill additional wells that they identify as dry holes in current and future drilling locations, their drilling success rate may decline and materially harm their business as well as ours.
We cannot assure you that the analogies our operators draw from available data from the wells on our acreage, more fully explored locations, or producing fields will be applicable to their drilling locations. Further, initial production rates reported by our or other operators in the areas in which our reserves are located may not be indicative of future or long-term production rates. Because of these uncertainties, we do not know if the potential drilling locations our operators have identified will ever be drilled or if our operators will be able to produce oil or natural gas from these or any other potential drilling locations. As such, the actual drilling activities of the operators of our properties may materially differ from those presently identified, which could materially adversely affect our business, results of operation and cash available for distribution.
Acreage must be drilled before lease expiration, generally within three to five years, in order to hold the acreage by production. Our operators' failure to drill sufficient wells to hold acreage may result in loss of the lease and prospective drilling opportunities.
Leases on oil and natural gas properties typically have a term of three to five years, after which they expire unless, prior to expiration, production is established within the spacing units covering the undeveloped acres. Any reduction in our operators' drilling programs, either through a reduction in capital expenditures or the unavailability of drilling rigs, could result in the loss of acreage through lease expirations which may terminate our overriding royalty interests derived from such leases. If our royalties are derived from mineral interests and production or drilling ceases on the leased property, the lease is typically terminated, subject to certain exceptions, and all mineral rights revert back to us and we will have to seek new lessees to explore and develop such mineral interests. Any such losses of our operators or lessees could materially and adversely affect the growth of our financial condition, results of operations and cash available for distribution.
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The unavailability, high cost, or shortages of rigs, equipment, raw materials, supplies or personnel may restrict or result in increased costs for operators related to developing and operating our properties.
The oil and natural gas industry is cyclical, which can result in shortages of drilling rigs, equipment, raw materials (particularly sand and other proppants), supplies and personnel. When shortages occur, the costs and delivery times of rigs, equipment, and supplies increase and demand for, and wage rates of, qualified drilling rig crews also rise with increases in demand. We cannot predict whether these conditions will exist in the future and, if so, what their timing and duration will be. In accordance with customary industry practice, the operators of our properties rely on independent third party service providers to provide many of the services and equipment necessary to drill new wells. If the operators of our properties are unable to secure a sufficient number of drilling rigs at reasonable costs, our financial condition and results of operations could suffer. In addition, they may not have long-term contracts securing the use of their rigs, and the operator of those rigs may choose to cease providing services to them. Shortages of drilling rigs, equipment, raw materials (particularly sand and other proppants), supplies, personnel, trucking services, tubulars, fracking and completion services and production equipment could delay or restrict our operators' exploration and development operations, which in turn could materially adversely affect our financial condition, results of operations and cash available for distribution.
The results of exploratory drilling in shale plays will be subject to risks associated with drilling and completion techniques and drilling results may not meet our expectations for reserves or production.
The operators of our properties may use the latest drilling and completion techniques in their operations, and these techniques come with inherent risks. Certain of the new techniques that the operators of our properties may adopt, such as horizontal drilling, infill drilling and multi-well pad drilling, may cause irregularities or interruptions in production due to, in the case of infill drilling, offset wells being shut in and, in the case of multi-well pad drilling, the time required to drill and complete multiple wells before these wells begin producing. The results of drilling in new or emerging formations are more uncertain initially than drilling results in areas that are more developed and have a longer history of established production. Newer or emerging formations and areas often have limited or no production history and consequently the operators of our properties will be less able to predict future drilling results in these areas.
Ultimately, the success of these drilling and completion techniques can only be evaluated over time as more wells are drilled and production profiles are established over a sufficiently long time period. If our operators' drilling results are weaker than anticipated or they are unable to execute their drilling program on our properties because of capital constraints, lease expirations, access to gathering systems, or declines in oil and natural gas prices, our operating and financial results in these areas may be lower than we anticipate. Further, as a result of any of these developments we could incur material write-downs of our oil and natural gas properties and the value of our undeveloped acreage could decline, and our results of operations and cash available for distribution could be materially adversely affected.
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The marketability of oil and natural gas production is dependent upon transportation and other facilities, certain of which neither we nor the operators of our properties control. If these facilities are unavailable, our operators' operations could be interrupted and our results of operations and cash available for distribution could be materially adversely affected.
The marketability of our operators' oil and natural gas production will depend in part upon the availability, proximity and capacity of transportation facilities, including gathering systems, trucks and pipelines, owned by third parties. Neither we nor the operators of our properties control these third party transportation facilities and our operators' access to them may be limited or denied. Insufficient production from the wells on our acreage or a significant disruption in the availability of third party transportation facilities or other production facilities could adversely impact our operators' ability to deliver to market or produce oil and natural gas and thereby cause a significant interruption in our operators' operations. If they are unable, for any sustained period, to implement acceptable delivery or transportation arrangements or encounter production related difficulties, they may be required to shut in or curtail production. In addition, the amount of oil and natural gas that can be produced and sold may be subject to curtailment in certain other circumstances outside of our or our operators' control, such as pipeline interruptions due to maintenance, excessive pressure, inability of downstream processing facilities to accept unprocessed gas, physical damage to the gathering system or transportation system or lack of contracted capacity on such systems. The curtailments arising from these and similar circumstances may last from a few days to several months. In many cases, we and our operators are provided with limited notice, if any, as to when these curtailments will arise and the duration of such curtailments. Any such shut in or curtailment, or an inability to obtain favorable terms for delivery of the oil and natural gas produced from our acreage, could materially adversely affect our financial condition, results of operations and cash available for distribution.
Oil and natural gas operations are subject to various governmental laws and regulations. Compliance with these laws and regulations can be burdensome and expensive, and failure to comply could result in significant liabilities, which could reduce our cash available for distribution.
Operations on the properties in which we hold interests are subject to various federal, state and local governmental regulations that may be changed from time to time in response to economic and political conditions. Matters subject to regulation include drilling operations, discharges or releases of pollutants or wastes and production and conservation matters (discussed in more detail below). From time to time, regulatory agencies have imposed price controls and limitations on production by restricting the rate of flow of oil and natural gas wells below actual production capacity to conserve supplies of oil and natural gas. In addition, the production, handling, storage, transportation, remediation, emission and disposal of oil and natural gas, by-products thereof and other substances and materials produced or used in connection with oil and natural gas operations are subject to regulation under federal, state and local laws and regulations primarily relating to protection of human health and safety and the environment. Failure to comply with these laws and regulations by the operators of our properties may result in the assessment of sanctions, including administrative, civil or criminal penalties, permit revocations, requirements for additional pollution controls and injunctions limiting or prohibiting some or all of their operations. Moreover, these laws and regulations have continually imposed increasingly strict requirements for water and air pollution control and solid waste management.
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Laws and regulations governing exploration and production may also affect production levels. The operators of our properties must comply with federal and state laws and regulations governing conservation matters, including:
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provisions related to the unitization or pooling of the oil and natural gas properties;
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the establishment of maximum rates of production from wells;
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the spacing of wells;
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the plugging and abandonment of wells; and
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- the removal of related production equipment.
Additionally, state and federal regulatory authorities may expand or alter applicable pipeline safety laws and regulations, compliance with which may require increased capital costs on the part of operators and third party downstream natural gas transporters.
The operators of our properties must also comply with laws and regulations prohibiting fraud and market manipulations in energy markets. To the extent the operators of our properties are shippers on interstate pipelines, they must comply with the tariffs of those pipelines and with federal policies related to the use of interstate capacity.
The operators of our properties may be required to make significant expenditures to comply with the governmental laws and regulations described above and are subject to potential fines and penalties if they are found to have violated these laws and regulations. These and other potential regulations could increase the operating costs of the operators and delay production from our properties, which could reduce the amount of cash available for distribution to our unitholders.
The operators of our properties are subject to complex and evolving environmental and occupational health and safety laws and regulations. As a result, they may incur significant delays, costs and liabilities that could materially adversely affect our business and financial condition.
The operators of our properties may incur significant delays, costs and liabilities as a result of environmental and occupational health and safety laws and regulations applicable to their exploration, development and production activities on our properties. These delays, costs and liabilities could arise under a wide range of federal, regional, state and local laws and regulations relating to protection of the environment and worker health and safety. These laws, regulations, and enforcement policies have become increasingly strict over time, resulting in longer waiting periods to receive permits and other regulatory approvals, and we believe this trend will continue. These laws include, but are not limited to, the federal Clean Air Act (and comparable state laws and regulations that impose obligations related to air emissions), the federal Water Pollution Control Act of 1972 ("Clean Water Act") and Oil Pollution Act ("OPA") (and comparable state laws and regulations that impose requirements related to discharges of pollutants into regulated bodies of water), the federal Resource Conservation and Recovery Act, as amended ("RCRA") (and comparable state laws that impose requirements for the handling and disposal of waste), the federal Comprehensive Environmental Response, Compensation and Liability Act, as amended ("CERCLA"), also known as the "Superfund" law, and the community right to know regulations under Title III of the act (and comparable state laws that regulate the
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cleanup of hazardous substances that may have been released at properties currently or previously owned or operated by our operators or at locations our operators sent waste for disposal and comparable state laws that require organization and/or disclosure of information about hazardous materials our operators use or produce), the federal Occupational Safety and Health Act (which establishes workplace standards for the protection of health and safety of employees and requires a hazardous communications program) and the Endangered Species Act and the Migratory Bird Treaty Act (and comparable state laws that seek to ensure activities do not jeopardize endangered or threatened animals, fish, plant species by limiting or prohibiting construction activities in areas that are inhabited by such species and penalizing the taking, killing or possession of migratory birds).
Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, imposition of cleanup and site restoration costs and liens, and, in some instances, issuance of orders or injunctions limiting or requiring discontinuation of certain operations. Additionally, actions taken by federal or state agencies under these laws and regulations, such as the designation of previously unprotected species as being endangered or threatened or the designation of previously unprotected areas as a critical habitat for such species, can cause the operators of our properties to incur additional costs or become subject to operating restrictions.
Strict, joint and several liabilities may be imposed under certain environmental laws, which could cause the operators of our properties to become liable for the conduct of others or for consequences of our operators' actions that were in compliance with all applicable laws at the time those actions were taken. In addition, claims for damages to persons or property, including natural resources, may result from the environmental and worker health and safety impacts of operations by the operators of our properties. Also, new laws, regulations or enforcement policies could be more stringent and impose unforeseen liabilities, significantly increase our operating or compliance costs, reduce our liquidity, delay or halt our operations or otherwise alter the way we conduct our business. If the operators of our properties are not able to recover the resulting costs through insurance or increased revenues, our business, financial condition or results of operations could be materially and adversely affected. Please read "Business—Regulation" for a description of the laws and regulations that affect the operators of our properties and that may affect us.
Federal and state legislative and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays.
The operators of our properties use hydraulic fracturing for the completion of their wells. Hydraulic fracturing is a process that involves pumping fluid and proppant at high pressure into a hydrocarbon bearing formation to create and hold open fractures. Those fractures enable gas or oil to move through the formation's pores to the wellbore. Typically, the fluid used in this process is primarily water. In plays where hydraulic fracturing is necessary for successful development, the demand for water may exceed the supply. If the operators of our properties are unable to obtain water to use in their operations from local sources or are unable to effectively utilize flowback water, they may be unable to economically drill for or produce oil and natural gas, which could materially adversely affect our financial condition, results of operations and cash available for distribution.
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Various federal, state and local initiatives are underway to investigate or regulate hydraulic fracturing. The adoption of new laws or regulations imposing additional permitting, disclosures, restrictions or costs related to hydraulic fracturing or restricting or even banning hydraulic fracturing in certain circumstances could make drilling certain wells less economically attractive to or impossible for the operators of our properties, which could materially adversely affect our business, results of operations, financial condition and ability to pay cash distributions to our unitholders.
Certain governmental reviews have been conducted or are underway that focus on the potential environmental impacts of hydraulic fracturing. These ongoing or proposed studies could spur initiatives to further regulate hydraulic fracturing and could ultimately make it more difficult or costly for the operators of our properties to perform fracturing and increase the costs of compliance and doing business. Additional legislation or regulation could also make it easier for parties opposing the hydraulic fracturing process to initiate legal proceedings based on allegations that specific chemicals used in the fracturing process could adversely affect groundwater. There has also been increasing public controversy regarding hydraulic fracturing with regard to the use of fracturing fluids, impacts on drinking water supplies, the use of water and the potential for impacts to surface water, groundwater and the environment generally. A number of lawsuits and enforcement actions have been initiated at the state level implicating hydraulic fracturing practices. The imposition of stringent new regulatory and permitting requirements related to the practice of hydraulic fracturing could significantly increase our cost of doing business, could create adverse effects on our operators, including creating delays related to the issuance of permits and, depending on the specifics of any particular proposal that is enacted, could be material.
State and federal regulatory agencies recently have focused on a possible connection between the hydraulic fracturing related activities, particularly the disposal of produced water in underground injection wells, and the increased occurrence of seismic activity. When caused by human activity, such events are called induced seismicity. In some instances, operators of injection wells in the vicinity of seismic events have been ordered to reduce injection volumes or suspend operations. Some state regulatory agencies, including those in Colorado, Ohio, Oklahoma and Texas, have modified their regulations to account for induced seismicity. For example, following earthquakes in and around Cushing, Oklahoma, the Oklahoma Corporation Commission announced plans on November 7, 2016, to shut down or reduce the volume of disposal at certain injection wells that discharge into the Arbuckle formation. Regulatory agencies at all levels are continuing to study the possible linkage between oil and gas activity and induced seismicity. These developments could result in additional regulation and restrictions on the use of injection wells and hydraulic fracturing. Such regulations and restrictions could cause delays and impose additional costs and restrictions on the operators of our properties and on their waste disposal activities. Please read "Business—Regulation" for a description of the laws and regulations that affect the operators of our properties and that may affect us.
The adoption of climate change legislation and regulations could result in increased operating costs and reduced demand for the oil and natural gas that our operators produce.
In response to findings that emissions of carbon dioxide, methane and other greenhouse gases ("GHGs") present an endangerment to public health and the environment, the EPA has adopted regulations under existing provisions of the federal Clean Air Act that, among other things, require preconstruction and operating permits for certain large stationary sources. Facilities required to obtain preconstruction permits for their GHG emissions also will be
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required to meet "best available control technology" standards that will be established on a case-by-case basis. These EPA rulemakings could adversely affect operations on our properties and restrict or delay the ability of our operators to obtain air permits for new or modified sources. In addition, the EPA has adopted rules requiring the monitoring and reporting of GHG emissions from specified onshore oil and natural gas production sources in the United States on an annual basis, which include operations on certain of our properties. These requirements could increase the costs of development and production, reducing the profits available to us and potentially impairing our operator's ability to economically develop our properties. Please read "Business—Regulation" for a description of the laws and regulations that affect the operators of our properties and that may affect us.
Efforts have been made and continue to be made in the international community toward the adoption of international treaties or protocols that would address global climate change issues. For example, in April 2016, the United States was one of 175 countries to sign the Paris Agreement, which requires member countries to review and "represent a progression" in their intended nationally determined contributions, which set GHG emission reduction goals, every five years beginning in 2020. The Paris Agreement entered into force in November 2016. The United States is one of more than 70 nations that has ratified or otherwise indicated that it intends to comply with the agreement. These and other initiatives or regulatory changes could result in increased costs of development and production, reducing the profits available to us and potentially impairing our operators' ability to economically develop our properties.
While Congress has from time to time considered legislation to reduce emissions of GHGs, there has not been significant activity in the form of adopted legislation to reduce GHG emissions at the federal level in recent years. In the absence of federal climate legislation, a number of state and regional efforts have emerged that are aimed at tracking or reducing GHG emissions by means of cap and trade programs. These programs typically require major sources of GHG emissions to acquire and surrender emission allowances in return for emitting those GHGs. Although it is not possible at this time to predict how legislation or new regulations that may be adopted to address GHG emissions would impact our business, any future laws and regulations imposing reporting obligations on, or limiting emissions of GHGs from, our operators' equipment and operations could require them to incur costs to reduce emissions of GHGs associated with their operations. In addition, substantial limitations on GHG emissions could adversely affect demand for the oil and natural gas produced from our properties. Restrictions on emissions of methane or carbon dioxide that may be imposed in various states, as well as state and local climate change initiatives, could adversely affect the oil and natural gas industry, and, at this time, it is not possible to accurately estimate how potential future laws or regulations addressing GHG emissions would impact our business.
Finally, increasing concentrations of GHGs in the Earth's atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, floods, and other climatic events; if any of these effects were to occur, they could materially adversely affect our properties and operations.
Drilling for and producing oil and natural gas are high-risk activities with many uncertainties that may materially adversely affect our business, financial condition, results of operations and cash available for distribution.
The drilling activities of the operators of our properties will be subject to many risks. For example, we will not be able to assure you that wells drilled by the operators of our properties will be productive. Drilling for oil and natural gas often involves unprofitable efforts, not only
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from dry wells but also from wells that are productive but do not produce sufficient oil or natural gas to return a profit at then realized prices after deducting drilling, operating and other costs. The seismic data and other technologies used do not provide conclusive knowledge prior to drilling a well that oil or natural gas is present or that it can be produced economically. The costs of exploration, exploitation and development activities are subject to numerous uncertainties beyond our control, and increases in those costs can adversely affect the economics of a project. Further, our operators' drilling and producing operations may be curtailed, delayed, canceled or otherwise negatively impacted as a result of other factors, including:
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unusual or unexpected geological formations;
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loss of drilling fluid circulation;
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title problems;
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facility or equipment malfunctions;
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unexpected operational events;
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shortages or delivery delays of equipment and services;
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compliance with environmental and other governmental requirements; and
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- adverse weather conditions.
Any of these risks can cause substantial losses, including personal injury or loss of life, damage to or destruction of property, natural resources and equipment, pollution, environmental contamination or loss of wells and other regulatory penalties. In the event that planned operations, including the drilling of development wells, are delayed or cancelled, or existing wells or development wells have lower than anticipated production due to one or more of the factors above or for any other reason, our financial condition, results of operations and cash available for distribution to our unitholders may be materially adversely affected.
Operating hazards and uninsured risks may result in substantial losses to the operators of our properties, and any losses could materially adversely affect our results of operations and cash available for distribution.
The operators of our properties will be subject to all of the hazards and operating risks associated with drilling for and production of oil and natural gas, including the risk of fire, explosions, blowouts, surface cratering, uncontrollable flows of natural gas, oil and formation water, pipe or pipeline failures, abnormally pressured formations, casing collapses and environmental hazards such as oil spills, natural gas leaks and ruptures or discharges of toxic gases. In addition, their operations will be subject to risks associated with hydraulic fracturing, including any mishandling, surface spillage or potential underground migration of fracturing fluids, including chemical additives. The occurrence of any of these events could result in substantial losses to the operators of our properties due to injury or loss of life, severe damage to or destruction of property, natural resources and equipment, pollution or other environmental damage, clean-up responsibilities, regulatory investigations and penalties, suspension of operations and repairs required to resume operations.
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If the operators of our properties suspend our right to receive royalty payments due to title or other issues, our business, financial condition, results of operations and cash available for distribution may be adversely affected.
Prior to the closing of this offering, record title to the mineral and royalty interests that comprise our initial assets was held by various unrelated entities. Upon the closing of this offering, a significant amount of these mineral and royalty interests will be conveyed to us or our subsidiaries as asset assignments, and we or our subsidiaries will become the record owner of these interests. Upon such a change in ownership, and at regular intervals pursuant to routine audit procedures at each of our operators otherwise at its discretion, the operator of the underlying property has the right to investigate and verify the title and ownership of mineral and royalty interests with respect to the properties it operates. If any title or ownership issues are not resolved to its reasonable satisfaction in accordance with customary industry standards, the operator may suspend payment of the related royalty. If an operator of our properties is not satisfied with the documentation we provide to validate our ownership, it may place our royalty payment in suspense until such issues are resolved, at which time we would receive in full payments that would have been made during the suspense period, without interest. Certain of our operators impose significant documentation requirements for title transfer and may keep royalty payments in suspense for significant periods of time. During the time that an operator puts our assets in pay suspense, we would not receive the applicable mineral or royalty payment owed to us from sales of the underlying oil or natural gas related to such mineral or royalty interest. If a significant amount of our royalty interests are placed in suspense, our quarterly distribution may be reduced significantly. We expect the risk of payment suspense to be greatest during the quarter in which this offering occurs and the immediately succeeding fiscal quarters due to the number of title transfers that will take place upon the closing of this offering.
Risks Inherent in an Investment in Us
Our general partner and its affiliates, including our Sponsors and their respective affiliates, have conflicts of interest with us and limited duties to us and our unitholders, and they may favor their own interests to the detriment of us and our unitholders. Additionally, we have no control over the business decisions and operations of our Sponsors and their respective affiliates, which are under no obligation to adopt a business strategy that favors us.
Upon the completion of this offering, affiliates of our Sponsors will own a % limited partner interest in us (or % if the underwriters' option to purchase additional common units is exercised in full) (excluding any common units purchased by officers and directors of our general partner under our directed unit program), and our Sponsors will indirectly own and control our general partner. Our general partner has sole responsibility for conducting our business and managing our operations. Although our general partner has a duty to manage us in a manner that is in, or not adverse to, the best interests of us and our unitholders, the directors and officers of our general partner also have a duty to manage our general partner in a manner that is beneficial to Kimbell Holdings and its parents, our Sponsors. Conflicts of interest may arise between our Sponsors and their respective affiliates, including our general partner, on the one hand, and us and our unitholders, on the other hand. In resolving these conflicts, our general partner may favor its own interests and the interests of its affiliates, including our Sponsors and their respective affiliates, over the interests of our unitholders. These conflicts include, among others, the following situations:
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- neither our partnership agreement nor any other agreement requires our Sponsors or the Contributing Parties to pursue a business strategy that favors us or utilizes our assets
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our Sponsors may change their strategy or priorities in a way that is detrimental to our future growth and acquisition opportunities;
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many of the officers and directors of our general partner are also officers or directors of, and equity owners in, our Sponsors and
the Contributing Parties and will owe fiduciary duties to our Sponsors and the Contributing Parties and their respective owners;
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our partnership agreement does not limit our Sponsors' or their respective affiliates' ability to compete with us and, subject to the
50% participation right included in the contribution agreement that we have entered into with our Sponsors and the Contributing Parties, neither our Sponsors nor the Contributing Parties have any
obligation to present business opportunities to us (subject to the non-competition provision of the limited liability company agreement of Kimbell Holdings), and although certain of the Contributing
Parties have granted us a right of first offer for a period of three years after the closing of this offering with respect to certain mineral and royalty interests in the Permian Basin, the
Bakken/Williston Basin and the Marcellus Shale, and such Contributing Parties are under no obligation to offer such assets to us;
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our Sponsors may be constrained by the terms of their current or future debt instruments from taking actions, or refraining from
taking actions, that may be in our best interests;
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our partnership agreement replaces the fiduciary duties that would otherwise be owed by our general partner with contractual standards
governing its duties, limiting our general partner's liabilities; and restricting the remedies available to our unitholders for actions that, without the limitations, might constitute breaches of
fiduciary duty;
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except in limited circumstances, our general partner has the power and authority to conduct our business without unitholder approval;
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contracts between us, on the one hand, and our general partner and its affiliates, on the other hand, may not be the result of arm's
length negotiations;
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disputes may arise under agreements we have with our general partner or its affiliates;
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our general partner will determine the amount and timing of acquisitions and dispositions, borrowings, issuance of additional
partnership securities and the creation, reduction or increase of cash reserves, each of which can affect the amount of cash that is distributed to our unitholders;
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- our general partner will determine which costs incurred by it or its affiliates are reimbursable by us;
(subject to the non-competition provision of the limited liability company agreement of Kimbell Holdings), which could involve decisions by our Sponsors to undertake acquisition opportunities for themselves, and the directors and officers of our Sponsors and the Contributing Parties have a fiduciary duty to make these decisions in the best interests of our Sponsors and such Contributing Parties, which may be contrary to our interests;
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our partnership agreement does not restrict our general partner from causing us to pay it or its affiliates for any services rendered
to us or entering into additional contractual arrangements with any of these entities on our behalf;
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we will enter into a management services agreement with Kimbell Operating, which will enter into separate service agreements with
certain entities controlled by Messrs. Duncan, R. Ravnaas, Taylor and Wynne, pursuant to which they and Kimbell Operating will provide management, administrative and operational services to us,
and such entities will also provide these services to certain other entities, including certain of the Contributing Parties;
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our general partner intends to limit its liability regarding our contractual and other obligations;
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our general partner may exercise its right to call and purchase all of the common units not owned by it and its affiliates if it and
its affiliates own more than 80% of our common units;
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our general partner controls the enforcement of obligations owed to us by our general partner and its affiliates, including under the
contribution agreement and other agreements with our Sponsors and the Contributing Parties; and
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- our general partner decides whether to retain separate counsel, accountants or others to perform services for us.
Our partnership agreement does not restrict our Sponsors and their respective affiliates, the Contributing Parties, or affiliates of our general partner from competing with us.
Our partnership agreement provides that our general partner is restricted from engaging in any business activities other than acting as our general partner and those activities incidental to its ownership of interests in us. Affiliates of our general partner are not prohibited from owning projects or engaging in businesses that compete directly or indirectly with us. Similarly, our partnership agreement does not limit our Sponsors' or their respective affiliates' ability to compete with us and, subject to the 50% participation right included in the contribution agreement that we have entered into with our Sponsors and the Contributing Parties, neither our Sponsors nor the Contributing Parties have any obligation to present business opportunities to us. Pursuant to the limited liability company agreement of Kimbell Holdings, the right of each of Messrs. Fortson, R. Ravnaas, Taylor and Wynne (and their designated successors) to serve as a director of our general partner is conditioned upon the applicable person not competing with us, our general partner, and our and its respective subsidiaries. Affiliates of our Sponsors currently hold interests in, and may make investments in and purchases of, entities that acquire and own mineral and royalty interests. Our Sponsors and their respective affiliates will be under no obligation to make any acquisition opportunities available to us, except as provided for under the contribution agreement.
Under the terms of our partnership agreement, the doctrine of corporate opportunity, or any analogous doctrine, does not apply to our general partner or any of its affiliates, including its executive officers and directors and our Sponsors and their respective affiliates, or the Contributing Parties. Any such person or entity that becomes aware of a potential transaction, agreement, arrangement or other matter that may be an opportunity for us will not have any duty to communicate or offer such opportunity to us. Any such person or entity will not be liable to
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us or to any limited partner for breach of any fiduciary duty or other duty by reason of the fact that such person or entity pursues or acquires such opportunity for itself, directs such opportunity to another person or entity or does not communicate such opportunity or information to us. This may create actual and potential conflicts of interest between us and affiliates of our general partner and result in less than favorable treatment of us and holders of our common units.
Our general partner intends to limit its liability regarding our obligations.
Our general partner intends to limit its liability under contractual arrangements between us and third parties so that the counterparties to such arrangements have recourse only against our assets, and not against our general partner or its assets. Our general partner may therefore cause us to incur indebtedness or other obligations that are nonrecourse to our general partner. Our partnership agreement provides that any action taken by our general partner to limit its liability is not a breach of our general partner's duties, even if we could have obtained more favorable terms without the limitation on liability. In addition, we are obligated to reimburse or indemnify our general partner to the extent that it incurs obligations on our behalf. Any such reimbursement or indemnification payments would reduce the amount of cash otherwise available for distribution to our unitholders.
Neither we, our general partner nor our subsidiaries have any employees, and we rely solely on Kimbell Operating to manage and operate, or arrange for the management and operation of, our business. The management team of Kimbell Operating, which includes the individuals who will manage us, will also provide substantially similar services to other entities and thus will not be solely focused on our business.
Neither we, our general partner nor our subsidiaries have any employees, and we rely solely on Kimbell Operating to manage us and operate our assets. In connection with this offering, we will enter into a management services agreement with Kimbell Operating, which will enter into separate service agreements with certain entities controlled by Messrs. Duncan, R. Ravnaas, Taylor and Wynne, pursuant to which they and Kimbell Operating will provide management, administrative and operational services to us.
Kimbell Operating will also provide substantially similar services and personnel to other entities, including certain of the Contributing Parties, and, as a result, may not have sufficient human, technical and other resources to provide those services at a level that it would be able to provide to us if it did not provide similar services to these other entities. Additionally, Kimbell Operating may make internal decisions on how to allocate its available resources and expertise that may not always be in our best interest compared to those of other entities or other affiliates of our general partner. There is no requirement that Kimbell Operating favor us over these other entities in providing its services. If the employees of Kimbell Operating do not devote sufficient attention to the management and operation of our business, our financial results may suffer and our ability to make distributions to our unitholders may be reduced.
Our partnership agreement replaces fiduciary duties applicable to a corporation with contractual duties and restricts the remedies available to holders of our common units for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty.
Our partnership agreement contains provisions that replace fiduciary duties applicable to a corporation with contractual duties and restrict the remedies available to unitholders for actions
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taken by our general partner that might otherwise constitute breaches of fiduciary duty under state fiduciary duty law. For example, our partnership agreement provides that:
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whenever our general partner (acting in its capacity as our general partner), the board of directors of our general partner or any
committee thereof (including the conflicts committee) makes a determination or takes, or declines to take, any other action in their respective capacities, our general partner, the board of directors
of our general partner and any committee thereof (including the conflicts committee), as applicable, is required to make such determination, or take or decline to take such other action, in good
faith, meaning that it subjectively believed that the decision was in, or not adverse to, our best interests, and, except as specifically provided by our partnership agreement, will not be subject to
any other or different standard imposed by our partnership agreement, Delaware law, or any other law, rule or regulation, or at equity;
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our general partner will not have any liability to us or our unitholders for decisions made in its capacity as a general partner so
long as such decisions are made in good faith;
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our general partner and its officers and directors will not be liable for monetary damages to us or our limited partners resulting
from any act or omission unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that our general partner or its officers and directors, as
the case may be, acted in bad faith or engaged in fraud or willful misconduct or, in the case of a criminal matter, acted with knowledge that the conduct was criminal; and
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our general partner will not be in breach of its obligations under the partnership agreement (including any duties to us or our
unitholders) if a transaction with an affiliate or the resolution of a conflict of interest is:
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approved by the conflicts committee of the board of directors of our general partner, although our general partner is not
obligated to seek such approval;
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approved by the vote of a majority of the outstanding common units, excluding any common units owned by our general
partner and its affiliates;
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determined by the board of directors of our general partner to be on terms no less favorable to us than those generally
being provided to or available from third parties; or
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- determined by the board of directors of our general partner to be fair and reasonable to us, taking into account the totality of the relationships among the parties involved, including other transactions that may be particularly favorable or advantageous to us.
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In connection with a situation involving a transaction with an affiliate or a conflict of interest, any determination by our general partner or the conflicts committee must be made in good faith. If an affiliate transaction or the resolution of a conflict of interest is not approved by our common unitholders or the conflicts committee and the board of directors of our general partner determines that the resolution or course of action taken with respect to the affiliate transaction or conflict of interest satisfies either of the standards set forth in the third and fourth sub bullet points above, then it will be presumed that, in making its decision, the board of directors of our general partner acted in good faith, and in any proceeding brought by or on behalf of any limited partner or the partnership challenging such determination, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption. Please read "Conflicts of Interest and Duties—Conflicts of Interest."
Our partnership agreement replaces our general partner's fiduciary duties to holders of our common units with contractual standards governing its duties.
Our partnership agreement contains provisions that eliminate the fiduciary standards to which our general partner would otherwise be held by state fiduciary duty law and replaces those duties with several different contractual standards. For example, our partnership agreement permits our general partner to make a number of decisions in its individual capacity, as opposed to in its capacity as our general partner, free of any duties to us and our unitholders other than the implied contractual covenant of good faith and fair dealing, which means that a court will enforce the reasonable expectations of the partners where the language in the partnership agreement does not provide for a clear course of action. This provision entitles our general partner to consider only the interests and factors that it desires and relieves it of any duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or our limited partners. Examples of decisions that our general partner may make in its individual capacity include:
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how to allocate corporate opportunities among us and its other affiliates;
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whether to exercise its limited call right;
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whether to seek approval of the resolution of a conflict of interest by the conflicts committee of the board of directors of our
general partner or by the unitholders;
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how to exercise its voting rights with respect to the units it owns;
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whether to sell or otherwise dispose of any units or other partnership interests it owns; and
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- whether or not to consent to any merger or consolidation of the partnership or amendment to the partnership agreement.
By purchasing a common unit, a common unitholder agrees to become bound by the provisions in the partnership agreement, including the provisions discussed above. Please read "Conflicts of Interest and Duties—Duties of Our General Partner."
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Holders of our common units have limited voting rights and are not entitled to elect our general partner or its directors, which could reduce the price at which our common units will trade.
Unlike the holders of common stock in a corporation, our unitholders have only limited voting rights on matters affecting our business and, therefore, limited ability to influence management's decisions regarding our business. Our unitholders will have no right on an annual or ongoing basis to elect our general partner or its board of directors. The board of directors of our general partner, including the independent directors, is chosen entirely by our Sponsors, as a result of such Sponsors controlling our general partner, and not by our unitholders. Please read "Management—Management of Kimbell Royalty Partners, LP" and "Certain Relationships and Related Party Transactions." Unlike publicly traded corporations, we will not conduct annual meetings of our unitholders to elect directors or conduct other matters routinely conducted at annual meetings of stockholders of corporations. As a result of these limitations, the price at which our common units will trade could be diminished because of the absence or reduction of a takeover premium in the trading price.
Even if holders of our common units are dissatisfied, they cannot initially remove our general partner without its consent.
If our unitholders are dissatisfied with the performance of our general partner, they will have limited ability to remove our general partner. The vote of the holders of at least 66 2 / 3 % of all outstanding common units is required to remove our general partner. Following the closing of this offering, affiliates of our Sponsors will own % of our common units (or % of our common units, if the underwriters exercise their option to purchase additional common units in full) (excluding any common units purchased by officers and directors of our general partner under our directed unit program), and our Sponsors will indirectly own and control our general partner.
Our partnership agreement restricts the voting rights of unitholders owning 20% or more of our common units (other than our general partner and its affiliates, the Contributing Parties and their respective affiliates and permitted transferees).
Our partnership agreement restricts unitholders' voting rights by providing that any units held by a person that owns 20% or more of any class of units then outstanding, other than our general partner, its affiliates and their transferees, the Contributing Parties, their respective affiliates and their transferees and persons who acquired such units with the prior approval of the board of directors of our general partner, may not vote on any matter. Our partnership agreement also contains provisions limiting the ability of common unitholders to call meetings or to acquire information about our operations, as well as other provisions limiting the ability of our common unitholders to influence the manner or direction of management.
Cost reimbursements due to our general partner and its affiliates for services provided to us or on our behalf will reduce cash available for distribution to our unitholders. Our partnership agreement does not set a limit on the amount of expenses for which our general partner and its affiliates may be reimbursed. The amount and timing of such reimbursements will be determined by our general partner.
Prior to paying any distribution on our common units, we will reimburse our general partner and its affiliates, including Kimbell Operating pursuant to its management services agreement discussed below, for all expenses they incur and payments they make on our behalf.
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Our partnership agreement does not set a limit on the amount of expenses for which our general partner and its affiliates may be reimbursed. These expenses include salary, bonus, incentive compensation and other amounts paid to persons who perform services for us or on our behalf and expenses allocated to our general partner by its affiliates. Our partnership agreement provides that our general partner will determine the expenses that are allocable to us. The reimbursement of expenses and payment of fees, if any, to our general partner and its affiliates will reduce the amount of cash available for distribution to our unitholders. Please read "Cash Distribution Policy and Restrictions on Distributions."
In connection with the closing of this offering, we will also enter into a management services agreement with Kimbell Operating, which will enter into separate service agreements with certain entities controlled by Messrs. Duncan, R. Ravnaas, Taylor and Wynne, pursuant to which they and Kimbell Operating will provide management, administrative and operational services to us. Amounts paid to Kimbell Operating and such other entities under their respective service agreements will reduce the amount of cash available for distribution to our unitholders. Please read "Certain Relationships and Related Party Transactions—Agreements and Transactions with Affiliates in Connection with this Offering—Management Services Agreements."
Our general partner interest or the control of our general partner may be transferred to a third party without unitholder consent.
Our general partner may transfer its general partner interest to a third party without the consent of our unitholders. Furthermore, our partnership agreement does not restrict the ability of the owner of our general partner to transfer its membership interests in our general partner to a third party. After any such transfer, the new member or members of our general partner would then be in a position to replace the board of directors and executive officers of our general partner with its own designees and thereby exert significant control over the decisions taken by the board of directors and executive officers of our general partner. This effectively permits a "change of control" without the vote or consent of the unitholders.
Unitholders may have liability to repay distributions and in certain circumstances may be personally liable for the obligations of the partnership.
Under certain circumstances, unitholders may have to repay amounts wrongfully returned or distributed to them. Under Section 17-607 of the Delaware Revised Uniform Limited Partnership Act (the "Delaware Act"), we may not pay a distribution to our unitholders if the distribution would cause our liabilities to exceed the fair value of our assets. Delaware law provides that for a period of three years from the date of the impermissible distribution, limited partners who received the distribution and who knew at the time of the distribution that it violated Delaware law will be liable to the limited partnership for the distribution amount. Liabilities to partners on account of their partnership interests and liabilities that are non-recourse to the partnership are not counted for purposes of determining whether a distribution is permitted.
A limited partner that participates in the control of our business within the meaning of the Delaware Act may be held personally liable for our obligations under the laws of Delaware, to the same extent as our general partner. This liability would extend to persons who transact business with us under the reasonable belief that the limited partner is a general partner. Neither our partnership agreement nor the Delaware Act specifically provides for legal recourse against our general partner if a limited partner were to lose limited liability through any fault of our general partner. Please read "The Partnership Agreement—Limited Liability."
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Increases in interest rates may cause the market price of our common units to decline.
While interest rates have been at record low levels in recent years, this low interest rate environment likely will not continue indefinitely. An increase in interest rates may cause a corresponding decline in demand for equity investments in general, and in particular, for yield-based equity investments such as our common units. Any such increase in interest rates or reduction in demand for our common units resulting from other relatively more attractive investment opportunities may cause the trading price of our common units to decline.
Unitholders will incur immediate and substantial dilution in net tangible book value per common unit.
The assumed initial public offering price of $ per common unit (the mid-point of the price range set forth on the cover page of this prospectus) exceeds our pro forma net tangible book value of $ per common unit. Based on the assumed initial public offering price of $ per common unit, unitholders will incur immediate and substantial dilution of $ per common unit. This dilution results primarily because the assets contributed to us by affiliates of our general partner are recorded at their historical cost in accordance with GAAP, and not their fair value. Please read "Dilution."
Our general partner has a call right that may require unitholders to sell their common units at an undesirable time or price.
If at any time our general partner and its affiliates (including our Sponsors and their respective affiliates) own more than 80% of our common units, our general partner will have the right, which it may assign to any of its affiliates or to us, but not the obligation, to acquire all, but not less than all, of the common units held by unaffiliated persons at a price equal to the greater of (1) the average of the daily closing price of our common units over the 20 trading days preceding the date three days before notice of exercise of the call right is first mailed and (2) the highest per-unit price paid by our general partner or any of its affiliates for common units during the 90-day period preceding the date such notice is first mailed. As a result, unitholders may be required to sell their common units at an undesirable time or price and may not receive any return or a negative return on their investment. Unitholders may also incur a tax liability upon a sale of their units. Our general partner is not obligated to obtain a fairness opinion regarding the value of the common units to be repurchased by it upon exercise of the limited call right. There is no restriction in our partnership agreement that prevents our general partner from causing us to issue additional common units and then exercising its call right. If our general partner exercised its limited call right, the effect would be to take us private and, if the units were subsequently deregistered, we would no longer be subject to the reporting requirements of the Exchange Act. Upon the completion of this offering, affiliates of our Sponsors will own % of our common units (excluding any common units purchased by officers and directors of our general partner under our directed unit program), and our Sponsors will indirectly own and control our general partner. For additional information about the limited call right, please read "The Partnership Agreement—Limited Call Right."
We may issue additional common units and other equity interests without unitholder approval, which would dilute existing unitholder ownership interests.
Under our partnership agreement, we are authorized to issue an unlimited number of additional interests, including common units, without a vote of the unitholders. The issuance by
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us of additional common units or other equity interests of equal or senior rank will have the following effects:
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the proportionate ownership interest of unitholders in us immediately prior to the issuance will decrease;
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the amount of cash distributions on each common unit may decrease;
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the ratio of our taxable income to distributions may increase;
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the relative voting strength of each previously outstanding common unit may be diminished; and
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- the market price of the common units may decline.
Please read "The Partnership Agreement—Issuance of Additional Partnership Interests."
There are no limitations in our partnership agreement on our ability to issue units ranking senior in right of distributions or liquidation to our common units.
In accordance with Delaware law and the provisions of our partnership agreement, we may issue additional partnership interests that rank senior in right of distributions, liquidation or voting to our common units. The issuance by us of units of senior rank may (i) reduce or eliminate the amount of cash available for distribution to our common unitholders; (ii) diminish the relative voting strength of the total common units outstanding as a class; or (iii) subordinate the claims of the common unitholders to our assets in the event of our liquidation.
The market price of our common units could be materially adversely affected by sales of substantial amounts of our common units in the public or private markets, including sales by our Sponsors and the Contributing Parties.
After this offering, we will have common units outstanding, including our common units that we are selling in this offering that may be resold in the public market immediately. of the common units to be issued to certain of the Contributing Parties, including affiliates of our Sponsors, will be subject to resale restrictions under a 180-day lock-up agreement with the underwriters. Each of the lock-up agreements with the underwriters may be waived in the discretion of certain of the underwriters. Sales by our Sponsors, certain of the Contributing Parties or other large holders of a substantial number of our common units in the public markets following this offering, or the perception that such sales might occur, could have a material adverse effect on the price of our common units or could impair our ability to obtain capital through an offering of equity securities. In addition, we have agreed to provide registration rights to the Contributing Parties. Please read "Units Eligible for Future Sale."
There is no existing market for our common units, and a trading market that will provide you with adequate liquidity may not develop. The price of our common units may fluctuate significantly, and unitholders could lose all or part of their investment.
Prior to this offering, there has been no public market for our common units. After this offering, there will be only publicly traded common units. We do not know the extent to which investor interest will lead to the development of a trading market or how liquid that market might be. Unitholders may not be able to resell their common units at or above the initial
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public offering price. Additionally, the lack of liquidity may result in wide bid-ask spreads, contribute to significant fluctuations in the market price of our common units and limit the number of investors who are able to buy our common units.
The initial public offering price for our common units will be determined by negotiations between us and the representatives of the underwriters and may not be indicative of the market price of our common units that will prevail in the trading market. The market price of our common units may decline below the initial public offering price. The market price of our common units may also be influenced by many factors, some of which are beyond our control, including:
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changes in commodity prices;
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public reaction to our press releases, announcements and filings with the SEC;
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fluctuations in broader securities market prices and volumes, particularly among securities of oil and natural gas companies and
securities of publicly traded limited partnerships and limited liability companies;
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changes in market valuations of similar companies;
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departures of key personnel;
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commencement of or involvement in litigation;
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variations in our quarterly results of operations or those of other oil and natural gas companies;
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changes in general economic conditions, financial markets or the oil and natural gas industry;
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announcements by us or our competitors of significant acquisitions or other transactions;
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variations in the amount of our quarterly cash distributions to our unitholders;
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changes in accounting standards, policies, guidance, interpretations or principles;
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the failure of securities analysts to cover our common units after this offering or changes in their recommendations and estimates of
our financial performance;
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future sales of our common units; and
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- the other factors described in these "Risk Factors."
We will incur increased costs as a result of being a publicly traded partnership.
We have no history operating as a publicly traded partnership. As a publicly traded partnership, we will incur significant legal, accounting and other expenses that we did not incur prior to this offering. In addition, the Sarbanes-Oxley Act and the Dodd-Frank Act of 2010, as well as rules implemented by the SEC and the NYSE, require, or will require, publicly traded entities to adopt various corporate governance practices that will further increase our costs.
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Before we are able to pay distributions to our unitholders, we must first pay our expenses, including the costs of being a publicly traded partnership and other operating expenses. As a result, the amount of cash we have available for distribution to our unitholders will be affected by our expenses, including the costs associated with being a publicly traded partnership.
Following this offering, we will become subject to the public reporting requirements of the Exchange Act. We expect these requirements will increase certain of our legal and financial compliance costs and make compliance activities more time-consuming and costly. For example, as a result of becoming a publicly traded partnership, we are required to have at least three independent directors and adopt policies regarding internal controls and disclosure controls and procedures, including the preparation of reports on internal control over financial reporting.
We estimate that we will incur approximately $1.5 million of incremental costs per year associated with being a publicly traded partnership; however, it is possible that our actual incremental costs of being a publicly traded partnership will be higher than we currently estimate.
For as long as we are an emerging growth company, we will not be required to comply with certain disclosure requirements that apply to other public companies.
We are an "emerging growth company" as defined in the JOBS Act. For as long as we are an emerging growth company, which may be up to five full fiscal years, unlike other public companies, we will not be required to, among other things, (1) provide an auditor's attestation report on the effectiveness of our system of internal control over financial reporting pursuant to Section 404(b) of the Sarbanes-Oxley Act, (2) comply with any new requirements adopted by the PCAOB requiring mandatory audit firm rotation or a supplement to the auditor's report in which the auditor would be required to provide additional information about the audit and the financial statements of the issuer, (3) comply with any new audit rules adopted by the PCAOB after April 5, 2012 unless the SEC determines otherwise or (4) provide certain disclosure regarding executive compensation required of larger public companies.
In addition, Section 102 of the JOBS Act also provides that an "emerging growth company" can use the extended transition period provided in Section 7(a)(2)(B) of the Securities Act for complying with new or revised accounting standards. An "emerging growth company" can therefore delay the adoption of certain accounting standards until those standards would otherwise apply to private companies. However, we are choosing to "opt out" of such extended transition period, and, as a result, we will comply with new or revised accounting standards on the relevant dates on which adoption of such standards is required for non-emerging growth companies. Section 107 of the JOBS Act provides that our decision to opt out of the extended transition period for complying with new or revised accounting standards is irrevocable.
If we fail to develop or maintain an effective system of internal controls, we may not be able to accurately report our financial results or prevent fraud. As a result, current and potential unitholders could lose confidence in our financial reporting, which would harm our business and the trading price of our units.
Prior to this offering, our predecessor has not been required to file reports with the SEC. Upon the completion of this offering, we will become subject to the public reporting requirements of the Exchange Act. We prepare our financial statements in accordance with GAAP, but our internal controls over financial reporting may not currently meet all standards applicable to companies with publicly traded securities. Effective internal controls are necessary
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for us to provide reliable financial reports, prevent fraud and operate successfully as a publicly traded partnership. If we cannot provide reliable financial reports or prevent fraud, our reputation and operating results would be harmed. We cannot be certain that our efforts to develop and maintain our internal controls will be successful, that we will be able to maintain adequate controls over our financial processes and reporting in the future or that we will be able to comply with our obligations under Section 404 of the Sarbanes-Oxley Act. For example, Section 404 will require us, among other things, to annually review and report on, and our independent registered public accounting firm to attest to, the effectiveness of our internal controls over financial reporting. However, for as long as we are an "emerging growth company" under the JOBS Act, our independent registered public accounting firm will not be required to attest to the effectiveness of our internal control over financial reporting. We must comply with Section 404 (except for the requirement for an auditor's attestation report) beginning with our fiscal year ending . Any failure to develop or maintain effective internal controls, or difficulties encountered in implementing or improving our internal controls, could harm our operating results or cause us to fail to meet our reporting obligations. Ineffective internal controls could also cause investors to lose confidence in our reported financial information, which would likely have a negative effect on the trading price of our common units.
The NYSE does not require a publicly traded partnership like us to comply with certain of its corporate governance requirements.
We have been approved to list our common units on the NYSE, subject to official notice of issuance. Because we will be a publicly traded partnership, the NYSE does not require us to have, and we do not intend to have, a majority of independent directors on our general partner's board of directors or to establish a compensation committee or a nominating and corporate governance committee. Additionally, any future issuance of common units or other securities, including to affiliates, will not be subject to the NYSE's shareholder approval rules that apply to corporations. Accordingly, unitholders will not have the same protections afforded to stockholders of certain corporations that are subject to all of the NYSE's corporate governance requirements. Please read "Management."
Our partnership agreement includes exclusive forum, venue and jurisdiction provisions. By purchasing a common unit, a limited partner is irrevocably consenting to these provisions regarding claims, suits, actions or proceedings and submitting to the exclusive jurisdiction of Delaware courts.
Our partnership agreement is governed by Delaware law. Our partnership agreement includes exclusive forum, venue and jurisdiction provisions designating Delaware courts as the exclusive venue for most claims, suits, actions and proceedings involving us or our officers, directors and employees. Please read "The Partnership Agreement—Applicable Law; Forum, Venue and Jurisdiction." By purchasing a common unit, a limited partner is irrevocably consenting to these provisions regarding claims, suits, actions or proceedings and submitting to the exclusive jurisdiction of Delaware courts. These provisions may have the effect of discouraging lawsuits against us and our general partner's officers and directors.
Our general partner may amend our partnership agreement, as it determines necessary or advisable, to permit our general partner to redeem the units of certain unitholders.
Our general partner may amend our partnership agreement, as it determines necessary or advisable, to obtain proof of the U.S. federal income tax status or the nationality, citizenship or other related status of our limited partners (and their owners, to the extent relevant) and to
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permit our general partner to redeem the units held by any person (i) whose tax status has or is reasonably likely to have a material adverse effect on the maximum applicable rates chargeable to our customers, (ii) whose nationality, citizenship or related status creates substantial risk of cancellation or forfeiture of any of our property or (iii) who fails to comply with the procedures established to obtain such proof. The redemption price in the case of such a redemption will be the average of the daily closing prices per unit for the 20 consecutive trading days immediately prior to the date set for redemption. Please read "The Partnership Agreement—Ineligible Holders; Redemption."
Tax Risks to Common Unitholders
In addition to reading the following risk factors, you should read "Material U.S. Federal Income Tax Consequences" for a more complete discussion of the expected material federal income tax consequences of owning and disposing of common units.
Our tax treatment depends on our status as a partnership for federal income tax purposes, as well as our not being subject to a material amount of entity-level taxation by individual states. If the IRS were to treat us as a corporation for federal income tax purposes or we were to become subject to entity-level taxation for state tax purposes, then our cash available for distribution to you could be substantially reduced.
The anticipated after-tax economic benefit of an investment in our common units depends largely on our being treated as a partnership for federal income tax purposes.
Despite the fact that we are organized as a limited partnership under Delaware law, we would be treated as a corporation for U.S. federal income tax purposes unless we satisfy a "qualifying income" requirement. Based upon our current operations, we believe we satisfy the qualifying income requirement. However, we have not requested, and do not plan to request, a ruling from the IRS on this or any other matter affecting us. A change in our business or a change in current law could cause us to be treated as a corporation for U.S. federal income tax purposes or otherwise subject us to taxation as an entity.
If we were treated as a corporation for federal income tax purposes, we would pay federal income tax on our taxable income at the corporate tax rate, which is currently a maximum of 35%. Distributions to you would generally be taxed again as corporate distributions, and no income, gains, losses or deductions would flow through to you. Because a tax would be imposed upon us as a corporation, our cash available for distribution to you would be substantially reduced. In addition, changes in current state law may subject us to additional entity-level taxation by individual states. Several states have subjected, or are evaluating ways to subject, partnerships to entity-level taxation through the imposition of state income, franchise and other forms of taxation. Imposition of any such taxes may substantially reduce the cash available for distribution to you. Therefore, treatment of us as a corporation or the assessment of a material amount of entity-level taxation would result in a material reduction in the anticipated cash flow and after-tax return to the unitholders, likely causing a substantial reduction in the value of our common units.
69
The tax treatment of publicly traded partnerships or an investment in our common units could be subject to potential legislative, judicial or administrative changes or differing interpretations, possibly applied on a retroactive basis.
The present U.S. federal income tax treatment of publicly traded partnerships, including us, or an investment in our common units may be modified by administrative, legislative or judicial changes or differing interpretations at any time. For example, from time to time, the President and members of Congress propose and consider substantive changes to the existing U.S. federal income tax laws that affect publicly traded partnerships, including elimination of partnership tax treatment for publicly traded partnerships. Any modification to the federal income tax laws and interpretations thereof may or may not be retroactively applied and could make it more difficult or impossible for us to meet the exception to be treated as a partnership for federal income tax purposes. Please read "Material U.S. Federal Income Tax Consequences—Partnership Status."
On May 5, 2015, the U.S. Treasury Department and the IRS issued proposed regulations (the "Proposed Regulations") regarding qualifying income under Section 7704(d)(1)(E) of the Internal Revenue Code of 1986, as amended (the "Code"). The Proposed Regulations provide an exclusive list of industry-specific rules regarding the qualifying income exception, including whether an activity constitutes the exploration, development, production and marketing of natural resources. Income earned from a royalty interest is not specifically enumerated as a qualifying income activity in the Proposed Regulations. However, we believe that royalty income is qualifying income for purposes of Section 7704 of the Code since it is "derived" from the exploration, development, production and marketing of natural resources, and Baker Botts L.L.P. is of the opinion that such income constitutes qualifying income, notwithstanding the Proposed Regulations. Further, the Proposed Regulations are proposed only to apply to income earned in a taxable year beginning on or after the date that the Proposed Regulations are published as final regulations. Therefore, prior to being published as final regulations, the Proposed Regulations are generally not applicable to any income that we earn. The U.S. Treasury Department and the IRS may clarify that royalty income is qualifying income for purposes of Section 7704 of the Code; however, there are no assurances that the Proposed Regulations, when published as final regulations, will not take a position that is contrary to our interpretation of Section 7704 of the Code.
We are unable to predict whether any of these changes or other proposals will ultimately be enacted or adopted. Any such changes could negatively impact the value of an investment in our common units. For further discussion of the importance of our treatment as a partnership for federal income tax purposes, please read "Material U.S. Federal Income Tax Consequences—Partnership Status."
If the IRS were to contest the federal income tax positions we take, it may adversely impact the market for our common units, and the costs of any such contest would reduce cash available for distribution to our unitholders.
We have not requested a ruling from the IRS with respect to our treatment as a partnership for federal income tax purposes or any other matter affecting us or our unitholders. The IRS may adopt positions that differ from the conclusions of our counsel expressed in this prospectus or from the positions we take. It may be necessary to resort to administrative or court proceedings to sustain some or all of our counsel's conclusions or the positions we take. A court may not agree with some or all of our counsel's conclusions or positions we take. Any contest with the IRS may materially and adversely impact the market for our common units and the price at which they trade. Moreover, the costs of any contest between us and the IRS will result in a
70
reduction in cash available for distribution to our unitholders and thus will be borne indirectly by our unitholders.
Even if you do not receive any cash distributions from us, you will be required to pay taxes on your share of our taxable income.
You will be required to pay federal income taxes and, in some cases, state and local income taxes on your share of our taxable income, whether or not you receive cash distributions from us. You may not receive cash distributions from us equal to your share of our taxable income or even equal to the actual tax due from you with respect to that income.
Tax gain or loss on disposition of our common units could be more or less than expected.
If you sell your common units, you will recognize a gain or loss for U.S. federal income tax purposes equal to the difference between the amount realized and your tax basis in those common units. Because distributions in excess of your allocable share of our net taxable income decrease your tax basis in your common units, the amount, if any, of such prior excess distributions with respect to the units you sell will, in effect, become taxable income to you if you sell such units at a price greater than your tax basis in those units, even if the price you receive is less than your original cost. Furthermore, a substantial portion of the amount realized, whether or not representing gain, may be taxed as ordinary income due to potential recapture items, including depreciation and depletion recapture. In addition, because the amount realized includes a unitholder's share of our nonrecourse liabilities, if you sell your common units, you may incur a tax liability in excess of the amount of cash you receive from the sale. Please read "Material U.S. Federal Income Tax Consequences—Disposition of Common Units—Recognition of Gain or Loss" for a further discussion of the foregoing.
Tax-exempt entities and non-U.S. persons face unique tax issues from owning our common units that may result in adverse tax consequences to them.
Investment in common units by tax-exempt entities, such as employee benefit plans and individual retirement accounts or annuities known as IRAs, and non-U.S. persons raises issues unique to them. For example, a portion of our income allocated to organizations that are exempt from federal income tax, including IRAs and other retirement plans, may be unrelated business taxable income and may be taxable to them. Distributions to non-U.S. persons will be subject to withholding taxes imposed at the highest effective tax rate applicable to such non-U.S. persons, and each non-U.S. person may be required to file U.S. federal income tax returns and pay tax on their share of our taxable income if it is treated as income effectively connected with the conduct of a U.S. trade or business ("effectively connected income"). If you are a tax-exempt entity or a non-U.S. person, you should consult your tax advisor before investing in our common units. Please read "Material U.S. Federal Income Tax Consequences—Tax-Exempt Organizations and Other Investors."
We will treat each purchaser of common units as having the same tax benefits without regard to the common units actually purchased. The IRS may challenge this treatment, which could adversely affect the value of our common units.
Because we cannot match transferors and transferees of our common units, and because of other reasons, we will adopt depreciation and amortization positions that may not conform to all aspects of existing Treasury regulations ("Treasury Regulations"). Our counsel is unable to opine as to the validity of this approach. A successful IRS challenge to those positions could adversely
71
affect the amount of tax benefits available to you. It also could affect the timing of these tax benefits or the amount of gain from your sale of common units and could have a negative impact on the value of our common units or result in audit adjustments to your tax returns. Please read "Material U.S. Federal Income Tax Consequences—Tax Consequences of Unit Ownership—Section 754 Election" for a further discussion of the effect of the depreciation and amortization positions we adopted.
We will prorate our items of income, gain, loss and deduction between transferors and transferees of our common units each month based upon the ownership of our common units on the first business day of each month, instead of on the basis of the date a particular unit is transferred. The IRS may challenge this treatment, which could change the allocation of items of income, gain, loss and deduction among our unitholders.
We will prorate our items of income, gain, loss and deduction between transferors and transferees of our units each month based upon the ownership of our units on the first business day of each month, instead of on the basis of the date a particular unit is transferred. Although simplifying conventions are contemplated by the Code and most publicly traded partnerships use similar simplifying conventions, the use of this proration method may not be permitted under existing Treasury Regulations. The U.S. Treasury Department recently adopted final Treasury Regulations allowing similar monthly simplifying conventions. However, the final Treasury Regulations do not specifically authorize the use of the proration method we will adopt. If the IRS were to challenge our proration method, we may be required to change the allocation of items of income, gain, loss and deduction among our unitholders. Baker Botts L.L.P. has not rendered an opinion with respect to whether our monthly convention for allocating taxable income and losses is permitted by existing Treasury Regulations. Please read "Material U.S. Federal Income Tax Consequences—Disposition of Common Units—Allocations Between Transferors and Transferees."
If the IRS makes audit adjustments to our income tax returns for tax years beginning after 2017, it may collect any resulting taxes (including any applicable penalties and interest) directly from us, in which case our cash available for distribution to our unitholders might be substantially reduced.
Pursuant to the Bipartisan Budget Act of 2015, if the IRS makes audit adjustments to our income tax returns for tax years beginning after 2017, it may collect any resulting taxes (including any applicable penalties and interest) directly from us. We will generally have the ability to shift any such tax liability to our unitholders in accordance with their interests in us during the year under audit, but there can be no assurance that we will be able to do so under all circumstances. If we are required to make payments of taxes, penalties and interest resulting from audit adjustments, our cash available for distribution to our unitholders might be substantially reduced.
A unitholder whose common units are loaned to a "short seller" to cover a short sale of common units may be considered as having disposed of those common units. If so, he would no longer be treated for federal income tax purposes as a partner with respect to those common units during the period of the loan and may recognize gain or loss from the disposition.
Because a unitholder whose common units are loaned to a "short seller" to cover a short sale of common units may be considered as having disposed of the loaned common units, he may no longer be treated for federal income tax purposes as a partner with respect to those
72
common units during the period of the loan to the short seller and the unitholder may recognize gain or loss from such disposition. Moreover, during the period of the loan to the short seller, any of our income, gain, loss or deduction with respect to those common units may not be reportable by the unitholder and any cash distributions received by the unitholder as to those common units could be fully taxable as ordinary income. Our counsel has not rendered an opinion regarding the treatment of a unitholder where common units are loaned to a short seller to cover a short sale of common units; therefore, our unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan to a short seller are urged to consult a tax advisor to discuss whether it is advisable to modify any applicable brokerage account agreements to prohibit their brokers from loaning their common units.
The sale or exchange of 50% or more of our capital and profits interests during any twelve-month period will result in the termination of our partnership for federal income tax purposes.
We will be considered to have technically terminated our partnership for federal income tax purposes if there is a sale or exchange of 50% or more of the total interests in our capital and profits within a twelve-month period. For purposes of determining whether the 50% threshold has been met, multiple sales of the same interest will be counted only once. Our technical termination would, among other things, result in the closing of our taxable year for all unitholders, which would result in us filing two tax returns (and our unitholders could receive two Schedules K-1 if relief was not available and/or granted by the IRS to provide one Schedule K-1 to unitholders for the year notwithstanding two partnership tax years) for one fiscal year and, in the event we acquire depreciable property in the future, could result in a deferral of depreciation deductions allowable in computing our taxable income. In the case of a unitholder reporting on a taxable year other than a fiscal year ending December 31, the closing of our taxable year may also result in more than twelve months of our taxable income or loss being includable in his taxable income for the year of termination. Our termination currently would not affect our classification as a partnership for federal income tax purposes, but instead we would be treated as a new partnership for tax purposes. If treated as a new partnership, we must make new tax elections and could be subject to penalties if we are unable to determine that a termination occurred. Please read "Material U.S. Federal Income Tax Consequences—Disposition of Common Units—Constructive Termination" for a discussion of the consequences of our termination for federal income tax purposes.
You will likely be subject to state and local taxes and return filing requirements in states where you do not live as a result of investing in our common units.
In addition to federal income taxes, you will likely be subject to other taxes, including state and local taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we conduct business or own property now or in the future, even if you do not live in any of those jurisdictions. We will initially own assets and conduct business in 20 states, many of which impose a personal income tax and also impose income taxes on corporations and other entities. You may be required to file state and local income tax returns and pay state and local income taxes in these jurisdictions. Further, you may be subject to penalties for failure to comply with those requirements. As we make acquisitions or expand our business, we may own assets or conduct business in additional states or foreign jurisdictions that impose a personal income tax. It is your responsibility to file all U.S. federal, foreign, state and local tax returns. Our counsel has not rendered an opinion on the foreign, state or local tax consequences of an investment in our common units.
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We will receive net proceeds of approximately $ million from this offering (based on an assumed initial offering price of $ per common unit, the mid-point of the price range set forth on the cover page of this prospectus), after deducting the estimated underwriting discount and structuring fee payable by us in connection with this offering. We intend to use the net proceeds of this offering to make a distribution to the Contributing Parties.
To the extent the underwriters exercise their option to purchase additional common units, we will issue such units to the public and distribute the net proceeds to the Contributing Parties. Any common units not purchased by the underwriters pursuant to their option will be issued to the Contributing Parties at the expiration of the option period for no additional consideration. If the underwriters exercise their option to purchase additional common units in full, the additional net proceeds to us would be approximately $ million, after deducting the estimated underwriting discount and structuring fee. We will use any net proceeds from the exercise of the underwriters' option to purchase additional common units from us to make an additional cash distribution to the Contributing Parties.
An increase or decrease in the initial public offering price of $1.00 per common unit would cause the net proceeds from the offering, after deducting the estimated underwriting discount and structuring fee, to increase or decrease by approximately $ million, based on an assumed initial public offering price of $ per common unit. Each increase of 1.0 million common units offered by us, together with a concurrent $1.00 increase in the assumed public offering price of $ per common unit, would increase net proceeds by approximately $ million. Similarly, each decrease of 1.0 million common units offered by us, together with a concurrent $1.00 decrease in the assumed initial public offering price of $ per common unit, would decrease the net proceeds to us from this offering by approximately $ million. If the proceeds increase due to a higher initial public offering price or decrease due to a lower initial public offering price, the cash distribution to the Contributing Parties from the proceeds of this offering will increase or decrease, as applicable, by a corresponding amount.
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The following table shows our cash and cash equivalents and capitalization as of September 30, 2016:
- •
-
on a historical basis for our predecessor; and
- •
- on a pro forma basis to reflect among other things, the portion of our initial assets to be contributed by the Kimbell Art Foundation, Trunk Bay Royalty Partners, Ltd., Oil Nut Bay Royalties, LP, Gorda Sound Royalties, LP and Bitter End Royalties, LP, RCPTX, Ltd., and French Capital Partners, Ltd. (but not by the other Contributing Parties), the offering and the application of the net proceeds from this offering as described under "Use of Proceeds."
This table is derived from, and should be read together with, the historical and pro forma condensed combined financial statements and the accompanying notes included elsewhere in this prospectus. You should also read this table in conjunction with "Use of Proceeds" and "Management's Discussion and Analysis of Financial Condition and Results of Operations."
|
|
As of September 30, 2016 | ||||||
|---|---|---|---|---|---|---|---|
|
|
Predecessor |
Kimbell Royalty
Partners, LP |
|||||
|
|
Historical | Pro Forma | |||||
|
Cash and cash equivalents |
$ | 679,635 | $ | ||||
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
|
Long-term debt |
$ | 10,898,860 | $ | ||||
| | | | | | | | |
|
Members' equity/partners' capital: |
|||||||
|
Members' equity |
$ | 8,675,203 | $ | ||||
|
General partner |
— | ||||||
|
Common units |
— | ||||||
| | | | | | | | |
|
Total members' equity/partners' capital |
$ | 8,675,203 | $ | ||||
| | | | | | | | |
|
Total capitalization |
$ | 19,574,063 | $ | ||||
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
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Purchasers of common units offered by this prospectus will suffer immediate and substantial dilution in net tangible book value per unit. Dilution in net tangible book value per unit represents the difference between the amount per unit paid by purchasers of our common units in this offering and the pro forma net tangible book value per unit immediately after this offering. After giving effect to the sale of common units in this offering at an initial public offering price of $ per common unit, and after deduction of the estimated underwriting discount and structuring fee payable by us in connection with this offering, our pro forma net tangible book value as of September 30, 2016 would have been approximately $ million, or $ per unit. This represents an immediate increase in net tangible book value of $ per unit to our existing unitholders and an immediate pro forma dilution of $ per unit to purchasers of common units in this offering. The following table illustrates this dilution on a per unit basis:
|
Assumed initial public offering price per common unit (1) |
$ | ||||||
|
Pro forma net tangible book value per common unit before the offering (2) |
$ | ||||||
|
Decrease in net tangible book value per common unit attributable to purchasers in the offering |
|||||||
| | | | | | | | |
|
Less: Pro forma net tangible book value per common unit after the offering (3) |
|||||||
| | | | | | | | |
|
Immediate dilution in net tangible book value per common unit to purchasers in the offering (4)(5) |
$ | ||||||
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
- (1)
-
The
mid-point of the price range set forth on the cover of this prospectus.
- (2)
-
Determined
by dividing the pro forma net tangible book value of the contributed assets and liabilities by the number of common units to be issued to the
Contributing Parties for their contribution of assets and liabilities to us.
- (3)
-
Determined
by dividing our pro forma net tangible book value, after giving effect to the use of the net proceeds of the offering, by the total number of
common units outstanding after this offering.
- (4)
-
If
the initial public offering price were to increase or decrease by $1.00 per common unit, then dilution in net tangible book value per common unit would
equal $ and $ , respectively.
- (5)
- Assumes the underwriters' option to purchase additional common units from us is not exercised. If the underwriters' option to purchase additional common units from us is exercised in full, the immediate dilution in net tangible book value per common unit to purchasers in this offering will be $ .
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The following table sets forth the number of units that we will issue and the total consideration contributed to us by the Contributing Parties and by the purchasers of our common units in this offering upon consummation of the transactions contemplated by this prospectus.
- (1)
- Reflects the value of the assets to be contributed to us by the Contributing Parties recorded at historical cost. Book value of the consideration provided by the Contributing Parties, as of September 30, 2016, after giving effect to the formation transactions, is as follows:
|
|
(in thousands) | |||
|---|---|---|---|---|
|
Book value of net assets contributed |
$ | |||
|
Less : Distribution to the Contributing Parties from net proceeds of this offering |
||||
| | | | | |
|
Total consideration |
$ | |||
| | | | | |
- (2)
- Reflects the net proceeds of this offering after deducting the estimated underwriting discount and structuring fee payable by us in connection with this offering, and assumes the underwriter's option to purchase additional common units is not exercised.
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CASH DISTRIBUTION POLICY AND RESTRICTIONS ON DISTRIBUTIONS
You should read the following discussion of our cash distribution policy in conjunction with the specific assumptions included in this section. Please read "—Estimated Cash Available for Distribution for the Twelve Months Ending December 31, 2017—Assumptions and Considerations" below. In addition, you should read "Forward-Looking Statements" and "Risk Factors" for information regarding statements that do not relate strictly to historical or current facts and certain risks inherent in our business.
For additional information regarding our historical and pro forma results of operations, you should refer to our historical financial statements and the accompanying notes and our unaudited pro forma condensed combined financial statements and the accompanying notes included elsewhere in this prospectus.
Our Cash Distribution Policy
Our partnership agreement will require us to distribute all of our cash on hand at the end of each quarter in an amount equal to our available cash for such quarter, beginning with the quarter ending , 2017. Our first distribution, however, will include available cash for the period from the closing of this offering through , 2017. Available cash for each quarter will be determined by the board of directors of our general partner following the end of such quarter. We define available cash in our partnership agreement, in the glossary of terms attached as Appendix B and in "How We Pay Distributions." We expect that available cash for each quarter will generally equal our Adjusted EBITDA for the quarter, less cash needed for debt service and other contractual obligations and fixed charges and reserves for future operating or capital needs that the board of directors may determine is appropriate. We do not currently intend to maintain excess distribution coverage for the purpose of maintaining stability or growth in our quarterly distribution or otherwise to reserve cash for distributions, nor do we intend to incur debt to pay quarterly distributions.
Unlike a number of other master limited partnerships, we do not currently intend to retain cash from our operations for capital expenditures necessary to replace our existing oil and natural gas reserves or otherwise maintain our asset base (replacement capital expenditures), primarily due to our expectation that the continued development of our properties and completion of drilled but uncompleted wells by working interest owners will substantially offset the natural production declines from our existing wells. Although we expect no or limited organic growth at current commodity prices, we believe that our operators have significant drilling inventory remaining on the acreage underlying our mineral or royalty interest in multiple resource plays that will provide a solid base for organic growth when commodity prices increase. The board of directors of our general partner may decide to withhold replacement capital expenditures from cash available for distribution, which would reduce the amount of cash available for distribution in the quarter(s) in which any such amounts are withheld. Over the long term, if our reserves are depleted and our operators become unable to maintain production on our existing properties and we have not been retaining cash for replacement capital expenditures, the amount of cash generated from our existing properties will decrease and we may have to reduce the amount of distributions payable to our unitholders. To the extent that we do not withhold replacement capital expenditures, a portion of our cash available for distribution will represent a return of your capital.
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It is our intent, subject to market conditions, to finance acquisitions of mineral and royalty interests that increase our asset base largely through external sources, such as borrowings under our secured revolving credit facility and the issuance of equity and debt securities, although the board of directors of our general partner may choose to reserve a portion of cash generated from operations to finance such acquisitions as well. We do not currently intend to maintain excess distribution coverage for the purpose of maintaining stability or growth in our quarterly distribution or otherwise reserve cash for distributions, or to incur debt to pay quarterly distributions, although the board of directors of our general partner may change this policy.
Limitations on Cash Distributions and Our Ability to Change Our Cash Distribution Policy
There is no guarantee that we will pay cash distributions to our unitholders each quarter. Our cash distribution policy is subject to certain restrictions, including the following:
- •
-
Following the formation transactions, we expect to borrow approximately $1.5 million under our secured revolving credit
facility to fund certain transaction expenses. We anticipate that our credit agreement and any future debt agreements will contain certain financial tests and covenants that we would have to satisfy.
We may also be prohibited from paying distributions if an event of default or borrowing base deficiency exists under our secured revolving credit facility. If we are unable to satisfy the restrictions
under any future debt agreements, we could be prohibited from paying a distribution to you notwithstanding our stated distribution policy.
- •
-
Our business performance may be volatile, and our cash flows may be less stable, than the business performance and cash flows of most
publicly traded partnerships. As a result, our quarterly cash distributions may be volatile and may vary quarterly and annually.
- •
-
We will not have a minimum quarterly distribution or employ structures intended to maintain or increase quarterly distributions over
time. Furthermore, none of our limited partner interests, including those held by the Contributing Parties, will be subordinate in right of distribution payment to the common units sold in this
offering.
- •
-
Our general partner will have the authority to establish cash reserves for the prudent conduct of our business, and the establishment
of, or increase in, those reserves could result in a reduction in cash distributions to our unitholders. Our partnership agreement does not set a limit on the amount of cash reserves that our general
partner may establish. Any decision to establish cash reserves made by our general partner will be binding on our unitholders.
- •
- Prior to paying any distributions on our units, we will reimburse our general partner and its affiliates, including Kimbell Operating pursuant to its management services agreement discussed below, for all direct and indirect expenses they incur on our behalf. Our partnership agreement provides that our general partner will determine the expenses that are allocable to us, but does not limit the amount of expenses for which our general partner and its affiliates may be reimbursed. In addition, we will enter into a management services agreement with Kimbell Operating, which will enter into separate service agreements with certain entities controlled by Messrs. Duncan, R. Ravnaas, Taylor and Wynne, pursuant to which they and Kimbell Operating will provide management, administrative and operational services to us. The reimbursement of expenses and payment of fees, if any, to our general partner and its affiliates, including Kimbell
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- •
-
Under Section 17-607 of the Delaware Act, we may not pay a distribution if the distribution would cause our liabilities to
exceed the fair value of our assets.
- •
- We may lack sufficient cash to pay distributions to our unitholders due to cash flow shortfalls attributable to a number of commercial or other factors as well as increases in general and administrative expenses, principal and interest payments on our outstanding debt, tax expenses, working capital requirements and anticipated cash needs.
Operating, and to such other entities providing services to us and Kimbell Operating, will reduce the amount of cash to pay distributions to our unitholders.
We expect to generally distribute a significant percentage of our cash from operations to our unitholders on a quarterly basis, after, among other things, the establishment of cash reserves and payment of our expenses. To fund growth, we will eventually need capital in excess of the amounts we may retain in our business. As a result, our growth will depend initially on our operators' ability, and perhaps our ability in the future, to raise debt and equity capital from third parties in sufficient amounts and on favorable terms when needed. To the extent efforts to access capital externally are unsuccessful, our ability to grow will be significantly impaired.
We expect to pay our distributions within 60 days of the end of each quarter. Our first distribution will include available cash for the period from the closing of this offering through , 2017.
In the sections that follow, we present the following two tables:
- •
-
"Unaudited Pro Forma Cash Available for Distribution," in which we present our unaudited estimate of the amount of pro forma cash
available for distribution we would have had for the year ended December 31, 2015 and the twelve months ended September 30, 2016 had this offering and the pro forma formation
transactions been consummated at the beginning of such period, in each case, based on our pro forma condensed combined financial statements included elsewhere in this prospectus; and
- •
- "Estimated Cash Available for Distribution," in which we provide our unaudited forecast of cash available for distribution for the twelve months ending December 31, 2017.
Unaudited Pro Forma Cash Available for Distribution for the Year Ended December 31, 2015 and the Twelve Months Ended September 30, 2016
We estimate that we would have generated $16.3 million and $10.9 million of pro forma cash available for distribution for the year ended December 31, 2015 and the twelve months ended September 30, 2016, respectively. Assuming we do not retain cash from operations for capital expenditures, this amount would have resulted in an aggregate annual distribution equal to $ for the year ended December 31, 2015 and $ for the twelve months ended September 30, 2016.
Our unaudited pro forma cash available for distribution for each of the year ended December 31, 2015 and the twelve months ended September 30, 2016 includes an incremental $1.5 million of general and administrative expenses we expect to incur as a result of becoming a publicly traded partnership. Incremental general and administrative expenses related to being a publicly traded partnership include: expenses associated with SEC reporting requirements, including annual and quarterly reports to unitholders, tax return and Schedule K-1 preparation and distribution expenses, Sarbanes-Oxley Act compliance expenses, expenses associated with
80
listing on the NYSE, independent auditor fees, independent reserve engineer fees, legal fees, investor relations expenses, registrar and transfer agent fees, director and officer insurance expenses and director and officer compensation expenses. These incremental general and administrative expenses are not reflected in the historical financial statements of our predecessor or our pro forma financial statements included elsewhere in this prospectus.
We based the pro forma adjustments upon currently available information and specific estimates and assumptions. The pro forma amounts below do not purport to present our results of operations had this offering and related formation transactions been completed as of the date indicated. In addition, cash available for distribution is primarily a cash accounting concept, while the historical financial statements of our predecessor included elsewhere in this prospectus have been prepared on an accrual basis. As a result, you should view the amount of pro forma cash available for distribution only as a general indication of the amount of cash available for distribution that we might have generated had we completed this offering on the date indicated. Our unaudited pro forma cash available for distribution should be read together with "Selected Historical and Unaudited Pro Forma Financial Data," "Management's Discussion and Analysis of Financial Condition and Results of Operations" and the audited historical financial statements and the accompanying notes included elsewhere in this prospectus.
The following table illustrates, on a pro forma basis, for the year ended December 31, 2015 and for the twelve months ended September 30, 2016, the amount of cash that would have been available for distribution to our unitholders, assuming that this offering and the pro forma formation transactions had been consummated at the beginning of such period. All of the amounts for the year ended December 31, 2015 and the twelve months ended September 30, 2016 in the table below are estimates.
Assets from the Contributing Parties (other than our predecessor, the Kimbell Art Foundation, Trunk Bay Royalty Partners, Ltd., Oil Nut Bay Royalties, LP, Gorda Sound Royalties, LP and Bitter End Royalties, LP, RCPTX, Ltd., and French Capital Partners, Ltd.) are not reflected in the pro forma financial statements. Financial statements relating to these additional assets that will be contributed to us at the consummation of this offering have not been audited and therefore are not presented in the pro forma cash available for distribution for the year ended December 31, 2015 and the twelve months ended September 30, 2016.
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Kimbell Royalty Partners, LP
Pro Forma Cash Available for Distribution
|
|
Year Ended
December 31, 2015 |
Twelve Months
Ended September 30, 2016 |
|||||
|---|---|---|---|---|---|---|---|
|
Revenue: |
|||||||
|
Oil, natural gas and NGL revenues |
$ | 26,691,028 | $ | 21,096,031 | |||
|
Costs and Expenses |
|||||||
|
Production and ad valorem taxes |
2,199,404 | 1,989,121 | |||||
|
Depreciation and depletion expenses |
18,164,181 | 14,165,486 | |||||
|
Impairment of oil and natural gas properties |
27,749,669 | 7,751,957 | |||||
|
Marketing and other deductions (1) |
1,271,104 | 1,429,759 | |||||
|
General and administrative expenses |
5,079,796 | 5,051,218 | |||||
| | | | | | | | |
|
Total costs and expenses |
$ | 54,464,154 | $ | 30,387,541 | |||
| | | | | | | | |
|
Operating loss |
$ | (27,773,126 | ) | $ | (9,291,510 | ) | |
|
Other expense: |
|||||||
|
Interest expense (2) |
308,343 | 308,343 | |||||
| | | | | | | | |
|
Pro forma net loss (3) |
$ | (28,081,469 | ) | $ | (9,599,853 | ) | |
| | | | | | | | |
|
Adjustments to reconcile to pro forma Adjusted EBITDA: |
|||||||
|
Depreciation and depletion expenses |
18,164,181 | 14,165,486 | |||||
|
Impairment of oil and natural gas properties |
27,749,669 | 7,751,957 | |||||
|
Interest expense (2) |
308,343 | 308,343 | |||||
| | | | | | | | |
|
Adjusted EBITDA (4) |
$ | 18,140,724 | $ | 12,625,933 | |||
| | | | | | | | |
|
Adjustments to reconcile pro forma Adjusted EBITDA to cash available for distribution: |
|||||||
|
Less: |
|||||||
|
Incremental general and administrative expenses (5) |
(1,471,000 | ) | (1,471,000 | ) | |||
|
Cash interest expense (2) |
(286,808 | ) | (286,808 | ) | |||
|
Capital expenditures (6) |
(42,000 | ) | — | ||||
| | | | | | | | |
|
Cash available for distribution |
$ | 16,340,916 | $ | 10,868,125 | |||
|
Cash reserves |
— | — | |||||
|
Aggregate distributions to: |
|||||||
|
Common units held by the public |
|||||||
|
Common units held by the Contributing Parties |
|||||||
| | | | | | | | |
|
Total distributions on common units |
$ | $ | |||||
| | | | | | | | |
- (1)
-
Includes
the reclassification of our predecessor's state income taxes into marketing and other deductions of ($32,199) and $11,557 for the year ended
December 31, 2015 and for the twelve months ended September 30, 2016, respectively.
- (2)
-
Interest
expense is based on expected borrowings of $1.5 million at the closing of this offering to fund certain transaction expenses, inclusive of
cash expenses of commitment fees and non-cash amortization of debt issuance costs. Cash interest expense does not include non-cash amortization of debt issuance costs.
- (3)
-
Net
loss for the year ended December 31, 2015 gives effect to the pro forma adjustments reflected in our unaudited pro forma condensed combined
financial statements included elsewhere is this prospectus.
- (4)
- Adjusted EBITDA is a financial measure not presented in accordance with U.S. GAAP. For a definition of Adjusted EBITDA and reconciliation to its most directly comparable financial measure calculated in accordance with U.S.
82
GAAP, please read "Summary—Summary Historical and Unaudited Pro Forma Condensed Combined Financial Data—Non-GAAP Financial Measures."
- (5)
-
Reflects
incremental general and administrative expenses that we expect to incur as a result of operating as a publicly traded partnership that are not
reflected in our pro forma financial statements.
- (6)
- Our capital expenditures during 2015 were funded with cash from operating activities. Historically, we did not make a distinction between maintenance capital expenditures and expansion capital expenditures. Maintenance capital expenditures are those capital expenditures required to maintain our long-term production or asset base, including expenditures to replace our oil and natural gas reserves, through the acquisition of new oil or natural gas properties. The allocation of capital expenditures as maintenance capital expenditures (as opposed to expansion capital expenditures) is determined by our general partner and is supported by management's analysis of the historical and projected decline profiles of wells on the acreage underlying our assets, the current and projected production rates of such wells and wells expected to be drilled, completed and brought online, and the existing and expected development of the acreage underlying our interests by our operators. Based on this analysis, we expect that, over the long term, working interest owners will continue to develop our acreage through infill drilling, hydraulic fracturing, recompletions and secondary and tertiary recovery methods, and, as a result, we have estimated that the amount of maintenance capital expenditures currently necessary to maintain our production over the near term is negligible.
Estimated Cash Available for Distribution for the Twelve Months Ending December 31, 2017
During the twelve months ending December 31, 2017, we estimate that we will generate $24.6 million of cash available for distribution. In "—Assumptions and Considerations" below, we discuss the major assumptions underlying this estimate. The cash available for distribution discussed in the forecast should not be viewed as management's projection of the actual cash available for distribution that we will generate during the twelve months ending December 31, 2017. We can give you no assurance that our assumptions will be realized or that we will generate any cash available for distribution, in which event we will not be able to pay quarterly cash distributions on our common units.
When considering our ability to generate cash available for distribution and how we calculate forecasted cash available for distribution, please keep in mind all the risk factors and other cautionary statements under the headings "Risk Factors" and "Forward-Looking Statements," which discuss factors that could cause our results of operations and available cash to vary significantly from our estimates.
Management has prepared the prospective financial information set forth in the table below to present our expectations regarding our ability to generate $24.6 million of cash available for distribution for the twelve months ending December 31, 2017. The accompanying prospective financial information was not prepared with a view toward public disclosure or complying with the guidelines established by the American Institute of Certified Public Accountants with respect to prospective financial information, but, in the view of our management, was prepared on a reasonable basis, reflects the best currently available estimates and judgments, and presents, to the best of management's knowledge and belief, the expected course of action and our expected future financial performance. However, this information is not fact and should not be relied upon as being necessarily indicative of future results, and readers of this prospectus are cautioned not to place undue reliance on this prospective financial information.
The assumptions and estimates underlying the prospective financial information are inherently uncertain and, though considered reasonable by the management team of our general partner as of the date of its preparation, are subject to a wide variety of significant business, economic, financial, regulatory, environmental and competitive risks and uncertainties that could cause actual results to differ materially from those contained in the prospective financial information. Accordingly, there can be no assurance that the prospective results are indicative of our future performance or that actual results will not differ materially from those presented in
83
the prospective financial information. Inclusion of the prospective financial information in this prospectus should not be regarded as a representation by any person that the results contained in the prospective financial information will be achieved.
We do not undertake any obligation to release publicly the results of any future revisions we may make to the financial forecast or to update this financial forecast to reflect events or circumstances after the date of this prospectus. In light of the above, the statement that we believe that we will have sufficient cash available for distribution to allow us to pay the forecasted quarterly distributions on all of our outstanding common units for the twelve months ending December 31, 2017 should not be regarded as a representation by us or the underwriters or any other person that we will pay such distributions. Therefore, you are cautioned not to place undue reliance on this information.
The following table shows how we calculate estimated cash available for distribution for the twelve months ending December 31, 2017. The assumptions that we believe are relevant to particular line items in the table below are explained in the corresponding footnotes and in "—Assumptions and Considerations."
Neither our independent registered public accounting firm nor any other independent registered public accounting firm has compiled, examined or performed any procedures with respect to the forecasted financial information contained herein, nor has it expressed any opinion or given any other form of assurance on such information or its achievability, and it assumes no responsibility for such forecasted financial information. Our independent registered public accounting firm's reports included elsewhere in this prospectus relate to our audited historical financial statements. These reports do not extend to the table and the related forecasted information contained in this section and should not be read to do so.
84
The following table illustrates the amount of cash available for distribution that we estimate that we will generate for the twelve months ending December 31, 2017 and for each quarter during that twelve-month period that would be available for distribution to our unitholders. All of the amounts for the twelve months ending December 31, 2017 in the table below are estimates and include the assets to be contributed to us at the consummation of this offering.
Kimbell Royalty Partners, LP
Estimated Cash Available for Distribution
(Unaudited)
|
|
Three Months
Ending March 31, 2017 |
Three Months
Ending June 30, 2017 |
Three Months
Ending September 30, 2017 |
Three Months
Ending December 31, 2017 |
Twelve
Months Ending December 31, 2017 |
|||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
|
Revenue: |
||||||||||||||||
|
Oil, natural gas and NGL revenues |
$ | 9,429,875 | $ | 9,224,287 | $ | 8,995,004 | $ | 8,935,872 | $ | 36,585,038 | ||||||
|
Cost and expenses: |
||||||||||||||||
|
Production and ad valorem taxes |
679,051 | 662,321 | 647,396 | 643,259 | 2,632,027 | |||||||||||
|
Depreciation and depletion expenses |
3,384,449 | 3,296,540 | 3,214,621 | 3,203,057 | 13,098,667 | |||||||||||
|
Marketing and other deductions |
680,192 | 664,843 | 641,812 | 638,359 | 2,625,206 | |||||||||||
|
General and administrative expenses (1) |
1,618,753 | 1,618,753 | 1,618,753 | 1,618,753 | 6,475,012 | |||||||||||
| | | | | | | | | | | | | | | | | |
|
Total costs and expenses |
$ | 6,362,445 | $ | 6,242,457 | $ | 6,122,582 | $ | 6,103,428 | $ | 24,830,912 | ||||||
| | | | | | | | | | | | | | | | | |
|
Operating income |
$ | 3,067,430 | $ | 2,981,830 | $ | 2,872,422 | $ | 2,832,444 | $ | 11,754,126 | ||||||
|
Other expense: |
||||||||||||||||
|
Interest expense (2) |
87,327 | 87,327 | 87,327 | 87,327 | 349,308 | |||||||||||
| | | | | | | | | | | | | | | | | |
|
Net Income |
$ | 2,980,103 | $ | 2,894,503 | $ | 2,785,095 | $ | 2,745,117 | $ | 11,404,818 | ||||||
| | | | | | | | | | | | | | | | | |
|
Adjustments to reconcile to pro forma Adjusted EBITDA: |
||||||||||||||||
|
Depreciation and depletion expenses |
3,384,449 | 3,296,540 | 3,214,621 | 3,203,057 | 13,098,667 | |||||||||||
|
Interest expense (2) |
87,327 | 87,327 | 87,327 | 87,327 | 349,308 | |||||||||||
| | | | | | | | | | | | | | | | | |
|
Adjusted EBITDA (3) |
$ | 6,451,879 | $ | 6,278,370 | $ | 6,087,043 | $ | 6,035,500 | $ | 24,852,793 | ||||||
| | | | | | | | | | | | | | | | | |
|
Adjustments to reconcile Adjusted EBITDA to cash available for distribution: |
||||||||||||||||
|
Cash interest expense (2) |
71,702 | 71,702 | 71,702 | 71,702 | 286,808 | |||||||||||
|
Capital expenditures (4) |
— | — | — | — | — | |||||||||||
| | | | | | | | | | | | | | | | | |
|
Cash available for distribution |
$ | 6,380,177 | $ | 6,206,668 | $ | 6,015,341 | $ | 5,963,798 | $ | 24,565,985 | ||||||
|
Cash reserves |
— | — | — | — | — | |||||||||||
|
Aggregate distributions to: |
||||||||||||||||
|
Common units held by the public |
||||||||||||||||
|
Common units held by the Contributing Parties |
||||||||||||||||
| | | | | | | | | | | | | | | | | |
|
Total distributions on common units |
$ | $ | $ | $ | $ | |||||||||||
| | | | | | | | | | | | | | | | | |
- (1)
-
Includes
the $1.5 million in incremental general and administrative expenses that we expect to incur as a result of operating as a publicly traded
partnership that are not reflected in our pro forma financial statements. Please read "—Assumptions and Considerations."
- (2)
-
Interest
expense is based on expected borrowings of $1.5 million at the closing of this offering to fund certain transaction expenses, inclusive of
cash expenses of commitment fees and non-cash amortization of debt issuance costs. Cash interest expense does not include non-cash amortization of debt issuance costs.
- (3)
- Adjusted EBITDA is a financial measure not presented in accordance with U.S. GAAP. For a definition of Adjusted EBITDA and reconciliation to its most directly comparable financial measure calculated in accordance with U.S. GAAP, please read
85
"Summary—Summary Historical and Unaudited Pro Forma Condensed Combined Financial Data—Non-GAAP Financial Measures."
- (4)
- Historically, we did not make a distinction between maintenance capital expenditures and expansion capital expenditures. Maintenance capital expenditures are those capital expenditures required to maintain our long-term production or asset base, including expenditures to replace our oil and natural gas reserves, through the acquisition of new oil or natural gas properties. The allocation of capital expenditures as maintenance capital expenditures (as opposed to expansion capital expenditures) is determined by our general partner and is supported by management's analysis of the historical and projected decline profiles of wells on the acreage underlying our assets, the current and projected production rates of such wells and wells expected to be drilled, completed and brought online, and the existing and expected development of the acreage underlying our interests by our operators. Based on this analysis, we expect that, over the long term, working interest owners will continue to develop our acreage through infill drilling, hydraulic fracturing, recompletions and secondary and tertiary recovery methods, and, as a result, we have estimated that the amount of maintenance capital expenditures currently necessary to maintain our production over the near term is negligible. However, the board of directors of our general partner may in the future determine that capital expenditures incurred in connection with acquisitions are required to be made to maintain our production over the long term, in which case, we will be required to deduct an estimated amount of such capital expenditures from our operating surplus in each quarter. This would reduce the amount of cash available for distribution.
Assumptions and Considerations
Based upon the specific assumptions outlined below, we expect to generate cash available for distribution in an amount sufficient to allow us to pay $ per common unit on all of our outstanding units for the twelve months ending December 31, 2017.
While we believe that these assumptions are reasonable in light of our management's current expectations concerning future events, the estimates underlying these assumptions are inherently uncertain and are subject to significant business, economic, regulatory, environmental and competitive risks and uncertainties that could cause actual results to differ materially from those we anticipate. If our assumptions are not correct, the amount of actual cash available to pay distributions could be substantially less than the amount we currently estimate and could, therefore, be insufficient to allow us to pay the forecasted cash distribution, or any amount, on our outstanding common units, in which event the market price of our common units may decline substantially. When reading this section, you should keep in mind the risk factors and other cautionary statements under the headings "Risk Factors" and "Forward-Looking Statements." Any of the risks discussed in this prospectus could cause our actual results to vary significantly from our estimates.
General Considerations
Substantially all of the anticipated increase in our estimated distributable cash flow for the twelve months ending December 31, 2017, compared to the pro forma year ended December 31, 2015 and the pro forma twelve months ended September 30, 2016, is primarily attributable to:
Assets from Contributing Parties not reflected in pro forma financial statements. Our estimate of cash available for distribution for the twelve months ending December 31, 2017 includes the additional assets that will be contributed to us at the consummation of this offering and which have not been audited and therefore are not presented in the pro forma cash available for distribution for the year ended December 31, 2015 and the twelve months ended September 30, 2016. These additional assets represent approximately 25% of our future undiscounted cash flows, based on the reserve report prepared by Ryder Scott as of December 31, 2015. During the year ended December 31, 2015 and the twelve months ended September 30, 2016, the operators on the properties reflected in our pro forma financial statements produced volumes of 917,751 Boe and 904,921 Boe, respectively, compared to our forecast of 1,076,524 Boe for the twelve months ending December 31, 2017. The volume increase reflected in the forecast compared to the year ended December 31, 2015 and the twelve months
86
ended September 30, 2016 is 17.3% and 19.0%, respectively. The volume increase for these periods is primarily attributable to the addition of the assets discussed above offset by a slight decline in forecasted volumes attributable to both the additional assets and those reflected in the pro forma financial statements.
Commodity prices. During the year ended December 31, 2015 and the twelve months ended September 30, 2016, our average realized price per Boe was $29.08 and $23.31, respectively, compared to the estimated weighted average NYMEX strip price of $33.98 per Boe for the twelve months ending December 31, 2017 as of December 27, 2016, based on our forecasted production volumes. Our average realized price per Boe gives effect to the differentials between published oil and natural gas prices and the prices actually received for the oil and natural gas production. These differentials may vary significantly due to market conditions, transportation, gathering and processing costs, quality of production and other factors. The price increase reflected in the forecast compared to the year ended December 31, 2015 and the twelve months ended September 30, 2016 is 16.9% and 45.8%, respectively.
Cash available for distribution. We estimate an $8.2 million increase in cash available for distribution for the twelve months ending December 31, 2017 as compared to the year ended December 31, 2015. The 17.3% increase in production volumes accounts for $4.6 million of the increase and the 16.9% increase in estimated price per Boe accounts for $5.3 million, offset by $1.4 million in estimated increased marketing and other deductions and $0.4 million in estimated increased production and ad valorem taxes. We do not expect the addition of our other assets at the consummation of this offering from the other Contributing Parties to result in significant additional general and administrative expenses because these Contributing Parties have invested in substantially the same assets as those that are reflected in our pro forma financial statements, and therefore the management and administration of these properties is not expected to burden our general and administrative expenses in a significant manner.
We estimated a $13.7 million increase in cash available for distribution for the twelve months ending December 31, 2017 when compared to the twelve months ended September 30, 2016. The increase was primarily attributable to the 19.0% increase in production volumes which accounted for $4.0 million of the increase and the 45.8% increase in price per Boe accounted for $11.5 million, offset by $1.2 million in increased marketing and other deductions and $0.6 million in increased production and ad valorem taxes.
Operations and Revenue
Oil, natural gas and natural gas liquids revenues. Substantially all our revenues are a function of oil, natural gas and natural gas liquids production volumes sold and average prices received for those volumes. Based on the production and pricing information included below, we estimate that our oil, natural gas and natural gas liquids revenues for the twelve months ending December 31, 2017 will be $36.6 million. For information on the effect of changes in prices and productions volumes, please read "—Sensitivity Analysis."
87
Production. The following table sets forth information regarding production on the properties underlying our interests for the twelve months ended December 31, 2015, September 30, 2016 and for the twelve months ending December 31, 2017:
|
|
Twelve Months Ended |
Twelve
Months Ending |
||||||||
|---|---|---|---|---|---|---|---|---|---|---|
|
|
December 31,
2015 |
September 30,
2016 |
December 31,
2017 |
|||||||
|
Production: |
||||||||||
|
Oil (Bbls) |
363,346 | 346,373 | 413,424 | |||||||
|
Natural Gas (Mcf) |
2,573,681 | 2,670,300 | 3,270,301 | |||||||
|
Natural gas liquids (Bbls) |
125,458 | 113,497 | 118,049 | |||||||
|
Combined volumes (BOE) |
917,751 | 904,921 | 1,076,524 | |||||||
|
Average daily production: |
|
|
|
|||||||
|
Oil (Bbl/d) |
995 | 946 | 1,133 | |||||||
|
Natural gas (Mcf/d) |
7,051 | 7,296 | 8,960 | |||||||
|
Natural gas liquids (Bbl/d) |
344 | 310 | 323 | |||||||
|
Combined volumes (BOE/d) |
2,514 | 2,472 | 2,949 | |||||||
We estimate that oil and natural gas production from the properties underlying our interests for the twelve months ending December 31, 2017 will be 1,077 MBOE. We estimate the average daily production for the three months ending March 31, 2017, June 30, 2017, September 30, 2017 and December 31, 2017, will be 3,091 BOE/d, 2,977 BOE/d, 2,872 BOE/d and 2,861 BOE/d, respectively.
We own a diversified portfolio of interests in oil and natural gas properties. Substantially all our revenues are a function of oil and natural gas production volumes sold and average prices received for those volumes. Our forecasted production is derived from existing wells on our assets and from new wells projected to begin producing during the year. Although we lack the influence of a working interest partner in the drilling schedule for PUD locations, we are able to forecast a drilling schedule for PUD reserves based on a multi-factor analysis, which we believe provides a reasonable basis for our estimations. As part of this multi-factor analysis, we obtain information from state regulatory agencies and third-party sources regarding production data on a well-by-well basis for each basin and play in which we own assets, including updates on each well's status throughout the drilling process. We examine this information on an acquisition-by-acquisition basis and devote resources to our analysis in proportion to the relative size of the acquisitions. We also review information regarding permits granted to our operators and rig activity and location on our acreage, in each case prioritizing review of our most significant operators and locations. Our ability to monitor permit trends, rig activity and rig location on our acreage is a critical component of our analysis. On a basin and play-wide perspective, we are able to determine where our operators deploy their assets by reviewing, among other things, our operators' publicly announced allotment of capital expenditures, proposed number of new wells drilled each year and additional spacing testing. Access to this information, including permits granted, wells spudded, wells drilled to total depth and wells completed and waiting for first connection, enables us to track well development through all phases of exploration and production on the acreage in each basin and play in which we own an interest.
We also review investor presentations and other public statements of our operators before booking undeveloped reserves and have general discussions with what we believe to be a
88
representative sampling of our operators to ascertain their reserve booking plans. On a pro forma basis for the year ended December 31, 2015, our top ten operators accounted for approximately 53.3% of our revenue. Information regarding reserve booking plans was gathered for all of these operators. We believe that the public statements and guidance by the operators of our acreage regarding future drilling activity, coupled with the historical information we gather, enable us to forecast a drilling schedule for PUD locations.
Prices. The table below illustrates the relationship between average realized sales prices and the estimated weighted average of the monthly NYMEX strip prices as of December 27, 2016 for the twelve months ending December 31, 2017 (held constant throughout the period):
|
Forecasted average oil sales prices: |
||||
|
NYMEX-WTI oil price per Bbl |
$ | 55.97 | ||
|
Differential to NYMEX-WTI oil per Bbl (1) |
$ | (4.67 | ) | |
|
Realized oil sales price per Bbl |
$ | 51.30 | ||
|
Forecasted average natural gas liquids sales prices: |
|
|||
|
NYMEX-WTI oil price per Bbl |
$ | 55.97 | ||
|
Differential to NYMEX-WTI oil per Bbl (1) |
$ | (34.93 | ) | |
|
Realized natural gas liquids sales price per Bbl |
$ | 21.04 | ||
|
Forecasted average natural gas sales prices: |
|
|||
|
NYMEX-Henry Hub per price MMBtu |
$ | 3.61 | ||
|
Differential to NYMEX-Henry Hub natural gas (1) |
$ | 0.33 | ||
|
Realized natural gas sales price per Mcf |
$ | 3.94 | ||
|
Total weighted average combined realized price (per BOE) |
$ |
33.98 |
- (1)
- Differentials between published oil and natural gas prices and the prices actually received for the oil and natural gas production may vary significantly due to market conditions, transportation, gathering and processing costs, quality of production and other factors. The differentials to published oil and natural gas prices are based upon our analysis of the historic price differentials for production from the mineral interests with consideration given to gravity, quality and transportation and marketing costs that may affect these differentials. There is no assurance that these assumed differentials will occur.
Costs and Expenses
Production and ad valorem taxes. The following table summarizes production and ad valorem taxes (in thousands) on a forecast basis for the twelve months ending December 31, 2017:
|
Production taxes |
$ | 1,653 | ||
|
Ad valorem taxes |
$ | 979 | ||
| | | | | |
|
Total production and ad valorem taxes |
$ | 2,632 | ||
|
Production and ad valorem taxes as a percentage of revenue |
7.2% |
Our production taxes are calculated as a percentage of our oil, natural gas and NGL revenues. In general, as prices and volumes increase, our production taxes increase. As prices and volumes decrease, our production taxes decrease. Ad valorem taxes are jurisdictional taxes levied on the value of oil and natural gas minerals and reserves. Rates, methods of calculating property values, and timing of payments vary between taxing authorities. Due to the direct nature of the reserve value to the price of the commodity, as commodity prices fluctuate, the
89
valuation of the underlying reserves generally fluctuate with the price, therefore, the cost of ad valorem taxes generally correlate to the changes in oil, natural gas and NGL revenues.
Depreciation and depletion expenses. We estimate that our depreciation and depletion expenses for the twelve months ending December 31, 2017 will be $13.1 million. The forecasted depreciation and depletion expense is based on the production estimates in our reserve reports. The per BOE depletion rate is $12.17.
Marketing and other deductions. We estimate that our marketing and other deductions for the twelve months ending December 31, 2017 will be $2.6 million. The forecasted marketing and other deductions is based on our historical marketing and other deductions applied to our forecasted production, which is based on our reserve reports.
General and administrative expenses. We estimate that our general and administrative expenses for the twelve months ending December 31, 2017 will be $6.5 million, including $2.1 million owed pursuant to the terms of service agreements with Kimbell Operating and affiliates of our Sponsors and an incremental $1.5 million of general and administrative expenses we expect to incur as a result of becoming a publicly traded partnership.
Interest expense. We estimate that we will have $349,308 in interest expense for the twelve months ending December 31, 2017. The new $50.0 million secured revolving credit facility we expect to enter into in connection with the closing of this offering is forecasted to have $1.5 million of borrowings outstanding, which we expect to use to fund certain transaction expenses at the closing of this offering. We will incur a commitment fee of $242,500 and amortization of deferred finance costs of $62,500.
Financing
At the closing of this offering, we expect to enter into a $50.0 million secured revolving credit facility with an accordion feature permitting aggregate commitments under the facility to be increased up to $100.0 million (subject to the satisfaction of certain conditions and the procurement of additional commitments from new or existing lenders). We expect that the unused portion of the secured revolving credit facility will be subject to a commitment fee equal to 50 basis points.
Capital Expenditures
We do not forecast any capital expenditures or acquisitions during the forecast period. Based on management's analysis, we expect that, over the long term, working interest owners will continue to develop our acreage through infill drilling, hydraulic fracturing, recompletions and secondary and tertiary recovery methods, and, as a result, we have estimated that we will not incur maintenance capital expenditures during the forecast period.
Regulatory, Industry and Economic Factors
Our forecast for the twelve months ending December 31, 2017 is based on the following significant assumptions related to regulatory, industry and economic factors:
- •
- there will not be any new federal, state or local regulation of portions of the energy industry in which we operate, or an interpretation of existing regulation, that will be materially adverse to our business;
90
- •
-
there will not be any major adverse change in commodity prices or the energy industry in general;
- •
-
our third party operators will continue to conduct their operations in a manner that is not substantially different than currently
conducted;
- •
-
market, insurance and overall economic conditions will not change substantially; and
- •
- we will not undertake any extraordinary transactions that would materially affect our cash flow.
Forecasted Distributions
We intend to distribute aggregate quarterly distributions on our common units for the twelve months ending December 31, 2017 of $ million. While we believe that the assumptions we have used in preparing the estimates set forth above are reasonable based upon management's current expectations concerning future events, they are inherently uncertain and are subject to significant business, economic regulatory and competitive risks and uncertainties, including those described in "Risk Factors," that could cause actual results to differ materially from those we anticipate. If our actual results are significantly below forecasted results, or if our expenses are greater than forecasted, we may not be able to pay the forecasted annual distribution on all our outstanding common units in respect of the four calendar quarters ending December 31, 2017 or thereafter, which may cause the market price of our common units to decline materially.
Sensitivity Analysis
Our ability to generate sufficient cash from operations to pay distributions to our unitholders is a function of two primary variables: (i) production volumes and (ii) commodity prices. In the paragraphs below, we demonstrate the impact that changes in either of these variables, while holding all other variables constant, would have on our ability to generate sufficient cash from our operations to pay quarterly distributions on our common units for the twelve months ending December 31, 2017.
91
Production Volume Changes
The following table shows estimated cash available for distribution under production levels of 90%, 100% and 110% of the production level we have forecasted for the twelve months ending December 31, 2017.
|
|
Percentage of Forecasted Annual
Production |
|||||||||
|---|---|---|---|---|---|---|---|---|---|---|
|
Forecasted annual production: |
90 | % | 100 | % | 110 | % | ||||
|
Oil (Bbls) |
372,082 | 413,424 | 454,767 | |||||||
|
Natural Gas (Mcf) |
2,943,271 | 3,270,301 | 3,597,332 | |||||||
|
Natural gas liquids (Bbls) |
106,244 | 118,049 | 129,854 | |||||||
|
Combined volumes (BOE) |
968,871 | 1,076,524 | 1,184,176 | |||||||
|
Forecasted average daily production: |
|
|
|
|||||||
|
Oil (Bbl/d) |
1,019 | 1,133 | 1,246 | |||||||
|
Natural gas (Mcf/d) |
8,064 | 8,960 | 9,856 | |||||||
|
Natural gas liquids (Bbl/d) |
291 | 323 | 356 | |||||||
|
Combined volumes (BOE/d) |
2,654 | 2,949 | 3,244 | |||||||
|
Forecasted average oil sales prices: |
100 |
% |
100 |
% |
100 |
% |
||||
|
NYMEX-WTI oil price per Bbl |
$ | 55.97 | $ | 55.97 | $ | 55.97 | ||||
|
Realized oil sales price per Bbl |
$ | 51.30 | $ | 51.30 | $ | 51.30 | ||||
|
NYMEX-WTI oil price per Bbl |
$ |
55.97 |
$ |
55.97 |
$ |
55.97 |
||||
|
Realized natural gas liquids sales price per Bbl |
$ | 21.04 | $ | 21.04 | $ | 21.04 | ||||
|
Forecasted average natural gas sales prices: |
|
|
|
|||||||
|
NYMEX-Henry Hub natural gas price per MMBtu |
$ | 3.61 | $ | 3.61 | $ | 3.61 | ||||
|
Realized natural gas sales price per Mcf |
$ | 3.94 | $ | 3.94 | $ | 3.94 | ||||
|
Revenue: |
|
|
|
|||||||
|
Oil, natural gas and NGL revenues |
$ | 32,926 | $ | 36,585 | $ | 40,243 | ||||
|
Cost and expenses: |
|
|
|
|||||||
|
Production and ad valorem taxes |
2,369 | 2,632 | 2,895 | |||||||
|
Depreciation and depletion expenses |
11,789 | 13,099 | 14,409 | |||||||
|
Marketing and other deductions |
2,363 | 2,625 | 2,888 | |||||||
|
General and administrative expenses (1) |
6,475 | 6,475 | 6,475 | |||||||
| | | | | | | | | | | |
|
Total costs and expenses |
$ | 22,996 | $ | 24,831 | $ | 26,667 | ||||
| | | | | | | | | | | |
|
Operating income |
$ | 9,930 | $ | 11,754 | $ | 13,576 | ||||
|
Other expense: |
|
|
|
|||||||
|
Interest expense (2) |
349 | 349 | 349 | |||||||
| | | | | | | | | | | |
|
Net Income |
$ | 9,581 | $ | 11,405 | $ | 13,227 | ||||
| | | | | | | | | | | |
|
Adjustments to reconcile to pro forma Adjusted EBITDA: |
||||||||||
|
Depreciation and depletion expenses |
11,789 | 13,099 | 14,409 | |||||||
|
Interest expense (2) |
349 | 349 | 349 | |||||||
| | | | | | | | | | | |
|
Adjusted EBITDA (3) |
$ | 21,719 | $ | 24,853 | $ | 27,985 | ||||
| | | | | | | | | | | |
|
Adjustments to reconcile Adjusted EBITDA to cash available for distribution: |
||||||||||
|
Cash interest expense (2) |
287 | 287 | 287 | |||||||
|
Capital expenditures |
— | — | — | |||||||
| | | | | | | | | | | |
|
Cash available for distribution |
$ | 21,432 | $ | 24,566 | $ | 27,698 | ||||
|
Cash reserves |
— | — | — | |||||||
|
Aggregate distributions to: |
||||||||||
|
Common units held by the public |
||||||||||
|
Common units held by the Contributing Parties |
||||||||||
|
Total distributions on common units |
||||||||||
- (1)
-
Includes
the $1.5 million in incremental general and administrative expenses that we expect to incur as a result of operating as a publicly traded
partnership that are not reflected in our pro forma financial statements. Please read "—Assumptions and Considerations."
- (2)
-
Interest
expense is based on expected borrowings of $1.5 million at the closing of this offering to fund certain transaction expenses, inclusive of
cash expenses of commitment fees and non-cash amortization of debt issuance costs. Cash interest expense does not include non-cash amortization of debt issuance costs.
- (3)
- Adjusted EBITDA is a financial measure not presented in accordance with U.S. GAAP. For a definition of Adjusted EBITDA and reconciliation to its most directly comparable financial measure calculated in accordance with U.S. GAAP, please read "Summary—Summary Historical and Unaudited Pro Forma Condensed Combined Financial Data—Non-GAAP Financial Measures."
92
Commodity Price Changes
The following table shows estimated cash available for distribution under various assumed NYMEX-WTI oil and natural gas prices for the twelve months ending December 31, 2017. The amounts shown below are based on forecasted realized commodity prices that take into account our average NYMEX commodity price differential assumptions. We have assumed no changes in our production based on changes in prices.
|
Forecasted annual production: |
||||||||||
|
Oil (Bbls) |
413,424 | 413,424 | 413,424 | |||||||
|
Natural Gas (Mcf) |
3,270,301 | 3,270,301 | 3,270,301 | |||||||
|
Natural gas liquids (Bbls) |
118,049 | 118,049 | 118,049 | |||||||
|
Combined volumes (BOE) |
1,076,524 | 1,076,524 | 1,076,524 | |||||||
|
Forecasted average daily production: |
|
|
|
|||||||
|
Oil (Bbl/d) |
1,133 | 1,133 | 1,133 | |||||||
|
Natural gas (Mcf/d) |
8,960 | 8,960 | 8,960 | |||||||
|
Natural gas liquids (Bbl/d) |
323 | 323 | 323 | |||||||
|
Combined volumes (BOE/d) |
2,949 | 2,949 | 2,949 |
|
|
Percentage Change in Commodity Price | |||||||||
|---|---|---|---|---|---|---|---|---|---|---|
|
Forecasted average oil sales prices: |
90 | % | 100 | % | 110 | % | ||||
|
NYMEX-WTI oil price per Bbl |
$ | 50.37 | $ | 55.97 | $ | 61.57 | ||||
|
Realized oil sales price per Bbl |
$ | 46.17 | $ | 51.30 | $ | 56.42 | ||||
|
NYMEX-WTI oil price per Bbl |
$ |
50.37 |
$ |
55.97 |
$ |
61.57 |
||||
|
Realized natural gas liquids sales price per Bbl |
$ | 18.93 | $ | 21.04 | $ | 23.14 | ||||
|
Forecasted average natural gas sales prices: |
|
|
|
|||||||
|
NYMEX-Henry Hub natural gas price per MMBtu |
$ | 3.25 | $ | 3.61 | $ | 3.97 | ||||
|
Realized natural gas sales price per Mcf |
$ | 3.55 | $ | 3.94 | $ | 4.34 | ||||
|
Revenue: |
|
|
|
|||||||
|
Oil, natural gas and NGL revenues |
$ | 32,926 | $ | 36,585 | $ | 40,243 | ||||
|
Cost and expenses: |
|
|
|
|||||||
|
Production and ad valorem taxes |
2,369 | 2,632 | 2,895 | |||||||
|
Depreciation and depletion expenses |
13,099 | 13,099 | 13,099 | |||||||
|
Marketing and other deductions |
2,363 | 2,625 | 2,888 | |||||||
|
General and administrative expenses (1) |
6,475 | 6,475 | 6,475 | |||||||
| | | | | | | | | | | |
|
Total costs and expenses |
$ | 24,306 | $ | 24,831 | $ | 25,357 | ||||
| | | | | | | | | | | |
|
Operating income |
$ | 8,620 | $ | 11,754 | $ | 14,886 | ||||
|
Other expense: |
|
|
|
|||||||
|
Interest expense (2) |
349 | 349 | 349 | |||||||
| | | | | | | | | | | |
|
Net Income |
$ | 8,271 | $ | 11,405 | $ | 14,537 | ||||
| | | | | | | | | | | |
|
Adjustments to reconcile to pro forma Adjusted EBITDA: |
||||||||||
|
Depreciation and depletion expenses |
13,099 | 13,099 | 13,099 | |||||||
|
Interest expense (2) |
349 | 349 | 349 | |||||||
| | | | | | | | | | | |
|
Adjusted EBITDA (3) |
$ | 21,719 | $ | 24,853 | $ | 27,985 | ||||
| | | | | | | | | | | |
|
Adjustments to reconcile Adjusted EBITDA to cash available for distribution: |
||||||||||
|
Cash interest expense (2) |
287 | 287 | 287 | |||||||
|
Capital expenditures |
— | — | — | |||||||
| | | | | | | | | | | |
|
Cash available for distribution |
$ | 21,432 | $ | 24,566 | $ | 27,698 | ||||
|
Cash reserves |
— | — | — | |||||||
|
Aggregate distributions to: |
||||||||||
|
Common units held by the public |
||||||||||
|
Common units held by the Contributing Parties |
||||||||||
|
Total distributions on common units |
||||||||||
- (1)
-
Includes
the $1.5 million in incremental general and administrative expenses that we expect to incur as a result of operating as a publicly traded
partnership that are not reflected in our pro forma financial statements. Please read "—Assumptions and Considerations."
- (2)
-
Interest
expense is based on expected borrowings of $1.5 million at the closing of this offering to fund certain transaction expenses, inclusive of
cash expenses of commitment fees and non-cash amortization of debt issuance costs. Cash interest expense does not include non-cash amortization of debt issuance costs.
- (3)
- Adjusted EBITDA is a financial measure not presented in accordance with U.S. GAAP. For a definition of Adjusted EBITDA and reconciliation to its most directly comparable financial measure calculated in accordance with U.S. GAAP, please read "Summary—Summary Historical and Unaudited Pro Forma Condensed Combined Financial Data—Non-GAAP Financial Measures."
93
Our partnership agreement requires that, within 60 days after the end of each quarter, we distribute all of our available cash to unitholders of record on the applicable record date. Our first distribution will include available cash for the period from the closing of this offering through , 2017. We define available cash in the glossary of terms attached as Appendix B, and it generally means all cash on hand at the end of that quarter:
- •
-
less the amount of cash reserves established by our general partner to:
- •
-
provide for the proper conduct of our business (including reserves for our future capital expenditures, future
acquisitions and anticipated future debt service requirements);
- •
-
comply with applicable law, any of our or our subsidiaries' debt instruments or other agreements; or
- •
-
provide funds for distributions to our unitholders and to our general partner for any one or more of the next four
quarters;
- •
- plus, if our general partner so determines, all or a portion of cash on hand on the date of determination of available cash for the quarter including cash from working capital borrowings. Working capital borrowings are generally borrowings incurred under a credit facility, commercial paper facility or similar financing arrangement that are used solely for working capital purposes or to pay distributions to unitholders, and with the intent of the borrower to repay such borrowings within 12 months with funds other than additional working capital borrowings.
Please read "Cash Distribution Policy and Restrictions on Distributions."
In addition, the limited liability company agreement of our general partner will contain provisions that prohibit certain actions without a supermajority vote of at least 66 2 / 3 % of the members of the board of directors of our general partner, including:
- •
-
the incurrence of borrowings in excess of 2.5 times our Debt to EBITDAX Ratio for the preceding four quarters;
- •
-
the reservation of a portion of cash generated from operations to finance acquisitions;
- •
-
modifications to the definition of "Available Cash" in our partnership agreement; and
- •
- the issuance of any partnership interests that rank senior in right of distributions or liquidation to our common units.
Please read "The Partnership Agreement—Certain Provisions of the Agreement Governing our General Partner."
94
We intend to distribute available cash to our unitholders, pro rata. Our partnership agreement permits us to borrow to pay distributions, but we are not required to, and do not intend to, borrow to pay quarterly distributions. Accordingly, there is no guarantee that we will pay any distribution on the units in any quarter.
At the closing of this offering, we will have common units outstanding. Each common unit will be entitled to receive cash distributions to the extent we distribute available cash. Common units will not accrue arrearages. Our partnership agreement allows us to issue an unlimited number of additional equity interests of equal or senior rank.
Upon the closing of this offering, our general partner will own a non-economic general partner interest in us and therefore will not be entitled to receive cash distributions. However, it may acquire common units and other partnership interests in the future and will be entitled to receive pro rata distributions in respect of those partnership interests.
95
SELECTED HISTORICAL AND UNAUDITED PRO FORMA FINANCIAL DATA
Kimbell Royalty Partners, LP was formed in October 2015. In this prospectus, we present the historical financial statements of Rivercrest Royalties, LLC, our predecessor for accounting purposes. We refer to this entity as "our predecessor." The following table presents selected historical financial data of our predecessor and selected unaudited pro forma financial data of Kimbell Royalty Partners, LP as of the dates and for the years indicated.
The selected historical financial data of our predecessor presented as of and for the years ended December 31, 2015 and 2014 are derived from the audited historical financial statements of our predecessor included elsewhere in this prospectus. The selected historical financial data presented as of September 30, 2016 and 2015 and for the nine months ended September 30, 2016 and 2015 are derived from the unaudited historical financial statements of our predecessor.
The selected unaudited pro forma financial data presented as of and for the nine months ended September 30, 2016 and for the year ended December 31, 2015 are derived from our unaudited pro forma financial statements included elsewhere in this prospectus and give effect to the following transactions:
- •
-
The assignment by our predecessor and associated entities to certain of their affiliates of certain non-operated working interests and
net profits interests that will not be contributed to us;
- •
-
Our acquisition of assets to be contributed by our predecessor and the Kimbell Art Foundation, Trunk Bay Royalty
Partners, Ltd., Oil Nut Bay Royalties, LP, Gorda Sound Royalties, LP and Bitter End Royalties, LP, RCPTX, Ltd., and French Capital Partners, Ltd. (but not by the other
Contributing Parties);
- •
-
The issuance by us of an aggregate of common units to all the Contributing Parties;
- •
-
The issuance by us of common units to the public in this offering at an assumed initial public offering price of
$ per common unit, which is the mid-point of the range set forth on the cover of the prospectus;
- •
-
The use of the net proceeds from this offering as set forth in "Use of Proceeds";
- •
-
Our expected entrance into a new $50.0 million secured revolving credit facility with an accordion feature permitting aggregate
commitments under the facility to be increased up to $100.0 million (subject to the satisfaction of certain conditions and the procurement of additional commitments from new or existing
lenders), pursuant to which we expect to borrow approximately $1.5 million at the closing of this offering to fund certain transaction expenses; and
- •
- Our entrance into a management services agreement with Kimbell Operating, which will enter into separate service agreements with certain entities controlled by Messrs. Duncan, R. Ravnaas, Taylor and Wynne.
The unaudited pro forma condensed combined balance sheet as of September 30, 2016 assumes the events described above occurred as of September 30, 2016. The unaudited pro forma condensed combined statements of operations for the nine months ended September 30,
96
2016 and the year ended December 31, 2015 assume the events described above occurred as of January 1, 2015.
We have not given pro forma effect to our acquisition of assets to be contributed by the Contributing Parties other than our predecessor, the Kimbell Art Foundation, Trunk Bay Royalty Partners, Ltd., Oil Nut Bay Royalties, LP, Gorda Sound Royalties, LP and Bitter End Royalties, LP, RCPTX, Ltd., and French Capital Partners, Ltd., which excluded assets represent approximately 25% of our future undiscounted cash flows, based on the reserve report prepared by Ryder Scott as of December 31, 2015.
We have not given pro forma effect to incremental general and administrative expenses of approximately $1.5 million that we expect to incur annually as a result of operating as a publicly traded partnership, such as expenses associated with SEC reporting requirements, including annual and quarterly reports to unitholders, tax return and Schedule K-1 preparation and distribution expenses, Sarbanes-Oxley Act compliance expenses, expenses associated with listing on the NYSE, independent auditor fees, independent reserve engineer fees, legal fees, investor relations expenses, registrar and transfer agent fees, director and officer insurance expenses and director and officer compensation expenses.
For a detailed discussion of the selected historical financial data contained in the following table, please read "Management's Discussion and Analysis of Financial Condition and Results of Operations." The following table should also be read in conjunction with "Use of Proceeds" and the audited historical financial statements of our predecessor and our pro forma condensed combined financial statements included elsewhere in this prospectus. Among other things, the historical financial statements include more detailed information regarding the basis of presentation for the information in the following table.
The following table presents Adjusted EBITDA, a financial measure that is not presented in accordance with GAAP. We use Adjusted EBITDA in our business as we believe it is an important supplemental measure of our operating performance and liquidity. For a definition of and a reconciliation of Adjusted EBITDA to net income and net cash provided by operating activities, its most directly comparable financial measures in accordance with GAAP, please read "—Non-GAAP Financial Measures." For a discussion of how we use Adjusted EBITDA to evaluate our operating performance and liquidity, please read "Management's Discussion and Analysis of Financial Condition and Results of Operations—Adjusted EBITDA."
97
- (1)
- For more information, please read "—Non-GAAP Financial Measures."
Adjusted EBITDA
Adjusted EBITDA is used as a supplemental non-GAAP financial measure by management and external users of our financial statements, such as industry analysts, investors, lenders and
98
rating agencies. We believe Adjusted EBITDA is useful because it allows us to more effectively evaluate our operating performance and compare the results of our operations period to period without regard to our financing methods or capital structure. In addition, management uses Adjusted EBITDA to evaluate cash flow available to pay distributions to our unitholders.
We define Adjusted EBITDA as net income (loss) plus interest expense, net of capitalized interest, non-cash unit-based compensation, impairment of oil and natural gas properties, income taxes and depreciation, depletion and accretion expense. Adjusted EBITDA is not a measure of net income (loss) or net cash provided by operating activities as determined by GAAP. We exclude the items listed above from net income (loss) in arriving at Adjusted EBITDA because these amounts can vary substantially from company to company within our industry depending upon accounting methods and book values of assets, capital structures and the method by which the assets were acquired. Certain items excluded from Adjusted EBITDA are significant components in understanding and assessing a company's financial performance, such as a company's cost of capital and tax structure, as well as historic costs of depreciable assets, none of which are components of Adjusted EBITDA.
Adjusted EBITDA should not be considered an alternative to net income, oil, natural gas and natural gas liquids revenues, net cash provided by operating activities or any other measure of financial performance or liquidity presented in accordance with GAAP. Our computations of Adjusted EBITDA may not be comparable to other similarly titled measures of other companies.
The following tables present a reconciliation of Adjusted EBITDA to net income and net cash provided by operating activities, our most directly comparable GAAP financial measures for the periods indicated.
99
|
|
Predecessor Historical | ||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
|
|
Nine Months Ended
September 30, |
Year Ended
December 31, |
|||||||||||
|
|
2016 | 2015 | 2015 | 2014 | |||||||||
|
Reconciliation of net cash provided by operating activities to Adjusted EBITDA: |
|||||||||||||
|
Net cash provided by operating activities |
$ | 956,793 | $ | 2,317,594 | $ | 2,713,133 | $ | 4,038,018 | |||||
|
Interest expense |
314,081 | 282,372 | 385,119 | 302,118 | |||||||||
|
State income taxes |
13,401 | 11,557 | (32,199 | ) | 16,970 | ||||||||
|
Impairment of oil and natural gas properties |
(4,992,897 | ) | (25,796,352 | ) | (28,673,166 | ) | (7,416,747 | ) | |||||
|
Amortization of loan origination costs |
(34,245 | ) | (30,724 | ) | (40,965 | ) | (34,916 | ) | |||||
|
Amortization of tenant improvement allowance |
25,777 | — | 14,321 | — | |||||||||
|
Unit-based compensation |
(453,795 | ) | (453,795 | ) | (605,059 | ) | (151,265 | ) | |||||
|
Changes in operating assets and liabilities: |
|||||||||||||
|
Oil, natural gas and NGL revenues receivable |
(11,258 | ) | (377,448 | ) | (464,877 | ) | 373,644 | ||||||
|
Other receivables |
(1,246,269 | ) | 600,579 | 1,371,540 | — | ||||||||
|
Other current assets |
— | — | (6,441 | ) | (72,742 | ) | |||||||
|
Accounts payable |
1,071,453 | (568,430 | ) | (1,604,999 | ) | (77,152 | ) | ||||||
|
Other current liabilities |
(89,550 | ) | (43,488 | ) | (8,683 | ) | (27,284 | ) | |||||
| | | | | | | | | | | | | | |
|
EBITDA |
$ | (4,446,509 | ) | $ | (24,058,135 | ) | $ | (26,952,276 | ) | $ | (3,049,356 | ) | |
|
Add: |
|||||||||||||
|
Impairment of oil and natural gas properties |
4,992,897 | 25,796,352 | 28,673,166 | 7,416,747 | |||||||||
|
Unit-based compensation |
453,795 | 453,795 | 605,059 | 151,265 | |||||||||
| | | | | | | | | | | | | | |
|
Adjusted EBITDA |
$ | 1,000,183 | $ | 2,192,012 | $ | 2,325,949 | $ | 4,518,656 | |||||
| | | | | | | | | | | | | | |
| | | | | | | | | | | | | | |
| | | | | | | | | | | | | | |
100
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following discussion should be read together with "Selected Historical and Unaudited Pro Forma Financial Data" and the historical and pro forma financial statements and related notes included elsewhere in this prospectus.
Unless otherwise indicated, the historical financial information in this "Management's Discussion and Analysis of Financial Condition and Results of Operations" reflects only the historical financial results of our predecessor, Rivercrest Royalties, LLC, and does not include the results of any of our Sponsors or the Contributing Parties or give pro forma effect to the transactions described in "Summary—Formation Transactions."
This discussion contains forward-looking statements that are based on the views and beliefs of our management, as well as assumptions and estimates made by our management. Such views, beliefs, assumptions and estimates may, and often do, vary from actual results and the differences can be material. Actual results could differ materially from such forward-looking statements as a result of various factors, including those that may not be in the control of our management. We do not undertake any obligation to publicly update any forward-looking statements except as otherwise required by applicable law. For further information on items that could impact our future operating performance or financial condition, please read the sections entitled "Risk Factors" and "Forward-Looking Statements" elsewhere in this prospectus.
Kimbell Royalty Partners, LP is a Delaware limited partnership formed to own and acquire mineral and royalty interests in oil and natural gas properties throughout the United States. As an owner of mineral and royalty interests, we are entitled to a portion of the revenues received from the production of oil, natural gas and associated natural gas liquids from the acreage underlying our interests, net of post-production expenses and taxes. We are not obligated to fund drilling and completion costs, lease operating expenses or plugging and abandonment costs at the end of a well's productive life. Our primary business objective is to provide increasing cash distributions to unitholders resulting from acquisitions from our Sponsors, the Contributing Parties and third parties and from organic growth through the continued development by working interest owners of the properties in which we own an interest.
As of December 31, 2015, Kimbell Royalty Partners, LP owned mineral and royalty interests in approximately 3.7 million gross acres and overriding royalty interests in approximately 0.9 million gross acres, with approximately 44% of our aggregate acres located in the Permian Basin. We refer to these non-cost-bearing interests collectively as our "mineral and royalty interests." As of December 31, 2015, over 95% of the acreage subject to our mineral and royalty interests was leased to working interest owners (including 100% of our overriding royalty interests), and substantially all of those leases were held by production. Our mineral and royalty interests are located in 20 states and in nearly every major onshore basin across the continental United States and include ownership in over 48,000 gross producing wells, including over 29,000 wells in the Permian Basin.
Oil, natural gas and natural gas liquids prices have been historically volatile and may continue to be volatile in the future. In late 2014, prices for oil, natural gas and natural gas
101
liquids declined precipitously, and prices remained low throughout 2015 and for the first six months of 2016. WTI has ranged from a low of $26.19 per Bbl in February 2016 to a high of $113.93 per Bbl in April 2011, and the Henry Hub spot market price of natural gas has ranged from a low of $1.49 per MMBtu in March 2016 to a high of $7.63 per MMBtu in February 2014. On September 30, 2016, the WTI posted price for crude oil was $48.24 per Bbl and the Henry Hub spot market price of natural gas was $2.84 per MMBtu. Additionally, natural gas liquids prices have declined from approximately $29.46 Boe in January 2015 to $28.65 Boe in August 2016. In response to low commodity prices, operators have scaled back their drilling activity significantly. The Baker Hughes U.S. Rotary Rig count was 569 active rigs at November 4, 2016, a greater than 18% decline from 698 active rigs at December 31, 2015. The 698 active rig count at December 31, 2015 is a greater than 61% decline from 1,811 active rigs at December 31, 2014. In addition, according to the Baker Hughes U.S. Rotary Rig count, rig activity in the 20 states in which we own mineral and royalty interests has further decreased, with a greater than 27% decline from 630 active rigs at December 31, 2015 to 468 active rigs at September 30, 2016. If oil, natural gas and natural gas liquids prices remain depressed, our revenue realized from the production and sale of oil, natural gas and natural gas liquids would be similarly lower than historical results.
The following table, as reported by the EIA, sets forth the average prices for oil, natural gas and natural gas liquids for the years ended December 31, 2015 and 2014 and for the nine months ended September 30, 2016 and 2015:
|
|
Nine Months Ended
September 30, |
Year Ended December 31, | |||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
|
Average Prices:
|
2016 | 2015 | 2015 | 2014 | |||||||||
|
Oil (Bbl) |
$ | 41.15 | $ | 50.93 | $ | 48.69 | $ | 93.26 | |||||
|
Natural gas (MMBtu) |
$ | 2.34 | $ | 2.80 | $ | 2.63 | $ | 4.39 | |||||
|
Natural gas liquids (Bbl) |
$ | 26.02 | $ | 28.34 | $ | 27.69 | $ | 29.29 | |||||
Source: EIA.
Our revenues are derived from royalty payments we receive from our operators based on the sale of oil, natural gas and natural gas liquids production, as well as the sale of natural gas liquids that are extracted from natural gas during processing. Our predecessor's revenues are primarily derived from mineral and royalty interests, which, together with its non-operated working interests, we refer to as "Interests." For the nine months ended September 30, 2016, our predecessor's revenues were generated 62% from oil sales, 28% from natural gas sales and 10% from natural gas liquid sales. For the year ended December 31, 2015, our predecessor's revenues were generated 63% from oil sales, 29% from natural gas sales and 8% from natural gas liquid sales.
Our revenues may vary significantly from period to period as a result of changes in volumes of production sold or changes in commodity prices. Oil, natural gas and natural gas liquids prices have been historically volatile based upon the dynamics of supply and demand. In the second half of 2014, oil prices began a rapid decline as global supply outpaced demand. The oil price decline continued throughout 2015 and into the first nine months of 2016 when the WTI spot price reached a low of $26.19 per Bbl on February 11, 2016, but rebounded to a high of $51.59 per Bbl on October 19, 2016. If product prices remain at the levels experienced during
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the fourth quarter of 2014 and the year ended December 31, 2015, we will experience lower revenue compared to historical results.
We have not entered into hedging arrangements to establish, in advance, a price for the sale of the oil, natural gas and natural gas liquids produced from our mineral and royalty interests. As a result, we may realize the benefit of any short-term increase in the price of oil, natural gas and natural gas liquids, but we will not be protected against decreases in price, and if the price of oil, natural gas and natural gas liquids decreases significantly, our business, results of operation and cash available for distribution may be materially adversely effected. We may enter into hedging arrangements in the future.
The table below identifies our predecessor's proved reserves at September 30, 2016 and December 31, 2015 and 2014, in each case based on our management's estimates. The prices used to estimate proved reserves for all periods were held constant throughout the life of the properties and have been adjusted for quality, transportation fees, geographical differentials, marketing bonuses or deductions and other factors affecting the price received at the wellhead.
|
|
Unweighted Arithmetic Average
First-Day-of-the-Month Prices |
|||||||||
|---|---|---|---|---|---|---|---|---|---|---|
|
|
|
As of December 31, | ||||||||
|
|
As of
September 30, 2016 |
|||||||||
|
|
2015 | 2014 | ||||||||
|
Oil (Bbls) |
$ | 41.68 | $ | 50.28 | $ | 86.12 | ||||
|
Natural gas (Mcf) |
$ | 2.28 | $ | 2.59 | $ | 3.84 | ||||
|
Natural gas liquids (Bbls) |
$ | 11.75 | $ | 16.18 | $ | 32.64 | ||||
Adjusted EBITDA is used as a supplemental non-GAAP financial measure by management and external users of our financial statements, such as industry analysts, investors, lenders and rating agencies. We believe Adjusted EBITDA is useful because it allows us to more effectively evaluate our operating performance and compare the results of our operations period to period without regard to our financing methods or capital structure. In addition, management uses Adjusted EBITDA to evaluate cash flow available to pay distributions to our unitholders.
We define Adjusted EBITDA as net income (loss) plus interest expense, net of capitalized interest, non-cash unit-based compensation, impairment of oil and natural gas properties, income taxes and depreciation, depletion and accretion expense. Adjusted EBITDA is not a measure of the income (loss) as determined by GAAP. We exclude the items listed above from net income (loss) in arriving at Adjusted EBITDA because these amounts can vary substantially from company to company within our industry depending upon accounting methods and book values
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of assets, capital structures and the method by which the assets were acquired. Certain items excluded from Adjusted EBITDA are significant components in understanding and assessing a company's financial performance, such as a company's cost of capital and tax structure, as well as historic costs of depreciable assets, none of which are components of Adjusted EBITDA.
Adjusted EBITDA should not be considered an alternative to net income, oil, natural gas and natural gas liquids revenues, net cash flows provided by operating activities or any other measure of financial performance or liquidity presented in accordance with GAAP. Our computations of Adjusted EBITDA may not be comparable to other similarly titled measures of other companies.
Factors Affecting the Comparability of Our Results to the Historical Results of Our Predecessor
Our predecessor's historical financial condition and results of operations may not be comparable, either from period to period or going forward, to the partnership's future results of operations, for the reasons described below:
Formation Transactions
The historical financial statements included in this prospectus of our predecessor, Rivercrest Royalties, LLC, do not reflect the formation transactions to be completed in connection with the completion of this offering. In connection with this offering, our predecessor will assign all of its non-operating working interests to an affiliate that will not be contributed to us and the member of our predecessor will contribute all of its membership interests in Rivercrest Royalties, LLC to us in exchange for common units in Kimbell Royalty Partners, LP. In addition, the Contributing Parties will directly or indirectly contribute to us the other assets that will make up our initial assets in exchange for common units in Kimbell Royalty Partners, LP and the net proceeds from this offering as described in "Use of Proceeds." The combination of the assets contributed to us by the Contributing Parties will be accounted for at fair value as asset acquisitions. The fair value of the purchase consideration will be based upon the fair value of the common units issued in the formation transactions. Factors that will impact the allocation of the purchase consideration include the estimated fair value of proved and unproved reserves, projections of future rates of production, expected recovery rates and risk adjusted discount rates.
The historical financial data of our predecessor included in this "Management's Discussion and Analysis of Financial Condition and Results of Operations" does not include the results of the Contributing Parties and may not give you an accurate indication of what our actual results would have been if the transactions described in "Summary—Formation Transactions" had been completed at the beginning of the periods presented or of what our future results of operations are likely to be. Moreover, the historical financial statements of our predecessor comprise 15.8% of our revenues on a pro forma basis after giving effect to the pro forma formation transactions. For more information, please read the historical financial statements of the entities other than our predecessor and the unaudited pro forma financial statements included elsewhere in this prospectus.
Credit Agreements
In January 2014, our predecessor entered into a credit agreement with Frost Bank, as lender. For the nine months ended September 30, 2016, our predecessor's interest expense was $0.3 million. Our predecessor had outstanding borrowings of $10.9 million as of September 30, 2016. We will not assume any indebtedness of our predecessor in connection with the formation
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transactions. In connection with this offering, we expect to enter into a new $50.0 million secured revolving credit facility with an accordion feature permitting aggregate commitments under the facility to be increased up to $100.0 million (subject to the satisfaction of certain conditions and the procurement of additional commitments from new or existing lenders), which will be minimally drawn at the closing of this offering. Please read "—Liquidity and Capital Resources—Indebtedness."
Acquisition Opportunities
Acquisitions are an important part of our growth strategy, and we expect to pursue acquisitions of mineral and royalty interests from our Sponsors, the Contributing Parties and third parties. We also may pursue acquisitions jointly with our Sponsors and the Contributing Parties. As a consequence of any such acquisition and acquisition-related expense, the historical financial statements of our predecessor will differ from our financial statements in the future.
Management Services Agreements
In connection with this offering, we will enter into a management services agreement with Kimbell Operating, which will enter into separate service agreements with certain entities controlled by Messrs. Duncan, R. Ravnaas, Taylor and Wynne, pursuant to which they and Kimbell Operating will provide management, administrative and operational services to us. In addition, under each of their respective service agreements, Messrs. R. Ravnaas, Taylor and Wynne will identify, evaluate and recommend to us acquisition opportunities and negotiate the terms of such acquisitions. Amounts paid to Kimbell Operating and such other entities under their respective service agreements will reduce the amount of cash available for distribution to our unitholders. Please read "Certain Relationships and Related Party Transactions—Agreements and Transactions with Affiliates in Connection with this Offering—Management Services Agreements."
Non-Operated Working Interest Assignment
Prior to the formation transactions, our predecessor will assign its non-operated working interests and associated asset retirement obligations to an affiliated company. At the closing of this offering, Kimbell Royalty Partners, LP will not own any working interests and will not have any asset retirement obligations.
Principal Components of Our Cost Structure
As an owner of mineral and royalty interests, we are not obligated to fund drilling and completion costs, lease operating expenses or plugging and abandonment costs at the end of a well's productive life.
Production and Ad Valorem Taxes
Production taxes are paid on produced oil, natural gas and natural gas liquids based on a percentage of revenues from products sold at fixed rates established by federal, state or local taxing authorities. Where available, we benefit from tax credits and exemptions in our various taxing jurisdictions. We are also subject to ad valorem taxes in the counties where our production is located. Ad valorem taxes are jurisdictional taxes levied on the value of oil, natural gas and natural gas liquids minerals and reserves. Rates, methods of calculating property values, and timing of payments vary between taxing authorities.
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Depreciation and Depletion
We follow the full cost method of accounting for costs related to our oil, natural gas and natural gas liquids mineral and royalty properties. Under this method, all such costs are capitalized and amortized on an aggregate basis over the estimated lives of the properties using the unit-of-production method. The capitalized costs are subject to a ceiling test, which limits such pooled costs to the aggregate of the present value of future net revenues attributable to proved oil, natural gas and natural gas liquids reserves discounted at 10%, including the effect of income taxes. We do not assign any value to unproved properties in which we hold a mineral or royalty interest. The full cost ceiling is evaluated at the end of each annual period and additionally when events indicate possible impairment.
General and Administrative Expense
General and administrative expenses are costs not directly associated with the production of oil, natural gas and natural gas liquids and include the cost of executives and employees and related benefits, office expenses and fees for professional services. In connection with the closing of this offering, we will enter into a management services agreement with Kimbell Operating, which will enter into separate service agreements with certain entities controlled by Messrs. Duncan, R. Ravnaas, Taylor and Wynne, pursuant to which they and Kimbell Operating will provide management, administrative and operational services to us. In addition, under each of their respective service agreements, Messrs. R. Ravnaas, Taylor and Wynne will identify, evaluate and recommend to us acquisition opportunities and negotiate the terms of such acquisitions.
In connection with the closing of this offering, we anticipate incurring incremental general and administrative expenses of approximately $1.5 million that we expect to incur annually as a result of operating as a publicly traded partnership, such as expenses associated with SEC reporting requirements, including annual and quarterly reports to unitholders, tax return and Schedule K-1 preparation and distribution expenses, Sarbanes-Oxley Act compliance expenses, expenses associated with listing on the NYSE, independent auditor fees, independent reserve engineer fees, legal fees, investor relations expenses, registrar and transfer agent fees, director and officer insurance expenses and director and officer compensation expenses. These incremental general and administrative expenses are not reflected in the historical financial statements of our predecessor or the unaudited pro forma financial statements included elsewhere in this prospectus.
Interest Expense
For the nine months ended September 30, 2016, our predecessor's interest expense was $0.3 million. Our predecessor had outstanding borrowings of $10.9 million as of September 30, 2016. We will not assume any indebtedness of our predecessor in connection with the formation transactions. In connection with this offering, we expect to enter into a new $50.0 million secured revolving credit facility, which is forecasted to have $1.5 million of borrowings outstanding, which will be used to fund certain transaction expenses at the closing of this offering. Please read "—Liquidity and Capital Resources—Indebtedness."
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Income Tax Expense
We will be treated as a partnership under the Code, with each partner being separately taxed on its proportionate share of our taxable income; therefore, there will be no federal income tax expense reflected in our financial statements.
Texas imposes a franchise tax (commonly referred to as the Texas margin tax, which is considered an income tax) at a rate of 0.95% on gross revenues less certain deductions, as specifically set forth in the Texas margin tax statute. A significant portion of our mineral and royalty interests are located in Texas basins and producing regions.
Predecessor Results of Operations
The following table summarizes our predecessor's revenue and expenses and production data for the periods indicated.
Predecessor Results of Operations
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|
Predecessor Results of Operations | ||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
|
|
Nine Months Ended September 30, | Year Ended December 31, | |||||||||||
|
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2016 | 2015 | 2015 | 2014 | |||||||||
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Operating Results: |
|||||||||||||
|
Oil, natural gas and NGL revenues |
$ | 2,572,477 | $ | 3,670,930 | $ | 4,684,923 | $ | 7,219,822 | |||||
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Costs and expenses |
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|
|
|
|||||||||
|
Production and ad valorem taxes |
203,567 | 214,150 | 426,885 | 568,327 | |||||||||
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Depreciation, depletion and accretion expense |
1,244,023 | 2,969,502 | 4,008,730 | 4,044,802 | |||||||||
|
Impairment of oil and natural gas properties |
4,992,897 | 25,796,352 | 28,673,166 | 7,416,747 | |||||||||
|
Marketing and other deductions |
570,521 | 590,637 | 747,264 | 526,727 | |||||||||
|
General and administrative expenses |
1,252,001 | 1,127,926 | 1,789,884 | 1,757,377 | |||||||||
| | | | | | | | | | | | | | |
|
Total costs and expenses |
8,263,009 | 30,698,567 | 35,645,929 | 14,313,980 | |||||||||
|
Operating income (loss) |
(5,690,532 | ) | (27,027,637 | ) | (30,961,006 | ) | (7,094,158 | ) | |||||
|
Interest expense |
314,081 | 282,372 | 385,119 | 302,118 | |||||||||
| | | | | | | | | | | | | | |
|
Income (loss) before income taxes |
(6,004,613 | ) | (27,310,009 | ) | (31,346,125 | ) | (7,396,276 | ) | |||||
|
State income taxes |
13,401 | 11,557 | (32,199 | ) | 16,970 | ||||||||
| | | | | | | | | | | | | | |
|
Net income (loss) |
$ | (6,018,014 | ) | $ | (27,321,566 | ) | $ | (31,313,926 | ) | $ | (7,413,246 | ) | |
| | | | | | | | | | | | | | |
| | | | | | | | | | | | | | |
| | | | | | | | | | | | | | |
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Production Data: |
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|
Oil (Bbls) |
41,548 | 47,317 | 59,321 | 50,570 | |||||||||
|
Natural gas (Mcf) |
343,078 | 398,302 | 548,386 | 515,130 | |||||||||
|
Natural gas liquids (Bbls) |
17,458 | 16,171 | 22,351 | 17,991 | |||||||||
|
Combined volumes (Boe) (6:1) |
116,186 | 129,872 | 173,070 | 154,416 | |||||||||
|
Average daily combined volumes (Boe/d) (6:1) |
424 | 476 | 474 | 423 | |||||||||
Comparison of the Nine Months Ended September 30, 2016 to the Nine Months Ended September 30, 2015
Oil, Natural Gas and Natural Gas Liquids Revenues
Our predecessor's revenues for the nine months ended September 30, 2016 was $2.6 million, a decrease of $1.1 million, from $3.7 million for the nine months ended September 30, 2015. Our predecessor's decrease in revenues was primarily due to the industry-wide steep declines in the price of oil, natural gas and natural gas liquids experienced through the first nine months of
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2016, coupled with a decrease in production for the nine months ended September 30, 2016 of 13,686 Boe when compared to production for the nine months ended September 30, 2015.
Our predecessor's revenues are a function of oil, natural gas, and natural gas liquids production volumes sold and average prices received for those volumes. Our predecessor's production volumes for the nine months ended September 30, 2016 were 116,186 Boe, or 424 Boe/d, a decrease from 129,872 Boe, or 476 Boe/d, for the nine months ended September 30, 2015. Our predecessor's operators received an average of $38.11 per Bbl of oil, $2.14 per Mcf of natural gas and $14.56 per Bbl of natural gas liquids for the volumes sold during the nine months ended September 30, 2016. Our predecessor's operators received an average of $48.58 per Bbl of oil, $2.68 per Mcf of natural gas and $18.74 per Bbl of natural gas liquids and for the volumes sold during the nine months ended September 30, 2015.
Production and Ad Valorem Taxes
Our predecessor's production and ad valorem taxes decreased by $10,583 to $203,567 for the nine months ended September 30, 2016, from $214,150 for the nine months ended September 30, 2015. The decrease in production and ad valorem taxes was attributable to a decline in oil, natural gas and natural gas liquids revenues.
Depreciation, Depletion and Accretion Expense
Our predecessor's depreciation, depletion and accretion expense decreased by $1.8 million to $1.2 million for the nine months ended September 30, 2016 from $3.0 million for the nine months ended September 30, 2015. The average depletion rate per barrel was $10.71 and $22.86 for the nine months ended September 30, 2016 and 2015, respectively. The decrease in the average depletion rate per barrel was primarily attributable to a $28.7 million impairment recorded on oil, natural gas and natural gas liquids properties in 2015, which resulted in a lower depletable base in oil, natural gas and natural gas liquids properties for the nine months ended September 30, 2016. Depletion is the amount of cost basis of oil and natural gas properties at the beginning of a period attributable to the volume of hydrocarbons extracted during such period, calculated on a units-of-production basis. Estimates of proved developed producing reserves are a major component in the calculation of depletion. Our predecessor has historically adjusted its depletion rates in the fourth quarter of each year based upon the year end reserve report and other times during the year when circumstances indicate that there has been a significant change in reserves or costs.
Impairment of Oil, Natural Gas and Natural Gas Liquids Expense
Our predecessor utilizes the full cost method of accounting for our oil and natural gas properties. Under the full cost method, capitalized costs are subject to a ceiling test, which limits such pooled costs to the aggregate of the present value of future net revenues attributable to proved oil, natural gas and natural gas liquids reserves discounted at 10%, including the effects of income taxes. Our predecessor does not assign any value to unproved properties in which it holds an Interest. The full cost ceiling is evaluated at the end of each annual period and additionally when events indicate possible impairment. Impairments totaled $5.0 million for the nine months ended September 30, 2016 primarily due to changes in reserve values resulting from the continued decline in commodity prices during the first nine months of 2016. Impairments totaled $25.8 million for the nine months ended September 30, 2015 primarily due to the impact that declines in commodity prices had on the value of reserve estimates.
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Marketing and Other Deductions
Our predecessor's marketing and other deductions includes product marketing expense, which is a post-production expense, and lease operating expenses related to its non-operated working interests. Our predecessor's marketing and other deductions for the nine months ended September 30, 2016 and 2015 were $0.6 million.
General and Administrative Expense
Our predecessor's general and administrative expenses for the nine months ended September 30, 2016 were $1.3 million, an increase of $0.2 million from $1.1 million for the nine months ended September 30, 2015. Increases in general and administrative expenses were attributable to the increased costs related to this offering.
Interest Expense
Our predecessor's interest expense for the nine months ended September 30, 2016 was $314,081, an increase of $31,709 from $282,372 for the nine months ended September 30, 2015. The increase of $31,709 was attributable to average outstanding debt of $11.2 million for the nine months ended September 30, 2016 as compared to the average outstanding debt of $10.4 million for the nine months ended September 30, 2015. Please read "—Liquidity and Capital Resources—Indebtedness."
State Income Taxes
Our predecessor's state income taxes for the nine months ended September 30, 2016 were $13,401, an increase of $1,844, as compared to $11,557 for the nine months ended September 30, 2015. Our predecessor operates within legal structures that are disregarded for federal and most state income tax purposes. Our predecessor's income tax expense primarily consists of income taxes on our predecessor's oil, natural gas and natural gas liquids revenue in Texas and other states in which our predecessor holds interests in oil, natural gas and natural gas liquids producing properties.
Comparison of the Year Ended December 31, 2015 to the Year Ended December 31, 2014
Oil, Natural Gas and Natural Gas Liquids Revenues
Our predecessor's revenues for the year ended December 31, 2015 were $4.7 million, a decrease of $2.5 million, from $7.2 million for the year ended December 31, 2014. Our predecessor's decrease in oil, natural gas and natural gas liquids revenues was primarily due to the sharp decline in commodity prices experienced over the second half of 2014 and through the year ended December 31, 2015, partially offset by an increase in production of 18,654 Boe year over year.
Our predecessor's revenues are a function of oil, natural gas, and natural gas liquids production volumes sold and average prices received for those volumes. Our predecessor's production volumes for the year ended December 31, 2015 were 173,070 Boe, or 474 Boe/d, an increase from 154,416 Boe, or 423 Boe/d, for the year ended December 31, 2014. The increase in production volumes was primarily due to acquisitions of Interests during the second half of 2014 and a full year of production on the Interests during 2015. Our predecessor's operators received an average of $49.79 per Bbl of oil, $2.44 per Mcf of natural gas and $17.56 per Bbl of natural gas liquids and for the volumes sold for the year ended December 31, 2015. Our predecessor's
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operators received an average of $87.25 per Bbl of oil, $4.22 per Mcf of natural gas and $35.26 per Bbl of natural gas liquids for the volumes sold for the year ended December 31, 2014.
Production and Ad Valorem Taxes
Our predecessor's production and ad valorem taxes decreased to $0.4 million for the year ended December 31, 2015, a decrease of $0.2 million, from $0.6 million for the year ended December 31, 2014. The decrease in production and ad valorem taxes was attributable to the sharp decline in commodity prices experienced throughout the industry beginning in the fourth quarter of 2014 through the beginning of the first quarter of 2016 and lower estimated mineral reserve valuations.
Depreciation, Depletion and Accretion Expense
Our predecessor's depreciation, depletion and accretion expense remained relatively flat at $4.0 million for the year ended December 31, 2015, consistent with the $4.0 million for the year ended December 31, 2014. The average depletion rate per barrel was $23.16 and $26.19 for the year ended December 31, 2015 and 2014, respectively. The decrease in the average depletion rate per barrel was primarily attributable to the $7.4 million impairment recorded on our predecessor's oil, natural gas and natural gas liquids properties in 2014, which resulted in a lower depletable base in oil, natural gas and natural gas liquids properties for the year ended December 31, 2015. The decrease in the depletable base was offset by an increase in production from 154,416 Boe for the year ended December 31, 2014 to 173,070 Boe for the year ended December 31, 2015.
Impairment of Oil, Natural Gas and Natural Gas Liquids Expense
Our predecessor's impairments totaled $28.7 million for the year ended December 31, 2015 primarily due to changes in reserve values resulting from the continued sharp decline in commodity prices and other factors in the last half of 2014 and through 2015. Impairments totaled $7.4 million for the year ended December 31, 2014 primarily due to the impact that declines in commodity prices had on the value of our predecessor's reserve estimates.
Marketing and Other Deductions
Our predecessor's marketing and other deductions for the year ended December 31, 2015 were $0.7 million compared to $0.5 million for the year ended December 31, 2014. Marketing and other deductions includes product marketing expense, which is a post-production expense, and lease operating expenses related to its non-operated working interests. Increases in marketing and other deductions were primarily due to a full year of operations during the year ended December 31, 2015 for the majority of our predecessor's oil, natural gas and natural gas liquids properties. A significant portion of the oil, natural gas and natural gas liquids properties were not held for the entirety of the year ended December 31, 2014 as the acquisition of these oil, natural gas and natural gas liquid properties were made during the year ended December 31, 2014.
General and Administrative Expense
Our predecessor's general and administrative expenses for the year ended December 31, 2015 were $1.8 million, which is consistent with general and administrative expenses for the year ended December 31, 2014.
Interest Expense
Our predecessor's interest expense for the year ended December 31, 2015 was $0.4 million, an increase of $0.1 million from the year ended December 31, 2014. The increase in interest expense is due to increased borrowings under the predecessor's credit facility.
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State Income Taxes
Our predecessor's state income taxes for the year ended December 31, 2015 were a net credit of $32,199, a change of $49,169, as compared to a $16,970 expense for the year ended December 31, 2014. This change was due to income tax credits received during the year ended December 31, 2015 from states for overpayments of income tax payments made by our predecessor in prior years. Our predecessor's income tax expense primarily consists of income taxes on our predecessor's oil, natural gas and natural gas liquids revenue in Texas and other states in which our predecessor holds interests in oil, natural gas and natural gas liquids producing properties.
Liquidity and Capital Resources
Overview
Following the completion of this offering, we expect our primary sources of liquidity will be cash flows from operations and equity and debt financings and our primary uses of cash will be for paying distributions to our unitholders and for growth capital expenditures, including the acquisition of mineral and royalty interests in oil and natural gas properties. In connection with the consummation of this offering, we expect to enter into a $50.0 million secured revolving credit facility with an accordion feature permitting aggregate commitments under the facility to be increased up to $100.0 million (subject to the satisfaction of certain conditions and the procurement of additional commitments from new or existing lenders), to initially be used for general partnership purposes, including working capital and acquisitions and certain transaction expenses. We expect to borrow approximately $1.5 million at the closing of this offering to fund certain transaction expenses.
Our partnership agreement requires us to distribute all of our cash on hand at the end of each quarter, less reserves established by our general partner. We refer to this cash as "available cash." Available cash for each quarter will be determined by the board of directors of our general partner following the end of such quarter. We expect that available cash for each quarter will generally equal our Adjusted EBITDA for the quarter, less cash needed for debt service and other contractual obligations and fixed charges and reserves for future operating or capital needs, including replacement or growth capital expenditures, that the board of directors may determine is appropriate.
Unlike a number of other master limited partnerships, we do not currently intend to retain cash from our operations for capital expenditures necessary to replace our existing oil and natural gas reserves or otherwise maintain our asset base (replacement capital expenditures), primarily due to our expectation that the continued development of our properties and completion of drilled but uncompleted wells by working interest owners will substantially offset the natural production declines from our existing wells. The board of directors of our general partner may change our distribution policy and decide to withhold replacement capital expenditures from cash available for distribution, which would reduce the amount of cash available for distribution in the quarter(s) in which any such amounts are withheld. Over the long term, if our reserves are depleted and our operators become unable to maintain production on our existing properties and we have not been retaining cash for replacement capital expenditures, the amount of cash generated from our existing properties will decrease and we may have to reduce the amount of distributions payable to our unitholders. To the extent that we do not withhold replacement capital expenditures, a portion of our cash available for distribution will represent a return of your capital.
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It is our intent, subject to market conditions, to finance acquisitions of mineral and royalty interests that increase our asset base largely through external sources, such as borrowings under our secured revolving credit facility and the issuance of equity and debt securities, although the board of directors of our general partner may choose to reserve a portion of cash generated from operations to finance such acquisitions as well. We do not currently intend to maintain excess distribution coverage for the purpose of maintaining stability or growth in our quarterly distribution or otherwise reserve cash for distributions, or to incur debt to pay quarterly distributions, although the board of directors of our general partner may change this policy.
Because our partnership agreement will require us to distribute an amount equal to all available cash we generate each quarter, our unitholders will have direct exposure to fluctuations in the amount of cash generated by our business. We expect that the amount of our quarterly distributions, if any, will fluctuate based on variations in, among other factors, (i) the performance of the operators of our properties, (ii) earnings caused by, among other things, fluctuations in the price of oil, natural gas and natural gas liquids, changes to working capital or capital expenditures and (iii) cash reserves deemed appropriate by the board of directors of our general partner. Such variations in the amount of our quarterly distributions may be significant and could result in our not making any distribution for any particular quarter. We will not have a minimum quarterly distribution or employ structures intended to consistently maintain or increase distributions over time. The board of directors of our general partner may change our distribution policy at any time at its discretion, without unitholder approval, and could elect not to pay distributions for one or more quarters.
Predecessor Cash Flows
The following table presents our predecessor's cash flows for the period indicated.
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Predecessor Cash Flows
(in thousands) |
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|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
|
|
Nine Months Ended
September 30, |
Year Ended December 31, | |||||||||||
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|
2016 | 2015 | 2015 | 2014 | |||||||||
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Cash Flow Data: |
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|
Cash flows provided by operating activities |
$ | 956,793 | $ | 2,317,594 | $ | 2,713,133 | $ | 4,038,018 | |||||
|
Cash flows used in investing activities |
(93,899 | ) | (503,989 | ) | (538,640 | ) | (53,463,030 | ) | |||||
|
Cash flows provided by (used in) financing activities |
(563,000 | ) | (1,762,973 | ) | (2,062,818 | ) | 39,645,738 | ||||||
| | | | | | | | | | | | | | |
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Net increase (decrease) in cash |
$ | 299,894 | $ | 50,632 | $ | 111,675 | $ | (9,779,274 | ) | ||||
Operating Activities (Predecessor)
Our predecessor's operating cash flow is impacted by many variables, the most significant of which is the change in prices for oil, natural gas and natural gas liquids. Prices for these commodities are determined primarily by prevailing market conditions. Regional and worldwide economic activity, weather and other substantially variable factors influence market conditions for these products. These factors are beyond our and our predecessor's control and are difficult to predict. The decreases in cash flows provided by operating activities for the nine months ended September 30, 2016 as compared to the nine months ended September 30, 2015 of $1.4 million were largely attributable to lower oil, natural gas and natural gas liquids sales prices.
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The decrease in cash flows provided by operating activities for the year ended December 31, 2015 as compared to the year ended December 31, 2014 of $1.3 million was largely attributable to lower oil, natural gas and natural gas liquids sales prices.
Investing Activities (Predecessor)
The purchase of Interests in producing oil and gas properties accounted for our predecessor's cash outlays for investing activities. For the nine months ended September 30, 2016, our predecessor used $0.1 million for investing activities compared to $0.5 million for the nine months ended September 30, 2015. The $0.4 million decrease was due to less drilling activity on our predecessor's working interest properties during the nine months ended September 30, 2016.
Cash used in investing activities was $0.5 million for the year ended December 31, 2015 as compared to $53.5 million for the year ended December 31, 2014. This decrease is due to the fact that our predecessor made no acquisitions during the year ended December 31, 2015, compared to the six acquisitions of Interests our predecessor made during the year ended December 31, 2014.
Financing Activities (Predecessor)
Cash used in financing activities was $0.6 million for the nine months ended September 30, 2016 as compared to cash used in financing activities of $1.8 million for the nine months ended September 30, 2015. During the nine months ended September 30, 2016, our predecessor repaid $0.6 million of long-term debt. Our predecessor borrowed $2.6 million in long-term debt, offset by $3.8 million in distributions to members and repayments on long-term debt of $0.6 million, in the nine months ended September 30, 2015.
Cash used in financing activities was $2.1 million for the year ended December 31, 2015 as compared to cash provided by financing activities of $39.6 million for the year ended December 31, 2014. Decreases in financing activities of $41.7 million were primarily attributable to a decrease of $34.1 million in proceeds from issuance of membership units, an additional $1.1 million in distributions to members, and $42.0 million less in borrowings on long term debt offset by a decrease of $35.4 million in repayments on long-term debt.
Capital Expenditures
During the nine months ended September 30, 2016, our predecessor spent $0.1 million on lease and well equipment related to our working interests and office equipment. During the nine months ended September 30, 2015, our predecessor spent $0.5 million on additional costs from the 2014 acquisitions of Interests, lease and well equipment and intangible drilling costs related to our working interests and office equipment. During the year ended December 31, 2015, our predecessor spent $0.5 million on additional costs from the 2014 acquisitions of Interests, lease and well equipment and intangible drilling costs related to our working interests and office equipment. During the year ended December 31, 2014, our predecessor spent $53.5 million on acquisitions of Interests.
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Indebtedness
Predecessor Credit Facility
Our predecessor entered into a credit agreement with Frost Bank for up to $50.0 million. The credit facility is subject to borrowing base restrictions and is collateralized by certain properties. The borrowing base is $20 million with interest payable monthly on Alternate Base Rate loans or at the end of the interest period on any Eurodollar loans. As of September 30, 2016, our predecessor's total indebtedness on its credit agreement was approximately $10.9 million with an average interest rate of 3.27%. The loan matures in January 2018. At September 30, 2016, our predecessor was not in compliance with the Debt to EBITDAX Ratio, as defined in the credit facility. On November 14, 2016, our predecessor received from the bank a formal waiver of this covenant, effective as of September 30, 2016. Our predecessor was in compliance with all other debt covenants at September 30, 2016. For further information on our predecessor's indebtedness, refer to Note 4 in the audited financial statements of our predecessor and Note 3 in the unaudited financial statements of our predecessor included elsewhere in this prospectus. Our predecessor will use a portion of the proceeds it receives from this offering to pay off the credit facility. We will not assume any indebtedness of our predecessor in connection with the formation transactions.
New Revolving Credit Agreement
In connection with the closing of this offering, we expect to enter into a $50.0 million revolving credit facility, which will be secured by substantially all of our assets and the assets of our wholly owned subsidiaries. Under the secured revolving credit facility, availability under the facility will equal the lesser of the aggregate maximum commitments of the lenders and the borrowing base. The borrowing base will be determined based on the value of our oil and natural gas properties and the oil and gas properties of our wholly owned subsidiaries. The oil and gas properties of our non-wholly owned subsidiaries will not be subject to a lien and will not be included in borrowing base valuations. We expect that the secured revolving credit facility will permit aggregate commitments under the facility to be increased to $100.0 million, subject to the satisfaction of certain conditions and the procurement of additional commitments from new or existing lenders.
We expect that the secured revolving credit facility will contain various affirmative, negative and financial maintenance covenants. These covenants would, among other things, limit our ability to incur or guarantee additional debt, make distributions on, or redeem or repurchase, common units, make certain investments and acquisitions, incur certain liens or permit them to exist, enter into certain types of transactions with affiliates, merge or consolidate with another company and transfer, sell or otherwise dispose of assets. We expect the secured revolving credit facility will also contain covenants requiring us to maintain the following financial ratios or to reduce our indebtedness if we are unable to comply with such ratios: (i) a Debt to EBITDAX Ratio (as more fully defined in the secured revolving credit facility) of not more than 4.0 to 1.0; and (ii) a ratio of current assets to current liabilities of not less than 1.0 to 1.0. We also expect that the secured revolving credit facility will contain customary events of default, including non-payment, breach of covenants, materially incorrect representations, cross-default, bankruptcy and change of control.
We expect to borrow approximately $1.5 million at the closing of this offering to fund certain transaction expenses.
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Predecessor Contractual Obligations
The following table summarizes the contractual obligations of our predecessor as of December 31, 2015:
Predecessor Contractual Obligations
(in thousands)
|
|
Total |
Less than
1 year |
1-3 years | 3-5 years |
More than
5 years |
|||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
|
Long-term debt (1) |
$ | 12,171,569 | $ | 346,900 | $ | 11,824,669 | $ | — | $ | — | ||||||
|
Operating leases |
360,740 | 77,176 | 236,498 | 47,066 | — | |||||||||||
| | | | | | | | | | | | | | | | | |
|
Total |
$ | 12,532,309 | $ | 424,076 | $ | 12,061,167 | $ | 47,066 | $ | — | ||||||
- (1)
- Our predecessor's credit agreement matures in January 2018. Includes principal as well as interest payments. For purposes of calculating future interest on the credit facility, assumes no change in balance or rate from December 31, 2015.
Internal Controls and Procedures
We are not currently required to comply with the SEC's rules implementing Section 404 of the Sarbanes-Oxley Act, and are therefore not required to make a formal assessment of the effectiveness of our internal controls over financial reporting for that purpose. Upon becoming a public company, we will be required to comply with the SEC's rules implementing Section 302 of the Sarbanes-Oxley Act, which will require our management to certify financial and other information in our quarterly and annual reports and provide an annual management report on the effectiveness of our internal controls over financial reporting. We will not be required to make our first assessment of our internal controls over financial reporting until the year following our first annual report required to be filed with the SEC. To comply with the requirements of being a public company, we will need to implement additional financial and management controls, reporting systems and procedures and hire additional accounting, finance and legal staff.
Further, our independent registered public accounting firm is not yet required to attest to the effectiveness of our internal controls over financial reporting, and will not be required to do so for as long as we are an "emerging growth company" pursuant to the provisions of the JOBS Act or as long as we are a non-accelerated filer. Please read "Summary—Emerging Growth Company Status" and "Risk Factors—Risks Inherent in an Investment in Us—For as long as we are an emerging growth company, we will not be required to comply with certain disclosure requirements that apply to other public companies."
New and Revised Financial Accounting Standards
We qualify as an "emerging growth company" pursuant to the provisions of the JOBS Act, enacted on April 5, 2012. Section 107 of the JOBS Act provides that an "emerging growth company" can take advantage of the extended transition period provided in Section 7(a)(2)(B) of the Securities Act for complying with new or revised accounting standards. However, we are choosing to "opt out" of such extended transition period, and as a result, we will comply with new or revised accounting standards on the relevant dates on which adoption of such standards is required for non-emerging growth companies. Our election to "opt out" of the extended transition period is irrevocable.
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In May 2014, the FASB issued Accounting Standards Update ("ASU") No. 2014-09, Revenue from Contracts with Customers (ASU 2014-09), which supersedes nearly all existing revenue recognition guidance under GAAP. The core principle of ASU 2014-09 is to recognize revenues when promised goods or services are transferred to customers in an amount that reflects the consideration to which an entity expects to be entitled for those goods or services. ASU 2014-09 defines a five step process to achieve this core principle and, in doing so, more judgment and estimates may be required within the revenue recognition process than are required under existing GAAP.
The standard is effective for annual periods beginning after December 15, 2017, and interim periods therein, using either of the following transition methods: (i) a full retrospective approach reflecting the application of the standard in each prior reporting period with the option to elect certain practical expedients, or (ii) a retrospective approach with the cumulative effect of initially adopting ASU 2014-09 recognized at the date of adoption (which includes additional footnote disclosures). We are currently evaluating the impact of the pending adoption of ASU 2014-09 on the financial statements and have not yet determined the method by which we will adopt the standard in 2017.
The discussion and analysis of our financial condition and results of operations are based upon the historical financial statements of our predecessor, which have been prepared in accordance with GAAP. Certain of our accounting policies involve judgments and uncertainties to such an extent that there is a reasonable likelihood that materially different amounts would have been reported under different conditions, or if different assumptions had been used. The following discussions of critical accounting estimates, including any related discussion of contingencies, address all important accounting areas where the nature of accounting estimates or assumptions could be material due to the levels of subjectivity and judgment necessary to account for highly uncertain matters or the susceptibility of such matters to change. Below, we have provided expanded discussion of our more significant accounting policies.
See the notes to our predecessor's historical financial statements included elsewhere in this prospectus for additional information regarding these accounting policies.
Use of Estimates
Certain amounts included in or affecting our financial statements and related disclosures must be estimated by our management, requiring certain assumptions to be made with respect to values or conditions that cannot be known with certainty at the time the financial statements are prepared. These estimates and assumptions affect the amounts we report for assets and liabilities and our disclosure of contingent assets and liabilities at the date of the financial statements. Actual results could differ from those estimates.
We evaluate these estimates on an ongoing basis, using historical experience, consultation with experts and other methods we consider reasonable in the particular circumstances. Nevertheless, actual results may differ significantly from our estimates. Any effects on our business, financial position or results of operations resulting from revisions to these estimates are recorded in the period in which the facts that give rise to the revision become known. Significant items subject to such estimates and assumptions include estimates of proved oil and gas reserves and related present value estimates of future net cash flows therefrom, the carrying value of oil and natural gas properties and equity-based compensation.
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Method of Accounting for Oil and Natural Gas Properties
We account for oil, natural gas and natural gas liquids producing activities using the full cost method of accounting. Accordingly, all costs incurred in the acquisition, exploration and development of proved oil, natural gas and natural gas liquids properties, including the costs of abandoned properties, dry holes, geophysical costs and annual lease rentals are capitalized. Sales or other dispositions of oil, natural gas and natural gas liquids properties are accounted for as adjustments to capitalized costs, with no gain or loss recorded unless the ratio of cost to proved reserves would significantly change.
Depletion of evaluated oil, natural gas and natural gas liquids properties is computed on the units of production method, whereby capitalized costs plus estimated future development costs are amortized over total proved reserves.
Costs associated with unevaluated properties are excluded from the full cost pool until we have made a determination as to the existence of proved reserves. We assess all items classified as unevaluated property on an annual basis for possible impairment. We assess properties on an individual basis or as a group if properties are individually insignificant. The assessment includes consideration of the following factors, among others: intent to drill; remaining lease term; geological and geophysical evaluations; drilling results and activity; the assignment of proved reserves; and the economic viability of development if proved reserves are assigned. During any period in which these factors indicate an impairment, the cumulative drilling costs incurred to date for such property and all or a portion of the associated leasehold costs are transferred to the full cost pool and are then subject to amortization.
Oil, Natural Gas and Natural Gas Liquids Reserve Quantities and Standardized Measure of Future Net Revenue
Our independent engineers prepare our estimates of oil, natural gas and natural gas liquids reserves and associated future net revenues. The SEC has defined proved reserves as the estimated quantities of oil and gas which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. The process of estimating oil, natural gas and natural gas liquids reserves is complex, requiring significant decisions in the evaluation of available geological, geophysical, engineering and economic data. The data for a given property may also change substantially over time as a result of numerous factors, including additional development activity, evolving production history and a continual reassessment of the viability of production under changing economic conditions. As a result, material revisions to existing reserve estimates occur from time to time. Although every reasonable effort is made to ensure that reserve estimates reported represent the most accurate assessments possible, the subjective decisions and variances in available data for various properties increase the likelihood of significant changes in these estimates. If such changes are material, they could significantly affect future amortization of capitalized costs and result in impairment of assets that may be material.
There are numerous uncertainties inherent in estimating quantities of proved oil, natural gas and natural gas liquids reserves. Oil, natural gas and natural gas liquids reserve engineering is a subjective process of estimating underground accumulations of oil, natural gas and natural gas liquids that cannot be precisely measured and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Results of drilling, testing and production subsequent to the date of the estimate may justify
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revision of such estimate. Accordingly, reserve estimates are often different from the quantities of oil, natural gas and natural gas liquids that are ultimately recovered.
Revenue Recognition
Mineral and royalty interests represent the right to receive revenues from the sale of oil, natural gas and natural gas liquids, less production and ad valorem taxes and post-production expenses. The pricing of oil, natural gas and natural gas liquids from the properties in which we own a mineral or royalty interest is primarily determined by supply and demand in the marketplace and can fluctuate considerably. As an owner of mineral and royalty interests, we have no involvement or operational control over the volumes and method of sale of the oil, natural gas and natural gas liquids produced and sold from the property. We have no rights or obligations to explore, develop or operate the property and do not incur any of the costs of exploration, development and operation of the property.
Oil, natural gas and natural gas liquids revenues from our Interests are recognized when the associated product is sold.
Impairment
The net capitalized costs of proved oil, natural gas and natural gas liquids properties are subject to a full cost ceiling limitation in which the costs are not allowed to exceed their related estimated future net revenues discounted at 10%. Estimated future net revenues are calculated as estimated future revenues from oil, natural gas and natural gas liquids properties less production taxes, ad valorem taxes and gas marketing expenses. To the extent capitalized costs of evaluated oil, natural gas and natural gas liquids properties, net of accumulated depreciation, depletion, amortization, impairment and deferred income taxes exceed the discounted future net revenues of proved oil, natural gas and natural gas liquids reserves, less any related income tax effects, the excess capitalized costs are charged to expense. In calculating future net revenues, prices are calculated as the average oil, natural gas and natural gas liquids prices during the preceding 12-month period prior to the end of the current reporting period, determined as the unweighted arithmetic average first-day-of-the-month prices for the prior 12-month period and costs used are those as of the end of the appropriate quarterly period.
Accounting for Unit-Based Compensation
We measure unit-based compensation grants at their grant date fair value and related compensation expense is recognized over the vesting period of the grant. The long-term incentive plan and related accounting policies are defined and described more fully in Note 7 in our predecessor's audited historical financial statements and in Note 6 of our predecessor's unaudited historical financial statements included elsewhere in this prospectus. The determination of the fair value of an award requires significant estimates and subjective judgments regarding, among other things, the appropriate option pricing model, the expected life of the award and forfeiture rate assumptions. Estimates of the fair value of unit options granted during the year ended December 31, 2015 and the nine months ended September 30, 2016 were completed using a Black-Scholes option valuation model, which requires us to make several assumptions.
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Inflation
Inflation in the United States has been relatively low in recent years and did not have a material impact on results of operations for the period from January 1, 2014 through September 30, 2016.
Off-Balance Sheet Arrangements
As of September 30, 2016, we did not have any off-balance sheet arrangements other than operating leases.
Quantitative and Qualitative Disclosure about Market Risk
Commodity Price Risk
Our major market risk exposure is in the pricing applicable to the oil, natural gas and natural gas liquids production of our operators. Realized pricing is primarily driven by the prevailing worldwide price for crude oil and spot market prices applicable to our natural gas production. Pricing for oil, natural gas and natural gas liquids production has been volatile and unpredictable for several years, and we expect this volatility to continue in the future. The prices that our operators receive for production depend on many factors outside of our or their control.
Credit Risk
As an owner of mineral and royalty interests, we have no control over the volumes or method of sale of oil, natural gas and natural gas liquids produced and sold from the underlying properties. During the year ended December 31, 2015, three purchasers accounted for approximately 19%, 13% and 10% of our predecessor's oil, natural gas and natural gas liquids revenues. It is believed that the loss of any single purchaser would not have a material adverse effect on our results of operations.
Interest Rate Risk
We will have exposure to changes in interest rates on our indebtedness. As of September 30, 2016, our predecessor had total borrowings outstanding under its credit facility of $10.9 million. The impact of a 1% increase in the interest rate on this amount of debt would result in an increase in interest expense of approximately $0.1 million annually, assuming that our indebtedness remained constant throughout the year. We do not currently have any interest rate hedges in place.
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We are a Delaware limited partnership formed to own and acquire mineral and royalty interests in oil and natural gas properties throughout the United States. As an owner of mineral and royalty interests, we are entitled to a portion of the revenues received from the production of oil, natural gas and associated natural gas liquids from the acreage underlying our interests, net of post-production expenses and taxes. We are not obligated to fund drilling and completion costs, lease operating expenses or plugging and abandonment costs at the end of a well's productive life. Our primary business objective is to provide increasing cash distributions to unitholders resulting from acquisitions from our Sponsors, the Contributing Parties and third parties and from organic growth through the continued development by working interest owners of the properties in which we own an interest.
As of December 31, 2015, we owned mineral and royalty interests in approximately 3.7 million gross acres and overriding royalty interests in approximately 0.9 million gross acres, with approximately 44% of our aggregate acres located in the Permian Basin. We refer to these non-cost-bearing interests collectively as our "mineral and royalty interests." As of December 31, 2015, over 95% of the acreage subject to our mineral and royalty interests was leased to working interest owners (including 100% of our overriding royalty interests), and substantially all of those leases were held by production. Our mineral and royalty interests are located in 20 states and in nearly every major onshore basin across the continental United States and include ownership in over 48,000 gross producing wells, including over 29,000 wells in the Permian Basin. For the six months ended June 30, 2016, approximately 52.6% of our production was from the Permian Basin, Eagle Ford, Terryville/Cotton Valley/Haynesville and the Bakken/Williston Basin, which are some of the most active areas in the country. The geographic breadth of our assets gives us exposure to potential production and reserves from new and existing plays. Over the long term, we expect working interest owners will continue to develop our acreage through infill drilling, horizontal drilling, hydraulic fracturing, recompletions and secondary and tertiary recovery methods. As an owner of mineral and royalty interests, we benefit from the continued development of the properties in which we own an interest without the need for investment of additional capital by us.
Certain members of our management team have completed over 160 acquisitions of mineral and royalty interests and have significant experience in identifying, evaluating and completing strategic acquisitions. Our founders began actively acquiring mineral and royalty interests in 1998 when they began to jointly acquire mineral and royalty interests in conventional onshore U.S. basins. They initially focused on mineral and royalty interests in the Permian Basin, and later expanded their acquisition efforts to several other basins. Beginning in 2000, this group expanded to include nearly all the Contributing Parties. Our founders have focused on acquiring properties characterized by long-life, shallow decline production and significant oil and natural gas reserves.
For the 15-year period ended December 31, 2015, the net oil and net natural gas production from our assets, including acquisitions, has grown at a compound annual growth rate of 16.8%
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and 19.2%, respectively. The chart below shows the compound annual growth rate of production from our mineral and royalty interests for such period:
Net Production Growth (Including Acquisitions) (2001-2015)
Note: Net oil and net natural gas production information was gathered from state reporting records. Natural gas liquids, which are not reported by the states, are excluded from the chart.
For the 15-year period ended December 31, 2015, the net oil and net natural gas production from our assets has grown organically (assuming we had acquired all of our interests on January 1, 2001 and made no additional acquisitions) at a compound annual growth rate of 3.2% and 1.0%, respectively. The chart below shows the compound annual growth rate attributable to our combined mineral and royalty interests as if we had acquired all of such interests on January 1, 2001 and made no additional acquisitions.
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Organic Net Production Growth (2001-2015)
Note: Net oil and net natural gas production information was gathered from state reporting records. Natural gas liquids, which are not reported by the states, are excluded from the chart.
As of December 31, 2015, the estimated proved oil, natural gas and natural gas liquids reserves attributable to our interests in our underlying acreage were 18,120 MBoe (52.4% liquids, consisting of 79.7% oil and 20.3% natural gas liquids) based on the reserve report prepared by Ryder Scott. Of these reserves, 70.4% were classified as PDP reserves, 0.8% were classified as PDNP reserves and 28.8% were classified as PUD reserves. The properties underlying our mineral and royalty interests typically have low estimated decline rates. Our PDP reserves have an average estimated initial five-year decline rate of 10%. PUD reserves included in this estimate are from 759 gross proved undeveloped locations. For the six months ended June 30, 2016, our average daily net production was 3,317 Boe/d.
For the year ended December 31, 2015, on a pro forma basis, our revenues were derived 63.0% from oil sales, 30.0% from natural gas sales and 7.0% from natural gas liquid sales. Our revenues are derived from royalty payments we receive from the operators of our properties based on the sale of oil and natural gas production, as well as the sale of natural gas liquids that are extracted from natural gas during processing. As of December 31, 2015, we had over 700 operators on our acreage, with our top ten operators (Occidental Permian Ltd., Newfield Exploration Company, Range Resources Corporation/Memorial Resource Development Corp., Aera Energy LLC (a joint venture of Royal Dutch Shell plc and ExxonMobil Corporation), XTO Energy, Inc., Jonah Energy LLC, Campbell Development Group, LLC, EOG Resources, Inc., Chesapeake Energy Corporation and Devon Energy Corporation) together accounting for
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approximately 46.9% of our combined discounted future net income (discounted at 10%). Our revenues may vary significantly from period to period as a result of changes in volumes of production sold or changes in commodity prices. Oil, natural gas and natural gas liquids prices have historically been volatile, and we do not currently hedge our exposure to changes in commodity prices.
We believe that one of our key strengths is our management team's extensive experience in acquiring and managing mineral and royalty interests. Our management team and board of directors, which includes our founders, have a long history of creating value. We expect our business model to allow us to integrate significant acquisitions into our existing organizational structure quickly and cost-efficiently. In particular, Messrs. R. Ravnaas, Taylor and Wynne average over 30 years sourcing, engineering, evaluating, acquiring and managing mineral and royalty interests. In connection with this offering, we will enter into a management services agreement with Kimbell Operating, which will enter into separate service agreements with certain entities controlled by Messrs. R. Ravnaas, Taylor and Wynne, pursuant to which they will identify, evaluate and recommend to us acquisition opportunities and negotiate the terms of such acquisitions. Please read "Certain Relationships and Related Party Transactions—Agreements and Transactions with Affiliates in Connection with this Offering—Management Services Agreements."
Upon completion of this offering, our Sponsors will indirectly own and control our general partner, and the Contributing Parties will own an aggregate of approximately % of our outstanding common units (excluding any common units purchased by officers and directors of our general partner under our directed unit program). The Contributing Parties, including affiliates of our Sponsors, will retain a diverse portfolio of mineral and royalty interests with production and reserve characteristics similar to the assets we will own at the closing of this offering. In connection with this offering and pursuant to the contribution agreement that we have entered into with our Sponsors and the Contributing Parties, certain of the Contributing Parties have granted us a right of first offer for a period of three years after the closing of this offering with respect to certain mineral and royalty interests in the Permian Basin, the Bakken/Williston Basin and the Marcellus Shale. We believe the Contributing Parties, including affiliates of our Sponsors, will be incentivized through their direct or indirect ownership of common units to offer us the opportunity to acquire additional mineral and royalty interests from them in the future. Such Contributing Parties, however, have no obligation to sell any assets to us or to accept any offer that we may make for such assets, and we may decide not to acquire such assets even if such Contributing Parties offer them to us. In addition, under the contribution agreement, we have a right to participate, at our option and on substantially the same or better terms, in up to 50% of any acquisitions, other than de minimis acquisitions, for which Messrs. R. Ravnaas, Taylor and Wynne provide, directly or indirectly, any oil and gas diligence, reserve engineering or other business services. Please read "Certain Relationships and Related Party Transactions—Agreements and Transactions with Affiliates in Connection with this Offering—Contribution Agreement."
We categorize our assets into two groups: mineral interests and overriding royalty interests.
Mineral Interests
Mineral interests are real property interests that are typically perpetual and grant ownership to all of the oil and natural gas lying below the surface of the property, as well as the right to explore, drill and produce oil and natural gas on that property or to lease such rights to a third
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party. Mineral owners typically grant oil and gas leases to operators for an initial three-year term with an upfront cash payment to the mineral owners known as a lease bonus. Under the lease, the mineral owner retains a royalty interest entitling it to a cost-free percentage (usually ranging from 20-25%) of production or revenue from production. The lease can be extended beyond the initial term with continuous drilling, production or other operating activities. When production or drilling ceases on the leased property, the lease is typically terminated, subject to certain exceptions, and all mineral rights revert back to the mineral owner who can then lease the exploration and development rights to another party. We also own royalty interests that have been carved out of mineral interests and are known as nonparticipating royalty interests. Nonparticipating royalty interests are typically perpetual and have rights similar to mineral interests, including the right to a cost-free percentage of production revenues for minerals extracted from the acreage, without the associated executive right to lease and the right to receive lease bonuses.
We combine our mineral and nonparticipating royalty assets into one category because they share many of the same characteristics due to the nature of the underlying interest. For example, we receive similar royalties from operators with respect to our mineral interests or nonparticipating royalty interests as long as such interests are subject to an oil and gas lease. As of December 31, 2015, over 95% of the acreage subject to our mineral and nonparticipating royalty interests was leased. When evaluating our business, our management team does not distinguish between mineral and nonparticipating royalty interests on leased acreage due to the similarity of the royalties received by the interests.
Overriding Royalty Interests
In addition to mineral interests, we also own overriding royalty interests, which are royalty interests that burden the working interests of a lease and represent the right to receive a fixed, cost-free percentage of production or revenue from production from a lease. Overriding royalty interests typically remain in effect until the associated lease expires, and because substantially all of the underlying leases are perpetual so long as production in paying quantities perpetuates the leasehold, substantially all of our overriding royalty interests are likewise perpetual.
Production
The following charts provide information regarding our production for the year ended December 31, 2015.
- (1)
-
"Btu-equivalent" production volumes are presented on an oil-equivalent basis using a conversion factor of six Mcf of natural gas per barrel
of "oil equivalent," which is based on approximate energy equivalency and does not reflect the price or value relationship between oil and natural gas.
- (2)
- "Value-equivalent" production volumes are presented on an oil-equivalent basis using a conversion factor of 20 Mcf of natural gas per barrel of "oil equivalent," which is the conversion factor we use in our business. For a discussion of the 20-to-1 conversion factor, please read footnote 3 to the Mineral Interests table under "—Our Properties—Material Basins and Producing Regions—Mineral Interests."
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Our primary business objective is to provide increasing cash distributions to unitholders resulting from acquisitions from our Sponsors, the Contributing Parties and third parties and from organic growth through the continued development by working interest owners of the properties in which we own an interest. We intend to accomplish this objective by executing the following strategies:
- •
-
Acquire additional mineral and royalty interests from our Sponsors and
the Contributing Parties.
Following the completion of this offering, the Contributing Parties, including affiliates of our Sponsors,
will continue to own significant mineral and royalty interests in oil and gas properties. We believe our Sponsors and the Contributing Parties view our partnership as part of their growth strategy. In
addition, we believe their direct or indirect ownership in us will incentivize them to offer us additional mineral and royalty interests from their existing asset portfolios in the future. In
connection with this offering and pursuant to the contribution agreement, certain of the Contributing Parties have granted us a right of first offer for a period of three years after the closing of
this offering with respect to certain mineral and royalty interests in the Permian Basin, the Bakken/Williston Basin and the Marcellus Shale. These mineral and royalty interests include ownership in
over 4,000 gross producing wells in 10 states. Such Contributing Parties, however, have no obligation to sell any assets to us or to accept any offer that we may make for such assets, and we may
decide not to acquire such assets even if such Contributing Parties offer them to us. Please read "Certain Relationships and Related Party Transactions—Agreements and Transactions with
Affiliates in Connection with this Offering—Contribution Agreement."
- •
-
Acquire additional mineral and royalty interests from third parties
and leverage our relationships with our Sponsors and the Contributing Parties to grow our business.
We intend to make opportunistic
acquisitions of mineral and royalty interests that have substantial resource and organic growth potential and meet our acquisition criteria, which include (i) mineral and royalty interests in
high-quality producing acreage that enhance our asset base, (ii) significant amounts of recoverable oil and natural gas in place with geologic support for future production and reserve growth
and (iii) a geographic footprint complementary to our diverse portfolio.
Our Sponsors and their affiliates have significant experience in identifying, evaluating and completing strategic acquisitions of mineral and royalty interests. In connection with the closing of this offering, we will enter into a management services agreement with Kimbell Operating, which will enter into separate service agreements with certain entities controlled by Messrs. R. Ravnaas, Taylor and Wynne, pursuant to which they will identify, evaluate and recommend to us acquisition opportunities and negotiate the terms of such acquisitions. We believe that these individuals' knowledge of the oil and natural gas industry, relationships within the industry and experience in identifying, evaluating and completing acquisitions will provide us opportunities to grow through strategic and accretive acquisitions that complement or expand our asset portfolio.
We also may have opportunities to acquire mineral or royalty interests from third parties jointly with our Sponsors and the Contributing Parties. In connection with this offering and pursuant to the contribution agreement that we have entered into with our Sponsors and the Contributing Parties, we have a right to participate, at our option and on substantially the same or better terms, in up to 50% of any acquisitions, other than de
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- •
-
Benefit from reserve, production and cash flow growth through organic
production growth and development of our mineral and royalty interests to grow distributions.
Our initial assets consist of diversified
mineral and royalty interests. For the six months ended June 30, 2016, approximately 52.6% of our production was from the Permian Basin, Eagle Ford, Terryville/Cotton Valley/Haynesville and the
Bakken/Williston Basin, which are some of the most active areas in the country. Over the long term, we expect working interest owners will continue to develop our acreage through infill drilling,
horizontal drilling, hydraulic fracturing, recompletions and secondary and tertiary recovery methods. As an owner of mineral and royalty interests, we are entitled to a portion of the revenues
received from the production of oil, natural gas and associated natural gas liquids from the acreage underlying our interests, net of post-production expenses and taxes. We are not obligated to fund
drilling and completion costs, lease operating expenses or plugging and abandonment costs at the end of a well's productive life. As such, we benefit from the continued development of the properties
we own a mineral or royalty interest in without the need for investment of additional capital by us, which we expect to increase our distributions over time.
- •
- Maintain a conservative capital structure and prudently manage our business for the long term. We are committed to maintaining a conservative capital structure that will afford us the financial flexibility to execute our business strategies on an ongoing basis. The limited liability company agreement of our general partner will contain provisions that prohibit certain actions without a supermajority vote of at least 66 2 / 3 % of the members of the board of directors of our general partner. Among the actions requiring a supermajority vote will be the incurrence of borrowings in excess of 2.5 times our Debt to EBITDAX Ratio for the preceding four quarters and the issuance of any partnership interests that rank senior in right of distributions or liquidation to our common units. Please read "The Partnership Agreement—Certain Provisions of the Agreement Governing our General Partner." We expect to enter into a $50.0 million secured revolving credit facility with an accordion feature permitting aggregate commitments under the facility to be increased up to $100.0 million (subject to the satisfaction of certain conditions and the procurement of additional commitments from new or existing lenders), which will be minimally drawn at the closing of this offering. We initially expect to use borrowings under the secured revolving credit facility for general partnership purposes, including the repayment of certain transaction expenses at the closing of this offering. We believe that this liquidity, along with internally generated cash from operations and access to the public capital markets, will provide us with the financial flexibility to grow our production, reserves and cash generated from operations through strategic acquisitions of mineral and royalty interests and the continued development of our existing assets.
minimis acquisitions, for which Messrs. R. Ravnaas, Taylor and Wynne provide, directly or indirectly, any oil and gas diligence, reserve engineering or other business services. We believe this arrangement will give us access to third-party acquisition opportunities we might not otherwise be in a position to pursue. Please read "Certain Relationships and Related Party Transactions—Agreements and Transactions with Affiliates in Connection with this Offering—Contribution Agreement."
126
We believe that the following competitive strengths will allow us to successfully execute our business strategies and achieve our primary business objective:
- •
-
Significant diversified portfolio of mineral and royalty interests in
mature producing basins and exposure to undeveloped opportunities
. We have a diversified, low decline asset base with exposure to
high-quality conventional and unconventional plays. As of December 31, 2015, we owned mineral and royalty interests in approximately 3.7 million gross acres and overriding royalty
interests in approximately 0.9 million gross acres, with approximately 44% of our aggregate acres located in the Permian Basin. As of December 31, 2015, over 95% of the acreage subject
to our mineral and royalty interests was leased to working interest owners (including 100% of our overriding royalty interests), and substantially all of those leases were held by production. As of
December 31, 2015, the estimated proved oil, natural gas and natural gas liquids reserves attributable to our interests in our underlying acreage were 18,120 MBoe (52.4% liquids, consisting of
79.7% oil and 20.3% natural gas liquids) based on the reserve report prepared by Ryder Scott. Of these reserves, 70.4% were classified as PDP reserves, 0.8% were classified as PDNP reserves and 28.8%
were classified as PUD reserves. PUD reserves included in this estimate are from 759 gross proved undeveloped locations. The geographic breadth of our assets gives us exposure to potential production
and reserves from new and existing plays without further required investment on our behalf. We believe that we will continue to benefit from these cost-free additions to production and reserves for
the foreseeable future as a result of technological advances and continuing interest by third-party producers in development activities on our acreage.
- •
-
Exposure to many of the leading resource plays in the United
States.
We expect the operators of our properties to continue to drill new wells and to complete drilled but uncompleted wells on our
acreage, which we believe should substantially offset the natural production declines from our existing wells. We believe that our operators have significant drilling inventory remaining on the
acreage underlying our mineral or royalty interest in multiple resource plays. Our mineral and royalty interests are located in 20 states and in nearly every major onshore basin across the
continental United States and include ownership in over 48,000 gross producing wells, including over 29,000 wells in the Permian Basin. For the six months ended June 30, 2016, approximately
52.6% of our production was from the Permian Basin, Eagle Ford, Terryville/Cotton Valley/Haynesville and the Bakken/Williston Basin, which are some of the most active areas in the country.
- •
- Financial flexibility to fund expansion. Our conservative capital structure after this offering will permit us to maintain financial flexibility to allow us to opportunistically purchase strategic mineral and royalty interests, subject to the supermajority vote provisions of the limited liability company agreement of our general partner. We expect to enter into a $50.0 million secured revolving credit facility with an accordion feature permitting aggregate commitments under the facility to be increased up to $100.0 million (subject to the satisfaction of certain conditions and the procurement of additional commitments from new or existing lenders), which will be minimally drawn at the closing of this offering. Please read "Management's Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Indebtedness—New Revolving Credit Agreement" for further information. We believe that we will be able to expand our asset base through acquisitions utilizing our credit facility, internally generated cash from operations and access to the public capital markets.
127
- •
- Experienced and proven management team with a track record of making acquisitions. The members of our management team and board of directors have an average of over 30 years of oil and gas experience. Our management team and board of directors, which includes our founders, have a long history of buying mineral and royalty interests in high-quality producing acreage throughout the United States. Certain members of our management team have managed a significant investment program, investing in over 160 acquisitions. We believe we have a proven competitive advantage in our ability to source, engineer, evaluate, acquire and manage mineral and royalty interests in high-quality producing acreage.
Material Basins and Producing Regions
The following is an overview of the U.S. basins and producing regions we consider most material to our current and future business.
- •
-
Permian
Basin.
The Permian Basin extends from southeastern New Mexico into west Texas and is currently one of the most active drilling regions
in the United States. It includes three geologic provinces: the Midland Basin to the east, the Delaware Basin to the west, and the Central Basin in between. The Permian Basin consists of mature legacy
onshore oil and liquids-rich natural gas reservoirs and has been actively drilled over the past 90 years. The extensive operating history, favorable operating environment, mature
infrastructure, long reserve life, multiple producing horizons, horizontal development potential and liquids-rich reserves make the Permian Basin one of the most prolific oil-producing regions in the
United States. Our acreage underlies prospective areas for the Wolfcamp play in the Midland and Delaware Basins, the Spraberry formation in the Midland Basin, and the Bone Springs formation in the
Delaware Basin, which are among the most active plays in the country.
- •
-
Mid-Continent.
The Mid-Continent is a broad area containing hundreds of fields in
Arkansas, Kansas, Louisiana, New Mexico, Oklahoma, Nebraska and Texas and including the Granite Wash, Cleveland and the Mississippi Lime formations. The Anadarko Basin is a structural basin centered
in the western part of Oklahoma and the Texas Panhandle, extending into southwestern Kansas and southeastern Colorado. A key feature of the Anadarko Basin is the stacked geologic horizons including
the Cana-Woodford and Springer shale in the SCOOP and STACK.
- •
-
Terryville/Cotton
Valley/Haynesville.
We own a substantial position in the core of the Terryville Field that the Contributing Parties acquired in 2007.
Our mineral interests are leased and operated by Range Resources Corporation/Memorial Resource Development Corp. Producing since 1954, the Terryville Field is one of the most prolific natural gas
fields in North America. Redevelopment of the field with horizontal drilling and modern completion techniques has resulted in high recoveries relative to drilling and completion costs, high initial
production rates with high liquids yields, and long reserve life with multiple stacked producing zones.
- •
- Eagle Ford. The Eagle Ford shale formation stretches across South Texas and includes some of the most economic and productive areas in the United States. The Eagle Ford contains significant amounts of hydrocarbons and is considered the source rock, or the original source, for much of the oil and natural gas contained in the Austin Chalk Basin.
128
- •
-
Barnett Shale/Fort Worth
Basin.
The Fort Worth Basin is a major petroleum producing geological system that is primarily located in north central Texas and
southwestern Oklahoma. This area is best known for the Barnett Shale, which was one of the first shale plays to utilize horizontal drilling and hydraulic fracturing, and is one of the most productive
sources of shale gas along with the Marcellus and Haynesville Shales. In addition to the Barnett Shale, this area is also known for the Marble Falls, Mississippi Lime, Bend Conglomerate and Caddo
plays.
- •
-
Bakken/Williston
Basin.
The Williston Basin stretches through North Dakota, the northwest part of South Dakota, and eastern Montana and is best known for
the Bakken/Three Forks shale formations. The Bakken ranks as one of the largest oil developments in the United States in the past 40 years. Development of the Bakken became commercial on a
large scale over the past ten years with the advent of horizontal drilling and hydraulic fracturing.
- •
-
San Juan
Basin.
The San Juan Basin is located in the Four Corners region of the southwestern United States, stretching over 4,600 square miles
and encompassing much of northwestern New Mexico, southwestern Colorado and parts of Arizona and Utah. Most gas production in the basin comes from the Fruitland Coalbed Methane Play, with the
remainder derived from the Mesaverde and Dakota tight gas plays. The San Juan Basin is the most productive coalbed methane basin in North America.
- •
-
Onshore
California.
The majority of our mineral and royalty interests in California are in the Ventura Basin. The Ventura Basin has been active
since the early 1900s and is one of the largest oil fields in California. The Ventura Basin contains multiple stacked formations throughout its depths, and a considerable inventory of existing
re-development opportunities, as well as new play discovery potential.
- •
-
DJ
Basin/Rockies/Niobrara.
The Denver-Julesburg Basin, also known as the DJ Basin, is a geologic basin centered in eastern Colorado
stretching into southeast Wyoming, western Nebraska and western Kansas. The area includes the Wattenberg Gas Field, one of the largest natural gas deposits in the United States, and the Niobrara
formation. The Niobrara includes three separate zones and stretches from the DJ Basin up into the Powder River Basin in Wyoming. Development in this area is currently focused on horizontal drilling in
the Niobrara and Codell formations.
- •
-
Illinois
Basin.
The Illinois Basin extends across most of Illinois, Indiana, Kentucky and parts of Tennessee. The Illinois Basin is a mature area
dominated by conventional oil production with some coalbed methane production. The Bridgeport, Cypress, Aux Vasses, Ste. Genevieve, Ullin, Fort Payne and New Albany are some of the formations with a
current commercial focus in the Illinois Basin.
- •
- Other. Our other assets are primarily located in the Western Gulf (onshore) Basin and the Louisiana-Mississippi Salt Basins. The Western Gulf region ranges from South Texas through southeastern Louisiana and includes a variety of conventional and unconventional plays. The Louisiana-Mississippi Salt Basins range from northern Louisiana and southern Arkansas through south central Mississippi, southern Alabama and the Florida Panhandle.
The Eagle Ford shale formation has benefitted from improvements in horizontal drilling and hydraulic fracturing.
129
The following tables present information about our mineral and royalty interest acreage, production, and well count by basin. We may own more than one type of interest in the same tract of land. Consequently, some of the acreage shown for one type of interest below may also be included in the acreage shown for another type of interest.
Mineral Interests
The following table sets forth information about our mineral interests:
|
|
|
|
|
Average Daily
Production For the Six Months Ended June 30, 2016 (Boe/d) |
||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
|
|
As of December 31, 2015 | |||||||||||||||
|
|
Gross
Acres |
|
Percent
Leased |
|||||||||||||
| Basin or Producing Region | Net Acres | 6:1 (1)(2) | 20:1 (1)(3) | |||||||||||||
|
Permian Basin (4) |
1,764,954 | 15,741 | 99 | % | 789 | 619 | ||||||||||
|
Mid-Continent |
336,481 | 9,115 | 97 | % | 123 | 75 | ||||||||||
|
Terryville/Cotton Valley/Haynesville |
261,762 | 2,347 | 98 | % | 130 | 76 | ||||||||||
|
Eagle Ford |
180,367 | 1,966 | 97 | % | 337 | 239 | ||||||||||
|
Barnett Shale/Fort Worth Basin (5) |
216,367 | 2,335 | 99 | % | 413 | 222 | ||||||||||
|
Bakken/Williston Basin (6) |
82,704 | 1,455 | 99 | % | 21 | 19 | ||||||||||
|
San Juan Basin |
28,852 | 214 | 98 | % | 25 | 11 | ||||||||||
|
Onshore California |
7,666 | 27 | 64 | % | 96 | 79 | ||||||||||
|
DJ Basin/Rockies/Niobrara |
3,967 | 97 | 59 | % | 34 | 19 | ||||||||||
|
Illinois Basin |
6,351 | 83 | 100 | % | 3 | 3 | ||||||||||
|
Other Western (onshore) Gulf Basin |
539,625 | 3,754 | 98 | % | 132 | 76 | ||||||||||
|
Other TX/LA/MS Salt Basin |
144,186 | 1,476 | 91 | % | 7 | 6 | ||||||||||
|
Other |
93,857 | 671 | 95 | % | 2 | 1 | ||||||||||
| | | | | | | | | | | | | | | | | |
|
Total |
3,667,139 | 39,281 | 98 | % (7) | 2,113 | 1,447 | ||||||||||
| | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
Note: We combine our mineral and nonparticipating royalty assets into one category because they share many of the same characteristics due to the nature of the underlying interest.
Note: Numbers may not add up to total amounts due to rounding.
- (1)
-
Production
volumes represent actual production plus allocated accrued volumes attributable to the period presented.
- (2)
-
"Btu-equivalent"
production volumes are presented on an oil-equivalent basis using a conversion factor of six Mcf of natural gas per barrel of "oil
equivalent," which is based on approximate energy equivalency and does not reflect the price or value relationship between oil and natural gas.
- (3)
- "Value-equivalent" production volumes are presented on an oil-equivalent basis using a conversion factor of 20 Mcf of natural gas per barrel of "oil equivalent," which is the conversion factor we use in our business. We are providing this measure supplementally because we believe this conversion factor represents an estimation of value equivalence over time and better correlates with the respective contribution of oil and natural gas to our revenues. We use the 20-to-1 conversion factor as we assess our business, including analysis of our financial and production performance, strategic decisions to purchase additional properties and budgeting. We do not adjust the 20-to-1 ratio to reflect current pricing, because the significant volatility in the conversion ratio makes it difficult for us to compare results across periods. By reviewing our aggregate production on a constant 20-to-1 basis, which removes the variability of price fluctuations but generally approximates price equivalence over recent periods, we are able to compare production data from period to period as well as the relative contribution of oil and natural gas to our revenues. The 20-to-1 conversion factor approximates the mean ratio of the price of WTI oil to the price of Henry Hub natural gas from January 3, 2006 to December 31, 2015, as reported by the EIA. During this period, the ratio of the price of oil to the price of natural gas ranged from 5.97 to 55.85. The mean ratios of the price of oil to the price of natural gas were 18.75 and 21.64 for the year ended December 31, 2015 and December 31, 2014, respectively. Due to the variability of the prices of oil and natural gas, there is no standard conversion ratio for value
130
equivalence, and the 20-to-1 ratio presented here may not accurately reflect the ratio of oil prices to natural gas prices for a given period.
- (4)
-
Includes
mineral interests in approximately 740,244 gross (6,723 net) acres in the Wolfcamp/Bone Spring.
- (5)
-
Includes
mineral interests in approximately 198,229 gross (1,762 net) acres in the Barnett Shale.
- (6)
-
Includes
mineral interests in approximately 74,504 gross (1,393 net) acres in the Bakken/Three Forks.
- (7)
- This figure represents the weighted average of our leased acres relative to our total acreage in the basins in which we own mineral interests.
ORRIs
The following table sets forth information about our ORRIs:
|
|
|
|
|
Average Daily
Production For the Six Months Ended June 30, 2016 (Boe/d) |
||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
|
|
As of December 31, 2015 | |||||||||||||||
|
|
Gross
Acres |
|
Percent
Producing |
|||||||||||||
| Basin or Producing Region | Net Acres | 6:1 (1)(2) | 20:1 (1)(3) | |||||||||||||
|
Permian Basin (4) |
232,723 | 2,814 | 100 | % | 145 | 117 | ||||||||||
|
Mid-Continent |
139,513 | 2,067 | 85 | % | 78 | 50 | ||||||||||
|
Terryville/Cotton Valley/Haynesville |
41,812 | 779 | 99 | % | 137 | 63 | ||||||||||
|
Eagle Ford |
72,970 | 597 | 100 | % | 132 | 90 | ||||||||||
|
Barnett Shale/Fort Worth Basin (5) |
54,888 | 445 | 100 | % | 9 | 5 | ||||||||||
|
Bakken/Williston Basin (6) |
31,554 | 1,879 | 100 | % | 52 | 44 | ||||||||||
|
San Juan Basin |
47,233 | 908 | 98 | % | 204 | 89 | ||||||||||
|
Onshore California |
9,286 | 9 | 100 | % | 13 | 13 | ||||||||||
|
DJ Basin/Rockies/Niobrara |
3,182 | 102 | 54 | % | 326 | 149 | ||||||||||
|
Illinois Basin |
13,304 | 1,032 | 100 | % | 49 | 49 | ||||||||||
|
Other Western (onshore) Gulf Basin |
71,435 | 1,086 | 100 | % | 26 | 19 | ||||||||||
|
Other TX/LA/MS Salt Basin |
22,616 | 1,140 | 100 | % | 2 | 2 | ||||||||||
|
Other |
133,093 | 10,854 | 99 | % | 31 | 14 | ||||||||||
| | | | | | | | | | | | | | | | | |
|
Total |
873,609 | 23,711 | 97 | % (7) | 1,204 | 703 | ||||||||||
| | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
Note: Numbers may not add up to total amounts due to rounding.
- (1)
-
Production
volumes represent actual production plus allocated accrued volumes attributable to the period presented.
- (2)
-
"Btu-equivalent"
production volumes are presented on an oil-equivalent basis using a conversion factor of six Mcf of natural gas per barrel of "oil
equivalent," which is based on approximate energy equivalency and does not reflect the price or value relationship between oil and natural gas.
- (3)
-
"Value-equivalent"
production volumes are presented on an oil-equivalent basis using a conversion factor of 20 Mcf of natural gas per barrel of "oil
equivalent," which is the conversion factor we use in our business. For a discussion of the 20-to-1 conversion factor, please read footnote 3 to the Mineral Interests table under "—Mineral
Interests."
- (4)
-
Includes
overriding royalty interests in approximately 149,173 gross (1,614 net) acres in the Wolfcamp/Bone Spring.
- (5)
-
Includes
overriding royalty interests in approximately 50,217 gross (389 net) acres in the Barnett Shale.
- (6)
-
Includes
overriding royalty interests in approximately 29,813 gross (1,792 net) acres in the Bakken/Three Forks.
- (7)
- This figure represents the weighted average of our acres that are producing relative to our total acreage in the basins in which we own ORRIs. Virtually all of this acreage is producing.
131
Wells
The following table sets forth information about the wells in which we have a mineral or royalty interest as of December 31, 2015:
| Mineral and Royalty Interests | ||||
|---|---|---|---|---|
| Basin or Producing Region | Well Count | |||
|
Permian Basin |
29,997 | |||
|
Mid-Continent |
2,224 | |||
|
Terryville/Cotton Valley/Haynesville |
5,188 | |||
|
Eagle Ford |
1,234 | |||
|
Barnett Shale/Fort Worth Basin |
2,342 | |||
|
Bakken/Williston Basin |
450 | |||
|
San Juan Basin |
565 | |||
|
Onshore California |
239 | |||
|
DJ Basin/Rockies/Niobrara |
3,499 | |||
|
Illinois Basin |
189 | |||
|
Other |
2,584 | |||
| | | | | |
|
Total |
48,511 | |||
| | | | | |
| | | | | |
| | | | | |
Proved Reserves
Evaluation and Review of Estimated Proved Reserves
Our historical reserve estimates as of December 31, 2015 were prepared by Ryder Scott, an independent petroleum engineering firm. Ryder Scott is a third party engineering firm and does not own an interest in any of our properties and is not employed by us on a contingent basis.
Within Ryder Scott, the technical person primarily responsible for preparing the reserve estimates set forth in the reserve report incorporated herein is Mr. Scott Wilson, who has been practicing petroleum-engineering consulting at Ryder Scott since 2000. Mr. Wilson is a registered Professional Engineer in the States of Alaska, Colorado, Texas and Wyoming. He earned a Bachelor of Science Degree in Petroleum Engineering from the Colorado School of Mines in 1983 and a Masters of Business Administration in Finance from the University of Colorado in 1985. As technical principal, Mr. Wilson meets or exceeds the education, training, and experience requirements set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers and is proficient in applying industry standard practices to engineering evaluations as well as in applying SEC and other industry reserves definitions and guidelines. A copy of Ryder Scott's estimated proved reserve report as of December 31, 2015 is attached as an exhibit to the registration statement of which this prospectus forms a part.
Our Chief Executive Officer, Robert D. Ravnaas, has agreed to provide us with reserve engineering services. Mr. R. Ravnaas is a petroleum engineer with over 30 years of reservoir and operations experience. Mr. R. Ravnaas and certain engineers and geoscience professionals under his supervision worked closely with our independent reserve engineers to ensure the integrity, accuracy and timeliness of the data used to calculate our proved reserves relating to our mineral and royalty interests. Mr. R. Ravnaas met with our independent reserve engineers periodically
132
during the period covered by the reserve report to discuss the assumptions and methods used in the proved reserve estimation process. We provide historical information to the independent reserve engineers for our properties such as ownership interest, oil and gas production, well test data, commodity prices and operating and development costs. Operating and development costs are not realized to our interest but are used to calculate the economic limit life of the wells. These costs are estimated and checked by our independent reserve engineers.
Following the completion of this offering, we anticipate that Mr. R. Ravnaas will continue to be primarily responsible for the preparation of our reserves. In addition, we anticipate that the preparation of our proved reserve estimates are completed in accordance with internal control procedures, including the following:
- •
-
review and verification of historical production data, which data is based on actual production as reported by the operators of our
properties;
- •
-
preparation of reserve estimates by Mr. R. Ravnaas or under his direct supervision;
- •
-
review by Mr. R. Ravnaas of all of our reported proved reserves at the close of each quarter, including the review of all
significant reserve changes and all new proved undeveloped reserves additions;
- •
-
verification of property ownership by our land department; and
- •
- no employee's compensation is tied to the amount of reserves booked.
Under SEC rules, proved reserves are those quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs and under existing economic conditions, operating methods and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. If deterministic methods are used, the SEC has defined reasonable certainty for proved reserves as a "high degree of confidence that the quantities will be recovered." All of our proved reserves as of December 31, 2015 were estimated using a deterministic method. The estimation of reserves involves two distinct determinations. The first determination results in the estimation of the quantities of recoverable oil and gas and the second determination results in the estimation of the uncertainty associated with those estimated quantities in accordance with the definitions established under SEC rules. The process of estimating the quantities of recoverable oil and gas reserves relies on the use of certain generally accepted analytical procedures. These analytical procedures fall into three broad categories or methods: (1) performance-based methods, (2) volumetric-based methods and (3) analogy. These methods may be used singularly or in combination by the reserve evaluator in the process of estimating the quantities of reserves. The proved reserves for our properties were estimated by performance methods, analogy or a combination of both methods. All proved producing reserves attributable to producing wells were estimated by performance methods. These performance methods include, but may not be limited to, decline curve analysis, which utilized extrapolations of available historical production and pressure data. All proved developed non-producing and undeveloped reserves were estimated by the analogy method.
To estimate economically recoverable proved reserves and related future net cash flows, Ryder Scott considered many factors and assumptions, including the use of reservoir parameters derived from geological, geophysical and engineering data which cannot be measured directly,
133
economic criteria based on current costs and the SEC pricing requirements and forecasts of future production rates. To establish reasonable certainty with respect to our estimated proved reserves, the technologies and economic data used in the estimation of our proved reserves included production and well test data, downhole completion information, geologic data, electrical logs, radioactivity logs, core analyses, available seismic data and historical well cost and production cost data.
Summary of Estimated Proved Reserves
The following table presents our estimated proved oil and natural gas reserves as of December 31, 2015 based on the reserve report prepared by Ryder Scott:
|
|
December 31,
2015 (1) |
|||
|---|---|---|---|---|
|
Estimated proved developed reserves: |
||||
|
Oil (MBbls) |
5,336 | |||
|
Natural gas (MMcf) |
35,910 | |||
|
Natural gas liquids (MBbls) |
1,575 | |||
|
Total (MBoe)(6:1) (2) |
12,896 | |||
|
Estimated proved undeveloped reserves: |
||||
|
Oil (MBbls) |
2,237 | |||
|
Natural gas (MMcf) |
15,808 | |||
|
Natural gas liquids (MBbls) |
352 | |||
|
Total (MBoe)(6:1) (2) |
5,224 | |||
|
Estimated proved reserves: |
||||
|
Oil (MBbls) |
7,573 | |||
|
Natural gas (MMcf) |
51,718 | |||
|
Natural gas liquids (MBbls) |
1,927 | |||
|
Total (MBoe)(6:1) (2) |
18,120 | |||
|
Percent proved developed |
71 | % | ||
- (1)
-
Estimates
of reserves as of December 31, 2015 were prepared using an average price equal to the unweighted arithmetic average of hydrocarbon prices
received on a field-by-field basis on the first day of each month within the year ended December 31, 2015, in accordance with SEC guidelines applicable to reserve estimates as of the end of
such period. The unweighted arithmetic average first day of the month prices were $50.28 per Bbl for oil and $2.59 per MMBtu for natural gas at December 31, 2015. The price per Bbl for natural
gas liquids was modeled as a percentage of oil price, which was derived from historical accounting data. Reserve estimates do not include any value for probable or possible reserves that may exist,
nor do they include any value for undeveloped acreage. The reserve estimates represent our net revenue interest in our properties. Although we believe these estimates are reasonable, actual future
production, cash flows, taxes, development expenditures, production costs and quantities of recoverable oil and natural gas reserves may vary substantially from these estimates.
- (2)
- Estimated proved reserves are presented on an oil-equivalent basis using a conversion of six Mcf per barrel of "oil equivalent." This conversion is based on energy equivalence and not price or value equivalence. If a price equivalent conversion based on the twelve-month average prices for the year ended December 31, 2015 was used, the conversion factor would be approximately 19.4 Mcf per Bbl of oil. In this prospectus, we supplementally provide "value-equivalent" production information or volumes presented on an oil-equivalent basis using a conversion factor of 20 Mcf of natural gas per barrel of "oil equivalent," which is the conversion factor we use in our business. For a discussion of the 20-to-1 conversion factor, please read footnote 3 to the Mineral Interests table under "—Our Properties—Material Basins and Producing Regions—Mineral Interests."
The foregoing reserves are all located within the continental United States. Reserve engineering is and must be recognized as a subjective process of estimating volumes of economically recoverable oil and natural gas that cannot be measured in an exact manner. The
134
accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation. As a result, the estimates of different engineers often vary. In addition, the results of drilling, testing, and production may justify revisions of such estimates. Accordingly, reserve estimates often differ from the quantities of oil and natural gas that are ultimately recovered. Estimates of economically recoverable oil and natural gas and of future net revenues are based on a number of variables and assumptions, all of which may vary from actual results, including geologic interpretation, prices, and future production rates and costs. Please read "Risk Factors."
Additional information regarding our estimated proved reserves can be found in the reserve report as of December 31, 2015, which is included as an exhibit to the registration statement of which this prospectus forms a part.
Estimated Proved Undeveloped Reserves
As of December 31, 2015, our PUD reserves totaled 2,237 MBbls of oil, 15,808 MMcf of natural gas and 352 MBbls of natural gas liquids, for a total of 5,224 MBoe. As of December 31, 2014, our PUD reserves totaled 1,925 MBbls of oil, 13,490 MMcf of natural gas and 248 MBbls of natural gas liquids, for a total of 4,422 MBoe. PUD reserves will be converted from undeveloped to developed as the applicable wells begin production.
The following tables summarize our changes in PUD reserves during the year ended December 31, 2015 (in MBoe):
|
|
Proved Undeveloped
Reserves (1) |
|||
|---|---|---|---|---|
|
Balance, December 31, 2014 |
4,422 | |||
|
Acquisitions of reserves |
868 | |||
|
Extensions and discoveries |
1,345 | |||
|
Revisions and previous estimates |
(25 | ) | ||
|
Transfers to estimated proved developed |
(1,386 | ) | ||
| | | | | |
|
Balance, December 31, 2015 |
5,224 | |||
| | | | | |
| | | | | |
| | | | | |
- (1)
- "Btu-equivalent" production volumes are presented on an oil-equivalent basis using a conversion factor of six Mcf of natural gas per barrel of "oil equivalent," which is based on approximate energy equivalency and does not reflect the price or value relationship between oil and natural gas. Please read "—Summary of Estimated Proved Reserves."
Our proved undeveloped reserves as of December 31, 2015 were from 361 vertical wells and 398 horizontal wells. As of December 31, 2015, all of our PUD drilling locations are scheduled to be drilled prior to December 31, 2020. As of December 31, 2015, approximately 0.8% of our total proved reserves were classified as proved developed non-producing.
Changes in PUDs that occurred from December 31, 2014 through December 31, 2015 were primarily due to:
- •
-
the acquisition of an additional 868 MBoe through one diverse acquisition for approximately $51.6 million of mineral and
royalty interests across 18 states, including areas such as the Wolfcamp play, Eagle Ford, Barnett Shale / Fort Worth Basin, Terryville / Cotton Valley / Haynesville and
Cana—Woodford shale.
- •
- additions of approximately 1,345 MBoe, as 598 well locations (185 horizontal and 413 vertical) were converted from probable to proved undeveloped, as offset drilling proved our acreage and projected drilling dates fell within five years of the effective date of the report. Of these 598 well locations, there were 63 in the Barnett Shale / Fort Worth
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- •
-
the conversion of approximately 1,386 MBoe PUD reserves into proved developed reserves as 673 locations (163 horizontal and 510
vertical) were drilled; and
- •
- negative revisions of approximately 25 MBoe in PUDs primarily due to lowered natural gas and oil forecasts associated with suppressed commodity prices.
Basin, 28 in the Bakken/Three Forks, 48 in the Eagle Ford, 32 in Haynesville / Cotton Valley / Terryville, 82 in the DJ Basin / Niobrara/ Rocky Mountains, one in the San Juan Basin, 10 in the Western Gulf Basin, five in the TX/LA/MS Gulf Salt Basin, 27 in Midcontinent, and 302 in the Permian Basin;
Of the 673 locations that were drilled in 2015, 37 locations were specifically identified by management in its 2014 reserve estimates, and all such locations were actually drilled in 2015. The remaining 636 locations were included in management's proved undeveloped forecast in its reserve estimates as being scheduled to be drilled in 2015. These locations include infill drilling in multi-well units and in some cases, waterflood response, CO 2 response, well stimulations, flood conformance improvements and pump upgrades. Management historically has not included conversions from multi-well units in its reserve estimates due to the time required to calculate such information (and related costs) and because management seeks to present a conservative estimate of its PUDs. Management's forecasts for its multi-well units are based on a multi-factor analysis that includes reviewing information from state regulatory agencies and other third-party sources, including publicly disclosed data by the operators, as well as management's experience with the units.
Oil and Natural Gas Production Prices and Production Costs
Production and Price History
The following table sets forth information regarding production of oil and natural gas and certain price and cost information of our predecessor for each of the periods indicated:
|
|
Nine Months
Ended September 30, 2016 |
Year Ended
December 31, 2015 |
Year Ended
December 31, 2014 |
|||||||
|---|---|---|---|---|---|---|---|---|---|---|
|
Predecessor Production Data: |
||||||||||
|
Oil and condensate (Bbls) |
41,548 | 59,321 | 50,570 | |||||||
|
Natural gas (Mcf) |
343,078 | 548,386 | 515,130 | |||||||
|
Natural gas liquids (Bbls) |
17,458 | 22,351 | 17,991 | |||||||
|
Total (Boe)(6:1) (1) |
116,186 | 173,070 | 154,416 | |||||||
|
Average daily production (Boe/d)(6:1) |
424 | 474 | 423 | |||||||
|
Total (Boe)(20:1) (2) |
76,160 | 109,091 | 94,318 | |||||||
|
Average daily production (Boe/d)(20:1) |
209 | 299 | 258 | |||||||
|
Predecessor Average Realized Prices: |
||||||||||
|
Oil and condensate (per Bbl) |
38.11 | $ | 49.79 | $ | 87.25 | |||||
|
Natural gas (per Mcf) |
2.14 | $ | 2.44 | $ | 4.22 | |||||
|
Natural gas liquids (per Bbl) |
14.56 | $ | 17.56 | $ | 35.26 | |||||
|
Predecessor Average Unit Cost per Boe(6:1) |
||||||||||
|
Production and ad valorem taxes |
1.75 | $ | 2.47 | $ | 3.68 | |||||
- (1)
-
"Btu-equivalent"
production volumes are presented on an oil-equivalent basis using a conversion factor of six Mcf of natural gas per barrel of "oil
equivalent," which is based on approximate energy equivalency and does not reflect the price or value relationship between oil and natural gas.
- (2)
- "Value-equivalent" production volumes are presented on an oil-equivalent basis using a conversion factor of 20 Mcf of natural gas per barrel of "oil equivalent," which is the conversion factor we use in our business. For a discussion of the 20-to-1 conversion factor, please read footnote 3 to the Mineral Interests table under "—Our Properties—Material Basins and Producing Regions—Mineral Interests."
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Productive Wells
Productive wells consist of producing wells, wells capable of production, and exploratory, development, or extension wells that are not dry wells. As of December 31, 2015, we owned mineral or royalty interests in over 48,511 productive wells, which consisted of 39,698 oil wells and 8,813 natural gas wells.
Acreage
Mineral and Royalty Interests
The following table sets forth information relating to the acreage underlying our mineral interests as of December 31, 2015:
|
|
Mineral Interests (1)(2) | |||||||||
|---|---|---|---|---|---|---|---|---|---|---|
| State |
Developed
Acreage |
Undeveloped
Acreage |
Total
Acreage |
|||||||
|
Texas |
2,983,512 | 41,363 | 3,024,875 | |||||||
|
Oklahoma |
101,081 | 6,129 | 107,210 | |||||||
|
Louisiana |
45,679 | 589 | 46,268 | |||||||
|
New Mexico |
77,443 | 1,005 | 78,448 | |||||||
|
North Dakota |
80,707 | 720 | 81,427 | |||||||
|
Colorado |
27,440 | 1,649 | 29,089 | |||||||
|
Wyoming |
2,562 | 640 | 3,202 | |||||||
|
Kansas |
83,428 | 1,880 | 85,308 | |||||||
|
Montana |
2,640 | 4,681 | 7,321 | |||||||
|
Other |
189,122 | 14,869 | 203,991 | |||||||
| | | | | | | | | | | |
|
Total |
3,593,614 | (3) | 73,525 | (4) | 3,667,139 | |||||
| | | | | | | | | | | |
| | | | | | | | | | | |
| | | | | | | | | | | |
- (1)
-
Includes
both mineral and nonparticipating royalty interests.
- (2)
-
Numbers
may not add up to total amounts due to rounding.
- (3)
-
Reflects
mineral interests in approximately 3,593,614 total gross (36,568 net) developed acres.
- (4)
- Reflects mineral interests in approximately 73,525 total gross (2,713 net) undeveloped acres.
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The following table sets forth information relating to our acreage for our ORRIs as of December 31, 2015:
|
|
ORRIs (1) | |||||||||
|---|---|---|---|---|---|---|---|---|---|---|
| State |
Developed
Acreage |
Undeveloped
Acreage |
Total
Acreage |
|||||||
|
Texas |
478,602 | 680 | 479,282 | |||||||
|
Oklahoma |
49,637 | 19,602 | 69,239 | |||||||
|
Louisiana |
34,948 | 511 | 35,459 | |||||||
|
New Mexico |
45,610 | 960 | 46,570 | |||||||
|
North Dakota |
31,554 | — | 31,554 | |||||||
|
Colorado |
20,577 | 1,454 | 22,031 | |||||||
|
Wyoming |
70,044 | — | 70,044 | |||||||
|
Kansas |
10,640 | — | 10,640 | |||||||
|
Montana |
— | — | — | |||||||
|
Other |
108,062 | 727 | 108,789 | |||||||
| | | | | | | | | | | |
|
Total |
849,674 | (2) | 23,934 | (3) | 873,609 | |||||
| | | | | | | | | | | |
| | | | | | | | | | | |
| | | | | | | | | | | |
- (1)
-
Numbers
may not add up to total amounts due to rounding.
- (2)
-
Reflects
ORRIs in approximately 849,674 total gross (23,507 net) developed acres.
- (3)
- Reflects ORRIs in approximately 23,934 total gross (204 net) undeveloped acres.
Drilling Results
As of December 31, 2014, the operators of our properties had drilled 36,496 gross productive development wells on the acreage underlying our mineral and royalty interests. As of December 31, 2015, the operators of our properties had drilled 48,511 gross productive development wells on the acreage underlying our mineral and royalty interests. As a holder of mineral and royalty interests, we generally are not provided information as to whether any wells drilled on the properties underlying our acreage are classified as exploratory. We are not aware of any dry holes drilled on the acreage underlying our mineral and royalty interests during the relevant periods.
The oil and natural gas industry is intensely competitive; we primarily compete with companies for the acquisition of oil and natural gas properties some of whom have greater resources than we do. These companies may be able to pay more for productive oil and natural gas properties and exploratory prospects or to define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit. Additionally, many of our competitors are, or are affiliated with, operators that engage in the exploration and production of their oil and gas properties, which allows them to acquire larger assets that include operated properties. Our larger or more integrated competitors may be able to absorb the burden of existing, and any changes to, federal, state and local laws and regulations more easily than we can, which would adversely affect our competitive position. These companies may also have a greater ability to continue exploration activities during periods of low oil and natural gas market prices. Our ability to acquire additional properties in the future will be dependent upon
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our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. In addition, because we have fewer financial and human resources than many companies in our industry, we may be at a disadvantage in bidding for exploratory prospects and producing oil and natural gas properties.
Generally, demand for oil and natural gas decreases during the summer months and increases during the winter months. Seasonal weather conditions and lease stipulations can limit drilling and producing activities and other oil and natural gas operations in a portion of our operating areas. These seasonal anomalies can pose challenges for the operators of our properties in meeting well drilling objectives and can increase competition for equipment, supplies and personnel during the spring and summer months, which could lead to shortages and increase costs or delay operations.
The following disclosure describes regulation directly associated with operators of oil and natural gas properties, including our current operators, and other owners of working interests in oil and natural gas properties.
Oil and natural gas operations are subject to various types of legislation, regulation and other legal requirements enacted by governmental authorities. This legislation and regulation affecting the oil and natural gas industry is under constant review for amendment or expansion. Some of these requirements carry substantial penalties for failure to comply. The regulatory burden on the oil and natural gas industry increases the cost of doing business.
Environmental Matters
Oil and natural gas exploration, development and production operations are subject to stringent laws and regulations governing the discharge of materials into the environment or otherwise relating to protection of the environment or occupational health and safety. These laws and regulations have the potential to impact production on our properties, which could materially adversely affect our business and our prospects. Numerous federal, state and local governmental agencies, such as the EPA, issue regulations that often require difficult and costly compliance measures that carry substantial administrative, civil and criminal penalties and may result in injunctive obligations for non-compliance. These laws and regulations may require the acquisition of a permit before drilling commences, restrict the types, quantities and concentrations of various substances that can be released into the environment in connection with drilling and production activities, limit or prohibit construction or drilling activities on certain lands lying within wilderness, wetlands, ecologically sensitive and other protected areas, require action to prevent or remediate pollution from current or former operations, such as plugging abandoned wells or closing earthen pits, result in the suspension or revocation of necessary permits, licenses and authorizations, require that additional pollution controls be installed and impose substantial liabilities for pollution resulting from operations. The strict, joint and several liability nature of such laws and regulations could impose liability upon the operators of our properties regardless of fault. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances, hydrocarbons or other waste products into the environment. Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent and costly pollution control or waste handling, storage,
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transport, disposal or cleanup requirements could materially adversely affect our business and prospects.
Non-Hazardous and Hazardous Waste
The RCRA, and comparable state statutes and regulations promulgated thereunder, affect oil and natural gas exploration, development, and production activities by imposing requirements regarding the generation, transportation, treatment, storage, disposal and cleanup of hazardous and non-hazardous wastes. With federal approval, the individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. Administrative, civil and criminal penalties can be imposed for failure to comply with waste handling requirements. Although most wastes associated with the exploration, development and production of oil and natural gas are exempt from regulation as hazardous wastes under RCRA, these wastes typically constitute nonhazardous solid wastes that are subject to less stringent requirements. From time to time, the EPA and state regulatory agencies have considered the adoption of stricter disposal standards for nonhazardous wastes, including crude oil and natural gas wastes. Moreover, it is possible that some wastes generated in connection with exploration and production of oil and gas that are currently classified as nonhazardous may, in the future, be designated as "hazardous wastes," resulting in the wastes being subject to more rigorous and costly management and disposal requirements. On May 4, 2016, a coalition of environmental groups filed a lawsuit against EPA in the U.S. District Court for the District of Columbia for failing to update regulations governing the disposal of certain oil and natural gas drilling wastes. Any changes in the laws and regulations could have a material adverse effect on the operators of our properties' capital expenditures and operating expenses, which in turn could affect production from the acreage underlying our mineral and royalty interests and adversely affect our business and prospects.
Remediation
The CERCLA and analogous state laws, generally impose strict, joint and several liability, without regard to fault or legality of the original conduct, on classes of persons who are considered to be responsible for the release of a "hazardous substance" into the environment. These persons include the current owner or operator of a contaminated facility, a former owner or operator of the facility at the time of contamination, and those persons that disposed or arranged for the disposal of the hazardous substance at the facility. Under CERCLA and comparable state statutes, persons deemed "responsible parties" may be subject to strict, joint and several liability for the costs of removing or remediating previously disposed wastes (including wastes disposed of or released by prior owners or operators) or property contamination (including groundwater contamination), for damages to natural resources and for the costs of certain health studies. In addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. In addition, the risk of accidental spills or releases could expose the operators of the acreage underlying our mineral interests to significant liabilities that could have a material adverse effect on the operators' businesses, financial condition and results of operations. Liability for any contamination under these laws could require the operators of the acreage underlying our mineral interests to make significant expenditures to investigate and remediate such contamination or attain and maintain compliance with such laws and may otherwise have a material adverse effect on their results of operations, competitive position or financial condition.
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Water Discharges
The Clean Water Act, the SDWA, the OPA, and analogous state laws and regulations promulgated thereunder impose restrictions and strict controls regarding the unauthorized discharge of pollutants, including produced waters and other gas and oil wastes, into regulated waters. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or the state. The Clean Water Act and regulations implemented thereunder also prohibit the discharge of dredge and fill material into regulated waters, including jurisdictional wetlands, unless authorized by an appropriately issued permit. In addition, spill prevention, control and countermeasure plan requirements under federal law require appropriate containment berms and similar structures to help prevent the contamination of navigable waters in the event of a petroleum hydrocarbon tank spill, rupture or leak. The EPA has also adopted regulations requiring certain oil and natural gas exploration and production facilities to obtain individual permits or coverage under general permits for storm water discharges, and in June 2016, the EPA finalized effluent limitation guidelines for the discharge of wastewater from hydraulic fracturing.
The OPA is the primary federal law for oil spill liability. The OPA contains numerous requirements relating to the prevention of and response to petroleum releases into regulated waters, including the requirement that operators of offshore facilities and certain onshore facilities near or crossing waterways must develop and maintain facility response contingency plans and maintain certain significant levels of financial assurance to cover potential environmental cleanup and restoration costs. The OPA subjects owners of facilities to strict, joint and several liability for all containment and cleanup costs and certain other damages arising from a release, including, but not limited to, the costs of responding to a release of oil into surface waters.
Noncompliance with the Clean Water Act or the OPA may result in substantial administrative, civil and criminal penalties, as well as injunctive obligations, for the operators of the acreage underlying our mineral interests.
Air Emissions
The federal Clean Air Act, and comparable state laws and regulations, regulate emissions of various air pollutants through the issuance of permits and the imposition of other requirements. The EPA has developed, and continues to develop, stringent regulations governing emissions of air pollutants at specified sources. New facilities may be required to obtain permits before work can begin, and existing facilities may be required to obtain additional permits and incur capital costs in order to remain in compliance. For example, most recently in May 2016, the EPA finalized additional regulations under the federal Clean Air Act that established new emission control requirements for oil and natural gas production and processing operations, which is discussed in more detail below in "—Regulation of Hydraulic Fracturing." These laws and regulations may increase the costs of compliance for oil and natural gas producers and impact production of the acreage underlying our mineral and royalty interests, and federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with air permits or other requirements of the federal Clean Air Act and associated state laws and regulations. Moreover, obtaining or renewing permits has the potential to delay the development of oil and natural gas projects.
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Climate Change
In response to findings that emissions of GHGs, including carbon dioxide and methane, present an endangerment to public health and the environment, the EPA has adopted regulations under existing provisions of the federal Clean Air Act that, among other things, require preconstruction and operating permits for certain large stationary sources. In addition, the EPA has adopted rules requiring the monitoring and reporting of GHGs from certain onshore oil and natural gas production sources on an annual basis. As a result of this continued regulatory focus, future GHG regulations of the oil and gas industry remain a possibility.
Congress has from time to time considered adopting legislation to reduce emissions of GHGs and many states have already taken legal measures to reduce emissions of GHGs primarily through the planned development of GHG emission inventories and/or regional GHG cap and trade programs. Although Congress has not adopted such legislation at this time, it may do so in the future and many states continue to pursue regulations to reduce GHG emissions. Additionally, efforts have been made and continue to be made in the international community toward the adoption of international treaties or protocols that would address global climate change issues. Most recently in 2015, the United States participated in the United Nations Conference on Climate Change, which led to the creation of the Paris Agreement. For example, in April 2016, the United States was one of 175 countries to sign the Paris Agreement, which requires member countries to review and "represent a progression" in their intended nationally determined contributions, which set GHG emission reduction goals, every five years beginning in 2020. The Paris Agreement entered into force in November 2016. The United States is one of more than 70 nations that has ratified or otherwise indicated that it intends to comply with the agreement.
Restrictions on emissions of methane or carbon dioxide that may be imposed in various states could adversely affect the oil and natural gas industry, and state and local climate change initiatives and, at this time, it is not possible to accurately estimate how potential future laws or regulations addressing GHG emissions would impact our business.
In addition, one potential consequence of climate change could be increased severity of extreme weather conditions such as more intense hurricanes, thunderstorms, tornados and snow or ice storms, as well as rising sea levels. Another possible consequence of climate change is increased volatility in seasonal temperatures. Extreme weather conditions can interfere with production and increase costs and damage resulting from extreme weather may not be fully insured. However, at this time, we are unable to determine the extent to which climate change may lead to increased storm or weather hazards affecting our business.
Regulation of Hydraulic Fracturing
Hydraulic fracturing is an important and common practice that is used to stimulate production of hydrocarbons from tight formations. The process involves the injection of water, sand and chemicals under pressure into formations to fracture the surrounding rock and stimulate production. Hydraulic fracturing operations have historically been overseen by state regulators as part of their oil and natural gas regulatory programs. However, on May 9, 2014, the EPA announced an advance notice of proposed rulemaking under the Toxic Substances Control Act, relating to chemical substances and mixtures used in oil and natural gas exploration or production. Further, in March 2015, the BLM adopted a rule requiring, among other things, public disclosure to the BLM of chemicals used in hydraulic fracturing operations after fracturing operations have been completed and would strengthen standards for wellbore integrity
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and management of fluids that return to the surface during and after fracturing operations on federal and Indian lands. On June 22, 2016, a federal district judge in Wyoming struck down the rule, finding that BLM lacked the authority to promulgate environmental regulations relating to hydraulic fracturing. The federal government has appealed this decision to the 10th Circuit Court of Appeals. In addition, legislation has been introduced before Congress that would provide for federal regulation of hydraulic fracturing and would require disclosure of the chemicals used in the fracturing process. If enacted, these or similar bills could result in additional permitting requirements for hydraulic fracturing operations as well as various restrictions on those operations. These permitting requirements and restrictions could result in delays in operations at well sites and also increased costs to make wells productive.
On August 16, 2012, the EPA approved final regulations under the federal Clean Air Act that establish new air emission controls for oil and natural gas production and natural gas processing operations. Specifically, the EPA's rule package includes New Source Performance Standards to address emissions of sulfur dioxide and volatile organic compounds ("VOCs") and a separate set of emission standards to address hazardous air pollutants frequently associated with oil and natural gas production and processing activities. The final rule seeks to achieve a 95% reduction in VOCs emitted by requiring the use of reduced emission completions or "green completions" on all hydraulically-fractured natural gas wells constructed or refractured after January 1, 2015. The rules also establish specific new requirements regarding emissions from compressors, controllers, dehydrators, storage tanks and other production equipment. In May 2016, the EPA finalized similar rules that impose VOC emissions limits on certain oil and natural gas operations that were previously unregulated, including hydraulically fractured oil wells, as well as methane emissions limits for certain new or modified oil and natural gas emissions sources.
In addition, governments have studied the environmental aspects of hydraulic fracturing practices. These studies, depending on their degree of pursuit and whether any meaningful results are obtained, could spur initiatives to further regulate hydraulic fracturing under the SDWA or other regulatory authorities. For example, in December 2016, the EPA issued its final report on a study it had conducted over several years regarding the effects of hydraulic fracturing on drinking water sources. The final report, contrary to several previously published draft reports issued by the EPA, found instances in which impacts to drinking water may occur. However, the report also noted significant data gaps that prevented the EPA from determining the extent or severity of these impacts. The U.S. Department of Energy has conducted an investigation into practices the agency could recommend to better protect the environment from drilling using hydraulic-fracturing completion methods. Additionally, certain members of Congress have called upon the U.S. Government Accountability Office to investigate how hydraulic fracturing might adversely affect water resources, the SEC to investigate the natural-gas industry and any possible misleading of investors or the public regarding the economic feasibility of pursuing natural gas deposits in shale formations by means of hydraulic fracturing, and the EIA to provide a better understanding of that agency's estimates regarding natural gas reserves, including reserves from shale formations, as well as uncertainties associated with those estimates.
Several states have adopted, or are considering adopting, regulations that could restrict or prohibit hydraulic fracturing in certain circumstances and/or require the disclosure of the composition of hydraulic fracturing fluids. For example, the Texas Legislature adopted legislation requiring oil and gas operators to publicly disclose the chemicals used in the hydraulic fracturing process, effective as of September 1, 2011. Further, in May 2013, the Texas Railroad Commission issued a "well integrity rule," which updates the requirements for drilling, putting pipe down, and cementing wells. The rule also includes new testing and reporting
143
requirements, such as: (i) the requirement to submit cementing reports after well completion or after cessation of drilling, whichever is later; and (ii) the imposition of additional testing on wells less than 1,000 feet below usable groundwater. The well integrity rule took effect in January 2014. Local governments also may seek to adopt ordinances within their jurisdictions regulating the time, place and manner of drilling activities in general or hydraulic fracturing activities in particular or prohibit the performance of well drilling in general or hydraulic fracturing in particular.
There has been increasing public controversy regarding hydraulic fracturing with regard to the use of fracturing fluids, impacts on drinking water supplies, use of water and the potential for impacts to surface water, groundwater and the environment generally. A number of lawsuits and enforcement actions have been initiated across the country implicating hydraulic fracturing practices. State and federal regulatory agencies recently have focused on a possible connection between the hydraulic fracturing related activities, particularly the disposal of produced water in underground injection wells, and the increased occurrence of seismic activity. When caused by human activity, such events are called induced seismicity. In some instances, operators of injection wells in the vicinity of seismic events have been ordered to reduce injection volumes or suspend operations. Some state regulatory agencies, including those in Colorado, Ohio, Oklahoma and Texas, have modified their regulations to account for induced seismicity. For example, following earthquakes in and around Cushing, Oklahoma, the Oklahoma Corporation Commission announced plans on November 7, 2016, to shut down or reduce the volume of disposal at certain injection wells that discharge into the Arbuckle formation. Regulatory agencies at all levels are continuing to study the possible linkage between oil and gas activity and induced seismicity. A 2012 report published by the National Academy of Sciences concluded that some of the tens of thousands of injection wells have been suspected to be, or have been, the likely cause of induced seismicity; and a 2015 report by researchers at the University of Texas has suggested that the link between seismic activity and wastewater disposal may vary by region. In 2015, the United States Geological Survey identified eight states including Colorado, Ohio, Oklahoma and Texas with areas of increased rates of induced seismicity that could be attributed to fluid injection or oil and gas extraction. More recently, in March 2016, the United States Geological Survey identified six states with the most significant hazards from induced seismicity, including Arkansas, Colorado, Kansas, New Mexico, Oklahoma and Texas, where many of our properties are located. In addition, a number of lawsuits have been filed, most recently in Oklahoma, alleging that disposal well operations have caused damage to neighboring properties or otherwise violated state and federal rules regulating waste disposal. These developments could result in additional regulation and restrictions on the use of injection wells and hydraulic fracturing. Such regulations and restrictions could cause delays and impose additional costs and restrictions on the operators of our properties and on their waste disposal activities.
If new laws or regulations that significantly restrict hydraulic fracturing and related activities are adopted, such laws could make it more difficult or costly to perform fracturing to stimulate production from tight formations as well as make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings based on allegations that specific chemicals used in the fracturing process could adversely affect groundwater. In addition, if hydraulic fracturing is further regulated at the federal or state level, fracturing activities could become subject to additional permitting and financial assurance requirements, more stringent construction specifications, increased monitoring, reporting and recordkeeping obligations, plugging and abandonment requirements and also to attendant permitting delays and potential increases in costs. Such legislative changes could cause operators to incur substantial compliance costs, and compliance or the consequences of any failure to comply by operators
144
could have a material adverse effect on our financial condition and results of operations. At this time, it is not possible to estimate the impact on our business of newly enacted or potential federal or state legislation governing hydraulic fracturing.
Other Regulation of the Oil and Natural Gas Industry
The oil and natural gas industry is extensively regulated by numerous federal, state and local authorities. Legislation affecting the oil and natural gas industry is under constant review for amendment or expansion, frequently increasing the regulatory burden. Also, numerous departments and agencies, both federal and state, are authorized by statute to issue rules and regulations that are binding on the oil and natural gas industry and its individual members, some of which carry substantial penalties for failure to comply. Although the regulatory burden on the oil and natural gas industry increases the cost of doing business, these burdens generally do not affect us any differently or to any greater or lesser extent than they affect other companies in the industry with similar types, quantities and locations of production.
The availability, terms and cost of transportation significantly affect sales of oil and natural gas. The interstate transportation of oil and natural gas and the sale for resale of natural gas is subject to federal regulation, including regulation of the terms, conditions and rates for interstate transportation, storage and various other matters, primarily by the Federal Energy Regulatory Commission ("FERC"). Federal and state regulations govern the price and terms for access to oil and natural gas pipeline transportation. FERC's regulations for interstate oil and natural gas transmission in some circumstances may also affect the intrastate transportation of oil and natural gas.
Although oil and natural gas prices are currently unregulated, Congress historically has been active in the area of oil and natural gas regulation. We cannot predict whether new legislation to regulate oil and natural gas might be proposed, what proposals, if any, might actually be enacted by Congress or the various state legislatures, and what effect, if any, the proposals might have on our operations. Sales of crude oil, condensate and natural gas liquids are not currently regulated and are made at market prices.
Drilling and Production
The operations of the operators of our properties are subject to various types of regulation at the federal, state and local level. These types of regulation include requiring permits for the drilling of wells, drilling bonds and reports concerning operations. The state, and some counties and municipalities, in which we operate also regulate one or more of the following:
- •
-
the location of wells;
- •
-
the method of drilling and casing wells;
- •
-
the timing of construction or drilling activities, including seasonal wildlife closures;
- •
-
the rates of production or "allowables";
- •
-
the surface use and restoration of properties upon which wells are drilled;
- •
- the plugging and abandoning of wells; and
145
- •
- notice to, and consultation with, surface owners and other third parties.
State laws regulate the size and shape of drilling and spacing units or proration units governing the pooling of oil and natural gas properties. Some states allow forced pooling or integration of tracts to facilitate exploration while other states rely on voluntary pooling of lands and leases. In some instances, forced pooling or unitization may be implemented by third parties and may reduce our interest in the unitized properties. In addition, state conservation laws establish maximum rates of production from oil and natural gas wells, generally prohibit the venting or flaring of natural gas and impose requirements regarding the ratability of production. These laws and regulations may limit the amount of oil and natural gas that the operators of our properties can produce from our wells or limit the number of wells or the locations at which operators can drill. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of oil, natural gas and natural gas liquids within its jurisdiction. States do not regulate wellhead prices or engage in other similar direct regulation, but we cannot assure you that they will not do so in the future. The effect of such future regulations may be to limit the amounts of oil and natural gas that may be produced from our wells, negatively affect the economics of production from these wells or to limit the number of locations operators can drill.
Federal, state and local regulations provide detailed requirements for the abandonment of wells, closure or decommissioning of production facilities and pipelines and for site restoration in areas where the operators of our properties operate. The U.S. Army Corps of Engineers and many other state and local authorities also have regulations for plugging and abandonment, decommissioning and site restoration. Although the U.S. Army Corps of Engineers does not require bonds or other financial assurances, some state agencies and municipalities do have such requirements.
Natural Gas Sales and Transportation
FERC has jurisdiction over the transportation and sale for resale of natural gas in interstate commerce by natural gas companies under the Natural Gas Act of 1938 ("NGA") and the Natural Gas Policy Act of 1978. Since 1978, various federal laws have been enacted which have resulted in the complete removal of all price and non-price controls for sales of domestic natural gas sold in "first sales."
Under the Energy Policy Act of 2005, FERC has substantial enforcement authority to prohibit the manipulation of natural gas markets and enforce its rules and orders, including the ability to assess substantial civil penalties. FERC also regulates interstate natural gas transportation rates and service conditions and establishes the terms under which the operators of our properties may use interstate natural gas pipeline capacity, as well as the revenues the operators of our properties receive for sales of natural gas and release of natural gas pipeline capacity. Interstate pipeline companies are required to provide nondiscriminatory transportation services to producers, marketers and other shippers, regardless of whether such shippers are affiliated with an interstate pipeline company. FERC's initiatives have led to the development of a competitive, open access market for natural gas purchases and sales that permits all purchasers of natural gas to buy gas directly from third party sellers other than pipelines.
Gathering service, which occurs upstream of jurisdictional transmission services, is regulated by the states onshore and in state waters. Section 1(b) of the NGA exempts natural gas gathering facilities from regulation by FERC under the NGA. Although its policy is still in flux, FERC has in the past reclassified certain jurisdictional transmission facilities as
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non-jurisdictional gathering facilities, which may increase the operators' costs of transporting gas to point-of-sale locations. This may, in turn, affect the costs of marketing natural gas that the operators of our properties produce.
Historically, the natural gas industry has been very heavily regulated; therefore, we cannot guarantee that the less stringent regulatory approach currently pursued by FERC and Congress will continue indefinitely into the future nor can we determine what effect, if any, future regulatory changes might have on our natural gas related activities.
Oil Sales and Transportation
Sales of crude oil, condensate and natural gas liquids are not currently regulated and are made at negotiated prices. Nevertheless, Congress could reenact price controls in the future.
Crude oil sales are affected by the availability, terms and cost of transportation. The transportation of oil in common carrier pipelines is also subject to rate regulation. FERC regulates interstate oil pipeline transportation rates under the Interstate Commerce Act and intrastate oil pipeline transportation rates are subject to regulation by state regulatory commissions. The basis for intrastate oil pipeline regulation, and the degree of regulatory oversight and scrutiny given to intrastate oil pipeline rates, varies from state to state. Insofar as effective interstate and intrastate rates are equally applicable to all comparable shippers, we believe that the regulation of oil transportation rates will not affect our operations in any materially different way than such regulation will affect the operations of our competitors.
Further, interstate and intrastate common carrier oil pipelines must provide service on a non-discriminatory basis. Under this open access standard, common carriers must offer service to all similarly situated shippers requesting service on the same terms and under the same rates. When oil pipelines operate at full capacity, access is governed by prorationing provisions set forth in the pipelines' published tariffs. Accordingly, we believe that our access to oil pipeline transportation services will not materially differ from our competitors' access to oil pipeline transportation services.
State Regulation
Texas regulates the drilling for, and the production, gathering and sale of, oil and natural gas, including imposing severance taxes and requirements for obtaining drilling permits. Texas currently imposes a 4.6% severance tax on the market value of oil production and a 7.5% severance tax on the market value of natural gas production. States also regulate the method of developing new fields, the spacing and operation of wells and the prevention of waste of oil and natural gas resources.
States may regulate rates of production and may establish maximum daily production allowables from oil and natural gas wells based on market demand or resource conservation, or both. States do not regulate wellhead prices or engage in other similar direct economic regulation, but we cannot assure you that they will not do so in the future. Should direct economic regulation or regulation of wellhead prices by the states increase, this could limit the amount of oil and natural gas that may be produced from our wells and the number of wells or locations the operators of our properties can drill.
The petroleum industry is also subject to compliance with various other federal, state and local regulations and laws. Some of those laws relate to resource conservation and equal
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employment opportunity. We do not believe that compliance with these laws will have a material adverse effect on our business.
We believe that the title to our assets is satisfactory in all material respects. Although title to these properties is subject to encumbrances in some cases, such as customary interests generally retained in connection with the acquisition of real property, customary royalty interests and contract terms and restrictions, liens under operating agreements, liens related to environmental liabilities associated with historical operations, liens for current taxes and other burdens, easements, restrictions, and minor encumbrances customary in the oil and natural gas industry, we believe that none of these liens, restrictions, easements, burdens, and encumbrances will materially detract from the value of these properties or from our interest in these properties.
The officers of our general partner will manage our operations and activities. However, neither we, our general partner nor our subsidiaries have employees. In connection with the closing of this offering, we will enter into a management services agreement with Kimbell Operating, which will enter into separate service agreements with certain entities controlled by Messrs. Duncan, R. Ravnaas, Taylor and Wynne, pursuant to which they and Kimbell Operating will provide management, administrative and operational services for us, including the operation of our properties. Please read "Management" and "Certain Relationships and Related Party Transactions." Immediately after the closing of this offering, we expect that Kimbell Operating will have approximately 10 employees performing services for our operations and activities. We believe that Kimbell Operating has a satisfactory relationship with those employees.
Our principal executive offices are located at 777 Taylor Street, Suite 810, Fort Worth, Texas 76102. We believe that these facilities are adequate for our current operations.
Although we may, from time to time, be involved in various legal claims arising out of our operations in the normal course of business, we do not believe that the resolution of these matters will have a material adverse impact on our financial condition or results of operations.
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Management of Kimbell Royalty Partners, LP
We are managed and operated by the board of directors and executive officers of our general partner.
Our Sponsors own all the membership interests in Kimbell GP Holdings, LLC, which owns all the membership interests in our general partner. As a result of controlling our general partner, our Sponsors will have the right to appoint all members of the board of directors of our general partner, including the independent directors. Our unitholders will not be entitled to elect our general partner or its directors or otherwise directly participate in our management or operation. Our general partner owes certain duties to our unitholders as well as a fiduciary duty to its owners.
Upon the closing of this offering, we expect that our general partner will have nine directors, at least three of whom will be independent as defined under the independence standards established by the NYSE and the Exchange Act. We anticipate that our board of directors will determine that William H. Adams III, C.O. Ted Collins, Jr. and Craig Stone are independent under the independence standards of the NYSE.
The NYSE does not require a listed publicly traded partnership, such as ours, to have a majority of independent directors on the board of directors of our general partner or to establish a compensation committee or a nominating and corporate governance committee. However, our general partner is required to have an audit committee of at least three members, and all its members are required to meet the independence and experience standards established by the NYSE and the Exchange Act, subject to the transitional relief during the one-year period following the completion of this offering.
All of the executive officers of our general partner are also officers of Kimbell Operating. The executive officers of our general partner will allocate their time between managing our business and affairs and the business and affairs of certain other entities, including our Sponsors, certain of the Contributing Parties and Kimbell Operating. In addition, employees of Kimbell Operating will provide management, administrative and operational services to us pursuant to a management services agreement, but they will also provide these services to certain other entities, including certain of the Contributing Parties. Please read "Certain Relationships and Related Party Transactions—Agreements and Transactions with Affiliates in Connection with this Offering—Management Services Agreements." We expect the executive officers of our general partner and other shared personnel to devote a sufficient amount of time to our business and affairs as is necessary for the proper management and conduct of our business and operations. However, we anticipate that, for the foreseeable future, the executive officers of our general partner and other shared personnel will also devote substantial amounts of their time to managing the businesses of other entities.
Our partnership agreement requires us to reimburse our general partner and its affiliates, including our Sponsors and their respective affiliates, for all expenses they incur and payments they make on our behalf in connection with operating our business. Our partnership agreement does not set a limit on the amount of expenses for which our general partner and its affiliates may be reimbursed. These expenses include salary, bonus, incentive compensation and other amounts paid to persons who perform services for us or on our behalf and expenses allocated to
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our general partner by its affiliates. Our partnership agreement provides that our general partner will determine the expenses that are allocable to us.
Executive Officers and Directors of Our General Partner
The following table shows information for the executive officers, directors and director nominees of our general partner upon the consummation of this offering. Directors hold office until their successors have been elected or qualified or until the earlier of their death, resignation, removal or disqualification. Executive officers serve at the discretion of the board. Messrs. R. Ravnaas and D. Ravnaas are father and son, respectively, and Messrs. Fortson and Wynne are father-in-law and son-in-law, respectively.
| Name |
Age
(as of September 30, 2016) |
Position With Our General Partner | |||
|---|---|---|---|---|---|
|
Robert D. Ravnaas |
59 | Chief Executive Officer and Chairman of the Board of Directors | |||
|
R. Davis Ravnaas |
31 | President and Chief Financial Officer | |||
|
Jeff McInnis |
40 | Chief Accounting Officer | |||
|
Matthew S. Daly |
44 | Senior Vice President—Corporate Development | |||
|
Brett G. Taylor |
56 | Executive Vice Chairman of the Board of Directors | |||
|
Benny D. Duncan |
73 | Director | |||
|
Ben J. Fortson |
84 | Director | |||
|
T. Scott Martin |
66 | Director | |||
|
Mitch S. Wynne |
58 | Director | |||
|
William H. Adams III |
58 | Independent Director Nominee | |||
|
C.O. Ted Collins, Jr. |
79 | Independent Director Nominee | |||
|
Craig Stone |
53 | Independent Director Nominee | |||
Robert D. Ravnaas. Robert D. Ravnaas was appointed Chief Executive Officer of our general partner and Chairman of the board of directors of our general partner in November 2015. Mr. R. Ravnaas has served as President of Cawley, Gillespie & Associates, Inc., a petroleum engineering firm, since 2011. He has also served as President and director of Rivercrest Royalties II, LLC since 2014, and as President and director of Rivercrest Royalties, LLC since 2013, and he is a partial owner of certain of the Contributing Parties. Prior to joining Cawley, Gillespie & Associates, Inc. in 1983, he worked as a Production Engineer for Amoco Production Company from 1981 to 1983. Mr. R. Ravnaas received a Bachelor of Science degree with special honors in Chemical Engineering from the University of Colorado at Boulder and a Master of Science degree in Petroleum Engineering from the University of Texas at Austin. He is a registered professional engineer in Texas and a member of the Society of Petroleum Engineers, the Society of Petroleum Evaluation Engineers and the American Association of Petroleum Geologists. Mr. R. Ravnaas was selected to serve as a director because of his broad knowledge of, and extensive experience in, the oil and gas industry.
R. Davis Ravnaas. R. Davis Ravnaas was appointed President and Chief Financial Officer of our general partner in November 2015. Mr. D. Ravnaas co-founded Rivercrest Royalties, LLC in October 2013, served as Vice President and Chief Financial Officer from November 2013 to October 2015 and has served as President and Chief Financial Officer of Rivercrest Royalties, LLC since October 2015. He has also served as Vice President and Chief Financial
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Officer of Rivercrest Royalties II, LLC since August 2014, and he is a partial owner of certain of the Contributing Parties. From 2010 to 2012, Mr. D. Ravnaas was responsible for sourcing, evaluating and monitoring investments in energy and industrials companies as an associate investment professional with Crestview Partners, a New York based private equity fund with $6.0 billion under management. Mr. D. Ravnaas left Crestview Partners in 2012 to attend the Stanford Graduate School of Business, where he earned his Master in Business Administration in 2014. Mr. D. Ravnaas also has an AB in Economics from Princeton University and a MSc in Finance and Economics from the London School of Economics.
Jeff McInnis. Jeff McInnis was appointed Chief Accounting Officer of our general partner in November 2015. Mr. McInnis has served as Chief Accounting Officer of Rivercrest Royalties, LLC since May 2015. From June 2014 until May 2015, Mr. McInnis worked as an independent consultant, advising oil and gas companies on accounting and financial reporting matters. Previously, he was Director of Financial Reporting at JP Energy Partners LP, a midstream master limited partnership, from 2012 to June 2014. From 2010 to 2012, Mr. McInnis was Controller at Hill & Hill Production, a suite of private, family-run entities concentrated on exploration and production oil and gas ventures. Additionally, he held positions at PricewaterhouseCoopers LLP in their Assurance group from 2003 to 2006 and again from 2009 to 2010 and as a Transaction Services Manager from 2006 to 2009, during which time he specialized in providing services to a variety of public and private clients. From 2001 to 2003, he was an International Accounting Analyst at Triton Energy Limited. Mr. McInnis has a Bachelor of Business Administration degree in Accounting and Finance and a Master of Accounting degree from Texas Christian University and is a certified public accountant.
Matthew S. Daly. Matthew S. Daly will serve as Senior Vice President—Corporate Development of our general partner. Mr. Daly has also served as Senior Vice President—Corporate Development of Rivercrest Royalties, LLC since August 2016. From 2014 to 2016, Mr. Daly served as Senior Analyst—Energy at Hirzel Capital Management LLC, a Dallas-based hedge fund, where he managed public energy investments. From 2004 to 2013, he served as Senior Analyst—Energy at Kleinheinz Capital Partners, Inc., where he managed public and private energy investments and assisted with macro hedging trades. From 2002 to 2004, Mr. Daly was a Vice President—Mergers and Acquisitions at Lazard Frères & Co. in New York City. Mr. Daly has a Bachelor of Business Administration from the University of Texas at Austin and a Master of Business Administration from the University of Chicago Booth School of Business and is a certified public accountant.
Brett G. Taylor. Brett G. Taylor was appointed as Executive Vice Chairman of the board of directors of our general partner in November 2015. Mr. Taylor has over 33 years of experience in the oil and gas industry as a petroleum landman. He began his career at Texas Oil and Gas Corporation from 1982 to 1985. He then spent thirteen years at Fortson Oil Company, where he served as Land Manager and Vice President—Land from 1985 to 1998. In 1998, Mr. Taylor co-founded, with Joe B. Neuhoff, Neuhoff-Taylor Royalty Company and began acquiring producing royalties and minerals. He has also served as President and Chief Executive Officer of various Taylor Companies since 1998, and certain of such companies are Contributing Parties. In 1999, Messrs. Taylor, Fortson and R. Ravnaas co-founded Kimbell Royalty Partners group, which is led by the Kimbell Art Foundation. Mr. Taylor has a Bachelor of Business Administration—Petroleum Land Management degree from the University of Texas at Austin and is a member of the American Association of Professional Landmen. Mr. Taylor was selected to serve as a director because of his broad knowledge of land management, oil and gas title, due diligence and related matters.
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Benny D. Duncan. Benny D. Duncan was appointed as a director of our general partner in November 2016. Mr. Duncan has over 50 years of experience in the oil and gas industry. He began his career with Vaughn Petroleum, Inc. and its subsidiaries ("VPI") as Assistant Land Manager from 1961 through 1970. Mr. Duncan joined First National Bank of Dallas in 1970 as Land Manager and Engineering Technician and later served as Assistant Vice President—Trust Oil and Gas Division until 1975. Mr. Duncan then returned to VPI, where he served in various operational positions from 1975 to 1990, including as Director and Land Manager, Executive Vice President and Chief Operating Officer, and President. In 1994, Mr. Duncan was actively involved in the formation of Vaughn Petroleum Royalty Partners, Ltd. ("VPRP"). He served as Manager of VPRP's properties in 1999, and he has continued to manage such properties since their sale in 2004. Between 2005 and 2009, Mr. Duncan formed: Trunk Bay Royalty Partners, Ltd., Bitter End Royalties, LP, Oil Nut Bay Royalties, LP, Nail Bay Royalties, LLC and Gorda Sound Royalties, LP, which make up a portion of the Contributing Parties. He has served as manager of (i) Trunk Bay, LLC, the general partner of Trunk Bay Royalty Partners, Ltd., since 2005; (ii) Bitter End, LLC, the general partner of Bitter End Royalties, LP, since 2008; (iii) Oil Nut Bay, LLC, the general partner of Oil Nut Bay Royalties, LP, since 2008; (iv) Nail Bay Royalties, LLC since 2009; and (v) Gorda Sound, LLC, the general partner of Gorda Sound Royalties, LP, since 2009. Mr. Duncan studied business administration at Arlington State College (now the University of Texas at Arlington). He is an active member of the American Association of Professional Landmen and the Dallas Petroleum Club. Mr. Duncan was selected to serve as a director because of his broad knowledge of, and extensive experience in, the oil and gas industry.
Ben J. Fortson. Ben J. Fortson was appointed as a director of our general partner in November 2015. He has nearly 60 years of experience in the oil and gas industry. Mr. Fortson has served as President and Chief Executive Officer of Fortson Oil Company since 1986 and has been Vice President and Chief Investment Officer of the Kimbell Art Foundation, a Contributing Party, since 1975. Mr. Fortson has served on the Board of Trustees of the Kimbell Art Foundation since 1964. He is also a trustee and Vice President of the Burnett Foundation, a member of the Exchange Club of Fort Worth, a Trustee Emeritus of Texas Christian University and an Emeritus Member of the All-American Wildcatters. Mr. Fortson has a Bachelor of Arts degree from the Texas Christian University. Mr. Fortson was selected to serve as a director because of his broad knowledge of, and extensive experience in, the oil and gas industry.
T. Scott Martin. T. Scott Martin was appointed as a director of our general partner in November 2015. Mr. Martin has served as Chief Executive Officer of our predecessor since July 2014 and Chief Executive Officer and Chairman of EE3 LLC since 2011. He has also served as Chairman of the board of directors of Rivercrest Royalties II, LLC since July 2015. He has over 35 years of experience in the oil and gas industry. Mr. Martin founded Ellora Energy LLC in 1995 and was Chairman and Chief Executive Officer of Ellora Energy Inc. from 2002 to 2010. Before that, he was Chief Operating Officer of Alta Energy Corporation from 1992 to 1994, Chief Executive Officer of TPEX Exploration, Inc. from 1990 to 1992 and a consulting engineer at BWAB, Inc. from 1985 to 1990. Mr. Martin began his career in the oil and gas industry in 1979 at Amoco Production Company. Mr. Martin has a Bachelor of Arts degree in Biology from Colorado College and a degree in Chemical Engineering from the University of Colorado at Boulder. He is a member of the Society of Petroleum Engineers and the Independent Petroleum Association of America. Mr. Martin was selected to serve as a director because of his broad knowledge of, and extensive experience in, the oil and gas industry.
Mitch S. Wynne. Mitch S. Wynne was appointed as a director of our general partner in November 2015. He has been President and owner of Wynne Petroleum Co. since 1992. Mr. Wynne has been engaged in the oil and gas industry for 35 years. In 2013, he founded MSW
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Royalties, LLC, a Contributing Party, where he serves as manager. Mr. Wynne served on the board of Inspire Insurance Solutions from 1997 to 2002, Millers Mutual Insurance in 1997 and the All Saints' Episcopal School from 1994 to 1996. He has also served on the board of the Union Gospel Mission in Fort Worth since 2010. Mr. Wynne has a Bachelor of Arts degree in Political Science from Washington and Lee University. Mr. Wynne was selected to serve as a director because of his broad knowledge of, and extensive experience in, the oil and gas industry.
William H. Adams III. William H. Adams III will serve as a director of our general partner effective as of the consummation of this offering. Since 2007, Mr. Adams has served as Chairman and Principal Owner of Texas Appliance Supply, Inc., a wholesale and retail appliance distribution company. From 1981 to 2006, Mr. Adams held a variety of positions in the commercial and energy banking sector, including as Executive Regional President of Texas Bank in Fort Worth and as President of Frost Bank—Arlington. From 2001 to 2010, Mr. Adams served as a member of the board of directors of XTO Energy, Inc., and he currently serves as a member of the board of directors of Morningstar Partners, a private oil and gas production company. Mr. Adams has a Bachelor of Business Administration in Finance from Texas Tech University. Mr. Adams was selected to serve as a director because of his extensive experience in the energy banking sector and as a former director of a public oil and gas company.
C.O. Ted Collins, Jr. C.O. Ted Collins, Jr. will serve as a director of our general partner effective as of the consummation of this offering. Mr. Collins has over 57 years of experience in the oil and gas industry, and he has been an independent oil and gas producer since 2000. Mr. Collins previously served as President of Collins & Ware Inc. from 1988 to 2000. From 1982 to 1988, Mr. Collins served as President of Enron Oil & Gas Co. and HNG Oil Company. From 1969 to 1982, he served as Executive Vice President of American Quasar Petroleum Company. Mr. Collins also serves as a member of the board of directors of Energy Transfer Equity, LP, Oasis Petroleum Corp., CLL Global Research Foundation and RSP Permian, Inc. Mr. Collins is a past President of the Permian Basin Petroleum Association, the Permian Basin Landmen's Association and the Petroleum Club of Midland, and has served as Chairman of the Midland Wildcat Committee since 1984. Mr. Collins has a Bachelor of Science in Geological Engineering from the University of Oklahoma. Mr. Collins was selected to serve as a director because of his broad knowledge of, and extensive experience in, the oil and gas industry, as well as his prior experience as a director of the general partner of a master limited partnership.
Craig Stone. Craig Stone will serve as a director of our general partner effective as of the consummation of this offering. Mr. Stone concluded a 30-year career with Ernst & Young LLP when he retired effective September 2015. Prior to his retirement, Mr. Stone was an audit partner and the Fort Worth Managing Partner at Ernst & Young LLP. Over the course of his career, he has served many public oil and gas clients and assisted in numerous mergers, acquisitions and public offerings, including initial public offerings, secondary offerings and public debt transactions. He has a Bachelor of Sciences in Accounting from Abilene Christian University and is a certified public accountant. Mr. Stone was selected to serve as a director because of his extensive financial experience with public oil and gas companies.
In accordance with the rules of the NYSE, our Sponsors must appoint at least one independent director by the time our common units are first listed on the NYSE, one additional independent member within 90 days of the effective date of the registration statement of which this prospectus forms a part and one additional independent member within one year of the
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effective date of the registration statement. We anticipate that our board of directors will determine that William H. Adams III, C.O. Ted Collins, Jr. and Craig Stone are independent under the independence standards of the NYSE in connection with their appointment to our board of directors upon the consummation of this offering.
Robert D. Ravnaas currently serves as the Chief Executive Officer and Chairman of the board of directors of our general partner. The board of directors of our general partner has no policy with respect to the separation of the offices of chairman of the board of directors and chief executive officer. Instead, that relationship is defined and governed by the limited liability company agreement of our general partner, which permits the same person to hold both offices. Directors of the board of directors of our general partner are appointed by Kimbell Holdings, which is jointly owned by our Sponsors. Accordingly, unlike holders of common stock in a corporation, our unitholders will have only limited voting rights on matters affecting our business or governance, subject in all cases to any specific unitholder rights contained in our partnership agreement.
Our corporate governance guidelines will provide that the board of directors of our general partner is responsible for reviewing the process for assessing the major risks facing us and the options for their mitigation. This responsibility will be largely satisfied by the audit committee, which is responsible for reviewing and discussing with management and our registered public accounting firm our major risk exposures and the policies management has implemented to monitor such exposures, including our financial risk exposures and risk management policies.
Committees of the Board of Directors
The board of directors of our general partner will have an audit committee and a conflicts committee. We do not expect that we will have a compensation committee, but rather that the board of directors of our general partner will have authority over compensation matters. The board may also have such other committees as they determine from time to time.
Audit Committee
We are required to have an audit committee of at least three members, and all its members are required to meet the independence and experience standards established by the NYSE and Rule 10A-3 promulgated under the Exchange Act, subject to certain transitional relief during the one-year period following consummation of this offering as described above. The audit committee will initially be composed of William H. Adams III and Craig Stone. The audit committee will assist the board of directors in its oversight of the integrity of our financial statements and our compliance with legal and regulatory requirements and partnership policies and controls. The audit committee will have the sole authority to retain and terminate our independent registered public accounting firm, approve all auditing services and related fees and the terms thereof performed by our independent registered public accounting firm, and pre-approve any non-audit services and tax services to be rendered by our independent registered public accounting firm. The audit committee will also be responsible for confirming the independence and objectivity of our independent registered public accounting firm. Our independent registered public accounting firm will be given unrestricted access to the audit committee and our management, as necessary.
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Conflicts Committee
In accordance with the terms of our partnership agreement, at least two members of the board of directors of our general partner will serve on our conflicts committee to review specific matters that may involve conflicts of interest. The conflicts committee will initially be composed of William H. Adams III and Craig Stone. The members of our conflicts committee cannot be officers or employees of our general partner or directors, officers or employees of its affiliates or the Contributing Parties, and must meet the independence and experience standards established by the NYSE and the Exchange Act to serve on an audit committee of a board of directors. In addition, the members of our conflicts committee cannot own any interest in our general partner, its affiliates or the Contributing Parties or any interest in us or our subsidiaries other than common units or awards, if any, under our long-term incentive plan. Please read "Conflicts of Interest and Duties."
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EXECUTIVE COMPENSATION AND OTHER INFORMATION
Compensation Discussion and Analysis
We and our general partner were formed in October 2015. Neither we nor our general partner have accrued or paid or will accrue or pay any obligations with respect to management compensation or retirement benefits for the directors and executive officers of our general partner for any periods prior to the consummation of this offering. Accordingly, we are not presenting any compensation for historical periods. We do not expect that we will have a compensation committee, but rather that the board of directors of our general partner will have authority over compensation matters.
Our general partner has the sole responsibility for conducting our business and for managing our operations, and its board of directors and executive officers make decisions on our behalf. We do not and will not directly employ any of the persons responsible for managing our business. Our general partner's executive officers will manage and operate our business as part of the services provided by Kimbell Operating to our general partner under a management services agreement. All of our general partner's executive officers and other employees necessary to operate our business will be employed and compensated by Kimbell Operating or an entity with which Kimbell Operating arranges for the provision of services, subject to reimbursement by our general partner. The compensation for all of our executive officers will be indirectly paid by us to the extent provided for in the partnership agreement because we will reimburse our general partner for payments it makes to Kimbell Operating. Please read "Certain Relationships and Related Party Transactions—Agreements and Transactions with Affiliates in Connection with this Offering—Management Services Agreements" and "Management."
Certain of the executive officers of our general partner will have responsibilities to both us and our Sponsors, certain of the Contributing Parties or Kimbell Operating, and we expect that these executive officers will allocate their time between managing our business and managing the respective businesses of our Sponsors, certain of the Contributing Parties and Kimbell Operating. Although we will bear an allocated portion of Kimbell Operating's costs of providing compensation and benefits to Kimbell Operating employees who serve as the executive officers of our general partner and provide services to us, our general partner and not us will have control over such costs and will establish or direct the compensation policies or practices of Kimbell Operating. All compensation-related decisions for Kimbell Operating, including all determinations with respect to any awards that may be made to our executive officers, key employees and independent directors under any long-term incentive plan we adopt, will be made by the board of directors of our general partner or a committee thereof that may be established for such purpose. Please read the description of the long-term incentive plan we intend to adopt prior to the completion of this offering below under the heading "—Long-Term Incentive Plan."
The executive officers of our general partner, as well as the employees of our Sponsors, the Contributing Parties and Kimbell Operating who provide services to us, may participate in employee benefit plans and arrangements sponsored by our Sponsors, the Contributing Parties and Kimbell Operating, including plans that may be established in the future. In accordance with the terms of our partnership agreement, we will reimburse our general partner for compensation related expenses attributable to the portion of the executive's time dedicated to providing services to us. Please read "The Partnership Agreement—Reimbursement of Expenses." Except with respect to any awards granted under the long-term incentive plan we intend to adopt prior to the completion of this offering, we expect that compensation paid or
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awarded by us in 2017 will consist only of the portion of compensation that is allocated to us and our general partner pursuant to our general partner's allocation methodology and subject to the terms of the partnership agreement and our management services agreement with Kimbell Operating.
If additional details regarding the terms of future compensatory arrangements for our executive officers are known prior to the effective date of this offering, such details will be outlined in further detail herein. In the future, as our general partner formulates and implements the compensation programs for our executive officers, our general partner or Kimbell Operating may provide different or additional compensation components, benefits or perquisites to our executive officers, to ensure they are provided with a balanced, comprehensive and competitive compensation structure.
In order to incentivize our management and directors following the completion of this offering to continue to grow our business, the board of directors of our general partner intends to adopt a long-term incentive plan ("LTIP") for employees, officers, consultants and directors of our general partner, Kimbell Operating and their respective affiliates, who perform services for us. Our general partner intends to implement the LTIP prior to the completion of this offering to provide maximum flexibility with respect to the design of compensatory arrangements for individuals providing services to us; however, at this time, neither we nor our general partner have made any decisions regarding any specific grants under the LTIP in conjunction with this offering or in the near term.
The description of the LTIP set forth below is a summary of the material features of the LTIP that our general partner intends to adopt. This summary, however, does not purport to be a complete description of all the provisions of the LTIP that will be adopted and represents only our general partner's current expectations regarding the LTIP. This summary is qualified in its entirety by reference to the LTIP, the form of which will be filed as an exhibit to this registration statement. The purpose of the LTIP is to provide a means to attract and retain individuals who are essential to our growth and profitability and to encourage them to devote their best efforts to advancing our business by affording such individuals a means to acquire and maintain ownership of awards, the value of which is tied to the performance of our common units. We expect that the LTIP will provide for the grant of unit options, unit appreciation rights, restricted units, unit awards, phantom units, distribution equivalent rights and cash awards (collectively, "awards"). These awards are intended to align the interests of employees, officers, consultants and directors with those of our unitholders and to give such individuals the opportunity to share in our long-term performance. Any awards that are made under the LTIP will be approved by the board of directors of our general partner or a committee thereof that may be established for such purpose. We will be responsible for the cost of awards granted under the LTIP.
Administration
The LTIP will be administered by the board of directors of our general partner or an alternative committee appointed by the board of directors of our general partner, which we refer to together as the "committee" for purposes of this summary. The committee will administer the LTIP pursuant to its terms and all applicable state, federal, or other rules or laws. The committee will have the power to determine to whom and when awards will be granted, determine the amount of awards (measured in cash or of our common units), proscribe and interpret the terms and provisions of each award agreement (the terms of which may vary), accelerate the vesting
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provisions associated with an award, delegate duties under the LTIP and execute all other responsibilities permitted or required under the LTIP. In the event that the committee is not comprised of "non-employee directors" within the meaning of Rule 16b-3 under the Exchange Act, the full board of directors or a subcommittee of two or more non-employee directors will administer all awards granted to individuals that are subject to Section 16 of the Exchange Act.
Securities to be Offered
The maximum aggregate number of common units that may be issued pursuant to any and all awards under the LTIP shall not exceed common units, subject to adjustment due to recapitalization or reorganization, or related to forfeitures or expiration of awards, as provided under the LTIP. Under the LTIP, the maximum aggregate grant date fair value of awards granted to a non-employee director of our general partner during any calendar year will not exceed $ (or $ in the first year in which an individual becomes a non-employee director).
If any common units subject to any award are not issued or transferred, or cease to be issuable or transferable for any reason, including (but not exclusively) because units are withheld or surrendered in payment of taxes or any exercise or purchase price relating to an award or because an award is forfeited, terminated, expires unexercised, is settled in cash in lieu of common units, or is otherwise terminated without a delivery of units, those common units will again be available for issue, transfer, or exercise pursuant to awards under the LTIP, to the extent allowable by law. Common units to be delivered pursuant to awards under our LTIP may be common units acquired by our general partner in the open market, from any other person, directly from us, or any combination of the foregoing.
Awards
Unit Options
We may grant unit options to eligible persons. Unit options are rights to acquire common units at a specified price. The exercise price of each unit option granted under the LTIP will be stated in the unit option agreement and may vary; provided, however, that, the exercise price for an unit option must not be less than 100% of the fair market value per common unit as of the date of grant of the unit option. Unit options may be exercised in the manner and at such times as the committee determines for each unit option and the term of the unit option will not exceed ten years. The committee will determine the methods and form of payment for the exercise price of a unit option and the methods and forms in which common units will be delivered to a participant.
Unit Appreciation Rights
A unit appreciation right is the right to receive, in cash or in common units, as determined by the committee, an amount equal to the excess of the fair market value of one common unit on the date of exercise over the grant price of the unit appreciation right. The committee will be able to make grants of unit appreciation rights and will determine the time or times at which a unit appreciation right may be exercised in whole or in part. The exercise price of each unit appreciation right granted under the LTIP will be stated in the unit appreciation right agreement and may vary; provided, however, that, the exercise price must not be less than 100% of the fair market value per common unit as of the date of grant of the unit appreciation right. The term of the unit appreciation right will not exceed ten years.
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Restricted Units
A restricted unit is a grant of a common unit subject to a risk of forfeiture, performance conditions, restrictions on transferability and any other restrictions imposed by the committee in its discretion. Restrictions may lapse at such times and under such circumstances as determined by the committee. Unless otherwise determined by the committee, a common unit distributed in connection with a unit split or unit dividend, and other property distributed as a dividend, will generally be subject to restrictions and a risk of forfeiture to the same extent as the restricted unit with respect to which such common unit or other property has been distributed. Unless otherwise determined by the committee, each restricted unit will be entitled to receive distributions in the same manner as other outstanding common units.
Unit Awards
The committee will be authorized to grant common units that are not subject to restrictions. The committee may grant unit awards to any eligible person in such amounts as the committee, in its sole discretion, may select.
Phantom Units
Phantom units are rights to receive common units, cash or a combination of both at the end of a specified period. The committee may subject phantom units to restrictions (which may include a risk of forfeiture) to be specified in the phantom unit agreement that may lapse at such times determined by the committee. Phantom units may be satisfied by delivery of common units, cash equal to the fair market value of the specified number of common units covered by the phantom unit or any combination thereof determined by the committee. Cash distribution equivalents may be paid during or after the vesting period with respect to a phantom unit, as determined by the committee.
Distribution Equivalent Rights
The committee will be able to grant distribution equivalent rights in tandem with awards under the LTIP (other than unit awards or an award of restricted units), or distribution equivalent rights may be granted alone. Distribution equivalent rights entitle the participant to receive cash equal to the amount of any cash distributions made by us during the period the distribution equivalent right is outstanding. Payment of cash distributions pursuant to a distribution equivalent right issued in connection with another award may be subject to the same vesting terms as the award to which it relates or different vesting terms, in the discretion of the committee.
Cash Awards
The LTIP will permit the grant of awards denominated and settled in cash. Cash awards may be based, in whole or in part, on the value or performance of a common unit.
Miscellaneous
Tax Withholding
At our discretion, and subject to conditions that the committee may impose, the payment of any applicable taxes with respect to an award may be satisfied by withholding from any
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payment related to an award or by the withholding of common units issuable pursuant to the award based on the fair market value of our common units in each case up to the maximum statutory rate.
Anti-Dilution Adjustments
In the event that any distribution, recapitalization, split, reverse split, reorganization, merger, consolidation, split-up, spin-off, combination, repurchase or exchange of our common units, issuance of warrants or other rights to purchase our common units or other similar transaction or event affects our common units, then a corresponding and proportionate adjustment shall be made in accordance with the terms of the LTIP, as appropriate, with respect to the maximum number of units available under the LTIP, the number of units that may be acquired with respect to an award, and, if applicable, the exercise price of an award, in order to prevent dilution or enlargement of awards as a result of such events.
Change of Control
The effect, if any, of a change of control on outstanding awards will be described in the applicable award agreement.
Termination of Employment or Service
The consequences of the termination of a participant's employment, consulting arrangement or membership on the board of directors will be determined by the committee in the terms of the relevant award agreement.
We and our general partner were formed in October 2015 and, as such, have not accrued or paid any obligations with respect to compensation for directors of our general partner for any periods prior to our formation date.
The executive officers or employees of our general partner or of Kimbell Operating who also serve as directors of our general partner will not receive additional compensation for their service as a director of our general partner. Directors of our general partner who are not executive officers or employees of our general partner or of Kimbell Operating will receive compensation as "non-employee directors" as set by our general partner's board of directors.
Effective as of the closing of this offering, each non-employee director will receive a compensation package that will consist of an annual cash retainer of $ plus an additional annual payment of $ for the chairperson and $ for each other member of the audit committee and $ for the chairperson and $ for each other member of each other committee. Our directors will also receive a fee of $ for attending each in-person meeting of the board of directors or its committees and $ for attending each telephone meeting. In addition, our directors will be reimbursed for out-of-pocket expenses in connection with attending meetings of the board of directors or its committees. Each non-employee director may receive grants of equity-based awards under the LTIP we intend to adopt prior to the completion of this offering from time to time for so long as he or she serves as a director.
Each member of the board of directors of our general partner will be indemnified for his actions associated with being a director to the fullest extent permitted under Delaware law.
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SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
The following table presents information regarding the beneficial ownership of our common units following this offering and the other formation transactions by:
- •
-
our general partner;
- •
-
each of our general partner's directors and executive officers;
- •
-
each unitholder known by us to beneficially hold 5% or more of our common units; and
- •
- all of our general partner's directors and executive officers as a group.
Beneficial ownership is determined under the rules of the SEC and generally includes voting or investment power with respect to securities. Unless otherwise noted, the address for each beneficial owner listed below is 777 Taylor Street, Suite 810, Fort Worth, Texas 76102.
The following table does not include any units that may be purchased pursuant to our directed unit program. Please read "Underwriting—Directed Unit Program."
| Name of Beneficial Owner |
Common Units
Beneficially Owned |
Percentage of
Common Units Beneficially Owned (1) |
|||||
|---|---|---|---|---|---|---|---|
|
(2) |
% | ||||||
|
(3) |
% | ||||||
|
(4) |
% | ||||||
|
(5) |
% | ||||||
|
Robert D. Ravnaas |
% | ||||||
|
R. Davis Ravnaas |
% | ||||||
|
Jeff McInnis |
% | ||||||
|
Matthew S. Daly |
% | ||||||
|
Brett G. Taylor |
% | ||||||
|
Benny D. Duncan |
% | ||||||
|
Ben J. Fortson |
% | ||||||
|
T. Scott Martin |
% | ||||||
|
Mitch S. Wynne |
% | ||||||
|
William H. Adams III |
% | ||||||
|
C.O. Ted Collins, Jr. |
% | ||||||
|
Craig Stone |
% | ||||||
|
All directors and executive officers as a group (12 persons) |
% | ||||||
- *
-
Less
than 1%
- (1)
-
This
table assumes the underwriters do not exercise their option to purchase additional common units and such units are therefore issued to the Contributing
Parties upon the expiration of the option period. If such option is exercised in full, the Contributing Parties will beneficially
own common units, or % of the total
common units outstanding.
- (2)
-
The
address for this beneficial owner is .
- (3)
-
The
address for this beneficial owner is .
- (4)
-
The
address for this beneficial owner is .
- (5)
- The address for this beneficial owner is .
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CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS
Upon the completion of this offering, assuming that the underwriters do not exercise their option to purchase additional common units, affiliates of our Sponsors will own an aggregate common units (excluding any common units purchased by officers and directors of our general partner under our directed unit program), representing a % limited partner interest in us, and our Sponsors will indirectly own and control our general partner. Our Sponsors will also appoint all of the directors of our general partner, which will own a non-economic general partner interest in us that does not entitle it to receive distributions.
The terms of the transactions and agreements disclosed in this section were determined by and among affiliated entities and, consequently, are not the result of arm's length negotiations. These terms are not necessarily at least as favorable to the parties to these transactions and agreements as the terms that could have been obtained from unaffiliated third parties.
Distributions and Payments to Our Sponsors, the Contributing Parties, Our General Partner and their Respective Affiliates
The following table summarizes the distributions and payments made or to be made by us to our Sponsors, the Contributing Parties, our general partner and their respective affiliates in connection with the formation, ongoing operation and any liquidation of us.
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|
Operational Stage |
||
|
Cash distributions to the Contributing Parties |
We will generally pay cash distributions 100% to our unitholders, including the Contributing Parties, pro rata. Upon the completion of this offering, the Contributing Parties, including affiliates of our Sponsors, will own common units, representing approximately % of our outstanding common units (or common units, representing approximately % of our outstanding common units if the underwriters exercise their option to purchase additional common units in full) (excluding any common units purchased by officers and directors of our general partner under our directed unit program) and would receive a pro rata percentage of the cash distributions that we distribute in respect thereof. | |
|
Payments to our Sponsors, our general partner and their respective affiliates |
We will reimburse our general partner and its affiliates for all direct and indirect expenses they incur and payments they make on our behalf. Our partnership agreement does not set a limit on the amount of expenses for which our general partner and its affiliates may be reimbursed. These expenses include salary, bonus, incentive compensation and other amounts paid to persons who perform services for us or on our behalf and expenses allocated to our general partner by its affiliates. Our partnership agreement provides that our general partner will determine the expenses that are allocable to us. In addition, we will enter into a management services agreement with Kimbell Operating, which will enter into separate service agreements with certain entities controlled by Messrs. Duncan, R. Ravnaas, Taylor and Wynne, pursuant to which they and Kimbell Operating will provide management, administrative and operational services to us. In addition, under each of their respective service agreements, Messrs. R. Ravnaas, Taylor and Wynne will identify, evaluate and recommend to us acquisition opportunities and negotiate the terms of such acquisitions. | |
|
Withdrawal or removal of our general partner |
If our general partner withdraws or is removed, its non-economic general partner interest will either be sold to the new general partner for cash or converted into common units, in each case for an amount equal to the fair market value of those interests. Please read "The Partnership Agreement—Withdrawal or Removal of Our General Partner." | |
|
Liquidation Stage |
||
|
Liquidation |
Upon our liquidation, our unitholders will be entitled to receive liquidating distributions according to their respective capital account balances. |
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Agreements and Transactions with Affiliates in Connection with this Offering
In connection with this offering, we have entered into and will enter into certain agreements and transactions with our Sponsors, the Contributing Parties and their respective affiliates, as described in more detail below. These agreements and transactions are not the result of arm's-length negotiations and they, or any of the transactions that they provide for, are not and may not be effected on terms at least as favorable to the parties to these agreements as could have been obtained from unaffiliated third parties. Because some of these agreements relate to formation transactions that, by their nature, would not occur in a third-party situation, it is not possible to determine what the differences would be in the terms of these transactions when compared to the terms of transactions with an unaffiliated third party. We believe the terms of these agreements to be comparable to the terms of agreements used in similarly structured transactions.
Contribution Agreement
In connection with this offering, we have entered into a contribution agreement with our Sponsors and the Contributing Parties that will effect the transfer of the mineral and royalty interests owned by the Contributing Parties to us and the use of the net proceeds of this offering, and also address the following matters:
- •
-
our right of first offer to acquire mineral and royalty interests owned by certain of the Contributing Parties for a period of three
years after the closing of this offering;
- •
-
our option to participate in certain acquisitions by the Contributing Parties of mineral and royalty interests;
- •
-
our Sponsors' and the Contributing Parties' registration rights with respect to the registration and sale of common units held by them
or their affiliates; and
- •
- the Contributing Parties' obligation to indemnify us for certain limited matters associated with the mineral and royalty interests and associated entities, and our obligation to indemnify the Contributing Parties for certain limited matters related to the mineral and royalty interests and associated entities to the extent they are not required to indemnify us.
Right of First Offer. Under the contribution agreement, if certain of the Contributing Parties decide to sell, transfer or otherwise dispose of certain mineral and royalty interests in the Permian Basin, the Bakken/Williston Basin and the Marcellus Shale, they will provide us with the opportunity to make the first offer on such assets. The right of first offer will have a three-year term from the closing of this offering. The consummation and timing of any acquisition by us of the interests covered by our right of first offer will depend upon, among other things, the Contributing Parties' decision to sell any of the assets covered by our right of first offer and our ability to reach an agreement with the Contributing Parties' on price and other terms. Accordingly, we can provide no assurance whether, when or on what terms we will be able to successfully consummate any future acquisitions pursuant to our right of first offer, and the Contributing Parties are under no obligation to accept any offer that we may choose to make.
Participation Right. Pursuant to the contribution agreement, we have a right to participate, at our option and on substantially the same or better terms, in up to 50% of any acquisitions, other than de minimis acquisitions, for which Messrs. R. Ravnaas, Taylor and Wynne provide,
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directly or indirectly, any oil and gas diligence, reserve engineering or other business services. Unless consented to in writing by our general partner on our behalf, the participation right shall be on terms and conditions substantially the same as or better than the acquisition by our Sponsors and the Contributing Parties. The participation right will last for so long as any of our Sponsors or their respective affiliates control our general partner.
Registration Rights. Pursuant to the contribution agreement, the Contributing Parties have specified demand and piggyback participation rights with respect to the registration and sale of common units held by them or their affiliates. At any time following the time when we are eligible to file a registration statement on Form S-3, each of our Sponsors has the right to cause us to prepare and file a registration statement on Form S-3 with the SEC covering the offering and sale of common units held by its affiliates. We are not obligated to effect more than one such demand registration in any 12-month period or two such demand registrations in the aggregate. If we propose to file a registration statement pursuant to a Sponsor's demand registration discussed above, the Contributing Parties may request to "piggyback" onto such registration statement in order to offer and sell common units held by them or their affiliates. We have agreed to pay all registration expenses in connection with such demand and piggyback registrations. Registration expenses do not include underwriters' compensation, stock transfer taxes or counsel fees. Please read "Units Eligible for Future Sale."
Indemnification. The Contributing Parties have made representations and warranties to us regarding their respective mineral and royalty interests and the associated entities. In addition, the Contributing Parties are, severally but not jointly, obligated to indemnify us for certain limited matters, including as follows:
- •
-
(i) For a period of one year following the closing of this offering, the Contributing Parties will indemnify us for breaches of
specified representations and warranties related to, among other things, (x) their authority to enter into the transactions contemplated by the contribution agreement and (y) the capitalization of the
entities that will be contributed to us; and (ii) for any federal, state and local income tax liabilities attributable to the ownership and operation of the mineral and royalty interests and
the associated entities prior to the closing of this offering until 30 days after the applicable statute of limitations. This indemnification obligation shall be capped at ten percent of the
net proceeds received by any such Contributing Party with respect to the entity or asset that is subject to such claim for indemnification. The Contributing Parties are not required to indemnify us
for breaches of any other representations and warranties under the contribution agreement, including breaches related to other title matters, consents and permits or compliance with environmental
laws, and such other representations and warranties shall not survive the closing of this offering.
- •
- In addition, the Contributing Parties will indemnify us for losses arising from certain liens and title defects created during their ownership of the entities and assets contributed to us in connection with this offering. This indemnification obligation shall be capped at the net proceeds received by any such Contributing Party with respect to the entity or asset that is subject to such claim for indemnification.
We have agreed to indemnify the Contributing Parties for breaches of our specified representation and warranties and for events and conditions associated with the ownership or operation of the mineral and royalty interests and the associated entities (other than any liabilities for which the Contributing Parties are specifically required to indemnify us as described above). Our indemnification obligation for breaches of specified representations and
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warranties shall be capped at ten percent of the aggregate net proceeds received by all of the Contributing Parties. Our indemnification obligation for all other liabilities shall be capped at the aggregate net proceeds received by all of the Contributing Parties.
Conditions Precedent. The obligation of the parties to the contribution agreement to proceed with the closing of the transactions contemplated by the contribution agreement is conditioned upon a minimum amount of gross proceeds to us from this offering and a minimum aggregate ownership of our outstanding common units by the Contributing Parties following this offering, as well as the satisfaction or waiver of certain other customary conditions.
Management Services Agreements
Management Services Agreement with Kimbell Operating
In connection with the closing of this offering, we will enter into a management services agreement with Kimbell Operating, pursuant to which Kimbell Operating will provide services to us via services provided by the Sponsor Managers and the Non-Sponsor Managers (each as defined below). The management services agreement with Kimbell Operating will be under terms and conditions similar to those described below in "—Service Agreement with Our Sponsors" and "—Other Service Agreements." Kimbell Operating will receive reimbursement for its expenses for providing such services to us, including expenses incurred pursuant to the service agreements with the Sponsor Managers and the Non-Sponsor Managers.
Service Agreements with Our Sponsors
Services. In connection with the closing of this offering, Kimbell Operating will enter into service agreements with Steward Royalties, LLC ("Steward Royalties"), Taylor Companies Mineral Management, LLC ("Taylor Companies") and K3 Royalties, LLC ("K3 Royalties" and together with Steward Royalties and Taylor Companies, the "Sponsor Managers"), which are entities controlled by Messrs. R. Ravnaas, Taylor and Wynne, respectively. Pursuant to these agreements, the Sponsor Managers will provide management, administrative and operational services to Kimbell Operating. In addition, the Sponsor Managers or their affiliates will provide acquisition services to us, including identifying, evaluating and recommending to us acquisition opportunities and any related negotiating of such opportunities. The services to be provided by each Sponsor Manager are as set forth below:
- •
-
Steward Royalties:
For all of our assets and the assets
of our affiliates, Steward Royalties will assist in sourcing, evaluating (including providing pricing guidance, reservoir engineering analysis, and geological work), and negotiating acquisition
opportunities for us; and provide ongoing petroleum engineering services.
- •
-
Taylor Companies:
- •
- Taylor Companies will assist in sourcing, evaluating (including directing all land and legal due diligence), and negotiating acquisition opportunities for us; assist in notifying and providing recorded transfer documents for newly acquired properties; assist in retaining outside legal counsel and landmen in connection with acquisition opportunities; maintain land and legal records with respect to newly acquired properties; and perform certain additional services with respect to newly acquired properties.
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- •
-
In addition, with respect to certain of our subsidiaries and assets, Taylor Companies will provide management services
including: negotiating and executing leases, right of way agreements, pooling orders and similar agreements and orders; providing certain recordkeeping services; resolving title issues; receiving and
disbursing royalty and other payments; and providing certain additional accounting, title, human resources, regulatory compliance and other services.
- •
- K3 Royalties: For all of our assets and the assets of our affiliates, K3 Royalties will assist in sourcing, evaluating and recommending acquisitions; and assist with business development, investor and public relations and relationship management between private side royalty investors and us.
The Sponsor Managers will have the exclusive right to provide the acquisition services listed above in connection with acquisitions by us, as well as the exclusive right to provide any additional management services reasonably required with respect to properties newly acquired by us.
Service Fees and Reimbursement. Under the service agreements with the Sponsor Managers, Kimbell Operating will initially pay to Steward Royalties, Taylor Companies and K3 Royalties a monthly services fee equal to $33,000, $33,000 and $10,000, respectively, which amounts represent an estimated allocation of all projected costs to be incurred by such Sponsor Manager in providing services to Kimbell Operating. Subject to the approval of the board of directors of our general partner, the monthly services fee shall be adjusted (i) annually, (ii) in the event of any sale of serviced properties or (iii) in the event of the provision of any additional management services (including with respect to acquisitions of new properties). In addition, Kimbell Operating is required to reimburse each Sponsor Manager for all other reasonable costs and expenses (including, but not limited to, third-party expenses and expenditures) that such Sponsor Manager incurs on behalf of Kimbell Operating in providing services. If Kimbell Operating terminates a service agreement for any reason other than the Sponsor Manager's default (as described below), then Kimbell Operating will also reimburse the applicable Sponsor Manager for its reasonable costs and expenses incurred in connection with such termination.
Term and Termination. The initial term of the service agreement with the Sponsor Managers will be five years, after which date they will continue on a year-to-year basis unless terminated by Kimbell Operating or by the applicable Sponsor Manager upon 90 days' notice, except as otherwise stated below:
- •
-
After the second anniversary of our initial public offering, the applicable Sponsor Manager may terminate its service agreement, or
the provision of any service thereunder, upon at least 180 days' notice to Kimbell Operating.
- •
-
The applicable Sponsor Manager may terminate its service agreement upon a default by Kimbell Operating, which includes
(i) Kimbell Operating's failure to perform any of its material obligations under the agreement, where such default continues unremedied for a period of 15 days after notice thereof, and
(ii) the occurrence of certain events relating to the bankruptcy or insolvency of Kimbell Operating.
- •
- Kimbell Operating may terminate a service agreement upon a default by the applicable Sponsor Manager, upon 15 days' notice to such Sponsor Manager. A Sponsor Manager is in default upon the occurrence of any gross negligence or willful misconduct of such Sponsor Manager in performing services under its service agreement, which results in
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- •
- Kimbell Operating or the Sponsor Manager may terminate the applicable service agreement if, at any time, the Sponsors or their affiliates no longer control our general partner, upon at least 90 days' notice to the other party.
material harm to us and our affiliates, including Kimbell Operating (the "Partnership Service Group").
Kimbell Operating's only remedy for a Sponsor Manager's default under its service agreement is the termination of the applicable agreement as described in the third bullet point above.
Indemnification. Under the service agreements with the Sponsor Managers, Kimbell Operating will agree to indemnify each Sponsor Manager, its affiliates and any of their respective employees, officers, directors and agents from and against all liability, demands, claims, actions or causes of action, assessments, losses, damages, costs and expenses (including legal fees) resulting from or arising out of (i) any material breach by Kimbell Operating of the applicable service agreement or (ii) the personal injury, death, property damage or liability of any member of the Partnership Service Group, any third party or any of their respective employees, officers, directors and agents arising from, connected with or under the applicable service agreement. The Sponsor Managers do not have corresponding indemnification obligations with respect to Kimbell Operating.
Other Service Agreements
Management Services. In connection with the closing of this offering, Kimbell Operating will enter into service agreements with Nail Bay Royalties, LLC ("Nail Bay Royalties") and Duncan Management, LLC ("Duncan Management" and together with Nail Bay Royalties, the "Non-Sponsor Managers"), which are entities controlled by Mr. Duncan. Pursuant to these agreements, the Non-Sponsor Managers will provide management, administrative and operational services to Kimbell Operating. These services include, with respect to the serviced properties: negotiating and executing leases, right of way agreements, pooling orders and similar agreements and orders; providing certain recordkeeping services; resolving title issues; collecting and disbursing payments and rendering related audit, accounting and bookkeeping services; monitoring drilling and production activities; assisting in preparing certain federal and state tax forms; and providing certain additional accounting, title, human resources, regulatory compliance and other services.
Service Fees and Reimbursement. Under the service agreements with the Non-Sponsor Managers, Kimbell Operating will initially pay to Nail Bay Royalties and Duncan Management a monthly services fee of approximately $41,960 and $54,870, respectively, which amounts represent an estimated allocation of all projected costs to be incurred by such Non-Sponsor Manager in providing services to Kimbell Operating. Subject to the approval of the board of directors of our general partner, the monthly services fee shall be adjusted (i) annually, (ii) in the event of any sale of serviced properties or (iii) in the event of the provision of any additional services by the Non-Sponsor Manager. In addition, Kimbell Operating is required to reimburse each Non-Sponsor Manager for all other reasonable costs and expenses (including, but not limited to, third-party expenses and expenditures) that such Non-Sponsor Manager incurs on behalf of Kimbell Operating in providing services. If Kimbell Operating terminates a service agreement for any reason other than the Non-Sponsor Manager's default (as described below), then Kimbell Operating will also reimburse the applicable Non-Sponsor Manager for its reasonable costs and expenses incurred in connection with such termination.
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Term and Termination. The initial term of the service agreements with the Non-Sponsor Managers will be five years, after which date they will continue on a year-to-year basis unless terminated by us or by the applicable Non-Sponsor Manager upon 90 days' notice, except as otherwise stated below:
- •
-
After the second anniversary of our initial public offering, the applicable Non-Sponsor Manager may terminate its service agreement,
or the provision of any service thereunder, upon at least 180 days' notice to Kimbell Operating.
- •
-
The applicable Non-Sponsor Manager may terminate its service agreement upon a default by Kimbell Operating, which includes
(i) Kimbell Operating's failure to perform any of its material obligations under the agreement, where such default continues unremedied for a period of 15 days after notice thereof, and
(ii) the occurrence of certain events relating to the bankruptcy or insolvency of Kimbell Operating.
- •
-
Kimbell Operating may terminate a service agreement upon a default by the applicable Non-Sponsor Manager, upon 15 days' notice
to such Non-Sponsor Manager. A Non-Sponsor Manager is in default upon the occurrence of any gross negligence or willful misconduct of such Sponsor Manager in performing services under its service
agreement, which results in material harm to any member of the Partnership Service Group.
- •
- Kimbell Operating or the Non-Sponsor Manager may terminate the applicable service agreement upon the sale of all or substantially all of the properties serviced thereunder, upon at least 90 days' notice to the other party.
Kimbell Operating's only remedy for a Non-Sponsor Manager's default under its service agreement is the termination of the applicable agreement as described in the third bullet point above.
Indemnification. Under the service agreements with the Non-Sponsor Managers, Kimbell Operating will agree to indemnify each Non-Sponsor Manager, its affiliates and any of their respective employees, officers, directors and agents from and against all liability, demands, claims, actions or causes of action, assessments, losses, damages, costs and expenses (including legal fees) resulting from or arising out of (i) any material breach by Kimbell Operating of the applicable service agreement or (ii) the personal injury, death, property damage or liability of any member of the Partnership Service Group, any third party or any of their respective employees, officers, directors and agents arising from, connected with or under the applicable service agreement. The Non-Sponsor Managers do not have corresponding indemnification obligations with respect to Kimbell Operating.
Limited Liability Company Agreement of Kimbell Holdings
In connection with the closing of this offering, our Sponsors will enter into the limited liability company agreement of Kimbell Holdings. Kimbell Holdings will be the sole member of our general partner. Pursuant to Kimbell Holdings' limited liability company agreement, for so long as Messrs. Fortson, R. Ravnaas, Taylor and Wynne (or their designated successors) serve as directors of Kimbell Holdings, such persons will also serve as directors of our general partner. The right of each of Messrs. Fortson, R. Ravnaas, Taylor and Wynne (and their designated successors) to serve as a director of our general partner is conditioned upon the applicable person not competing with us, our general partner, and our and its respective subsidiaries.
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Procedures for Review, Approval and Ratification of Transactions with Related Persons
We expect that the board of directors of our general partner will adopt policies for the review, approval and ratification of transactions with related persons. We anticipate the board will adopt a written code of business conduct and ethics, under which a director would be expected to bring to the attention of our chief executive officer or the board any conflict or potential conflict of interest that may arise between the director or any affiliate of the director, on the one hand, and us or our general partner on the other. The resolution of any conflict or potential conflict should, at the discretion of the board in light of the circumstances, be determined by a majority of the disinterested directors.
If a conflict or potential conflict of interest arises between our general partner or its affiliates, including our Sponsors or their respective affiliates, on the one hand, and us or our unitholders, on the other hand, the resolution of any such conflict or potential conflict should be addressed by the board of directors of our general partner in accordance with the provisions of our partnership agreement. At the discretion of the board in light of the circumstances, the resolution may be determined by the board in its entirety or by the conflicts committee.
Upon our adoption of our code of business conduct and ethics, we would expect that any executive officer will be required to avoid conflicts of interest unless approved by the board of directors of our general partner.
Please read "Conflicts of Interest and Duties—Conflicts of Interest" for additional information regarding the relevant provisions of our partnership agreement.
The code of business conduct and ethics described above will be adopted in connection with the closing of this offering, and as a result, the transactions described above were not reviewed according to such procedures.
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CONFLICTS OF INTEREST AND DUTIES
Conflicts of interest exist and may arise in the future as a result of the relationships between our general partner and its affiliates, including our Sponsors and their respective affiliates, on the one hand, and us and our unaffiliated limited partners, on the other hand. Conflicts may arise under any of the agreements between us and our Sponsors, the Contributing Parties and their respective affiliates. The directors and officers of our general partner have fiduciary duties to manage our general partner in a manner that is beneficial to Kimbell Holdings and its parents, our Sponsors. At the same time, our general partner has a duty to manage us in a manner that is in, or not adverse to, the best interests of our partnership. The Delaware Act provides that Delaware limited partnerships may, in their partnership agreements, expand, restrict or eliminate the fiduciary duties otherwise owed by a general partner to limited partners and the partnership. Pursuant to these provisions, our partnership agreement contains various provisions replacing the fiduciary duties that would otherwise be owed by our general partner with contractual standards governing the duties of our general partner and the methods of resolving conflicts of interest. Our partnership agreement also specifically defines the remedies available to limited partners for actions taken that, without these defined liability standards, might constitute breaches of fiduciary duty under applicable Delaware law.
Whenever a conflict arises between our general partner or its affiliates, including our Sponsors or their respective affiliates, on the one hand, and us or any other partner, on the other hand, our general partner will resolve that conflict. Our general partner may seek the approval of such resolution from the conflicts committee of the board of directors of our general partner or from our unitholders. There is no requirement under our partnership agreement that our general partner seek the approval of the conflicts committee or our unitholders for the resolution of any conflict, and, under our partnership agreement, our general partner may decide to seek such approval or resolve a conflict of interest in any other way permitted by our partnership agreement, as described below, in its sole discretion. Our general partner will decide whether to refer the matter to the conflicts committee or our unitholders on a case-by-case basis. An independent third party is not required to evaluate the fairness of the resolution. In determining whether to refer a matter to the conflicts committee or to our unitholders for approval, our general partner may consider a variety of factors, including the nature of the conflict, the size and dollar amount involved, the identity of the parties involved and any other factors the board of directors deems relevant in determining whether it will seek approval from the conflicts committee or our unitholders. Whenever our general partner makes a determination to refer or not to refer any potential conflict of interest to the conflicts committee for approval or to seek or not to seek unitholder approval, our general partner is acting in its individual capacity, which means that it may act free of any duty or obligation whatsoever to us or our unitholders and will not be required to act in good faith or pursuant to any other standard or duty imposed by our partnership agreement or under applicable law, other than the implied contractual covenant of good faith and fair dealing. For a more detailed discussion of the duties applicable to our general partner, as well as the implied contractual covenant of good faith and fair dealing, please read "—Duties of Our General Partner."
Our general partner will not be in breach of its obligations under our partnership agreement or its duties to us or our limited partners if the resolution of the conflict is:
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- approved by the conflicts committee, which our partnership agreement defines as "special approval";
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approved by the vote of a majority of the outstanding common units, excluding any common units owned by our general partner or any of
its affiliates;
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determined by the board of directors of our general partner to be on terms no less favorable to us than those generally being provided
to or available from third parties; or
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- determined by the board of directors of our general partner to be fair and reasonable to us, taking into account the totality of the relationships between the parties involved, including other transactions that may be particularly favorable or advantageous to us.
If our general partner seeks approval from the conflicts committee, then it will be presumed that, in making its decision, the conflicts committee acted in good faith, and in any proceeding brought by or on behalf of any limited partner or the partnership challenging such determination, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption. If our general partner does not seek approval from the conflicts committee or our unitholders and our general partner's board of directors determines that the resolution or course of action taken with respect to the conflict of interest satisfies either of the standards set forth in the third and fourth bullet points above, then it will be presumed that, in making its decision, the board of directors of our general partner acted in good faith, and in any proceeding brought by or on behalf of any limited partner or the partnership challenging such determination, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption. Unless the resolution of a conflict is specifically provided for in our partnership agreement, our general partner or the conflicts committee of our general partner's board of directors may consider any factors it determines in good faith to consider when resolving a conflict. When our partnership agreement requires someone to act in good faith, it requires that person to subjectively believe that he is acting in a manner that is in, or not adverse to, the best interests of the partnership or that the determination to take or not to take action meets the specified standard, for example, a transaction on terms no less favorable to the us than those generally being provided to or available from third parties, or is "fair and reasonable" to us. In taking such action, such person may take into account the totality of the circumstances or the totality of the relationships between the parties involved, including other relationships or transactions that may be particularly favorable or advantageous to us. If that person has the required subjective belief, then the decision or action will be conclusively deemed to be in good faith for all purposes under our partnership agreement. Please read "Management—Committees of the Board of Directors—Conflicts Committee" for information about the conflicts committee of our general partner's board of directors.
Conflicts of interest could arise in the situations described below, among others.
Neither our partnership agreement nor any other agreement requires our Sponsors and the Contributing Parties to pursue a business strategy that favors us or utilizes our assets (subject to the non-competition provision of the limited liability company agreement of Kimbell Holdings). The directors and officers of our Sponsors and the Contributing Parties have a fiduciary duty to make these decisions in a manner beneficial to our Sponsors and the Contributing Parties, which may be contrary to our interests.
Because some of the officers and directors of our general partner are also officers or directors of our Sponsors and the Contributing Parties, such directors and officers have fiduciary duties to our Sponsors and such Contributing Parties that may cause them to pursue business strategies that disproportionately benefit our Sponsors and such Contributing Parties or which otherwise are not in our best interests.
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Agreements between us, on the one hand, and our general partner and its affiliates, on the other hand, are not and will not be the result of arm's-length negotiations.
Neither our partnership agreement nor any of the other agreements, contracts and arrangements between us and our general partner and its affiliates, including our Sponsors and their respective affiliates, are or will be the result of arm's-length negotiations. Our partnership agreement generally provides that any affiliated transaction, such as an agreement, contract or arrangement between us and our general partner and its affiliates that does not receive unitholder or conflicts committee approval, must be determined by the board of directors of our general partner to be:
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on terms no less favorable to us than those generally being provided to or available from third parties; or
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- "fair and reasonable" to us, taking into account the totality of the relationships between the parties involved, including other transactions that may be particularly favorable or advantageous to us.
Our general partner and its affiliates have no obligation to permit us to use any facilities or assets of our general partner and its affiliates, except as may be provided in agreements entered into specifically dealing with that use. Our general partner may also enter into additional contractual arrangements with any of its affiliates on our behalf. There is no obligation of our general partner and its affiliates to enter into any contracts of this kind.
Our general partner's affiliates and the Contributing Parties may compete with us and, except in certain limited circumstances, neither our general partner nor its affiliates or the Contributing Parties have any obligation to present business opportunities to us.
Our partnership agreement provides that our general partner is restricted from engaging in any business activities other than those incidental to its ownership of interests in us. However, affiliates of our general partner are not prohibited from engaging in other businesses or activities, including those that might directly compete with us (subject to the non-competition provision of the limited liability company agreement of Kimbell Holdings). In addition, under our partnership agreement, the doctrine of corporate opportunity, or any analogous doctrine, will not apply to our general partner and its affiliates (including our officers and directors who are also officers and directors of our Sponsors and their respective affiliates, or the Contributing Parties).
Similarly, our partnership agreement does not limit our Sponsors' or their respective affiliates' ability to compete with us and, subject to the 50% participation right included in the contribution agreement that we have entered into with our Sponsors and the Contributing Parties, neither our Sponsors nor the Contributing Parties have any obligation to present business opportunities to us. Pursuant to the limited liability company agreement of Kimbell Holdings, the right of each of Messrs. Fortson, R. Ravnaas, Taylor and Wynne (and their designated successors) to serve as a director of our general partner is conditioned upon the applicable person not competing with us, our general partner, and our and its respective subsidiaries. In addition, certain of the Contributing Parties have granted us a right of first offer for a period of three years after the closing of this offering with respect to certain mineral and royalty interests in the Permian Basin, the Bakken/Williston Basin and the Marcellus Shale. Except as described above, neither our general partner nor any of its affiliates have any obligation to present business opportunities to us.
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Our general partner is allowed to take into account the interests of parties other than us, such as our Sponsors and the Contributing Parties, in resolving conflicts of interest.
Our partnership agreement contains provisions that permissibly modify and reduce the standards to which our general partner would otherwise be held by state fiduciary duty law. For example, our partnership agreement permits our general partner to make a number of decisions in its individual capacity, as opposed to in its capacity as our general partner or otherwise, free of any duty or obligation whatsoever to us and our unitholders, including any duty to act in a manner it subjectively believes is in, or not adverse to, the best interests of us or our unitholders, other than the implied contractual covenant of good faith and fair dealing, which means that a court will enforce the reasonable expectations of the partners where the language in our partnership agreement does not provide for a clear course of action. This entitles our general partner to consider only the interests and factors that it desires and relieves it of any duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or any limited partner. Examples of decisions that our general partner may make in its individual capacity include the allocation of corporate opportunities among us and our affiliates, the exercise of its limited call right or its voting rights with respect to the units it owns and whether or not to consent to any merger, consolidation or conversion of the partnership or amendment to our partnership agreement.
Neither we, our general partner nor our subsidiaries have any employees, and we rely solely on Kimbell Operating to manage and operate, or arrange for the management and operation of, our business. The management team of Kimbell Operating, which includes the individuals who will manage us, will also provide substantially similar services to other entities, and thus will not be solely focused on our business.
Neither we, our general partner nor our subsidiaries have any employees, and we rely solely on Kimbell Operating to manage us and operate our business. In connection with this offering, we will enter into a management services agreement with Kimbell Operating, which will enter into separate service agreements with certain entities controlled by Messrs. Duncan, R. Ravnaas, Taylor and Wynne, pursuant to which they and Kimbell Operating will provide management, administrative and operational services to us.
Kimbell Operating will also continue to provide substantially similar services and personnel to other entities and, as a result, may not have sufficient human, technical and other resources to provide those services at a level that it would be able to provide to us if it did not provide similar services to these other entities. Additionally, Kimbell Operating may make internal decisions on how to allocate its available resources and expertise that may not always be in our best interest compared to those of the other entities or other affiliates of our general partner. There is no requirement that Kimbell Operating favor us over these other entities in providing its services. If the employees of Kimbell Operating do not devote sufficient attention to the management and operation of our business, our financial results may suffer and our ability to make distributions to our unitholders may be reduced.
Our partnership agreement replaces the fiduciary duties that would otherwise be owed by our general partner with contractual standards governing its duties and limits our general partner's liabilities and the remedies available to our unitholders for actions that, without the limitations, might constitute breaches of fiduciary duty under applicable Delaware law.
In addition to the provisions described above, our partnership agreement contains provisions that restrict the remedies available to our limited partners for actions that might constitute
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breaches of fiduciary duty under applicable Delaware law. For example, our partnership agreement:
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permits our general partner to make a number of decisions in its individual capacity, as opposed to in its capacity as our general
partner. This entitles our general partner to consider only the interests and factors that it desires, and it has no duty or obligation to give any consideration to any interest of, or factors
affecting, us, our affiliates or any limited partner;
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provides that our general partner shall not have any liability to us or our limited partners for decisions made in its capacity so
long as such decisions are made in good faith;
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generally provides that in a situation involving a transaction with an affiliate or a conflict of interest, any determination by our
general partner must be made in good faith. If an affiliate transaction or the resolution of a conflict of interest is not approved by our public common unitholders or the conflicts committee and the
board of directors of our general partner determines that the resolution or course of action taken with respect to the affiliate transaction or conflict of interest is either on terms no less
favorable to us than those generally being provided to or available from third parties or is "fair and reasonable" to us, considering the totality of the relationships between the parties involved,
including other transactions that may be particularly advantageous or beneficial to us, then it will be presumed that in making its decision, the board of directors of our general partner acted in
good faith, and in any proceeding brought by or on behalf of any limited partner or us challenging such decision, the person bringing or prosecuting such proceeding will have the burden of overcoming
such presumption; and
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- provides that our general partner and its officers and directors will not be liable for monetary damages to us or our limited partners resulting from any act or omission unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that our general partner or its officers or directors, as the cases may be, acted in bad faith or engaged in fraud or willful misconduct or, in the case of a criminal matter, acted with knowledge that the conduct was unlawful.
By purchasing a common unit, a common unitholder will be deemed to have agreed to become bound by the provisions in our partnership agreement, including the provisions discussed above.
Except in limited circumstances, our general partner has the power and authority to conduct our business without unitholder approval.
Under our partnership agreement, our general partner has full power and authority to do all things, other than those items that require unitholder approval, on such terms as it determines to be necessary or appropriate to conduct our business including, but not limited to, the following:
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- the making of any expenditures, the lending or borrowing of money, the assumption or guarantee of, or other contracting for, indebtedness and other liabilities, the issuance of evidences of indebtedness, including indebtedness that is convertible into or exchangeable for equity interests of the partnership, and the incurring of any other obligations;
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the making of tax, regulatory and other filings, or rendering of periodic or other reports to governmental or other agencies having
jurisdiction over our business or assets;
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the acquisition, disposition, mortgage, pledge, encumbrance, hypothecation or exchange of any or all of our assets or the merger or
other combination of us with or into another person;
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the negotiation, execution and performance of any contracts, conveyances or other instruments;
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the distribution of cash held by the partnership;
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the selection and dismissal of employees and agents, outside attorneys, accountants, consultants and contractors and the determination
of their compensation and other terms of employment or hiring;
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the maintenance of insurance for our benefit and the benefit of our partners and indemnitees;
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the formation of, or acquisition of an interest in, and the contribution of property and the making of loans to, any further limited
or general partnerships, joint ventures, corporations, limited liability companies or other entities;
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the making of all such rules and regulations as it may deem expedient concerning the issue, transfer and registration or replacement
of certificates;
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the control of any matters affecting our rights and obligations, including the bringing and defending of actions at law or in equity
and otherwise engaging in the conduct of litigation, arbitration or mediation and the incurring of legal expense and the settlement of claims and litigation;
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the indemnification of any person against liabilities and contingencies to the extent permitted by law;
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the purchase, sale or other acquisition or disposition of our equity interests, or the issuance of additional options, rights,
warrants and appreciation rights relating to our equity interests; and
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- the entering into of agreements with any of its affiliates to render services to us or to itself in the discharge of its duties as our general partner.
Please read "The Partnership Agreement—Voting Rights" for information regarding the voting rights of unitholders.
Our general partner determines which of the costs it incurs on our behalf are reimbursable by us.
We will reimburse our general partner and its affiliates for the costs incurred in managing and operating us, including costs incurred in rendering corporate staff and support services to us. Our partnership agreement provides that our general partner will determine such other expenses that are allocable to us, and the partnership agreement does not limit the amount of
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expenses for which our general partner and its affiliates may be reimbursed. Please read "The Partnership Agreement—Reimbursement of Expenses."
Our general partner intends to limit its liability regarding our obligations.
Our general partner intends to limit its liability under contractual arrangements so that the other party to such agreements has recourse only against our assets and not against our general partner or its assets or any affiliate of our general partner or its assets. Our partnership agreement permits our general partner to limit its or our liability, even if we could have obtained terms that are more favorable without the limitation on liability.
Common units are subject to our general partner's limited call right.
Our general partner may exercise its right to call and purchase common units as provided in our partnership agreement or assign this right to one of its affiliates or to us free of any liability or obligation to us or our partners. As a result, a common unitholder may have his common units purchased from him at an undesirable time or price. Please read "The Partnership Agreement—Limited Call Right."
Limited partners have no right to enforce obligations of our general partner and its affiliates under agreements with us.
Any agreements between us, on the one hand, and our general partner and its affiliates, on the other, will not grant to the limited partners, separate and apart from us, the right to enforce the obligations of our general partner and its affiliates in our favor.
Our general partner decides whether to retain separate counsel, accountants or others to perform services for us.
The attorneys, independent accountants and others who perform services for us will be retained by our general partner. Attorneys, independent accountants and others who perform services for us are selected by our general partner or the conflicts committee and may also perform services for our general partner and its affiliates. We may retain separate counsel for ourselves or the holders of common units in the event of a conflict of interest between our general partner and its affiliates, on the one hand, and us or the holders of common units, on the other, depending on the nature of the conflict. We do not intend to do so in most cases.
The Delaware Act provides that Delaware limited partnerships may, in their partnership agreements, expand, restrict or eliminate the fiduciary duties otherwise owed by a general partner to limited partners and the partnership, provided that partnership agreements may not eliminate the implied contractual covenant of good faith and fair dealing. This implied covenant is a judicial doctrine utilized by Delaware courts in connection with interpreting ambiguities in partnership agreements and other contracts and does not form the basis of any separate or independent fiduciary duty in addition to the express contractual duties set forth in our partnership agreement. Under the implied contractual covenant of good faith and fair dealing, a court will enforce the reasonable expectations of the partners where the language in our partnership agreement does not provide for a clear course of action.
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As permitted by the Delaware Act, our partnership agreement contains various provisions replacing the fiduciary duties that would otherwise be owed by our general partner with contractual standards governing the duties of our general partner and the methods of resolving conflicts of interest. We have adopted these provisions to allow our general partner or its affiliates to engage in transactions with us that otherwise might be prohibited or restricted by state-law fiduciary standards and to take into account the interests of other parties in addition to our interests when resolving conflicts of interest. We believe this is appropriate and necessary because the board of directors of our general partner has fiduciary duties to manage our general partner in a manner that is beneficial to Kimbell Holdings and its parents, our Sponsors. Without these provisions, our general partner's ability to make decisions involving conflicts of interest would be restricted.
These provisions enable our general partner to take into consideration the interests of all parties involved in the proposed action. These provisions also strengthen the ability of our general partner to attract and retain experienced and capable directors. These provisions disadvantage the limited partners because they restrict the remedies available to limited partners for actions that, without those provisions, might constitute breaches of fiduciary duty, as described below and permit our general partner to take into account the interests of third parties in addition to our interests when resolving conflicts of interest. The following is a summary of:
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the fiduciary duties imposed on general partners of a limited partnership by the Delaware Act in the absence of partnership agreement
provisions to the contrary;
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the contractual duties of our general partner contained in our partnership agreement that replace the fiduciary duties referenced in
the preceding bullet that would otherwise be imposed by Delaware law on our general partner; and
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- certain rights and remedies of our limited partners contained in our partnership agreement and the Delaware Act.
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Delaware law fiduciary duty standards |
Fiduciary duties are generally considered to include an obligation to act in good faith and with due care and loyalty. The duty of care, in the absence of a provision in a partnership agreement providing otherwise, would generally require a general partner of a Delaware limited partnership to use that amount of care that an ordinarily careful and prudent person would use in similar circumstances and to consider all material information reasonably available in making business decisions. The duty of loyalty, in the absence of a provision in a partnership agreement providing otherwise, would generally prohibit a general partner of a Delaware limited partnership from taking any action or engaging in any transaction where a conflict of interest is present unless such transaction were entirely fair to the partnership. Our partnership agreement modifies these standards as described below. |
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Partnership agreement contractual standards |
Our partnership agreement contains provisions that waive or consent to conduct by our general partner and its affiliates (including its directors and officers) that might otherwise raise issues as to compliance with fiduciary duties or applicable
law. For example, our partnership agreement provides that when our general partner is acting in its capacity as our general partner, as opposed to in its individual capacity, it must act in "good faith," meaning that it subjectively believed that the
decision was in, or not adverse, to our best interests, and our general partner will not be subject to any other standard under our partnership agreement or applicable law, other than the implied contractual covenant of good faith and fair dealing.
If our general partner has the required subjective belief, then the decision or action will be conclusively deemed to be in good faith for all purposes under our partnership agreement. In taking such action, our general partner may take into account
the totality of the circumstances or the totality of the relationships between the parties involved, including other relationships or transactions that may be particularly favorable or advantageous to us. In addition, when our general partner is
acting in its individual capacity, as opposed to in its capacity as our general partner, it may act free of any duty or obligation whatsoever to us or our limited partners, other than the implied contractual covenant of good faith and fair dealing.
These standards reduce the obligations to which our general partner would otherwise be held under applicable Delaware law.
Our partnership agreement generally provides that affiliated transactions and resolutions of conflicts of interest not approved by the public common unitholders or the conflicts committee of the board of directors of our general partner must be determined by the board of directors of our general partner to be: • on terms no less favorable to us than those generally being provided to or available from third parties; or • fair and reasonable to us, taking into account the totality of the relationships between the parties involved, including other transactions that may be particularly favorable or advantageous to us. |
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If our general partner seeks approval from the conflicts committee, then it will be presumed that, in making its decision, the conflicts committee acted in good faith, and in any proceeding brought by or on behalf of any limited partner or the partnership challenging such determination, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption. If our general partner does not seek approval from the public common unitholders or the conflicts committee and the board of directors of our general partner determines that the resolution or course of action taken with respect to the conflict of interest satisfies either of the standards set forth in the bullet points above, then it will be presumed that, in making its decision, the board of directors of our general partner acted in good faith, and in any proceeding brought by or on behalf of any limited partner or the partnership challenging such determination, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption. These standards reduce the obligations to which our general partner would otherwise be held. In addition to the other more specific provisions limiting the obligations of our general partner, our partnership agreement further provides that our general partner, its affiliates and their officers and directors will not be liable for monetary damages to us or, our limited partners for losses sustained or liabilities incurred as a result of any acts or omissions unless there has been a final and non-appealable judgment by a court of competent jurisdiction determining that such person acted in bad faith or engaged in fraud or willful misconduct or, in the case of a criminal matter, acted with knowledge that the conduct was unlawful. |
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Rights and remedies of limited partners |
The Delaware Act favors the principles of freedom of contract and enforceability of partnership agreements and allows our partnership agreement to contain terms governing the rights of our unitholders. The rights of our unitholders, including voting and approval rights and the ability of the partnership to issue additional units, are governed by the terms of our partnership agreement. Please read "The Partnership Agreement." As to remedies of unitholders, the Delaware Act generally provides that a limited partner may institute legal action on behalf of the partnership to recover damages from a third party where a general partner has wrongfully refused to institute the action or where an effort to cause a general partner to do so is not likely to succeed. These actions include actions against a general partner for breach of its fiduciary duties, if any, or of our partnership agreement. In addition, the statutory or case law of some jurisdictions may permit a limited partner to institute legal action on behalf of himself and all other similarly situated limited partners to recover damages from a general partner for violations of its fiduciary duties to the limited partners. |
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By purchasing our common units, each common unitholder will be deemed to have agreed to be bound by the provisions in our partnership agreement, including the provisions discussed above. Please read "Description of Our Common Units—Transfer of Common Units." This is in accordance with the policy of the Delaware Act favoring the principle of freedom of contract and the enforceability of partnership agreements. The failure of a limited partner to sign our partnership agreement does not render our partnership agreement unenforceable against that person.
Under our partnership agreement, we must indemnify our general partner and its officers, directors and managers, to the fullest extent permitted by law, against liabilities, costs and expenses incurred by our general partner or these other persons. We must provide this indemnification, and advance expenses, unless there has been a final and non-appealable judgment by a court of competent jurisdiction determining that our general partner or these persons acted in bad faith or engaged in fraud or willful misconduct. We also must provide this indemnification for criminal proceedings unless our general partner or these other persons acted with knowledge that their conduct was unlawful. Thus, our general partner could be indemnified for its negligent acts if it meets the requirements set forth above. To the extent that these provisions purport to include indemnification for liabilities arising under the U.S. federal securities laws, in the opinion of the SEC such indemnification is contrary to public policy and therefore unenforceable. Please read "The Partnership Agreement—Indemnification."
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DESCRIPTION OF OUR COMMON UNITS
The common units offered hereby represent limited partner interests in us. The holders of common units are entitled to participate in partnership distributions and exercise the rights and privileges provided to limited partners under our partnership agreement. For a description of the relative rights and privileges of holders of our common units to partnership distributions, please read "How We Pay Distributions." For a description of the rights and privileges of limited partners under our partnership agreement, including voting rights, please read "The Partnership Agreement."
Duties
American Stock Transfer & Trust Company, LLC will serve as transfer agent and registrar for our common units. We pay all fees charged by the transfer agent for transfers of common units, except the following, which must be paid by unitholders:
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surety bond premiums to replace lost or stolen certificates, taxes and other governmental charges;
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special charges for services requested by a holder of a common unit; and
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- other similar fees or charges.
There is no charge to our unitholders for disbursements of our quarterly cash distributions. We will indemnify the transfer agent, its agents and each of their stockholders, directors, officers and employees against all claims and losses that may arise out of acts performed or omitted for its activities in that capacity, except for any liability due to any gross negligence or intentional misconduct of the indemnified person or entity.
Resignation or Removal
The transfer agent may resign, by notice to us, or be removed by us. The resignation or removal of the transfer agent will become effective upon our appointment of a successor transfer agent and registrar and its acceptance of the appointment. If a successor has not been appointed or has not accepted its appointment within 30 days after notice of the resignation or removal, our general partner may act as the transfer agent and registrar until a successor is appointed.
By transfer of common units in accordance with our partnership agreement, each transferee of common units shall be admitted as a limited partner with respect to our common units transferred when such transfer and admission are reflected in our books and records. Each transferee:
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- represents that the transferee has the capacity, power and authority to become bound by our partnership agreement;
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automatically agrees to be bound by the terms and conditions of, and is deemed to have executed, our partnership agreement; and
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- gives the consents and approvals contained in our partnership agreement, such as the approval of all transactions and agreements entered into in connection with our formation and this offering.
A transferee will become a substituted limited partner of our partnership for the transferred common units automatically upon the recording of the transfer on our books and records. Our general partner will cause any transfers to be recorded on our books and records from time to time as necessary to accurately reflect the transfers.
We may, at our discretion, treat the nominee holder of a common unit as the absolute owner. In that case, the beneficial holder's rights are limited solely to those that it has against the nominee holder as a result of any agreement between the beneficial owner and the nominee holder.
Common units are securities and are transferable according to the laws governing transfer of securities. In addition to other rights acquired upon transfer, the transferor gives the transferee the right to become a limited partner in our partnership for the transferred common units.
Until a common unit has been transferred on our books, we and the transfer agent may treat the record holder of the common unit as the absolute owner for all purposes, except as otherwise required by law or stock exchange regulations.
We have been approved to list our common units on the NYSE, subject to official notice of issuance, under the symbol "KRP."
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The following is a summary of the material provisions of our partnership agreement, which we will adopt in connection with the closing of this offering. We also summarize certain material provisions of the limited liability company agreement of our general partner. The form of our partnership agreement is included in this prospectus as Appendix A. We will provide investors and prospective investors with a copy of our partnership agreement, when available, upon request at no charge.
We summarize the following provisions of our partnership agreement elsewhere in this prospectus:
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with regard to distributions of cash, please read "How We Pay Distributions";
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with regard to the duties of our general partner, please read "Conflicts of Interest and Duties";
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with regard to the transfer of common units, please read "Description of Our Common Units—Transfer of Common Units"; and
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- with regard to allocations of taxable income and taxable loss, please read "Material U.S. Federal Income Tax Consequences."
We were organized in October 2015 and will have a perpetual existence unless terminated pursuant to the terms of our partnership agreement.
Our purpose, as set forth in our partnership agreement, is limited to any business activity that is approved by our general partner and that lawfully may be conducted by a limited partnership organized under Delaware law; provided that our general partner shall not cause us to engage, directly or indirectly, in any business activity that our general partner determines would be reasonably likely to cause us to be treated as an association taxable as a corporation or otherwise taxable as an entity for federal income tax purposes.
Although our general partner has the ability to cause us and our subsidiaries to engage in activities other than our current activities, our general partner may decline to do so free of any duty or obligation whatsoever to us or the limited partners, including any duty to act in the best interests of us or our limited partners, other than the implied contractual covenant of good faith and fair dealing. Our general partner is generally authorized to perform all acts it determines to be necessary or appropriate to carry out our purposes and to conduct our business.
Our partnership agreement specifies the manner in which we will pay distributions to holders of our common units. For a description of these distributions, please read "How We Pay Distributions."
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Unitholders are not obligated to make additional capital contributions, except as described below under "—Limited Liability."
Adjustments to Capital Accounts Upon Issuance of Additional Common Units
We will make adjustments to capital accounts upon the issuance of additional common units. In doing so, we will generally allocate any unrealized and, for tax purposes, unrecognized gain or loss resulting from the adjustments to our unitholders prior to such issuance on a pro rata basis, so that after such issuance, the capital account balances attributable to all common units are equal.
The following is a summary of the unitholder vote required for approval of the matters specified below. Matters that call for the approval of a "unit majority" require the approval of a majority of the outstanding common units.
In voting their common units, our general partner and its affiliates will have no duty or obligation whatsoever to us or the limited partners, including any duty to act in the best interests of us or the limited partners, other than the implied covenant of good faith and fair dealing. The holders of a majority of our common units (including common units deemed owned by our general partner) represented in person or by proxy shall constitute a quorum at a meeting of such common unitholders, unless any such action requires approval by holders of a greater percentage of such units in which case the quorum shall be such greater percentage.
The following is a summary of the vote requirements specified for certain matters under our partnership agreement.
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Issuance of additional units |
No unitholder approval rights. | |
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Amendment of the partnership agreement |
Certain amendments may be made by our general partner without the approval of the unitholders. Other amendments generally require the approval of a unit majority. Please read "—Amendment of the Partnership Agreement." |
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Merger of our partnership or the sale of all or substantially all of our assets |
Unit majority in certain circumstances. Please read "—Merger, Consolidation, Conversion, Sale or Other Disposition of Assets." |
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Dissolution of our partnership |
Unit majority. Please read "—Dissolution." |
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Continuation of our business upon dissolution |
Unit majority. Please read "—Dissolution." |
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Withdrawal of our general partner |
Our general partner may withdraw as the general partner without a vote of our unitholders. Please read "—Withdrawal or Removal of Our General Partner." |
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Removal of our general
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Not less than 66 2 / 3 % of the outstanding common units, including common units held by our general partner and its affiliates. Please read "—Withdrawal or Removal of Our General Partner." |
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Transfer of our general partner interest |
Our general partner may transfer any or all of its general partner interest in us without a vote of our unitholders. Please read "—Transfer of General Partner Interest." |
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Transfer of ownership interests in our general partner |
No unitholder approval required. Please read "—Transfer of Ownership Interests in Our General Partner." |
If any person or group other than our general partner and its affiliates or the Contributing Parties and their respective affiliates acquires beneficial ownership of 20% or more of any class of units, that person or group loses voting rights on all of its units. This loss of voting rights does not apply to any person or group that acquires the units from our general partner or its affiliates and any transferees of that person or group approved by our general partner or to any person or group who acquires the units with the specific prior approval of our general partner.
Applicable Law; Forum, Venue and Jurisdiction
Our partnership agreement is governed by Delaware law. Our partnership agreement requires that any claims, suits, actions or proceedings:
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arising out of or relating in any way to the partnership agreement (including any claims, suits or actions to interpret, apply or
enforce the provisions of the partnership agreement or the duties, obligations or liabilities among limited partners or of limited partners to us, or the rights or powers of, or restrictions on, the
limited partners or us);
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brought in a derivative manner on our behalf;
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asserting a claim of breach of a duty (including a fiduciary duty) owed by any director, officer or other employee of us or our
general partner, or owed by our general partner, to us or the limited partners;
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asserting a claim arising pursuant to any provision of the Delaware Act; or
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- asserting a claim governed by the internal affairs doctrine,
shall be exclusively brought in the Court of Chancery of the State of Delaware (or, if such court does not have subject matter jurisdiction, any other court located in the State of Delaware with subject matter jurisdiction), regardless of whether such claims, suits, actions or proceedings sound in contract, tort, fraud or otherwise, are based on common law, statutory, equitable, legal or other grounds, or are derivative or direct claims.
By purchasing a common unit, a limited partner is irrevocably consenting to these limitations and provisions regarding claims, suits, actions or proceedings and submitting to the exclusive jurisdiction of the Court of Chancery of the State of Delaware (or such other Delaware court) in connection with any such claims, suits, actions or proceedings. The enforceability of
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similar choice of forum provisions in other companies' certificates of incorporation or similar governing documents have been challenged in legal proceedings, and it is possible that, in connection with any action, a court could find the choice of forum provisions contained in our partnership agreement to be inapplicable or unenforceable in such action.
Assuming that a limited partner does not participate in the control of our business within the meaning of the Delaware Act and that he otherwise acts in conformity with the provisions of the partnership agreement, his liability under the Delaware Act will be limited, subject to possible exceptions, to the amount of capital he is obligated to contribute to us for his common units plus his share of any undistributed profits and assets. However, if it were determined that the right, or exercise of the right, by the limited partners as a group:
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to remove or replace our general partner;
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to approve some amendments to our partnership agreement; or
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- to take other action under our partnership agreement,
constituted "participation in the control" of our business for the purposes of the Delaware Act, then the limited partners could be held personally liable for our obligations under the laws of Delaware, to the same extent as our general partner. This liability would extend to persons who transact business with us under the reasonable belief that the limited partner is a general partner. Neither our partnership agreement nor the Delaware Act specifically provides for legal recourse against our general partner if a limited partner were to lose limited liability through any fault of our general partner. While this does not mean that a limited partner could not seek legal recourse, we know of no precedent for this type of a claim in Delaware case law.
Under the Delaware Act, a limited partnership may not make a distribution to a partner if, after the distribution, all liabilities of the limited partnership, other than liabilities to partners on account of their partnership interests and liabilities for which the recourse of creditors is limited to specific property of the partnership, would exceed the fair value of the assets of the limited partnership. For the purpose of determining the fair value of the assets of a limited partnership, the Delaware Act provides that the fair value of property subject to liability for which recourse of creditors is limited shall be included in the assets of the limited partnership only to the extent that the fair value of that property exceeds the nonrecourse liability. The Delaware Act provides that a limited partner who receives a distribution and knew at the time of the distribution that the distribution was in violation of the Delaware Act shall be liable to the limited partnership for the amount of the distribution for three years. Under the Delaware Act, a substituted limited partner of a limited partnership is liable for the obligations of its assignor to make contributions to the partnership, except that such person is not obligated for liabilities unknown to him at the time he became a limited partner and that could not be ascertained from our partnership agreement.
Following the completion of this offering, our subsidiaries will conduct business in 20 states and we may have subsidiaries that conduct business in other states or countries in the future. Maintenance of our limited liability as owner of our operating subsidiaries may require compliance with legal requirements in the jurisdictions in which the operating subsidiaries conduct business, including qualifying our subsidiaries to do business there.
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Limitations on the liability of members or limited partners for the obligations of a limited liability company or limited partnership have not been clearly established in many jurisdictions. If, by virtue of our ownership interest in our subsidiaries or otherwise, it were determined that we were conducting business in any jurisdiction without compliance with the applicable limited partnership or limited liability company statute, or that the right or exercise of the right by the limited partners as a group to remove or replace our general partner, to approve some amendments to our partnership agreement, or to take other action under our partnership agreement constituted "participation in the control" of our business for purposes of the statutes of any relevant jurisdiction, then the limited partners could be held personally liable for our obligations under the law of that jurisdiction to the same extent as our general partner under the circumstances. We will operate in a manner that our general partner considers reasonable and necessary or appropriate to preserve the limited liability of the limited partners.
Issuance of Additional Partnership Interests
Our partnership agreement authorizes us to issue an unlimited number of additional partnership interests for the consideration and on the terms and conditions determined by our general partner without the approval of the unitholders.
It is possible that we will fund acquisitions through the issuance of additional common units or other partnership interests. Holders of any additional common units we issue will be entitled to share equally with the then-existing common unitholders in our distributions. In addition, the issuance of additional common units or other partnership interests may dilute the value of the interests of the then-existing common unitholders in our net assets.
In accordance with Delaware law and the provisions of our partnership agreement, we may also issue additional partnership interests that, as determined by our general partner, may have rights to distributions or special voting rights to which our common units are not entitled. In addition, our partnership agreement does not prohibit our subsidiaries from issuing equity interests, which may effectively rank senior in right of distributions or liquidation to our common units.
Our general partner will have the right, which it may from time to time assign in whole or in part to any of its affiliates, to purchase common units or other partnership interests whenever, and on the same terms that, we issue partnership interests to persons other than our general partner and its affiliates, to the extent necessary to maintain the percentage interest of our general partner and its affiliates, including such interest represented by common units, that existed immediately prior to each issuance. The common unitholders will not have preemptive rights under our partnership agreement to acquire additional common units or other partnership interests.
Amendment of the Partnership Agreement
General
Amendments to our partnership agreement may be proposed only by our general partner. However, our general partner will have no duty or obligation to propose any amendment and may decline to propose or approve any amendment to our partnership agreement free of any duty or obligation whatsoever to us or the limited partners, including any duty to act in the best interests of us or the limited partners. In order to adopt a proposed amendment, other than the amendments discussed below, our general partner is required to seek written approval of the holders of the number of units required to approve the amendment or to call a meeting of the limited partners to consider and vote upon the proposed amendment. Except as described below, an amendment must be approved by a unit majority.
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Prohibited Amendments
No amendment may be made that would:
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enlarge the duties or payment obligations of any limited partner without his consent, unless approved by at least a majority of the
type or class of limited partner interests so affected; or
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- enlarge the duties or payment obligations of, restrict in any way any action by or rights of, or reduce in any way the amounts distributable, reimbursable or otherwise payable by us to our general partner or any of its affiliates without the consent of our general partner, which consent may be given or withheld in its sole discretion.
The provision of our partnership agreement preventing the amendments having the effects described in the clauses above can be amended upon the approval of the holders of at least 90% of the outstanding units, voting as a single class (including units owned by our general partner and its affiliates). Upon completion of the offering, affiliates of our Sponsors will own approximately % of our outstanding common units (excluding any common units purchased by officers and directors of our general partner under our directed unit program), and our Sponsors will indirectly own and control our general partner.
No Unitholder Approval
Our general partner may generally make amendments to our partnership agreement without the approval of any limited partner to reflect:
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a change in our name, the location of our principal office, our registered agent or our registered office;
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the admission, substitution, withdrawal or removal of partners in accordance with our partnership agreement;
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a change that our general partner determines to be necessary or appropriate to qualify or continue our qualification as a limited
partnership or other entity in which the limited partners have limited liability under the laws of any state or to ensure that neither we nor any of our subsidiaries will be treated as an association
taxable as a corporation or otherwise taxed as an entity for federal income tax purposes;
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a change in our fiscal year or taxable year and any other changes that our general partner determines to be necessary or appropriate
as a result of such change;
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an amendment that is necessary, in the opinion of our counsel, to prevent us or our general partner or its directors, officers, agents
or trustees from in any manner being subjected to the provisions of the Investment Company Act of 1940, the Investment Advisers Act of 1940 or "plan asset" regulations adopted under the Employee
Retirement Income Security Act of 1974 ("ERISA"), whether or not substantially similar to plan asset regulations currently applied or proposed;
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- an amendment that our general partner determines to be necessary or appropriate for the creation, authorization or issuance of additional partnership interests or the right to acquire partnership interests;
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any amendment expressly permitted in our partnership agreement to be made by our general partner acting alone;
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an amendment effected, necessitated or contemplated by a merger agreement or plan of conversion that has been approved under the terms
of our partnership agreement;
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any amendment that our general partner determines to be necessary or appropriate to reflect and account for the formation by us of, or
our investment in, any corporation, partnership, joint venture, limited liability company or other entity, in connection with our conduct of activities as otherwise permitted by our partnership
agreement;
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conversions into, mergers with or conveyances to another limited liability entity that is newly formed and has no assets, liabilities
or operations at the time of the conversion, merger or conveyance other than those it receives by way of the conversion, merger or conveyance; or
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- any other amendments substantially similar to any of the matters described in the clauses above.
In addition, our general partner may make amendments to our partnership agreement, without the approval of any limited partner, if our general partner determines that those amendments:
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do not adversely affect in any material respect the limited partners, considered as a whole, or any particular class of partnership
interests as compared to other classes of partnership interests;
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are necessary or appropriate to satisfy any requirements, conditions or guidelines contained in any opinion, directive, order, ruling
or regulation of any federal or state agency or judicial authority or contained in any federal or state statute;
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are necessary or appropriate to facilitate the trading of limited partner interests or to comply with any rule, regulation, guideline
or requirement of any securities exchange on which the limited partner interests are or will be listed or admitted to trading;
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are necessary or appropriate for any action taken by our general partner relating to splits or combinations of units under the
provisions of our partnership agreement; or
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- are required to effect the intent expressed in this prospectus or the intent of the provisions of our partnership agreement or are otherwise contemplated by our partnership agreement.
Opinion of Counsel and Unitholder Approval
For amendments of the type not requiring unitholder approval, our general partner will not be required to obtain an opinion of counsel to the effect that an amendment will not affect the limited liability of any limited partner under Delaware law. No other amendments to our partnership agreement will become effective without the approval of holders of at least 90% of the outstanding units, voting as a single class, unless we first obtain such an opinion.
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In addition to the above restrictions, any amendment that would have a material adverse effect on the rights or preferences of any type or class of partnership interests in relation to other classes of partnership interests will require the approval of at least a majority of the type or class of partnership interests so affected. Any amendment that would reduce the percentage of units required to take any action, other than to remove our general partner or call a meeting of unitholders, must be approved by the affirmative vote of limited partners whose aggregate outstanding units constitute not less than the percentage sought to be reduced. Any amendment that would increase the percentage of units required to remove our general partner must be approved by the affirmative vote of limited partners whose aggregate outstanding units constitute not less than 90% of outstanding units. Any amendment that would increase the percentage of units required to call a meeting of unitholders must be approved by the affirmative vote of limited partners whose aggregate outstanding units constitute at least a majority of the outstanding units.
Certain Provisions of the Agreement Governing our General Partner
The limited liability company agreement of our general partner will contain provisions that prohibit certain actions without a supermajority vote of at least 66 2 / 3 % of the members of the board of directors of our general partner, including:
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the incurrence of borrowings in excess of 2.5 times our Debt to EBITDAX Ratio (as defined below) for the preceding four quarters;
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the reservation of a portion of cash generated from operations to finance acquisitions;
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modifications to the definition of "Available Cash" in our partnership agreement; and
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- the issuance of any partnership interests that rank senior in right of distributions or liquidation to our common units.
As used in the limited liability company agreement of our general partner, the term "Debt to EBITDAX Ratio" refers to the ratio of (i) the total debt of the Partnership and its consolidated subsidiaries as of the relevant determination date to (ii) EBITDAX (as defined in such agreement) of the Partnership and its consolidated subsidiaries for the most recent four fiscal quarter period, subject to certain exceptions.
Merger, Consolidation, Conversion, Sale or Other Disposition of Assets
A merger, consolidation or conversion of us requires the prior consent of our general partner. However, our general partner will have no duty or obligation to consent to any merger, consolidation or conversion and may decline to do so free of any duty or obligation whatsoever to us or the limited partners, including any duty to act in the best interest of us or the limited partners, other than the implied contractual covenant of good faith and fair dealing.
In addition, our partnership agreement generally prohibits our general partner, without the prior approval of the holders of a unit majority, from causing us to, among other things, sell, exchange or otherwise dispose of all or substantially all of our assets in a single transaction or a series of related transactions. Our general partner may, however, mortgage, pledge, hypothecate or grant a security interest in all or substantially all of our assets without such approval. Our general partner may also sell any or all of our assets under a foreclosure or other realization upon those encumbrances without such approval. Finally, our general partner may consummate
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any merger without the prior approval of our unitholders if we are the surviving entity in the transaction, our general partner has received an opinion of counsel regarding limited liability and tax matters, the transaction would not result in an amendment to the partnership agreement requiring unitholder approval, each of our units will be an identical unit of our partnership following the transaction and the partnership interests to be issued by us in such merger do not exceed 20% of our outstanding partnership interests immediately prior to the transaction.
If the conditions specified in our partnership agreement are satisfied, our general partner may convert us or any of our subsidiaries into a new limited liability entity or merge us or any of our subsidiaries into, or convey all of our assets to, a newly formed entity, if the sole purpose of that conversion, merger or conveyance is to effect a mere change in our legal form into another limited liability entity, our general partner has received an opinion of counsel regarding limited liability and tax matters, and our general partner determines that the governing instruments of the new entity provide the limited partners and our general partner with the same rights and obligations as contained in our partnership agreement. Our unitholders are not entitled to dissenters' rights of appraisal under our partnership agreement or applicable Delaware law in the event of a conversion, merger or consolidation, a sale of substantially all of our assets or any other similar transaction or event.
We will continue as a limited partnership until dissolved under our partnership agreement. We will dissolve upon:
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the election of our general partner to dissolve us, if approved by the holders of units representing a unit majority;
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there being no limited partners, unless we are continued without dissolution in accordance with applicable Delaware law;
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the entry of a decree of judicial dissolution of our partnership; or
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- the withdrawal or removal of our general partner or any other event that results in its ceasing to be our general partner other than by reason of a transfer of its general partner interest in accordance with our partnership agreement or its withdrawal or removal following the approval and admission of a successor.
Upon a dissolution under the last clause above, the holders of a unit majority may also elect, within specific time limitations, to continue our business on the same terms and conditions described in our partnership agreement by appointing as a successor general partner an entity approved by the holders of units representing a unit majority, subject to our receipt of an opinion of counsel to the effect that:
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the action would not result in the loss of limited liability under Delaware law of any limited partner; and
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- neither our partnership nor any of our subsidiaries would be treated as an association taxable as a corporation or otherwise be taxable as an entity for federal income tax purposes upon the exercise of that right to continue (to the extent not already so treated or taxed).
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Liquidation and Distribution of Proceeds
Upon our dissolution, unless our business is continued, the liquidator authorized to wind up our affairs will, acting with all of the powers of our general partner that are necessary or appropriate, liquidate our assets and apply the proceeds of the liquidation as set forth in our partnership agreement. The liquidator may defer liquidation or distribution of our assets for a reasonable period of time or distribute assets to partners in kind if it determines that a sale would be impractical or would cause undue loss to our partners.
Withdrawal or Removal of Our General Partner
Our general partner may withdraw as general partner in compliance with our partnership agreement after giving 90 days' written notice to our unitholders, and that withdrawal will not constitute a violation of our partnership agreement.
Upon voluntary withdrawal of our general partner by giving notice to the other partners, the holders of a unit majority may select a successor to that withdrawing general partner. If a successor is not elected, or is elected but an opinion of counsel regarding limited liability and tax matters cannot be obtained, we will be dissolved, wound up and liquidated, unless within a specified period after that withdrawal, the holders of a unit majority agree to continue our business by appointing a successor general partner. Please read "—Dissolution."
Our general partner may not be removed unless that removal is approved by the vote of the holders of not less than 66 2 / 3 % of the outstanding units, voting together as a single class, including common units held by our general partner and its affiliates, and we receive an opinion of counsel regarding limited liability and tax matters. Any removal of our general partner is also subject to the approval of a successor general partner by the vote of the holders of a majority of the outstanding common units. Upon the completion of this offering, assuming no exercise of the underwriters' option to purchase additional common units, affiliates of our Sponsors will own % of our outstanding common units (excluding any common units purchased by officers and directors of our general partner under our directed unit program), and our Sponsors will indirectly own and control our general partner.
In the event of the removal of our general partner under circumstances where cause exists or withdrawal of our general partner where that withdrawal violates our partnership agreement, a successor general partner will have the option to purchase the general partner interest of the departing general partner for a cash payment equal to the fair market value of those interests. Under all other circumstances where our general partner withdraws or is removed by the limited partners, the departing general partner will have the option to require the successor general partner to purchase the general partner interest of the departing general partner for fair market value. In each case, this fair market value will be determined by agreement between the departing general partner and the successor general partner. If no agreement is reached, an independent investment banking firm or other independent expert selected by the departing general partner and the successor general partner will determine the fair market value. Or, if the departing general partner and the successor general partner cannot agree upon an expert, then an expert chosen by agreement of the experts selected by each of them will determine the fair market value.
If the option described above is not exercised by either the departing general partner or the successor general partner, the departing general partner will become a limited partner and its general partner interest will automatically convert into common units pursuant to a valuation of
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those interests as determined by an investment banking firm or other independent expert selected in the manner described in the preceding paragraph.
In addition, we will be required to reimburse the departing general partner for all amounts due the departing general partner, including, without limitation, all employee-related liabilities, including severance liabilities, incurred as a result of the termination of any employees employed for our benefit by the departing general partner or its affiliates.
Transfer of General Partner Interest
At any time, our general partner may transfer all or any of its general partner interest to another person without the approval of our common unitholders. As a condition of this transfer, the transferee must, among other things, assume the rights and duties of our general partner, agree to be bound by the provisions of our partnership agreement and furnish an opinion of counsel regarding limited liability and tax matters.
Transfer of Ownership Interests in Our General Partner
At any time, the owners of our general partner may sell or transfer all or part of their ownership interests in our general partner to an affiliate or third party without the approval of our unitholders.
Change of Management Provisions
Our partnership agreement contains specific provisions that are intended to discourage a person or group from attempting to remove Kimbell Royalty GP, LLC as our general partner or from otherwise changing our management. Please read "—Withdrawal or Removal of Our General Partner" for a discussion of certain consequences of the removal of our general partner. If any person or group, other than our general partner and its affiliates or the Contributing Parties and their respective affiliates acquires beneficial ownership of 20% or more of any class of units, that person or group loses voting rights on all of its units. This loss of voting rights does not apply to any person or group that acquires the units from our general partner or its affiliates and any transferees of that person or group who are notified by our general partner that they will not lose their voting rights or to any person or group who acquires the units with the prior approval of the board of directors of our general partner.
If at any time our general partner and its affiliates (including our Sponsors and their respective affiliates) own more than 80% of the then-issued and outstanding limited partner interests of any class, our general partner will have the right, which it may assign in whole or in part to any of its affiliates or to us, to acquire all, but not less than all, of the limited partner interests of the class held by unaffiliated persons, as of a record date to be selected by our general partner, on at least 10, but not more than 60, days' notice. The purchase price in the event of this purchase is the greater of:
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- the highest price paid by our general partner or any of its affiliates for any limited partner interests of the class purchased within the 90 days preceding the date on which our general partner first mails notice of its election to purchase those limited partner interests; and
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- the current market price calculated in accordance with our partnership agreement as of the date three business days before the date the notice is mailed.
As a result of our general partner's right to purchase outstanding limited partner interests, a holder of limited partner interests may have his limited partner interests purchased at an undesirable time or at a price that may be lower than market prices at various times prior to such purchase or lower than a unitholder may anticipate the market price to be in the future. The tax consequences to a unitholder of the exercise of this call right are the same as a sale by that unitholder of his common units in the market. Please read "Material U.S. Federal Income Tax Consequences—Disposition of Common Units."
Except as described below regarding a person or group owning 20% or more of any class of units then outstanding, record holders of units on the record date will be entitled to notice of, and to vote at, meetings of our limited partners and to act upon matters for which approvals may be solicited.
Our general partner does not anticipate that any meeting of unitholders will be called in the foreseeable future. Any action that is required or permitted to be taken by the unitholders may be taken either at a meeting of the unitholders or if authorized by our general partner, without a meeting if consents in writing describing the action so taken are signed by holders of the number of units that would be necessary to authorize or take that action at a meeting where all limited partners were present and voted. Meetings of the unitholders may be called by our general partner or by unitholders owning at least 20% of the outstanding units of the class for which a meeting is proposed. Unitholders may vote either in person or by proxy at meetings. The holders of a majority of the outstanding units of the class or classes for which a meeting has been called, represented in person or by proxy, will constitute a quorum, unless any action by the unitholders requires approval by holders of a greater percentage of the units, in which case the quorum will be the greater percentage.
Each record holder of a unit has a vote according to his percentage interest in us, although additional limited partner interests having special voting rights could be issued. Please read "—Issuance of Additional Partnership Interests." However, if at any time any person or group, other than our general partner and its affiliates, the Contributing Parties and their respective affiliates, or a direct or subsequently approved transferee of our general partner or its affiliates or the Contributing Parties and their affiliates and purchasers specifically approved by our general partner, acquires, in the aggregate, beneficial ownership of 20% or more of any class of units then outstanding, that person or group will lose voting rights on all of its units and the units may not be voted on any matter and will not be considered to be outstanding when sending notices of a meeting of unitholders, calculating required votes, determining the presence of a quorum or for other similar purposes. Common units held in nominee or street name account will be voted by the broker or other nominee in accordance with the instruction of the beneficial owner unless the arrangement between the beneficial owner and his nominee provides otherwise.
Any notice, demand, request, report or proxy material required or permitted to be given or made to record common unitholders under our partnership agreement will be delivered to the record holder by us or by the transfer agent.
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By transfer of common units in accordance with our partnership agreement, each transferee of common units shall be admitted as a limited partner with respect to our common units transferred when such transfer and admission are reflected in our books and records. Except as described under "—Limited Liability," our common units will be fully paid, and unitholders will not be required to make additional contributions.
Ineligible Holders; Redemption
Under our partnership agreement, an "Eligible Taxable Holder" is a limited partner who is qualified to hold an interest in oil and gas leases on federal lands, as determined by our general partner with the advice of counsel. An "Ineligible Holder" is a limited partner (a) who is not an Eligible Taxable Holder or (b) whose, or whose owners', nationality, citizenship or other related status would create a substantial risk of cancellation or forfeiture of any property in which we have an interest, as determined by our general partner with the advice of counsel.
If at any time our general partner determines, with the advice of counsel, that one or more limited partners are Ineligible Holders, then our general partner may request any limited partner to furnish to our general partner an executed certification or other information about its federal income tax status and/or nationality, citizenship or related status. If a limited partner fails to furnish such certification or other requested information within 30 days (or such other period as our general partner may determine) after a request for such certification or other information, or our general partner determines after receipt of the information that the limited partner is an Ineligible Holder, the limited partner may be treated as an Ineligible Holder. An Ineligible Holder does not have the right to direct the voting of its units and may not receive distributions in kind upon our liquidation.
Furthermore, we have the right to redeem all of our common units of any holder that our general partner concludes is an Ineligible Holder or fails to furnish the information requested by our general partner. The redemption price in the event of such redemption for each unit held by such unitholder will be the current market price of such unit (the date of determination of which shall be the date fixed for redemption). The redemption price will be paid, as determined by our general partner, in cash or by delivery of a promissory note. Any such promissory note will bear interest at the rate of 5% annually and be payable in three equal annual installments of principal and accrued interest, commencing one year after the redemption date.
Under our partnership agreement, in most circumstances, we will indemnify the following persons, to the fullest extent permitted by law, from and against all losses, claims, damages or similar events:
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our general partner;
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any departing general partner;
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- any person who is or was an affiliate of our general partner or any departing general partner;
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any person who is or was a manager, managing member, general partner, director, officer, fiduciary or trustee of us, our subsidiaries
or any entity set forth in the preceding three bullet points;
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any person who is or was serving as a manager, managing member, general partner, director, officer, fiduciary or trustee of another
person owing a fiduciary duty to us or any of our subsidiaries at the request of our general partner or any departing general partner or any of their affiliates; and
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- any person designated by our general partner.
Any indemnification under these provisions will only be out of our assets. Unless it otherwise agrees, our general partner will not be personally liable for, or have any obligation to contribute or lend funds or assets to us to enable us to effectuate, indemnification. We may purchase insurance against liabilities asserted against and expenses incurred by persons for our activities, regardless of whether we would have the power to indemnify the person against such liabilities under our partnership agreement.
Our partnership agreement requires us to reimburse our general partner for all direct and indirect expenses it incurs or payments it makes on our behalf and all other expenses allocable to us or otherwise incurred by our general partner in connection with operating our business. Our partnership agreement does not set a limit on the amount of expenses for which our general partner and its affiliates may be reimbursed. These expenses include salary, bonus, incentive compensation and other amounts paid to persons who perform services for us or on our behalf and expenses allocated to our general partner by its affiliates. Kimbell Operating, a wholly owned subsidiary of our general partner, will provide management, administrative and operational services to us pursuant to a management services agreement. We expect these services to be provided indirectly by affiliates of our general partner. Our general partner is entitled to determine in good faith the expenses that are allocable to us. The expenses for which we are required to reimburse our general partner are not subject to any caps or other limits.
Our general partner is required to keep appropriate books of our business at our principal offices. These books will be maintained for financial reporting purposes on an accrual basis. For tax and fiscal reporting purposes, our fiscal year is the calendar year.
We will furnish or make available to record holders of our common units, within 105 days after the close of each fiscal year, an annual report containing audited consolidated financial statements and a report on those consolidated financial statements by our independent public accountants. Except for our fourth quarter, we will also furnish or make available summary financial information within 50 days after the close of each quarter. We will be deemed to have made any such report available if we file such report with the SEC on EDGAR or make the report available on a publicly available website that we maintain.
We will furnish each record holder with information reasonably required for tax reporting purposes within 90 days after the close of each calendar year. This information is expected to be furnished in summary form so that some complex calculations normally required of partners can be avoided. Our ability to furnish this summary information to our unitholders will depend on
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their cooperation in supplying us with specific information. Every unitholder will receive information to assist him in determining his federal and state tax liability and in filing his federal and state income tax returns, regardless of whether he supplies us with the necessary information.
Right to Inspect Our Books and Records
Our partnership agreement provides that a limited partner can, for a purpose reasonably related to his interest as a limited partner, upon reasonable written demand stating the purpose of such demand and at his own expense, have furnished to him:
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a current list of the name and last known address of each record holder;
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copies of our partnership agreement and our certificate of limited partnership and all amendments thereto; and
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- certain information regarding the status of our business and financial condition.
Our general partner may, and intends to, keep confidential from the limited partners trade secrets or other information the disclosure of which our general partner determines is not in our best interests or that we are required by law or by agreements with third parties to keep confidential. Our partnership agreement limits the rights to information that a limited partner would otherwise have under Delaware law.
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UNITS ELIGIBLE FOR FUTURE SALE
Upon the completion of this offering, the Contributing Parties, including affiliates of our Sponsors, will hold common units. The sale of these common units could have an adverse impact on the price of our common units or on any trading market that may develop.
Our common units sold in this offering will generally be freely transferable without restriction or further registration under the Securities Act, except that units purchased through the directed unit program will be subject to the lock-up restrictions described below and any common units held by an "affiliate" of ours may not be resold publicly except in compliance with the registration requirements of the Securities Act or under an exemption under Rule 144 of the Securities Act ("Rule 144") or otherwise. Rule 144 permits securities acquired by an affiliate of the issuer to be sold into the market in an amount that does not exceed, during any three-month period, the greater of:
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1% of the total number of the securities outstanding; or
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- the average weekly reported trading volume of our common units for the four weeks prior to the sale.
Sales under Rule 144 are also subject to specific manner of sale provisions, holding period requirements, notice requirements and the availability of current public information about us. A person who is not deemed to have been an affiliate of ours at any time during the three months preceding a sale, and who has beneficially owned our common units for at least six months (provided we are in compliance with the current public information requirement), or one year (regardless of whether we are in compliance with the current public information requirement), would be entitled to sell those common units under Rule 144, subject only to the current public information requirement. After beneficially owning Rule 144 restricted units for at least one year, a person who is not deemed to have been an affiliate of ours at any time during the 90 days preceding a sale would be entitled to freely sell those common units without regard to the public information requirements, volume limitations, manner of sale provisions and notice requirements of Rule 144.
Our partnership agreement provides that we may issue an unlimited number of limited partner interests of any type and at any time without a vote of the unitholders. Any issuance of additional common units or other limited partner interests would result in a corresponding decrease in the proportionate ownership interest in us represented by, and could adversely affect the cash distributions to and market price of, common units then outstanding. Please read "The Partnership Agreement—Issuance of Additional Partnership Interests."
In connection with this offering, we have entered into a contribution agreement with our Sponsors and the Contributing Parties. Pursuant to the contribution agreement, the Contributing Parties have specified demand and piggyback participation rights with respect to the registration and sale of common units held by them or their affiliates. At any time following the time when we are eligible to file a registration statement on Form S-3, each of our Sponsors has the right to cause us to prepare and file a registration statement on Form S-3 with the SEC covering the offering and sale of common units held by affiliates. We are not obligated to effect more than one such demand registration in any 12-month period or two such demand registrations in the aggregate. If we propose to file a registration statement pursuant to a Sponsor's demand registration discussed above, the Contributing Parties may request to "piggyback" onto such registration statement in order to offer and sell common units held by them or their affiliates. We
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have agreed to pay all registration expenses in connection with such demand and piggyback registrations.
In connection with any registration of this kind, we will indemnify each unitholder participating in the registration and its officers, directors and controlling persons from and against certain liabilities under the Securities Act or any applicable state securities laws arising from the registration statement or prospectus. We will bear all costs and expenses incidental to any registration, excluding any underwriting discounts.
Our affiliates may also sell their units or other partnership interests in private transactions at any time, subject to compliance with applicable laws and the lock-up agreement described below and under the heading "Underwriting."
We, our general partner, executive officers and directors of our general partner, our Sponsors, certain of the Contributing Parties and each person buying common units through the directed unit program have agreed not to sell any common units they beneficially own for a period of 180 days from the date of this prospectus. Please read "Underwriting—Lock-Up Agreements" for a description of these lock-up provisions.
Prior to the completion of this offering, we will to adopt a new LTIP. We intend to file a registration statement on Form S-8 under the Securities Act to register common units issuable under the LTIP. This registration statement on Form S-8 is expected to be filed following the effective date of the registration statement of which this prospectus is a part and will be effective upon filing. Accordingly, common units issued under the LTIP will be eligible for resale in the public market without restriction after the effective date of the Form S-8 registration statement, subject to applicable vesting requirements, Rule 144 limitations applicable to affiliates and the lock-up restrictions described above.
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MATERIAL U.S. FEDERAL INCOME TAX CONSEQUENCES
This section is a summary of the material tax considerations that may be relevant to prospective unitholders who are individual citizens or residents of the United States and, unless otherwise noted in the following discussion, is the opinion of Baker Botts L.L.P., counsel to our general partner and us, insofar as it relates to legal conclusions with respect to matters of U.S. federal income tax law. This section is based upon current provisions of the Internal Revenue Code of 1986, as amended (the "Code"), existing and proposed Treasury regulations promulgated under the Code (the "Treasury Regulations") and current administrative rulings and court decisions, all of which are subject to change. Later changes in these authorities may cause the tax consequences to vary substantially from the consequences described below. Unless the context otherwise requires, references in this section to "us," "our" or "we" are references to Kimbell Royalty Partners, LP and operating subsidiaries.
The following discussion does not comment on all federal income tax matters affecting us or our unitholders. Moreover, the discussion focuses on unitholders who are individual citizens or residents of the United States and has only limited application to corporations, estates, trusts, partnerships and entities treated as partnerships for federal income tax purposes, nonresident aliens, U.S. expatriates and former citizens or long-term residents of the United States or other unitholders subject to specialized tax treatment, such as banks, insurance companies and other financial institutions, tax-exempt institutions, foreign persons (including, without limitation, controlled foreign corporations, passive foreign investment companies and non-U.S. persons eligible for the benefits of an applicable income tax treaty with the United States), IRAs, real estate investment trusts, employee benefit plans or mutual funds, dealers in securities or currencies, traders in securities, U.S. persons whose "functional currency" is not the U.S. dollar, persons holding their units as part of a "straddle," "hedge," "conversion transaction" or other risk reduction transaction, and persons deemed to sell their units under the constructive sale provisions of the Code. In addition, the discussion only comments to a limited extent on state, local or foreign tax consequences. Accordingly, we encourage each prospective unitholder to consult, and depend on, his own tax advisor in analyzing the federal, state, local and foreign tax consequences particular to him of the ownership or disposition of common units.
All statements as to matters of law and legal conclusions, but not as to factual matters, contained in this section, unless otherwise noted, are the opinion of Baker Botts L.L.P. and are based on the accuracy of the representations made by us.
We are relying on the opinions of Baker Botts L.L.P. Unlike an IRS ruling, an opinion of counsel represents only counsel's best legal judgment and does not bind the IRS or the courts. Accordingly, the opinions and statements made herein may not be sustained by a court if contested by the IRS. Any contest of this sort with the IRS may materially and adversely impact the market for our units and the prices at which our units trade. In addition, the costs of any contest with the IRS, principally legal, accounting and related fees, will result in a reduction in cash available for distribution to our unitholders and thus will be borne indirectly by our unitholders. Furthermore, the tax treatment of us, or of an investment in us, may be significantly modified by future legislative or administrative changes or court decisions. Any modifications may or may not be retroactively applied.
For the reasons described below, Baker Botts L.L.P. has not rendered an opinion with respect to the following specific federal income tax issues: (i) the treatment of a unitholder whose units are loaned to a short seller to cover a short sale of units (please read "—Tax Consequences of Unit Ownership—Treatment of Securities Loans"); (ii) whether our monthly convention for
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allocating taxable income and losses is permitted by existing Treasury Regulations (please read "—Disposition of Common Units—Allocations Between Transferors and Transferees"); and (iii) whether our method for depreciating Section 743 adjustments is sustainable in certain cases (please read "—Tax Consequences of Unit Ownership—Section 754 Election" and "—Uniformity of Units").
Subject to the discussion below under "—Tax Consequences of Unit Ownership—Entity-Level Collections, Audits and Adjustments," a partnership is not a taxable entity and incurs no federal income tax liability. Instead, each partner of a partnership is required to take into account his share of items of income, gain, loss and deduction of the partnership in computing his federal income tax liability, regardless of whether cash distributions are made to him by the partnership. Distributions by a partnership to a partner are generally not taxable to the partnership or the partner unless the amount of cash distributed to him is in excess of the partner's adjusted basis in his partnership interest.
Section 7704 of the Code provides that publicly traded partnerships will, as a general rule, be taxed as corporations. However, an exception, referred to as the "Qualifying Income Exception," exists with respect to publicly traded partnerships of which 90.0% or more of the gross income for every taxable year consists of "qualifying income." Qualifying income includes income and gains derived from the exploration, production and marketing of crude oil, natural gas and other products thereof. Other types of qualifying income include interest (other than from a financial business), dividends, gains from the sale of real property and gains from the sale or other disposition of capital assets held for the production of income that otherwise constitutes qualifying income. We estimate that less than % of our current gross income is not qualifying income; however, this estimate could change from time to time. Based upon and subject to this estimate, the factual representations made by us and our general partner and a review of the applicable legal authorities, Baker Botts L.L.P. is of the opinion that at least 90.0% of our current gross income constitutes qualifying income. The portion of our income that is qualifying income may change from time to time.
It is the opinion of Baker Botts L.L.P. that, based upon the Code, its regulations, published revenue rulings and court decisions and the representations described below that:
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We will be classified as a partnership for federal income tax purposes; and
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- Each of our operating subsidiaries will be disregarded as an entity separate from us or will be treated as a partnership for federal income tax purposes.
In rendering its opinion, Baker Botts L.L.P. has relied on factual representations made by us and our general partner. The representations made by us and our general partner upon which Baker Botts L.L.P. has relied include, without limitation:
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Neither we nor any of the operating subsidiaries, is organized as, has elected to be treated as or will elect to be treated as a
corporation for federal income tax purposes; and
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- For every taxable year, more than 90.0% of our gross income has been and will be income of the type that Baker Botts L.L.P. has opined or will opine is "qualifying income" within the meaning of Section 7704(d) of the Code.
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We believe that these representations have been true in the past and expect that these representations will continue to be true in the future.
We will be a publicly traded partnership. The present federal income tax treatment of publicly traded partnerships or an investment in the units of publicly traded partnerships may be modified by administrative, legislative or judicial interpretation at any time. For example, from time to time, the President and members of the U.S. Congress propose and consider substantive changes to the existing federal income tax laws that affect publicly traded partnerships, such as proposals eliminating the qualifying income exception upon which we rely for our treatment as a partnership for U.S. federal income tax purposes.
Additionally, the Proposed Regulations provide an exclusive list of industry-specific rules regarding the qualifying income exception, including whether an activity constitutes the exploration, development, production and marketing of natural resources. Income earned from a royalty interest is not specifically enumerated as a qualifying income activity in the Proposed Regulations. However, we believe that royalty income is qualifying income for purposes of Section 7704 of the Code since it is "derived" from the exploration, development, production and marketing of natural resources, and Baker Botts L.L.P. is of the opinion that such income constitutes qualifying income, notwithstanding the Proposed Regulations. Further, the Proposed Regulations are proposed only to apply to income earned in a taxable year beginning on or after the date that the Proposed Regulations are published as final Treasury Regulations. Therefore, prior to being published as final Treasury Regulations, the Proposed Regulations are generally not applicable to any income that we earn. The U.S. Treasury Department and the IRS may clarify that royalty income is qualifying income for purposes of Section 7704 of the Code; however, there are no assurances that the Proposed Regulations, when published as final Treasury Regulations, will not take a position that is contrary to our interpretation of Section 7704 of the Code.
If we fail to meet the Qualifying Income Exception, other than a failure that is determined by the IRS to be inadvertent and that is cured within a reasonable time after discovery (in which case the IRS may also require us to make adjustments with respect to our unitholders or pay other amounts), we will be treated as if we had transferred all of our assets, subject to liabilities, to a newly formed corporation, on the first day of the year in which we fail to meet the Qualifying Income Exception, in return for stock in that corporation, and then distributed that stock to the unitholders in liquidation of their interests in us. This deemed contribution and liquidation should be tax-free to unitholders and us so long as we, at that time, do not have liabilities in excess of the tax basis of our assets. Thereafter, we would be treated as a corporation for federal income tax purposes.
If we were taxed as a corporation for federal income tax purposes in any taxable year, either as a result of a failure to meet the Qualifying Income Exception or otherwise, our items of income, gain, loss and deduction would be reflected only on our tax return rather than being passed through to our unitholders, and our net income would be taxed to us at corporate rates. In addition, any distribution made to a unitholder would be treated as taxable dividend income, to the extent of our current and accumulated earnings and profits, or, in the absence of earnings and profits, a nontaxable return of capital, to the extent of the unitholder's tax basis in his common units, or taxable capital gain, after the unitholder's tax basis in his common units is reduced to zero.
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Accordingly, taxation as a corporation would result in a material reduction in a unitholder's cash flow and after-tax return and thus would likely result in a substantial reduction of the value of the units.
The discussion below is based on Baker Botts L.L.P.'s opinion that we will be classified as a partnership for federal income tax purposes.
Unitholders who are admitted as limited partners of Kimbell Royalty Partners, LP will be treated as partners of Kimbell Royalty Partners, LP for federal income tax purposes. Also, unitholders whose units are held in street name or by a nominee and who have the right to direct the nominee in the exercise of all substantive rights attendant to the ownership of their common units will be treated as partners of Kimbell Royalty Partners, LP for federal income tax purposes.
A beneficial owner of common units whose units have been transferred to a short seller to complete a short sale would appear to lose his status as a partner with respect to those units for federal income tax purposes. Please read "—Tax Consequences of Unit Ownership—Treatment of Securities Loans."
Income, gains, deductions or losses would not appear to be reportable by a unitholder who is not a partner for federal income tax purposes, and any cash distributions received by a unitholder who is not a partner for federal income tax purposes would therefore be fully taxable as ordinary income. These holders are urged to consult their own tax advisors with respect to the tax consequences of holding units in Kimbell Royalty Partners, LP. The references to "unitholders" in the discussion that follows are to persons who are treated as partners in Kimbell Royalty Partners, LP for federal income tax purposes.
Tax Consequences of Unit Ownership
Flow-Through of Taxable Income
Subject to the discussion below under "—Entity-Level Collections, Audits and Adjustments" we will not pay any federal income tax. Instead, each unitholder will be required to report on his income tax return his share of our income, gains, losses and deductions without regard to whether we make cash distributions to him. Consequently, we may allocate income to a unitholder even if he has not received a cash distribution. The income we allocate to common unitholders will generally be taxable as ordinary income. Each unitholder will be required to include in income his allocable share of our income, gains, losses and deductions for our taxable year ending with or within his taxable year. Our taxable year ends on December 31.
Treatment of Distributions
Distributions by us to a unitholder generally will not be taxable to the unitholder for federal income tax purposes, except to the extent the amount of any such cash distribution exceeds his tax basis in his common units immediately before the distribution. Cash distributions made by us to a unitholder in an amount in excess of a unitholder's tax basis generally will be considered to be gain from the sale or exchange of our common units, taxable in accordance with the rules described under "—Disposition of Common Units" below. Any reduction in a unitholder's share of our liabilities for which no partner, including our general partner, bears the economic risk of
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loss, known as "nonrecourse liabilities," will be treated as a distribution by us of cash to that unitholder. To the extent our distributions cause a unitholder's "at-risk" amount to be less than zero at the end of any taxable year, the unitholder must recapture any losses deducted in previous years. Please read "—Limitations on Deductibility of Losses."
A decrease in a unitholder's percentage interest in us because of our issuance of additional common units will decrease his share of our nonrecourse liabilities, and thus will result in a corresponding deemed distribution of cash. This deemed distribution may constitute a non-pro rata distribution. A non-pro rata distribution of money or property may result in ordinary income to a unitholder, regardless of his tax basis in his common units, if the distribution reduces the unitholder's share of our "unrealized receivables," including depreciation recapture, depletion recapture and/or substantially appreciated "inventory items," each as defined in the Code, and collectively, "Section 751 Assets." To that extent, the unitholder will be treated as having been distributed his proportionate share of the Section 751 Assets and then having exchanged those assets with us in return for the non-pro rata portion of the actual distribution made to him. This latter deemed exchange will generally result in the unitholder's realization of ordinary income, which will equal the excess of (i) the non-pro rata portion of that distribution over (ii) the unitholder's tax basis (generally zero) for the share of Section 751 Assets deemed relinquished in the exchange.
Basis of Common Units
A unitholder's initial tax basis for his common units will generally equal the amount he paid for our common units plus his share of our nonrecourse liabilities. That basis will be increased by his share of our income and by any increases in his share of our nonrecourse liabilities and decreased, but not below zero, by distributions from us, by the unitholder's share of our losses, by any decreases in his share of our nonrecourse liabilities and by his share of our expenditures that are not deductible in computing taxable income and are not required to be capitalized. A unitholder will have no share of our debt that is recourse to our general partner to the extent of our general partner's "net value," as defined in Treasury Regulations under Code Section 752, but will have a share, generally based on his share of profits, of our nonrecourse liabilities. Please read "—Disposition of Common Units—Recognition of Gain or Loss."
Ratio of Taxable Income to Distributions
We estimate that a purchaser of units in this offering who owns those units from the date of closing of this offering through the record date for distributions for the period ending December 31, will be allocated, on a cumulative basis, an amount of federal taxable income that will be less than % of the cash expected to be distributed on those units with respect to that period. These estimates are based upon the assumption that earnings from operations will approximate the amount required to pay the anticipated quarterly distributions on all units and other assumptions with respect to capital expenditures, cash flow, net working capital and anticipated cash distributions. These estimates and assumptions are subject to, among other things, numerous business, economic, regulatory, legislative, competitive and political uncertainties beyond our control. Further, the estimates are based on current tax law and tax reporting positions that we will adopt and which could be changed or with which the IRS could disagree. Accordingly, we cannot assure that these estimates will prove to be correct, and our counsel has not opined on the accuracy of such estimates. The actual ratio of taxable income to cash distributions could be higher or lower than expected, and any differences could be material and could affect the value of units. For example, the ratio of taxable income to cash
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distributions to a purchaser of units in this offering would be higher, and perhaps substantially higher, than our estimate with respect to the period described above if:
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we distribute less cash than we have assumed in making this projection;
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we make a future offering of units and use the proceeds of the offering in a manner that does not produce additional deductions during
the period described above, such as to repay indebtedness outstanding at the time of this offering or to acquire property that is not eligible for depletion, depreciation or amortization for federal
income tax purposes during such period or that is depletable, depreciable or amortizable at a rate significantly slower than the rate applicable to our assets at the time of this offering; or
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- legislation is enacted that limits or repeals certain U.S. federal income tax preferences currently available to oil and gas exploration and production companies (please read "—Tax Treatment of Operations—Recent Legislative Developments").
Limitations on Deductibility of Losses
The deduction by a unitholder of his share of our losses will be limited to the tax basis in his units and, in the case of an individual unitholder, estate, trust, or corporate unitholder (if more than 50.0% of the value of the corporate unitholder's stock is owned directly or indirectly by or for five or fewer individuals or some tax-exempt organizations) to the amount for which the unitholder is considered to be "at-risk" with respect to our activities, if that is less than his tax basis. A unitholder subject to these limitations must recapture losses deducted in previous years to the extent that distributions cause his at-risk amount to be less than zero at the end of any taxable year. Losses disallowed to a unitholder or recaptured as a result of these limitations will carry forward and will be allowable as a deduction to the extent that his at-risk amount is subsequently increased, provided such losses do not exceed such common unitholder's tax basis in his common units. Upon the taxable disposition of a unit, any gain recognized by a unitholder can be offset by losses that were previously suspended by the at-risk limitation but may not be offset by losses suspended by the basis limitation. Any loss previously suspended by the at-risk limitation in excess of that gain would no longer be utilizable.
In general, a unitholder will be at-risk to the extent of the tax basis of his units, excluding any portion of that basis attributable to his share of our nonrecourse liabilities, reduced by (i) any portion of that basis representing amounts otherwise protected against loss because of a guarantee, stop loss agreement or other similar arrangement and (ii) any amount of money he borrows to acquire or hold his units, if the lender of those borrowed funds owns an interest in us, is related to another unitholder or can look only to the units for repayment. A unitholder's at-risk amount will increase or decrease as the tax basis of the unitholder's units increases or decreases, other than tax basis increases or decreases attributable to increases or decreases in his share of our nonrecourse liabilities.
In addition to the basis and at-risk limitations on the deductibility of losses, the passive loss limitations generally provide that individuals, estates, trusts and some closely-held corporations and personal service corporations can deduct losses from passive activities, which are generally defined as trade or business activities in which the taxpayer does not materially participate, only to the extent of the taxpayer's income from those passive activities. The passive loss limitations are applied separately with respect to each publicly traded partnership. Consequently, any passive losses we generate will only be available to offset our passive income generated in the future and will not be available to offset income from other passive activities or investments,
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including our investments or a unitholder's investments in other publicly traded partnerships, or salary or active business income. Passive losses that are not deductible because they exceed a unitholder's share of income we generate may be deducted in full when he disposes of his entire investment in us in a fully taxable transaction with an unrelated party. The passive loss limitations are applied after other applicable limitations on deductions, including the at-risk rules and the basis limitation.
A unitholder's share of our net income may be offset by any of our suspended passive losses, but it may not be offset by any other current or carryover losses from other passive activities, including those attributable to other publicly traded partnerships.
Limitations on Interest Deductions
The deductibility of a non-corporate taxpayer's "investment interest expense" is generally limited to the amount of that taxpayer's "net investment income." Investment interest expense includes:
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interest on indebtedness properly allocable to property held for investment;
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our interest expense attributed to portfolio income; and
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- the portion of interest expense incurred to purchase or carry an interest in a passive activity to the extent attributable to portfolio income.
The computation of a unitholder's investment interest expense will take into account interest on any margin account borrowing or other loan incurred to purchase or carry a unit. Net investment income includes gross income from property held for investment and amounts treated as portfolio income under the passive loss rules, less deductible expenses, other than interest, directly connected with the production of investment income, but generally does not include gains attributable to the disposition of property held for investment or (if applicable) qualified dividend income. The IRS has indicated that the net passive income earned by a publicly traded partnership will be treated as investment income to its unitholders. In addition, the unitholder's share of our portfolio income will be treated as investment income.
Entity-Level Collections, Audits and Adjustments
If we are required or elect under applicable law to pay any federal, state, local or foreign income tax on behalf of any unitholder or our general partner or any former unitholder, we are authorized to pay those taxes from our funds. That payment, if made, will be treated as a distribution of cash to the unitholder on whose behalf the payment was made. If the payment is made on behalf of a person whose identity cannot be determined, we are authorized to treat the payment as a distribution to all current unitholders. We are authorized to amend our partnership agreement in the manner necessary to maintain uniformity of intrinsic tax characteristics of units and to adjust later distributions, so that after giving effect to these distributions, the priority and characterization of distributions otherwise applicable under our partnership agreement is maintained as nearly as is practicable. Payments by us as described above could give rise to an overpayment of tax on behalf of an individual unitholder in which event the unitholder would be required to file a claim in order to obtain a credit or refund.
Pursuant to the Bipartisan Budget Act of 2015, if the IRS makes audit adjustments to our income tax returns for tax years beginning after 2017, it (and some states) may collect any
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resulting taxes (including any applicable penalties and interest) directly from us. We will generally have the ability to shift any such tax liability to our unitholders in accordance with their interests in us during the year under audit, but there can be no assurance that we will be able to do so (or will choose to do so) under all circumstances, or that we will be able to (or choose to) effect corresponding shifts in state income or similar tax liability resulting from the IRS adjustment in states in which we do business in the year under audit or in the adjustment year. If we make payments of taxes, penalties and interest resulting from audit adjustments, our cash available for distribution to our unitholders might be substantially reduced.
Pursuant to this new legislation, we will designate a person (our general partner) to act as the partnership representative who shall have the sole authority to act on behalf of the partnership with respect to dealings with the IRS under these new audit procedures.
Allocation of Income, Gain, Loss and Deduction
In general, if we have a net profit, our items of income, gain, loss and deduction will be allocated among our unitholders in accordance with their percentage interests in us. If we have a net loss, that loss will be allocated first to our unitholders in accordance with their percentage interests in us to the extent of their positive capital accounts and, second, to our general partner.
Code Section 704(c) and related Treasury Regulations require us to adjust the "book" basis of all assets held by us prior to an issuance of additional units to equal their fair market values at the time of unit issuance. Purchasers of newly issued units in an offering are entitled to calculate tax depreciation and amortization deductions and other relevant tax items with respect to our assets based upon that "book" basis, which effectively puts purchasers in that offering in the same position as if our assets had a tax basis equal to their fair market value at the time of unit issuance. This may have the effect of decreasing the amount of our tax depreciation or amortization deductions thereafter allocated to purchasers of units in an earlier offering or of requiring purchasers of units in an earlier offering to thereafter recognize "remedial income" rather than depreciation and amortization deductions. In this context, we use the term "book" as that term is used in Treasury Regulations under Code Section 704. The "book" basis assigned to our assets for this purpose may not be the same as the book value of our property for financial reporting purposes.
It may not be administratively feasible to make the relevant adjustments to "book" basis and the relevant Section 704(c) allocations separately each time we issue units, particularly in the case of small and frequent unit issuances. We do not currently anticipate unit issuances of that type. However, if we were to make such issuances, we may use simplifying conventions to make those adjustments and allocations, which may include the aggregation of certain issuances of units. Our counsel, Baker Botts L.L.P., is unable to opine as to the validity of such conventions.
In addition, items of recapture income will be allocated to the extent possible to the unitholder who was allocated the deduction giving rise to the treatment of that gain as recapture income in order to minimize the recognition of ordinary income by some unitholders. Finally, although we do not expect that our operations will result in the creation of negative capital accounts, if negative capital accounts nevertheless result, items of our income and gain will be allocated in an amount and manner sufficient to eliminate the negative balance as quickly as possible.
An allocation of items of our income, gain, loss or deduction, other than an allocation required under the Section 704(c) principles described above, will generally be given effect for
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federal income tax purposes in determining a partner's share of an item of income, gain, loss or deduction only if the allocation has "substantial economic effect." In any other case, a partner's share of an item will be determined on the basis of his interest in us, which will be determined by taking into account all the facts and circumstances, including:
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the partner's relative contributions to us;
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the interests of all the partners in profits and losses;
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the interests of all the partners in cash flows; and
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- the rights of all the partners to distributions of capital upon liquidation.
Baker Botts L.L.P. is of the opinion that, with the exception of the issues described in "—Section 754 Election," "—Disposition of Common Units—Allocations Between Transferors and Transferees," and "—Uniformity of Units," allocations under our partnership agreement will be given effect under Code Section 704 for federal income tax purposes in determining a partner's share of an item of income, gain, loss or deduction.
Treatment of Securities Loans
A unitholder whose units are loaned to a "short seller" to cover a short sale of units may be considered as having disposed of those units. If so, he would no longer be treated for tax purposes as a partner with respect to those units during the period of the loan and may recognize gain or loss from the disposition. As a result, during this period:
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any of our income, gain, loss or deduction with respect to those units would not be reportable by the unitholder;
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any cash distributions received by the unitholder as to those units would be fully taxable; and
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- all of these distributions would appear to be ordinary income.
Because there is no direct or indirect controlling authority on the issue relating to partnership interests, Baker Botts L.L.P. has not rendered an opinion regarding the tax treatment of a unitholder whose common units are loaned to a short seller to cover a short sale of common units; therefore, unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan to a short seller are urged to modify any applicable brokerage account agreements to prohibit their brokers from borrowing and loaning their units. The IRS has previously announced that it is studying issues relating to the tax treatment of short sales of partnership interests. Please also read "—Disposition of Common Units—Recognition of Gain or Loss."
Alternative Minimum Tax
Each unitholder will be required to take into account his distributive share of any items of our income, gain, loss or deduction for purposes of the alternative minimum tax. For non-corporate married taxpayers filing jointly in 2017, the minimum tax is 26.0% on the first $187,800 of alternative minimum taxable income in excess of the exemption amount and 28.0% on any additional alternative minimum taxable income, which threshold changes annually. Prospective unitholders are urged to consult with their tax advisors as to the impact of an investment in units on their liability for the alternative minimum tax.
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Tax Rates
The highest marginal U.S. federal income tax rates applicable to ordinary income and long-term capital gains (generally, capital gains on certain assets held for more than twelve months) of individuals currently are 39.6% and 20.0%, respectively. These rates are subject to change by new legislation at any time.
In addition, a 3.8% Medicare tax, or NIIT, is imposed on certain net investment income earned by individuals, estates and trusts. For these purposes, net investment income generally includes a unitholder's allocable share of our income and gain realized by a unitholder from a sale of units. In the case of an individual, the tax will be imposed on the lesser of (i) the unitholder's net investment income or (ii) the amount by which the unitholder's modified adjusted gross income exceeds $250,000 (if the unitholder is married and filing jointly or a surviving spouse), $125,000 (if the unitholder is married and filing separately) or $200,000 (in any other case). In the case of an estate or trust, the tax will be imposed on the lesser of (i) undistributed net investment income, or (ii) the excess adjusted gross income over the dollar amount at which the highest income tax bracket applicable to an estate or trust begins.
Section 754 Election
We will make the election permitted by Code Section 754. That election is irrevocable without the consent of the IRS unless there is a constructive termination of the partnership. Please read "—Disposition of Common Units—Constructive Termination." The election will generally permit us to adjust a common unit purchaser's tax basis in our assets, or inside basis, under Code Section 743(b) to reflect his purchase price. This election does not apply with respect to a person who purchases common units directly from us. The Section 743(b) adjustment belongs to the purchaser and not to other unitholders. For purposes of this discussion, the inside basis in our assets with respect to a unitholder will be considered to have two components: (i) his share of our tax basis in our assets, or common basis, and (ii) his Section 743(b) adjustment to that basis.
The timing of deductions attributable to a Section 743(b) adjustment to our common basis will depend upon a number of factors, including the nature of the assets to which the adjustment is allocable, the extent to which the adjustment offsets any Section 704(c) type gain or loss with respect to an asset and certain elections we make as to the manner in which we apply Section 704(c) principles with respect to an asset with respect to which the adjustment is allocable. Please read "—Allocation of Income, Gain, Loss and Deduction." The timing of these deductions may affect the uniformity of our units. Please read "—Uniformity of Units."
A Section 754 election is advantageous if the transferee's tax basis in his units is higher than the units' share of the aggregate tax basis of our assets immediately prior to the transfer. In that case, as a result of the election, the transferee would have, among other items, a greater amount of depreciation deductions and his share of any gain or loss on a sale of our assets would be less. Conversely, a Section 754 election is disadvantageous if the transferee's tax basis in his units is lower than those units' share of the aggregate tax basis of our assets immediately prior to the transfer. Thus, the fair market value of the units may be affected either favorably or unfavorably by the election. A basis adjustment is required regardless of whether a Section 754 election is made in the case of a transfer of an interest in us if we have a substantial built-in loss immediately after the transfer or if we distribute property and have a substantial basis reduction. Generally a built-in loss or a basis reduction is substantial if it exceeds $250,000.
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The calculations involved in the Section 754 election are complex and will be made on the basis of assumptions as to the value of our assets and other matters. For example, the allocation of the Section 743(b) adjustment among our assets must be made in accordance with the Code. The IRS could seek to reallocate some or all of any Section 743(b) adjustment allocated by us to our tangible assets to goodwill instead. Goodwill, as an intangible asset, is generally nonamortizable or amortizable over a longer period of time or under a less accelerated method than our tangible assets. We cannot assure you that the determinations we make will not be successfully challenged by the IRS and that the deductions resulting from them will not be reduced or disallowed altogether. Should the IRS require a different basis adjustment to be made, and should, in our opinion, the expense of compliance exceed the benefit of the election, we may seek permission from the IRS to revoke our Section 754 election. If permission is granted, a subsequent purchaser of units may be allocated more income than he would have been allocated had the election not been revoked.
Accounting Method and Taxable Year
We use the year ending December 31 as our taxable year and the accrual method of accounting for federal income tax purposes. Each unitholder will be required to include in income his share of our income, gain, loss and deduction for our taxable year ending within or with his taxable year. In addition, a unitholder who has a taxable year ending on a date other than December 31 and who disposes of all of his units following the close of our taxable year but before the close of his taxable year must include his share of our income, gain, loss and deduction in income for his taxable year, with the result that he will be required to include in income for his taxable year his share of more than twelve months of our income, gain, loss and deduction. Please read "—Disposition of Common Units—Allocations Between Transferors and Transferees."
Depletion Deductions
Subject to the limitations on deductibility of losses discussed above (please read "—Tax Consequences of Unit Ownership—Limitations on Deductibility of Losses"), common unitholders will be entitled to deductions for the greater of either cost depletion or (if otherwise allowable) percentage depletion with respect to our oil and gas interests. Although the Code requires each common unitholder to compute its own depletion allowance and maintain records of its share of the adjusted tax basis of the underlying property for depletion and other purposes, we intend to furnish each of our common unitholders with information relating to this computation for federal income tax purposes. Each common unitholder, however, remains responsible for calculating its own depletion allowance and maintaining records of its share of the adjusted tax basis of the underlying property for depletion and other purposes.
Percentage depletion is generally available with respect to common unitholders who qualify under the independent producer exemption contained in Section 613A(c) of the Code. For this purpose, an independent producer is a person not directly or indirectly involved in the retail sale of oil, gas, or derivative products or the operation of a major refinery. Percentage depletion is calculated as an amount generally equal to 15% (and, in the case of marginal production, potentially a higher percentage) of the common unitholder's gross income from the depletable property for the taxable year. The percentage depletion deduction with respect to any property is limited to 100% of the taxable income of the common unitholder from the property for each taxable year, computed without the depletion allowance. A common unitholder that qualifies as
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an independent producer may deduct percentage depletion only to the extent the common unitholder's average daily production of domestic crude oil, or the gas equivalent, does not exceed 1,000 barrels. This depletable amount may be allocated between oil and gas production, with 6,000 cubic feet of domestic gas production regarded as equivalent to one barrel of crude oil. The 1,000 barrel limitation must be allocated among the independent producer and controlled or related persons and family members in proportion to the respective production by such persons during the period in question.
In addition to the foregoing limitations, the percentage depletion deduction otherwise available is limited to 65% of a common unitholder's total taxable income from all sources for the year, computed without the depletion allowance, net operating loss carrybacks, or capital loss carrybacks. Any percentage depletion deduction disallowed because of the 65% limitation may be deducted in the following taxable year if the percentage depletion deduction for such year plus the deduction carryover does not exceed 65% of the common unitholder's total taxable income for that year. The carryover period resulting from the 65% net income limitation is unlimited.
Common unitholders that do not qualify under the independent producer exemption are generally restricted to depletion deductions based on cost depletion. Cost depletion deductions are calculated by (i) dividing the common unitholder's share of the adjusted tax basis in the underlying mineral property by the number of mineral units (barrels of oil and Mcf of gas) remaining as of the beginning of the taxable year and (ii) multiplying the result by the number of mineral units sold within the taxable year. The total amount of deductions based on cost depletion cannot exceed the common unitholder's share of the total adjusted tax basis in the property.
All or a portion of any gain recognized by a common unitholder as a result of either the disposition by us of some or all of our oil and gas interests or the disposition by the common unitholder of some or all of its units may be taxed as ordinary income to the extent of recapture of depletion deductions, except for percentage depletion deductions in excess of the tax basis of the property. The amount of the recapture is generally limited to the amount of gain recognized on the disposition.
The foregoing discussion of depletion deductions does not purport to be a complete analysis of the complex legislation and Treasury Regulations relating to the availability and calculation of depletion deductions by the common unitholders. Further, because depletion is required to be computed separately by each common unitholder and not by us, no assurance can be given, and counsel is unable to express any opinion, with respect to the availability or extent of percentage depletion deductions to the unitholders for any taxable year. We encourage each prospective common unitholder to consult its tax advisor to determine whether percentage depletion would be available to the common unitholder.
Administrative Expenses
Expenses of the partnership will include administrative expenses, the deductibility of which may be subject to limitation. As long as we only own royalty interests, under applicable rules, administrative expenses attributable to common units will be considered miscellaneous itemized deductions that generally will have to be aggregated with an individual unitholder's other miscellaneous itemized deductions. These rules disallow itemized deductions that are less than 2% of a taxpayer's adjusted gross income, and the amount of otherwise allowable itemized deductions will be reduced by the lesser of (i) 3% of (A) adjusted gross income over
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(B) $311,300 if married and filing jointly, $155,650 if married filing separately or $259,400 if the unitholder is unmarried or in any other case and (ii) 80% of the amount of itemized deductions that are otherwise allowable, or both. It is anticipated that the amount of such administrative expenses will not be significant in relation to the partnership's income.
Recent Legislative Developments
From time to time, the President and members of Congress propose and consider legislative changes to the existing federal income tax laws that affect oil and natural gas exploration and production companies. Recent proposals have suggested eliminating or reducing certain key U.S. federal income tax incentives currently available to oil and natural gas exploration and production companies. These proposed changes have included, (i) the repeal of the percentage depletion allowance for oil and natural gas properties, (ii) the elimination of current deductions for intangible drilling and development costs, (iii) the elimination of the deduction for certain domestic production activities, (iv) an extension of the amortization period for certain geological and geophysical expenditures, and (v) the imposition of a new $10.25 per barrel fee on certain oil production, to be paid by certain oil companies. It is unclear whether any of these proposals will be introduced into law and, if so, how soon any resulting changes could become effective. The passage of any legislation as a result of these proposals or any other similar changes in U.S. federal income tax laws could eliminate or postpone certain tax deductions that are currently available with respect to oil and natural gas exploration and development, and any such change could increase the taxable income allocable to our unitholders and negatively impact the value of an investment in our units.
Tax Basis, Depreciation and Amortization
The tax basis of our assets will be used for purposes of computing depreciation, depletion and cost recovery deductions, if any, and, ultimately, gain or loss on the disposition of these assets. Under Code Section 704, the federal income tax burden associated with the difference between the fair market value of our assets and their tax basis immediately prior to an offering will be borne by all of our unitholders as of that time. Please read "—Tax Consequences of Unit Ownership—Allocation of Income, Gain, Loss and Deduction."
Part or all of the goodwill, going concern value and other intangible assets we have acquired or will acquire may not produce any amortization deductions because of the application of the anti-churning restrictions of Code Section 197. Please read "—Uniformity of Units."
If we dispose of depreciable or depletable property by sale, foreclosure or otherwise, all or a portion of any gain, determined by reference to the amount of depreciation and depletion deductions previously taken and the nature of the property, may be subject to the recapture rules and taxed as ordinary income rather than capital gain. Similarly, a unitholder who has taken cost recovery, depletion or depreciation deductions with respect to property we own will likely be required to recapture some or all of those deductions as ordinary income upon a sale of his interest in us. Please read "—Tax Consequences of Unit Ownership—Allocation of Income, Gain, Loss and Deduction" and "—Disposition of Common Units—Recognition of Gain or Loss."
The costs we incur in selling our units (called "syndication expenses") must be capitalized and cannot be deducted currently, ratably or upon our termination. There are uncertainties regarding the classification of costs as organization expenses, which may be amortized by us, and as syndication expenses, which may not be amortized by us. The underwriting discounts and commissions we incur will be treated as syndication expenses.
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Valuation and Tax Basis of Our Properties
The federal income tax consequences of the ownership and disposition of units will depend in part on our estimates of the relative fair market values, and the initial tax bases, of our assets. Although we may from time to time consult with professional appraisers regarding valuation matters, we will make many of the relative fair market value estimates ourselves. These estimates and determinations of basis are subject to challenge and will not be binding on the IRS or the courts. If the estimates of fair market value or basis are later found to be incorrect, the character and amount of items of income, gain, loss or deductions previously reported by unitholders might change, and unitholders might be required to adjust their tax liability for prior years and incur interest and penalties with respect to those adjustments.
Recognition of Gain or Loss
Gain or loss will be recognized on a sale of units equal to the difference between the amount realized and the unitholder's tax basis for the units sold. A unitholder's amount realized will be measured by the sum of the cash or the fair market value of other property received by him plus his share of our nonrecourse liabilities. Because the amount realized includes a unitholder's share of our nonrecourse liabilities, the gain recognized on the sale of units could result in a tax liability in excess of any cash received from the sale.
Except as noted below, gain or loss recognized by a unitholder, other than a "dealer" in units, on the sale or exchange of a unit will generally be taxable as capital gain or loss. Capital gain recognized by an individual on the sale of units held for more than twelve months will generally be taxed at a maximum U.S. federal income tax rate of 20.0%. However, a portion of this gain or loss, which will likely be substantial, will be separately computed and taxed as ordinary income or loss under Code Section 751 to the extent attributable to assets giving rise to depreciation or depletion recapture or other "unrealized receivables" or to "inventory items" we own. The term "unrealized receivables" includes potential recapture items, including depreciation recapture and depletion recapture. Ordinary income attributable to unrealized receivables and inventory items may exceed net taxable gain realized upon the sale of a unit and may be recognized even if there is a net taxable loss realized on the sale of a unit. Thus, a unitholder may recognize both ordinary income and a capital loss upon a sale of units. Capital losses may offset capital gains and no more than $3,000 of ordinary income each year, in the case of individuals, and may only be used to offset capital gains in the case of corporations. Both ordinary income and capital gain recognized on the sale of common units may be subject to NIIT in certain circumstances.
The IRS has ruled that a partner who acquires interests in a partnership in separate transactions must combine those interests and maintain a single adjusted tax basis for all those interests. Upon a sale or other disposition of less than all of those interests, a portion of that tax basis must be allocated to the interests sold using an "equitable apportionment" method, which generally means that the tax basis allocated to the interest sold equals an amount that bears the same relation to the partner's tax basis in his entire interest in the partnership as the value of the interest sold bears to the value of the partner's entire interest in the partnership. Treasury Regulations under Code Section 1223 allow a selling unitholder who can identify common units transferred with an ascertainable holding period to elect to use the actual holding period of our common units transferred. Thus, according to the ruling discussed above, a common unitholder will be unable to select high or low basis common units to sell as would be the case with
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corporate stock, but, according to the Treasury Regulations, he may designate specific common units sold for purposes of determining the holding period of units transferred. A unitholder electing to use the actual holding period of common units transferred must consistently use that identification method for all subsequent sales or exchanges of common units. A unitholder considering the purchase of additional units or a sale of common units purchased in separate transactions is urged to consult his tax advisor as to the possible consequences of this ruling and application of the Treasury Regulations.
Specific provisions of the Code can affect the taxation of some financial products and securities, including partnership interests, by treating a taxpayer as having sold an "appreciated" partnership interest, one in which gain would be recognized if it were sold, assigned or terminated at its fair market value, if the taxpayer or related persons enter(s) into:
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a short sale;
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an offsetting notional principal contract; or
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in each case, with respect to the partnership interest or substantially identical property.
Moreover, if a taxpayer has previously entered into a short sale, an offsetting notional principal contract or a futures or forward contract with respect to the partnership interest, the taxpayer will be treated as having sold that position if the taxpayer or a related person then acquires the partnership interest or substantially identical property. The Secretary of the Treasury is also authorized to issue regulations that treat a taxpayer that enters into transactions or positions that have substantially the same effect as the preceding transactions as having constructively sold the financial position.
Allocations Between Transferors and Transferees
In general, our taxable income and losses will be determined annually, will be prorated on a monthly basis and will be subsequently apportioned among the unitholders in proportion to the number of units owned by each of them as of the opening of the applicable exchange on the first business day of the month, which we refer to in this prospectus as the "Allocation Date." However, gain or loss realized on a sale or other disposition of our assets other than in the ordinary course of business or, in the discretion of our general partner, any other extraordinary item of income, gain, loss or deduction will be allocated among the unitholders on the Allocation Date in the month in which such income, gain, loss or deduction is recognized. As a result, a unitholder transferring units may be allocated income, gain, loss and deduction realized after the date of transfer.
Simplifying conventions are contemplated by the Code and most publicly traded partnerships use similar simplifying conventions. The U.S. Treasury Department recently adopted final Treasury Regulations allowing a similar monthly simplifying convention. However, such final regulations do not specifically authorize the use of the proration method we have adopted. Accordingly, Baker Botts L.L.P. is unable to opine on the validity of this method of allocating income and deductions between transferee and transferor unitholders. If the IRS takes the position that this method is not allowed under the final Treasury Regulations, or that it only applies to transfers of less than all of the unitholder's interest, our taxable income or losses could be reallocated among our unitholders. We are authorized to revise our method of
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allocation between transferor and transferee unitholders, as well as among unitholders whose interests vary during a taxable year, to conform to a method permitted under future Treasury Regulations.
A unitholder who disposes of units prior to the record date set for a cash distribution for any quarter will be allocated items of our income, gain, loss and deductions attributable to the month of sale but will not be entitled to receive that cash distribution.
Notification Requirements
A unitholder who sells any of his units is generally required to notify us in writing of that sale within 30 days after the sale (or, if earlier, January 15 of the year following the sale). A purchaser of units who purchases units from another unitholder is also generally required to notify us in writing of that purchase within 30 days after the purchase. Upon receiving such notifications, we are required to notify the IRS of that transaction and to furnish specified information to the transferor and transferee. Failure to notify us of a sale may lead to the imposition of penalties. However, these reporting requirements do not apply to a sale by an individual who is a citizen of the United States and who effects the sale or exchange through a broker who will satisfy such requirements.
Constructive Termination
We will be considered to have terminated our tax partnership for federal income tax purposes upon the sale or exchange of our interests that, in the aggregate, constitute 50.0% or more of the total interests in our capital and profits within a twelve-month period. For purposes of measuring whether the 50.0% threshold is reached, multiple sales of the same interest are counted only once. A constructive termination results in the closing of our taxable year for all unitholders. In the case of a unitholder reporting on a taxable year other than a fiscal year ending December 31, the closing of our taxable year may result in more than twelve months of our taxable income or loss being includable in his taxable income for the year of termination. A constructive termination occurring on a date other than December 31 will result in us filing two tax returns (and unitholders could receive two Schedules K-1 if the relief discussed below is not available) for one fiscal year and the cost of the preparation of these returns will be borne by all unitholders. We would be required to make new tax elections after a termination, including a new election under Code Section 754, and a termination would result in a deferral of our deductions for depreciation. A termination could also result in penalties if we were unable to determine that the termination had occurred. Moreover, a termination might either accelerate the application of, or subject us to, any tax legislation enacted before the termination. The IRS recently announced a relief procedure whereby if a publicly traded partnership that has technically terminated requests publicly traded partnership technical termination relief and the IRS grants such relief, among other things, the partnership will only have to provide one Schedule K-1 to unitholders for the year notwithstanding two partnership tax years.
Because we cannot match transferors and transferees of units, we must maintain uniformity of the economic and tax characteristics of the units to a purchaser of these units. In the absence of uniformity, we may be unable to completely comply with a number of federal income tax requirements, both statutory and regulatory. Any non-uniformity could have an impact upon the value of our units. The timing of deductions attributable to Section 743(b) adjustments to the common basis of our assets with respect to persons purchasing units from another unitholder
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may affect the uniformity of our units. Please read "—Tax Consequences of Unit Ownership—Section 754 Election."
For example, some types of depreciable assets are not subject to the typical rules governing depreciation (under Code Section 168) or amortization (under Code Section 197). If we were to acquire any assets of that type, the timing of a unit purchaser's deductions with respect to Section 743(b) adjustments to the common basis of those assets might differ depending upon when and to whom the unit he purchased was originally issued. We do not currently expect to acquire any assets of that type. However, if we were to acquire a material amount of assets of that type, we intend to adopt tax positions as to those assets that will not result in any such lack of uniformity. Any such tax positions taken by us might result in allocations to some unitholders of smaller depreciation deductions than they would otherwise be entitled to receive. Baker Botts L.L.P. has not rendered an opinion with respect to those types of tax positions. Moreover, the IRS might challenge those tax positions. If we took such a tax position and the IRS successfully challenged the position, the uniformity of our units might be affected, and the gain from the sale of our units might be increased without the benefit of additional deductions. Please read "—Disposition of Common Units—Recognition of Gain or Loss."
In addition, as described above at "—Tax Consequences of Unit Ownership—Allocation of Income, Gain, Loss and Deduction," if we aggregate multiple issuances of units for purposes of making adjustments to "book" basis and related tax allocations, we will treat each of our units as having the same capital account balance, regardless of the price actually paid by each purchaser of units in the aggregated offerings. Our counsel, Baker Botts L.L.P., is unable to opine as to validity of such an approach. We do not expect the number of affected units, or the differences between the purchase price of a unit and the initial capital account balance assigned to the unit, to be material, and we do not expect this convention to have a material effect upon the trading of our units.
Tax-Exempt Organizations and Other Investors
Ownership of units by employee benefit plans, other tax-exempt organizations, non-resident aliens, foreign corporations and other foreign persons raises issues unique to those investors and, as described below to a limited extent, may have substantially adverse tax consequences to them. If you are a tax-exempt entity or a non-U.S. person, you should consult your tax advisor before investing in our units.
Employee benefit plans and most other organizations exempt from federal income tax, including individual retirement accounts and other retirement plans, are subject to federal income tax on unrelated business taxable income. Because our properties may be financed with debt, portions of our income allocated to a unitholder that is a tax-exempt organization may be unrelated business taxable income and may be taxable to it.
Non-U.S. unitholders are taxed by the United States on effectively connected income and on certain types of U.S.-source non-effectively connected income (such as dividends and royalties), unless exempted or further limited by an income tax treaty. At the time of this offering, we will only have income from our mineral, royalty and overriding royalty interests and thus should not have any effectively connected income. We may have effectively connected income in the future if we acquire working interests or otherwise engage in any active trade or business. Furthermore, it is probable that we will be deemed to conduct such activities through permanent establishments in the United States within the meaning of applicable tax treaties. Consequently, non-U.S. unitholders may be required to file federal tax returns to report their share of our
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income, gain, loss or deduction and pay federal income tax on their share of our net income or gain in a manner similar to taxable U.S. unitholders. Moreover, under rules concerning withholding on effectively connected income applicable to publicly traded partnerships, distributions to non-U.S. unitholders are subject to withholding at the highest applicable effective tax rate. Even though at the time of this offering income from our mineral, royalty and overriding royalty interests will not be effectively connected income and would otherwise be subject to withholding at a 30% or lower applicable treaty rate, we will instruct brokers and nominees to withhold on all distributions to non-U.S. unitholders at the highest applicable effective tax rate based upon the convention available to publicly traded partnerships for effectively connected income. We are authorized by our partnership agreement to adopt such conventions related to withholding as we deem appropriate; however, there can be no assurance that the IRS will not successfully challenge any withholding convention adopted by us. Non-U.S. unitholders may be entitled to a refund of all or a portion of amounts withheld and may seek to obtain such refund by filing a U.S. income tax return. Additionally, each non-U.S. unitholder that obtains a taxpayer identification number from the IRS and submits that number to our transfer agent on a Form W-8BEN, Form W-8BEN-E or applicable substitute form may obtain credit for these withholding taxes.
In addition, because a foreign corporation that owns units will be treated as engaged in a U.S. trade or business, that corporation may be subject to the U.S. branch profits tax at a rate of 30.0%, in addition to regular federal income tax, on its share of our income and gain, as adjusted for changes in the foreign corporation's "U.S. net equity," which is effectively connected with the conduct of a U.S. trade or business. That tax may be reduced or eliminated by an income tax treaty between the United States and the country in which the foreign corporate unitholder is a "qualified resident." In addition, this type of unitholder is subject to special information reporting requirements under Code Section 6038C.
A foreign unitholder who sells or otherwise disposes of a common unit will be subject to U.S. federal income tax on gain realized from the sale or disposition of that unit to the extent the gain is effectively connected with a U.S. trade or business of the foreign unitholder. Under a ruling published by the IRS interpreting the scope of "effectively connected income," a foreign unitholder would be considered to be engaged in a trade or business in the United States by virtue of the U.S. activities of the partnership, and part or all of that unitholder's gain would be effectively connected with that unitholder's indirect U.S. trade or business. Moreover, under the Foreign Investment in Real Property Tax Act, a foreign common unitholder generally will be subject to U.S. federal income tax upon the sale or disposition of a unit if (i) he owned (directly or constructively applying certain attribution rules) more than 5.0% of our common units at any time during the five-year period ending on the date of such disposition and (ii) 50.0% or more of the fair market value of all of our assets consisted of U.S. real property interests at any time during the shorter of the period during which such unitholder held our common units or the five-year period ending on the date of disposition. Currently, more than 50.0% of our assets consist of U.S. real property interests and we do not expect that to change in the foreseeable future. Therefore, foreign unitholders may be subject to federal income tax on gain from the sale or disposition of their units.
Information Returns and Audit Procedures
We intend to furnish to each unitholder, within 90 days after the close of each taxable year, specific tax information, including a Schedule K-1, which describes his share of our income,
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gain, loss and deduction for our preceding taxable year. In preparing this information, which will not be reviewed by counsel, we will take various accounting and reporting positions, some of which have been mentioned earlier, to determine each unitholder's share of income, gain, loss and deduction. We cannot assure you that those positions will yield a result that conforms to the requirements of the Code, Treasury Regulations or administrative interpretations of the IRS. Neither we nor Baker Botts L.L.P. can assure prospective unitholders that the IRS will not successfully contend in court that those positions are impermissible. Any challenge by the IRS could negatively affect the value of the units.
The IRS may audit our federal income tax information returns. Adjustments resulting from an IRS audit may require each unitholder to adjust a prior year's tax liability, and possibly may result in an audit of his return. Any audit of a unitholder's return could result in adjustments not related to our returns as well as those related to our returns.
Partnerships generally are treated as separate entities for purposes of federal tax audits, judicial review of administrative adjustments by the IRS and tax settlement proceedings. The tax treatment of partnership items of income, gain, loss and deduction are determined in a partnership proceeding rather than in separate proceedings with the partners. The Code requires that one partner be designated as the "Tax Matters Partner" for these purposes. Our partnership agreement names our general partner as our Tax Matters Partner.
The Tax Matters Partner will make some elections on our behalf and on behalf of unitholders. In addition, the Tax Matters Partner can extend the statute of limitations for assessment of tax deficiencies against unitholders for items in our returns. The Tax Matters Partner may bind a unitholder with less than a 1.0% profits interest in us to a settlement with the IRS unless that unitholder elects, by filing a statement with the IRS, not to give that authority to the Tax Matters Partner. The Tax Matters Partner may seek judicial review, by which all the unitholders are bound, of a final partnership administrative adjustment and, if the Tax Matters Partner fails to seek judicial review, judicial review may be sought by any unitholder having at least a 1.0% interest in profits or by any group of unitholders having in the aggregate at least a 5.0% interest in profits. However, only one action for judicial review will go forward, and each unitholder with an interest in the outcome may participate.
A unitholder must file a statement with the IRS identifying the treatment of any item on his federal income tax return that is not consistent with the treatment of the item on our return. Intentional or negligent disregard of this consistency requirement may subject a unitholder to substantial penalties.
Due to the recent enactment of the Bipartisan Budget Act of 2015, the audit procedures discussed above will change for partnership taxable years beginning after December 31, 2017. Please read "—Tax Consequences of Unit Ownership—Entity-Level Collections, Audits and Adjustments."
Additional Withholding Requirements
Withholding taxes may apply to certain types of payments made to "foreign financial institutions" (as specially defined in the Code) and certain other non-U.S. entities. Specifically, a 30.0% withholding tax may be imposed on interest, dividends and other fixed or determinable annual or periodical gains, profits and income from sources within the United States ("FDAP Income"), or gross proceeds from the sale or other disposition of any property of a type which can produce interest or dividends from sources within the United States ("Gross Proceeds") paid
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to a foreign financial institution or to a "non-financial foreign entity" (as specially defined in the Code), unless (i) the foreign financial institution undertakes certain diligence and reporting, (ii) the non-financial foreign entity either certifies it does not have any substantial U.S. owners or furnishes identifying information regarding each substantial U.S. owner or (iii) the foreign financial institution or non-financial foreign entity otherwise qualifies for an exemption from these rules. If the payee is a foreign financial institution and is subject to the diligence and reporting requirements in clause (i) above, it must enter into an agreement with the U.S. Treasury Department requiring, among other things, that it undertake to identify accounts held by certain U.S. persons or U.S.-owned foreign entities, annually report certain information about such accounts, and withhold 30.0% on payments to noncompliant foreign financial institutions and certain other account holders. An intergovernmental agreement between the United States and an applicable foreign country, or future Treasury Regulations, may modify these requirements.
These rules generally apply to payments of FDAP Income currently and generally will apply to payments of relevant Gross Proceeds from sales or dispositions occurring on or after January 1, 2019. Thus, to the extent we have FDAP Income or will have Gross Proceeds on or after January 1, 2019 that are not treated as effectively connected with a U.S. trade or business (please read "—Tax-Exempt Organizations and Other Investors"), unitholders who are foreign financial institutions or certain other non-U.S. entities may be subject to withholding on distributions they receive from us, or their distributive share of our income, pursuant to the rules described above.
Prospective investors should consult their own tax advisors regarding the potential application of these withholding provisions to their investment in our common units.
Nominee Reporting
Persons who hold an interest in us as a nominee for another person are required to furnish to us:
- •
-
the name, address and taxpayer identification number of the beneficial owner and the nominee;
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-
a statement regarding whether the beneficial owner is:
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-
a person that is not a U.S. person;
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a foreign government, an international organization or any wholly-owned agency or instrumentality of either of the
foregoing; or
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-
a tax-exempt entity;
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the amount and description of units held, acquired or transferred for the beneficial owner; and
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- specific information including the dates of acquisitions and transfers, means of acquisitions and transfers, and acquisition cost for purchases, as well as the amount of net proceeds from sales.
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Brokers and financial institutions are required to furnish additional information, including whether they are U.S. persons and specific information on units they acquire, hold or transfer for their own account. A penalty of $250 per failure, up to a maximum of $3 million per calendar year, is imposed for failure to report that information to us. The nominee is required to supply the beneficial owner of the units with the information furnished to us.
Accuracy-Related Penalties
An additional tax equal to 20.0% of the amount of any portion of an underpayment of tax that is attributable to one or more specified causes, including negligence or disregard of rules or regulations, substantial understatements of income tax and substantial valuation misstatements, is imposed by the Code. No penalty will be imposed, however, for any portion of an underpayment if it is shown that there was a reasonable cause for that portion and that the taxpayer acted in good faith regarding that portion.
For individuals, a substantial understatement of income tax in any taxable year exists if the amount of the understatement exceeds the greater of 10.0% of the tax required to be shown on the return for the taxable year or $5,000 ($10,000 for most corporations). The amount of any understatement subject to penalty generally is reduced if any portion is attributable to a position adopted on the return:
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for which there is, or was, "substantial authority"; or
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- as to which there is a reasonable basis and the pertinent facts of that position are disclosed on the return.
If any item of income, gain, loss or deduction included in the distributive shares of unitholders might result in that kind of an "understatement" of income for which no "substantial authority" exists, we must disclose the pertinent facts on our return. In addition, we will make a reasonable effort to furnish sufficient information for unitholders to make adequate disclosure on their returns and to take other actions as may be appropriate to permit unitholders to avoid liability for this penalty. More stringent rules apply to "tax shelters," which we do not believe includes us, or any of our investments, plans or arrangements.
A substantial valuation misstatement exists if (i) the value of any property, or the adjusted basis of any property, claimed on a tax return is 150.0% or more of the amount determined to be the correct amount of the valuation or adjusted basis, (ii) the price for any property or services (or for the use of property) claimed on any such return with respect to any transaction between persons described in Code Section 482 is 200.0% or more (or 50.0% or less) of the amount determined under Code Section 482 to be the correct amount of such price, or (iii) the net Section 482 transfer price adjustment for the taxable year exceeds the lesser of $5 million or 10.0% of the taxpayer's gross receipts. No penalty is imposed unless the portion of the underpayment attributable to a substantial valuation misstatement exceeds $5,000 ($10,000 for most corporations). If the valuation claimed on a return is 200.0% or more than the correct valuation or certain other thresholds are met, the penalty imposed increases to 40.0%. We do not anticipate making any valuation misstatements.
In addition, the 20.0% accuracy-related penalty also applies to any portion of an underpayment of tax that is attributable to transactions lacking economic substance. To the extent that such transactions are not disclosed, the penalty imposed is increased to 40.0%.
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Additionally, there is no reasonable cause defense to the imposition of this penalty to such transactions.
Reportable Transactions
If we were to engage in a "reportable transaction," we (and possibly you and others) would be required to make a detailed disclosure of the transaction to the IRS. A transaction may be a reportable transaction based upon any of several factors, including the fact that it is a type of tax avoidance transaction publicly identified by the IRS as a "listed transaction" or that it produces certain kinds of losses for partnerships, individuals, S corporations, and trusts in excess of $2 million in any single year, or $4 million in any combination of six successive tax years. Our participation in a reportable transaction could increase the likelihood that our federal income tax information return (and possibly your tax return) would be audited by the IRS. Please read "—Information Returns and Audit Procedures."
Moreover, if we were to participate in a reportable transaction with a significant purpose to avoid or evade tax, or in any listed transaction, you may be subject to the following additional consequences:
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accuracy-related penalties with a broader scope, significantly narrower exceptions, and potentially greater amounts than described
above at "—Accuracy-Related Penalties";
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for those persons otherwise entitled to deduct interest on federal tax deficiencies, nondeductibility of interest on any resulting tax
liability; and
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- in the case of a listed transaction, an extended statute of limitations.
We do not expect to engage in any "reportable transactions."
State, Local, Foreign and Other Tax Considerations
In addition to federal income taxes, you likely will be subject to other taxes, such as state, local and foreign income taxes, unincorporated business taxes, and estate, inheritance or intangible taxes that may be imposed by the various jurisdictions in which we do business or own property or in which you are a resident. We currently do business or own property in 20 states, most of which impose personal income taxes on individuals. Most of these states also impose an income or gross receipts tax on corporations and other entities. Moreover, we may also own property or do business in other states in the future that impose income or similar taxes on nonresident individuals. Although an analysis of those various taxes is not presented here, each prospective unitholder should consider their potential impact on his investment in us.
A unitholder may be required to file income tax returns and to pay income taxes in many of these jurisdictions in which we do business or own property and may be subject to penalties for failure to comply with those requirements. In some jurisdictions, tax losses may not produce a tax benefit in the year incurred and may not be available to offset income in subsequent taxable years. Some of the jurisdictions may require us, or we may elect, to withhold a percentage of income from amounts to be distributed to a unitholder who is not a resident of the jurisdiction. Withholding, the amount of which may be greater or less than a particular unitholder's income tax liability to the jurisdiction, generally does not relieve a nonresident unitholder from the obligation to file an income tax return. Amounts withheld will be treated as if distributed to
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unitholders for purposes of determining the amounts distributed by us. Please read "—Tax Consequences of Unit Ownership—Entity-Level Collections, Audits and Adjustments." Based on current law and our estimate of our future operations, our general partner anticipates that any amounts required to be withheld will not be material.
It is the responsibility of each unitholder to investigate the legal and tax consequences, under the laws of pertinent jurisdictions, of his investment in us. Accordingly, each prospective unitholder is urged to consult, and depend upon, his tax counsel or other advisor with regard to those matters. Further, it is the responsibility of each unitholder to file all state, local and foreign, as well as U.S. federal tax returns, that may be required of him. Baker Botts L.L.P. has not rendered an opinion on the state, local or foreign tax consequences of an investment in us.
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INVESTMENT IN KIMBELL ROYALTY PARTNERS, LP BY EMPLOYEE BENEFIT PLANS
An investment in us by an employee benefit plan is subject to additional considerations because the investments of these plans are subject to the fiduciary responsibility and prohibited transaction provisions of ERISA, restrictions imposed by Section 4975 of the Code, and/or provisions under any federal, state, local, non- U.S. or other laws or regulations that are similar to such provisions of the Code or ERISA (collectively, "Similar Laws"). For these purposes the term "employee benefit plan" includes, but is not limited to, qualified pension, profit-sharing and stock bonus plans, Keogh plans, simplified employee pension plans and tax deferred annuities or IRAs and entities whose underlying assets are considered to include "plan assets" of such plans, accounts or arrangements. In considering an investment in our common units, among other things, consideration should be given to:
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whether the investment is prudent under Section 404(a)(1)(B) of ERISA and any other applicable Similar Laws;
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whether in making the investment, the plan will satisfy the diversification requirements of Section 404(a)(1)(C) of ERISA and
any other applicable Similar Laws;
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whether the investment is permitted under the terms of the applicable documents governing the employee benefit plan;
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whether in making the investment, the employee benefit plan will be considered to hold, as plan assets, (1) only the investment
in our common units or (2) an undivided interest in our underlying assets;
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whether the investment will result in recognition of unrelated business taxable income by the plan and, if so, the potential after-tax
investment return. Please read "Material U.S. Federal Income Tax Consequences—Tax-Exempt Organizations and Other Investors"; and
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- whether making such an investment will comply with the delegation of control and prohibited transaction provisions of ERISA, the Code and any other applicable Similar Laws.
The person with investment discretion with respect to the assets of an employee benefit plan, often called a fiduciary, should determine whether an investment in us is authorized by the appropriate governing instrument and is a proper investment for the plan.
Section 406 of ERISA and Section 4975 of the Code prohibit employee benefit plans from engaging in specified transactions involving "plan assets" with parties that are "parties in interest" under ERISA or "disqualified persons" under the Code with respect to the employee benefit plan, unless an exemption is applicable. A party in interest or disqualified person who engages in a non-exempt prohibited transaction may be subject to excise taxes and other penalties and liabilities under ERISA and the Code. In addition, the fiduciary of the ERISA plan that engaged in such a non-exempt prohibited transaction may be subject to excise taxes, penalties and liabilities under ERISA and the Code.
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In addition to considering whether the purchase of common units is a prohibited transaction, a fiduciary of an employee benefit plan should consider whether the plan will, by investing in us, be deemed to own an undivided interest in our assets, with the result that our operations would be subject to the regulatory restrictions of ERISA, including its prohibited transaction rules, as well as the prohibited transaction rules of the Code and any other applicable Similar Laws.
The U.S. Department of Labor regulations provide guidance with respect to whether the assets of an entity in which employee benefit plans acquire equity interests would be deemed "plan assets" under some circumstances. Under these regulations, an entity's assets would not be considered to be "plan assets" if, among other things:
(1) the equity interests acquired by employee benefit plans are publicly offered securities—i.e., the equity interests are widely held by 100 or more investors independent of the issuer and each other, freely transferable and registered under some provisions of the federal securities laws;
(2) the entity is an "operating company"—i.e., it is primarily engaged in the production or sale of a product or service other than the investment of capital either directly or through a majority-owned subsidiary or subsidiaries; or
(3) there is no significant investment by benefit plan investors, which is defined to mean that less than 25% of the value of each class of equity interest is held by the employee benefit plans referred to above.
The foregoing discussion of issues arising for employee benefit plan investments under ERISA, the Code and applicable Similar Laws is general in nature and is not intended to be all inclusive, nor should it be construed as legal advice. Plan fiduciaries contemplating a purchase of common units should consult with their own counsel regarding the consequences under ERISA, the Code and any other applicable Similar Laws in light of the serious penalties imposed on persons who engage in prohibited transactions or other violations.
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Raymond James & Associates, Inc., RBC Capital Markets, LLC and Stifel, Nicolaus & Company, Incorporated are acting as representatives of each of the underwriters named below. Subject to the terms and conditions set forth in an underwriting agreement among us and the underwriters, dated the date of this prospectus, we have agreed to sell to the underwriters, and each of the underwriters has agreed, severally and not jointly, to purchase from us the number of common units set forth opposite its name below:
| Underwriters |
Number of
Common Units |
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|---|---|---|---|---|
|
Raymond James & Associates, Inc. |
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RBC Capital Markets, LLC |
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Stifel, Nicolaus & Company, Incorporated |
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Stephens Inc. |
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Wunderlich Securities, Inc. |
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| | | | | |
|
Total |
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| | | | | |
| | | | | |
| | | | | |
The underwriting agreement provides that the obligations of the underwriters to purchase and accept delivery of our common units offered by this prospectus are subject to approval by their counsel of certain legal matters and to certain other customary conditions set forth in the underwriting agreement.
The underwriters are obligated to purchase and accept delivery of all of our common units offered by this prospectus, if any of our common units are purchased, other than those covered by the underwriters' purchase option described below.
The underwriters initially propose to offer our common units directly to the public at the public offering price listed on the cover page of this prospectus and to various dealers at that price less a concession not in excess of $ per common unit. After the public offering of our common units, the underwriters may change the public offering price and other selling terms. Our common units are offered by the underwriters as stated in this prospectus, subject to receipt and acceptance by them. The underwriters reserve the right to reject an order for the purchase of our common units in whole or in part.
Option to Purchase Additional Common Units
We have granted the underwriters an option, exercisable for 30 days from the date of this prospectus, to purchase up to an aggregate of additional common units from us at the public offering price set forth on the cover page of this prospectus, less underwriting discounts and commissions. If the underwriters exercise this option, each underwriter, subject to certain conditions, will become obligated to purchase approximately the same percentage of these additional units as the number listed next to the underwriter's name in the preceding table bears to the total number of common units listed next to the names of all underwriters in the preceding table.
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The following table shows the amount per common unit and total underwriting discount that we will pay to the underwriters and the proceeds to us before expenses. These amounts are shown assuming both no exercise and full exercise of the underwriters' option to purchase additional common units.
|
|
Per Common
Unit |
No Exercise | Full Exercise | |||||||
|---|---|---|---|---|---|---|---|---|---|---|
|
Initial public offering price |
$ | $ | $ | |||||||
|
Underwriting discount |
$ | $ | $ | |||||||
|
Proceeds (before expenses) to us |
$ | $ | $ | |||||||
We will pay Raymond James & Associates, Inc. a structuring fee of $ million (or $ million if the underwriters exercise their option to purchase additional common units in full) for evaluation, analysis and structuring of the partnership. We have also agreed to reimburse the underwriters for up to $20,000 of reasonable fees and expenses of counsel related to the review by the Financial Industry Regulatory Authority ("FINRA") of the terms of sale of the common units offered hereby.
The other offering expenses that are payable by us are estimated to be $ million (exclusive of the underwriting discount and structuring fee).
We, our general partner and certain of its affiliates have agreed to indemnify the underwriters against various liabilities that may arise in connection with this offering and in connection with the directed unit program referred to below, including liabilities under the Securities Act for errors or omissions in this prospectus or the registration statement of which this prospectus is a part. However, we will not indemnify the underwriters if the error or omission was the result of information the underwriters supplied in writing for inclusion in this prospectus or the registration statement.
Subject to specified exceptions, we, our general partner, executive officers and directors of our general partner, our Sponsors, certain of the Contributing Parties and certain individuals who purchase common units in our directed unit program have agreed with the underwriters, for a period of 180 days after the date of this prospectus, not to directly or indirectly offer, sell, contract to sell or otherwise dispose of or transfer any common units or any securities convertible into or exchangeable for common units without the prior written consent of the representatives. These agreements also preclude any hedging collar or other transaction designed or reasonably expected to result in a disposition of common units or securities convertible into or exercisable or exchangeable for common units. The representatives may, in their sole discretion and at any time without notice, release all or any portion of the securities subject to these agreements. The representatives do not have any present intent or any understanding to release all or any portion of the securities subject to these agreements.
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Until this offering is completed, SEC rules may limit the ability of the underwriters and certain selling group members to bid for and purchase our common units. As an exception to these rules and in accordance with Regulation M of the Exchange Act, the underwriters may engage in certain transactions that stabilize, maintain or otherwise affect the price of our common units in order to facilitate the offering of our common units, including:
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stabilizing transactions;
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short sales; and
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- purchases to cover positions created by short sales.
Stabilizing transactions may include making short sales of common units, which involve the sale by the underwriters of a greater number of common units than it is required to purchase in this offering and purchasing common units from us by exercising their option to purchase additional common units or in the open market to cover positions created by short sales. Short sales may be "covered" shorts, which are short positions in an amount not greater than the underwriters' purchase option referred to above, or may be "naked" shorts, which are short positions in excess of that amount.
The underwriters may close out any covered short position by exercising their option to purchase additional common units or by purchasing common units in the open market after the distribution has been completed. In making this determination, the underwriters will consider, among other things, the price of common units available for purchase in the open market.
A naked short position is more likely to be created if the underwriters are concerned that there may be downward pressure on the price of our common units in the open market after pricing that could adversely affect investors who purchased in this offering. To the extent that the underwriters create a naked short position, they will purchase common units in the open market to cover the position after the pricing of this offering.
The underwriters may also reclaim selling concessions allowed to an underwriter or a dealer for distributing our common units in the offering, if the syndicate repurchases previously distributed common units to cover syndicate short positions or to stabilize the price of our common units. These activities may raise or maintain the market price of our common units above independent market levels or prevent or retard a decline in market price of our common units.
As a result of these activities, the price of our common units may be higher than the price that otherwise might exist in the open market. The underwriters are not required to engage in these activities. If these activities are commenced, they may discontinue them without notice at any time. The underwriters may carry out these transactions on the NYSE or otherwise.
The underwriters and their respective affiliates are full service financial institutions engaged in various activities, which may include securities trading, commercial and investment banking, financial advisory, investment management, investment research, principal investment, hedging, financing, valuation and brokerage activities. From time to time, the underwriters and/or their respective affiliates have directly and indirectly engaged, or may engage, in various financial
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advisory, investment banking and commercial banking and other services for us and our affiliates in the ordinary course of their business, for which they have received, or may receive, customary compensation, fees, commissions and expense reimbursement.
In the ordinary course of their business activities, the underwriters and their affiliates may make or hold a broad array of investments and actively trade debt and equity securities (or related derivative securities) and financial instruments (including bank loans) for their own account and for the accounts of their customers. Such investments and securities activities may involve securities and/or instruments of ours or our affiliates. The underwriters and their affiliates may also make investment recommendations and/or publish or express independent research views in respect of such securities or financial instruments and may hold, or recommend to clients that they acquire, long and/or short positions in such securities and instruments.
The underwriters may confirm sales of the common units offered by this prospectus to accounts over which they exercise discretionary authority but do not expect those sales to exceed 5% of the total common units offered by this prospectus.
At our request, the underwriters have reserved up to 10% of the common units being offered by this prospectus (excluding the common units that may be issued upon the underwriters' exercise of their option to purchase additional common units) for sale at the initial public offering price to directors and officers of our general partner, the Contributing Parties and their affiliates, individuals providing services to us and certain other persons associated with us. The sales will be made by Raymond James & Associates, Inc. through a directed unit program. It is not certain if these persons will choose to purchase all or any portion of these reserved units, but any purchases they make will reduce the number of common units available for sale to the general public. Any reserved units not so purchased will be offered by the underwriters to the general public on the same basis as the other common units offered by this prospectus. The individuals eligible to participate in the directed unit program must commit to purchase no later than before the opening of business on the day following the date of this prospectus. We, our general partner and certain of its affiliates have agreed to indemnify Raymond James & Associates, Inc. against certain liabilities and expenses in connection with the directed unit program, including liabilities under the Securities Act in connection with the sale of the reserved units and for the failure of any participant to pay for its common units.
We have been approved to list our common units on the NYSE, subject to official notice of issuance, under the symbol "KRP." In connection with the listing of our common units on the NYSE, the underwriters will undertake to sell round lots of 100 units or more to a minimum of 400 beneficial owners.
Determination of Initial Offering Price
Prior to this offering, there has been no public market for our common units. Consequently, the initial public offering price for our common units will be determined by negotiations among
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us and the underwriters. The primary factors to be considered in determining the initial public offering price will be:
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estimates of distributions to our unitholders;
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-
overall quality of our properties and operations;
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industry and market conditions prevalent in our industry;
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-
the information set forth in this prospectus and otherwise available to the representatives; and
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- the general conditions of the securities markets at the time of this offering.
A prospectus in electronic format may be made available by e-mail or on the websites or through other online services maintained by one or more of the underwriters or their affiliates. In those cases, prospective investors may view offering terms online and may be allowed to place orders online. The underwriters may agree with us to allocate a specific number of common units for sale to online brokerage account holders. Any such allocation for online distributions will be made by the representatives on the same basis as other allocations.
Other than the prospectus in electronic format, the information on the underwriters' websites and any information contained on any other website maintained by any of the underwriters is not part of this prospectus or the registration statement of which this prospectus forms a part, has not been approved or endorsed by the underwriters or us and should not be relied upon by investors.
Because FINRA is expected to view the common units offered hereby as interests in a direct participation program, this offering is being made in compliance with Rule 2310 of the FINRA Conduct Rules. Investor suitability with respect to our common units should be judged similarly to the suitability with respect to other securities that are listed for trading on a national securities exchange.
This prospectus does not constitute an offer to sell to, or a solicitation of an offer to buy from, anyone in any country or jurisdiction (i) in which such an offer or solicitation is not authorized, (ii) in which any person making such offer or solicitation is not qualified to do so or (iii) in which any such offer or solicitation would otherwise be unlawful. No action has been taken that would, or is intended to, permit a public offer of our common units or possession or distribution of this prospectus or any other offering or publicity material relating to our common units in any country or jurisdiction (other than the United States) where any such action for that purpose is required. Accordingly, each underwriter has undertaken that it will not, directly or indirectly, offer or sell any common units or have in its possession, distribute or publish any prospectus, form of application, advertisement or other document or information in any country or jurisdiction except under circumstances that will, to the best of its knowledge and belief, result in compliance with any applicable laws and regulations and all offers and sales of common units by it will be made on the same terms.
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The validity of our common units and certain other legal matters will be passed upon for us by Baker Botts L.L.P., Houston, Texas. Certain legal matters in connection with this offering will be passed upon for the underwriters by Latham & Watkins LLP, Houston, Texas.
The audited financial statements of Kimbell Royalty Partners, LP included in this prospectus and elsewhere in the registration statement have been so included in reliance upon the report of Grant Thornton LLP, independent registered public accountants, upon the authority of said firm as experts in accounting and auditing.
The audited financial statements of Rivercrest Royalties, LLC included in this prospectus and elsewhere in the registration statement have been so included in reliance upon the report of Grant Thornton LLP, independent registered public accountants, upon the authority of said firm as experts in accounting and auditing.
The audited statements of revenues and direct operating expenses of certain oil and gas properties owned by the Kimbell Art Foundation included in this prospectus and elsewhere in the registration statement have been so included in reliance upon the report of Grant Thornton LLP, independent certified public accountants, upon the authority of said firm as experts in accounting and auditing.
The audited statements of revenues and direct operating expenses of certain oil and gas properties owned by Trunk Bay Royalty Partners, Ltd., Oil Nut Bay Royalties, LP, Gorda Sound Royalties, LP and Bitter End Royalties, LP included in this prospectus and elsewhere in the registration statement have been so included in reliance upon the report of Grant Thornton LLP, independent certified public accountants, upon the authority of said firm as experts in accounting and auditing.
The audited statements of revenues and direct operating expenses of certain oil and gas properties owned by RCPTX, Ltd. included in this prospectus and elsewhere in the registration statement have been so included in reliance upon the report of Grant Thornton LLP, independent certified public accountants, upon the authority of said firm as experts in accounting and auditing.
The audited statements of revenues and direct operating expenses of certain oil and gas properties owned by French Capital Partners, Ltd. included in this prospectus and elsewhere in the registration statement have been so included in reliance upon the report of Grant Thornton LLP, independent certified public accountants, upon the authority of said firm as experts in accounting and auditing.
Information included in this prospectus regarding our estimated quantities of oil and natural gas reserves as of December 31, 2015 and the discounted present value of future net cash flows therefrom is based upon estimates of such reserves and present values prepared by Ryder Scott Company, L.P., an independent petroleum engineering firm. This information is included herein in reliance upon the authority of said firm as experts in these matters.
231
WHERE YOU CAN FIND MORE INFORMATION
We have filed with the SEC a registration statement on Form S-1 (including the exhibits, schedules and amendments thereto) under the Securities Act with respect to our common units being offered hereunder. This prospectus does not contain all of the information set forth in the registration statement and the exhibits and schedules to the registration statement. For further information with respect to us and our common units, we refer you to the registration statement and the exhibits filed as a part of the registration statement. Statements contained in this prospectus concerning the contents of any contract or any other documents are not necessarily complete. If a contract or document has been filed as an exhibit to the registration statement, we refer you to the copy of the contract or document that has been filed as an exhibit and reference thereto is qualified in all respects by the terms of the filed exhibit. The registration statement, including any exhibits and schedules, may be inspected without charge at the Public Reference Room of the SEC at 100 F Street, N.E., Washington, D.C. 20549, and copies of these materials may be obtained from that office after payment of fees prescribed by the SEC. Information on the operation of the Public Reference Room may be obtained by calling the SEC at 1-800- SEC-0330. The SEC maintains a web site that contains reports, proxy and information statements and other information regarding registrants that file electronically with the SEC at http://www.sec.gov.
As a result of this offering, we will become subject to the full informational requirements of the Exchange Act. We will fulfill our obligations with respect to such requirements by filing period reports and other information with the SEC.
232
This prospectus contains forward-looking statements. Forward-looking statements give our current expectations, contain projections of results of operations or of financial condition, or forecasts of future events. Words such as "may," "assume," "forecast," "position," "predict," "strategy," "expect," "intend," "plan," "estimate," "anticipate," "believe," "project," "budget," "potential," or "continue," and similar expressions are used to identify forward-looking statements. They can be affected by assumptions used or by known or unknown risks or uncertainties. Consequently, no forward-looking statements can be guaranteed. When considering these forward-looking statements, you should keep in mind the risk factors and other cautionary statements in this prospectus. Actual results may vary materially. You are cautioned not to place undue reliance on any forward-looking statements. You should also understand that it is not possible to predict or identify all such factors and should not consider the following list to be a complete statement of all potential risks and uncertainties. Factors that could cause our actual results to differ materially from the results contemplated by such forward-looking statements include:
- •
-
our ability to execute our business strategies;
- •
-
the volatility of realized prices for oil, natural gas and natural gas liquids;
- •
-
the level of production on our properties;
- •
-
the level of drilling and completion activity by the operators of our properties;
- •
-
regional supply and demand factors, delays or interruptions of production;
- •
-
our ability to replace our reserves;
- •
-
our ability to identify and complete acquisitions of assets or businesses;
- •
-
general economic, business or industry conditions;
- •
-
competition in the oil and natural gas industry;
- •
-
the ability of the operators of our properties to obtain capital or financing needed for development and exploration operations;
- •
-
title defects in the properties in which we invest;
- •
-
uncertainties with respect to identified drilling locations and estimates of reserves;
- •
-
the availability or cost of rigs, completion crews, equipment, raw materials, supplies, oilfield services or personnel;
- •
-
restrictions on or the availability of the use of water in the business of the operators of our properties;
- •
- the availability of transportation facilities;
233
- •
-
the ability of the operators of our properties to comply with applicable governmental laws and regulations and to obtain permits and
governmental approvals;
- •
-
federal and state legislative and regulatory initiatives relating to the environment, hydraulic fracturing and other matters affecting
the oil and gas industry;
- •
-
future operating results;
- •
-
exploration and development drilling prospects, inventories, projects and programs;
- •
-
operating hazards faced by the operators of our properties;
- •
-
the ability of the operators of our properties to keep pace with technological advancements; and
- •
- certain factors discussed elsewhere in this prospectus.
All forward-looking statements are expressly qualified in their entirety by the foregoing cautionary statements.
234
F-1
F-2
Unaudited Pro Forma Condensed Combined Financial Statements
The following unaudited pro forma condensed combined balance sheet of Kimbell Royalty Partners, LP as of September 30, 2016 and the unaudited pro forma condensed combined statements of operations of Kimbell Royalty Partners, LP for the nine months ended September 30, 2016 and for the year ended December 31, 2015 are based on (i) the unaudited financial statements as of and for the nine months ended September 30, 2016 and the audited financial statements for the year ended December 31, 2015 of Rivercrest Royalties, LLC, our predecessor for accounting purposes, and (ii) the unaudited statements of combined revenues and direct operating expenses of oil and gas properties as of and for the nine months ended September 30, 2016 and the audited statements of revenues and direct operating expenses of oil and gas properties for the year ended December 31, 2015 of the Kimbell Art Foundation, Trunk Bay Royalty Partners, Ltd., Oil Nut Bay Royalties LP, Gorda Sound Royalties, LP and Bitter End Royalties, LP, RCPTX, Ltd., and French Capital Partners, Ltd.
The unaudited pro forma condensed combined statement of operations for the nine months ended September 30, 2016 and for the year ended December 31, 2015 and the unaudited pro forma condensed combined balance sheet as of September 30, 2016 have been prepared to reflect the pro forma formation transactions (defined below). The pro forma financial data is presented as if the pro forma formation transactions had occurred on September 30, 2016 for the purposes of the unaudited pro forma condensed combined balance sheet and on January 1, 2015 for the purposes of the unaudited pro forma condensed combined statements of operations.
The unaudited pro forma adjustments are based on preliminary estimates, accounting judgments and currently available information and assumptions that management believes are reasonable. The notes to the unaudited pro forma condensed combined statements provide a detailed discussion of how such adjustments were derived and presented in the unaudited pro forma financial information. The unaudited pro forma condensed combined financial information should be read in conjunction with "Capitalization," "Use of Proceeds," "Selected Historical and Unaudited Pro Forma Financial Data" and "Management's Discussion and Analysis of Financial Condition and Results of Operations."
The unaudited pro forma condensed combined financial information has been prepared to reflect adjustments to our historical financial information that are (i) directly attributable to this offering and (ii) factually supportable, and with respect to the unaudited pro forma condensed combined statement of operations, expected to have a continuing impact on our results.
These transactions include (collectively, the "pro forma formation transactions"):
- •
-
The assignment by our predecessor and associated entities to certain of their affiliates of certain non-operated working interests and
net profits interests that will not be contributed to us;
- •
-
Our acquisition of assets to be contributed by our predecessor and the Kimbell Art Foundation, Trunk Bay Royalty
Partners, Ltd., Oil Nut Bay Royalties, LP, Gorda Sound Royalties, LP and Bitter End Royalties, LP, RCPTX, Ltd., and French Capital Partners, Ltd. (but not by the
other Contributing Parties);
- •
- The issuance by us of an aggregate of common units to all of the Contributing Parties;
F-3
- •
-
The issuance by us of common units
to the public in this offering at an assumed initial price of $ per
common unit, which is the mid-point of the ranges set forth on the cover of the prospectus;
- •
-
The use of the net proceeds from this offering as set forth in "Use of Proceeds";
- •
-
Our expected entrance into a new $50.0 million secured revolving credit facility with an accordion feature permitting aggregate
commitments under the facility to be increased up to $100.0 million (subject to the satisfaction of certain conditions and the procurement of additional commitments from new or existing
lenders), pursuant to which we expect to borrow approximately $1.5 million at the closing of this offering to fund certain transaction expenses; and
- •
- Our entrance into a management services agreement with Kimbell Operating Company, LLC ("Kimbell Operating"), which will enter into separate service agreements with certain entities controlled by Messrs. Duncan, R. Ravnaas, Taylor and Wynne.
The unaudited pro forma condensed combined statements of operations do not give pro forma effect to our acquisition of assets to be contributed by the Contributing Parties other than our predecessor, the Kimbell Art Foundation, Trunk Bay Royalty Partners, Ltd., Oil Nut Bay Royalties, LP, Gorda Sound Royalties, LP and Bitter End Royalties, LP, RCPTX, Ltd., and French Capital Partners, Ltd., which excluded assets represent approximately 25% of our future undiscounted cash flows, based on a reserve report prepared by Ryder Scott as of December 31, 2015.
The unaudited pro forma condensed combined statements of operations do not include certain non-recurring items that we expect to incur in connection with the pro forma formation transactions, including costs related to legal, accounting, and consulting services. We have incurred costs totaling approximately $0.4 million for transaction-related services during the nine months ended September 30, 2016 and approximately $0.5 million for the year ended December 31, 2015 relating to the acquisition of assets contributed by the Kimbell Art Foundation, Trunk Bay Royalty Partners, Ltd., Oil Nut Bay Royalties, LP, Gorda Sound Royalties, LP and Bitter End Royalties, LP, RCPTX, Ltd., and French Capital Partners, Ltd. and this offering.
Upon completion of this offering, we anticipate incurring incremental general and administrative expenses of approximately $1.5 million per year as a result of becoming a publicly traded partnership, including expenses associated with SEC reporting requirements, including annual and quarterly reports to unitholders, tax return and Schedule K-1 preparation and distribution expenses, Sarbanes-Oxley Act compliance expenses, expenses associated with listing on the NYSE, independent auditor fees, independent reserve engineer fees, legal fees, investor relations expenses, registrar and transfer agent fees, director and officer insurance expenses and director and officer compensation expenses. The unaudited pro forma condensed combined financial statements do not reflect these incremental general and administrative expenses.
The unaudited pro forma condensed combined financial statements included in this registration statement do not purport to represent what our financial position and results of operations would have been had this offering and the acquisition of assets contributed by the Kimbell Art Foundation, Trunk Bay Royalty Partners, Ltd., Oil Nut Bay Royalties, LP, Gorda Sound Royalties, LP and Bitter End Royalties, LP, RCPTX, Ltd., and French Capital Partners, Ltd. occurred on the dates indicated or to project our financial performance for any future period. A number of factors may affect our results. Please read "Risk Factors" and "Forward-Looking Statements" for information regarding statements that do not relate strictly to historical or current facts and certain risks inherent in our business.
F-4
KIMBELL ROYALTY PARTNERS, LP
UNAUDITED PRO FORMA CONDENSED COMBINED BALANCE SHEET
As of September 30, 2016
|
|
Predecessor
Entity |
Acquisition
Adjustments |
Equity
Offering and Other Pro Forma Adjustments |
Pro Forma | |||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
|
Assets |
|||||||||||||
|
Current assets |
|||||||||||||
|
Cash and cash equivalents |
$ | 679,635 | $ | (39,014,000) | (A) | $ | (C)(D)(E) | $ | |||||
|
Oil, natural gas and NGL revenues receivable |
396,390 | (6,856) | (B) | (B) | |||||||||
|
Other receivables |
125,271 | — | (B) | (B) | |||||||||
| | | | | | | | | | | | | | |
|
Total current assets |
1,201,296 | (39,020,856 | ) | ||||||||||
|
Property and equipment, net |
278,728 | — | |||||||||||
|
Oil and natural gas properties, at cost |
|||||||||||||
|
Oil, natural gas and NGL properties (full cost method) |
70,885,845 | 195,070,000 | (A) | ||||||||||
|
|
(2,351,379) | (B) | |||||||||||
|
Less: accumulated depreciation, depletion, accretion and impairment |
(51,606,906 | ) | 1,462,810 | (B) | |||||||||
| | | | | | | | | | | | | | |
|
Total oil, natural gas and NGL properties |
19,278,939 | 194,181,431 | |||||||||||
|
Loan origination costs, net |
25,770 | — | |||||||||||
| | | | | | | | | | | | | | |
|
Total assets |
$ | 20,784,733 | $ | 155,160,575 | $ | $ | |||||||
| | | | | | | | | | | | | | |
| | | | | | | | | | | | | | |
| | | | | | | | | | | | | | |
|
Liabilities and equity |
|||||||||||||
|
Current liabilities |
|||||||||||||
|
Accounts payable |
$ | 912,209 | $ | (4,714) | (B) | $ | $ | ||||||
|
Other current liabilities |
125,517 | — | (B) | ||||||||||
|
Asset retirement obligation, current portion |
27,013 | (27,013) | (B) | ||||||||||
| | | | | | | | | | | | | | |
|
Total current liabilities |
1,064,739 | (31,727 | ) | ||||||||||
|
Asset retirement obligation, net of current portion |
14,181 | (14,181) | (B) | ||||||||||
|
Other liabilities |
131,750 | — | |||||||||||
|
Long-term debt |
10,898,860 | — | (C)(D) | ||||||||||
| | | | | | | | | | | | | | |
|
Total liabilities |
12,109,530 | (45,908 | ) | ||||||||||
|
Commitments and contingencies |
— | ||||||||||||
|
Equity |
|||||||||||||
|
Members' equity |
8,675,203 | (849,517) | (B) | (B)(F) | |||||||||
|
|
|||||||||||||
|
General partner |
— | — | |||||||||||
|
Common units |
— | 156,056,000 | (A) | (E)(F) | |||||||||
|
|
|||||||||||||
| | | | | | | | | | | | | | |
|
Total liabilities and equity |
$ | 20,784,733 | $ | 155,160,575 | $ | $ | |||||||
| | | | | | | | | | | | | | |
| | | | | | | | | | | | | | |
| | | | | | | | | | | | | | |
See the accompanying Notes to Unaudited Pro Forma Condensed Combined Financial Statements.
F-5
KIMBELL ROYALTY PARTNERS, LP
UNAUDITED PRO FORMA CONDENSED COMBINED STATEMENT OF OPERATIONS
For the Nine Months Ended September 30, 2016
|
|
Predecessor
Entity |
Kimbell Art
Foundation |
Trunk Bay
Royalty Partners, Ltd. (1) |
RCPTX, Ltd. |
French
Capital Partners, Ltd. |
Acquisition
Adjustments |
Equity
Offering and Other Pro Forma Adjustments |
Pro
Forma |
|||||||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
|
Oil, natural gas and NGL revenues |
$ | 2,572,477 | $ | 5,624,706 | (J) | $ | 3,734,486 | (J) | $ | 1,877,122 | (J) | $ | 1,686,221 | (J) | $ | (140,554) | (B) | $ | — | $ | 15,354,458 | ||||
| | | | | | | | | | | | | | | | | | | | | | | | | | |
|
Total revenues |
2,572,477 | 5,624,706 | 3,734,486 | 1,877,122 | 1,686,221 | (140,554 | ) | — | 15,354,458 | ||||||||||||||||
| | | | | | | | | | | | | | | | | | | | | | | | | | |
|
Costs and expenses |
|||||||||||||||||||||||||
|
Production and ad valorem taxes |
203,567 | — | — | — | — | (44,690) | (B) | — | 1,284,194 | ||||||||||||||||
|
|
1,125,317 | (I) | |||||||||||||||||||||||
|
Depreciation, depletion and accretion expenses |
1,244,023 | — | — | — | — | 8,353,518 | (A) | — | 9,586,455 | ||||||||||||||||
|
|
(11,086) | (B) | |||||||||||||||||||||||
|
Impairment of oil and natural gas properties |
4,992,897 | — | — | — | — | (10,158) | (B) | — | 4,982,739 | ||||||||||||||||
|
Marketing and other deductions (2) |
570,521 | 802,543 | (J) | 495,529 | (J) | 317,177 | (J) | 268,078 | (J) | (93,968) | (B) | — | 1,247,964 | ||||||||||||
|
|
(1,125,317) | (I) | |||||||||||||||||||||||
|
|
13,401 | (K) | |||||||||||||||||||||||
|
General and administrative expenses |
1,252,001 | — | — | — | — | — | (393,170 | )(F) | 3,659,341 | ||||||||||||||||
|
|
2,800,510 | (G) | |||||||||||||||||||||||
| | | | | | | | | | | | | | | | | | | | | | | | | | |
|
Total costs and expenses |
8,263,009 | 802,543 | 495,529 | 317,177 | 268,078 | 8,207,017 | 2,407,340 | 20,760,693 | |||||||||||||||||
| | | | | | | | | | | | | | | | | | | | | | | | | | |
|
Operating income (loss) |
(5,690,532 | ) | 4,822,163 | 3,238,957 | 1,559,945 | 1,418,143 | (8,347,571 | ) | (2,407,340 | ) | (5,406,235 | ) | |||||||||||||
| | | | | | | | | | | | | | | | | | | | | | | | | | |
|
Interest expense |
314,081 | — | — | — | — | — | (86,344 | )(H) | 227,737 | ||||||||||||||||
| | | | | | | | | | | | | | | | | | | | | | | | | | |
|
Income (loss) before income taxes |
(6,004,613 | ) | 4,822,163 | 3,238,957 | 1,559,945 | 1,418,143 | (8,347,571 | ) | (2,320,996 | ) | (5,633,972 | ) | |||||||||||||
|
State income taxes |
13,401 | — | — | — | — | (13,401) | (K) | — | — | ||||||||||||||||
| | | | | | | | | | | | | | | | | | | | | | | | | | |
|
Net income (loss) |
$ | (6,018,014 | ) | $ | 4,822,163 | $ | 3,238,957 | $ | 1,559,945 | $ | 1,418,143 | $ | (8,334,170 | ) | $ | (2,320,996 | ) | $ | (5,633,972 | ) | |||||
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | |
|
Net income (loss) per common unit |
|||||||||||||||||||||||||
|
Basic |
$ | — | $ | — | |||||||||||||||||||||
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | |
|
Diluted |
$ | — | $ | — | |||||||||||||||||||||
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | |
|
Weighted average common unit outstanding |
|||||||||||||||||||||||||
|
Basic |
— | — | |||||||||||||||||||||||
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | |
|
Diluted |
— | — | |||||||||||||||||||||||
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | |
|
Distributions declared per common unit |
$ | — | $ | — | |||||||||||||||||||||
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | |
- (1)
-
Includes
Trunk Bay Royalty Partners, Ltd., Oil Nut Bay Royalties, LP, Gorda Sound Royalties, LP and Bitter End Royalties, LP.
- (2)
- Includes direct operating expenses for the Kimbell Art Foundation, Trunk Bay Royalty Partners, Ltd., RCPTX, Ltd., and French Capital Partners, Ltd.
See the accompanying Notes to Unaudited Pro Forma Condensed Combined Financial Statements.
F-6
KIMBELL ROYALTY PARTNERS, LP
UNAUDITED PRO FORMA CONDENSED COMBINED STATEMENT OF OPERATIONS
For the Year Ended December 31, 2015
|
|
Predecessor
Entity |
Kimbell Art
Foundation |
Trunk Bay
Royalty Partners, Ltd. (1) |
RCPTX, Ltd. |
French
Capital Partners, Ltd. |
Acquisition
Adjustments |
Equity
Offering and Other Pro Forma Adjustments |
Pro
Forma |
|||||||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
|
Oil, natural gas and NGL revenues |
$ | 4,684,923 | $ | 9,584,930 | (J) | $ | 6,511,538 | (J) | $ | 3,465,958 | (J) | $ | 2,925,217 | (J) | $ | (481,538) | (B) | $ | — | $ | 26,691,028 | ||||
| | | | | | | | | | | | | | | | | | | | | | | | | | |
|
Total revenues |
4,684,923 | 9,584,930 | 6,511,538 | 3,465,958 | 2,925,217 | (481,538 | ) | — | 26,691,028 | ||||||||||||||||
| | | | | | | | | | | | | | | | | | | | | | | | | | |
|
Costs and expenses |
|||||||||||||||||||||||||
|
Production and ad valorem taxes |
426,885 | — | — | — | — | (35,426) | (B) | — | 2,199,404 | ||||||||||||||||
|
|
1,807,945 | (I) | |||||||||||||||||||||||
|
Depreciation, depletion and accretion expenses |
4,008,730 | — | — | — | — | 14,279,336 | (A) | — | 18,164,181 | ||||||||||||||||
|
|
(123,885 | )(B) | |||||||||||||||||||||||
|
Impairment of oil and natural gas properties |
28,673,166 | — | — | — | — | (923,497) | (B) | — | 27,749,669 | ||||||||||||||||
|
Marketing and other deductions (2) |
747,264 | 1,087,632 | (J) | 821,085 | (J) | 414,400 | (J) | 384,106 | (J) | (343,239) | (B) | — | 1,271,104 | ||||||||||||
|
|
(1,807,945) | (I) | |||||||||||||||||||||||
|
|
(32,199) | (K) | |||||||||||||||||||||||
|
General and administrative expenses |
1,789,884 | — | — | — | — | — | (444,101 | )(F) | 5,079,796 | ||||||||||||||||
|
|
3,734,013 | (G) | |||||||||||||||||||||||
| | | | | | | | | | | | | | | | | | | | | | | | | | |
|
Total costs and expenses |
35,645,929 | 1,087,632 | 821,085 | 414,400 | 384,106 | 12,821,090 | 3,289,912 | 54,464,154 | |||||||||||||||||
| | | | | | | | | | | | | | | | | | | | | | | | | | |
|
Operating income (loss) |
(30,961,006 | ) | 8,497,298 | 5,690,453 | 3,051,558 | 2,541,111 | (13,302,628 | ) | (3,289,912 | ) | (27,773,126 | ) | |||||||||||||
| | | | | | | | | | | | | | | | | | | | | | | | | | |
|
Interest expense |
385,119 | — | — | — | — | — | (76,776 | )(H) | 308,343 | ||||||||||||||||
| | | | | | | | | | | | | | | | | | | | | | | | | | |
|
Income (loss) before income taxes |
(31,346,127 | ) | 8,497,298 | 5,690,453 | 3,051,558 | 2,541,111 | (13,302,628 | ) | (3,213,136 | ) | (28,081,469 | ) | |||||||||||||
|
State income taxes |
(32,199 | ) | — | — | — | — | 32,199 | (K) | — | — | |||||||||||||||
| | | | | | | | | | | | | | | | | | | | | | | | | | |
|
Net income (loss) |
$ | (31,313,926 | ) | $ | 8,497,298 | $ | 5,690,453 | $ | 3,051,558 | $ | 2,541,111 | $ | (13,334,827 | ) | $ | (3,213,136 | ) | $ | (28,081,469 | ) | |||||
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | |
|
Net income (loss) per common unit |
|||||||||||||||||||||||||
|
Basic |
$ | — | $ | — | |||||||||||||||||||||
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | |
|
Diluted |
$ | — | $ | — | |||||||||||||||||||||
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | |
|
Weighted average common unit outstanding |
|||||||||||||||||||||||||
|
Basic |
— | — | |||||||||||||||||||||||
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | |
|
Diluted |
— | — | |||||||||||||||||||||||
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | |
|
Distributions declared per common unit |
$ | — | $ | — | |||||||||||||||||||||
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | |
- (1)
-
Includes
Trunk Bay Royalty Partners, Ltd., Oil Nut Bay Royalties, LP, Gorda Sound Royalties, LP and Bitter End Royalties, LP.
- (2)
- Includes direct operating expenses for the Kimbell Art Foundation, Trunk Bay Royalty Partners, Ltd., RCPTX, Ltd., and French Capital Partners, Ltd.
See the accompanying Notes to Unaudited Pro Forma Condensed Combined Financial Statements.
F-7
KIMBELL ROYALTY PARTNERS, LP
NOTES TO UNAUDITED PRO FORMA CONDENSED COMBINED FINANCIAL STATEMENTS
For the Nine Months Ended September 30, 2016 and for the Year Ended December 31, 2015
1) Basis of Presentation
The unaudited pro forma condensed combined balance sheet as of September 30, 2016 and the unaudited pro forma condensed combined statement of operations for the nine months ended September 30, 2016 and for the year ended December 31, 2015 are derived from the historical financial statements of our predecessor and the historical statements of revenues and direct operating expenses of oil and gas properties of the Kimbell Art Foundation, Trunk Bay Royalty Partners, Ltd., Oil Nut Bay Royalties, LP, Gorda Sound Royalties, LP and Bitter End Royalties, LP, RCPTX, Ltd., and French Capital Partners, Ltd.
2) Pro Forma Adjustments and Assumptions
The adjustments are based on currently available information, certain estimates and assumptions. Therefore the actual effects of these transactions will differ from the pro forma adjustments. A general description of these transactions and adjustments is provided as follows:
- A)
- Represents the pro forma impact of the fair value adjustment to mineral and royalty interests, and the associated change to depreciation, depletion and accretion expense, recorded as a result of the acquisition of assets contributed by the Kimbell Art Foundation, Trunk Bay Royalty Partners, Ltd., Oil Nut Bay Royalties, LP, Gorda Sound Royalties, LP and Bitter End Royalties, LP, RCPTX, Ltd., and French Capital Partners, Ltd. The amounts assigned to oil and natural gas properties (full cost method), the estimated useful lives, and the estimated depreciation, depletion and accretion expense related to oil and natural gas properties acquired are as follows:
|
|
Estimated
Fair Value |
Proved
Reserves |
Nine Months
Ended September 30, 2016 Depreciation, Depletion and Accretion Expense |
Year Ended
December 31, 2015 Depreciation, Depletion and Accretion Expense |
|||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
|
Oil and natural gas properties: |
|||||||||||||
|
Kimbell Art Foundation |
$ | 79,570,000 | 4,618 | $ | 3,145,364 | $ | 5,246,728 | ||||||
|
Trunk Bay Royalty Partners, Ltd. (1) |
57,610,000 | 3,006 | 2,816,240 | 4,699,624 | |||||||||
|
RCPTX, Ltd. |
31,050,000 | 2,406 | 1,164,323 | 2,172,420 | |||||||||
|
French Capital Partners, Ltd. |
26,840,000 | 1,108 | 1,227,591 | 2,160,564 | |||||||||
| | | | | | | | | | | | | | |
|
Total pro forma adjustments |
$ | 195,070,000 | 11,138 | $ | 8,353,518 | $ | 14,279,336 | ||||||
| | | | | | | | | | | | | | |
- (1)
- Includes Trunk Bay Royalty Partners, Ltd., Oil Nut Bay Royalties, LP, Gorda Sound Royalties, LP and Bitter End Royalties, LP.
The assets to be acquired, included in these pro forma adjustments, do not constitute "an integrated set of activities and assets that are capable of being conducted and managed for the purpose of providing a return in the form of dividends, lower costs, or other economic benefits directly to investors or other owners, members, or participants."
F-8
KIMBELL ROYALTY PARTNERS, LP
NOTES TO UNAUDITED PRO FORMA CONDENSED COMBINED FINANCIAL STATEMENTS (Continued)
For the Nine Months Ended September 30, 2016 and for the Year Ended December 31, 2015
2) Pro Forma Adjustments and Assumptions (Continued)
- B)
-
Reflects
the assignment of certain non-operated working interests by our predecessor to an affiliate that will not be contributed to us and the removal of
associated asset retirement obligations.
- C)
-
Reflects
the net proceeds to us from this offering of $ million, which consists of $ million
in gross proceeds
from the issuance and sale of common units at an assumed initial offering price of
$ per common unit, which is the mid-point of the price range set forth on the cover of
the prospectus, less the underwriting discount of $ million and structuring fee of
$ million. Any net proceeds received from the exercise of the
underwriters' option will be used to make an additional cash distribution to the Contributing Parties.
- D)
-
Reflects
our predecessor's repayment of its credit facility using the proceeds it receives from this offering, our expected entrance into a new
$50.0 million secured revolving credit facility with an accordion feature permitting aggregate commitments under the facility to be increased up to $100.0 million (subject to the
satisfaction of certain conditions and the procurement of additional commitments from new or existing lenders), and our expected borrowings of approximately $1.5 million at the closing of this
offering to fund certain transaction expenses. We will not assume any indebtedness of the predecessor in connection with this offering.
- E)
- Reflects the effect of our recapitalization as a result of the pro forma formation transactions, and a distribution of $ to the Contributing Parties with the proceeds of this offering.
As a result, the acquisitions are treated as an acquisition of assets under generally accepted accounting principles based on the guidance in ASC 805—Business Combinations. Because they are treated as an acquisition of assets, they will not be treated as an acquisition of a business for purposes of ASC 805.
This methodology requires the recording of net assets acquired and consideration transferred at fair value. The mineral and royalty interests acquired are based upon a valuation performed with the assistance of a third party valuation specialist as well as management estimates, utilizing a combination of the income, market and cost approaches to valuation.
We intend to acquire the mineral and royalty interests for an estimated purchase price of approximately $195.1 million. The total estimated net consideration paid will take the form of $39.0 million of cash and $ million of equity consideration, which we expect to take the form of our common units prior to or concurrently with the consummation of this offering.
F-9
KIMBELL ROYALTY PARTNERS, LP
NOTES TO UNAUDITED PRO FORMA CONDENSED COMBINED FINANCIAL STATEMENTS (Continued)
For the Nine Months Ended September 30, 2016 and for the Year Ended December 31, 2015
2) Pro Forma Adjustments and Assumptions (Continued)
- F)
-
Reflects
the removal of non-recurring transaction expenses of $0.4 million and $0.4 million related to the acquisition of assets contributed by
the Kimbell Art Foundation, Trunk Bay Royalty Partners, Ltd., Oil Nut Bay Royalties, LP, Gorda Sound Royalties, LP and Bitter End Royalties, LP, RCPTX, Ltd., and
French Capital Partners, Ltd. to this offering for the nine months ended September 30, 2016 and the year ended December 31, 2015, respectively.
- G)
-
Reflects
$2.8 million for the nine months ended September 30, 2016 and $3.7 million for the year ended December 31, 2015, which
are the fees to be charged by Kimbell Operating for management and administrative services under its management services agreement with us. Kimbell Operating will enter into separate service
agreements with certain entities controlled by Messrs. Duncan, R. Ravnaas, Taylor and Wynne, pursuant to which they and Kimbell Operating will provide management, administrative and operational
services to us. In addition, under each of their respective service agreements, Messrs. R. Ravnaas, Taylor and Wynne will identify, evaluate and recommend to us acquisition opportunities and negotiate
the terms of such acquisitions.
- H)
- Represents the impact of adjustments to interest expense:
|
|
Nine Months
Ended September 30, 2016 |
Year Ended
December 31, 2015 |
|||||
|---|---|---|---|---|---|---|---|
|
New secured revolving credit facility: |
|||||||
|
Interest expense |
$ | 215,105 | $ | 286,808 | |||
|
Amortization expense of loan origination costs |
46,875 | 62,500 | |||||
| | | | | | | | |
|
|
261,980 | 349,308 | |||||
| | | | | | | | |
|
Repayment of existing debt: |
|||||||
|
Interest expense |
314,081 | 385,119 | |||||
|
Amortization expense of loan origination costs |
34,245 | 40,965 | |||||
| | | | | | | | |
|
|
348,326 | 426,084 | |||||
| | | | | | | | |
|
Net adjustment to interest expense |
$ | 86,344 | $ | 76,776 | |||
| | | | | | | | |
- I)
- Reflects the re-classification of the direct expenses derived from the statements of revenues and direct expenses of certain oil and gas properties owned by the Kimbell Art Foundation, Trunk Bay Royalty Partners, Ltd., Oil Nut Bay Royalties, LP, Gorda Sound Royalties, LP and Bitter End Royalties, LP, RCPTX, Ltd., and French Capital Partners, Ltd. into production and ad valorem taxes in the amount of $1.1 million for the nine months ended September 30, 2016 and $1.8 million for the year ended December 31, 2015.
F-10
KIMBELL ROYALTY PARTNERS, LP
NOTES TO UNAUDITED PRO FORMA CONDENSED COMBINED FINANCIAL STATEMENTS (Continued)
For the Nine Months Ended September 30, 2016 and for the Year Ended December 31, 2015
2) Pro Forma Adjustments and Assumptions (Continued)
- J)
-
Revenues
and direct operating expenses are presented on the accrual basis of accounting and were derived from the historical accounting records of the
Kimbell Art Foundation, Trunk Bay Royalty Partners, Ltd., Oil Nut Bay Royalties, LP, Gorda Sound Royalties, LP and Bitter End Royalties, LP, RCPTX, Ltd., and French
Capital Partners, Ltd. During the periods presented, the assets to be contributed by the Kimbell Art Foundation, Trunk Bay Royalty Partners, Ltd., Oil Nut Bay Royalties, LP, Gorda
Sound Royalties, LP and Bitter End Royalties, LP, RCPTX, Ltd., and French Capital Partners, Ltd. were not accounted for or operated as a separate division or entity;
therefore, certain expenses such as depreciation, depletion and amortization expense, general and administrative expense, interest expense and income taxes were not allocated to such assets. As such,
the combined pro forma condensed consolidated combined statements of operations are not intended to be a complete presentation of the revenues and expenses of the assets to be contributed by the
Kimbell Art Foundation, Trunk Bay Royalty Partners, Ltd., Oil Nut Bay Royalties, LP, Gorda Sound Royalties, LP and Bitter End Royalties, LP, RCPTX, Ltd., and French
Capital Partners, Ltd. and are not indicative of the results of the operation of such going forward due to the omission of various expenses, including those described above.
- K)
- Reflects the reclassification of state income taxes into marketing and other deductions of $13,401 and a $32,199 tax credit for the nine months ended September 30, 2016 and for the year ended December 31, 2015, respectively.
3) Pro Forma Net Income (Loss) per Common Unit
Pro forma net income per unit is determined by dividing the pro forma net income available to common unitholders by the number of common units to be issued to our predecessor's existing members and the number of common units expected to be sold to the public in the offering. For purposes of this calculation, the number of common units outstanding at the closing of the offering was assumed to be for the nine months ended September 30, 2016 and the year ended December 31, 2015 and , respectively. All common units were assumed to have been outstanding since the beginning of the periods presented.
4) Pro Forma Supplemental Oil and Gas Reserve Information
The following pro forma standardized measure of the discounted net future cash flows and changes are applicable to the proved reserves of our predecessor, the Kimbell Art Foundation, Trunk Bay Royalty Partners, Ltd., Oil Nut Bay Royalties, LP, Gorda Sound Royalties, LP and Bitter End Royalties, LP, RCPTX, Ltd., and French Capital Partners, Ltd. The future cash flows are discounted at 10% per year and assume continuation of existing economic conditions.
The standardized measure of discounted future net cash flows, in management's opinion, should be examined with caution. The basis for this table are the reserve studies prepared by
F-11
KIMBELL ROYALTY PARTNERS, LP
NOTES TO UNAUDITED PRO FORMA CONDENSED COMBINED FINANCIAL STATEMENTS (Continued)
For the Nine Months Ended September 30, 2016 and for the Year Ended December 31, 2015
4) Pro Forma Supplemental Oil and Gas Reserve Information (Continued)
management, which contain imprecise estimates of quantities and rates of production of reserves. Revisions of previous year estimates can have a significant impact on these results. Also, exploration costs in one year may lead to significant discoveries in later years and may significantly change previous estimates of proved reserves and their valuation. Therefore, the standardized measure of discounted future net cash flows is not necessarily indicative of the fair value of the proved oil and natural gas properties of our predecessor, the Kimbell Art Foundation, Trunk Bay Royalty Partners, Ltd., Oil Nut Bay Royalties, LP, Gorda Sound Royalties, LP and Bitter End Royalties, LP, RCPTX, Ltd., and French Capital Partners, Ltd.
The data presented should not be viewed as representing the expected cash flows from, or current value of, existing proved reserves since the computations are based on a large number of estimates and arbitrary assumptions. Reserve quantities cannot be measured with precision and their estimation requires many judgmental determinations and frequent revisions. Actual future prices and costs are likely to be substantially different from the prices and costs utilized in the computation of reported amounts.
F-12
KIMBELL ROYALTY PARTNERS, LP
NOTES TO UNAUDITED PRO FORMA CONDENSED COMBINED FINANCIAL STATEMENTS (Continued)
For the Nine Months Ended September 30, 2016 and for the Year Ended December 31, 2015
4) Pro Forma Supplemental Oil and Gas Reserve Information (Continued)
The following tables provide a pro forma rollforward of the total proved reserves for the year ended December 31, 2015, as well as pro forma proved developed and proved undeveloped reserves at the beginning and end of the year:
Crude Oil, Condensate and Natural Gas Liquids (MBbls)
|
|
Predecessor
Entity |
Kimbell Art
Foundation |
Trunk Bay
Royalty Partners, Ltd. (1) |
RCPTX, Ltd. |
French
Capital Partners, Ltd. |
Acquisition
Adjustments |
Pro Forma (2) | |||||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
|
Net proved reserves at January 1, 2014 |
486 | 2,447 | 1,904 | 906 | 1,261 | (106 | ) | 6,898 | ||||||||||||||
|
Purchase of minerals in place |
834 | — | — | — | — | (24 | ) | 810 | ||||||||||||||
|
Revisions of previous estimates |
— | — | — | — | 27 | — | 27 | |||||||||||||||
|
Extensions and discoveries |
75 | 73 | 30 | 2 | — | (2 | ) | 178 | ||||||||||||||
|
Production |
(67 | ) | (146 | ) | (137 | ) | (67 | ) | (96 | ) | 11 | (502 | ) | |||||||||
| | | | | | | | | | | | | | | | | | | | | | | |
|
Net proved reserves at December 31, 2014 |
1,328 | 2,374 | 1,797 | 841 | 1,192 | (121 | ) | 7,411 | ||||||||||||||
|
Extensions and discoveries |
— | — | 15 | — | — | — | 15 | |||||||||||||||
|
Revisions of previous estimates |
(81 | ) | (118 | ) | 115 | 404 | 13 | (25 | ) | 308 | ||||||||||||
|
Production |
(82 | ) | (151 | ) | (188 | ) | (82 | ) | (97 | ) | 10 | (590 | ) | |||||||||
| | | | | | | | | | | | | | | | | | | | | | | |
|
Net proved reserves at December 31, 2015 |
1,165 | 2,105 | 1,739 | 1,163 | 1,108 | (136 | ) | 7,144 | ||||||||||||||
| | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | |
|
Net Proved Developed Reserves |
||||||||||||||||||||||
|
December 31, 2014 |
703 | 1,674 | 1,338 | 563 | 1,192 | (120 | ) | 5,350 | ||||||||||||||
|
December 31, 2015 |
681 | 1,536 | 1,264 | 746 | 1,108 | (90 | ) | 5,245 | ||||||||||||||
|
Net Proved Undeveloped Reserves |
||||||||||||||||||||||
|
December 31, 2014 |
625 | 700 | 459 | 278 | — | (1 | ) | 2,061 | ||||||||||||||
|
December 31, 2015 |
484 | 569 | 475 | 417 | — | (46 | ) | 1,899 | ||||||||||||||
- (1)
-
Includes
Trunk Bay Royalty Partners, Ltd., Oil Nut Bay Royalties, LP, Gorda Sound Royalties, LP and Bitter End Royalties, LP.
- (2)
- Does not give pro forma effect to our acquisition of assets to be contributed by the Contributing Parties other than our predecessor, the Kimbell Art Foundation, Trunk Bay Royalty Partners, Ltd., Oil Nut Bay Royalties, LP, Gorda Sound Royalties, LP and Bitter End Royalties, LP, RCPTX, Ltd., and French Capital Partners, Ltd., which excluded assets represent approximately 25% of our future undiscounted cash flows, based on the reserve report prepared by Ryder Scott as of December 31, 2015.
F-13
KIMBELL ROYALTY PARTNERS, LP
NOTES TO UNAUDITED PRO FORMA CONDENSED COMBINED FINANCIAL STATEMENTS (Continued)
For the Nine Months Ended September 30, 2016 and for the Year Ended December 31, 2015
4) Pro Forma Supplemental Oil and Gas Reserve Information (Continued)
|
|
Predecessor
Entity |
Kimbell Art
Foundation |
Trunk Bay
Royalty Partners, Ltd. (1) |
RCPTX, Ltd. |
French
Capital Partners, Ltd. |
Acquisition
Adjustments |
Pro Forma (2) | |||||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
|
Net proved reserves at January 1, 2014 |
3,096 | 17,000 | 8,192 | 7,852 | — | (83 | ) | 36,057 | ||||||||||||||
|
Purchase of minerals in place |
5,083 | — | — | — | — | (195 | ) | 4,888 | ||||||||||||||
|
Revisions of previous estimates |
— | — | — | — | — | — | — | |||||||||||||||
|
Extensions and discoveries |
279 | 901 | 275 | 44 | — | 4 | 1,503 | |||||||||||||||
|
Production |
(560 | ) | (1,257 | ) | (582 | ) | (557 | ) | — | 22 | (2,934 | ) | ||||||||||
| | | | | | | | | | | | | | | | | | | | | | | |
|
Net proved reserves at December 31, 2014 |
7,898 | 16,644 | 7,885 | 7,339 | — | (252 | ) | 39,514 | ||||||||||||||
|
Extensions and discoveries |
— | — | 37 | — | — | — | 37 | |||||||||||||||
|
Revisions of previous estimates |
(184 | ) | (513 | ) | 151 | 714 | — | 20 | 188 | |||||||||||||
|
Production |
(548 | ) | (1,052 | ) | (475 | ) | (594 | ) | — | 24 | (2,645 | ) | ||||||||||
| | | | | | | | | | | | | | | | | | | | | | | |
|
Net proved reserves at December 31, 2015 |
7,166 | 15,079 | 7,598 | 7,459 | — | (208 | ) | 37,094 | ||||||||||||||
| | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | |
|
Net Proved Developed Reserves |
||||||||||||||||||||||
|
December 31, 2014 |
5,225 | 12,568 | 5,030 | 5,129 | — | (251 | ) | 27,701 | ||||||||||||||
|
December 31, 2015 |
4,720 | 11,709 | 4,658 | 4,754 | — | (208 | ) | 25,633 | ||||||||||||||
|
Net Proved Undeveloped Reserves |
||||||||||||||||||||||
|
December 31, 2014 |
2,673 | 4,076 | 2,855 | 2,210 | — | (1 | ) | 11,813 | ||||||||||||||
|
December 31, 2015 |
2,446 | 3,370 | 2,940 | 2,705 | — | — | 11,461 | |||||||||||||||
- (1)
-
Includes
Trunk Bay Royalty Partners, Ltd., Oil Nut Bay Royalties, LP, Gorda Sound Royalties, LP and Bitter End Royalties, LP.
- (2)
- Does not give pro forma effect to our acquisition of assets to be contributed by the Contributing Parties other than our predecessor, the Kimbell Art Foundation, Trunk Bay Royalty Partners, Ltd., Oil Nut Bay Royalties, LP, Gorda Sound Royalties, LP and Bitter End Royalties, LP, RCPTX, Ltd., and French Capital Partners, Ltd., which excluded assets represent approximately 25% of our future undiscounted cash flows, based on the reserve report prepared by Ryder Scott as of December 31, 2015.
F-14
KIMBELL ROYALTY PARTNERS, LP
NOTES TO UNAUDITED PRO FORMA CONDENSED COMBINED FINANCIAL STATEMENTS (Continued)
For the Nine Months Ended September 30, 2016 and for the Year Ended December 31, 2015
4) Pro Forma Supplemental Oil and Gas Reserve Information (Continued)
|
|
Predecessor
Entity |
Kimbell Art
Foundation |
Trunk Bay
Royalty Partners, Ltd. (1) |
RCPTX, Ltd. |
French
Capital Partners, Ltd. |
Acquisition
Adjustments |
Pro Forma (2) | |||||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
|
Net proved reserves at January 1, 2014 |
1,001 | 5,280 | 3,269 | 2,215 | 1,261 | (119 | ) | 12,907 | ||||||||||||||
|
Purchase of minerals in place |
1,681 | — | — | — | — | (57 | ) | 1,624 | ||||||||||||||
|
Revisions of previous estimates |
— | — | — | — | 27 | — | 27 | |||||||||||||||
|
Extensions and discoveries |
122 | 223 | 76 | 9 | — | (1 | ) | 429 | ||||||||||||||
|
Production |
(160 | ) | (355 | ) | (234 | ) | (160 | ) | (96 | ) | 14 | (991 | ) | |||||||||
| | | | | | | | | | | | | | | | | | | | | | | |
|
Net proved reserves at December 31, 2014 |
2,644 | 5,148 | 3,111 | 2,064 | 1,192 | (163 | ) | 13,996 | ||||||||||||||
|
Extensions and discoveries |
— | — | 21 | — | — | — | 21 | |||||||||||||||
|
Revisions of previous estimates |
(111 | ) | (204 | ) | 141 | 523 | 13 | (22 | ) | 340 | ||||||||||||
|
Production |
(173 | ) | (326 | ) | (267 | ) | (181 | ) | (97 | ) | 14 | (1,030 | ) | |||||||||
| | | | | | | | | | | | | | | | | | | | | | | |
|
Net proved reserves at December 31, 2015 |
2,360 | 4,618 | 3,006 | 2,406 | 1,108 | (171 | ) | 13,327 | ||||||||||||||
| | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | |
|
Net Proved Developed Reserves |
||||||||||||||||||||||
|
December 31, 2014 |
1,574 | 3,768 | 2,176 | 1,418 | 1,192 | (162 | ) | 9,966 | ||||||||||||||
|
December 31, 2015 |
1,468 | 3,488 | 2,040 | 1,538 | 1,108 | (125 | ) | 9,517 | ||||||||||||||
|
Net Proved Undeveloped Reserves |
||||||||||||||||||||||
|
December 31, 2014 |
1,070 | 1,380 | 935 | 646 | — | (1 | ) | 4,030 | ||||||||||||||
|
December 31, 2015 |
892 | 1,130 | 966 | 868 | — | (46 | ) | 3,810 | ||||||||||||||
- (1)
-
Includes
Trunk Bay Royalty Partners, Ltd., Oil Nut Bay Royalties, LP, Gorda Sound Royalties, LP and Bitter End Royalties, LP.
- (2)
- Does not give pro forma effect to our acquisition of assets to be contributed by the Contributing Parties other than our predecessor, the Kimbell Art Foundation, Trunk Bay Royalty Partners, Ltd., Oil Nut Bay Royalties, LP, Gorda Sound Royalties, LP and Bitter End Royalties, LP, RCPTX, Ltd., and French Capital Partners, Ltd., which excluded assets represent approximately 25% of our future undiscounted cash flows, based on the reserve report prepared by Ryder Scott as of December 31, 2015.
F-15
KIMBELL ROYALTY PARTNERS, LP
NOTES TO UNAUDITED PRO FORMA CONDENSED COMBINED FINANCIAL STATEMENTS (Continued)
For the Nine Months Ended September 30, 2016 and for the Year Ended December 31, 2015
4) Pro Forma Supplemental Oil and Gas Reserve Information (Continued)
The pro forma standardized measure of discounted future net cash flows was as follows as of December 31, 2015 (in thousands):
|
|
Predecessor
Entity |
Kimbell Art
Foundation |
Trunk Bay
Royalty Partners, Ltd. (1) |
RCPTX, Ltd. |
French
Capital Partners, Ltd. |
Acquisition
Adjustments |
Pro Forma (2) | |||||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
|
Future cash inflows |
$ | 59,972 | $ | 121,009 | $ | 99,548 | $ | 56,957 | $ | 45,132 | $ | (7,894 | ) | $ | 374,724 | |||||||
|
Future production costs |
(5,490 | ) | (7,524 | ) | (8,000 | ) | (5,513 | ) | (3,279 | ) | 2,976 | (26,830 | ) | |||||||||
| | | | | | | | | | | | | | | | | | | | | | | |
|
Future net cash flows |
54,482 | 113,485 | 91,548 | 51,444 | 41,853 | (4,918 | ) | 347,894 | ||||||||||||||
|
Less 10% annual discount to reflect estimated timing of cash flows |
(31,112 | ) | (63,993 | ) | (54,836 | ) | (28,735 | ) | (23,759 | ) | 2,552 | (199,883 | ) | |||||||||
| | | | | | | | | | | | | | | | | | | | | | | |
|
Standard measure of discounted future net cash flows |
$ | 23,370 | $ | 49,492 | $ | 36,712 | $ | 22,709 | $ | 18,094 | $ | (2,366 | ) | $ | 148,011 | |||||||
| | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | |
- (1)
-
Includes
Trunk Bay Royalty Partners, Ltd., Oil Nut Bay Royalties, LP, Gorda Sound Royalties, LP and Bitter End Royalties, LP.
- (2)
- Does not give pro forma effect to our acquisition of assets to be contributed by the Contributing Parties other than our predecessor, the Kimbell Art Foundation, Trunk Bay Royalty Partners, Ltd., Oil Nut Bay Royalties, LP, Gorda Sound Royalties, LP and Bitter End Royalties, LP, RCPTX, Ltd., and French Capital Partners, Ltd., which excluded assets represent approximately 25% of our future undiscounted cash flows, based on the reserve report prepared by Ryder Scott as of December 31, 2015.
F-16
KIMBELL ROYALTY PARTNERS, LP
NOTES TO UNAUDITED PRO FORMA CONDENSED COMBINED FINANCIAL STATEMENTS (Continued)
For the Nine Months Ended September 30, 2016 and for the Year Ended December 31, 2015
4) Pro Forma Supplemental Oil and Gas Reserve Information (Continued)
The changes in the pro forma standardized measure of discounted estimated future net cash flows were as follows for the year ended December 31, 2015 (in thousands):
|
|
Predecessor
Entity |
Kimbell Art
Foundation |
Trunk Bay
Royalty Partners, Ltd. (1) |
RCPTX, Ltd. |
French
Capital Partners, Ltd. |
Acquisition
Adjustments |
Pro Forma (2) | |||||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
|
Standardized measure, beginning of year |
$ | 50,764 | $ | 104,672 | $ | 69,054 | $ | 42,906 | $ | 37,008 | $ | (3,123 | ) | $ | 301,281 | |||||||
|
Sales, net of production costs |
(4,258 | ) | (8,497 | ) | (5,690 | ) | (3,052 | ) | (2,541 | ) | 289 | (23,749 | ) | |||||||||
|
Net changes of prices and production costs related to future production |
(25,570 | ) | (51,297 | ) | (32,719 | ) | (24,392 | ) | (18,373 | ) | 755 | (151,596 | ) | |||||||||
|
Extensions, discoveries and improved recovery, net of future production and development costs |
— | — | 397 | — | — | — | 397 | |||||||||||||||
|
Revisions of previous quantity estimates, net of related costs |
(1,100 | ) | (2,186 | ) | 1,730 | 4,937 | 205 | (301 | ) | 3,285 | ||||||||||||
|
Accretion of discount |
5,076 | 10,467 | 6,905 | 4,291 | 3,701 | (312 | ) | 30,128 | ||||||||||||||
|
Purchases of reserves in place, less related costs |
— | — | — | — | — | — | — | |||||||||||||||
|
Timing differences and other |
(1,542 | ) | (3,667 | ) | (2,965 | ) | (1,981 | ) | (1,906 | ) | 326 | (11,735 | ) | |||||||||
| | | | | | | | | | | | | | | | | | | | | | | |
|
Standardized measure—end of year |
$ | 23,370 | $ | 49,492 | $ | 36,712 | $ | 22,709 | $ | 18,094 | $ | (2,366 | ) | $ | 148,011 | |||||||
| | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | |
- (1)
-
Includes
Trunk Bay Royalty Partners, Ltd., Oil Nut Bay Royalties, LP, Gorda Sound Royalties, LP and Bitter End Royalties, LP.
- (2)
- Does not give pro forma effect to our acquisition of assets to be contributed by the Contributing Parties other than our predecessor, the Kimbell Art Foundation, Trunk Bay Royalty Partners, Ltd., Oil Nut Bay Royalties, LP, Gorda Sound Royalties, LP and Bitter End Royalties, LP, RCPTX, Ltd., and French Capital Partners, Ltd., which excluded assets represent approximately 25% of our future undiscounted cash flows, based on the reserve report prepared by Ryder Scott as of December 31, 2015.
F-17
KIMBELL ROYALTY PARTNERS, LP
BALANCE SHEETS
(Unaudited)
|
|
As of
September 30, 2016 |
As of
December 31, 2015 |
|||||
|---|---|---|---|---|---|---|---|
|
Assets |
|||||||
|
Current assets |
|||||||
|
Cash and cash equivalents |
$ | 255 | $ | 318 | |||
| | | | | | | | |
|
Total assets |
$ | 255 | $ | 318 | |||
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
|
Partners' capital |
|||||||
|
General partners' capital |
$ | — | $ | — | |||
|
Common units |
255 | 318 | |||||
| | | | | | | | |
|
Total partners' capital |
$ | 255 | $ | 318 | |||
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
The accompanying notes are an integral part of these financial statements.
F-18
KIMBELL ROYALTY PARTNERS, LP
STATEMENT OF OPERATIONS
For the Nine Months Ended September 30, 2016
(Unaudited)
|
Oil, natural gas and NGL revenues |
$ | — | ||
|
General and administrative expenses |
63 | |||
| | | | | |
|
Net loss |
$ | (63 | ) | |
| | | | | |
| | | | | |
| | | | | |
The accompanying notes are an integral part of these financial statements.
F-19
KIMBELL ROYALTY PARTNERS, LP
STATEMENT OF CHANGES IN PARTNERS' CAPITAL
For the Nine Months Ended September 30, 2016
(Unaudited)
|
|
Total | |||
|---|---|---|---|---|
|
Partners' capital—December 31, 2015 |
$ | 318 | ||
|
Net loss |
(63 | ) | ||
| | | | | |
|
Partners' capital—September 30, 2016 |
$ | 255 | ||
| | | | | |
| | | | | |
| | | | | |
The accompanying notes are an integral part of these financial statements.
F-20
KIMBELL ROYALTY PARTNERS, LP
STATEMENT OF CASH FLOWS
For the Nine Months Ended September 30, 2016
(Unaudited)
|
Cash flows from operating activities |
||||
|
Net loss |
$ | (63 | ) | |
| | | | | |
|
Net cash used in operating activities |
(63 | ) | ||
|
Decrease in cash and cash equivalents |
(63 | ) | ||
|
Cash and cash equivalents, beginning of period |
318 | |||
|
Cash and cash equivalents, end of period |
$ | 255 | ||
| | | | | |
| | | | | |
| | | | | |
The accompanying notes are an integral part of these financial statements.
F-21
KIMBELL ROYALTY PARTNERS, LP
NOTES TO FINANCIAL STATEMENTS
For the Nine Months Ended September 30, 2016
(Unaudited)
NOTE 1—ORGANIZATION
Kimbell Royalty Partners, LP (the "Partnership") was formed on October 30, 2015. The Partnership has adopted a fiscal year-end of December 31. In connection with its formation, the Partnership issued a non-economic general partner interest in the Partnership to Kimbell Royalty GP, LLC.
NOTE 2—SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Use of Estimates
The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, as well as certain financial statement disclosures. The Partnership evaluates estimates and assumptions on an ongoing basis using historical experience and other factors, including the current economic and commodity price environment. While management believes that the estimates and assumptions used in the preparation of the financial statements are appropriate, actual results could differ from these estimates.
Subsequent Events
Management has evaluated subsequent events through November 22, 2016, the date the financial statements were issued.
NOTE 3—COMMITMENTS AND CONTINGENCIES
Legal Contingencies
As of the date of these financial statements, the Partnership had no outstanding commitments and contingencies.
F-22
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
Board
of Directors
Kimbell Royalty Partners, LP
We have audited the accompanying balance sheet of Kimbell Royalty Partners, LP (the "Partnership") as of December 31, 2015 and the related statements of operations, changes in partners' capital, and cash flows for the period from October 30, 2015 (Inception) to December 31, 2015. These financial statements are the responsibility of the Partnership's management. Our responsibility is to express an opinion on these financial statements based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States) and in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. We were not engaged to perform an audit of the Partnership's internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Partnership's internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Kimbell Royalty Partners, LP as of December 31, 2015 and the results of its operations and its cash flows for the period from October 30, 2015 (Inception) to December 31, 2015 in conformity with accounting principles generally accepted in the United States of America.
/s/ GRANT THORNTON LLP
Dallas,
Texas
July 15, 2016
F-23
KIMBELL ROYALTY PARTNERS, LP
BALANCE SHEET
As of December 31, 2015
|
Assets |
||||
|
Current assets |
||||
|
Cash and cash equivalents |
$ | 318 | ||
| | | | | |
|
Total assets |
$ | 318 | ||
| | | | | |
| | | | | |
| | | | | |
|
Partners' capital |
||||
|
General partners' capital |
$ | — | ||
|
Common units |
318 | |||
| | | | | |
|
Total partners' capital |
$ | 318 | ||
| | | | | |
| | | | | |
| | | | | |
The accompanying notes are an integral part of these financial statements.
F-24
KIMBELL ROYALTY PARTNERS, LP
STATEMENT OF OPERATIONS
For the Period from Inception (October 30, 2015) to December 31, 2015
|
Oil, natural gas and NGL revenues |
$ | — | ||
|
General and administrative expenses |
682 | |||
| | | | | |
|
Net loss |
$ | (682 | ) | |
| | | | | |
| | | | | |
| | | | | |
The accompanying notes are an integral part of these financial statements.
F-25
KIMBELL ROYALTY PARTNERS, LP
STATEMENT OF CHANGES IN PARTNERS' CAPITAL
For the Period from Inception (October 30, 2015) to December 31, 2015
|
|
Total | |||
|---|---|---|---|---|
|
Partners' capital—October 30, 2015 |
$ | — | ||
|
Contributions from members |
1,000 | |||
|
Net loss |
(682 | ) | ||
| | | | | |
|
Partners' capital—December 31, 2015 |
$ | 318 | ||
| | | | | |
| | | | | |
| | | | | |
The accompanying notes are an integral part of these financial statements.
F-26
KIMBELL ROYALTY PARTNERS, LP
STATEMENT OF CASH FLOWS
For the Period from Inception (October 30, 2015) to December 31, 2015
|
Cash flows from operating activities |
||||
|
Net loss |
$ | (682 | ) | |
| | | | | |
|
Net cash used in operating activities |
(682 | ) | ||
|
Cash flow from financing activities |
||||
|
Contributions from partners |
1,000 | |||
| | | | | |
|
Net cash provided by financing activities |
1,000 | |||
| | | | | |
|
Increase in cash and cash equivalents |
318 | |||
| | | | | |
|
Cash and cash equivalents, beginning of period |
— | |||
|
Cash and cash equivalents, end of period |
$ | 318 | ||
| | | | | |
| | | | | |
| | | | | |
The accompanying notes are an integral part of these financial statements.
F-27
KIMBELL ROYALTY PARTNERS, LP
NOTES TO FINANCIAL STATEMENTS
For the Period from Inception (October 30, 2015) to December 31, 2015
NOTE 1—ORGANIZATION
Kimbell Royalty Partners, LP (the "Partnership") was formed on October 30, 2015. The Partnership has adopted a fiscal year-end of December 31. In connection with its formation, the Partnership issued a non-economic general partner interest in the Partnership to Kimbell Royalty GP, LLC.
NOTE 2—SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Use of Estimates
The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, as well as certain financial statement disclosures. The Partnership evaluates estimates and assumptions on an ongoing basis using historical experience and other factors, including the current economic and commodity price environment. While management believes that the estimates and assumptions used in the preparation of the financial statements are appropriate, actual results could differ from these estimates.
Subsequent Events
Management has evaluated subsequent events through July 15, 2016, the date the financial statements were issued.
NOTE 3—COMMITMENTS AND CONTINGENCIES
Legal Contingencies
As of the date of these financial statements, the Partnership had no outstanding commitments and contingencies.
F-28
RIVERCREST ROYALTIES, LLC
BALANCE SHEETS
(Unaudited)
|
|
Supplemental
Pro Forma September 30, 2016 |
As of
September 30, 2016 |
As of
December 31, 2015 |
|||||||
|---|---|---|---|---|---|---|---|---|---|---|
|
Assets |
||||||||||
|
Current assets |
||||||||||
|
Cash and cash equivalents |
$ | $ | 679,635 | $ | 379,741 | |||||
|
Oil, natural gas and NGL receivables |
396,390 | 407,648 | ||||||||
|
Other receivables |
125,271 | 1,371,540 | ||||||||
| | | | | | | | | | | |
|
Total current assets |
1,201,296 | 2,158,929 | ||||||||
|
Property and equipment, net |
278,728 | 347,815 | ||||||||
|
Oil and natural gas properties, at cost |
||||||||||
|
Oil and natural gas properties (full cost method) |
70,885,845 | 70,809,962 | ||||||||
|
Less: accumulated depreciation, depletion, accretion and impairment |
(51,606,906 | ) | (45,457,931 | ) | ||||||
| | | | | | | | | | | |
|
Total oil and natural gas properties |
19,278,939 | 25,352,031 | ||||||||
|
Loan origination costs, net |
25,770 | 47,015 | ||||||||
| | | | | | | | | | | |
|
Total assets |
$ | $ | 20,784,733 | $ | 27,905,790 | |||||
| | | | | | | | | | | |
| | | | | | | | | | | |
| | | | | | | | | | | |
|
Liabilities and members' equity |
||||||||||
|
Current liabilities |
||||||||||
|
Accounts payable |
912,209 | 1,983,662 | ||||||||
|
Other current liabilities |
125,517 | 35,967 | ||||||||
|
Asset retirement obligation, current portion |
27,013 | 1,223 | ||||||||
| | | | | | | | | | | |
|
Total current liabilities |
1,064,739 | 2,020,852 | ||||||||
|
Asset retirement obligation, net of current portion |
14,181 | 39,129 | ||||||||
|
Other liabilities |
131,750 | 157,527 | ||||||||
|
Long-term debt |
10,898,860 | 11,448,860 | ||||||||
| | | | | | | | | | | |
|
Total liabilities |
12,109,530 | 13,666,368 | ||||||||
|
Commitments and contingencies |
||||||||||
|
Members' equity |
8,675,203 | 14,239,422 | ||||||||
| | | | | | | | | | | |
|
Total liabilities and members' equity |
$ | $ | 20,784,733 | $ | 27,905,790 | |||||
| | | | | | | | | | | |
| | | | | | | | | | | |
| | | | | | | | | | | |
The accompanying notes are an integral part of these financial statements.
F-29
RIVERCREST ROYALTIES, LLC
STATEMENTS OF OPERATIONS
(Unaudited)
|
|
For the Nine Months Ended
September 30, |
||||||
|---|---|---|---|---|---|---|---|
|
|
2016 | 2015 | |||||
|
Oil, natural gas and NGL revenues |
$ | 2,572,477 | $ | 3,670,930 | |||
|
Costs and expenses |
|||||||
|
Production and ad valorem taxes |
203,567 | 214,150 | |||||
|
Depreciation, depletion and accretion expenses |
1,244,023 | 2,969,502 | |||||
|
Impairment of oil and natural gas properties |
4,992,897 | 25,796,352 | |||||
|
Marketing and other deductions |
570,521 | 590,637 | |||||
|
General and administrative expenses |
1,252,001 | 1,127,926 | |||||
| | | | | | | | |
|
Total costs and expenses |
8,263,009 | 30,698,567 | |||||
| | | | | | | | |
|
Operating loss |
(5,690,532 | ) | (27,027,637 | ) | |||
|
Interest expense |
314,081 | 282,372 | |||||
| | | | | | | | |
|
Loss before income taxes |
(6,004,613 | ) | (27,310,009 | ) | |||
|
State income taxes |
13,401 | 11,557 | |||||
| | | | | | | | |
|
Net loss |
$ | (6,018,014 | ) | $ | (27,321,566 | ) | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
|
Net loss per common unit (unaudited—Note 5) |
|||||||
|
Basic and diluted |
$ | (9.96 | ) | $ | (45.22 | ) | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
|
Weighted average number of member units outstanding |
|||||||
|
Basic and diluted |
604,137 | 604,137 | |||||
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
The accompanying notes are an integral part of these financial statements.
F-30
RIVERCREST ROYALTIES, LLC
STATEMENT OF CHANGES IN MEMBERS' EQUITY
(Unaudited)
|
|
Units | Total | |||||
|---|---|---|---|---|---|---|---|
|
Members' equity—December 31, 2015 |
604,137 | $ | 14,239,422 | ||||
|
Unit-based compensation |
— | 453,795 | |||||
|
Net loss |
— | (6,018,014 | ) | ||||
| | | | | | | | |
|
Members' equity—September 30, 2016 |
604,137 | $ | 8,675,203 | ||||
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
The accompanying notes are an integral part of these financial statements.
F-31
RIVERCREST ROYALTIES, LLC
STATEMENTS OF CASH FLOWS
(Unaudited)
The accompanying notes are an integral part of these financial statements.
F-32
RIVERCREST ROYALTIES, LLC
NOTES TO FINANCIAL STATEMENTS
For the Nine Months Ended September 30, 2016 and 2015
(Unaudited)
NOTE 1—ORGANIZATION
Rivercrest Royalties, LLC (the "Company") is a Delaware limited liability company formed on October 25, 2013. The Company is a Fort Worth, Texas based owner of oil, natural gas and natural gas liquids mineral and royalty interests in the United States of America ("United States"). In addition to mineral and royalty interests, the Company's assets include overriding royalty interests. These non-cost-bearing interests are collectively referred to as "mineral and royalty interests." The Company also has non-operated working interests in certain oil and natural gas properties, which together with the mineral and royalty interests, we refer to as the "Interests." The Company has Interests in nearly every major onshore basin across the continental United States.
NOTE 2—SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Basis of Presentation
The unaudited financial information in the accompanying financial statements has been prepared on the same basis as the audited financial statements of the Company for the year ended December 31, 2015. In the opinion of the Company's management, such financial information reflects all adjustments necessary for a fair presentation of the financial position and the results of operations for such interim periods in accordance with accounting principles generally accepted in the United States of America ("U.S. GAAP"). A summary of the significant accounting policies applied in the preparation of the accompanying financial statements follows.
Supplemental Pro Forma Information
Staff Accounting Bulletin 1.B.3 requires that certain distributions to owners prior to or coincident with an initial public offering be considered as distributions in contemplation of that offering. Upon completion of this offering of Kimbell Royalty Partners, LP ("Partnership"), the Partnership intends to distribute approximately $ million in cash to the members of the Company. The distribution is intended to be made in consideration of the Company's contribution of assets to the Partnership in connection with the offering. This distribution will be paid with offering proceeds. The supplemental pro forma balance sheet as of September 30, 2016 gives pro forma effect to this assumed distribution as though it had been declared and was payable as of that date.
The unaudited pro forma earnings per common unit for the nine months ended September 30, 2016 assumed common units were outstanding in the period. The common units represent the number of common units we would have been required to issue to fund the $ million distribution. For the nine months ended September 30, 2016, pro forma net loss per common unit would have been $ .
F-33
RIVERCREST ROYALTIES, LLC
NOTES TO FINANCIAL STATEMENTS (Continued)
For the Nine Months Ended September 30, 2016 and 2015
(Unaudited)
NOTE 2—SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)
Segment Reporting
The Company operates in a single operating and reportable segment. Operating segments are defined as components of an enterprise for which separate financial information is evaluated regularly by the chief operating decision maker in deciding how to allocate resources and assess performance. The Company's chief operating decision maker allocates resources and assesses performance based upon financial information at the Company level.
Management Estimates
The preparation of financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, as well as certain financial statement disclosures. The Company evaluates estimates and assumptions on an ongoing basis using historical experience and other factors, including the current economic and commodity price environment. While management believes that the estimates and assumptions used in the preparation of the financial statements are appropriate, actual results could differ from these estimates. Significant estimates made in preparing these financial statements include the estimate of uncollected revenues and unpaid expenses from Interests in properties operated by nonaffiliated entities and the estimate of proved oil, natural gas and natural gas liquids reserves and related present value estimates of future net cash flows from those properties.
The discounted present value of the proved oil, natural gas and natural gas liquids reserves is a major component of the ceiling test calculation and requires many subjective judgments. Estimates of reserves are forecasts based on engineering and geological analyses. Different reserve engineers could reach different conclusions as to estimated quantities of oil, natural gas and natural gas liquids reserves based on the same information.
The passage of time provides more qualitative and quantitative information regarding reserve estimates, and revisions are made to prior estimates based on updated information. However, there can be no assurance that more significant revisions will not be necessary in the future. Significant downward revisions could result in an impairment representing a noncash charge to income. In addition to the impact on the calculation of the ceiling test, estimates of proved reserves are also a major component of the calculation of depletion.
Cash and Cash Equivalents
The Company considers all highly liquid instruments purchased with a maturity date of three months or less to be cash and cash equivalents.
F-34
RIVERCREST ROYALTIES, LLC
NOTES TO FINANCIAL STATEMENTS (Continued)
For the Nine Months Ended September 30, 2016 and 2015
(Unaudited)
NOTE 2—SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)
Accounts Receivable
Accounts receivable consists of revenue payments due to us from our Interests and amounts due as reimbursement for costs incurred by the Company. These reimbursable costs included in accounts receivable were $125,271 and $1,356,937 at September 30, 2016 and December 31, 2015, respectively. No allowance for doubtful accounts is deemed necessary based upon the lack of historical write offs and review of current receivables.
Oil and Natural Gas Properties
The Company follows the full cost method of accounting for costs related to its oil and natural gas properties. Under this method, all such costs are capitalized and amortized on an aggregate basis over the estimated lives of the properties using the unit-of-production method.
The capitalized costs are subject to a ceiling test, which limits such pooled costs to the aggregate of the present value of future net revenues attributable to proved oil, natural gas and natural gas liquids reserves discounted at 10% plus the lower of cost or market value of unproved properties. The Company did not assign any value to unproved properties in which it holds an interest. The full cost ceiling is evaluated at the end of each period and additionally when events indicate possible impairment.
While the quantities of proved reserves require substantial judgment, the associated prices of oil, natural gas and natural gas liquids reserves that are included in the discounted present value of our reserves are objectively determined. The ceiling test calculation requires use of the unweighted arithmetic average of the first day of the month price during the 12-month period ending on the balance sheet date and costs in effect as of the last day of the accounting period, which are generally held constant for the life of the properties. As a result, the present value is not necessarily an indication of the fair value of the reserves. Oil, natural gas and natural gas liquids prices have historically been volatile, and the prevailing prices at any given time may not reflect the Company's or the industry's forecast of future prices.
During the nine months ended September 30, 2016 and 2015, management estimates and the cost ceiling analysis established that the Company's proved properties required the recording of an impairment. During the nine months ended September 30, 2016 and 2015, the Company recorded an impairment expense of $4,992,897 and $25,796,352, respectively, as a result of reductions in estimated proved reserves and reduced commodity prices.
The Company's properties are being depleted on the unit-of-production method using estimates of proved oil, natural gas and natural gas liquids reserves. Gains and losses are recognized upon the disposition of oil and natural gas properties involving a significant portion (greater than 25%) of the Company's reserves.
F-35
RIVERCREST ROYALTIES, LLC
NOTES TO FINANCIAL STATEMENTS (Continued)
For the Nine Months Ended September 30, 2016 and 2015
(Unaudited)
NOTE 2—SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)
Proceeds from other dispositions of oil and natural gas properties are credited to the full cost pool. No gains or losses were recorded for the nine months ended September 30, 2016 and 2015.
Due to the nature of the Company's Interests, there are no exploratory activities pending determination, and no exploratory costs were charged to expense for the nine months ended September 30, 2016 and 2015.
Asset Retirement Obligations
The Company's asset retirement obligation ("ARO") reflects the present value of estimated costs of dismantlement, removal, site reclamation, and similar activities associated with the Company's non-operated working interests in oil and natural gas properties.
Fair values of legal obligations to retire and remove long-lived assets are recorded when the obligation is incurred. When the liability is initially recorded, the Company capitalizes this cost by increasing the carrying amount of the related property and equipment. Over time, the liability is accreted for the change in its present value and the capitalized cost in oil and natural gas properties is depleted based on units of production consistent with the related asset.
Loan Origination Costs
The Company records costs associated with establishing its debt facilities as loan origination costs and amortizes such costs over the terms of the respective loans.
Income Taxes
The Company is a limited liability company and is taxed as a partnership under the Internal Revenue Code whereby the Company's members are taxed on their proportionate share of taxable income. The financial statements, therefore, do not include a provision for federal income taxes.
Texas imposes a franchise tax (commonly referred to as the Texas margin tax, which is considered an income tax) at a rate of 0.95% on gross revenues less certain deductions, as specifically set forth in the Texas margin tax statute. During the nine months ended September 30, 2016 and 2015, the Company incurred income taxes in Texas and other states amounting to $13,401 and $11,557, respectively.
Uncertain tax positions are recognized in the financial statements only if that position is more-likely-than-not of being sustained upon examination by taxing authorities, based on the technical merits of the position. At September 30, 2016, the Company had no uncertain tax positions.
F-36
RIVERCREST ROYALTIES, LLC
NOTES TO FINANCIAL STATEMENTS (Continued)
For the Nine Months Ended September 30, 2016 and 2015
(Unaudited)
NOTE 2—SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)
The Company recognizes interest and penalties related to uncertain tax positions in income tax expense. For the nine months ended September 30, 2016 and 2015, the Company did not recognize any interest or penalty expense related to uncertain tax positions.
The Company has filed all tax returns to date that are currently due.
Limited Liability Company
As a limited liability company, the members of the Company are not liable for the liabilities or other obligations of the Company, and the Company will continue perpetually until terminated pursuant to statute or any provisions of its limited liability company agreement (the "Company Agreement").
Revenue Recognition
The Company recognizes revenue when it is realized or realizable and earned. Revenues are considered realized or realizable and earned when: (i) persuasive evidence of an arrangement exists, (ii) delivery has occurred or services have been rendered, (iii) the seller's price to the buyer is fixed or determinable, and (iv) collectability is reasonably assured.
As an owner of Interests, the Company is entitled to a portion of the revenues received from the production of oil, natural gas and associated natural gas liquids from the underlying acreage, net of post-production expenses and taxes. The pricing of oil, natural gas and natural gas liquids sales from the properties is primarily determined by supply and demand in the marketplace and can fluctuate considerably. The Company has no involvement or operational control over the volumes and method of sale of oil, natural gas and natural gas liquids produced and sold from the properties.
To the extent actual volumes and prices of oil, natural gas and natural gas liquids are unavailable for a given reporting period because of timing or information not received from third parties, the expected sales volume and prices for these properties are estimated and recorded within accounts receivable in the accompanying balance sheet. Differences between estimates of revenue and the actual amounts are adjusted and recorded in the period that the actual amounts are known.
Fair Value Measurements
The carrying amount of cash and cash equivalents, accounts receivable, and accounts payable, as reflected in the balance sheets, approximate fair value because of the short-term maturity of these instruments. The carrying amount reported for long-term debt represents fair value as the interest rates approximate current market rates. These estimated fair values may not
F-37
RIVERCREST ROYALTIES, LLC
NOTES TO FINANCIAL STATEMENTS (Continued)
For the Nine Months Ended September 30, 2016 and 2015
(Unaudited)
NOTE 2—SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)
be representative of actual values of the financial instruments that could have been realized or that will be realized in the future.
Fair value is defined as the price that would be received to sell an asset or the price paid to transfer a liability in an orderly transaction between market participants at the measurement date. Fair value measurements are based upon inputs that market participants use in pricing an asset or liability, which are characterized according to a hierarchy that prioritizes those inputs based on the degree to which they are observable. Observable inputs represent market data obtained from independent sources, whereas unobservable inputs reflect a company's own market assumptions, which are used if observable inputs are not reasonably available without undue cost and effort. The three input levels of the fair value hierarchy are as follows:
- •
-
Level 1—quoted market prices for identical assets or liabilities in active markets.
- •
-
Level 2—quoted market prices for similar assets or liabilities in active markets; quoted prices for identical or
similar assets or liabilities in markets that are not active; inputs other than quoted prices that are observable for the asset or liability and inputs derived principally from or corroborated by
observable market data by correlation or other means.
- •
- Level 3—unobservable inputs for the asset or liability.
The ARO is classified within Level 3 as the fair value is estimated using discounted cash flow projections using numerous estimates, assumptions and judgments regarding such factors as the existence of a legal obligation for an ARO, estimated amounts and timing of settlements, the credit-adjusted risk-free rate to be used and inflation rates. See Note 10 for the summary of changes in the fair value of the ARO for the nine months ended September 30, 2016.
Recently Issued Accounting Pronouncements
The Company has implemented all new accounting pronouncements that have required adoption and does not believe that there are any others that would have a material impact on its financial statements, except as discussed below.
In May 2014, the Financial Accounting Standards Board (the "FASB") issued an accounting standards update on a comprehensive new revenue recognition standard that will supersede Accounting Standards Codification ("ASC") 605, Revenue Recognition. The new accounting guidance creates a framework under which an entity will allocate the transaction price to separate performance obligations and recognize revenue when each performance obligation is satisfied. Under the new standard, entities will be required to use judgment and make estimates, including identifying performance obligations in a contract, estimating the amount of variable consideration to include in the transaction price, allocating the transaction price to each separate
F-38
RIVERCREST ROYALTIES, LLC
NOTES TO FINANCIAL STATEMENTS (Continued)
For the Nine Months Ended September 30, 2016 and 2015
(Unaudited)
NOTE 2—SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)
performance obligation, and determining when an entity satisfies its performance obligations. The standard allows for either "full retrospective" adoption, meaning that the standard is applied to all of the periods presented with a cumulative catch-up as of the earliest period presented, or "modified retrospective" adoption, meaning the standard is applied only to the most current period presented in the financial statements with a cumulative catch-up as of the current period.
In July 2015, the FASB decided to defer the original effective date by one year to be effective for annual reporting periods beginning after December 15, 2017 instead of December 15, 2016 for public entities. The Company is still evaluating the impact that the new accounting guidance will have on its financial statements and related disclosures and has not yet determined the method by which it will adopt the standard.
In February 2016, the FASB issued Accounting Standard Update ("ASU") No. 2016-02, Leases (Topic 842) , which requires lessees to recognize the lease assets and lease liabilities classified as operating leases on the balance sheet. The amendment will be effective for reporting periods beginning on or after December 15, 2018, and early adoption is permitted. The Company is evaluating the impact that the new accounting guidance will have on its financial statements and related disclosures.
In March 2016, the FASB issued ASU No. 2016-06, Derivatives and Hedging (Topic 815): Contingent put and call options in debt instruments , which clarifies the requirements for assessing whether contingent call (put) options that can accelerate the payment of principal on debt instruments are clearly and closely related to their debt hosts. The amendment will be effective prospectively for reporting periods beginning on or after December 31, 2016, and early adoption is permitted. The Company does not expect that the impact of adopting this guidance will be material to the Company's financial statements and related disclosures.
In March 2016, the FASB issued ASU No. 2016-08, Revenue from Contracts with Customers (Topic 606): Principal versus agent considerations (reporting revenue gross versus net) , which clarifies the implementation guidance on principal versus agent considerations. The amendment will be effective prospectively for reporting periods beginning on or after December 31, 2017, and early adoption is not permitted. The Company is evaluating the impact that the new accounting guidance will have on its financial statements and related disclosures.
In March 2016, the FASB issued ASU No. 2016-09, Compensation—Stock Compensation (Topic 718): Improvements to employee share-based payment accounting , which includes provisions intended to simplify various aspects related to how share-based compensation payments are accounted for and presented in the financial statements. This amendment will be effective prospectively for reporting periods beginning on or after December 15, 2016, and early adoption is permitted. The Company is evaluating the impact that the new accounting guidance will have on its financial statements and related disclosures.
F-39
RIVERCREST ROYALTIES, LLC
NOTES TO FINANCIAL STATEMENTS (Continued)
For the Nine Months Ended September 30, 2016 and 2015
(Unaudited)
NOTE 2—SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)
In June 2016, the FASB issued ASU No. 2016-13, Financial Instruments—Credit Losses (Topic 326): Measurement of credit losses on financial instruments, which changes the impairment model for most financial assets and certain other instruments, including trade and other receivables, held-to-maturity debt securities and loans, and requires entities to use a new forward-looking expected loss model that will result in the earlier recognition of allowance for losses. This amendment is effective for fiscal years beginning after December 15, 2019, and early adoption is permitted. Entities will apply the standard's provisions as a cumulative-effect adjustment to retained earnings as of the beginning of the first reporting period in which the guidance is adopted. The Company is evaluating the impact that the new accounting guidance will have on its financial statements and related disclosures.
NOTE 3—LONG-TERM DEBT
On January 31, 2014, the Company entered into a credit agreement with Frost Bank for up to a $50,000,000 revolving credit facility. The credit facility is subject to borrowing base restrictions and is collateralized by certain properties. The initial borrowing base was $10,000,000. Interest is payable monthly on Alternate Base Rate loans or at the end of the interest period on any Eurodollar loans, with all principal and unpaid interest due at maturity on January 15, 2018. The credit facility provides for access to standby and/or commercial letters of credit up to an aggregate sum of $1,000,000. The credit facility also provides for commitment fees of 0.50% calculated on the difference between the borrowing base and the aggregate outstanding loans under the credit facility.
The credit facility is subject to semi-annual redeterminations of the borrowing base to be performed on February 1 and August 1 of each year. In addition to the scheduled semi-annual borrowing base redeterminations, the lenders or the Company have the right to redetermine the borrowing base at any time, provided that no party can request more than one such redetermination between the regularly scheduled borrowing base redeterminations. The determination of the borrowing base is subject to a number of factors including quantities of proved oil, natural gas and natural gas liquids reserves, Frost Bank's price assumptions and other various factors. Frost Bank can redetermine the borrowing base to a lower level than the current borrowing base if they determine that the oil, natural gas and natural gas liquids reserves, at the time of redetermination, are inadequate to support the borrowing base then in effect.
On May 12, 2014, the Company and Frost Bank amended the credit facility to increase the borrowing base to $20,000,000 and to change certain covenants. At September 30, 2016 and December 31, 2015, the Company had outstanding advances on long-term debt totaling $10,898,860 and $11,448,860, respectively. At September 30, 2016 and December 31, 2015, the weighted average interest rate on the Company's outstanding advances was 3.27% and 3.03%, respectively.
F-40
RIVERCREST ROYALTIES, LLC
NOTES TO FINANCIAL STATEMENTS (Continued)
For the Nine Months Ended September 30, 2016 and 2015
(Unaudited)
NOTE 3—LONG-TERM DEBT (Continued)
On January 28, 2016, the Company and Frost Bank amended the credit facility to decrease the borrowing base to $13,000,000 and to change certain covenants.
On May 23, 2016, the Company and Frost Bank amended the credit facility to extend the maturity date of the credit facility to January 15, 2018.
The credit facility contains certain restrictive covenants. At September 30, 2016, the Company was not in compliance with the Debt to EBITDAX Ratio, as defined in the credit facility. On November 14, 2016, the Company received from the bank a formal waiver of this covenant, effective as of September 30, 2016. The Company was in compliance with all other debt covenants at September 30, 2016.
NOTE 4—COMMON UNITS
Limited Call Right
The Company Agreement provides for a limited call right. If at any time any person owns more than 90% of the then issued and outstanding membership interests of any class, such person will have the right, which it may assign in whole or in part to any of its affiliates or to the Company, to acquire all, but not less than all, of the remaining membership interests of the class held by unaffiliated persons as of a record date to be selected by the Company's board of managers (the "Board of Managers"), on at least 10 but not more than 60 days' notice. Unitholders are not entitled to dissenters' rights of appraisal under the Company Agreement or applicable Delaware law if this limited call right is exercised.
Distributions
The Company may distribute funds of the Company that the Board of Managers reasonably determines are not needed for payment of existing or foreseeable Company obligations and expenditures at such times and in such amounts as the Board of Managers determines to be appropriate. Distributions are made to all unitholders pro rata in accordance with their respective sharing ratios. During the nine months ended September 30, 2016 and 2015, the Company declared distributions to members totaling $0 and $3,249,327, respectively.
NOTE 5—EARNINGS PER UNIT
The earnings per unit ("EPU") on the statements of operations is based on the net loss of the Company for the nine months ended September 30, 2016 and September 30, 2015, since this is the amount of net loss that is attributable to the Company's common units.
Payments made to the Company's unitholders are determined in relation to the cash distribution policy described in Note 4—Common Units.
F-41
RIVERCREST ROYALTIES, LLC
NOTES TO FINANCIAL STATEMENTS (Continued)
For the Nine Months Ended September 30, 2016 and 2015
(Unaudited)
NOTE 5—EARNINGS PER UNIT (Continued)
Basic EPU is calculated by dividing net income by the weighted-average number of common units outstanding during the period. Diluted net income per common unit gives effect, when applicable, to unvested common units granted under the Company's long-term incentive plan described in Note 6—Unit-Based Compensation. At September 30, 2016 and September 30, 2015, the effect of the 110,000 options issued under the Company's long-term incentive plan would be anti-dilutive. Therefore, the options issued under the Company's long-term incentive plan were not included in the diluted EPU calculation on the statements of operations.
|
|
Nine Months Ended
September 30, |
||||||
|---|---|---|---|---|---|---|---|
|
|
2016 | 2015 | |||||
|
Net income attributable to the period |
$ | (6,018,014 | ) | $ | (27,321,566 | ) | |
|
Net income per common unit, basic and diluted |
$ | (9.96 | ) | $ | (45.22 | ) | |
|
Weighted-average common units outstanding, basic and diluted |
604,137 | 604,137 | |||||
NOTE 6—UNIT-BASED COMPENSATION
On October 1, 2014, the Board of Managers approved and adopted a long-term incentive plan that provided for the issuance of up to 110,000 membership units in the form of options.
Certain unitholders were granted options as compensation for services they performed for the Company. The options vest upon the first to occur of five years from the grant date or upon a change in control of the Company. The options expire ten years from the grant date. The options carry a distribution right, whereby the option holder receives distributions that are commensurate with those given to holders of membership units. The option agreement also specifies the option holder will receive a cumulative catch-up payment for distributions made to unitholders since inception of the Company to the date of grant. The Company has recognized compensation expense for the cumulative catch-up distribution payments in the period paid and the vesting of the options ratably over the vesting period.
The fair value of each option award was estimated on the date of grant using the Black-Scholes option pricing model and using certain assumptions. The risk-free interest rate represents the U.S. Treasury bill rate for the expected life of the related unit options. The expected distribution represents the Company's historical and anticipated cash distributions over the expected life of the unit options. The grant date fair value of the options was $27.50 per
F-42
RIVERCREST ROYALTIES, LLC
NOTES TO FINANCIAL STATEMENTS (Continued)
For the Nine Months Ended September 30, 2016 and 2015
(Unaudited)
NOTE 6—UNIT-BASED COMPENSATION (Continued)
unit, based on a grant date of October 1, 2014, which was determined with the following assumptions:
|
Expected volatility (1) |
55 | % | ||
|
Expected distributions (2) |
7 | % | ||
|
Expected term (in years) |
5 | |||
|
Risk free interest rate (3) |
1.69 | % |
- (1)
-
Because
the Company's membership units have no trading history, the Company does not have sufficient information available on which to base a reasonable and
supportable estimate of the expected volatility of its unit price. As a result, the Company used an average historical volatility of the Company's peer group over a time period consistent with its
expected term assumption. The Company's peer group was determined based upon industry peers with similar business models.
- (2)
-
At
the time of the unit grant, the Company had historically paid a 7% distribution.
- (3)
- Based on the yields of U.S. Department of Treasury instruments with similar expected lives.
A summary of the unit option activity as of September 30, 2016 is as follows:
For the nine months ended September 30, 2016 and 2015, total compensation expense for awards under the long-term incentive plan was $453,795 and $453,795, respectively, and is included general and administrative expenses in the statements of operations. Unrecognized compensation expense at September 30, 2016 was $1,815,178, which will be recognized on a straight-line basis over the remaining vesting period of the options. As of September 30, 2016, no units have been forfeited from awards made under the long-term incentive plan.
As of September 30, 2016, there were no additional units available for future issuance under the long-term incentive plan.
F-43
RIVERCREST ROYALTIES, LLC
NOTES TO FINANCIAL STATEMENTS (Continued)
For the Nine Months Ended September 30, 2016 and 2015
(Unaudited)
NOTE 7—RELATED PARTY TRANSACTIONS
During the nine months ended September 30, 2016 and 2015, the Company had certain related party receivables and payables; however, such amounts are de minimis at September 30, 2016.
NOTE 8—ADMINISTRATIVE SERVICES
The Company relies upon its officers, directors and outside consultants to further its business efforts. The Company also hires independent contractors and consultants involved in land, technical, regulatory and other disciplines to assist its officers and directors. Certain administrative services are being provided by individuals on the Company's Board of Managers and their affiliated entities.
NOTE 9—COMMITMENTS AND CONTINGENCIES
Management is not aware of any legal, environmental or other commitments or contingencies that would have a material effect on the Company's financial condition, results of operations or liquidity.
NOTE 10—ASSET RETIREMENT OBLIGATIONS
The ARO liability reflects the present value of estimated costs of dismantlement, removal, site reclamation, and similar activities associated with the Company's non-operated working interest in oil and natural gas properties. The Company utilizes current retirement costs to estimate the expected cash outflows for retirement obligations. The Company estimates the ultimate productive life of its properties, a risk-adjusted discount rate, and an inflation factor in order to determine the current present value of this obligation.
To the extent future revisions to these assumptions impact the present value of the existing ARO liability, a corresponding adjustment is made to the oil and natural gas property balance. The following table describes changes to the Company's ARO liability during the period:
|
|
For the
Nine Months Ended September 30, 2016 |
|||
|---|---|---|---|---|
|
Asset retirement obligation at December 31, 2015 |
$ | 40,352 | ||
|
Accretion expense |
842 | |||
| | | | | |
|
Asset retirement obligation at September 30, 2016 |
$ | 41,194 | ||
| | | | | |
| | | | | |
| | | | | |
NOTE 11—SUBSEQUENT EVENTS
Management has evaluated subsequent events through November 22, 2016, the date the financial statements were issued.
F-44
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
Board
of Managers
Rivercrest Royalties, LLC
We have audited the accompanying balance sheets of Rivercrest Royalties, LLC, a Delaware limited liability company (the "Company"), as of December 31, 2015 and 2014, and the related statements of operations, changes in members' equity, and cash flows for each of the two years in the period ended December 31, 2015. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States) and in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. We were not engaged to perform an audit of the Company's internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Rivercrest Royalties, LLC as of December 31, 2015 and 2014, and the results of its operations and its cash flows for each of the two years in the period ended December 31, 2015 in conformity with accounting principles generally accepted in the United States of America.
/s/ GRANT THORNTON LLP
Dallas,
Texas
July 15, 2016 (except for Note 6, as to which the date is November 22, 2016)
F-45
RIVERCREST ROYALTIES, LLC
BALANCE SHEETS
|
|
As of
December 31, |
||||||
|---|---|---|---|---|---|---|---|
|
|
2015 | 2014 | |||||
|
Assets |
|||||||
|
Current assets |
|||||||
|
Cash and cash equivalents |
$ | 379,741 | $ | 268,066 | |||
|
Oil, natural gas and NGL revenues receivable |
407,648 | 872,525 | |||||
|
Other receivables |
1,371,540 | 6,441 | |||||
| | | | | | | | |
|
Total current assets |
2,158,929 | 1,147,032 | |||||
|
Property and equipment, net |
347,815 | — | |||||
|
Oil and natural gas properties, at cost |
|||||||
|
Oil and natural gas properties (full cost method) |
70,809,962 | 70,303,282 | |||||
|
Less: accumulated depreciation, depletion, accretion and impairment |
(45,457,931 | ) | (12,784,406 | ) | |||
| | | | | | | | |
|
Total oil and natural gas properties |
25,352,031 | 57,518,876 | |||||
|
Loan origination costs, net |
47,015 | 87,980 | |||||
| | | | | | | | |
|
Total assets |
$ | 27,905,790 | $ | 58,753,888 | |||
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
|
Liabilities and members' equity |
|||||||
|
Current liabilities |
|||||||
|
Accounts payable |
$ | 1,983,662 | $ | 227,105 | |||
|
Other current liabilities |
35,967 | 27,284 | |||||
|
Asset retirement obligation, current portion |
1,223 | 1,199 | |||||
|
Member distributions payable |
— | 1,258,491 | |||||
| | | | | | | | |
|
Total current liabilities |
2,020,852 | 1,514,079 | |||||
|
Asset retirement obligation, net of current portion |
39,129 | 38,333 | |||||
|
Other liabilities |
157,527 | — | |||||
|
Long-term debt |
11,448,860 | 9,003,860 | |||||
| | | | | | | | |
|
Total liabilities |
13,666,368 | 10,556,272 | |||||
|
Commitments and contingencies |
|||||||
|
Members' equity |
14,239,422 | 48,197,616 | |||||
| | | | | | | | |
|
Total liabilities and members' equity |
$ | 27,905,790 | $ | 58,753,888 | |||
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
The accompanying notes are an integral part of these financial statements.
F-46
RIVERCREST ROYALTIES, LLC
STATEMENTS OF OPERATIONS
|
|
For the Years Ended
December 31, |
||||||
|---|---|---|---|---|---|---|---|
|
|
2015 | 2014 | |||||
|
Oil, natural gas and NGL revenues |
$ | 4,684,923 | $ | 7,219,822 | |||
|
Costs and expenses |
|||||||
|
Production and ad valorem taxes |
426,885 | 568,327 | |||||
|
Depreciation, depletion and accretion expenses |
4,008,730 | 4,044,802 | |||||
|
Impairment of oil and natural gas properties |
28,673,166 | 7,416,747 | |||||
|
Marketing and other deductions |
747,264 | 526,727 | |||||
|
General and administrative expenses |
1,789,884 | 1,757,377 | |||||
| | | | | | | | |
|
Total costs and expenses |
35,645,929 | 14,313,980 | |||||
| | | | | | | | |
|
Operating loss |
(30,961,006 | ) | (7,094,158 | ) | |||
|
Interest expense |
385,119 | 302,118 | |||||
| | | | | | | | |
|
Loss before income taxes |
(31,346,125 | ) | (7,396,276 | ) | |||
|
State income taxes |
(32,199 | ) | 16,970 | ||||
| | | | | | | | |
|
Net loss |
$ | (31,313,926 | ) | $ | (7,413,246 | ) | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
|
Net loss per common unit (unaudited—Note 6) |
|||||||
|
Basic and diluted |
$ | (51.83 | ) | $ | (14.47 | ) | |
|
Weighted average number of units outstanding |
|||||||
|
Basic and diluted |
604,137 | 512,149 | |||||
The accompanying notes are an integral part of these financial statements.
F-47
RIVERCREST ROYALTIES, LLC
STATEMENTS OF CHANGES IN MEMBERS' EQUITY
|
|
Total | |||
|---|---|---|---|---|
|
Members' equity—January 1, 2014 |
$ | 25,623,438 | ||
|
Contributions of cash |
34,150,000 | |||
|
Contributions of oil and natural gas properties |
329,876 | |||
|
Distributions to members |
(4,643,717 | ) | ||
|
Unit-based compensation |
151,265 | |||
|
Net loss |
(7,413,246 | ) | ||
| | | | | |
|
Members' equity—December 31, 2014 |
$ | 48,197,616 | ||
|
Distributions to members |
(3,249,327 | ) | ||
|
Unit-based compensation |
605,059 | |||
|
Net loss |
(31,313,926 | ) | ||
| | | | | |
|
Members' equity—December 31, 2015 |
$ | 14,239,422 | ||
| | | | | |
| | | | | |
| | | | | |
The accompanying notes are an integral part of these financial statements.
F-48
RIVERCREST ROYALTIES, LLC
STATEMENTS OF CASH FLOWS
The accompanying notes are an integral part of these financial statements.
F-49
RIVERCREST ROYALTIES, LLC
NOTES TO FINANCIAL STATEMENTS
For the Years Ended December 31, 2015 and 2014
NOTE 1—ORGANIZATION
Rivercrest Royalties, LLC (the "Company") is a Delaware limited liability company formed on October 25, 2013. The Company is a Fort Worth, Texas based owner of oil, natural gas and natural gas liquids mineral and royalty interests in the United States of America ("United States"). In addition to mineral and royalty interests, the Company's assets include overriding royalty interests. These non-cost-bearing interests are collectively referred to as "mineral and royalty interests." The Company also has non-operated working interests in certain oil and natural gas properties, which together with the mineral and royalty interests, we refer to as the "Interests." The Company has Interests in nearly every major onshore basin across the continental United States.
NOTE 2—SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Basis of Presentation
The Company's year-end is December 31. The accompanying financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America ("U.S. GAAP"). A summary of the significant accounting policies applied in the preparation of the accompanying financial statements follows.
Segment Reporting
The Company operates in a single operating and reportable segment. Operating segments are defined as components of an enterprise for which separate financial information is evaluated regularly by the chief operating decision maker in deciding how to allocate resources and assess performance. The Company's chief operating decision maker allocates resources and assesses performance based upon financial information at the Company level.
Management Estimates
The preparation of financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, as well as certain financial statement disclosures. The Company evaluates estimates and assumptions on an ongoing basis using historical experience and other factors, including the current economic and commodity price environment. While management believes that the estimates and assumptions used in the preparation of the financial statements are appropriate, actual results could differ from these estimates. Significant estimates made in preparing these financial statements include the estimate of uncollected revenues and unpaid expenses from Interests in properties operated by nonaffiliated entities and the estimate of proved oil, natural gas and natural gas liquids reserves and related present value estimates of future net cash flows from those properties.
The discounted present value of the proved oil, natural gas and natural gas liquids reserves is a major component of the ceiling test calculation and requires many subjective judgments.
F-50
RIVERCREST ROYALTIES, LLC
NOTES TO FINANCIAL STATEMENTS (Continued)
For the Years Ended December 31, 2015 and 2014
NOTE 2—SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)
Estimates of reserves are forecasts based on engineering and geological analyses. Different reserve engineers could reach different conclusions as to estimated quantities of oil, natural gas and natural gas liquids reserves based on the same information.
The passage of time provides more qualitative and quantitative information regarding reserve estimates, and revisions are made to prior estimates based on updated information. However, there can be no assurance that more significant revisions will not be necessary in the future. Significant downward revisions could result in an impairment representing a noncash charge to income. In addition to the impact on the calculation of the ceiling test, estimates of proved reserves are also a major component of the calculation of depletion.
Cash and Cash Equivalents
The Company considers all highly liquid instruments purchased with a maturity date of three months or less to be cash and cash equivalents.
Accounts Receivable
Accounts receivable consists of revenue payments due to us from our Interests and amounts due as reimbursement for costs incurred by the Company. These reimbursable costs included in accounts receivable were $1,356,937 and $0 at December 31, 2015 and 2014, respectively. The Company estimates portions of these receivables for which failure to collect is probable based on the relevant facts and circumstances surrounding the receivable. As of December 31, 2015 and 2014, no allowance for doubtful accounts is deemed necessary based upon the lack of historical write offs and review of current receivables.
Property and Equipment
Other property and equipment includes furniture, fixtures, office equipment, leasehold improvements, and computer software and is stated at historical cost. Depreciation and amortization are calculated using the straight-line method over expected useful lives ranging from three to seven years. Leasehold improvements are depreciated over the term of the underlying lease. Depreciation expense totaled $7,551 and $0 during the years ended December 31, 2015 and 2014, respectively. As of December 31, 2015, property and equipment consisted of the following:
|
Computer hardware and equipment |
$ | 4,290 | ||
|
Office furniture and equipment |
27,669 | |||
|
Leasehold improvements |
323,407 | |||
|
Less: accumulated depreciation |
(7,551 | ) | ||
| | | | | |
|
Property and equipment, net |
$ | 347,815 | ||
| | | | | |
| | | | | |
| | | | | |
F-51
RIVERCREST ROYALTIES, LLC
NOTES TO FINANCIAL STATEMENTS (Continued)
For the Years Ended December 31, 2015 and 2014
NOTE 2—SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)
Oil and Natural Gas Properties
The Company follows the full cost method of accounting for costs related to its oil, natural gas and natural gas liquids properties. Under this method, all such costs are capitalized and amortized on an aggregate basis over the estimated lives of the properties using the unit-of-production method.
The capitalized costs are subject to a ceiling test, which limits such pooled costs to the aggregate of the present value of future net revenues attributable to proved oil, natural gas and natural gas liquids reserves discounted at 10% plus the lower of cost or market value of unproved properties. The Company did not assign any value to unproved properties in which it holds an interest. The full cost ceiling is evaluated at the end of each period and additionally when events indicate possible impairment.
While the quantities of proved reserves require substantial judgment, the associated prices of oil, natural gas and natural gas liquids reserves that are included in the discounted present value of our reserves are objectively determined. The ceiling test calculation requires use of the unweighted arithmetic average of the first day of the month price during the 12-month period ending on the balance sheet date and costs in effect as of the last day of the accounting period, which are generally held constant for the life of the properties. As a result, the present value is not necessarily an indication of the fair value of the reserves. Oil, natural gas and natural gas liquids prices have historically been volatile, and the prevailing prices at any given time may not reflect the Company's or the industry's forecast of future prices.
During the years ended December 31, 2015 and 2014, management's estimates and the cost ceiling analysis established that the Company's proved properties required the recording of an impairment.
The Company recorded an impairment expense of $28,673,166 and $7,416,747 for the years ended December 31, 2015 and 2014, respectively, as a result of reductions in estimated proved reserves and reduced commodity prices.
The Company's properties are being depleted on the unit-of-production method using estimates of proved oil, natural gas and natural gas liquids reserves. Gains and losses are recognized upon the disposition of oil, natural gas and natural gas liquids properties involving a significant portion (greater than 25%) of the Company's reserves.
Proceeds from other dispositions of oil, natural gas and natural gas liquids properties are credited to the full cost pool. No gains or losses were recorded for the years ended December 31, 2015 and 2014.
F-52
RIVERCREST ROYALTIES, LLC
NOTES TO FINANCIAL STATEMENTS (Continued)
For the Years Ended December 31, 2015 and 2014
NOTE 2—SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)
Due to the nature of the Company's Interests, there are no exploratory activities pending determination, and no exploratory costs were charged to expense for the years ended December 31, 2015 and 2014.
Asset Retirement Obligations
The Company's asset retirement obligation ("ARO") reflects the present value of estimated costs of dismantlement, removal, site reclamation, and similar activities associated with the Company's non-operated working interests in oil and natural gas properties.
Fair values of legal obligations to retire and remove long-lived assets are recorded when the obligation is incurred. When the liability is initially recorded, the Company capitalizes this cost by increasing the carrying amount of the related property and equipment. Over time, the liability is accreted for the change in its present value and the capitalized cost in oil and natural gas properties is depleted based on units of production consistent with the related asset.
Loan Origination Costs
The Company records costs associated with establishing its debt facilities as loan origination costs and amortizes such costs over the terms of the respective loans.
Other Long-Term Liabilities
Other long-term liabilities consist of the tenant improvement allowance granted at the effective date of the lease for the Company's office space. This allowance is accounted for as a deferred incentive and will be amortized over the term of the lease as a reduction to future rent expense.
Income Taxes
The Company is a limited liability company and is taxed as a partnership under the Internal Revenue Code whereby the Company's members are taxed on their proportionate share of taxable income. The financial statements, therefore, do not include a provision for federal income taxes.
Texas imposes a franchise tax (commonly referred to as the Texas margin tax, which is considered an income tax) at a rate of 0.95% on gross revenues less certain deductions, as specifically set forth in the Texas margin tax statute. During the years ended December 31, 2015 and 2014, the Company incurred income taxes in Texas and other states amounting to $8,111 and $16,970, respectively. During the year ended December 31, 2015, the Company was refunded $40,310 from states for overpayments of income tax payments made in prior years. These refunds are recognized in the statements of operations as an offset to state income tax expense.
F-53
RIVERCREST ROYALTIES, LLC
NOTES TO FINANCIAL STATEMENTS (Continued)
For the Years Ended December 31, 2015 and 2014
NOTE 2—SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)
Uncertain tax positions are recognized in the financial statements only if that position is more-likely-than-not of being sustained upon examination by taxing authorities, based on the technical merits of the position. At December 31, 2015 and 2014, the Company had no uncertain tax positions.
The Company recognizes interest and penalties related to uncertain tax positions in income tax expense. For the years ended December 31, 2015 and 2014, the Company did not recognize any interest or penalty expense related to uncertain tax positions.
The Company has filed all tax returns to date that are currently due. Tax returns filed for the years ended December 31 2015, 2014 and 2013 remain subject to possible examination by taxing authorities although no such examination has been requested.
Concentration of Credit Risk
The Company has no involvement or operational control over the volumes and method of sale of oil, natural gas and natural gas liquids produced and sold from the properties. It is believed that the loss of any single customer would not have a material adverse effect on the results of operations.
At times, the Company maintains deposits in federally insured financial institutions in excess of federally insured limits. Management monitors the credit ratings and concentration of risk with these financial institutions on a continuing basis to safeguard cash deposits. The Company has not experienced any losses related to amounts in excess of federally insured limits.
During the year ended December 31, 2015, three purchasers accounted for approximately 19%, 13% and 10% of oil, natural gas and natural gas liquids sales revenue. During the year ended December 31, 2014, two purchasers accounted for approximately 19% and 14% of oil, natural gas and natural gas liquids sales revenue.
Limited Liability Company
As a limited liability company, the members of the Company are not liable for the liabilities or other obligations of the Company, and the Company will continue perpetually until terminated pursuant to statute or any provisions of its limited liability company agreement (the "Company Agreement").
Revenue Recognition
The Company recognizes revenue when it is realized or realizable and earned. Revenues are considered realized or realizable and earned when: (i) persuasive evidence of an arrangement
F-54
RIVERCREST ROYALTIES, LLC
NOTES TO FINANCIAL STATEMENTS (Continued)
For the Years Ended December 31, 2015 and 2014
NOTE 2—SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)
exists, (ii) delivery has occurred or services have been rendered, (iii) the seller's price to the buyer is fixed or determinable, and (iv) collectability is reasonably assured.
As an owner of Interests, the Company is entitled to a portion of the revenues received from the production of oil, natural gas and associated natural gas liquids from the underlying acreage, net of post-production expenses and taxes. The pricing of oil, natural gas and natural gas liquids sales from the properties is primarily determined by supply and demand in the marketplace and can fluctuate considerably. The Company has no involvement or operational control over the volumes and method of sale of oil, natural gas and natural gas liquids produced and sold from the properties.
To the extent actual volumes and prices of oil, natural gas and natural gas liquids are unavailable for a given reporting period because of timing or information not received from third parties, the expected sales volume and prices for these properties are estimated and recorded within accounts receivable in the accompanying consolidated balance sheet. Differences between estimates of revenue and the actual amounts are adjusted and recorded in the period that the actual amounts are known.
Fair Value Measurements
The carrying amount of cash and cash equivalents, accounts receivable, and accounts payable, as reflected in the balance sheets, approximate fair value because of the short-term maturity of these instruments. The carrying amount reported for long-term debt represents fair value as the interest rates approximate current market rates. These estimated fair values may not be representative of actual values of the financial instruments that could have been realized or that will be realized in the future.
Fair value is defined as the price that would be received to sell an asset or the price paid to transfer a liability in an orderly transaction between market participants at the measurement date. Fair value measurements are based upon inputs that market participants use in pricing an asset or liability, which are characterized according to a hierarchy that prioritizes those inputs based on the degree to which they are observable. Observable inputs represent market data obtained from independent sources, whereas unobservable inputs reflect a company's own market assumptions, which are used if observable inputs are not reasonably available without undue cost and effort. The three input levels of the fair value hierarchy are as follows:
- •
-
Level 1—quoted market prices for identical assets or liabilities in active markets.
- •
- Level 2—quoted market prices for similar assets or liabilities in active markets; quoted prices for identical or similar assets or liabilities in markets that are not active; inputs other than quoted prices that are observable for the asset or liability and inputs derived principally from or corroborated by observable market data by correlation or other means.
F-55
RIVERCREST ROYALTIES, LLC
NOTES TO FINANCIAL STATEMENTS (Continued)
For the Years Ended December 31, 2015 and 2014
NOTE 2—SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)
- •
- Level 3—unobservable inputs for the asset or liability.
The ARO is classified within Level 3 as the fair value is estimated using discounted cash flow projections using numerous estimates, assumptions and judgments regarding such factors as the existence of a legal obligation for an ARO, estimated amounts and timing of settlements, the credit-adjusted risk-free rate to be used and inflation rates. See Note 11 for the summary of changes in the fair value of the ARO for the years ended December 31, 2015 and 2014.
Recently Issued Accounting Pronouncements
In May 2014, the Financial Accounting Standards Board (the "FASB") issued an accounting standards update on a comprehensive new revenue recognition standard that will supersede Accounting Standards Codification ("ASC") 605, Revenue Recognition. The new accounting guidance creates a framework under which an entity will allocate the transaction price to separate performance obligations and recognize revenue when each performance obligation is satisfied. Under the new standard, entities will be required to use judgment and make estimates, including identifying performance obligations in a contract, estimating the amount of variable consideration to include in the transaction price, allocating the transaction price to each separate performance obligation, and determining when an entity satisfies its performance obligations. The standard allows for either "full retrospective" adoption, meaning that the standard is applied to all of the periods presented with a cumulative catch-up as of the earliest period presented, or "modified retrospective" adoption, meaning the standard is applied only to the most current period presented in the financial statements with a cumulative catch-up as of the current period.
In July 2015, the FASB decided to defer the original effective date by one year to be effective for annual reporting periods beginning after December 15, 2017 instead of December 15, 2016 for public entities. The Company is still evaluating the impact that the new accounting guidance will have on its financial statements and related disclosures and has not yet determined the method by which it will adopt the standard.
In November 2014, the FASB issued an accounting standards update that clarifies how U.S. GAAP should be applied in determining whether the nature of a host contract is more akin to debt or equity and in evaluating whether the economic characteristics and risks of an embedded feature are "clearly and closely related" to its host contract. The guidance is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2015. The Company adopted this guidance on January 1, 2016, and there was no material impact to the Company's financial statements and related disclosures.
In April 2015, the FASB issued an accounting standards update that requires debt issuance costs related to a recognized debt liability to be presented in the balance sheet as a direct deduction from the carrying value of that debt liability, consistent with debt discounts. The guidance is effective retrospectively for fiscal years, and interim periods within those years,
F-56
RIVERCREST ROYALTIES, LLC
NOTES TO FINANCIAL STATEMENTS (Continued)
For the Years Ended December 31, 2015 and 2014
NOTE 2—SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)
beginning after December 15, 2015. Early adoption is permitted for financial statements that have not been previously issued. The Company does not expect the impact of adopting this guidance will be material to the Company's financial statements and related disclosures.
In September 2015, the FASB issued an accounting standards update that requires that adjustments to provisional amounts identified during the measurement period of a business combination be recognized in the reporting period in which those adjustments are determined, including the effect on earnings, if any, calculated as if the accounting had been completed at the acquisition date. This eliminates the previous requirement to retrospectively account for such adjustments. The new standard also requires additional disclosures related to the income statement effects of adjustments to provisional amounts identified during the measurement period. The guidance is effective for public companies during interim and annual reporting periods beginning after December 15, 2015. Early adoption is permitted. The Company does not expect the impact of adopting this guidance will be material to the Company's financial statements and related disclosures.
NOTE 3—ACQUISITIONS
On December 31, 2013, with an effective date of January 1, 2014, the Company acquired overriding royalty interests located in the Webster Unit in South Texas as well as many other units and interests across Texas, New Mexico, North Dakota and six other states for approximately $8,666,000 including working interests amounting to $575,000.
On February 27, 2014, with an effective date of February 1, 2014, the Company acquired royalty and overriding royalty interests located primarily in the Bakken / Williston Basin in North Dakota as well as various other interests in Wyoming, Utah, Oklahoma and Texas. The total consideration for the purchase was approximately $4,322,000.
On April 2, 2014, with an effective date of April 1, 2014, the Company acquired a diverse portfolio of royalty and overriding royalty interests in various West Texas units and interests in the Permian Basin. The total consideration for the purchase was $10,371,000.
On May 12, 2014, with an effective date of May 1, 2014, the Company acquired diverse royalty and overriding royalty interests located primarily in South and East Texas. The total consideration for the purchase was $9,323,000.
On July 14, 2014, with an effective date of July 1, 2014, the Company acquired diverse royalty and overriding royalty interests located primarily in the Permian Basin. The total consideration for the purchase was $7,034,000.
On July 17, 2014, with an effective date of July 1, 2014, the Company acquired diverse royalty and overriding royalty interests located primarily in the Bakken / Williston Basin in North Dakota. The total consideration for the purchase was $3,090,000.
F-57
RIVERCREST ROYALTIES, LLC
NOTES TO FINANCIAL STATEMENTS (Continued)
For the Years Ended December 31, 2015 and 2014
NOTE 3—ACQUISITIONS (Continued)
On September 10, 2014, with an effective date of July 1, 2014, the Company acquired diverse royalty and overriding royalty interests located in the Barnett Shale / Fort Worth Basin. The total consideration for the purchase was $1,890,000.
The Company determined that the acquisitions, other than one acquisition in 2014 with immaterial working interest components, were the conveyance of a passive interest without inputs and processes necessary to conduct normal operations. Thus, the assets acquired by the Company do not constitute "an integrated set of activities and assets that is capable of being conducted and managed for the purpose of providing a return in the form of dividends, lower costs, or other economic benefits directly to investors or other owners, members, or participants." As a result, the acquisitions by the Company were treated as an acquisition of assets under U.S. GAAP based on the guidance in ASC 805, Business Combinations. Because it is treated as an acquisition of assets, it was not treated as an acquisition of a business for purposes of ASC 805. This methodology requires the recording of net assets acquired and consideration transferred at fair value. The estimated fair values of these properties approximate the consideration paid.
NOTE 4—LONG-TERM DEBT
On January 31, 2014, the Company entered into a credit agreement with Frost Bank for up to a $50,000,000 revolving credit facility. The credit facility is subject to borrowing base restrictions and is collateralized by certain properties. The initial borrowing base was $10,000,000. Interest is payable monthly on Alternate Base Rate loans or at the end of the interest period on any Eurodollar loans, with all principal and unpaid interest due at maturity on January 15, 2018. The credit facility provides for access to standby and/or commercial letters of credit up to an aggregate sum of $1,000,000. The credit facility also provides for commitment fees of 0.50% calculated on the difference between the borrowing base and the aggregate outstanding loans under the credit facility.
The credit facility is subject to semi-annual redeterminations of the borrowing base to be performed on February 1 and August 1 of each year. In addition to the scheduled semi-annual borrowing base redeterminations, the lenders or the Company have the right to redetermine the borrowing base at any time, provided that no party can request more than one such redetermination between the regularly scheduled borrowing base redeterminations. The determination of the borrowing base is subject to a number of factors including quantities of proved oil, natural gas and natural gas liquids reserves, Frost Bank's price assumptions and other various factors. Frost Bank can redetermine the borrowing base to a lower level than the current borrowing base if they determine that the oil, natural gas and natural gas liquids reserves, at the time of redetermination, are inadequate to support the borrowing base then in effect.
On May 12, 2014, the Company and Frost Bank amended the credit facility to increase the borrowing base to $20,000,000 and to change certain covenants. At December 31, 2015 and 2014, the Company had outstanding advances on long-term debt totaling $11,448,860 and $9,003,860,
F-58
RIVERCREST ROYALTIES, LLC
NOTES TO FINANCIAL STATEMENTS (Continued)
For the Years Ended December 31, 2015 and 2014
NOTE 4—LONG-TERM DEBT (Continued)
respectively. The Company was required to pay loan origination fees totaling $122,896 during the year ended December 31, 2014. These loan origination fees are being amortized over the term of the credit agreement. At December 31, 2015 and 2014, the weighted average interest rate on the Company's outstanding advances was 3.03% and 2.65%.
On January 28, 2016, the Company and Frost Bank amended the credit facility to decrease the borrowing base to $13,000,000 and to change certain covenants.
On May 23, 2016, the Company and Frost Bank amended the credit facility to extend the maturity date of the credit facility to January 15, 2018.
The credit facility contains certain restrictive covenants. The Company was in compliance with all of the covenants included in the credit facility as of December 31, 2015. At March 31, 2016, the Company was not in compliance with the Debt to EBITDAX Ratio, as defined in the credit facility. On July 12, 2016, the Company received from the bank a formal waiver of this covenant, effective as of March 31, 2016. The Company was in compliance with all other debt covenants at March 31, 2016.
NOTE 5—COMMON UNITS
Limited Call Right
The Company Agreement provides for a limited call right. If at any time any person owns more than 90% of the then issued and outstanding membership interests of any class, such person will have the right, which it may assign in whole or in part to any of its affiliates or to the Company, to acquire all, but not less than all, of the remaining membership interests of the class held by unaffiliated persons as of a record date to be selected by the Company's Board of Managers (the "Board of Managers"), on at least 10 but not more than 60 days' notice. Unitholders are not entitled to dissenters' rights of appraisal under the Company Agreement or applicable Delaware law if this limited call right is exercised.
Distributions
The Company may distribute funds of the Company that the Board of Managers reasonably determines are not needed for payment of existing or foreseeable Company obligations and expenditures at such times and in such amounts as the Board of Managers determines to be appropriate. Distributions are made to all unitholders pro rata in accordance with their respective sharing ratios. During the years ended December 31, 2015 and 2014, the Company made distributions to members totaling $3,249,327 and $4,643,717, respectively. At December 31, 2015 and 2014, member distributions payable amounted to $0 and $1,258,491, respectively.
F-59
RIVERCREST ROYALTIES, LLC
NOTES TO FINANCIAL STATEMENTS (Continued)
For the Years Ended December 31, 2015 and 2014
NOTE 6—EARNINGS PER UNIT
The earnings per unit ("EPU") on the statements of operations is based on the net income of the Company for the years ended December 31, 2015 and December 31, 2014, since this is the amount of net income that is attributable to the Company's common units.
Payments made to the Company's unitholders are determined in relation to the cash distribution policy described in Note 5—Common Units.
Basic EPU is calculated by dividing net income by the weighted-average number of common units outstanding during the period. Diluted net income per common unit gives effect, when applicable, to unvested common units granted under the Company's long-term incentive plan described in Note 7—Unit-Based Compensation. At December 31, 2015 and December 31, 2014, the effect of the 110,000 options issued under the Company's long-term incentive plan would be anti-dilutive. Therefore, the options issued under the Company's long-term incentive plan were not included in the diluted EPU calculation on the statements of operations.
|
|
Year Ended December 31, | ||||||
|---|---|---|---|---|---|---|---|
|
|
2015 | 2014 | |||||
|
Net income attributable to the period |
$ | (31,313,926 | ) | $ | (7,413,246 | ) | |
|
Net income per common unit, basic and diluted |
$ | (51.83 | ) | $ | (14.47 | ) | |
|
Weighted-average common units outstanding, basic and diluted |
604,137 | 512,149 | |||||
NOTE 7—UNIT-BASED COMPENSATION
On October 1, 2014, the Board of Managers approved and adopted a long-term incentive plan that provided for the issuance of up to 110,000 membership units in the form of options.
Certain unitholders were granted options as compensation for services they performed for the Company. The options vest upon the first to occur of five years from the grant date or upon a change in control of the Company. The options expire ten years from the grant date. The options carry a distribution right, whereby the option holder receives distributions that are commensurate with those given to holders of membership units. The option agreement also specifies the option holder will receive a cumulative catch-up payment for distributions made to unitholders since inception of the Company to the date of grant. The Company has recognized compensation expense for the cumulative catch-up distribution payments in the period paid and the vesting of the options ratably over the vesting period.
The fair value of each option award was estimated on the date of grant using the Black-Scholes option pricing model and using certain assumptions. The risk-free interest rate represents the U.S. Treasury bill rate for the expected life of the related unit options. The expected distribution represents the Company's historical and anticipated cash distributions over the expected life of the unit options. The grant date fair value of the options was $27.50 per
F-60
RIVERCREST ROYALTIES, LLC
NOTES TO FINANCIAL STATEMENTS (Continued)
For the Years Ended December 31, 2015 and 2014
NOTE 7—UNIT-BASED COMPENSATION (Continued)
unit, based on a grant date of October 1, 2014, which was determined with the following assumptions:
|
Expected volatility (1) |
55 | % | ||
|
Expected distributions (2) |
7 | % | ||
|
Expected term (in years) |
5 | |||
|
Risk free interest rate (3) |
1.69 | % |
- (1)
-
Because
the Company's membership units have no trading history, the Company does not have sufficient information available on which to base a reasonable and
supportable estimate of the expected volatility of its unit price. As a result, the Company used an average historical volatility of the Company's peer group over a time period consistent with its
expected term assumption. The Company's peer group was determined based upon industry peers with similar business models.
- (2)
-
At
the time of the unit grant, the Company had historically paid a 7% distribution.
- (3)
- Based on the yields of U.S. Department of Treasury instruments with similar expected lives.
A summary of the unit option activity as of December 31, 2015 is as follows:
For the years ended December 31, 2015 and 2014, total compensation expense for awards under the long-term incentive plan was $605,059 and $151,265, respectively, and is included general and administrative expenses in the statements of operations. Unrecognized compensation expense was $2,268,973, which will be recognized on a straight-line basis over the remaining vesting period of the options. As of December 31, 2015, no units have been forfeited from awards made under the long-term incentive plan. As of December 31, 2015, there were no additional units available for future issuance under the long-term incentive plan.
NOTE 8—RELATED PARTY TRANSACTIONS
During the years ended December 31, 2015 and 2014, the Company had certain related party receivables and payables; however, such amounts are de minimis at December 31, 2015 and 2014. Additionally, during the year ended December 31, 2014, the Company issued membership units to certain existing unit holders as consideration for the contribution of oil and natural gas
F-61
RIVERCREST ROYALTIES, LLC
NOTES TO FINANCIAL STATEMENTS (Continued)
For the Years Ended December 31, 2015 and 2014
NOTE 8—RELATED PARTY TRANSACTIONS (Continued)
properties with a fair value of $329,876. Fair value was determined by a concurrent arm's length transaction with a third party on the same oil and natural gas properties.
NOTE 9—ADMINISTRATIVE SERVICES
The Company relies upon its officers, directors and outside consultants to further its business efforts. The Company also hires independent contractors and consultants involved in land, technical, regulatory and other disciplines to assist its officers and directors. Certain administrative services are being provided by individuals on the Company's Board of Managers and their affiliated entities.
NOTE 10—COMMITMENTS
Effective August 1, 2015, the Company entered into a lease for office space under a non-cancelable operating lease that expires on July 31, 2020. Future minimum rental payments under this non-cancelable operating lease agreement are:
| Years Ending December 31, |
|
|||
|---|---|---|---|---|
|
2016 |
$ | 77,176 | ||
|
2017 |
77,176 | |||
|
2018 |
78,638 | |||
|
2019 |
80,684 | |||
|
2020 |
47,066 | |||
| | | | | |
|
Total |
$ | 360,740 | ||
| | | | | |
| | | | | |
| | | | | |
Rental expense for the years ended December 31, 2015 and 2014 was $24,826 and $20,129, respectively.
Management is not aware of any legal, environmental or other commitments or contingencies that would have a material effect on the Company's financial condition, results of operations or liquidity.
NOTE 11—ASSET RETIREMENT OBLIGATIONS
The asset retirement obligations ("ARO") liability reflects the present value of estimated costs of dismantlement, removal, site reclamation, and similar activities associated with the Company's non-operated working interest in oil, natural gas and natural gas liquids properties. The Company utilizes current retirement costs to estimate the expected cash outflows for retirement obligations. The Company estimates the ultimate productive life of the properties, a risk-adjusted discount rate, and an inflation factor in order to determine the current present value of this obligation. To the extent future revisions to these assumptions impact the present
F-62
RIVERCREST ROYALTIES, LLC
NOTES TO FINANCIAL STATEMENTS (Continued)
For the Years Ended December 31, 2015 and 2014
NOTE 11—ASSET RETIREMENT OBLIGATIONS (Continued)
value of the existing ARO liability, a corresponding adjustment is made to the oil and natural gas property balance. The following table describes changes to the Company's ARO liability:
|
|
As of December 31, | ||||||
|---|---|---|---|---|---|---|---|
|
|
2015 | 2014 | |||||
|
Asset retirement obligation at beginning of year |
$ | 39,532 | $ | 25,553 | |||
|
Liabilities incurred |
— | 12,716 | |||||
|
Accretion expense |
820 | 1,263 | |||||
| | | | | | | | |
|
Asset retirement obligation at end of year |
$ | 40,352 | $ | 39,532 | |||
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
NOTE 12—SUBSEQUENT EVENTS
Management has evaluated subsequent events through July 15, 2016, the date the financial statements were issued.
NOTE 13—SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION (UNAUDITED)
The Company has only one reportable operating segment, which is oil and gas producing activities in the United States. See the Company's accompanying statements of operations for information about results of operations for oil and gas producing activities.
Capitalized oil and natural gas costs
Aggregate capitalized costs related to oil and natural gas production activities with applicable accumulated depreciation, depletion and amortization are as follows:
|
|
December 31, | ||||||
|---|---|---|---|---|---|---|---|
|
|
2015 | 2014 | |||||
|
Oil, natural gas and NGL interests |
|||||||
|
Proved |
$ | 70,809,962 | $ | 70,303,282 | |||
| | | | | | | | |
|
Total oil and natural gas interests |
70,809,962 | 70,303,282 | |||||
|
Accumulated depletion and impairment |
(45,457,931 | ) | (12,784,406 | ) | |||
| | | | | | | | |
|
Net oil and natural gas interests capitalized |
$ | 25,352,031 | $ | 57,518,876 | |||
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
F-63
RIVERCREST ROYALTIES, LLC
NOTES TO FINANCIAL STATEMENTS (Continued)
For the Years Ended December 31, 2015 and 2014
NOTE 13—SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION (UNAUDITED) (Continued)
Costs incurred in oil and natural gas activities
Costs incurred in oil, natural gas and natural gas liquids acquisition and development activities are as follows:
|
|
December 31, | ||||||
|---|---|---|---|---|---|---|---|
|
|
2015 | 2014 | |||||
|
Acquisition costs |
|||||||
|
Proved properties |
$ | 42,000 | $ | 52,885,102 | |||
| | | | | | | | |
|
Total |
42,000 | 52,885,102 | |||||
|
Development costs |
|||||||
|
Proved properties |
464,680 | 577,928 | |||||
| | | | | | | | |
|
Total |
464,680 | 577,928 | |||||
| | | | | | | | |
|
Total costs incurred on oil, natural gas and natural gas liquids activities |
$ | 506,680 | $ | 53,463,030 | |||
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
Results of Operations from Oil, Natural Gas and Natural Gas Liquids Producing Activities
The following schedule sets forth the revenues and expenses related to the production and sale of oil, natural gas and natural gas liquids. It does not include any interest costs or general and administrative costs and, therefore, is not necessarily indicative of the contribution to the net operating results of the Company's oil, natural gas and natural gas liquids operations.
|
|
December 31, | ||||||
|---|---|---|---|---|---|---|---|
|
|
2015 | 2014 | |||||
|
Oil, natural gas and natural gas liquids revenues |
$ | 4,684,923 | $ | 7,219,822 | |||
|
Production and ad valorem taxes |
(426,885 | ) | (568,327 | ) | |||
|
Marketing and other deductions |
(747,264 | ) | (526,727 | ) | |||
|
Depletion |
(4,008,730 | ) | (4,044,802 | ) | |||
|
Impairment |
(28,673,166 | ) | (7,416,747 | ) | |||
| | | | | | | | |
|
Results of operations from oil, natural gas and natural gas liquids |
$ | (29,171,122 | ) | $ | (5,336,781 | ) | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
The following tables summarize the net ownership interest in the proved oil, natural gas and natural gas liquids reserves and the standardized measure of discounted future net cash flows related to the proved oil, natural gas and natural gas liquids reserves, and the estimates were prepared by the Company based on management's estimates for the years ended December 31, 2015 and 2014. The standardized measure presented here excludes income taxes, as the tax basis for the properties is not applicable on a go-forward basis. The proved oil, natural gas and natural
F-64
RIVERCREST ROYALTIES, LLC
NOTES TO FINANCIAL STATEMENTS (Continued)
For the Years Ended December 31, 2015 and 2014
NOTE 13—SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION (UNAUDITED) (Continued)
gas liquids reserve estimates and other components of the standardized measure were determined in accordance with the authoritative guidance of the FASB and the SEC.
Proved Oil, Natural Gas and Natural Gas Liquids Reserve Quantities
Proved reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations. Proved developed reserves are proved reserves that can be expected to be recovered through existing wells with existing equipment and operating methods, or in which the cost of the required equipment is relatively minor compared to the cost of a new well. Proved undeveloped reserves are proved reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.
A barrels of equivalent ("Boe") conversion ratio of six thousand cubic feet per barrel (6mcf/bbl) of natural gas to barrels of oil equivalence is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. All Boe conversions in the report are derived from converting gas to oil in the ratio mix of six thousand cubic feet of gas to one barrel of oil.
F-65
RIVERCREST ROYALTIES, LLC
NOTES TO FINANCIAL STATEMENTS (Continued)
For the Years Ended December 31, 2015 and 2014
NOTE 13—SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION (UNAUDITED) (Continued)
The net proved oil, natural gas and natural gas liquid reserves and changes in net proved oil, natural gas and natural gas liquid reserves attributable to the oil, natural gas and natural gas liquids properties, which are located in multiple states are summarized below:
|
|
Crude Oil,
Condensate and Natural Gas Liquids (MBbls) |
Natural Gas
(MMcf) |
Total
(MBoe) |
|||||||
|---|---|---|---|---|---|---|---|---|---|---|
|
Net proved reserves at January 1, 2014 |
486 | 3,096 | 1,001 | |||||||
|
Purchases of minerals in place |
834 | 5,083 | 1,681 | |||||||
|
Extensions and discoveries |
75 | 279 | 122 | |||||||
|
Production |
(67 | ) | (560 | ) | (160 | ) | ||||
| | | | | | | | | | | |
|
Net proved reserves at December 31, 2014 |
1,328 | 7,898 | 2,644 | |||||||
|
Revisions of previous estimates |
(81 | ) | (184 | ) | (111 | ) | ||||
|
Production |
(82 | ) | (548 | ) | (173 | ) | ||||
| | | | | | | | | | | |
|
Net proved reserves at December 31, 2015 |
1,165 | 7,166 | 2,360 | |||||||
| | | | | | | | | | | |
| | | | | | | | | | | |
| | | | | | | | | | | |
|
Net proved developed reserves |
||||||||||
|
December 31, 2014 |
703 | 5,225 | 1,574 | |||||||
|
December 31, 2015 |
681 | 4,720 | 1,468 | |||||||
|
Net proved undeveloped reserves |
|
|
|
|||||||
|
December 31, 2014 |
625 | 2,673 | 1,070 | |||||||
|
December 31, 2015 |
484 | 2,446 | 892 | |||||||
Revisions represent changes in previous reserves estimates, either upward or downward, resulting from new information normally obtained from development drilling and production history or resulting from a change in economic factors, such as commodity prices, operating costs or development costs.
Purchases of minerals in place during the year ended December 31, 2014 were attributable to six acquisitions made primarily in the Permian Basin, Bakken / Williston Basin in North Dakota, South and East Texas, and the Barnett Shale / Fort Worth basin, as well as other areas throughout the United States. Extensions were primarily the result of horizontal development in the Permian Basin. During the year ended December 31, 2015, revisions were primarily the result of the decrease in oil, natural gas and natural gas liquids prices.
F-66
RIVERCREST ROYALTIES, LLC
NOTES TO FINANCIAL STATEMENTS (Continued)
For the Years Ended December 31, 2015 and 2014
NOTE 13—SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION (UNAUDITED) (Continued)
Standardized Measure
The standardized measure of discounted future net cash flows before income taxes related to the proved oil, natural gas and natural gas liquids reserves of the properties is as follows:
|
|
For the Years Ended
December 31, |
||||||
|---|---|---|---|---|---|---|---|
|
|
2015 | 2014 | |||||
|
|
(in thousands)
|
||||||
|
Future cash inflows |
$ | 59,972 | $ | 133,281 | |||
|
Future production costs (a) |
(5,490 | ) | (12,352 | ) | |||
| | | | | | | | |
|
Future net cash flows |
54,482 | 120,929 | |||||
|
Less 10% annual discount to reflect timing of cash flows |
(31,112 | ) | (70,165 | ) | |||
| | | | | | | | |
|
Standard measure of discounted future net cash flows |
$ | 23,370 | $ | 50,764 | |||
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
- (a)
- Includes $40,352 and $39,532 of undiscounted future asset retirement expenditures estimated as of December 31, 2015 and 2014, respectively, using current estimates of future abandonment costs. See Note 11 for additional information regarding the Company's discounted asset retirement obligations.
Reserve estimates and future cash flows are based on the average market prices for sales of oil, natural gas and natural gas liquids adjusted for basis differentials, on the first calendar day of each month during the year. The average prices used for 2015 were $44.26 per barrel for crude oil and condensate, $2.02 per Mcf for natural gas, and $14.92 per barrel for natural gas liquids. The average prices used for 2014 were $86.12 per barrel for crude oil and condensate, $3.84 per Mcf for natural gas, and $32.64 per barrel for natural gas liquids.
Future production costs are computed primarily by the Company's petroleum engineers by estimating the expenditures to be incurred in developing and producing the proved oil and gas reserves at the end of the year, based on year-end costs and assuming continuation of existing economic conditions. As mentioned above, the standardized measure presented here does not include the effects of income taxes, as the tax basis for the properties is not applicable on a go-forward basis. A discount factor of 10% was used to reflect the timing of future net cash flows. The standardized measure of discounted future net cash flows is not intended to represent the replacement cost or fair value of the properties. An estimate of fair value would also take into account, among other things, the recovery of reserves not presently classified as proved, anticipated future changes in prices and costs, and a discount factor more representative of the time value of money and the risks inherent in oil, natural gas and natural gas liquids reserve estimates.
F-67
RIVERCREST ROYALTIES, LLC
NOTES TO FINANCIAL STATEMENTS (Continued)
For the Years Ended December 31, 2015 and 2014
NOTE 13—SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION (UNAUDITED) (Continued)
Changes in Standardized Measure
Changes in the standardized measure of discounted future net cash flows before income taxes related to the proved oil, natural gas and natural gas liquids reserves of the properties are as follows:
|
|
For the Years
Ended December 31, |
||||||
|---|---|---|---|---|---|---|---|
|
|
2015 | 2014 | |||||
|
|
(in thousands)
|
||||||
|
Standardized measure, beginning of year |
$ | 50,764 | $ | 19,355 | |||
|
Sales, net of production costs |
(4,258 | ) | (5,711 | ) | |||
|
Net changes of prices and production costs related to future production |
(25,570 | ) | 268 | ||||
|
Extensions, discoveries and improved recovery, net of future production and development costs |
— | 3,744 | |||||
|
Development costs incurred during the period |
— | 503 | |||||
|
Revisions of previous quantity estimates, net of related costs |
(1,100 | ) | — | ||||
|
Accretion of discount |
5,076 | 1,935 | |||||
|
Purchases of reserves in place, less related costs |
— | 30,670 | |||||
|
Timing differences and other |
(1,542 | ) | — | ||||
| | | | | | | | |
|
Standardized measure—end of year |
$ | 23,370 | $ | 50,764 | |||
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
F-68
REPORT OF INDEPENDENT CERTIFIED PUBLIC ACCOUNTANTS
Board
of Managers
Rivercrest Royalties, LLC
We have audited the accompanying Statements of Revenues and Direct Operating Expenses of certain oil and gas properties (the "Statements") owned by the Kimbell Art Foundation for the years ended December 31, 2015 and 2014 and the related notes to the Statements.
Management's responsibility for the financial statements
Management is responsible for the preparation and fair presentation of these Statements in accordance with accounting principles generally accepted in the United States of America; this includes the design, implementation, and maintenance of internal control relevant to the preparation and fair presentation of Statements that are free from material misstatement, whether due to fraud or error.
Our responsibility is to express an opinion on these Statements based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the Statements are free from material misstatement.
An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the Statements. The procedures selected depend on the auditor's judgment, including the assessment of the risks of material misstatement of the Statements, whether due to fraud or error. In making those risk assessments, the auditor considers internal control relevant to the entity's preparation and fair presentation of the Statements in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the entity's internal control. Accordingly, we express no such opinion. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of significant accounting estimates made by management, as well as evaluating the overall presentation of the Statements.
We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our audit opinion.
In our opinion, the Statements referred to above present fairly, in all material respects, the revenues and direct operating expenses of certain oil and gas properties owned by the Kimbell Art Foundation for the years ended December 31, 2015 and 2014, in accordance with accounting principles generally accepted in the United States of America.
As described in Note 1 to the Statements, the accompanying statements of revenues and direct operating expenses were prepared for the purpose of complying with the rules and regulations of the U.S. Securities and Exchange Commission (for inclusion in the registration statement on Form S-1 of Kimbell Royalty Partners, LP) and are not intended to be a complete presentation of the results of operations of the oil and gas properties owned by the Kimbell Art Foundation. Our opinion is not modified with respect to this matter.
/s/ GRANT THORNTON LLP
Dallas,
Texas
December 30, 2016
F-69
STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES
OF CERTAIN OIL AND GAS PROPERTIES OWNED BY THE KIMBELL ART FOUNDATION
|
|
For the Nine Months Ended
September 30, |
For the Years Ended
December 31, |
|||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
|
|
2016 | 2015 | 2015 | 2014 | |||||||||
|
|
(unaudited)
|
|
|
||||||||||
|
Oil, natural gas and NGL revenues |
$ | 5,624,706 | $ | 7,573,521 | $ | 9,584,930 | $ | 17,300,074 | |||||
|
Direct operating expenses |
802,543 | 821,353 | 1,087,632 | 1,538,323 | |||||||||
| | | | | | | | | | | | | | |
|
Revenues in excess of direct operating expenses |
$ | 4,822,163 | $ | 6,752,168 | $ | 8,497,298 | $ | 15,761,751 | |||||
| | | | | | | | | | | | | | |
| | | | | | | | | | | | | | |
| | | | | | | | | | | | | | |
The accompanying notes are an integral part of these statements.
F-70
NOTES TO STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES OF CERTAIN OIL AND GAS PROPERTIES OWNED BY THE KIMBELL ART FOUNDATION
1. BASIS OF PRESENTATION
The accompanying statements include revenues from the sale of crude oil, natural gas and natural gas liquids production and direct operating expenses associated with certain proved reserves and properties in the United States of America (collectively, the "Properties") owned by the Kimbell Art Foundation ("Kimbell") for the periods presented. Revenues and direct operating expenses are presented on the accrual basis of accounting and were derived from Kimbell's historical accounting records. During the periods presented, the Properties were not accounted for or operated as a separate division or entity of Kimbell; therefore, certain expenses such as depreciation, depletion and amortization expense, general and administrative expense, interest expense and income taxes were not allocated to the Properties. Accordingly, complete separate financial statements reflecting the financial position, results of operations and cash flows of the Properties prepared in accordance with accounting principles generally accepted in the United States of America ("U.S. GAAP") are not presented because the information necessary to prepare such statements is neither readily available on a combined or individual property basis, nor practicable to obtain in these circumstances. As such, the accompanying statements are not intended to be a complete presentation of the revenues and expenses of the Properties and are not indicative of the results of the operation of the Properties going forward due to the omission of various expenses including those described above.
Revenue Recognition
Kimbell recognizes revenue when it is realized or realizable and earned. Revenues are considered realized or realizable and earned when: (i) persuasive evidence of an arrangement exists, (ii) delivery has occurred or services have been rendered, (iii) the seller's price to the buyer is fixed or determinable, and (iv) collectability is reasonably assured.
As an owner of mineral and royalty interests, Kimbell is entitled to a portion of the revenues received from the production of oil, natural gas and associated natural gas liquids from the underlying acreage, net of post-production expenses and taxes. The pricing of oil, natural gas and natural gas liquids sales from the properties is primarily determined by supply and demand in the marketplace and can fluctuate considerably. Kimbell has no involvement or operational control over the volumes and method of sale of the oil, natural gas and natural gas liquids produced and sold from the properties.
To the extent actual volumes and prices of oil, natural gas and natural gas liquids are unavailable for a given reporting period because of timing or information not received from third parties, the expected sales volume and prices for these properties are estimated and accrued in oil, natural gas and natural gas liquids revenues in the statement of revenues and direct operating expenses. Differences between estimates of revenue and the actual amounts are adjusted and recorded in the period that the actual amounts are known.
Direct Operating Expenses
Direct operating expenses are recognized when incurred and include (a) gathering, transportation, and other direct operating expenses (b) production taxes and (c) ad valorem taxes.
F-71
NOTES TO STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES OF CERTAIN OIL AND GAS PROPERTIES OWNED BY THE KIMBELL ART FOUNDATION (Continued)
1. BASIS OF PRESENTATION (Continued)
Management Estimates
The preparation of financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of revenues and direct operating expenses during the reporting period. These estimates and assumptions are based on management's best estimates and judgment. Actual results may differ from the estimates and assumptions used in the preparation of the statements of revenues and direct operating expenses. Management evaluates its estimates and assumptions on an ongoing basis using historical experience and other factors, including the current economic environment, which management believes to be reasonable under the circumstances. Management evaluates subsequent events through the date the financial statements are issued.
2. COMMITMENTS AND CONTINGENCIES
Management is not aware of any legal, environmental or other commitments or contingencies that would have a material effect on Kimbell's financial condition, results of operations or liquidity.
3. SUBSEQUENT EVENTS
Management has evaluated subsequent events through December 30, 2016, the date the financial statements were issued.
4. SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION (UNAUDITED)
The following tables summarize the net ownership interest in the proved oil and gas reserves and the standardized measure of discounted future net cash flows related to the proved oil, natural gas and natural gas liquids reserves. The estimates were developed by Kimbell based on management's estimates for the years ended December 31, 2015 and 2014. The standardized measure presented here excludes income taxes, as the tax basis for the properties is not applicable on a go-forward basis. The proved oil, natural gas and natural gas liquids reserve estimates and other components of the standardized measure were determined in accordance with the guidelines of the Securities and Exchange Commission.
Proved Oil, Natural Gas and Natural Gas Liquids Reserve Quantities
Proved reserves are those quantities of oil, natural gas and natural gas liquids, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations. Proved developed reserves are proved reserves that can be expected to be recovered through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well. Proved undeveloped reserves are proved reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.
F-72
NOTES TO STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES OF CERTAIN OIL AND GAS PROPERTIES OWNED BY THE KIMBELL ART FOUNDATION (Continued)
4. SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION (UNAUDITED) (Continued)
A barrels of equivalent ("Boe") conversion ratio of six thousand cubic feet per barrel (6mcf/bbl) of natural gas to barrels of oil equivalence is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. All Boe conversions in the report are derived from converting gas to oil in the ratio mix of six thousand cubic feet of gas to one barrel of oil.
The net proved oil, natural gas and natural gas liquids reserves and changes in net proved oil, natural gas and natural gas liquids reserves attributable to the Properties, which are located in multiple states are summarized below:
|
|
Crude Oil,
Condensate and Natural Gas Liquids (MBbls) |
Natural Gas
(MMcf) |
Total
(MBoe) |
|||||||
|---|---|---|---|---|---|---|---|---|---|---|
|
Net proved reserves at January 1, 2014 |
2,447 | 17,000 | 5,280 | |||||||
|
Extensions and discoveries |
73 | 901 | 223 | |||||||
|
Production |
(146 | ) | (1,257 | ) | (355 | ) | ||||
| | | | | | | | | | | |
|
Net proved reserves at December 31, 2014 |
2,374 | 16,644 | 5,148 | |||||||
|
Revisions of previous estimates |
(118 | ) | (513 | ) | (204 | ) | ||||
|
Production |
(151 | ) | (1,052 | ) | (326 | ) | ||||
| | | | | | | | | | | |
|
Net proved reserves at December 31, 2015 |
2,105 | 15,079 | 4,618 | |||||||
| | | | | | | | | | | |
| | | | | | | | | | | |
| | | | | | | | | | | |
|
Net proved developed reserves |
||||||||||
|
December 31, 2014 |
1,674 | 12,568 | 3,768 | |||||||
|
December 31, 2015 |
1,536 | 11,709 | 3,488 | |||||||
|
Net proved undeveloped reserves |
||||||||||
|
December 31, 2014 |
700 | 4,076 | 1,380 | |||||||
|
December 31, 2015 |
569 | 3,370 | 1,130 | |||||||
F-73
NOTES TO STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES OF CERTAIN OIL AND GAS PROPERTIES OWNED BY THE KIMBELL ART FOUNDATION (Continued)
4. SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION (UNAUDITED) (Continued)
Standardized Measure
The standardized measure of discounted future net cash flows before income taxes related to the proved oil, natural gas and natural gas liquids reserves of the Properties is as follows:
|
|
For the Years Ended December 31, | ||||||
|---|---|---|---|---|---|---|---|
|
|
2015 | 2014 | |||||
|
|
(in thousands)
|
||||||
|
Future cash inflows |
$ | 121,009 | $ | 261,534 | |||
|
Future production costs |
(7,524 | ) | (16,030 | ) | |||
| | | | | | | | |
|
Future net cash flows |
113,485 | 245,504 | |||||
|
Less 10% annual discount to reflect timing of cash flows |
(63,993 | ) | (140,832 | ) | |||
| | | | | | | | |
|
Standard measure of discounted future net cash flows |
$ | 49,492 | $ | 104,672 | |||
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
Reserve estimates and future cash flows are based on the average market prices, adjusted for basis differentials, for sales of oil, natural gas and natural gas liquids on the first calendar day of each month during the year. The average prices used for 2015 were $47.37 per barrel for crude oil, $2.31 per Mcf for natural gas and $12.77 per barrel for natural gas liquids. The average prices used for 2014 were $91.78 per barrel for crude oil, $4.45 per Mcf for natural gas and $27.82 per barrel for natural gas liquids.
Future production costs are computed primarily by Kimbell's petroleum engineers by estimating the expenditures to be incurred in producing the proved oil, natural gas and natural gas liquids reserves at the end of the year, based on year-end costs and assuming continuation of existing economic conditions. As mentioned above, the standardized measure presented here does not include the effects of income taxes as the tax basis for the Properties is not applicable on a go-forward basis. A discount factor of 10% was used to reflect the timing of future net cash flows. The standardized measure of discounted future net cash flows is not intended to represent the replacement cost or fair value of the Properties. An estimate of fair value would also take into account, among other things, the recovery of reserves not presently classified as proved, anticipated future changes in prices and costs, and a discount factor more representative of the time value of money and the risks inherent in oil, natural gas and natural gas liquids reserve estimates.
F-74
NOTES TO STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES OF CERTAIN OIL AND GAS PROPERTIES OWNED BY THE KIMBELL ART FOUNDATION (Continued)
4. SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION (UNAUDITED) (Continued)
Changes in Standardized Measure
Changes in the standardized measure of discounted future net cash flows before income taxes related to the proved oil, natural gas and natural gas liquids reserves of the Properties are as follows:
|
|
For the Years Ended December 31, | ||||||
|---|---|---|---|---|---|---|---|
|
|
2015 | 2014 | |||||
|
|
(in thousands)
|
||||||
|
Standardized measure, beginning of year |
$ | 104,672 | $ | 103,657 | |||
|
Sales, net of production costs |
(8,497 | ) | (15,762 | ) | |||
|
Net changes of prices and production costs related to future production |
(51,297 | ) | — | ||||
|
Extensions, discoveries and improved recovery, net of future production and development costs |
— | 6,411 | |||||
|
Revisions of previous quantity estimates, net of related costs |
(2,186 | ) | — | ||||
|
Accretion of discount |
10,467 | 10,366 | |||||
|
Timing differences and other |
(3,667 | ) | — | ||||
| | | | | | | | |
|
Standardized measure—end of year |
$ | 49,492 | $ | 104,672 | |||
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
F-75
REPORT OF INDEPENDENT CERTIFIED PUBLIC ACCOUNTANTS
Board
of Managers
Rivercrest Royalties, LLC
We have audited the accompanying Combined Statements of Revenues and Direct Operating Expenses of certain oil and gas properties (the "Statements") owned by Trunk Bay Royalty Partners, Ltd., Oil Nut Bay Royalties, LP, Gorda Sound Royalties, LP and Bitter End Royalties, LP for the years ended December 31, 2015 and 2014 and the related notes to the Statements.
Management's responsibility for the financial statements
Management is responsible for the preparation and fair presentation of these Statements in accordance with accounting principles generally accepted in the United States of America; this includes the design, implementation, and maintenance of internal control relevant to the preparation and fair presentation of Statements that are free from material misstatement, whether due to fraud or error.
Our responsibility is to express an opinion on these Statements based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the Statements are free from material misstatement.
An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the Statements. The procedures selected depend on the auditor's judgment, including the assessment of the risks of material misstatement of the Statements, whether due to fraud or error. In making those risk assessments, the auditor considers internal control relevant to the entity's preparation and fair presentation of the Statements in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the entity's internal control. Accordingly, we express no such opinion. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of significant accounting estimates made by management, as well as evaluating the overall presentation of the Statements.
We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our audit opinion.
In our opinion, the Statements referred to above present fairly, in all material respects, the revenues and direct operating expenses of certain oil and gas properties owned by Trunk Bay Royalty Partners, Ltd., Oil Nut Bay Royalties, LP, Gorda Sound Royalties, LP and Bitter End Royalties, LP for the years ended December 31, 2015 and 2014, in accordance with accounting principles generally accepted in the United States of America.
As described in Note 1 to the Statements, the accompanying statements of revenues and direct operating expenses were prepared for the purpose of complying with the rules and regulations of the U.S. Securities and Exchange Commission (for inclusion in the registration statement on Form S-1 of Kimbell Royalty Partners, LP) and are not intended to be a complete presentation of the results of operations of the oil and gas properties owned by Trunk Bay Royalty Partners, Ltd., Oil Nut Bay Royalties, LP, Gorda Sound Royalties, LP and Bitter End Royalties, LP. Our opinion is not modified with respect to this matter.
/s/ GRANT THORNTON LLP
Dallas,
Texas
July 15, 2016
F-76
COMBINED STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES OF CERTAIN OIL AND GAS PROPERTIES OWNED BY TRUNK BAY ROYALTY PARTNERS, LTD., OIL NUT BAY ROYALTIES, LP, GORDA SOUND ROYALTIES, LP AND BITTER END ROYALTIES, LP
|
|
For the Nine Months
Ended September 30, |
For the Years Ended
December 31, |
|||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
|
|
2016 | 2015 | 2015 | 2014 | |||||||||
|
|
(unaudited)
|
|
|
||||||||||
|
Oil, natural gas and NGL revenues |
$ | 3,734,486 | $ | 5,060,067 | $ | 6,511,538 | $ | 13,172,562 | |||||
|
Direct operating expenses |
495,529 | 645,800 | 821,085 | 1,376,547 | |||||||||
| | | | | | | | | | | | | | |
|
Revenues in excess of direct operating expenses |
$ | 3,238,957 | $ | 4,414,267 | $ | 5,690,453 | $ | 11,796,015 | |||||
| | | | | | | | | | | | | | |
| | | | | | | | | | | | | | |
| | | | | | | | | | | | | | |
The accompanying notes are an integral part of these statements.
F-77
NOTES TO COMBINED STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES OF CERTAIN OIL AND GAS PROPERTIES OWNED BY TRUNK BAY ROYALTY PARTNERS, LTD., OIL NUT BAY ROYALTIES, LP, GORDA
SOUND ROYALTIES, LP AND BITTER END ROYALTIES, LP
1. BASIS OF PRESENTATION
The accompanying combined statements include revenues from the sale of crude oil, natural gas and natural gas liquids production and direct operating expenses associated with certain proved reserves and properties in the United States of America (collectively, the "Properties") owned by Trunk Bay Royalty Partners, Ltd., Oil Nut Bay Royalties, LP, Gorda Sound Royalties, LP and Bitter End Royalties, LP (collectively, "Trunk Bay") for the periods presented. One individual holds more than 50 percent of the voting interest of each of the aforementioned entities and has the ability to control the activities of the Properties. Therefore, the statements of revenues and direct operating expenses of certain oil and gas properties owned by Trunk Bay Royalty Partners, Ltd., Oil Nut Bay Royalties, LP, Gorda Sound Royalties, LP and Bitter End Royalties have been presented on a combined basis as entities under common control. Revenues and direct operating expenses are presented on the accrual basis of accounting and were derived from Trunk Bay's historical accounting records. During the periods presented, the Properties were not accounted for or operated as a separate division or entity of Trunk Bay; therefore, certain expenses such as depreciation, depletion and amortization expense, general and administrative expense, interest expense and income taxes were not allocated to the Properties. Accordingly, complete separate financial statements reflecting the financial position, results of operations and cash flows of the Properties prepared in accordance with accounting principles generally accepted in the United States of America ("U.S. GAAP") are not presented because the information necessary to prepare such statements is neither readily available on a combined or individual property basis, nor practicable to obtain in these circumstances. As such, the accompanying combined statements are not intended to be a complete presentation of the revenues and expenses of the Properties and are not indicative of the results of the operation of the Properties going forward due to the omission of various expenses including those described above.
Revenue Recognition
Trunk Bay recognizes revenue when it is realized or realizable and earned. Revenues are considered realized or realizable and earned when: (i) persuasive evidence of an arrangement exists, (ii) delivery has occurred or services have been rendered, (iii) the seller's price to the buyer is fixed or determinable, and (iv) collectability is reasonably assured.
As an owner of mineral and royalty interests, Trunk Bay is entitled to a portion of the revenues received from the production of oil, natural gas and associated natural gas liquids from the underlying acreage, net of post-production expenses and taxes. The pricing of oil, natural gas and natural gas liquids sales from the properties is primarily determined by supply and demand in the marketplace and can fluctuate considerably. Trunk Bay has no involvement or operational control over the volumes and method of sale of the oil, natural gas and natural gas liquids produced and sold from the properties.
To the extent actual volumes and prices of oil, natural gas and natural gas liquids are unavailable for a given reporting period because of timing or information not received from third parties, the expected sales volume and prices for these properties are estimated and accrued in
F-78
NOTES TO COMBINED STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES OF CERTAIN OIL AND GAS PROPERTIES OWNED BY TRUNK BAY ROYALTY PARTNERS, LTD., OIL NUT BAY
ROYALTIES, LP, GORDA SOUND ROYALTIES, LP AND BITTER END ROYALTIES, LP (Continued)
1. BASIS OF PRESENTATION (Continued)
oil, natural gas and natural gas liquids revenues in the statement of revenues and direct operating expenses. Differences between estimates of revenue and the actual amounts are adjusted and recorded in the period that the actual amounts are known.
Direct Operating Expenses
Direct operating expenses are recognized when incurred and include (a) gathering, transportation, and other direct operating expenses (b) production taxes and (c) ad valorem taxes.
Management Estimates
The preparation of financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of revenues and direct operating expenses during the reporting period. These estimates and assumptions are based on management's best estimates and judgment. Actual results may differ from the estimates and assumptions used in the preparation of the statements of revenues and direct operating expenses. Management evaluates its estimates and assumptions on an ongoing basis using historical experience and other factors, including the current economic environment, which management believes to be reasonable under the circumstances. Management evaluates subsequent events through the date the financial statements are issued.
2. COMMITMENTS AND CONTINGENCIES
Management is not aware of any legal, environmental or other commitments or contingencies that would have a material effect on Trunk Bay's financial condition, results of operations or liquidity.
3. SUBSEQUENT EVENTS—ANNUAL
For the purposes of annual financial statements, management has evaluated subsequent events through July 15, 2016, the date the financial statements were issued.
4. SUBSEQUENT EVENTS—INTERIM (UNAUDITED)
For the purposes of unaudited interim financial statements, management has evaluated subsequent events through November 22 2016, the date the financial statements were issued.
5. SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION (UNAUDITED)
The following tables summarize the net ownership interest in the proved oil and gas reserves and the standardized measure of discounted future net cash flows related to the proved oil, natural gas and natural gas liquids reserves. The estimates were developed by Trunk Bay
F-79
NOTES TO COMBINED STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES OF CERTAIN OIL AND GAS PROPERTIES OWNED BY TRUNK BAY ROYALTY PARTNERS, LTD., OIL NUT BAY
ROYALTIES, LP, GORDA SOUND ROYALTIES, LP AND BITTER END ROYALTIES, LP (Continued)
5. SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION (UNAUDITED) (Continued)
based on management's estimates for the years ended December 31, 2015 and 2014. The standardized measure presented here excludes income taxes, as the tax basis for the properties is not applicable on a go-forward basis. The proved oil, natural gas and natural gas liquids reserve estimates and other components of the standardized measure were determined in accordance with the guidelines of the Securities and Exchange Commission.
Proved Oil, Natural Gas and Natural Gas Liquids Reserve Quantities
Proved reserves are those quantities of oil, natural gas and natural gas liquids, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations. Proved developed reserves are proved reserves that can be expected to be recovered through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well. Proved undeveloped reserves are proved reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.
A barrels of equivalent ("Boe") conversion ratio of six thousand cubic feet per barrel (6mcf/bbl) of natural gas to barrels of oil equivalence is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. All Boe conversions in the report are derived from converting gas to oil in the ratio mix of six thousand cubic feet of gas to one barrel of oil.
F-80
NOTES TO COMBINED STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES OF CERTAIN OIL AND GAS PROPERTIES OWNED BY TRUNK BAY ROYALTY PARTNERS, LTD., OIL NUT BAY
ROYALTIES, LP, GORDA SOUND ROYALTIES, LP AND BITTER END ROYALTIES, LP (Continued)
5. SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION (UNAUDITED) (Continued)
The net proved oil, natural gas and natural gas liquids reserves and changes in net proved oil, natural gas and natural gas liquids reserves attributable to the Properties, which are located in multiple states are summarized below:
|
|
Crude Oil,
Condensate and Natural Gas Liquids (MBbls) |
Natural Gas
(MMcf) |
Total
(MBoe) |
|||||||
|---|---|---|---|---|---|---|---|---|---|---|
|
Net proved reserves at January 1, 2014 |
1,904 | 8,192 | 3,269 | |||||||
|
Extensions and discoveries |
30 | 275 | 76 | |||||||
|
Production |
(137 | ) | (582 | ) | (234 | ) | ||||
| | | | | | | | | | | |
|
Net proved reserves at December 31, 2014 |
1,797 | 7,885 | 3,111 | |||||||
|
Extensions and discoveries |
15 | 37 | 21 | |||||||
|
Revisions of previous estimates |
115 | 151 | 141 | |||||||
|
Production |
(188 | ) | (475 | ) | (267 | ) | ||||
| | | | | | | | | | | |
|
Net proved reserves at December 31, 2015 |
1,739 | 7,598 | 3,006 | |||||||
| | | | | | | | | | | |
| | | | | | | | | | | |
| | | | | | | | | | | |
|
Net proved developed reserves |
||||||||||
|
December 31, 2014 |
1,338 | 5,030 | 2,176 | |||||||
|
December 31, 2015 |
1,264 | 4,658 | 2,040 | |||||||
|
Net proved undeveloped reserves |
||||||||||
|
December 31, 2014 |
459 | 2,855 | 935 | |||||||
|
December 31, 2015 |
475 | 2,940 | 966 | |||||||
Standardized Measure
The standardized measure of discounted future net cash flows before income taxes related to the proved oil, natural gas and natural gas liquids reserves of the Properties is as follows:
|
|
For the Years Ended
December 31, |
||||||
|---|---|---|---|---|---|---|---|
|
|
2015 | 2014 | |||||
|
|
(in thousands)
|
||||||
|
Future cash inflows |
$ | 99,548 | $ | 189,303 | |||
|
Future production costs |
(8,000 | ) | (15,302 | ) | |||
| | | | | | | | |
|
Future net cash flows |
91,548 | 174,001 | |||||
|
Less 10% annual discount to reflect timing of cash flows |
(54,836 | ) | (104,947 | ) | |||
| | | | | | | | |
|
Standard measure of discounted future net cash flows |
$ | 36,712 | $ | 69,054 | |||
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
Reserve estimates and future cash flows are based on the average market prices, adjusted for basis differentials, for sales of oil, natural gas and natural gas liquids on the first calendar day of each month during the year. The average prices used for 2015 were $47.54 per barrel for crude
F-81
NOTES TO COMBINED STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES OF CERTAIN OIL AND GAS PROPERTIES OWNED BY TRUNK BAY ROYALTY PARTNERS, LTD., OIL NUT BAY
ROYALTIES, LP, GORDA SOUND ROYALTIES, LP AND BITTER END ROYALTIES, LP (Continued)
5. SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION (UNAUDITED) (Continued)
oil, $3.56 per Mcf for natural gas and $5.12 per barrel for natural gas liquids. The average prices used for 2014 were $89.75 per barrel for crude oil, $5.93 per Mcf for natural gas and $10.08 per barrel for natural gas liquids.
Future production costs are computed primarily by Trunk Bay's petroleum engineers by estimating the expenditures to be incurred in producing the proved oil, natural gas and natural gas liquids reserves at the end of the year, based on year-end costs and assuming continuation of existing economic conditions. As mentioned above, the standardized measure presented here does not include the effects of income taxes, as the tax basis for the Properties is not applicable on a go-forward basis. A discount factor of 10% was used to reflect the timing of future net cash flows. The standardized measure of discounted future net cash flows is not intended to represent the replacement cost or fair value of the Properties. An estimate of fair value would also take into account, among other things, the recovery of reserves not presently classified as proved, anticipated future changes in prices and costs, and a discount factor more representative of the time value of money and the risks inherent in oil, natural gas and natural gas liquids reserve estimates.
Changes in Standardized Measure
Changes in the standardized measure of discounted future net cash flows before income taxes related to the proved oil, natural gas and natural gas liquids reserves of the Properties are as follows:
|
|
For the Years Ended
December 31, |
||||||
|---|---|---|---|---|---|---|---|
|
|
2015 | 2014 | |||||
|
|
(in thousands)
|
||||||
|
Standardized measure, beginning of year |
$ | 69,054 | $ | 73,088 | |||
|
Sales, net of production costs |
(5,690 | ) | (11,796 | ) | |||
|
Net changes of prices and production costs related to future production |
(32,719 | ) | — | ||||
|
Extensions, discoveries and improved recovery, net of future production and development costs |
397 | 453 | |||||
|
Revisions of previous quantity estimates, net of related costs |
1,730 | — | |||||
|
Accretion of discount |
6,905 | 7,309 | |||||
|
Timing differences and other |
(2,965 | ) | — | ||||
| | | | | | | | |
|
Standardized measure—end of year |
$ | 36,712 | $ | 69,054 | |||
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
F-82
REPORT OF INDEPENDENT CERTIFIED PUBLIC ACCOUNTANTS
Board
of Managers
Rivercrest Royalties, LLC
We have audited the accompanying Statements of Revenues and Direct Operating Expenses of certain oil and gas properties (the "Statements") owned by RCPTX, Ltd. for the years ended December 31, 2015 and 2014 and the related notes to the Statements.
Management's responsibility for the financial statements
Management is responsible for the preparation and fair presentation of these Statements in accordance with accounting principles generally accepted in the United States of America; this includes the design, implementation, and maintenance of internal control relevant to the preparation and fair presentation of Statements that are free from material misstatement, whether due to fraud or error.
Our responsibility is to express an opinion on these Statements based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the Statements are free from material misstatement.
An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the Statements. The procedures selected depend on the auditor's judgment, including the assessment of the risks of material misstatement of the Statements, whether due to fraud or error. In making those risk assessments, the auditor considers internal control relevant to the entity's preparation and fair presentation of the Statements in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the entity's internal control. Accordingly, we express no such opinion. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of significant accounting estimates made by management, as well as evaluating the overall presentation of the Statements.
We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our audit opinion.
In our opinion, the Statements referred to above present fairly, in all material respects, the revenues and direct operating expenses of certain oil and gas properties owned by RCPTX, Ltd. for the years ended December 31, 2015 and 2014, in accordance with accounting principles generally accepted in the United States of America.
As described in Note 1 to the Statements, the accompanying statements of revenues and direct operating expenses were prepared for the purpose of complying with the rules and regulations of the U.S. Securities and Exchange Commission (for inclusion in the registration statement on Form S-1 of Kimbell Royalty Partners, LP) and are not intended to be a complete presentation of the results of operations of the oil and gas properties owned by RCPTX, Ltd. Our opinion is not modified with respect to this matter.
/s/ GRANT THORNTON LLP
Dallas,
Texas
July 15, 2016
F-83
STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES
OF CERTAIN OIL AND GAS PROPERTIES OWNED BY RCPTX, LTD.
|
|
For the Nine Months Ended
September 30, |
For the Years Ended
December 31, |
|||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
|
|
2016 | 2015 | 2015 | 2014 | |||||||||
|
|
(unaudited)
|
|
|
||||||||||
|
Oil, natural gas and NGL revenues |
$ | 1,877,122 | $ | 2,737,312 | $ | 3,465,958 | $ | 6,345,828 | |||||
|
Direct operating expenses |
317,177 | 308,677 | 414,400 | 773,961 | |||||||||
| | | | | | | | | | | | | | |
|
Revenues in excess of direct operating expenses |
$ |
1,559,945 |
$ |
2,428,635 |
$ |
3,051,558 |
$ |
5,571,867 |
|||||
| | | | | | | | | | | | | | |
| | | | | | | | | | | | | | |
| | | | | | | | | | | | | | |
The accompanying notes are an integral part of these statements.
F-84
NOTES TO STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES OF CERTAIN OIL AND GAS PROPERTIES OWNED BY RCPTX, LTD.
1. BASIS OF PRESENTATION
The accompanying statements include revenues from the sale of crude oil, natural gas and natural gas liquids production and direct operating expenses associated with certain proved reserves and properties in the United States of America (collectively, the "Properties") owned by RCPTX, Ltd. ("RCPTX") for the periods presented. Revenues and direct operating expenses are presented on the accrual basis of accounting and were derived from RCPTX's historical accounting records. During the periods presented, the Properties were not accounted for or operated as a separate division or entity of RCPTX; therefore, certain expenses such as depreciation, depletion and amortization expense, general and administrative expense, interest expense and income taxes were not allocated to the Properties. Accordingly, complete separate financial statements reflecting the financial position, results of operations and cash flows of the Properties prepared in accordance with accounting principles generally accepted in the United States of America ("U.S. GAAP") are not presented because the information necessary to prepare such statements is neither readily available on a combined or individual property basis, nor practicable to obtain in these circumstances. As such, the accompanying statements are not intended to be a complete presentation of the revenues and expenses of the Properties and are not indicative of the results of the operation of the Properties going forward due to the omission of various expenses including those described above.
Revenue Recognition
RCPTX recognizes revenue when it is realized or realizable and earned. Revenues are considered realized or realizable and earned when: (i) persuasive evidence of an arrangement exists, (ii) delivery has occurred or services have been rendered, (iii) the seller's price to the buyer is fixed or determinable, and (iv) collectability is reasonably assured.
As an owner of mineral and royalty interests, RCPTX is entitled to a portion of the revenues received from the production of oil, natural gas and associated natural gas liquids from the underlying acreage, net of post-production expenses and taxes. The pricing of oil, natural gas and natural gas liquids sales from the properties is primarily determined by supply and demand in the marketplace and can fluctuate considerably. RCPTX has no involvement or operational control over the volumes and method of sale of the oil, natural gas and natural gas liquids produced and sold from the properties.
To the extent actual volumes and prices of oil, natural gas and natural gas liquids are unavailable for a given reporting period because of timing or information not received from third parties, the expected sales volume and prices for these properties are estimated and accrued in oil, natural gas and natural gas liquids revenues in the statement of revenues and direct operating expenses. Differences between estimates of revenue and the actual amounts are adjusted and recorded in the period that the actual amounts are known.
F-85
NOTES TO STATEMENTS OF REVENUES AND DIRECT
OPERATING EXPENSES OF CERTAIN OIL AND GAS PROPERTIES OWNED BY RCPTX, LTD. (Continued)
1. BASIS OF PRESENTATION (Continued)
Direct Operating Expenses
Direct operating expenses are recognized when incurred and include (a) gathering, transportation, and other direct operating expenses (b) production taxes and (c) ad valorem taxes.
Management Estimates
The preparation of financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of revenues and direct operating expenses during the reporting period. These estimates and assumptions are based on management's best estimates and judgment. Actual results may differ from the estimates and assumptions used in the preparation of the statements of revenues and direct operating expenses. Management evaluates its estimates and assumptions on an ongoing basis using historical experience and other factors, including the current economic environment, which management believes to be reasonable under the circumstances. Management evaluates subsequent events through the date the financial statements are issued.
2. COMMITMENTS AND CONTINGENCIES
Management is not aware of any legal, environmental or other commitments or contingencies that would have a material effect on RCPTX's financial condition, results of operations or liquidity.
3. SUBSEQUENT EVENTS—ANNUAL
For the purposes of annual financial statements, management has evaluated subsequent events through July 15, 2016, the date the financial statements were issued.
4. SUBSEQUENT EVENTS—INTERIM (UNAUDITED)
For the purposes of unaudited interim financial statements, management has evaluated subsequent events through November 22, 2016, the date the financial statements were issued.
5. SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION (UNAUDITED)
The following tables summarize the net ownership interest in the proved oil and gas reserves and the standardized measure of discounted future net cash flows related to the proved oil, natural gas and natural gas liquids reserves. The estimates were developed by RCPTX based on management's estimates for the years ended December 31, 2015 and 2014. The standardized measure presented here excludes income taxes, as the tax basis for the properties is not applicable on a go-forward basis. The proved oil, natural gas and natural gas liquids reserve estimates and other components of the standardized measure were determined in accordance with the guidelines of the Securities and Exchange Commission.
F-86
NOTES TO STATEMENTS OF REVENUES AND DIRECT
OPERATING EXPENSES OF CERTAIN OIL AND GAS PROPERTIES OWNED BY RCPTX, LTD. (Continued)
5. SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION (UNAUDITED) (Continued)
Proved Oil, Natural Gas and Natural Gas Liquids Reserve Quantities
Proved reserves are those quantities of oil, natural gas and natural gas liquids, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations. Proved developed reserves are proved reserves that can be expected to be recovered through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well. Proved undeveloped reserves are proved reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.
A barrels of equivalent ("Boe") conversion ratio of six thousand cubic feet per barrel (6mcf/bbl) of natural gas to barrels of oil equivalence is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. All Boe conversions in the report are derived from converting gas to oil in the ratio mix of six thousand cubic feet of gas to one barrel of oil.
The net proved oil, natural gas and natural gas liquids reserves and changes in net proved oil, natural gas and natural gas liquids reserves attributable to the Properties, which are located in multiple states are summarized below:
|
|
Crude Oil,
Condensate and Natural Gas Liquids (MBbls) |
Natural Gas
(MMcf) |
Total
(MBoe) |
|||||||
|---|---|---|---|---|---|---|---|---|---|---|
|
Net proved reserves at January 1, 2014 |
906 | 7,852 | 2,215 | |||||||
|
Extensions and discoveries |
2 | 44 | 9 | |||||||
|
Production |
(67 | ) | (557 | ) | (160 | ) | ||||
| | | | | | | | | | | |
|
Net proved reserves at December 31, 2014 |
841 | 7,339 | 2,064 | |||||||
|
Revisions of previous estimates |
404 | 714 | 523 | |||||||
|
Production |
(82 | ) | (594 | ) | (181 | ) | ||||
| | | | | | | | | | | |
|
Net proved reserves at December 31, 2015 |
1,163 | 7,459 | 2,406 | |||||||
| | | | | | | | | | | |
| | | | | | | | | | | |
| | | | | | | | | | | |
|
Net proved developed reserves |
||||||||||
|
December 31, 2014 |
563 | 5,129 | 1,418 | |||||||
|
December 31, 2015 |
746 | 4,754 | 1,538 | |||||||
|
Net proved undeveloped reserves |
|
|
|
|||||||
|
December 31, 2014 |
278 | 2,210 | 646 | |||||||
|
December 31, 2015 |
417 | 2,705 | 868 | |||||||
F-87
NOTES TO STATEMENTS OF REVENUES AND DIRECT
OPERATING EXPENSES OF CERTAIN OIL AND GAS PROPERTIES OWNED BY RCPTX, LTD. (Continued)
5. SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION (UNAUDITED) (Continued)
Standardized Measure
The standardized measure of discounted future net cash flows before income taxes related to the proved oil, natural gas and natural gas liquids reserves of the Properties is as follows:
|
|
For the Years Ended
December 31, |
||||||
|---|---|---|---|---|---|---|---|
|
|
2015 | 2014 | |||||
|
|
(in thousands)
|
||||||
|
Future cash inflows |
$ | 56,957 | $ | 109,224 | |||
|
Future production costs |
(5,513 | ) | (10,418 | ) | |||
| | | | | | | | |
|
Future net cash flows |
51,444 | 98,806 | |||||
|
Less 10% annual discount to reflect timing of cash flows |
(28,735 | ) | (55,900 | ) | |||
| | | | | | | | |
|
Standard measure of discounted future net cash flows |
$ | 22,709 | $ | 42,906 | |||
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
Reserve estimates and future cash flows are based on the average market prices, adjusted for basis differentials, for sales of oil, natural gas and natural gas liquids on the first calendar day of each month during the year. The average prices used for 2015 were $41.73 per barrel for crude oil, $2.31 per Mcf for natural gas and $18.10 per barrel for natural gas liquids. The average prices used for 2014 were $93.30 per barrel for crude oil, $4.35 per Mcf for natural gas and $28.50 per barrel for natural gas liquids.
Future production costs are computed primarily by RCPTX's petroleum engineers by estimating the expenditures to be incurred in producing the proved oil, natural gas and natural gas liquids reserves at the end of the year, based on year-end costs and assuming continuation of existing economic conditions. As mentioned above, the standardized measure presented here does not include the effects of income taxes, as the tax basis for the Properties is not applicable on a go-forward basis. A discount factor of 10% was used to reflect the timing of future net cash flows. The standardized measure of discounted future net cash flows is not intended to represent the replacement cost or fair value of the Properties. An estimate of fair value would also take into account, among other things, the recovery of reserves not presently classified as proved, anticipated future changes in prices and costs, and a discount factor more representative of the time value of money and the risks inherent in oil, natural gas and natural gas liquids reserve estimates.
F-88
NOTES TO STATEMENTS OF REVENUES AND DIRECT
OPERATING EXPENSES OF CERTAIN OIL AND GAS PROPERTIES OWNED BY RCPTX, LTD. (Continued)
5. SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION (UNAUDITED) (Continued)
Changes in Standardized Measure
Changes in the standardized measure of discounted future net cash flows before income taxes related to the proved oil, natural gas and natural gas liquids reserves of the Properties are as follows:
|
|
For the Years Ended
December 31, |
||||||
|---|---|---|---|---|---|---|---|
|
|
2015 | 2014 | |||||
|
|
(in thousands)
|
||||||
|
Standardized measure, beginning of year |
$ | 42,906 | $ | 44,805 | |||
|
Sales, net of production costs |
(3,052 | ) | (5,572 | ) | |||
|
Net changes of prices and production costs related to future production |
(24,392 | ) | — | ||||
|
Extensions, discoveries and improved recovery, net of future production and development costs |
— | 733 | |||||
|
Revisions of previous quantity estimates, net of related costs |
4,937 | — | |||||
|
Accretion of discount |
4,291 | 4,480 | |||||
|
Timing differences and other |
(1,981 | ) | (1,540 | ) | |||
| | | | | | | | |
|
Standardized measure—end of year |
$ | 22,709 | $ | 42,906 | |||
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
F-89
REPORT OF INDEPENDENT CERTIFIED PUBLIC ACCOUNTANTS
Board
of Managers
Rivercrest Royalties, LLC
We have audited the accompanying Statements of Revenues and Direct Operating Expenses of certain oil and gas properties (the "Statements") owned by French Capital Partners, Ltd. for the years ended December 31, 2015 and 2014 and the related notes to the Statements.
Management's responsibility for the financial statements
Management is responsible for the preparation and fair presentation of these Statements in accordance with accounting principles generally accepted in the United States of America; this includes the design, implementation, and maintenance of internal control relevant to the preparation and fair presentation of Statements that are free from material misstatement, whether due to fraud or error.
Our responsibility is to express an opinion on these Statements based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the Statements are free from material misstatement.
An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the Statements. The procedures selected depend on the auditor's judgment, including the assessment of the risks of material misstatement of the Statements, whether due to fraud or error. In making those risk assessments, the auditor considers internal control relevant to the entity's preparation and fair presentation of the Statements in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the entity's internal control. Accordingly, we express no such opinion. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of significant accounting estimates made by management, as well as evaluating the overall presentation of the Statements.
We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our audit opinion.
In our opinion, the Statements referred to above present fairly, in all material respects, the revenues and direct operating expenses of certain oil and gas properties owned by French Capital Partners, Ltd. for the years ended December 31, 2015 and 2014, in accordance with accounting principles generally accepted in the United States of America.
As described in Note 1 to the Statements, the accompanying statements of revenues and direct operating expenses were prepared for the purpose of complying with the rules and regulations of the U.S. Securities and Exchange Commission (for inclusion in the registration statement on Form S-1 of Kimbell Royalty Partners, LP) and are not intended to be a complete presentation of the results of operations of the oil and gas properties owned by French Capital Partners, Ltd. Our opinion is not modified with respect to this matter.
/s/ GRANT THORNTON LLP
Dallas,
Texas
November 22, 2016
F-90
STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES OF CERTAIN OIL
AND GAS PROPERTIES OWNED BY FRENCH CAPITAL PARTNERS, LTD.
|
|
For the Nine Months Ended
September 30, |
For the Years Ended
December 31, |
|||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
|
|
2016 | 2015 | 2015 | 2014 | |||||||||
|
|
(unaudited)
|
|
|
||||||||||
|
Oil, natural gas and NGL revenues |
$ | 1,686,221 | $ | 2,292,499 | $ | 2,925,217 | $ | 5,415,532 | |||||
|
Direct operating expenses |
268,078 | 291,845 | 384,106 | 595,674 | |||||||||
| | | | | | | | | | | | | | |
|
Revenues in excess of direct operating expenses |
$ | 1,418,143 | $ | 2,000,654 | $ | 2,541,111 | $ | 4,819,858 | |||||
| | | | | | | | | | | | | | |
| | | | | | | | | | | | | | |
| | | | | | | | | | | | | | |
The accompanying notes are an integral part of these statements.
F-91
NOTES TO STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES OF CERTAIN OIL AND GAS PROPERTIES OWNED BY FRENCH CAPITAL PARTNERS, LTD.
1. BASIS OF PRESENTATION
The accompanying statements include revenues from the sale of crude oil, natural gas and natural gas liquids production and direct operating expenses associated with certain proved reserves and properties in the United States of America (collectively, the "Properties") owned by French Capital Partners, Ltd. ("French") for the periods presented. Revenues and direct operating expenses are presented on the accrual basis of accounting and were derived from French's historical accounting records. During the periods presented, the Properties were not accounted for or operated as a separate division or entity of French; therefore, certain expenses such as depreciation, depletion and amortization expense, general and administrative expense, interest expense and income taxes were not allocated to the Properties. Accordingly, complete separate financial statements reflecting the financial position, results of operations and cash flows of the Properties prepared in accordance with accounting principles generally accepted in the United States of America ("U.S. GAAP") are not presented because the information necessary to prepare such statements is neither readily available on a combined or individual property basis, nor practicable to obtain in these circumstances. As such, the accompanying statements are not intended to be a complete presentation of the revenues and expenses of the Properties and are not indicative of the results of the operation of the Properties going forward due to the omission of various expenses including those described above.
Revenue Recognition
French recognizes revenue when it is realized or realizable and earned. Revenues are considered realized or realizable and earned when: (i) persuasive evidence of an arrangement exists, (ii) delivery has occurred or services have been rendered, (iii) the seller's price to the buyer is fixed or determinable, and (iv) collectability is reasonably assured.
As an owner of mineral and royalty interests, French is entitled to a portion of the revenues received from the production of oil, natural gas and associated natural gas liquids from the underlying acreage, net of post-production expenses and taxes. The pricing of oil, natural gas and natural gas liquids sales from the properties is primarily determined by supply and demand in the marketplace and can fluctuate considerably. French has no involvement or operational control over the volumes and method of sale of the oil, natural gas and natural gas liquids produced and sold from the properties.
To the extent actual volumes and prices of oil, natural gas and natural gas liquids are unavailable for a given reporting period because of timing or information not received from third parties, the expected sales volume and prices for these properties are estimated and accrued in oil, natural gas and natural gas liquids revenues in the statement of revenues and direct operating expenses. Differences between estimates of revenue and the actual amounts are adjusted and recorded in the period that the actual amounts are known.
Direct Operating Expenses
Direct operating expenses are recognized when incurred and include (a) gathering, transportation, and other direct operating expenses (b) production taxes and (c) ad valorem taxes.
F-92
NOTES TO STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES OF CERTAIN OIL AND GAS PROPERTIES OWNED BY FRENCH CAPITAL PARTNERS, LTD.
(Continued)
1. BASIS OF PRESENTATION (Continued)
Management Estimates
The preparation of financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of revenues and direct operating expenses during the reporting period. These estimates and assumptions are based on management's best estimates and judgment. Actual results may differ from the estimates and assumptions used in the preparation of the statements of revenues and direct operating expenses. Management evaluates its estimates and assumptions on an ongoing basis using historical experience and other factors, including the current economic environment, which management believes to be reasonable under the circumstances. Management evaluates subsequent events through the date the financial statements are issued.
2. COMMITMENTS AND CONTINGENCIES
Management is not aware of any legal, environmental or other commitments or contingencies that would have a material effect on French's financial condition, results of operations or liquidity.
3. SUBSEQUENT EVENTS
Management has evaluated subsequent events through November 22, 2016, the date the financial statements were issued.
4. SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION (UNAUDITED)
The following tables summarize the net ownership interest in the proved oil and gas reserves and the standardized measure of discounted future net cash flows related to the proved oil, natural gas and natural gas liquids reserves. The estimates were developed by French based on management's estimates for the years ended December 31, 2015 and 2014. The standardized measure presented here excludes income taxes, as the tax basis for the properties is not applicable on a go-forward basis. The proved oil, natural gas and natural gas liquids reserve estimates and other components of the standardized measure were determined in accordance with the guidelines of the Securities and Exchange Commission.
Proved Oil, Natural Gas and Natural Gas Liquids Reserve Quantities
Proved reserves are those quantities of oil, natural gas and natural gas liquids, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations. Proved developed reserves are proved reserves that can be expected to be recovered through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well. Proved undeveloped reserves are proved reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.
F-93
NOTES TO STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES OF CERTAIN OIL AND GAS PROPERTIES OWNED BY FRENCH CAPITAL PARTNERS, LTD.
(Continued)
4. SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION (UNAUDITED) (Continued)
A barrels of equivalent ("Boe") conversion ratio of six thousand cubic feet per barrel (6mcf/bbl) of natural gas to barrels of oil equivalence is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. All Boe conversions in the report are derived from converting gas to oil in the ratio mix of six thousand cubic feet of gas to one barrel of oil.
The net proved oil, natural gas and natural gas liquids reserves and changes in net proved oil, natural gas and natural gas liquids reserves attributable to the Properties, which are located in multiple states are summarized below:
|
|
Crude Oil,
Condensate and Natural Gas Liquids (MBbls) |
Natural Gas
(MMcf) |
Total
(MBoe) |
|||||||
|---|---|---|---|---|---|---|---|---|---|---|
|
Net proved reserves at January 1, 2014 |
1,261 | — | 1,261 | |||||||
|
Revisions of previous estimates |
27 | — | 27 | |||||||
|
Production |
(96 | ) | — | (96 | ) | |||||
| | | | | | | | | | | |
|
Net proved reserves at December 31, 2014 |
1,192 | — | 1,192 | |||||||
|
Revisions of previous estimates |
13 | — | 13 | |||||||
|
Production |
(97 | ) | — | (97 | ) | |||||
| | | | | | | | | | | |
|
Net proved reserves at December 31, 2015 |
1,108 | — | 1,108 | |||||||
| | | | | | | | | | | |
| | | | | | | | | | | |
| | | | | | | | | | | |
|
Net proved developed reserves |
— | |||||||||
|
December 31, 2014 |
1,192 | — | 1,192 | |||||||
|
December 31, 2015 |
1,108 | — | 1,108 | |||||||
|
Net proved undeveloped reserves |
||||||||||
|
December 31, 2014 |
— | — | — | |||||||
|
December 31, 2015 |
— | — | — | |||||||
Standardized Measure
The standardized measure of discounted future net cash flows before income taxes related to the proved oil, natural gas and natural gas liquids reserves of the Properties is as follows:
|
|
For the Years Ended
December 31, |
||||||
|---|---|---|---|---|---|---|---|
|
|
2015 | 2014 | |||||
|
|
(in thousands)
|
||||||
|
Future cash inflows |
$ | 45,132 | $ | 94,095 | |||
|
Future production costs |
(3,279 | ) | (6,825 | ) | |||
| | | | | | | | |
|
Future net cash flows |
41,853 | 87,270 | |||||
|
Less 10% annual discount to reflect timing of cash flows |
(23,759 | ) | (50,262 | ) | |||
| | | | | | | | |
|
Standard measure of discounted future net cash flows |
18,094 | 37,008 | |||||
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
F-94
NOTES TO STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES OF CERTAIN OIL AND GAS PROPERTIES OWNED BY FRENCH CAPITAL PARTNERS, LTD.
(Continued)
4. SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION (UNAUDITED) (Continued)
Reserve estimates and future cash flows are based on the average market prices, adjusted for basis differentials, for sales of oil, natural gas and natural gas liquids on the first calendar day of each month during the year. The average prices used for 2015 were $50.28 per barrel for crude oil, $2.59 per Mcf for natural gas and $21.12 per barrel for natural gas liquids. The average prices used for 2014 were $94.99 per barrel for crude oil, $4.35 per Mcf for natural gas and $39.90 per barrel for natural gas liquids.
Future production costs are computed primarily by French's petroleum engineers by estimating the expenditures to be incurred in producing the proved oil, natural gas and natural gas liquids reserves at the end of the year, based on year-end costs and assuming continuation of existing economic conditions. As mentioned above, the standardized measure presented here does not include the effects of income taxes, as the tax basis for the Properties is not applicable on a go-forward basis. A discount factor of 10% was used to reflect the timing of future net cash flows. The standardized measure of discounted future net cash flows is not intended to represent the replacement cost or fair value of the Properties. An estimate of fair value would also take into account, among other things, the recovery of reserves not presently classified as proved, anticipated future changes in prices and costs, and a discount factor more representative of the time value of money and the risks inherent in oil, natural gas and natural gas liquids reserve estimates.
Changes in Standardized Measure
Changes in the standardized measure of discounted future net cash flows before income taxes related to the proved oil, natural gas and natural gas liquids reserves of the Properties are as follows:
|
|
For the Years Ended
December 31, |
||||||
|---|---|---|---|---|---|---|---|
|
|
2015 | 2014 | |||||
|
|
(in thousands)
|
||||||
|
Standardized measure, beginning of year |
$ | 37,008 | $ | 39,457 | |||
|
Sales, net of production costs |
(2,541 | ) | (4,820 | ) | |||
|
Net changes of prices and production costs related to future production |
(18,373 | ) | (988 | ) | |||
|
Extensions, discoveries and improved recovery, net of future production and development costs |
— | — | |||||
|
Revisions of previous quantity estimates, net of related costs |
205 | 844 | |||||
|
Accretion of discount |
3,701 | 3,946 | |||||
|
Timing differences and other |
(1,906 | ) | (1,431 | ) | |||
| | | | | | | | |
|
Standardized measure—end of year |
$ | 18,094 | $ | 37,008 | |||
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
F-95
APPENDIX A—FORM OF AMENDED AND RESTATED AGREEMENT OF LIMITED
PARTNERSHIP OF KIMBELL ROYALTY PARTNERS, LP
To be provided by amendment.
A-1
The following are definitions of certain terms used in this prospectus.
Available cash. For any quarter ending prior to liquidation:
(a) the sum of:
(1) all cash and cash equivalents of Kimbell Royalty Partners, LP and its subsidiaries on hand at the end of that quarter; and
(2) as determined by the general partner of Kimbell Royalty Partners, LP, all cash or cash equivalents of Kimbell Royalty Partners, LP and its subsidiaries on hand on the date of determination of available cash for that quarter resulting from working capital borrowings made after the end of that quarter;
(b) less the amount of cash reserves established by the general partner of Kimbell Royalty Partners, LP to:
(1) provide for the proper conduct of the business of Kimbell Royalty Partners, LP and its subsidiaries (including reserves for future capital expenditures and for future credit needs of Kimbell Royalty Partners, LP and its subsidiaries) after that quarter;
(2) comply with applicable law or any debt instrument or other agreement or obligation to which Kimbell Royalty Partners, LP or any of its subsidiaries is a party or its assets are subject; and
(3) provide funds for distributions for any one or more of the next four quarters; provided, however, that disbursements made by Kimbell Royalty Partners, LP or any of its subsidiaries or cash reserves established, increased or reduced after the end of that quarter but on or before the date of determination of available cash for that quarter shall be deemed to have been made, established, increased or reduced, for purposes of determining available cash, within that quarter if the general partner of Kimbell Royalty Partners, LP so determines.
Basin. A large depression on the earth's surface in which sediments accumulate.
Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume.
Boe. Barrels of oil equivalent, with six thousand cubic feet of natural gas being equivalent to one barrel of oil.
Boe/d. Boe per day.
British Thermal Unit (Btu). The quantity of heat required to raise the temperature of one pound of water by one degree Fahrenheit.
Completion. The process of treating a drilling well followed by the installation of permanent equipment for the production of natural gas or oil, or in the case of a dry hole, the reporting of abandonment to the appropriate agency.
B-1
Condensate. Liquid hydrocarbons associated with the production of a primarily natural gas reserve.
Crude oil. Liquid hydrocarbons retrieved from geological structures underground to be refined into fuel sources.
Deterministic method. The method of estimating reserves or resources under which a single value for each parameter (from the geoscience, engineering, or economic data) in the reserves calculation is used in the reserves estimation procedure.
Developed acreage. The number of acres that are allocated or assignable to productive wells or wells capable of production.
Development costs. Capital costs incurred in the acquisition, exploitation and exploration of proved oil and natural gas reserves divided by proved reserve additions and revisions to proved reserves.
Development well. A well drilled within the proved area of an oil and natural gas reservoir to the depth of a stratigraphic horizon known to be productive.
Differential. An adjustment to the price of oil or natural gas from an established spot market price to reflect differences in the quality and/or location of oil or natural gas.
Dry hole or dry well. A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes.
Economically producible. A resource that generates revenue that exceeds, or is reasonably expected to exceed, the costs of the operation.
Electrical log. Provide information on porosity, hydraulic conductivity, and fluid content of formations drilled in fluid-filled boreholes.
Exploration. A drilling or other project which may target proven or unproven reserves (such as probable or possible reserves).
Extension well. A well drilled to extend the limits of a known reservoir.
Field. An area consisting of either a single reservoir or multiple reservoirs, all grouped on or related to the same individual geological structural feature and/or stratigraphic condition.
Formation. A layer of rock which has distinct characteristics that differs from nearby rock.
Fracturing. The process of creating and preserving a fracture or system of fractures in a reservoir rock typically by injecting a fluid under pressure through a wellbore and into the targeted formation.
Gross acres or gross wells. The total acres or wells, as the case may be, in which a working interest is owned.
B-2
Horizontal drilling. A drilling technique used in certain formations where a well is drilled vertically to a certain depth and then drilled at a right angle within a specified interval.
Hydraulic fracturing. A process used to stimulate production of hydrocarbons. The process involves the injection of water, sand, and chemicals under pressure into the formation to fracture the surrounding rock and stimulate production.
Lease bonus. Usually a one-time payment made to a mineral owner as consideration for the execution of an oil and natural gas lease.
Lease operating expense. All direct and allocated indirect costs of lifting hydrocarbons from a producing formation to the surface constituting part of the current operating expenses of a working interest. Such costs include labor, superintendence, supplies, repairs, maintenance, allocated overhead charges, workover, insurance, and other expenses incidental to production, but exclude lease acquisition or drilling or completion expenses.
MBbl/d. MBbl per day.
MBbls. One thousand barrels of oil or other liquid hydrocarbons.
MBoe. One thousand barrels of oil equivalent, determined using a ratio of six Mcf of natural gas to one Bbl of oil.
Mcf. One thousand cubic feet of natural gas.
Mineral interests. Real-property interests that grant ownership of the oil and natural gas under a tract of land and the rights to explore for, drill for, and produce oil and natural gas on that land or to lease those exploration and development rights to a third party.
MMBtu. One million British Thermal Units.
MMcf. One million cubic feet of natural gas.
Net acres. The sum of the fractional working interest owned in gross acres.
Net revenue interest. An owner's interest in the revenues of a well after deducting proceeds allocated to royalty, overriding royalty and other non-cost-bearing interests.
Natural gas. A combination of light hydrocarbons that, in average pressure and temperature conditions, is found in a gaseous state. In nature, it is found in underground accumulations, and may potentially be dissolved in oil or may also be found in its gaseous state.
Natural gas liquids or NGLs. Hydrocarbons found in natural gas which may be extracted as liquefied petroleum gas and natural gasoline.
Nonparticipating royalty interest. A type of non-cost-bearing royalty interest, which is carved out of the mineral interest and represents the right, which is typically perpetual, to receive a fixed cost-free percentage of production or revenue from production, without an associated right to lease.
Oil. Crude oil and condensate.
B-3
Oil and natural gas properties. Tracts of land consisting of properties to be developed for oil and natural gas resource extraction.
Operator. The individual or company responsible for the exploration and/or production of an oil or natural gas well or lease. Refers to the operator of record and any lessor or working interest holder for which the operator is acting.
Overriding royalty interest or ORRI. A fractional, undivided interest or right of participation in the oil or natural gas, or in the proceeds from the sale of the oil or gas, produced from a specified tract or tracts, which are limited in duration to the terms of an existing lease and which are not subject to any portion of the expense of development, operation or maintenance.
Pad drilling. The practice of drilling multiple wellbores from a single surface location.
PDP. Proved developed producing.
Play. A set of discovered or prospective oil and/or natural gas accumulations sharing similar geologic, geographic and temporal properties, such as source rock, reservoir structure, timing, trapping mechanism and hydrocarbon type.
Plugging and abandonment. Refers to the sealing off of fluids in the strata penetrated by a well so that the fluids from one stratum will not escape into another or to the surface. Regulations of all states require plugging of abandoned wells.
Pooling. The majority of our producing acreage is pooled with third-party acreage. Pooling refers to an operator's consolidation of multiple adjacent leased tracts, which may be covered by multiple leases with multiple lessors, in order to maximize drilling efficiency or to comply with state mandated well spacing requirements. Pooling dilutes our royalty in a given well or unit, but it also increases both the acreage footprint and the number of wells in which we have an economic interest. To estimate our total potential drilling locations in a given play, we include third-party acreage that is pooled with our acreage.
Production costs. The production or operational costs incurred while extracting and producing, storing, and transporting oil and/or natural gas. Typical of these costs are wages for workers, facilities lease costs, equipment maintenance, logistical support, applicable taxes and insurance.
PUD. Proved undeveloped.
Productive well. A well that is found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of the production exceed production expenses and taxes.
Prospect. A specific geographic area which, based on supporting geological, geophysical or other data and also preliminary economic analysis using reasonably anticipated prices and costs, is deemed to have potential for the discovery of commercial hydrocarbons.
Proved developed reserves. Reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.
B-4
Proved developed producing reserves. Reserves expected to be recovered from existing completion intervals in existing wells.
Proved reserves. The estimated quantities of oil, natural gas and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be commercially recoverable in future years from known reservoirs under existing economic and operating conditions.
Proved undeveloped reserves. Proved reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion.
Recompletion. The process of re-entering an existing wellbore that is either producing or not producing and completing new reservoirs in an attempt to establish or increase existing production.
Reserves. Reserves are estimated remaining quantities of oil and natural gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and natural gas or related substances to the market and all permits and financing required to implement the project. Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).
Reservoir. A porous and permeable underground formation containing a natural accumulation of producible natural gas and/or oil that is confined by impermeable rock or water barriers and is separate from other reservoirs.
Resource play. A set of discovered or prospective oil and/or natural gas accumulations sharing similar geologic, geographic and temporal properties, such as source rock, reservoir structure, timing, trapping mechanism and hydrocarbon type.
Royalty interest. An interest that gives an owner the right to receive a portion of the resources or revenues without having to carry any costs of development.
SCOOP. South Central Oklahoma Oil Province.
Seismic data. Seismic data is used by scientists to interpret the composition, fluid content, extent, and geometry of rocks in the subsurface. Seismic data is acquired by transmitting a signal from an energy source, such as dynamite or water, into the earth. The energy so transmitted is subsequently reflected beneath the earth's surface and a receiver is used to collect and record these reflections.
Shale. A fine grained sedimentary rock formed by consolidation of clay- and silt-sized particles into thin, relatively impermeable layers. Shale can include relatively large amounts of organic material compared with other rock types and thus has the potential to become rich
B-5
hydrocarbon source rock. Its fine grain size and lack of permeability can allow shale to form a good cap rock for hydrocarbon traps.
Spacing. The distance between wells producing from the same reservoir. Spacing is often expressed in terms of acres, e.g., 40-acre spacing, and is often established by regulatory agencies.
STACK. Sooner Trend, Anadarko Basin, Canadian and Kingfisher counties.
Standardized measure. The present value of estimated future net revenue to be generated from the production of proved reserves, determined in accordance with the rules and regulations of the SEC (using prices and costs in effect as of the date of estimation), less future development, production and income tax expenses, and discounted at 10% per annum to reflect the timing of future net revenue. Because we are a limited partnership, we are generally not subject to federal or state income taxes and thus make no provision for federal or state income taxes in the calculation of our standardized measure. Standardized measure does not give effect to derivative transactions.
Tight formation. A formation with low permeability that produces natural gas with low flow rates for long periods of time.
Undeveloped acreage. Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas regardless of whether such acreage contains proved reserves.
Wellbore. The hole drilled by the bit that is equipped for oil or natural gas production on a completed well.
Working interest. An operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and receive a share of production and requires the owner to pay a share of the costs of drilling and production operations.
WTI. West Texas Intermediate oil, which is a light, sweet crude oil, characterized by an American Petroleum Institute gravity, of API gravity, between 39 and 41 and a sulfur content of approximately 0.4 weight percent that is used as a benchmark for the other crude oils.
B-6
Kimbell Royalty Partners, LP
Common Units
Representing Limited Partner Interests
Prospectus
, 2017
Joint Book-Running Managers
RAYMOND JAMES
RBC CAPITAL MARKETS
STIFEL
Co-Managers
STEPHENS INC.
WUNDERLICH
Through and including , 2017 (25 days after the date of this prospectus), all dealers that buy, sell or trade our common units, whether or not participating in this offering, may be required to deliver a prospectus. This is in addition to the dealers' obligation to deliver a prospectus when acting as underwriters and with respect to their unsold allotments or subscriptions.
PART II
INFORMATION NOT REQUIRED IN PROSPECTUS
ITEM 13. OTHER EXPENSES OF ISSUANCE AND DISTRIBUTION.
Set forth below are the expenses (other than the underwriting discount and structuring fee) expected to be incurred in connection with the issuance and distribution of the securities registered hereby. With the exception of the SEC registration fee, the FINRA filing fee and the NYSE listing fee, the amounts set forth below are estimates.
|
SEC registration fee |
$ | 11,590 | ||
|
FINRA filing fee |
15,500 | |||
|
Printing and engraving expenses |
350,000 | |||
|
Fees and expenses of legal counsel |
2,500,000 | |||
|
Accounting fees and expenses |
1,410,000 | |||
|
Transfer agent and registrar fees |
17,750 | |||
|
NYSE listing fee |
150,000 | |||
|
Miscellaneous |
415,160 | |||
| | | | | |
|
Total |
$ | 4,870,000 |
ITEM 14. INDEMNIFICATION OF OFFICERS AND MEMBERS OF THE BOARD OF DIRECTORS OF OUR GENERAL PARTNER.
The section of the prospectus entitled "The Partnership Agreement—Indemnification" is incorporated herein by reference and discloses that we will generally indemnify the directors, officers and affiliates of the general partner to the fullest extent permitted by law against all losses, claims, damages or similar events. Subject to any terms, conditions or restrictions set forth in the partnership agreement, Section 17-108 of the Delaware Revised Uniform Limited Partnership Act empowers a Delaware limited partnership to indemnify and hold harmless any partner or other person from and against all claims and demands whatsoever.
Section 18-108 of the Delaware Limited Liability Company Act provides that a Delaware limited liability company may indemnify and hold harmless any member or manager or other person from and against any and all claims and demands whatsoever. The limited liability company agreement of Kimbell Royalty GP, LLC, our general partner, provides for the indemnification of its directors and officers against liabilities they incur in their capacities as such. We may enter into indemnity agreements with each of the current directors and officers of our general partner to give these directors and officers additional contractual assurances regarding the scope of the indemnification set forth in our general partner's limited liability company agreement and to provide additional procedural protections.
The underwriting agreement that we expect to enter into with the underwriters, the form of which will be filed as Exhibit 1.1 to this registration statement, will contain indemnification and contribution provisions that will indemnify and hold harmless the directors and officers of our general partner.
Our general partner maintains insurance covering its officers and directors against liabilities asserted and expenses incurred in connection with their activities as officers and directors of our general partner or any of its direct or indirect subsidiaries.
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ITEM 15. RECENT SALES OF UNREGISTERED SECURITIES.
In connection with our formation in October 2015, we issued (i) the non-economic general partner interest in us to Kimbell Royalty GP, LLC and (ii) a 100% limited partner interest in us to Rivercrest Royalties, LLC for an aggregate of $1,000. These issuances were exempt from registration under Section 4(a)(2) of the Securities Act.
On December 20, 2016, we entered into a Contribution, Conveyance, Assignment and Assumption Agreement with Kimbell Royalty GP, LLC, Kimbell Intermediate GP, LLC, Kimbell Intermediate Holdings, LLC, Kimbell Royalty Holdings, LLC and the other parties named therein, pursuant to which we agreed to issue the number of common units to be set forth in the prospectus and distribute the net proceeds of the offering to the Contributing Parties in connection with such Contributing Parties' contribution of certain assets to us at or prior to the closing of this offering. The common units will be issued in reliance on the exemptions for sales of securities not involving a public offering, as set forth in Rule 506(b) promulgated under the Securities Act and in Section 4(a)(2) of the Securities Act.
See the Exhibit Index on the page immediately preceding the exhibits for a list of exhibits filed as part of this Registration Statement on Form S-1, which Exhibit Index is incorporated herein by reference.
The undersigned registrant hereby undertakes to provide to the underwriters at the closing specified in the underwriting agreement certificates in such denominations and registered in such names as required by the underwriters to permit prompt delivery to each purchaser.
Insofar as indemnification for liabilities arising under the Securities Act may be permitted to directors, officers and controlling persons of the registrant pursuant to the foregoing provisions, or otherwise, the registrant has been advised that in the opinion of the Securities and Exchange Commission such indemnification is against public policy as expressed in the Securities Act and is, therefore, unenforceable. In the event that a claim for indemnification against such liabilities (other than the payment by the registrant of expenses incurred or paid by a director, officer or controlling person of the registrant in the successful defense of any action, suit or proceeding) is asserted by such director, officer or controlling person in connection with the securities being registered, the registrant will, unless in the opinion of its counsel the matter has been settled by controlling precedent, submit to a court of appropriate jurisdiction the question whether such indemnification by it is against public policy as expressed in the Securities Act and will be governed by the final adjudication of such issue.
The undersigned registrant hereby undertakes that, for the purpose of determining liability of the registrant under the Securities Act to any purchaser in the initial distribution of the securities, in a primary offering of securities of the undersigned registrant pursuant to this registration statement, regardless of the underwriting method used to sell the securities to the purchaser, if the securities are offered or sold to such purchaser by means of any of the
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following communications, the undersigned registrant will be a seller to the purchaser and will be considered to offer or sell such securities to such purchaser:
(i) Any preliminary prospectus or prospectus of the undersigned registrant relating to this offering required to be filed pursuant to Rule 424;
(ii) Any free writing prospectus relating to this offering prepared by or on behalf of the undersigned registrant or used or referred to by the undersigned registrant;
(iii) The portion of any other free writing prospectus relating to this offering containing material information about the undersigned registrant or its securities provided by or on behalf of the undersigned registrant; and
(iv) Any other communication that is an offer in this offering made by the undersigned registrant to the purchaser.
The undersigned registrant hereby undertakes that:
(i) For the purpose of determining liability under the Securities Act to any purchaser, each prospectus filed pursuant to Rule 424(b) as part of a registration statement relating to an offering, other than registration statements relying on Rule 430B or other than prospectuses filed in reliance on Rule 430A, shall be deemed to be part of and included in the registration statement as of the date it is first used after effectiveness. Provided, however, that no statement made in a registration statement or prospectus that is part of the registration statement or made in a document incorporated or deemed incorporated by reference into the registration statement or prospectus that is part of the registration statement will, as to a purchaser with a time of contract of sale prior to such first use, supersede or modify any statement that was made in the registration statement or prospectus that was part of the registration statement or made in any such document immediately prior to such date of first use.
(ii) For purposes of determining any liability under the Securities Act, the information omitted from the form of prospectus filed as part of this registration statement in reliance upon Rule 430A and contained in a form of prospectus filed by the registrant pursuant to Rule 424(b)(1) or (4) or 497(h) under the Securities Act shall be deemed to be part of this registration statement as of the time it was declared effective.
(iii) For the purpose of determining any liability under the Securities Act, each post-effective amendment that contains a form of prospectus shall be deemed to be a new registration statement relating to the securities offered therein, and the offering of such securities at that time shall be deemed to be the initial bona fide offering thereof.
The undersigned registrant undertakes to send to each common unitholder, at least on an annual basis, a detailed statement of any transactions with our Sponsors, our general partner and their respective affiliates and of fees, commissions, compensation and other benefits paid, or accrued to our Sponsors, our general partner and their respective affiliates for the fiscal year completed, showing the amount paid or accrued to each recipient and the services performed.
The registrant undertakes to provide to the common unitholders the financial statements required by Form 10-K for the first full fiscal year of operations of the registrant.
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Pursuant to the requirements of the Securities Act of 1933, as amended, the registrant has duly caused this Registration Statement to be signed on its behalf by the undersigned, hereunto duly authorized, in the City of Fort Worth, State of Texas, on January 6, 2017.
| Kimbell Royalty Partners, LP | ||||||
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By: |
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Kimbell Royalty GP, LLC, its general partner |
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By: |
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/s/ ROBERT D. RAVNAAS |
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| Name: | Robert D. Ravnaas | |||||
| Title: |
Chief Executive Officer and
Chairman of the Board |
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Each person whose signature appears below appoints Robert D. Ravnaas and R. Davis Ravnaas, and each of them, any of whom may act without the joinder of the other, as his or her true and lawful attorneys-in-fact and agents, with full power of substitution and re-substitution, for him or her and in his or her name, place and stead, in any and all capacities, to sign any and all amendments (including post-effective amendments) to this Registration Statement and any Registration Statement (including any amendment thereto) for this offering that is to be effective upon filing pursuant to Rule 462(b) under the Securities Act of 1933, as amended, and to file the same, with all exhibits thereto, and all other documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorneys-in-fact and agents full power and authority to do and perform each and every act and thing requisite and necessary to be done, as fully to all intents and purposes as he might or would do in person, hereby ratifying and confirming all that said attorneys-in-fact and agents, or any of them of their, or his or her substitute and substitutes, may lawfully do or cause to be done by virtue hereof.
Pursuant to the requirements of the Securities Act of 1933, as amended, this Registration Statement has been signed below by the following persons in the capacities and the dates indicated.
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Signature
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Title
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Date
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/s/ ROBERT D. RAVNAAS
Robert D. Ravnaas |
Chief Executive Officer and Chairman of the Board
(Principal Executive Officer) |
January 6, 2017 | ||
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/s/ R. DAVIS RAVNAAS R. Davis Ravnaas |
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President and Chief Financial Officer (Principal Financial Officer) |
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January 6, 2017 |
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/s/ JEFF MCINNIS Jeff McInnis |
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Chief Accounting Officer (Principal Accounting Officer) |
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January 6, 2017 |
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Signature
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Title
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Date
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/s/ BRETT G. TAYLOR
Brett G. Taylor |
Executive Vice Chairman of the Board | January 6, 2017 | ||
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/s/ BENNY D. DUNCAN Benny D. Duncan |
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Director |
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January 6, 2017 |
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/s/ BEN J. FORTSON Ben J. Fortson |
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Director |
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January 6, 2017 |
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/s/ T. SCOTT MARTIN T. Scott Martin |
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Director |
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January 6, 2017 |
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/s/ MITCH S. WYNNE Mitch S. Wynne |
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Director |
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January 6, 2017 |
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Exhibit
Number |
|
Description | |||
|---|---|---|---|---|---|
| 1.1 | ** | — | Form of Underwriting Agreement | ||
| 2.1 | * # | — | Contribution, Conveyance, Assignment and Assumption Agreement, dated as of December 20, 2016, by and among Kimbell Royalty Partners, LP, Kimbell Royalty GP, LLC, Kimbell Intermediate GP, LLC, Kimbell Intermediate Holdings, LLC, Kimbell Royalty Holdings, LLC, and the other parties named therein | ||
| 3.1 | * | — | Certificate of Limited Partnership of Kimbell Royalty Partners, LP | ||
| 3.2 | ** | — | Form of Amended and Restated Agreement of Limited Partnership of Kimbell Royalty Partners, LP (included as Appendix A in the prospectus included in this Registration Statement) | ||
| 3.3 | * | — | Certificate of Formation of Kimbell Royalty GP, LLC | ||
| 3.4 | ** | — | Form of Amended and Restated Limited Liability Company Agreement of Kimbell Royalty GP, LLC | ||
| 5.1 | ** | — | Opinion of Baker Botts L.L.P. as to the legality of the securities being registered | ||
| 8.1 | ** | — | Opinion of Baker Botts L.L.P. relating to tax matters | ||
| 10.1 | ** | — | Form of Revolving Credit Agreement | ||
| 10.2 | ** | — | Form of Kimbell Royalty GP, LLC Long-Term Incentive Plan | ||
| 10.3 | ** | — | Form of Restricted Unit Agreement | ||
| 10.4 | * | — | Form of Management Services Agreement (Steward Royalties, LLC) | ||
| 10.5 | * | — | Form of Management Services Agreement (Taylor Companies Mineral Management, LLC) | ||
| 10.6 | * | — | Form of Management Services Agreement (K3 Royalties, LLC) | ||
| 10.7 | * | — | Form of Management Services Agreement (Nail Bay Royalties, LLC) | ||
| 10.8 | * | — | Form of Management Services Agreement (Duncan Management, LLC) | ||
| 10.9 | ** | — | Form of Management Services Agreement (Kimbell Operating Company, LLC) | ||
| 21.1 | * | — | List of subsidiaries of Kimbell Royalty Partners, LP | ||
| 23.1 | * | — | Consent of Grant Thornton LLP | ||
| 23.2 | * | — | Consent of Grant Thornton LLP | ||
| 23.3 | * | — | Consent of Grant Thornton LLP | ||
| 23.4 | * | — | Consent of Grant Thornton LLP | ||
| 23.5 | * | — | Consent of Grant Thornton LLP | ||
| 23.6 | * | — | Consent of Grant Thornton LLP | ||
| 23.7 | * | — | Consent of Ryder Scott Company, L.P. | ||
| 23.8 | ** | — | Consent of Baker Botts L.L.P. (included in Exhibit 5.1) | ||
| 23.9 | ** | — | Consent of Baker Botts L.L.P. (included in Exhibit 8.1) | ||
| 24.1 | * | — | Powers of Attorney (included on signature page) | ||
| 99.1 | * | — | Report of Ryder Scott Company, L.P. as of December 31, 2015 | ||
| 99.2 | * | — | Consent of Director Nominee (William H. Adams III) | ||
| 99.3 | * | — | Consent of Director Nominee (C.O. Ted Collins, Jr.) | ||
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Exhibit
Number |
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Description | |||
|---|---|---|---|---|---|
| 99.4 | * | — | Consent of Director Nominee (Craig Stone) | ||
- *
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Provided
herewith.
- **
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To
be provided by amendment.
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- The schedules to this agreement have been omitted pursuant to Item 601(b)(2) of Regulation S-K. The registrant will furnish supplementally a copy of each such schedule to the Securities and Exchange Commission upon request.
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