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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

FORM 10-K

 

☒

ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2019

or

☐

TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from                      to                     

Commission File Number: 001-36511

 

Montage Resources Corporation

(Exact name of registrant as specified in its charter)

 

 

Delaware

 

46-4812998

(State or other jurisdiction of
incorporation or organization)

 

(I.R.S. Employer
Identification No.)

 

 

122 West John Carpenter Freeway, Suite 300
Irving, TX

 

75039

(Address of principal executive offices)

 

(Zip code)

(469) 444-1647

(Registrant’s telephone number, including area code)

Securities registered pursuant to Section 12(b) of the Act:

 

Title of each class

 

Trading

Symbol(s)

 

Name of each exchange on which registered

Common Stock, Par Value $0.01 Per Share

 

MR

 

New York Stock Exchange

 

Securities registered pursuant to Section 12(g) of the Act: None.

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.    Yes   ☐     No   ☒

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.    Yes   ☐     No   ☒

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes   ☒     No   ☐

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).    Yes   ☒     No   ☐

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

 

Large accelerated filer

 

☐

  

Accelerated filer

 

☒

 

 

 

 

Non-accelerated filer

 

☐  

  

Smaller reporting company

 

☒

 

 

 

 

 

 

 

 

 

 

 

Emerging growth company

 

☐

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.  ☐

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).    ☐   Yes    ☒  No

The aggregate market value of the voting common stock held by non-affiliates of the registrant as of June 28, 2019, the last business day of the most recently completed second fiscal quarter, was approximately $129.1 million.

Number of shares of the registrant’s common stock outstanding at March 5, 2020: 35,826,888 shares.

Documents incorporated by reference: Portions of the registrant’s proxy statement for its 2020 annual meeting of stockholders to be filed pursuant to Regulation 14A within 120 days after the registrant’s fiscal year end are incorporated by reference into Part III of this Annual Report on Form 10-K.

 

 

 

 

 

Table of Contents

 

 

  

 

 

Page

Cautionary Statement Regarding Forward-Looking Statements

 

 

ii

 

 

 

 

Glossary of Oil and Natural Gas Terms

  

  

iii

 

 

 

 

 

 

PART I

  

 

 

 

 

Items 1 and 2  

  

Business and Properties

 

 

1

Item 1A

  

Risk Factors

 

 

23

Item 1B

  

Unresolved Staff Comments

 

 

50

Item 3

  

Legal Proceedings

 

 

50

Item 4

  

Mine Safety Disclosures

 

 

50

 

 

 

 

 

 

PART II

  

 

 

 

 

Item 5

  

Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

 

 

51

Item 6

  

Selected Financial Data

 

 

51

Item 7

  

Management’s Discussion and Analysis of Financial Condition and Results of Operations

 

 

53

Item 7A

  

Quantitative and Qualitative Disclosures About Market Risk

 

 

77

Item 8

  

Financial Statements and Supplementary Data

 

 

77

Item 9

  

Changes in and Disagreements With Accountants on Accounting and Financial Disclosure

 

 

77

Item 9A

  

Controls and Procedures

 

 

77

Item 9B

  

Other Information

 

 

80

 

 

 

 

 

 

PART III

  

 

 

 

 

Item 10

  

Directors, Executive Officers and Corporate Governance

 

 

81

Item 11

  

Executive Compensation

 

 

81

Item 12

  

Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

 

 

81

Item 13

  

Certain Relationships and Related Transactions, and Director Independence

 

 

81

Item 14

  

Principal Accounting Fees and Services

 

 

81

 

 

 

 

 

 

PART IV

  

 

 

 

 

Item 15

  

Exhibits, Financial Statement Schedules

 

 

82

Item 16

 

Form 10-K Summary

 

 

87

 

 

 

 

SIGNATURES

 

 

88

 

i

Cautionary Statement Regarding Forward-Looking Statements

This Annual Report on Form 10-K (the “Annual Report”) contains “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”), and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). All statements, other than statements of historical fact included in this Annual Report, including statements regarding our strategy, future operations, financial position, estimated revenues and income or losses, projected costs and capital expenditures, prospects, plans and objectives of management, are forward-looking statements. When used in this Annual Report, the words “will,” “may,” “plan,” “would,” “should,” “could,” “endeavor,” “believe,” “anticipate,” “intend,” “seek,” “estimate,” “expect,” “project,” “future,” “strategy,” “potential,” “continue,” “budget,” “forecast,” “assume” and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. These forward-looking statements are or were, when made, based on current expectations and assumptions about future events and are or were, when made based on currently available information as to the outcome and timing of future events. When considering forward-looking statements, you should keep in mind the risk factors and other cautionary statements described in “Item 1A. Risk Factors” of this Annual Report.

Forward-looking statements may include statements about, among other things:

 

•

realized prices for natural gas, natural gas liquids (“NGLs”) and oil and the volatility of those prices;

 

•

write-downs of our natural gas and oil asset values due to declines in commodity prices;

 

•

our business strategy;

 

•

our reserves;

 

•

general economic conditions;

 

•

our financial strategy, liquidity and capital required for developing our properties and the timing related thereto;

 

•

the timing and amount of our future production of natural gas, NGLs and oil;

 

•

our hedging strategy and results;

 

•

future drilling plans;

 

•

competition and government regulations, including those related to hydraulic fracturing;

 

•

the anticipated benefits under our commercial agreements;

 

•

marketing of natural gas, NGLs and oil;

 

•

leasehold and business acquisitions and joint ventures;

 

•

leasehold terms expiring before production can be established and our costs to extend such terms;

 

•

the costs, terms and availability of gathering, processing, fractionation and other midstream services;

 

•

credit markets;

 

•

uncertainty regarding our future operating results, including initial production rates and liquids yields in our type curve areas; and

 

•

plans, objectives, expectations and intentions contained in this Annual Report that are not historical.

We caution you that these forward-looking statements are subject to all of the risks and uncertainties, most of which are difficult to predict and many of which are beyond our control, incident to the exploration for and development, production, gathering and sale of natural gas, NGLs and oil. These risks include, but are not limited to, legal and environmental risks, drilling and other operating risks, regulatory changes, including US federal, state and local tax regulatory changes, commodity price volatility and the significant decline of the price of natural gas, NGLs and oil from historical highs, inflation, lack of availability of drilling, production and processing equipment and services, counterparty credit risk, the uncertainty inherent in estimating natural gas, NGLs and oil reserves and in projecting future rates of production, cash flows and access to capital, risks associated with our level of indebtedness, the timing of development expenditures, and the other risks described in “Item 1A. Risk Factors” of this Annual Report.

ii

Reserve engineering is a process of estimating underground accumulations of natural gas, NGLs and oil that cannot be measured in an exact way. The accuracy of any reserve estimate depends on the quality of available data, the interpretation of such data and price and cost assumptions made by reserve engineers. In addition, the results of drilling, testing and production activities may justify revisions of estimates that were made previously. If significant, such revisions could change the schedule of any further production and development drilling. Accordingly, reserve estimates may differ significantly from the quantities of natural gas, NGLs and oil that are ultimately recovered.

Should one or more of the risks or uncertainties described in this Annual Report occur, or should underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements.

All forward-looking statements, expressed or implied, included in this Annual Report are expressly qualified in their entirety by this cautionary statement. This cautionary statement should also be considered in connection with any subsequent written or oral forward-looking statements that we or persons acting on our behalf may issue.

Except as otherwise required by applicable law, we disclaim any duty to update any forward-looking statements, all of which are expressly qualified by the statements in this section, to reflect new information obtained or events or circumstances that occur after the date of this Annual Report.

Glossary of Oil and Natural Gas Terms

As used in this Annual Report, unless the context indicates or otherwise requires, the following terms have the following meanings:

 

•

“Bbl” refers to a standard barrel containing 42 U.S. gallons;

 

•

“Bbls/d” refers to Bbls per day;

 

•

“Bcfe” refers to one billion cubic feet of natural gas equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or NGLs;

 

•

“Boe” refers to one barrel of oil equivalent, calculated by converting natural gas to oil equivalent barrels at a ratio of six Mcf of natural gas to one Bbl of oil;

 

•

“Btu” refers to one British thermal unit, which is the quantity of heat required to raise the temperature of a one-pound mass of water by one-degree Fahrenheit;

 

•

“Completion” refers to the process of treating a drilled well followed by the installation of permanent equipment for the production of oil or natural gas or, in the case of a dry hole, the reporting of abandonment to the appropriate agency;

 

•

“Condensate” or “Condensate Window” refers to the area in which we generally expect Utica Shale wells to produce an initial condensate yield of up to approximately 0 to 300 barrels per MMcf of natural gas produced;

 

•

“Developed acreage” refers to the number of acres that are allocated or assignable to productive wells or wells capable of production;

 

•

“Differential” refers to 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 Gas” refers to the area in which we generally expect Utica Shale wells to produce natural gas having a heat content between 1,010 Btu and 1,080 Btu with no initial condensate yield;

 

•

“Dry hole” or “dry well” refers to 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;

iii

 

•

“Exploration” refers to a development or other project that may target proven or unproven reserves (such as probable or possible reserves), but which generally has a lower risk than that associated with exploration projects;

 

•

“Field” refers to an area consisting of a single reservoir or multiple reservoirs all grouped on, or related to, the same individual geological structural feature or stratigraphic condition. The field name refers to the surface area, although it may refer to both the surface and the underground productive formations;

 

•

“Formation” refers to a layer of rock that has distinct characteristics that differs from nearby rock;

 

•

“Gross acres” or “gross wells” refers to the total acres or wells, as the case may be, in which a working interest is owned;

 

•

“Horizontal drilling” refers to 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;

 

•

“Identified drilling locations” refers to total gross (net) resource play locations that we may be able to drill on our existing acreage. Actual drilling activities may change depending on the availability of capital, regulatory approvals, seasonal restrictions, natural gas and oil prices, costs, drilling results and other factors;

 

•

“Marcellus” or “Marcellus Area” refers to the area in which we generally expect Marcellus Shale wells to produce an initial condensate yield of approximately 0 to 140 barrels per MMcf of natural gas produced;

 

•

“MBbl” refers to one thousand barrels;

 

•

“Mcf” refers to one thousand cubic feet;

 

•

“Mcfe” refers to one thousand cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or NGLs;

 

•

“Mcf/d” refers to Mcfs per day;

 

•

“MMBbls” refers to one million barrels;

 

•

“MMBoe” refers to one million Boe;

 

•

“MMBtu” refers to one million British thermal units;

 

•

“MMcf” refers to one million cubic feet;

 

•

“MMcfe” refers to one million cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or NGLs;

 

•

“Net acres” refers to the amount of leased real estate that a petroleum and/or natural gas company has a true working interest in. Net acres express actual percentage interest when a company shares its working interest with another company; the total acreage under lease by a company is referred to as gross acres. Net acres account for the company’s percentage interest, multiplied by the gross acreage. If a company holds the entire working interest, its net acreage and gross acreage will be the same;

 

•

“Net production” refers to production that is owned by us less royalties and production due others;

 

•

“NGLs” refers to natural gas liquids, which are hydrocarbons found in natural gas that may be extracted as liquefied petroleum gas and natural gasoline;

 

•

“NYMEX” refers to the New York Mercantile Exchange;

 

•

“Operator” refers to the individual or company responsible for the exploration and/or production of an oil or natural gas well or lease;

iv

 

•

“Plugging” 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;

 

•

“Productive well” refers to a well that is expected to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of the production exceeds production expenses and taxes;

 

•

“Prospect” refers to a geological feature mapped as a location or probable location of a commercial oil and/ or gas accumulation. A prospect is defined as a result of geophysical and geological studies allowing the identification and quantification of uncertainties, probabilities of success, estimates of potential resources and economic viability;

 

•

“Proved undeveloped reserves” refers to 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;

 

(i)

Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances;

 

(ii)

Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances justify a longer time;

 

(iii)

Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir (as defined in Rule 4-10(a) (2) of Regulation S-X), or by other evidence using reliable technology establishing reasonable certainty;

 

•

“PV-10” refers to, when used with respect to natural gas and oil reserves, the estimated future gross revenue to be generated from the production of proved reserves, net of estimated production, future development and abandonment costs, using sales prices used in estimating proved oil and gas reserves and costs in effect at the determination date, before income taxes, and without giving effect to non-property-related expenses, discounted to a present value using an annual discount rate of 10% in accordance with the guidelines of the SEC;

 

•

“Realized price” refers to the cash market price less all expected quality, transportation and demand adjustments;

 

•

“Reservoir” refers to a porous and permeable underground formation containing a natural accumulation of producible oil and/or natural gas that is confined by impermeable rock or water barriers and is separate from other reservoirs;

 

•

“Rich Gas” or “Rich Gas Window” refers to the area in which we generally expect Utica Shale wells to produce natural gas having a heat content between 1,080 Btu and 1,150 Btu;

 

•

“SEC” refers to the United States Securities and Exchange Commission;

 

•

“Spacing” refers to 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;

 

•

“Spot market price” refers to the cash market price without reduction for expected quality, transportation and demand adjustments;

v

 

•

“Standardized measure” refers to discounted future net cash flows estimated by applying sales prices used in estimating proved oil and gas reserves to the estimated future production of year-end proved reserves. Future cash inflows are reduced by estimated future production and development costs based on period-end costs to determine pre-tax cash inflows. Future income taxes, if applicable, are computed by applying the statutory tax rate to the excess of pre-tax cash inflows over our tax basis in the natural gas and oil properties. Future net cash inflows after income taxes are discounted using a 10% annual discount rate;

 

•

“Undeveloped acreage” refers to 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;

 

•

“Unit” refers to the joining of all or substantially all interests in a reservoir or field, rather than a single tract, to provide for development and operation without regard to separate property interests. Also, the area covered by a unitization agreement;

 

•

“Working interest” refers to the right granted to the lessee of a property to explore for and to produce and own oil, natural gas or other minerals. The working interest owners bear the exploration, development and operating costs on either a cash, penalty or carried basis;

 

•

“WTI” refers to West Texas Intermediate; and

 

•

The terms “development project,” “development well,” “exploratory well,” “proved developed reserves,” “proved reserves” and “reserves” are defined by the SEC.

 

 

 

vi

PART I

 

 

Items 1 and 2.

Business and Properties

Our Company

Montage Resources Corporation, a Delaware corporation formed in 2014, is an independent exploration and production company engaged in the acquisition and development of oil and natural gas properties in the Appalachian Basin. On February 28, 2019, we completed a business combination (the “BRMR Merger”) with Blue Ridge Mountain Resources, Inc. (“BRMR”), and immediately thereafter, we changed our legal name from “Eclipse Resources Corporation” to “Montage Resources Corporation.” As of December 31, 2019, we had assembled an acreage position approximating 233,800 net surface acres in Eastern Ohio, 38,700 net surface acres in Pennsylvania, and 49,700 net surface acres in West Virginia, which excludes any acreage currently pending title.  We intend to focus on developing our substantial inventory of horizontal drilling locations during commodity price environments that will allow us to generate attractive returns and will continue to opportunistically add to this acreage position where we can acquire acreage at attractive prices.  As used in this Annual Report, unless the context indicates or otherwise requires, “Montage,” “Montage Resources,” the “Company,” “we,” “our,” “us” and like terms refer collectively to Montage Resources Corporation and its consolidated subsidiaries.

Our Properties

As of December 31, 2019, we had approximately 192,800 net acres in the Utica Shale fairway, which we refer to as the Utica Core Area, and approximately 55,300 net acres of stacked pay opportunity in our Marcellus Area.  We are the operator of approximately 98% of our net acreage within the Utica Core Area and our Marcellus Area. Additionally, we own approximately 74,100 net acres (which are approximately 80% held by production) outside of the Utica Core Area that may be prospective for the oil window of the Utica Shale.

Utica Shale

The Ordovician-aged Utica Shale is an unconventional reservoir comprised of organic-rich black shale, with most production occurring at vertical depths between 6,000 and 10,000 feet. The richest and thickest concentration of organic-carbon content is present within the Point Pleasant layer of the Lower Utica formation.  Across the Utica Core Area, the eastern boundary is more thermally mature and expected to produce dry gas, while the western boundary is less thermally mature and expected to produce a greater proportion of condensate and NGLs in addition to natural gas.  We classify our acreage between these boundaries as being prospective for Dry Gas, Rich Gas, or Condensate.

Indian Castle/Flat Creek Shales

The Indian Castle and Flat Creek Shales consist of organic-rich black shale, and we refer to them collectively as the “Flat Castle” area.  They are Ordovician in age and are correlative to the Utica, Point Pleasant and Logana Shales of Ohio.  The core of the area is located in Tioga County, Pennsylvania.  The top of the Flat Castle area formation is between 9,500 and 10,500 feet deep.  The shales in the Flat Castle area are very mature and produce dry gas in the area.

Marcellus Shale

The Marcellus Shale consists of organic-rich black shale, with most production occurring at vertical depths between 5,000 and 8,000 feet.  The reservoir underlying this acreage is less thermally mature than the Marcellus Shale in Southwestern Pennsylvania, and consequently, we believe natural gas production from this area will yield significant NGLs and condensate.

1

Activity

As of December 31, 2019, we had 370 gross (235.7 net) wells within the Utica Core Area and our Marcellus Area, which are summarized below:

 

 

 

Operated Gross Wells

 

 

Non-Operated Gross Wells

 

Type Curve Area(1)

 

Producing

to Sales

 

 

Awaiting

Turn to

Sales

 

 

Awaiting

Completion/

Completing

 

 

Drilling

 

 

Producing

to Sales

 

 

Awaiting

Turn to

Sales

 

 

Awaiting

Completion/

Completing

 

 

Drilling

 

Dry Gas

 

 

78

 

 

 

—

 

 

 

3

 

 

 

—

 

 

 

15

 

 

 

—

 

 

 

—

 

 

 

—

 

Rich Gas

 

 

—

 

 

 

—

 

 

 

—

 

 

 

—

 

 

 

18

 

 

 

—

 

 

 

—

 

 

 

—

 

Condensate

 

 

96

 

 

 

—

 

 

 

—

 

 

 

—

 

 

 

77

 

 

 

—

 

 

 

—

 

 

 

—

 

Flat Castle

 

 

2

 

 

 

—

 

 

 

—

 

 

 

—

 

 

 

—

 

 

 

—

 

 

 

—

 

 

 

—

 

Total Utica Core Area

 

 

176

 

 

 

—

 

 

 

3

 

 

 

—

 

 

 

110

 

 

 

—

 

 

 

—

 

 

 

—

 

Marcellus

 

 

56

 

 

 

—

 

 

 

3

 

 

 

1

 

 

 

21

 

 

 

—

 

 

 

—

 

 

 

—

 

Marcellus Area

 

 

56

 

 

 

—

 

 

 

3

 

 

 

1

 

 

 

21

 

 

 

—

 

 

 

—

 

 

 

—

 

Total

 

 

232

 

 

 

—

 

 

 

6

 

 

 

1

 

 

 

131

 

 

 

—

 

 

 

—

 

 

 

—

 

 

 

 

Operated Net Wells

 

 

Non-Operated Net Wells

 

Type Curve Area(1)

 

Producing

to Sales

 

 

Awaiting

Turn to

Sales

 

 

Awaiting

Completion/

Completing

 

 

Drilling

 

 

Producing

to Sales

 

 

Awaiting

Turn to

Sales

 

 

Awaiting

Completion/

Completing

 

 

Drilling

 

Dry Gas

 

 

61.6

 

 

 

—

 

 

 

2.8

 

 

 

—

 

 

 

1.7

 

 

 

—

 

 

 

—

 

 

 

—

 

Rich Gas

 

 

—

 

 

 

—

 

 

 

—

 

 

 

—

 

 

 

1.6

 

 

 

—

 

 

 

—

 

 

 

—

 

Condensate

 

 

82.3

 

 

 

—

 

 

 

—

 

 

 

—

 

 

 

14.4

 

 

 

—

 

 

 

—

 

 

 

—

 

Flat Castle

 

 

2.0

 

 

 

—

 

 

 

—

 

 

 

—

 

 

 

—

 

 

 

—

 

 

 

—

 

 

 

—

 

Total Utica Core Area

 

 

145.9

 

 

 

—

 

 

 

2.8

 

 

 

—

 

 

 

17.7

 

 

 

—

 

 

 

—

 

 

 

—

 

Marcellus

 

 

55.7

 

 

 

—

 

 

 

2.4

 

 

 

0.7

 

 

 

10.5

 

 

 

—

 

 

 

—

 

 

 

—

 

Marcellus Area

 

 

55.7

 

 

 

—

 

 

 

2.4

 

 

 

0.7

 

 

 

10.5

 

 

 

—

 

 

 

—

 

 

 

—

 

Total

 

 

201.6

 

 

 

—

 

 

 

5.2

 

 

 

0.7

 

 

 

28.2

 

 

 

—

 

 

 

—

 

 

 

—

 

 

(1)

All producing wells are classified as gas wells, except 1 gross (0.1 net) non-operated producing oil well.

Southern Appalachian Basin and Other Properties

Outside of the Utica Core Area and our Marcellus Area, we had 1,002 gross (975.3 net) conventional wells operated under multiple subsidiaries as of December 31, 2019.

Our subsidiary, Magnum Hunter Production, Inc. (“MHP”), owns certain oil and gas properties, primarily in Kentucky, including interests in certain drilling partnerships.  We have adopted a plan to divest these assets and continue to seek to do so.  These assets are reflected as assets held for sale on the Consolidated Balance Sheets, and the results of operations of these assets are included in discontinued operations on the Consolidated Statements of Operations and Comprehensive Income (Loss). (See Note 5— Assets Held for Sale and Discontinued Operations).

We also own an immaterial amount of royalty interests and working interests in other oil and gas properties, primarily consisting of interests in the Eagle Ford Shale in South Texas that are not material to our business and results of operations and are expected to be divested when practicable.

2

Reserves

As of December 31, 2019, our estimated proved reserves were 2,729.8 Bcfe, or 455.0 MMBoe, an increase of 46% from December 31, 2018 estimated proved reserves of 1,864.7 Bcfe, or 310.8 MMBoe, based on reserve reports prepared by Software Integrated Solutions Division of Schlumberger Technology Corporation (“SIS”), our independent petroleum engineers for the years ended December 31, 2019 and 2018. As of December 31, 2019, our estimated proved reserves were approximately 78% natural gas, 15% NGLs and 7% oil, and approximately 55% were proved developed reserves. The following table provides information regarding our proved reserves as of December 31, 2019, 2018, and 2017:

 

 

 

Estimated Total Proved Reserves

 

 

 

Natural Gas

(Bcf)

 

 

Oil

(MMBbls)

 

 

NGLs

(MMBbls)

 

 

Total

(Bcfe)

 

 

Total

(MMBoe)

 

 

%

Liquids

 

 

%

Developed

 

December 31, 2017

 

 

1,090.1

 

 

 

19.5

 

 

 

41.9

 

 

 

1,458.6

 

 

 

243.1

 

 

 

25.3

%

 

 

31.3

%

December 31, 2018

 

 

1,531.2

 

 

 

20.9

 

 

 

34.7

 

 

 

1,864.7

 

 

 

310.8

 

 

 

17.9

%

 

 

36.0

%

December 31, 2019

 

 

2,137.7

 

 

 

30.3

 

 

 

68.4

 

 

 

2,729.8

 

 

 

455.0

 

 

 

21.7

%

 

 

54.7

%

 

Net Undeveloped Locations

The following table provides a summary of our approximate net acreage, net producing locations and net undeveloped locations in our Utica Core and Marcellus Areas as of December 31, 2019:

 

 

 

As of December 31, 2019

 

 

 

Approximate Net Acreage

 

 

Net Producing Locations

 

 

Net Undeveloped Locations(1)

 

Dry Gas

 

 

92,650

 

 

 

63.3

 

 

 

220.0

 

Rich Gas

 

 

7,648

 

 

 

1.6

 

 

 

22.0

 

Condensate

 

 

53,841

 

 

 

96.7

 

 

 

133.0

 

Flat Castle

 

 

38,675

 

 

 

2.0

 

 

 

95.0

 

Marcellus

 

 

55,350

 

 

 

66.2

 

 

 

171.0

 

Total

 

 

248,164

 

 

 

229.8

 

 

 

641.0

 

 

(1)

Based on our reserve report as of December 31, 2019, we had 111 net drilling locations associated with proved undeveloped reserves and 3 net locations associated with proved developed non-producing reserves.  Please see “—Determination of Drilling Locations” for more information regarding the process and criteria through which these drilling locations were identified. The drilling locations on which we actually drill will depend on the availability of capital, regulatory approvals, commodity prices, costs, actual drilling results and other factors.  Our drilling locations are also scheduled out over many years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling. In addition, we may not be able to raise the substantial amount of capital that would be necessary to drill our drilling locations.  Please see “Item 1A. Risk Factors” for more information.

Determination of Drilling Locations

Net undeveloped locations are calculated by taking our total net undeveloped core acreage and multiplying such amount by a risk factor, which is then divided by our expected well spacing.  In each type curve area, we apply a 10% risk factor to our net undeveloped acreage to account for inefficient unitization, acreage expirations and the risk associated with our inability to force pool under state law.

 

 

•

Undeveloped Net Dry Gas Locations – We assume these locations have 13,000 foot laterals and 1,000 foot spacing between wells which yields approximately 298 acre spacing.  As of December 31, 2019, we had approximately 92,650 total net acres in the Dry Gas area, which, after removing net developed acres in this area, results in 220.0 net undeveloped locations.

 

•

Undeveloped Net Rich Gas Locations – We assume these locations have 13,000 foot laterals and 1,000 foot spacing between wells which yields approximately 298 acre spacing.  As of December 31, 2019, we had approximately 7,648 total net acres in the Rich Gas area, which, after removing net developed acres in this area, results in 22.0 net undeveloped locations.

3

 

•

Undeveloped Net Condensate Locations – We assume these locations have 13,000 foot laterals and 750 foot spacing between wells which yields approximately 224 acre spacing.  As of December 31, 2019, we had approximately 53,841 total net acres in the Condensate area, which, after removing net developed acres in this area, results in 133.0 net undeveloped locations.

 

•

Undeveloped Net Flat Castle Locations – We assume these locations have 13,000 foot laterals and 1,200 foot spacing between wells which yields approximately 358 acre spacing.  As of December 31, 2019, we had approximately 38,675 total net acres in the Flat Castle area, which, after removing net developed acres in this area, results in 95.0 net undeveloped locations.

 

•

Undeveloped Net Marcellus Locations – We assume these locations have 13,000 foot laterals and 750 foot spacing between wells which yields approximately 224 acre spacing.  As of December 31, 2019, we had approximately 55,350 total net acres in the Marcellus area, which, after removing net developed acres in this area, results in 171.0 net undeveloped locations.

Midstream and Firm Transportation Agreements

We work closely with our midstream partners to coordinate our drilling and completion schedule with their well hook up and facility construction schedules to ensure sufficient capacity is available to minimize any delays in turning production into sales.

Gas Gathering and Processing Agreements

We have contracted for firm gathering, processing and fractionation capacity for a significant portion of our operated acreage in the Condensate and Rich Gas Windows of the Utica Core Area with Blue Racer Midstream, LLC (“Blue Racer”), a joint venture between First Reserve and Caiman Energy II, LLC.  This gas-processing agreement does not require us to make minimum volume deliveries or shortfall payments.

In 2018, we amended our firm gas gathering services agreement with Eureka Midstream, LLC (“Eureka Midstream”) to gather and compress a substantial portion of our operated production of Dry Gas through Eureka Midstream’s system. This new agreement replaced an existing agreement with Eureka Midstream that we had entered into in 2013. Under the new 20-year agreement, we have firm gathering capacity, which increases during the term of the agreement, from between approximately 275 MMcf to 900 MMcf per day. This agreement provides for reduced gathering and compression charges. Through this agreement, we obtained access to additional downstream pipelines and markets connected to Eureka Midstream including the Rover Pipeline System, accessing our firm transportation capacity. This midstream agreement requires us to make minimum volume deliveries to the Eureka Midstream gathering system or shortfall payments. The following table illustrates the minimum volume commitments under our agreement with Eureka Midstream:

 

Term

 

Natural Gas

(Mcf/d)

 

January 2020 – December 2020

 

 

310,000

 

January 2021 – December 2021

 

 

355,000

 

January 2022 – December 2022

 

 

400,000

 

January 2023 – December 2023

 

 

362,500

 

January 2024 – December 2024

 

 

331,250

 

January 2025 – December 2025

 

 

250,000

 

January 2026 – December 2026

 

 

202,500

 

January 2027 – December 2027

 

 

165,000

 

January 2028 – December 2028

 

 

140,000

 

January 2029 – December 2029

 

 

122,500

 

January 2030 – June 2030

 

 

105,000

 

 

4

During 2019, Eclipse Resources I, L.P., a wholly owned subsidiary of the Company (“Eclipse I”), entered into a rich gas gathering agreement (firm service – three well pads) with Eureka Midstream, under which Eclipse I committed to the payment of monthly reservation fees for certain maximum daily quantities of gas delivered from three well pads in Monroe County, Ohio.  The rich gas gathering agreement provides for minimum volume commitments with respect to production from the pads, with annual commitments as follows:

 

Term

 

Natural Gas

(Mcf/d)

 

July 2019 – June 2020

 

 

41,000

 

July 2020 – June 2021

 

 

40,000

 

July 2021 – June 2022

 

 

23,000

 

July 2022 – June 2023

 

 

16,500

 

July 2023 – June 2024

 

 

12,500

 

July 2024 – June 2025

 

 

10,400

 

July 2025 – June 2026

 

 

8,500

 

July 2026 – June 2027

 

 

7,250

 

July 2027 – June 2028

 

 

6,000

 

July 2028 – June 2029

 

 

5,250

 

July 2029 – June 2030

 

 

4,250

 

July 2030 – June 2031

 

 

3,500

 

July 2031 – June 2032

 

 

3,000

 

July 2032 – June 2033

 

 

2,500

 

July 2033 – June 2034

 

 

2,000

 

 

During 2018, we assigned our option to purchase all of the outstanding equity interests of Cardinal NE Holdings, LLC (“Cardinal”), a wholly owned subsidiary of Cardinal Midstream II, LLC, which owns midstream infrastructure with associated gathering rights on acreage in the Flat Castle area, to DTE Pipeline Company (“DTE”).  The option was exercised and DTE completed its acquisition of Cardinal in July 2018.  The legacy gathering agreement for our Flat Castle area was assigned to DTE and does not require us to make minimum volume deliveries or shortfall payments.

As part of the BRMR Merger, we assumed a gas gathering contract for Triad Hunter, LLC (“Triad Hunter”), a wholly owned subsidiary of BRMR, with Eureka Midstream for operated acreage located in Eastern Ohio and West Virginia.  The gas gathering contract provides for minimum volume commitments determined on a system-wide basis with volume banking, with annual commitments of 210,000 MMBtu per day for 2019 through 2033.  In addition, the contract includes a minimum volume commitment of 50,000 Mcf per day for a compression facility through December 2033.

Also, as part of the BRMR Merger, we assumed Triad Hunter’s gas processing agreement with MarkWest Liberty Midstream and Resources, LLC (“MarkWest”).  The agreement provides for minimum volume commitments of 37,500 Mcf per day and expires in November 2024.  Effective May 1, 2019, this agreement was amended to reflect an adjusted acreage dedication and reduced processing fee.

5

Firm Transportation Agreements

The following table illustrates the natural gas firm transportation and sales volumes associated with our operated assets:

 

Firm Sales & Transportation

 

Start Date

 

Term

 

Volume (MMBtu/d)

 

 

Market

Columbia Gas Transmission

  (“TCO”)

 

October 2016

 

15 years

 

 

205,000

 

 

TCO Pool

Rover Pipeline System

 

June 2018

 

15 years

 

 

100,000

 

 

Gulf Coast

Rover Pipeline System

 

June 2018

 

15 years

 

 

50,000

 

 

Canada

Rockies Express Pipeline,

   LLC (“REX”)

 

March 2016

 

15 years

 

 

38,000

 

 

Midwest

REX

 

March 2016

 

15 years

 

 

12,000

 

 

Midwest

REX

 

October 2018

 

9 years

 

 

50,000

 

 

Midwest

Equitrans, L.P.

 

March 2019

 

5 years

 

 

50,000

 

 

REX Interconnect

Equitrans, L.P.

 

January 2025

 

4 years

 

 

35,000

 

 

REX Interconnect

As of December 31, 2019, our natural gas firm transportation commitments through 2033 include:

 

Year Ended December 31,

 

Volume of

Natural Gas

(MMBtu/d)

 

2020

 

 

505,000

 

2021

 

 

505,000

 

2022

 

 

505,000

 

2023

 

 

505,000

 

2024

 

 

505,000

 

2025

 

 

490,000

 

2026

 

 

490,000

 

2027

 

 

490,000

 

2028

 

 

440,000

 

2029

 

 

440,000

 

2030

 

 

405,000

 

2031

 

 

405,000

 

2032

 

 

150,000

 

2033

 

 

150,000

 

 Other Midstream Agreements

In March 2014, we entered into a 20-year contract with Shell Chemical, LP (“Shell Chemical”) for the sale of ethane to Shell Chemical’s proposed Appalachian cracker project in Monaca, Pennsylvania. Under the terms of the contract, we agreed to sell to Shell Chemical, at a minimum, all of our “Must Recover Ethane” (i.e., 30% of total recoverable ethane) at Blue Racer’s fractionation facility near Natrium, West Virginia.  In June 2016, Shell Chemical provided notice of a positive final investment decision and election to purchase our ethane.

In August 2014, we entered into an agreement with EnLink Midstream Operating, LP (“EnLink Midstream”) for the marketing of our condensate and operation of our condensate stabilization facilities. Under the terms of the agreement, among other things, EnLink Midstream purchased two of our existing condensate stabilization facilities and plans to construct and operate additional facilities to support our drilling program in the Utica Shale. This midstream agreement requires us to make minimum volume deliveries to the condensate stabilization facilities or shortfall payments. As of December 2019, we had fulfilled our firm commitments with EnLink Midstream.

  

In December 2014, we entered into a 10-year firm transportation and marketing agreement with Blue Racer to market a substantial portion of our operated production of propane and butane through Blue Racer’s firm capacity on Sunoco’s Mariner East II Project. Commencing operations in late 2018, the Mariner East II Project connects the

6

NGL resources in the Marcellus and Utica Shale to Sunoco’s existing infrastructure and international port at its Marcus Hook facility near Philadelphia.  During 2018, we modified the agreement to eliminate minimum volume commitments or shortfall payments, while maintaining our ability to market a portion of our operated production of propane and butane through the Mariner East II Project.  Through this agreement, we export propane and butane in order to potentially capture the premium pricing offered by international markets, but also retain the ability to sell domestically.

In April 2017, we entered into a 2-year hauling and marketing agreement with Marathon Petroleum Company, LP (“Marathon” or “Marathon Petroleum”) to sell condensate volumes. As a part of this contract, Marathon picked up the produced condensate at our stabilization facilities and well pads and hauled it away utilizing their own fleet of vehicles or third-party services. The title and risk of loss passed to Marathon at the intake flange of our stabilization facilities under the terms of this contract.  This agreement expired in March 2019 and we are currently using short-term agreements to sell condensate volumes to various purchasers going forward.

See “Item 1A. Risk Factors” for a discussion of risks and uncertainties relating to our gathering, processing, fractionation, and firm transportation arrangements.

Recent Developments

2020 Capital Budget

Our Board of Directors recently approved an initial capital budget for 2020 of between approximately $190 - $210 million, allocated approximately 95% for drilling and completions activities and approximately 5% for land capital requirements. The 2020 capital budget is expected to be substantially funded through internally generated cash flows, the Company’s current cash balance and borrowings under our revolving credit facility.

Oil and Natural Gas Data

Proved Reserves

Evaluation and Review of Proved Reserves. Our historical proved reserve estimates were prepared by SIS for the years ended December 31, 2019 and 2018 and Netherland, Sewell & Associates, Inc. (“NSAI”) for all prior years. The technical persons responsible for preparing our proved reserve estimates meet the requirements with regard to qualifications, independence, objectivity and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. Neither SIS nor NSAI owns an interest in any of our properties, nor are they employed by us on a contingent basis. A copy of SIS’s proved reserve reports as of December 31, 2019 and 2018 and NSAI’s proved reserve report as of December 31, 2017 are attached hereto as exhibits.

We maintain an internal staff of engineers and geoscience professionals who work closely with SIS to ensure the integrity, accuracy and timeliness of the data used to calculate our proved reserves relating to our assets. Our internal technical team members meet with SIS periodically during the period covered by the proved reserve report to discuss the assumptions and methods used in the proved reserve estimation process. We provide historical information for our properties to SIS, such as ownership interest, oil and natural gas production, well test data, commodity prices and operating and development costs. Matthew H. Rucker, our Executive Vice President, Resource Planning and Development, is primarily responsible for overseeing the preparation of all of our reserve estimates. Mr. Rucker is an engineer with approximately twelve years of reservoir engineering experience and our reservoir engineering staff has an average of approximately seven years of industry experience.

The preparation of our proved reserve estimates are completed in accordance with our internal control procedures. These procedures, which are intended to ensure reliability of reserve estimations, include the following:

 

•

review and verification of historical production data, which data is based on actual production as reported by us;

 

•

preparation of reserve estimates by Mr. Rucker or under his direct supervision;

7

 

•

review by Mr. Rucker 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 by our President and Chief Executive Officer;

 

•

direct reporting responsibilities by Mr. Rucker to our President and Chief Executive Officer; and

 

•

verification of property ownership by our land department.

SIS evaluated the proved reserves of 2,729.8 Bcfe and 1,864.7 Bcfe as of December 31, 2019 and 2018, respectively.  Schlumberger Technology Corporation was founded in 1926 and is the world’s leading provider of technology for reservoir characterization, drilling, production and process to the oil and natural gas industry.  SIS provides consulting, information management, and IT infrastructure services and sells proprietary software to customers in the oil and natural gas industry.  SIS also offers expert consulting services for reservoir characterization, field development planning and production enhancement.  The Lead Evaluator for the evaluation was Charles M. Boyer II, and his qualifications, independence, objectivity, and confidentiality meet the 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.  He has over 27 years of practical experience in the estimation and evaluation of reserves.  Mr. Boyer has been an employee of SIS since 1998 and is currently the Technical Team Leader and Advisor-Unconventional Reservoirs.  His responsibilities include reserves evaluation, acquisition and divestiture analysis, unconventional reservoir analysis, and underground gas storage evaluation.  Mr. Boyer graduated with a Bachelor of Science degree in Geological Sciences from The Pennsylvania State University in 1976; he is a registered Professional Geologist in the Commonwealth of Pennsylvania (No. PG004509), a Certified Petroleum Geologist of the American Association of Petroleum Geologists (No. 5733), and is a member in good standing of the Society of Petroleum Engineers, the Society of Petroleum Evaluation Engineers, the American Association of Petroleum Geologists, and the Society for Mining, Metallurgy, and Exploration.

The reserves estimate as of December 31, 2017 shown herein is based upon evaluations prepared by NSAI, a worldwide leader of petroleum property analysis for industry and financial organizations and government agencies. NSAI was founded in 1961 and performs consulting petroleum engineering services under Texas Board of Professional Engineers Registration No. F-2699.  Within NSAI, the technical persons primarily responsible for preparing the estimates set forth in the NSAI reserves report incorporated herein are Mr. Steven W. Jansen and Mr. Edward C. Roy III.  Mr. Jansen, a Licensed Professional Engineer in the State of Texas (No. 112973), has been practicing consulting petroleum engineering at NSAI since 2011 and has over 4 years of prior industry experience.  He graduated from Kansas State University in 2007 with a Bachelor of Science Degree in Chemical Engineering.  Mr. Roy, a Licensed Professional Geoscientist in the State of Texas, Geology (No. 2364), has been practicing consulting petroleum geoscience at NSAI since 2008 and has over 11 years of prior industry experience.  He graduated from Texas Christian University in 1992 with a Bachelor of Science Degree in Geology and from Texas A&M University in 1998 with a Master of Science Degree in Geology.  Both technical principals meet or exceed 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; both are proficient in judiciously applying industry standard practices to engineering and geoscience evaluations as well as applying SEC and other industry reserves definitions and guidelines.

8

Estimation of Proved Reserves. 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, 2019, 2018, and 2017 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 natural 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 natural gas reserves relies on the use of certain generally accepted analytical procedures. These analytical procedures fall into four broad categories or methods: (1) production performance-based methods; (2) material balance-based methods; (3) volumetric-based methods and (4) analogy. These methods may be used singularly or in combination by the reserve evaluator in the process of estimating the quantities of reserves. Reserves for proved developed producing wells were estimated using production performance methods for the vast majority of properties. Certain new producing properties with very little production history were forecast using a combination of production performance and analogy to similar production, both of which are considered to provide a relatively high degree of accuracy. Non-producing reserve estimates, for developed and undeveloped properties, were forecast using either volumetric or analogy methods, or a combination of both. These methods provide a relatively high degree of accuracy for predicting proved developed non-producing and proved undeveloped reserves for our properties.

To estimate economically recoverable proved reserves and related future net cash flows, SIS and NSAI considered many factors and assumptions, including the use of reservoir parameters derived from geological, geophysical and engineering data which cannot be measured directly, economic criteria based on current costs and the SEC pricing requirements and forecasts of future production rates.

Under SEC rules, reasonable certainty can be established using techniques that have been proven effective by actual production from projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology that establishes reasonable certainty. Reliable technology is a grouping of one or more technologies (including computational methods) that has been field-tested and has been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation. To establish reasonable certainty with respect to our estimated proved reserves, the technologies and economic data used in the estimation of our proved reserves have been demonstrated to yield results with consistency and repeatability, and include production and well test data, downhole completion information, geologic data, electrical logs, radioactivity logs, core analyses, available seismic data and historical well cost and operating expense data.

9

Summary of Natural Gas, NGLs and Oil Reserves. The following table presents our estimated net proved natural gas, NGLs and oil reserves as of December 31, 2019 and 2018, based on the proved reserve reports prepared by SIS, our independent petroleum engineers for the years ended December 31, 2019 and 2018, and as of December 31, 2017, based on the proved reserve report prepared by NSAI, our independent petroleum engineers for the year ended December 31, 2017, and such proved reserve reports have been prepared in accordance with the rules and regulations of the SEC. Our estimated proved reserves were determined using a 12-month unweighted arithmetic average of the first-day-of-the-month price for each month in the period January through December for the years 2019, 2018, and 2017. For oil and NGLs volumes, the SEC benchmark average WTI spot price of $55.85 per barrel for December 31, 2019, $65.56 per barrel for December 31, 2018 and $51.34 per barrel for December 31, 2017, is then adjusted by our property group for quality, transportation fees and regional price differentials. For gas volumes, the SEC benchmark average NYMEX Henry Hub spot price of $2.58 per MMBtu for December 31, 2019, $3.10 per MMBtu for December 31, 2018 and $2.98 per MMBtu for December 31, 2017 is then adjusted by our property group for energy content, transportation fees and regional price differentials. All prices are held constant throughout the lives of the properties. All of our proved reserves are located in the United States. Copies of the proved reserve reports as of December 31, 2019 and 2018 prepared by SIS and December 31, 2017 prepared by NSAI with respect to our properties are included as exhibits to this Annual Report. Our estimates of net proved reserves have not been filed with or included in reports to any federal authority or agency other than the SEC.

 

 

 

2019

 

 

2018

 

 

2017

 

Proved Developed Reserves:

 

 

 

 

 

 

 

 

 

 

 

 

Natural gas (Bcf)

 

 

1,183.2

 

 

 

501.0

 

 

 

334.6

 

NGLs (MBbls)

 

 

39,316.3

 

 

 

20,213.8

 

 

 

13,782.9

 

Oil (MBbls)

 

 

12,512.6

 

 

 

8,058.7

 

 

 

6,449.6

 

Combined (Bcfe)

 

 

1,494.2

 

 

 

670.7

 

 

 

456.0

 

Proved Undeveloped Reserves:

 

 

 

 

 

 

 

 

 

 

 

 

Natural gas (Bcf)

 

 

954.5

 

 

 

1,030.2

 

 

 

755.5

 

NGLs (MBbls)

 

 

29,043.2

 

 

 

14,517.2

 

 

 

28,147.7

 

Oil (MBbls)

 

 

17,812.2

 

 

 

12,793.4

 

 

 

13,031.2

 

Combined (Bcfe)

 

 

1,235.6

 

 

 

1,194.1

 

 

 

1,002.6

 

Proved Reserves:

 

 

 

 

 

 

 

 

 

 

 

 

Natural gas (Bcf)

 

 

2,137.7

 

 

 

1,531.2

 

 

 

1,090.1

 

NGLs (MBbls)

 

 

68,359.4

 

 

 

34,730.9

 

 

 

41,930.6

 

Oil (MBbls)

 

 

30,324.8

 

 

 

20,852.1

 

 

 

19,480.8

 

Combined (Bcfe)

 

 

2,729.8

 

 

 

1,864.7

 

 

 

1,458.6

 

 

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 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 natural gas, NGLs and oil that are ultimately recovered. Estimates of economically recoverable natural gas, NGLs and oil 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 “Item 1A. Risk Factors” appearing elsewhere in this Annual Report.

Additional information regarding our proved reserves can be found in the notes to our Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data” and the proved reserve reports as of December 31, 2019, 2018, and 2017, which are included as exhibits to this Annual Report.

10

Proved Reserves Additions and Revisions

To maintain and grow production and cash flow, we must continue to develop existing proved reserves and locate or acquire new natural gas, NGLs and oil reserves. The following is a discussion of net proved reserves, reserve additions and revisions and future net cash flows from proved reserves.

 

 

 

Natural Gas

(Bcf)

 

 

NGLs

(MBbls)

 

 

Oil

(MBbls)

 

 

Total

(Bcfe)

 

Proved Reserves:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

December 31, 2016

 

 

386.4

 

 

 

8,675.5

 

 

 

5,157.7

 

 

 

469.4

 

Reserve revisions

 

 

515.1

 

 

 

20,327.3

 

 

 

9,746.8

 

 

 

695.6

 

Extensions and discoveries

 

 

274.4

 

 

 

15,598.8

 

 

 

6,192.9

 

 

 

405.1

 

Acquisitions

 

 

1.6

 

 

 

42.6

 

 

 

5.8

 

 

 

1.9

 

Production

 

 

(87.4

)

 

 

(2,713.6

)

 

 

(1,622.4

)

 

 

(113.4

)

December 31, 2017

 

 

1,090.1

 

 

 

41,930.6

 

 

 

19,480.8

 

 

 

1,458.6

 

Reserve revisions

 

 

5.6

 

 

 

(8,307.5

)

 

 

231.2

 

 

 

(42.8

)

Extensions and discoveries

 

 

515.8

 

 

 

4,059.4

 

 

 

2,995.7

 

 

 

558.1

 

Acquisitions

 

 

9.9

 

 

 

551.4

 

 

 

522.2

 

 

 

16.3

 

Divestitures

 

 

(0.2

)

 

 

—

 

 

 

—

 

 

 

(0.2

)

Production

 

 

(90.0

)

 

 

(3,503.0

)

 

 

(2,377.8

)

 

 

(125.3

)

December 31, 2018

 

 

1,531.2

 

 

 

34,730.9

 

 

 

20,852.1

 

 

 

1,864.7

 

Reserve revisions

 

 

(77.0

)

 

 

4,454.5

 

 

 

(1,569.8

)

 

 

(59.6

)

Extensions and discoveries

 

 

418.7

 

 

 

19,016.3

 

 

 

11,078.1

 

 

 

599.2

 

Acquisitions

 

 

418.9

 

 

 

14,844.0

 

 

 

2,915.2

 

 

 

525.5

 

Production

 

 

(154.1

)

 

 

(4,686.3

)

 

 

(2,950.8

)

 

 

(200.0

)

December 31, 2019

 

 

2,137.7

 

 

 

68,359.4

 

 

 

30,324.8

 

 

 

2,729.8

 

 

During the year ended December 31, 2019, we increased proved reserves by 865.1 Bcfe compared to the year ended December 31, 2018, primarily through extensions and acquisitions. This increase in proved reserves was comprised of 599.2 Bcfe of extensions and 525.5 Bcfe of acquisitions.  The increase was offset by 200.0 Bcfe of production and 59.6 Bcfe of revisions primarily driven by a decrease in SEC pricing.

Future Net Cash Flows. At December 31, 2019, 2018, and 2017, the standardized measure of estimated future net cash flows after income taxes from our proved reserves was $1,195.8 million, $1,329.3 million and $729.7 million, respectively.  At December 31, 2019, 2018, and 2017, the PV-10 value of estimated future net cash flows before income taxes from our proved reserves was $1,470.7 million, $1,366.7 million and $729.7 million, respectively. These PV-10 values were calculated based on the unweighted average first-day-of-the-month oil and gas prices for the prior twelve months held flat for the life of the reserves.

The following table sets forth the estimated future net cash flows from our proved reserves (without giving effect to our commodity hedges), the present value of those net cash flows before income tax (PV-10) and the present value of those net cash flows after income tax (standardized measure):

 

 

 

Year Ended December 31,

 

(In thousands)

 

2019

 

 

2018

 

 

2017

 

Future net cash flows

 

$

3,363,019

 

 

$

2,909,969

 

 

$

1,538,529

 

Present value of future net cash flows:

 

 

 

 

 

 

 

 

 

 

 

 

Before income tax (PV-10)

 

$

1,470,651

 

 

$

1,366,655

 

 

$

729,686

 

Income taxes

 

 

(274,827

)

 

 

(37,345

)

 

 

—

 

After income tax (standardized measure)

 

$

1,195,824

 

 

$

1,329,310

 

 

$

729,686

 

 

11

PV-10 is a non-GAAP financial measure and generally differs from standardized measure, the most directly comparable GAAP financial measure, because it does not include the effects of income taxes on future net revenues.  Neither PV-10 nor standardized measure represents an estimate of the fair market value of our oil and natural gas properties. We, and others, in the industry use PV-10 as a measure to compare the relative size and value of proved reserves held by companies without regard to the specific tax characteristics of such entities.  We believe that the presentation of the pre-tax PV-10 is relevant and useful to investors because it presents the discounted future net cash flows attributable to our reserves prior to taking into account corporate income taxes and our current tax structure.

Proved Undeveloped Reserves (PUDs)

As of December 31, 2019, our proved undeveloped reserves were comprised of 17,812.2 MBbls of oil, 954.5 Bcf of natural gas and 29,043.2 MBbls of NGLs, for a total of 1,235.6 Bcfe. As of December 31, 2018, our proved undeveloped reserves were comprised of 12,793.4 MBbls of oil, 1,030.2 Bcf of natural gas and 14,517.2 MBbls of NGLs, for a total of 1,194.1 Bcfe.  As of December 31, 2017, our proved undeveloped reserves were comprised of 13,031.2 MBbls of oil, 755.5 Bcf of natural gas and 28,147.7 MBbls of NGLs, for a total of 1,002.6 Bcfe.  PUDs will be converted from undeveloped to developed as the applicable wells begin production.

The following table summarizes our changes in PUDs during 2017, 2018, and 2019 (in Bcfe):

 

Balance, December 31, 2016

 

 

171.6

 

Reserve revisions(1)

 

 

528.5

 

Acquisitions

 

 

1.3

 

Extensions and discoveries

 

 

391.2

 

Transfers to proved developed

 

 

(90.0

)

Balance, December 31, 2017

 

 

1,002.6

 

Reserve revisions(2)

 

 

(101.8

)

Acquisitions

 

 

11.6

 

Extensions and discoveries

 

 

409.8

 

Transfers to proved developed

 

 

(128.1

)

Balance, December 31, 2018

 

 

1,194.1

 

Reserve revisions(3)

 

 

(130.0

)

Acquisitions

 

 

94.2

 

Extensions and discoveries

 

 

498.7

 

Transfers to proved developed

 

 

(421.4

)

Balance, December 31, 2019

 

 

1,235.6

 

 

(1)

Revisions to previous estimates are comprised of 91.1 Bcfe of negative technical revisions primarily due to well performance, 620.6 Bcfe of positive revisions related to pricing and differential changes, and negative revisions of 1.0 Bcfe due to expense assumption changes.

(2)

Revisions to previous estimates are comprised of 22.3 Bcfe of positive revisions primarily due to well performance, 8.0 Bcfe of positive revisions related to pricing and differential changes, and negative revisions of 132.1 Bcfe due to changes in well spacing assumptions.

(3)

Revisions to previous estimates are comprised of 158.0 Bcfe of positive revisions primarily due to adjustments to well performance, capital allocation, and lease operating expense, 243.8 Bcfe of negative revisions related to pricing and differential changes and 44.2 Bcfe of negative revisions due to changes in development.

During the year ended December 31, 2019, we converted approximately 421.4 Bcfe, or 35.3% of our proved undeveloped reserves as of December 31, 2018, to proved developed reserves at a capital cost of approximately $245.9 million.  Estimated future development costs relating to the development of our proved undeveloped reserves as of December 31, 2019 are approximately $920.6 million over the next five years.  All PUD drilling locations are scheduled to be converted to proved developed within five years of initial disclosure, with more than 60% of the future development costs expected to be spent in the next three years.

The development plan is formulated by our resource development and planning department and reviewed by our reserves committee and senior management.  This plan is frequently reviewed to ensure all capital is allocated to the wells that have the highest rate of return and optimal development profile within the undrilled well inventory.  This process may cause wells that were previously planned to be developed within five years to be rescheduled beyond five years and therefore no longer included as proved undeveloped wells in future filings.

12

Production and Price History

The following table sets forth information regarding net production of natural gas, NGLs and oil, and certain price and cost information for the periods indicated:

 

 

 

Year Ended December 31,

 

 

 

2019

 

 

2018

 

 

2017

 

Total Utica production volumes:

 

 

 

 

 

 

 

 

 

 

 

 

Natural gas (MMcf)

 

 

140,044.1

 

 

 

86,803.3

 

 

 

87,055.0

 

NGLs (MBbls)

 

 

4,072.2

 

 

 

3,499.8

 

 

 

2,710.1

 

Oil (MBbls)

 

 

2,578.8

 

 

 

2,246.4

 

 

 

1,612.6

 

Combined (MMcfe)

 

 

179,950.1

 

 

 

121,280.5

 

 

 

112,991.2

 

Average Utica daily production volumes:

 

 

 

 

 

 

 

 

 

 

 

 

Natural gas (Mcf/d)

 

 

383,683

 

 

 

237,817

 

 

 

238,507

 

NGLs (Bbls/d)

 

 

11,157

 

 

 

9,589

 

 

 

7,425

 

Oil (Bbls/d)

 

 

7,065

 

 

 

6,154

 

 

 

4,418

 

Combined (Mcfe/d)

 

 

493,012

 

 

 

332,277

 

 

 

309,567

 

Total Marcellus production volumes:

 

 

 

 

 

 

 

 

 

 

 

 

Natural gas (MMcf)

 

 

14,093.4

 

 

 

3,162.4

 

 

 

349.2

 

NGLs (MBbls)

 

 

614.1

 

 

 

3.3

 

 

 

3.6

 

Oil (MBbls)

 

 

372.0

 

 

 

131.6

 

 

 

9.8

 

Combined (MMcfe)

 

 

20,010.0

 

 

 

3,971.8

 

 

 

429.6

 

Average Marcellus daily production volumes:

 

 

 

 

 

 

 

 

 

 

 

 

Natural gas (Mcf/d)

 

 

38,612

 

 

 

8,664

 

 

 

957

 

NGLs (Bbls/d)

 

 

1,682

 

 

 

9

 

 

 

10

 

Oil (Bbls/d)

 

 

1,019

 

 

 

361

 

 

 

27

 

Combined (Mcfe/d)

 

 

54,822

 

 

 

10,882

 

 

 

1,177

 

Total production volumes:

 

 

 

 

 

 

 

 

 

 

 

 

Natural gas (MMcf)

 

 

154,137.5

 

 

 

89,965.7

 

 

 

87,404.2

 

NGLs (MBbls)

 

 

4,686.3

 

 

 

3,503.1

 

 

 

2,713.7

 

Oil (MBbls)

 

 

2,950.8

 

 

 

2,378.0

 

 

 

1,622.4

 

Combined (MMcfe)

 

 

199,960.1

 

 

 

125,252.3

 

 

 

113,420.8

 

Average daily production volumes:

 

 

 

 

 

 

 

 

 

 

 

 

Natural gas (Mcf/d)

 

 

422,295

 

 

 

246,481

 

 

 

239,464

 

NGLs (Bbls/d)

 

 

12,839

 

 

 

9,598

 

 

 

7,435

 

Oil (Bbls/d)

 

 

8,084

 

 

 

6,515

 

 

 

4,445

 

Combined (Mcfe/d)

 

 

547,834

 

 

 

343,159

 

 

 

310,744

 

Average Realized Price (including cash settled

   derivatives and firm transportation):

 

 

 

 

 

 

 

 

 

 

 

 

Natural gas ($/Mcf)

 

$

1.99

 

 

$

2.41

 

 

$

2.34

 

NGLs ($/Bbl)

 

 

18.45

 

 

 

24.32

 

 

 

21.96

 

Oil ($/Bbl)

 

 

50.01

 

 

 

50.47

 

 

 

46.14

 

Combined ($/Mcfe)

 

$

2.70

 

 

$

3.37

 

 

$

2.99

 

Expenses (per Mcfe):

 

 

 

 

 

 

 

 

 

 

 

 

Lease operating

 

$

0.22

 

 

$

0.23

 

 

$

0.18

 

Transportation, gathering and compression

 

 

1.04

 

 

 

1.10

 

 

 

1.10

 

Production, severance and ad valorem taxes

 

 

0.06

 

 

 

0.08

 

 

 

0.07

 

Depreciation, depletion, amortization and

   accretion

 

 

0.77

 

 

 

1.07

 

 

 

1.05

 

General and administrative

 

 

0.35

 

 

 

0.35

 

 

 

0.39

 

13

Developed and Undeveloped Acreage

The following table sets forth information as of December 31, 2019 relating to our leasehold acreage. Developed acres are acres spaced or assigned to productive wells and does not include undrilled acreage held by production under the terms of the lease. Undeveloped acres are acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil or natural gas, regardless of whether such acreage contains proved reserves. A gross acre is an acre in which a working interest is owned. The number of gross acres is the total number of acres in which a working interest is owned. A net acre is deemed to exist when the sum of the fractional ownership working interests in gross acres equals one. The number of net acres is the sum of the fractional working interests owned in gross acres expressed as whole numbers and fractions thereof.

 

 

 

Developed Acreage

 

 

Undeveloped Acreage

 

 

Total Acreage

 

Area

 

Gross

 

 

Net(1)

 

 

Gross

 

 

Net(1)

 

 

Gross

 

 

Net(1)

 

Ohio

 

 

68,353

 

 

 

46,229

 

 

 

243,884

 

 

 

187,531

 

 

 

312,237

 

 

 

233,760

 

Pennsylvania

 

 

2,928

 

 

 

2,859

 

 

 

39,657

 

 

 

35,815

 

 

 

42,585

 

 

 

38,674

 

West Virginia

 

 

5,854

 

 

 

5,684

 

 

 

50,112

 

 

 

44,044

 

 

 

55,966

 

 

 

49,728

 

Total

 

 

77,135

 

 

 

54,772

 

 

 

333,653

 

 

 

267,390

 

 

 

410,788

 

 

 

322,162

 

 

(1)

United Company owns a right to participate for a 12.5% working interest in approximately 1,368 gross acres within our area of mutual interest with Antero Resources Corporation. In calculating our net acreage, we have assumed that United Company will elect to participate in all wells in which they have a right to participate for their full interest and have deducted this 12.5% working interest from our net acreage where applicable.

 

As part of the BRMR Merger, we became party to a Joint Development Agreement (“JDA”) in which an unaffiliated third party owns the right to participate for a 40% working interest in approximately 19,143 gross acres within our JDA area of mutual interest located predominately in Benton, Ludow and Grandview townships in Monroe and Washington Counties, Ohio.  In calculating our net acreage, we have assumed that the unaffiliated third party will elect to participate in all wells in which it has a right to participate for its full interest and have deducted this 40% working interest from our net acreage where applicable.

Many of the leases comprising the undeveloped acreage set forth in the table above will expire at the end of their respective primary terms, although approximately 56% of our leases in the Utica Core Area have a 3-5 year extension at our option. The following table sets forth the total gross and net undeveloped acres as of December 31, 2019 that will expire over the next five years unless operations have commenced on the leasehold acreage or lands pooled therewith have been established prior to such date, in which event the lease will remain in effect until the cessation of production in commercial quantities:

 

Year Ending December 31,

 

Gross Acres

 

 

Net Acres

 

2020

 

 

29,149

 

 

 

23,806

 

2021

 

 

18,764

 

 

 

12,449

 

2022

 

 

11,001

 

 

 

4,899

 

2023

 

 

7,611

 

 

 

4,233

 

2024 and beyond

 

 

18,867

 

 

 

13,650

 

 

In 2020, we expect to incur approximately $5.7 million related to delay rentals and lease extensions related to acreage that would otherwise expire during 2020.  

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Drilling Results

The following table sets forth information with respect to the number of wells completed during the years indicated. The information should not be considered indicative of future performance, nor should it be assumed that there is necessarily any correlation between the number of productive wells drilled, quantities of reserves found or economic value. Productive wells are those that produce commercial quantities of hydrocarbons, whether or not they produce a reasonable rate of return.

 

 

 

2019

 

 

2018

 

 

2017

 

 

 

Gross

 

 

Net

 

 

Gross

 

 

Net

 

 

Gross

 

 

Net

 

Development Wells:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Productive

 

 

39

 

 

 

30.8

 

 

 

30

 

 

 

17.6

 

 

 

25

 

 

 

22.2

 

Dry holes

 

 

—

 

 

 

—

 

 

 

—

 

 

 

—

 

 

 

—

 

 

 

—

 

Exploratory Wells:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Productive

 

 

—

 

 

 

—

 

 

 

—

 

 

 

—

 

 

 

—

 

 

 

—

 

Dry holes

 

 

—

 

 

 

—

 

 

 

—

 

 

 

—

 

 

 

—

 

 

 

—

 

Total:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Productive

 

 

39

 

 

 

30.8

 

 

 

30

 

 

 

17.6

 

 

 

25

 

 

 

22.2

 

Dry holes

 

 

—

 

 

 

—

 

 

 

—

 

 

 

—

 

 

 

—

 

 

 

—

 

 

All of these productive wells are gas wells. Many of our gas wells also produce oil, condensate and NGLs. As of December 31, 2019, we had 7 gross (5.9 net) wells in the process of drilling, completing or shut in awaiting infrastructure that are not reflected in the above table.

Operations

General

As of December 31, 2019, we operated approximately 98% of our net acreage. As operator, we design and manage the development of a well and supervise operation and maintenance activities on a day-to-day basis. Independent contractors engaged by us provide all the equipment and personnel associated with these activities. We employ engineers, geologists and land professionals who work to improve production rates, increase reserves and lower the cost of operating our oil and natural gas properties.

Major Customers

For the year ended December 31, 2019, sales to BP Energy Company (“BP”) and Marathon represented approximately 23% and 20% of our total sales, respectively.  For the year ended December 31, 2018, sales to Marathon represented approximately 25% of our total sales. For the year ended December 31, 2017, sales to Emera Energy Services, Inc. (“Emera Energy Services”) and Marathon represented approximately 17% and 10% of our total sales, respectively. Although a substantial portion of production is purchased by these major customers, we do not believe the loss of any one or several customers would have a material adverse effect on our business, as other customers or markets would be accessible to us.

Title to Properties

We believe that we have satisfactory title to all of our producing properties in accordance with generally accepted industry standards. As is customary in the industry, in the case of undeveloped properties, often-cursory investigation of record title is made at the time of lease acquisition. Investigations are made before the consummation of an acquisition of producing properties and before commencement of drilling operations on undeveloped properties. Individual properties may be subject to burdens that we believe do not materially interfere with the use or affect the value of the properties. Burdens on properties may include:

 

•

customary royalty interests;

 

•

liens incident to operating agreements and for current taxes;

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•

obligations or duties under applicable laws;

 

•

development obligations under natural gas leases;

 

•

net profits interests;

 

•

mortgages by a lessor; or

 

•

rights of way or easements held by third parties such as utilities.

Seasonality

Demand for natural gas generally decreases during the spring and fall months and increases during the summer and winter months. However, seasonal anomalies such as mild winters or mild summers sometimes lessen this fluctuation. In addition, some natural gas users utilize natural gas storage facilities and purchase some of their anticipated winter requirements during the summer. This can also lessen seasonal demand fluctuations. These seasonal anomalies can increase competition for equipment, supplies and personnel during the spring and summer months, which could lead to shortages and increase costs or delay our operations.

Competition

The oil and natural gas industry is intensely competitive, and we compete with other companies in our industry that have greater resources than we do. Many of these companies not only explore for and produce natural gas, but also carry on refining operations and market petroleum and other products on a regional, national or worldwide basis. These companies may be able to pay more for productive natural gas properties and exploratory prospects or define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit and may be able to expend greater resources to attract and maintain industry personnel. In addition, these companies may have a greater ability to continue exploration activities during periods of low natural gas market prices. Our larger 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. Our ability to acquire additional properties and to discover reserves in the future will be dependent upon 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 do in our industry, we may be at a disadvantage in bidding for exploratory prospects and producing natural gas properties.

Regulation of the Oil and Natural Gas Industry

Our operations are substantially affected by federal, state and local laws and regulations. In particular, natural gas production and related operations are, or have been, subject to price controls, taxes and numerous other laws and regulations. All of the jurisdictions in which we own or operate producing natural gas and oil properties have statutory provisions regulating the exploration for and production of natural gas and oil, including provisions related to permits for the drilling of wells, bonding requirements to drill or operate wells, the location of wells, the method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled, sourcing and disposal of water used in the drilling and completion process, and the abandonment of wells. Our operations are also subject to various conservation laws and regulations. These include the regulation of the size of drilling and spacing units or proration units, the number of wells that may be drilled in an area, and the unitization or pooling of crude oil or natural gas wells, as well as regulations that generally prohibit the venting or flaring of natural gas, and impose certain requirements regarding the ratability or fair apportionment of production from fields and individual wells.

Failure to comply with applicable laws and regulations can result in substantial penalties. The regulatory burden on the industry increases the cost of doing business and affects profitability. Although we believe that we are in substantial compliance with all applicable laws and regulations, such laws and regulations are frequently amended or reinterpreted.  Therefore, we are unable to predict our future ability to comply with applicable law and regulations or the future costs or impact of compliance.

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Regulation of Production of Natural Gas and Oil

The production of natural gas and oil is subject to regulation under a wide range of local, state and federal statutes, rules, orders and regulations. Federal, state and local statutes and regulations require permits for drilling operations, drilling bonds and reports concerning operations. All of the states in which we own and operate properties have regulations governing conservation matters, including provisions for the unitization or pooling of natural gas and oil properties, the establishment of maximum allowable rates of production from natural gas and oil wells, the regulation of well spacing or density, and plugging and abandonment of wells. The effect of these regulations is to limit the amount of natural gas and oil that we can produce from our wells and to limit the number of wells or the locations at which we can drill; although in some cases, we can apply for exceptions to such regulations or to have reductions in well spacing or density. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of natural gas, NGLs and oil within its jurisdiction.

We own interests in properties located onshore in primarily three U.S. states. These states regulate drilling and operating activities by requiring, among other things, permits for the drilling of wells, maintaining bonding requirements in order to drill or operate wells, and regulating the location of wells, the method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled and the plugging and abandonment of wells. The laws of these states also govern a number of environmental and conservation matters, including the handling and disposing or discharge of waste materials, the size of drilling and spacing units or proration units and the density of wells that may be drilled, unitization and pooling of oil and gas properties and establishment of maximum rates of production from oil and gas wells. Some states have the power to prorate production to the market demand for oil and gas. The failure to comply with these rules and regulations can result in substantial penalties.

Regulation of Transportation and Sales of Natural Gas

Historically, the transportation (including storage services) and sale for resale of natural gas in interstate commerce have been regulated by agencies of the U.S. federal government, primarily the Federal Energy Regulatory Commission, or FERC. FERC regulates interstate natural gas transportation rates and service conditions, which affects the marketing of natural gas that we produce and the revenues we receive for sales of our natural gas.

FERC’s current policies allow for the sale of natural gas by producers at market-based prices. However, Congress could enact price controls in the future. The transportation and sale for resale of natural gas in interstate commerce is regulated primarily under the Natural Gas Act, or NGA, and by regulations and orders promulgated under the NGA by FERC. In some limited circumstances, intrastate transportation and wholesale sales of natural gas may also be affected directly or indirectly by laws enacted by Congress and by FERC regulations.

The Energy Policy Act of 2005, or the EPAct 2005, among other matters, amended the NGA to add an anti-manipulation provision, which makes it unlawful for any entity, directly or indirectly, to use or employ, in connection with the purchase or sale of natural gas or the purchase of natural gas transportation services subject to FERC jurisdiction, any manipulative or deceptive device or contrivance of such rules and regulations as FERC may prescribe as necessary in the public interest or for the protection of natural gas ratepayers.  Furthermore, EPAct 2005 provides FERC with additional civil penalty authority. The EPAct 2005 provides FERC with the power to assess civil penalties of up to $1,000,000 per day for violations of the NGA and increases FERC’s civil penalty authority under the Natural Gas Policy Act, or NGPA, from $5,000 per violation per day to $1,000,000 per violation per day. These civil penalty amounts under the NGA and NGPA have been adjusted in accordance with the Federal Civil Penalties Inflation Adjustment Act of 1990, as amended by the Federal Civil Penalties Inflation Adjustment Improvements Act of 2015, from $1,000,000 per violation per day to $1,291,894 per violation per day, effective January 14, 2020.

On January 19, 2006, FERC issued Order No. 670 to implement the anti-manipulation provision of the EPAct 2005. The rule makes it unlawful for any entity, directly or indirectly, in connection with the purchase or sale of natural gas or transportation services subject to the jurisdiction of FERC, to (1) use or employ any device, scheme or artifice to defraud; (2) make any untrue statement of material fact or omit to make any such statement necessary to make the statements made, in light of the circumstances under which they were made, not misleading; or (3) engage in any act, practice or course of business that operates, or would operate, as a fraud or deceit upon any entity. The anti-manipulation rule applies to “any entity”, including otherwise non-jurisdictional entities, and may include activities that relate to intrastate or other non-jurisdictional sales or gathering, to the extent such activities are conducted “in connection with” gas sales, purchases or transportation subject to FERC jurisdiction.

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On December 26, 2007, FERC issued Order 704, a final rule on the annual natural gas transaction reporting requirements, as amended by subsequent orders on rehearing. Under Order 704, wholesale buyers and sellers of more than 2.2 million MMBtus of physical natural gas in the previous calendar year, including natural gas gatherers and marketers, are now required to report, on May 1 of each year, aggregate volumes of natural gas purchased or sold at wholesale in the prior calendar year to the extent such transactions utilize, contribute to, or may contribute to the formation of price indices. It is the responsibility of the reporting entity to determine which individual transactions should be reported based on the guidance of Order 704. Order 704 also requires market participants to indicate whether they report prices to any index publishers, and if so, whether their reporting complies with FERC’s policy statement on price reporting. Reporting required under Order 704 is considered to constitute an activity conducted “in connection with” gas sales, purchases or transportation subject to FERC jurisdiction.

We cannot reliably predict whether FERC’s actions will achieve the goal of increasing competition in markets in which our natural gas is sold. Additional proposals and proceedings that might affect the natural gas industry are pending before FERC and the courts and new proposals and proceedings are likely to arise. The natural gas industry historically has been very heavily regulated and changing conditions and experience has led to changes in such regulation. However, we do not believe that any action taken will affect us in a way that materially differs from the way it affects other, similarly situated, natural gas producers.

Gathering service is regulated by the states onshore and in state waters. Although its policy is still in flux, FERC has reclassified certain jurisdictional transmission facilities as non-jurisdictional gathering facilities, which can increase our costs of getting gas to point of sale locations. State regulation of natural gas gathering facilities generally includes various safety, environmental and, in some circumstances, nondiscriminatory-take requirements. Although such regulation has not generally been affirmatively applied by state agencies, natural gas gathering may receive greater regulatory scrutiny in the future.

Section 1(b) of the NGA excludes natural gas gathering facilities from regulation by FERC under the NGA. Further, an entity is not subject to regulation under NGA by FERC as a “natural gas company” solely by virtue of such entity owning or operating such facilities. We believe that the natural gas pipelines in our gathering systems meet the traditional tests FERC has used to determine that the owner/operator of such facilities is not subject to regulation as a natural gas company under the NGA. However, FERC orders may affect the distinction between FERC-regulated transmission services and federally unregulated gathering services, which is the subject of ongoing litigation.  Furthermore, Congress has discretion to revise the jurisdictional line. Consequently, the classification and regulation of our gathering facilities are subject to change based on future determinations by FERC, the courts or Congress.

Our sales of natural gas are also subject to certain requirements under the Commodity Exchange Act, or CEA, and regulations promulgated thereunder by the Commodity Futures Trading Commission, or CFTC. The CEA prohibits any person from manipulating or attempting to manipulate the price of any commodity in interstate commerce or futures on such commodity. The CEA also prohibits knowingly delivering or causing to be delivered, false or misleading or knowingly inaccurate reports concerning market information or conditions that affect or tend to affect the price of a commodity.

Intrastate natural gas transportation is subject to regulation by state regulatory agencies. The basis for intrastate regulation of natural gas transportation and the degree of regulatory oversight and scrutiny given to intrastate natural gas pipeline rates and services varies from state to state. Insofar as such regulation within a particular state will generally affect all intrastate natural gas shippers within the state on a comparable basis, we believe that the regulation of similarly situated intrastate natural gas transportation in any states in which we operate and ship natural gas on an intrastate basis will not affect our operations in any way that is of material difference from those of our competitors. Like the regulation of interstate transportation rates, the regulation of intrastate transportation rates affects the marketing of natural gas that we produce, as well as the revenues we receive for sales of our natural gas.

Changes in law and to FERC policies and regulations may adversely affect the availability and reliability of firm and/or interruptible transportation service on interstate pipelines, and we cannot predict what future action Congress or FERC will take. We do not believe, however, that any regulatory changes will affect us in a way that materially differs from the way they will affect other, similarly situated, natural gas producers, gatherers and marketers with which we compete.

18

Regulation of Environmental and Occupational Safety and Health Matters

General

Our operations are subject to numerous federal, regional, state, local, and other laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. Applicable U.S. federal environmental laws include, but are not limited to, the Comprehensive Environmental Response, Compensation, and Liability Act, or CERCLA, the Resource Conservation and Recovery Act, or RCRA, the Clean Water Act, or the CWA, and the Clean Air Act, or the CAA. These laws and regulations, along with state analogs, govern environmental cleanup standards, require permits for air, water, underground injection, and solid and hazardous waste disposal and set environmental compliance criteria. In addition, state and local laws and regulations set forth specific standards for drilling wells, the maintenance of bonding requirements in order to drill or operate wells, the spacing and location of wells, the method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled, the plugging and abandoning of wells, and the prevention and cleanup of pollutants and other matters. We maintain insurance against costs of clean-up operations, but we are not fully insured against all such risks. Additionally, Congress, state legislatures and federal and state agencies frequently revise environmental laws and regulations, and any changes that result in delay or more stringent and costly permitting, waste handling, disposal and clean-up requirements for the oil and gas industry could have a significant impact on our operating costs.  In jurisdictions which allow them, direct voter initiatives seeking to restrict oil and gas development could result in similar impacts.

In addition, public and regulatory scrutiny of the energy industry has resulted in increased environmental regulation and enforcement being either proposed or implemented. For example, “Ensuring Energy Extraction Activities Comply with Environmental Laws” was selected by the EPA as a National Compliance Initiative for fiscal years 2017 through 2019.  Although the EPA will discontinue this category as a National Compliance Initiative for fiscal years 2020 through 2023, the energy industry will continue to be subject to increased scrutiny under the “Creating Clean Air for Communities by Reducing Excess Emissions of Harmful Pollutants from Stationary Sources” National Compliance Initiative selected for 2020 through 2023.  According to the EPA’s website, this new initiative will focus on significant sources of volatile organic compound emissions contributing to non-attainment with federal air quality standards and on hazardous air pollutants. This initiative could involve a large-scale investigation of our facilities and processes, and could lead to potential enforcement actions, penalties or injunctive relief against us.

Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal fines and penalties and the imposition of injunctive relief. Noncompliance could also result in an increase in capital expenditures or reduced earnings and hurt our ability to compete in the marketplace. Accidental releases or spills may occur in the course of our operations, and we cannot be sure that we will not incur significant costs and liabilities as a result of such releases or spills, including any third-party claims for damage to property, natural resources or persons. Although we believe that we are in substantial compliance with applicable environmental laws and regulations and that continued compliance with existing requirements will not have a material adverse impact on us, there can be no assurance that this will continue in the future.

The Safe Drinking Water Act and the Underground Injection Control Program

Hydraulic fracturing is an important and common practice that is used to stimulate production of natural gas and/or oil from subsurface rock formations. We regularly use hydraulic fracturing as part of our operations. Hydraulic fracturing typically is regulated by state oil and natural gas commissions, but the EPA has asserted federal regulatory authority pursuant to the federal Safe Drinking Water Act, or the SDWA, over hydraulic fracturing activities involving the use of diesel fuel. From time to time, however, Congress has proposed legislation to amend the SDWA to repeal the exemption for hydraulic fracturing from the definition of “underground injection” and require federal permitting and regulatory control of all hydraulic fracturing activities, as well as to require disclosure of the chemical constituents of the fluids used in the fracturing process. Scrutiny of hydraulic fracturing activities by the EPA continues in other ways, with the EPA having completed a final report for a multi-year study of the potential environmental impacts of hydraulic fracturing. In addition, in June 2016, the EPA published final regulations under the CWA for wastewater discharges associated with unconventional oil and natural gas resources, such as low permeability and porosity formations.  Moreover, in 2015, the U.S. Department of the Interior finalized updated requirements for hydraulic fracturing activities on federal lands, including new requirements relating to public disclosure, well bore integrity and handling of flowback water and, in 2016, the Department of the Interior

19

finalized rules to minimize venting and flaring from wells on federal lands.  Although the Department of the Interior hydraulic fracturing rule has been rescinded and the venting and flaring rule has been replaced with a less stringent version, the original rules could be reinstated through litigation, which could result in material compliance obligations.  Other governmental agencies, including the United States Department of Energy have evaluated or are evaluating various other aspects of hydraulic fracturing. These ongoing or proposed studies could spur initiatives to further regulate hydraulic fracturing under the SDWA or other regulatory mechanisms and could ultimately make it more difficult or costly for us to perform fracturing and increase our costs of compliance and doing business.

At the state level, several states have adopted or are considering legal requirements that could impose more stringent permitting, disclosure, and well construction requirements on hydraulic fracturing activities. In Ohio, the Department of Natural Resources finalized new horizontal well site construction requirements in 2015.  In 2016, the Pennsylvania Department of Environmental Protection updated its performance standards for surface activities at oil and gas well sites.  Local governments may also seek to adopt ordinances within their jurisdictions regulating the time, place and manner of drilling activities in general or hydraulic fracturing activities in particular. We believe that we follow applicable standard industry practices and legal requirements for groundwater protection in our hydraulic fracturing activities. Nonetheless regulations can be expected to become stricter in the future, and, if new or more stringent federal, state, or local legal restrictions relating to the hydraulic fracturing process are adopted in areas where we operate, we could incur potentially significant added costs to comply with such requirements, experience delays or curtailment in the pursuit of exploration, development, or production activities, and perhaps even be precluded from drilling wells.

Hazardous Substances and Wastes

CERCLA, also known as the “Superfund law,” imposes cleanup obligations, without regard to fault or the legality of the original conduct, on certain classes of persons that are considered to be responsible for the release of a “hazardous substance” into the environment. These persons include the owner or operator of the disposal site or sites where the release occurred and companies that transported, disposed, or arranged for the transport or disposal of the hazardous substances found at the site. Persons who are or were responsible for releases of hazardous substances under CERCLA and any state analogs may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment and for damages to natural resources, and it is not uncommon for neighboring landowners and other third parties to file corresponding common law claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. While petroleum and crude oil fractions are not considered hazardous substances under CERCLA because of the so-called “petroleum exclusion,” adulterated petroleum products containing other hazardous substances have been treated as hazardous substances in the past.

The RCRA regulates the generation and disposal of solid wastes and hazardous wastes. The RCRA specifically excludes from the definition of hazardous waste “drilling fluids, produced waters and other wastes associated with the exploration, development or production of crude oil, natural gas or geothermal energy.”  These materials are currently regulated as non-hazardous solid wastes.  However, legislation has been proposed from time to time that could reclassify certain natural gas and oil exploration and production wastes as “hazardous wastes,” which would make the reclassified wastes subject to much more stringent handling, disposal and clean-up requirements. In addition, the EPA has from time to time been petitioned to reclassify oil and gas wastes as hazardous.  If such legislation were to be enacted, or the regulatory exemption rescinded, it could have a significant impact on our operating costs, as well as the natural gas and oil industry in general. Moreover, some ordinary industrial wastes that we generate, such as paint wastes, waste solvents, laboratory wastes and waste oils, may be regulated as hazardous wastes.

In addition, current and future regulations governing the handling and disposal of Naturally Occurring Radioactive Materials, or NORM, may affect our operations. For example, the Ohio Department of Natural Resources has asked operators to identify technologically enhanced NORM, or TENORM, in their processes, such as hydraulic fracturing sand, recycled drilling mud, and spent tank bottoms. Local landfills only accept such waste when it meets their TENORM standards. As a result, we may have to locate out-of-state landfills to accept TENORM waste from time to time, potentially increasing our disposal costs.

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Some of our leases may have had prior owners who commenced exploration and production of natural gas and oil operations on these sites. Although we have utilized operating and disposal practices that were standard in the industry at the time, hydrocarbons or other wastes may have been disposed of or released on or under the properties owned or leased by us on or under other locations where such wastes have been taken for disposal. In addition, a portion of these properties may have been operated by third parties whose treatment and disposal or release of wastes was not under our control. These properties and the wastes disposed thereon may be subject to CERCLA, the RCRA, and/or analogous state laws. Under such laws, we could be required to remove or remediate previously disposed wastes (including waste disposed of or released by prior owners or operators) or property contamination (including groundwater contamination by prior owners or operators), or to perform remedial plugging or closure operations to prevent future contamination.

Waste Discharges

The CWA and its state analog impose restrictions and strict controls with respect to the discharge of pollutants, including spills and leaks of oil and other substances, into waters of the United States. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or an analogous state agency. The CWA 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. Spill prevention, control and countermeasure requirements of federal laws require appropriate containment berms and similar structures to help prevent the contamination of navigable waters by a petroleum hydrocarbon tank spill, rupture or leak. In addition, the CWA and analogous state laws require individual permits or coverage under general permits for discharges of storm water runoff from certain types of facilities. Federal and state regulatory agencies can impose administrative, civil and criminal penalties as well as other enforcement mechanisms for non-compliance with discharge permits or other requirements of the CWA and analogous state laws and regulations.

Air Emissions

The CAA and its state analog and regulations restrict the emission of air pollutants from many sources, including oil and gas operations. New facilities may be required to obtain permits before construction can begin, and existing facilities may be required to obtain additional permits and incur capital costs in order to remain in compliance. The EPA has also established air emission controls for oil and natural gas production and natural gas processing operations. These rules address emissions of various pollutants frequently associated with oil and natural gas production and processing activities by, among other things, requiring new or reworked hydraulically-fractured wells to control emissions through reduced emission (or “green”) completions, or flaring where green completions are not feasible. The rules also established specific requirements for emissions from compressors, controllers, dehydrators, storage tanks, gas-processing plants, and certain other equipment. The EPA is continuing to consider other aspects of its oil and gas air emissions rules and may propose additional amendments. In addition, the U.S. Department of Interior finalized rules to reduce venting and flaring from oil and natural gas operations located on federal lands.  In September of 2018, the Department of the Interior decreased the stringency of the venting and flaring rules; however, the replacement rule is under legal challenge and could be reinstated.  If reinstated, the original rule may require a number of modifications to our own operations, including the installation of new equipment to control emissions. Compliance with such rules could result in additional costs for us and our customers, including increased capital expenditures and operating costs, which may adversely impact our cash flows and results of operations.

Oil Pollution Act

The Oil Pollution Act of 1990, or the OPA, and regulations thereunder impose a variety of requirements on “responsible parties” related to the prevention of oil spills and liability for damages resulting from such spills in United States waters. A “responsible party” includes the owner or operator of an onshore facility, pipeline or vessel, or the lessee or permittee of the area in which an offshore facility is located. The OPA assigns liability to each responsible party for oil cleanup costs and a variety of public and private damages. While liability limits apply in some circumstances, a party cannot take advantage of liability limits if the spill was caused by gross negligence or willful misconduct or resulted from violation of a federal safety, construction or operating regulation. If the party fails to report a spill or to cooperate fully in the cleanup, liability limits likewise do not apply. Few defenses exist to the liability imposed by the OPA. The OPA imposes ongoing requirements on a responsible party, including the preparation of oil spill response plans and proof of financial responsibility to cover environmental cleanup and restoration costs that could be incurred in connection with an oil spill.

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National Environmental Policy Act

Oil and natural gas exploration and production activities on federal lands are subject to the National Environmental Policy Act, or the NEPA. The NEPA requires federal agencies, including the Department of Interior, to evaluate major agency actions having the potential to significantly impact the environment. The process involves the preparation of either an environmental assessment or environmental impact statement depending on whether the specific circumstances surrounding the proposed federal action will have a significant impact on the human environment. The NEPA process involves public input through comments, which can alter the nature of a proposed project either by limiting the scope of the project or requiring resource-specific mitigation. The NEPA decisions can be appealed through the court system by process participants. This process may result in delaying the permitting and development of projects, increase the costs of permitting and developing some facilities and could result in certain instances in the cancellation of existing leases.

Endangered Species Act and Migratory Bird Treaty Act

The Endangered Species Act, or the ESA, and similar applicable state legislation restrict activities that may affect endangered or threatened species or their habitats. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act. For example, regulations designed to protect the Indiana bat (Myotis soldalis), which is an endangered species protected by the ESA and similar state legislation, restrict or increase the cost of our operations by, among other things, limiting our ability to clear trees to establish rights of way or pad locations on some of our acreage during certain periods of the year. While some of our operations may be located in areas that are designated as habitats for endangered or threatened species or that may attract migratory birds we believe that we are in substantial compliance with the ESA, similar applicable state legislation and the Migratory Bird Treaty Act, and we are not aware of any proposed ESA listings that will materially affect our operations. However, the designation of previously unidentified endangered or threatened species, including as a result of petitions submitted to the United States Fish and Wildlife Service from time to time by environmental groups, could cause us to incur additional costs or become subject to operating restrictions or bans in the affected states.

Worker Safety

The Occupational Safety and Health Act, or the OSHA, and any analogous state law regulate the protection of the safety and health of workers. The OSHA hazard communication standard requires maintenance of information about hazardous materials used or produced in operations and provision of such information to employees. Other OSHA standards regulate specific worker safety aspects of our operations. Failure to comply with OSHA requirements can lead to the imposition of penalties.

Employees

As of December 31, 2019, we had 236 full-time employees. Our future success will depend partially on our ability to attract, retain and motivate qualified personnel. We are not a party to any collective bargaining agreements and have not experienced any strikes or work stoppages. We utilize the services of independent contractors to perform various field and other services.

Corporate Information

Our principal executive offices are located at 122 West John Carpenter Freeway, Suite 300, Irving, Texas 75039, and our telephone number is (469) 444-1647. Our website is www.montageresources.com. We expect 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, the SEC. The SEC maintains an Internet site that contains reports, proxy and information statements, and other information regarding issuers that file electronically with the SEC at www.sec.gov.  The information on, or otherwise accessible through, our website or any other website does not constitute a part of this Annual Report.

 

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Item 1A.

RISK FACTORS

Our business involves a high degree of risk. If any of the following risks, or any risk described elsewhere in this Annual Report, actually occur, our business, financial condition or results of operations could suffer. Additional risks not presently known to us or which we currently consider immaterial also may adversely affect our company.

Risks Related to Our Business

Natural gas, NGLs and oil prices have been volatile and have declined from recent historical highs. If commodity prices remain depressed for a lengthy period of time or experience a further substantial or extended decline, our business, financial condition or results of operations and our ability to meet our capital expenditure obligations and financial commitments may be adversely affected.

The prices we receive for our natural gas, NGLs and oil production heavily influence our revenue, operating results, profitability, access to capital, future rate of growth and carrying value of our properties. Natural gas, NGLs and oil are commodities, and therefore, their prices are subject to wide fluctuations in response to relatively minor changes in supply and demand. Historically, the commodities markets have been volatile, and these markets will likely continue to be volatile in the future. The prices we receive for our production, and the levels of our production, depend on numerous factors beyond our control. These factors include, but are not limited to, the following:

 

•

worldwide and regional economic conditions impacting the global supply of and demand for natural gas, NGLs and oil;

 

•

the price and quantity of imports of foreign natural gas, including liquefied natural gas, foreign oil and refined products;

 

•

the price and quantity of exported domestic crude oil, natural gas, including liquefied natural gas, NGLs and refined products;

 

•

political conditions in or affecting other producing countries, including conflicts in the Middle East, Africa, South America and Russia;

 

•

the level of global exploration and production;

 

•

the level of global inventories;

 

•

changes in the level of consumer and industrial demand, including impacts from global or national health epidemics and concerns, such as the recent coronavirus (COVID-19);

 

•

prevailing prices on local price indexes in the areas in which we operate and expectations about future commodity prices;

 

•

the actions of the Organization of the Petroleum Exporting Countries;

 

•

the proximity, capacity, cost and availability of gathering and transportation facilities, and other factors that result in differentials to benchmark prices;

 

•

the cost of exploring for, developing, producing and transporting reserves;

 

•

speculative trading in natural gas and crude oil derivative contracts;

 

•

risks associated with operating drilling rigs;

 

•

increased end-user conservation or conversion of alternative fuels;

 

•

the price and availability of competitors’ supplies of natural gas, NGLs, oil and alternative fuels;

 

•

localized and global supply and demand fundamentals and transportation availability;

 

•

adverse or severe weather conditions and other natural disasters;

 

•

technological advances affecting energy consumption and production; and

23

 

•

domestic, local and foreign governmental regulation and taxes.

In addition, substantially all of our natural gas production and oil production is sold to purchasers under contracts with market-based prices based on NYMEX Henry Hub prices and WTI prices, respectively. The actual prices realized from the sale of natural gas and oil differ from the quoted NYMEX Henry Hub and WTI prices as a result of location differentials. Location differentials to NYMEX Henry Hub and WTI prices, also known as basis differential, result from variances in regional natural gas and oil prices as compared to NYMEX Henry Hub and WTI prices due to regional supply and demand factors. We have experienced, and expect to continue to experience, differentials to NYMEX Henry Hub and WTI prices, which may be material and could reduce the price we receive for these products relative to these benchmarks.

Lower commodity prices and negative increases in our differentials have reduced, and we expect will continue to reduce our cash flows and borrowing ability. We may be unable to obtain needed capital or financing on satisfactory terms, or at all, which could lead to a decline in our reserves as existing reserves are depleted.  Lower commodity prices and negative differentials have also caused a significant portion of our development and exploration projects to become uneconomic, which may result in our having to make significant downward adjustments to our reserves.  As a result, if commodity prices continue to remain depressed for a lengthy period of time or experience a further substantial or extended decline, or if our negative differentials increase, our future business, financial condition, results of operations, liquidity or ability to finance planned capital expenditures may be materially adversely affected.

Commodity prices have declined substantially from historic highs and may remain depressed for the foreseeable future. If commodity prices continue to remain depressed, we may be required to write down the value of our oil and natural gas properties, some of our undeveloped locations may no longer be economically viable and the value of our estimated proved reserves could be reduced materially.

During the eight years prior to December 31, 2019, natural gas prices at Henry Hub have ranged from a high of $8.15 per MMBtu in 2014 to a low of $1.49 per MMBtu in 2016. On December 31, 2019, the Henry Hub spot market price of natural gas was $2.09 per MMBtu. The reduction in prices has been caused by many factors, including increases in natural gas production and reserves from unconventional (shale) reservoirs, without an offsetting increase in demand. In addition, oil prices have declined significantly since the second half of 2014. The price of WTI crude oil was $61.14 per barrel on December 31, 2019, which is a significant decline from $106.07 per barrel on June 30, 2014. This environment could cause the commodity prices for oil and natural gas to remain at currently depressed levels or to fall to lower levels. If commodity prices remain depressed for lengthy periods, we may be required to write down the value of our oil and natural gas properties, and some of our undeveloped locations may no longer be economically viable.  For example, for the year ended December 31, 2019, we recorded an impairment charge on certain oil and gas properties of $45.8 million for unproved properties, primarily attributable to lower commodity prices, and we have recorded impairment charges in prior years for similar reasons. In addition, sustained low commodity prices will negatively impact the value of our estimated proved reserves, which will negatively affect the borrowing base under our revolving credit facility and reduce the amounts of cash we would otherwise have available to pay expenses and service any indebtedness that we may incur. In such a case, we may be required to sell assets or raise capital by issuing additional debt or equity in order to pay expenses and service indebtedness. Furthermore, the value of our assets, if sold, may not be sufficient to pay our expenses or service our indebtedness.

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. For example, for the year ended December 31, 2019, we recorded an impairment charge on certain oil and gas properties of $45.8 million for unproved properties, primarily attributable to lower commodity prices, and we have recorded impairment charges in prior years for similar reasons. 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 further write down the carrying value of our properties. A write-down constitutes a non-cash charge to earnings. We may incur additional impairment charges in

24

the future, which could have a material adverse effect on our results of operations for the periods in which such charges are taken.

If commodity prices do not improve or worsen or if we are unable to increase our liquidity, we could experience ratings downgrades.

If commodity prices do not improve or worsen or if we are unable to increase our liquidity, we could experience ratings downgrades. For example, in January 2016, Moody’s downgraded our corporate family credit rating and the rating of our 8.875% senior unsecured notes due 2023 primarily due to the effect of high leverage, low natural gas prices and significant production curtailments on our ability to generate cash flow from operations. These ratings were subsequently upgraded by Moody’s in July 2017 and March 2019. In the event of any future downgrade, certain of our service providers, including our pipeline providers, could attempt to require us to post collateral or provide other assurances of our ability to perform our obligations under our contracts with such providers, which would negatively affect our liquidity and the borrowing base under our revolving credit facility and, in turn, increase the risk of additional downgrades.

Our development and exploration projects require substantial capital expenditures. We may be unable to obtain required capital or financing on satisfactory terms, or at all, which could lead to a decline in our oil and natural gas reserves.

The oil and natural gas industry is capital intensive. We have made, and if commodity prices rebound, expect to continue to make, substantial capital expenditures for the development and acquisition of oil and natural gas reserves. We expect to fund our capital expenditures in 2020 and subsequent to 2020 with cash on hand, cash generated by our operations and financing activities, which may include borrowings under our revolving credit facility, proceeds from non-core asset sales, and issuances of debt or equity. If we do not have sufficient borrowing availability under our revolving credit facility due to the current commodity price environment or otherwise, we may seek alternate debt or equity financing options (including, subject to compliance with our debt agreements, the issuance of first lien notes or other priority lien obligations), to sell assets or to further reduce our capital expenditures. The actual amount and timing of our future capital expenditures may differ materially from our estimates as a result of, among other things, natural gas, NGLs and oil prices and differentials, actual drilling results, the availability of drilling rigs and other services and equipment, and regulatory, technological and competitive developments. A reduction in realized natural gas, NGLs or oil prices from current levels may result in a decrease in our actual capital expenditures, which would negatively impact our ability to grow production. Our financing needs may require us to alter or increase our capitalization substantially through the issuance of debt or equity securities or the sale of assets. The issuance of additional indebtedness would require that a portion of our cash flows from operations be used for the payment of interest and principal on our indebtedness, thereby reducing our ability to use cash flows from operations to fund working capital, capital expenditures and acquisitions.

Our cash flows from operations and access to capital are subject to a number of variables, including, without limitation, the following:

 

•

our proved reserves;

 

•

the volumes and types of hydrocarbons we are able to produce from existing and future wells;

 

•

our access to, and the cost of accessing, end markets for our production;

 

•

the prices at which our production is sold;

 

•

our ability to acquire, locate and develop new reserves;

 

•

the levels of our operating expenses; and

 

•

our ability to borrow under our revolving credit facility and issue additional debt and equity securities.

If our revenues or the borrowing base under our revolving credit facility decrease as a result of lower natural gas, NGLs or oil prices, operating difficulties, declines in reserves or for any other reason, we may have limited ability to obtain the capital necessary to sustain our operations at current levels. If additional capital is needed, we may not be able to obtain debt or equity financing on terms acceptable to us, if at all. If our cash on hand, cash flows

25

generated by our operations and available borrowings under our revolving credit facility are insufficient to meet our capital requirements, the failure to obtain additional financing could result in a further curtailment of our operations relating to development of our properties, which in turn could lead to a decline in our reserves and production, and could adversely affect our business, financial condition and results of operations.

Changes in laws or government regulations regarding hydraulic fracturing could increase our costs of doing business, limit the areas in which we can operate and reduce our oil and natural gas production, which could adversely impact our business.

Hydraulic fracturing is an important and common practice that is used to stimulate production of natural gas and/or oil from dense subsurface rock formations. Hydraulic fracturing involves the injection of water, sand or alternative proppant and additives under pressure into target geological formations to fracture the surrounding rock and stimulate production. We regularly use hydraulic fracturing as part of our operations. Presently, hydraulic fracturing is regulated primarily at the state level, typically by state oil and natural gas commissions and similar agencies. However, with increased public concern regarding the potential for hydraulic fracturing to adversely affect drinking water supplies or other environmental impacts, proposals have been made, and in many cases finalized, to enact federal, state and local legislation and regulations that would increase, or have increased, the regulatory burden imposed on hydraulic fracturing. For example, the U.S. Environmental Protection Agency (the “EPA”) issued regulations to control air emissions from oil and natural gas production and natural gas processing operations, then proposed and finalized additional air emissions regulations from oil and natural gas production and natural gas processing operations, completed a multi-year study examining the potential impacts of hydraulic fracturing on drinking water resources, established standards for wastewater discharges from oil and gas extraction activities and released an Advance Notice of Proposed Rulemaking to solicit public comment on potential chemical disclosure requirements. The U.S. Congress continues to consider amending the Safe Drinking Water Act to remove the exemption for hydraulic fracturing activities and to require disclosure of additives constituents of fluids used in the fracturing process. The Department of the Interior released final rules to regulate hydraulic fracturing activities on federal lands and to limit venting and flaring from production operations.  Although the Department of the Interior hydraulic fracturing rules have been rescinded and the venting and flaring rule has been replaced with a less stringent version, both are the subject of litigation that could result in the prior version of such rules becoming effective and it is possible that amended or similar rules will be proposed and finalized.  In addition, the United States has made commitments to reduce greenhouse gas emissions under the Paris Agreement, part of the United Nations Framework Convention on Climate Change.  The Trump administration has begun the process to formally withdraw from the Paris Agreement, but under the terms of the agreement the U.S. will remain a party until November 4, 2020.

If new federal, state or local laws or regulations that significantly restrict hydraulic fracturing are adopted, such legal requirements could result in delays, eliminate certain drilling and injection activities and make it more difficult or costly for us to perform fracturing. Any such regulations limiting or prohibiting hydraulic fracturing or imposing punitive taxation could reduce our oil and natural gas exploration and production activities and, therefore, adversely affect our business. Such laws or regulations could also materially increase our costs of compliance and doing business by more strictly regulating how hydraulic fracturing wastes are handled or disposed.

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Properties that we decide to drill may not yield natural gas, NGLs or oil in commercially viable quantities.

Properties that we decide to drill that do not yield natural gas, NGLs or oil in commercially viable quantities will adversely affect our results of operations and financial condition. Our project areas are in various stages of development, ranging from project areas with current drilling or production activity to project areas that consist of recently acquired leasehold acreage or that have limited drilling or production history. If the wells in the process of being drilled and completed do not produce sufficient revenues to return a profit or if we drill dry holes in the future, our business may be materially affected. In addition, there is no way to predict in advance of drilling and testing whether any particular prospect will yield natural gas, NGLs or oil in sufficient quantities to recover drilling and completion costs or to be economically viable. The use of micro-seismic data and other technologies and the study of producing fields in the same area will not enable us to know conclusively prior to drilling whether natural gas, NGLs or oil will be present or, if present, whether natural gas, NGLs or oil will be present in commercial quantities. We cannot assure you that the analogies we draw from available data from other wells, more fully explored prospects or producing fields will be applicable to our drilling prospects. Further, our drilling operations may be curtailed, delayed or cancelled as a result of numerous factors, including:

 

•

unexpected drilling conditions;

 

•

title problems;

 

•

pressure or lost circulation in formations;

 

•

equipment failure or accidents;

 

•

adverse weather conditions;

 

•

compliance with environmental and other governmental or contractual requirements; and

 

•

increase in the cost of, shortages or delays in the availability of, electricity, supplies, materials, drilling or workover rigs, equipment and services.

Hydrocarbon windows, phases or type curve areas have an inherent degree of variability and may change over time, and as a result, the available well data with respect to such windows, phases and type curve areas may not be indicative of the actual hydrocarbon composition for the windows, phases or type curve areas.

Based upon the well data available to us, we have grouped the publicly disclosed Utica Shale wells within the Utica Core Area into several distinct hydrocarbon windows, phases or type curve areas in an effort to better understand the thermal maturation variability within the Utica Core Area. However, there is an inherent degree of variability within such hydrocarbon windows, phases or type curve areas. Additionally, the well data we have utilized is predominantly based upon initial production rate, Btu content, natural gas yields and condensate yields, which may change over time. As a result, the well data with respect to the windows, phases and type curve areas within the Utica Core Area may not be indicative of the actual hydrocarbon composition for the windows, phases or type curve areas, or may not be the hydrocarbon composition of the windows, phases or type curve areas at the time we drill. Due to such factors, the performance, Btu content and NGLs and/or condensate yields of our wells may be substantially less than we anticipate or substantially less than performance and yields of other operators in the Utica Core Area, which may materially adversely affect our future business, financial condition, results of operations, liquidity or ability to finance planned capital expenditures.

We have been an early entrant into the Utica Core Area and have also been an early entrant into the portion of the Marcellus Shale underlying our Marcellus Area. As a result, our expected well results in these areas are uncertain, and the value of our undeveloped acreage will decline if well results are unsuccessful.

Our expected well results in the Utica Core Area and our Marcellus Area are more uncertain than well results in areas that are more developed and have a greater number of producing wells. As a result, our cost of drilling, completing and operating wells in the Utica Core Area and our Marcellus Area may be higher than initially expected, the ultimate production and reserves from these wells may be lower than initially expected and the value of our undeveloped acreage may decline. Additionally, we cannot assure you that all prospects will be economically viable or that we will not abandon our investments. We cannot assure you that unproved property acquired by us or

27

undeveloped acreage leased by us will be profitably developed, that wells drilled by us in prospects that we pursue will be productive or that we will recover all or any portion of our investment in such unproved property or wells.

Part of our strategy involves using some of the latest available horizontal drilling and completion techniques, which involve risks and uncertainties in their application.

Our operations involve utilizing some of the latest drilling and completion techniques as developed by us, other oil and gas exploration and production companies and our service providers. Risks that we face while drilling include, but are not limited to, the following:

 

•

drilling wells that are significantly longer and/or deeper than more conventional wells;

 

•

landing our wellbore in the desired drilling zone;

 

•

staying in the desired drilling zone while drilling horizontally through the formation;

 

•

running our casing the entire length of the wellbore; and

 

•

being able to run tools and other equipment consistently through the horizontal wellbore.

Risks that we face while completing our wells include, but are not limited to, the following:

 

•

the ability to fracture stimulate the planned number of stages;

 

•

the ability to run tools the entire length of the wellbore during completion operations; and

 

•

the ability to successfully clean out the wellbore after completion of the final fracture stimulation stage.

Drilling for and producing natural gas, NGLs and oil are high-risk activities with many uncertainties that could result in a total loss of investment or otherwise adversely affect our business, financial condition and results of operations.

Our future financial condition and results of operations will depend on the success of our development and acquisition activities, which are subject to numerous risks beyond our control, including the risk that drilling will not result in commercially viable production or that we will not recover all or any portion of our investment in such wells.

Our decisions to purchase, explore or develop prospects or properties will depend in part on the evaluation of data obtained through geophysical and geological analyses, production data and engineering studies, the results of which are often inconclusive or subject to varying interpretations. For a discussion of the uncertainty involved in these processes, see “Items 1 and 2. Business and Properties—Oil and Natural Gas Data.” Reserve estimates depend on many assumptions that may turn out to be inaccurate. Any material inaccuracies in reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves, which could materially reduce our borrowing capacity. In addition, our cost of drilling, completing and operating wells is often uncertain before drilling commences.

Further, many factors may curtail, delay or cancel our scheduled drilling projects, including, without limitation, the following:

 

•

compliance with regulatory requirements, including limitations resulting from wastewater disposal, discharge of greenhouse gases, and limitations on hydraulic fracturing;

 

•

pressure or irregularities in geological formations;

 

•

shortages of or delays in obtaining equipment and qualified personnel or in obtaining water for hydraulic fracturing activities;

 

•

equipment failures, accidents or other unexpected operational events;

 

•

lack of available gathering and processing facilities or delays in construction of gathering and processing facilities;

28

 

•

lack of available capacity on interconnecting transmission pipelines;

 

•

adverse weather conditions, such as blizzards and ice storms;

 

•

issues related to compliance with environmental regulations;

 

•

environmental hazards, such as natural gas leaks, oil spills, pipeline and tank ruptures, encountering naturally occurring radioactive materials, and unauthorized discharges of brine, well stimulation and completion fluids, toxic gases or other pollutants into the surface and subsurface environment;

 

•

terrorist (including eco-terrorist) attacks targeting natural gas and oil related facilities and infrastructure;

 

•

declines in natural gas, NGLs and oil prices;

 

•

limited availability of financing at acceptable terms;

 

•

title problems and well permit objections from coal operators; and

 

•

limitations in the market for natural gas.

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.

We have incurred losses from operations in a significant number of years since our inception and may do so in the future.

Although we generated net income of $31.8 million, $18.8 million, and $8.5 million for the years ended December 31, 2019, 2018, and 2017, respectively, we incurred a net loss in each of the prior years since our inception. Our development of and participation in prospects has required, and if commodity prices rebound will require, substantial capital expenditures. The uncertainty and factors described throughout this “Risk Factors” section may impede our ability to economically find, develop and acquire oil and natural gas reserves. As a result, we may not be able to achieve or sustain profitability or positive cash flows from operating activities in the future, which could adversely affect the trading price of our common stock and our ability to fund our operations and fulfill our debt obligations.

We may not be able to generate sufficient cash to service all of our indebtedness, including our senior unsecured notes, and may be forced to take other actions to satisfy our obligations under our indebtedness, which may not be successful.

Our ability to make scheduled payments on or to refinance our indebtedness obligations, including our revolving credit facility and our senior unsecured notes, depends on our financial condition and operating performance, which are subject to prevailing economic and competitive conditions and financial, business and other factors beyond our control. We may not be able to maintain a level of cash flows from operating activities sufficient to permit us to pay the principal of, or premium, if any, and interest on, our indebtedness when due.

If our cash flows and capital resources are insufficient to fund our debt service obligations, we may be forced to reduce or delay investments and capital expenditures, sell assets, raise additional capital or restructure or refinance our indebtedness. Our ability to raise additional capital or restructure or refinance our indebtedness will depend on the condition of the credit, financial or other capital markets and our financial condition at such time. Any refinancing of our indebtedness could be at higher interest rates and may require us to comply with covenants that could further restrict our business operations. The terms of existing or future debt instruments may restrict us from adopting some of these alternatives. In addition, any failure to make payments of interest and principal on our outstanding indebtedness on a timely basis would likely result in a reduction of our credit rating, which could harm our ability to incur additional indebtedness.

In the absence of sufficient cash flows and capital resources, we could face substantial liquidity problems and might be required to dispose of material assets or operations to meet our debt service and other obligations. The value of our assets, particularly in times of low or volatile commodity prices, may not be sufficient to satisfy our

29

liquidity needs or to repay our indebtedness. Furthermore, the credit agreement governing our revolving credit facility, which we refer to as the Credit Agreement, and the indenture governing our senior unsecured notes restrict our subsidiaries’ ability to dispose of assets and our subsidiaries’ use of the proceeds from any such disposition. We may not be able to consummate those dispositions, and the proceeds of any such disposition may not be adequate to meet any debt service obligations then due. These alternative measures may not be successful and may not permit us to meet our scheduled debt service obligations and fund our operations.

As of December 31, 2019, we had approximately $640.5 million in total indebtedness, excluding discount, and approximately $340.8 million of available borrowing capacity under our revolving credit facility (after giving effect to approximately $29.2 million of outstanding letters of credit and $130.0 million of outstanding borrowings).

In the future, we may not be able to access adequate funding under our revolving credit facility as a result of a decrease in borrowing base due to the issuance of new indebtedness, the outcome of a subsequent borrowing base redetermination, unwillingness of the lenders to increase their aggregate commitment up to an increased borrowing base amount or an unwillingness or inability on the part of one or more lenders to meet their funding obligations and the inability of other lenders to provide additional funding to cover each unwilling or defaulting lender’s portion. Declines in commodity prices could result in a determination to lower the borrowing base in the future, and in such a case, we could be required to repay any indebtedness in excess of the redetermined borrowing base. As a result, we may be unable to implement our drilling and development plan, make acquisitions or otherwise carry out our business plans, which would have a material adverse effect on our financial condition and results of operations and impair our ability to service our indebtedness.

Our producing properties are primarily concentrated in the Appalachian Basin, which makes us vulnerable to risks associated with operating in one major geographic area.

Our producing properties are primarily geographically concentrated in the Appalachian Basin. At December 31, 2019, all of our total estimated proved reserves were attributable to properties located in this area. As a result of this concentration, we may be disproportionately exposed to the impact of regional supply and demand factors, delays or interruptions of production from wells in this area caused by governmental regulation, processing or transportation capacity constraints, market limitations, water shortages, weather related conditions or interruption of the processing or transportation of natural gas, NGLs or oil. Such delays or interruptions could have a material adverse effect on our financial condition and results of operations. In addition, a number of areas within the Appalachian Basin have historically been subject to mining operations, the existence of which could require coordination to avoid adverse impacts as a result of drilling and mining in close proximity. These restrictions on our operations, and any similar restrictions, can cause delays or interruptions or can prevent us from executing our business strategy, which could have a material adverse effect on our financial condition and results of operations.

Due to the concentrated nature of our portfolio of natural gas and oil properties, a number of our properties could experience any of the same conditions at the same time, resulting in a relatively greater impact on our results of operations than they might have on other companies that have a more diversified portfolio of properties.

We own non-operating interests in properties developed and operated by third parties, and as a result, we are unable to control the operation and profitability of such properties.

We frequently participate as a non-operator in the drilling and completion of wells with third parties that exercise exclusive control over such operations. As a non-operator participant, we rely on the third-party operating company to successfully operate these properties pursuant to joint operating agreements and other similar contractual arrangements.

As a non-operator participant in these operations, we may not be able to maximize the value associated with these properties in the manner we believe appropriate, or at all. For example, we cannot control the success of drilling and development activities on properties operated by third parties, which depend on a number of factors under the control of a third party operator, including such operator’s determinations with respect to, among other things, the nature and timing of drilling and operational activities, the timing and amount of capital expenditures and the selection of suitable technology. In addition, the third-party operator’s operational expertise and financial resources and ability to gain the approval of other participants in drilling wells will impact the timing and potential

30

success of our drilling and development activities in a manner that we are unable to control. The failure of an operator of our wells to adequately perform operations, an operator’s breach of the applicable agreements or an operator’s failure to act in ways that are favorable to us could reduce our production and revenues, negatively impact our liquidity and cause us to spend capital in excess of our current plans, and have a material adverse effect on our financial condition and results of operations.

Our existing providers of gas gathering, processing and fractionation capacity may not be able to provide to us sufficient capacity for our production from the Utica Core Area, and as a result, we may be required to find alternative markets and gathering, processing or fractionation arrangements for our production from the Utica Core Area, which alternative arrangements may not be available on favorable terms, or at all.

A significant portion of our Utica Core Area acreage position is dedicated to long-term firm gas gathering, processing and fractionation agreements with primary terms of approximately 14 years. These agreements give us priority service and capacity over non-firm parties that wish to utilize the gas processing and fractionation plants and gas gathering system. As a result of such dedications, a significant portion of our operated wet gas acreage is committed to Blue Racer for gathering, processing and fractionation. Additionally, a significant portion of our operated dry gas acreage is committed to Eureka Midstream for gathering and a significant portion of our operated wet gas acreage is committed to EnLink Midstream for condensate gathering and stabilization. While we believe we have reserved sufficient capacity at these plants and on such systems to gather, process, fractionate and stabilize all of our projected production associated with our proved resources and a significant portion of our projected production from the Utica Core Area, that capacity may not be sufficient to handle all of our production or the plants and systems may experience significant mechanical problems or delays in construction or become unavailable to us due to unforeseen circumstances. As a result, we may be required to find alternative markets and gathering, processing or fractionation arrangements for our production from the Utica Core Area that is committed under these agreements, and such alternative arrangements may only be available on less favorable terms, or not at all.

We currently do not have long-term gathering agreements with providers with respect to a portion of our undeveloped acreage from our Marcellus Area, and we may not be able to enter into such agreements on favorable terms, or at all.

We have not entered into any gas gathering agreements with respect to our undeveloped acreage from a portion of our Marcellus Area. We may not be able to enter into any such agreements on favorable terms, or at all. Without such agreements, we may not receive priority service or capacity over third parties that utilize the same gas gathering systems. Our inability to obtain sufficient gas gathering for our production from a portion of our Marcellus Area could negatively impact our cash flows, financial condition and results of operations and reduce the overall value of our assets within this area.

Insufficient processing or takeaway capacity in the Appalachian Basin could cause significant fluctuations in our realized natural gas, NGLs and oil prices.

The Appalachian Basin natural gas business environment has historically been characterized by periods in which production has surpassed local processing and takeaway capacity, resulting in substantial discounts in the price received by producers such as us. A significant portion of our production from the Utica Core Area is currently being transported on pipelines that, after including the cost of such transportation, will consistently or periodically experience a negative differential to NYMEX Henry Hub prices.

Significant portions of our contracted firm transportation capacity have not been put into service. To the extent such projects are delayed or cancelled, and we are unable to secure additional long-term firm takeaway capacity on major pipelines that are in existence or currently under construction in our core operating area to accommodate our production and to manage basis differentials, it could have a material adverse effect on our financial condition and results of operations.

Oil and condensate produced in the Appalachian Basin has increased substantially. There is limited takeaway capacity for these products and our sales of these products are currently occurring, and we expect will continue to occur, at a discount to the benchmark WTI price. If our providers are unable to secure buyers for these products, it could have a material adverse effect on our financial condition and results of operations.

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We currently are and, in the future, expect to be party to contracts with third parties that include contractual minimums.

We are currently party to and expect to continue to be party to service contracts with drilling rig companies that require us to make shortfall payments to such companies if our actual activity level falls below specified contractual minimum activity levels. Moreover, we have entered into service contracts, and in the future may enter into additional service contracts, such as firm pipeline transportation contracts with companies owning interstate pipelines, that require us or may require us to make shortfall payments if our actual throughput falls below specified contractual minimum volumes. For the year ended December 31, 2019, we incurred approximately $2.0 million in shortfall payments under such contracts. As such, we can provide no assurance that our activity levels will be sufficient to satisfy the minimum requirements under our drilling rig contracts or that our future volumes will be sufficient to satisfy the minimum requirements under any such firm transportation contracts. If we fail to satisfy the minimum activity levels or throughput requirements associated with such contracts, we would be obligated to make shortfall payments to our counterparties based on the difference between our actual activity levels and throughput volumes, respectively, and the contract minimums in each case. These differences and the associated shortfall payments could be significant, and we may not be able to generate sufficient cash to cover those obligations, which may require us to reduce or delay our planned investments and capital expenditures or seek alternative means of financing.

Restrictions in our existing and future debt agreements could limit our growth and our ability to engage in certain activities.

The Credit Agreement contains a number of significant covenants, including restrictive covenants that restrict our and our subsidiaries’ ability to, among other things:

 

•

incur additional indebtedness;

 

•

sell assets;

 

•

make loans to others;

 

•

make investments;

 

•

enter into mergers;

 

•

hedge future production;

 

•

incur liens;

 

•

change the nature of our business; and

 

•

engage in certain other transactions without the prior consent of the lenders.

The indenture governing our senior unsecured notes contains similar restrictive covenants. In addition, the Credit Agreement requires us to maintain certain financial ratios or to reduce our indebtedness if we are unable to comply with such ratios. These restrictions, together with those in the indenture governing our senior unsecured notes, may 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 imposed on us by the restrictive covenants of the Credit Agreement and the indenture governing our senior unsecured notes.

A breach of any covenant in the Credit Agreement or the indenture governing our senior unsecured notes would result in a default under the applicable agreement after any applicable grace periods. A default, if not waived or cured, could result in acceleration of the indebtedness outstanding under the relevant agreement and in a default with respect to, and an acceleration of, the indebtedness outstanding under other debt agreements. The accelerated indebtedness would become immediately due and payable. If that occurs, we may not be able to make all of the required payments or obtain sufficient capital to refinance such indebtedness. Even if a refinancing were available, it may not be on terms that are acceptable to us. Moreover, an increased interest rate is also payable in connection with a default under the Credit Agreement and certain payment defaults under the indenture governing our senior unsecured notes.

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Any significant reduction in our borrowing base or reduction of lender commitments under our revolving credit facility, as a result of the periodic borrowing base redeterminations or otherwise, may negatively impact our ability to fund our capital expenditure plan.

We may fund a portion of our capital expenditure plan through 2020 with future borrowings under our revolving credit facility.  The Credit Agreement limits the amounts we can borrow under our revolving credit facility from time to time up to a specified maximum borrowing base amount or the aggregate amount of lender commitments, whichever is less. The lenders, in their sole discretion, will determine a borrowing base on a semi-annual basis based upon the loan value assigned to the proved reserves attributable to our oil and gas properties evaluated in our most recent reserve report(s). Our lenders may further request two additional unscheduled borrowing base redeterminations during each calendar year. Any increase in the borrowing base will require the consent of the lenders holding 95.0% (or 100.0% if there are fewer than three lenders at the time of determination) of the outstanding credit amounts, or if none are then outstanding, 95% of the commitments (provided that no lender’s commitment may increase without its consent). Distinct from determinations of a borrowing base, each lender, in its sole discretion, will determine the maximum amount of loans it will commit to make under our revolving credit facility based, in part, on general economic considerations and its prevailing lending policies. Outstanding borrowings in excess of the lesser of the specified maximum borrowing base amount or the prevailing aggregate lender commitment must be repaid. If we fail to repay such excess borrowings on a timely basis, we must provide additional oil and gas properties as collateral to the extent necessary to eliminate the deficiency. As of December 31, 2019, the borrowing base under our revolving credit facility was $500 million with $130.0 million in outstanding borrowings under our revolving credit facility, resulting in borrowing availability of approximately $340.8 million (after giving effect to approximately $29.2 million of outstanding letters of credit).

We may be unable to make attractive acquisitions or successfully integrate acquired businesses, and any inability to do so may disrupt our business and hinder our ability to grow.

We have made asset and business acquisitions in the past, including, most recently, the BRMR Merger, and we may continue to make acquisitions of assets or businesses in the future that complement or expand our current business. We may not be able to identify attractive acquisition opportunities. Even if we do identify attractive acquisition opportunities, we may not be able to complete the acquisition or do so on commercially acceptable terms. Further, the success of any completed acquisition, including the BRMR Merger, depends on our ability to integrate the acquired business effectively into our existing operations and such integration process may involve difficulties that require a disproportionate amount of our managerial and financial resources to resolve. We may also fail to realize the expected benefits of any completed acquisitions and completed acquisitions may subject us to significant transaction costs, unknown liabilities, and/or other unanticipated expenses, such as litigation expenses.

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 additional suitable acquisition opportunities, negotiate acceptable terms, obtain financing for acquisitions on acceptable terms or successfully acquire identified targets. Our failure to achieve consolidation savings, to integrate successfully the acquired businesses and assets into our existing operations or to minimize any unforeseen liabilities or operational difficulties could have a material adverse effect on our financial condition and results of operations.

In addition, the Credit Agreement and the indenture governing our senior unsecured notes impose certain limitations on our ability to enter into mergers or combination transactions and to make investments. The Credit Agreement and the indenture governing our senior unsecured notes also limit our ability to incur certain indebtedness and liens, which could limit our ability to engage in acquisitions of businesses.

We may be subject to risks in connection with acquisitions of properties.

We have historically acquired assets and businesses that we feel complement our assets and business and may continue to do so in the future. The successful acquisition of producing properties requires an assessment of several factors, including:

 

•

recoverable reserves;

 

•

future natural gas, NGLs or oil prices and their applicable differentials;

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operating costs; and

 

•

potential environmental and other liabilities.

The accuracy of these assessments is inherently uncertain. In connection with these assessments, we perform a review of the subject properties that we believe to be generally consistent with industry practices. Our review will not reveal all existing or potential problems, nor will it permit us to become sufficiently familiar with the properties to fully assess their deficiencies and capabilities. Inspections may not always be 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. We often are not entitled to contractual indemnification for environmental liabilities and acquire properties on an “as is” basis.

Reserve estimates depend on many assumptions that may turn out to be inaccurate. Any material inaccuracies in reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.

The process of estimating oil and natural gas reserves is complex. It requires interpretations of available technical data and many assumptions, including, without limitation, assumptions relating to current and future economic conditions and commodity prices. Any significant inaccuracies in these interpretations or assumptions could materially affect the estimated quantities and present value of our reserves.

In order to prepare reserve estimates, we must project production rates and timing of development expenditures. We must also analyze available geological, geophysical, production and engineering data. The extent, quality and reliability of this data can vary. The process also requires economic assumptions about matters such as oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds.

Actual future production, natural gas and oil prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves will vary from our estimates. As a substantial portion of our reserve estimates are made without the benefit of a lengthy production history, any significant variance from the above assumption could materially affect the estimated quantities and present value of our reserves. In addition, we may adjust reserve estimates to reflect production history, results of exploration and development, existing commodity prices and other factors, many of which are beyond our control.

You should not assume that the present value of future net revenues from our reserves is the current market value of our estimated natural gas reserves. We generally base the estimated discounted future net cash flows from reserves on prices and costs on the date of the estimate. Actual future prices and costs may differ materially from those used in the present value estimate.

Reserve estimates for plays, such as the Utica Core Area, Flat Castle and our Marcellus Area, where we predominately operate, that do not have a lengthy production history are less reliable than estimates for fields with lengthy production histories. Less production history may contribute to less accurate estimates of reserves, future production rates and the timing of development expenditures. Estimated reserves may not be correlated to perforated lateral length or completion technique. Furthermore, the lack of operational history for horizontal wells in the Utica Core Area, Flat Castle and our Marcellus Area may also contribute to the inaccuracy of future estimates of reserves and could result in our failing to achieve expected results in these plays. A material and adverse variance of actual production, revenues and expenditures from those underlying reserve estimates or management expectations would have a material adverse effect on our business, financial condition, results of operations and cash flows. Furthermore, given the amount of our total estimated proved reserves in relation to the amount of our outstanding debt obligations, the value of our assets may not be sufficient to satisfy our liquidity needs or to repay our indebtedness.

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Our net identified drilling locations are scheduled out over many years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling. In addition, we may not be able to raise the capital that we expect to be necessary to drill our identified drilling locations.

Our management team has specifically identified and scheduled certain well locations as an estimation of our future multi-year drilling activities on our existing acreage. These well locations represent a significant part of our growth strategy. Our ability to drill and develop these locations depends on a number of uncertainties, including natural gas, NGLs and oil prices, the availability and cost of capital, drilling and production costs, availability of drilling services and equipment, drilling results, topographical constraints, lease expirations, the ability to form units, gathering system and pipeline transportation constraints, access to and availability of water sourcing and distribution systems, governmental regulation, the ability to pool or unitize our acreage with acreage leased to other operators and approvals and other factors. Because of these uncertain factors, we do not know if the numerous drilling locations we have identified will ever be drilled or if we will be able to produce natural gas or oil from these or any other identified drilling locations. In addition, unless production is established within the spacing units covering the undeveloped acres on which some of the potential locations are obtained, the leases for such acreage will expire. Further, some of the horizontal wells we intend to drill in the future may require unitization with adjacent leaseholds controlled by third parties. If these third parties are unwilling to unitize such leaseholds with ours, this may limit the total locations we can drill. As such, our actual drilling activities may materially differ from those presently identified.

As of December 31, 2019, after deducting wells that have been drilled or are in progress, we had identified approximately 220.0, 22.0, 133.0, 95.0 and 171.0 net undeveloped Dry Gas, Rich Gas, Condensate, Flat Castle and Marcellus locations, respectively. As a result of the limitations described above, including the recent significant declines in natural gas and oil prices, we may be unable to drill many of our identified drilling locations. In addition, we will require significant additional capital over a prolonged period in order to pursue the development of these locations, and we may not be able to raise or generate the capital required to do so. Any drilling activities we are able to conduct on these potential locations may not be successful or result in our ability to add additional proved reserves to our overall proved reserves or may result in a downward revision of our estimated proved reserves, which could have a material adverse effect on our future business and results of operations. For more information on our identified drilling locations, see “Items 1 and 2. Business and Properties—Our Properties.”

We have acreage that we must commence operations upon before lease expiration in order to hold the acreage by production. If we fail to drill sufficient wells to hold acreage, we incur substantial lease renewal costs, or if renewal is not feasible, lose our lease and prospective drilling opportunities.

Leases on our oil and natural gas properties typically have a primary term of 5 years, after which they expire unless, prior to expiration, we commence operations within the spacing units covering the undeveloped acres. As of December 31, 2019, we had leases representing approximately 29,149 gross (23,806 net) undeveloped acres scheduled to expire in 2020, 18,764 gross (12,449 net) undeveloped acres scheduled to expire in 2021, 11,001 gross (4,899 net) undeveloped acres scheduled to expire in 2022, 7,611 gross (4,233 net) undeveloped acres scheduled to expire in 2023, and 18,867 gross (13,650 net) undeveloped acres scheduled to expire in 2024 and beyond. The cost to renew such leases may increase significantly, and we may not be able to renew such leases on commercially reasonable terms, or at all. Moreover, many of our leases require lessor consent to create units larger than the leases currently permit, which may make it more difficult to hold our leases by production or optimally develop our leasehold position. Although we seek to actively manage our undeveloped properties, our drilling plans for these areas are subject to change based upon various factors, including drilling results, natural gas, NGLs and oil prices, the availability and cost of capital, drilling and production costs, the availability of drilling services and equipment, gathering systems and pipeline transportation constraints and regulatory approvals. In order to hold our current leases that are scheduled to expire in 2020 and 2021, we have deployed a strategy to convert our land extension payments into multi-year delay rental payments, which is designed to spread the costs beyond a single year. We cannot assure you that we will have the liquidity to execute on this strategy, that landowners will be willing to enter into this type of lease modification or that we will have the liquidity to otherwise deploy rigs when needed to hold this expiring acreage. Our reserves and future production, and therefore, our future cash flows and income, are highly dependent on successfully extending or developing our undeveloped leasehold acreage and the loss of any leases could materially adversely affect our ability to so develop such acreage.

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The standardized measure of discounted future net cash flows from our proved reserves will not be the same as the current market value of our estimated oil and natural gas reserves.

You should not assume that the standardized measure of discounted future net cash flows from our proved reserves is the current market value of our estimated oil and natural gas reserves. In accordance with SEC requirements in effect at December 31, 2019, 2018, and 2017, we based the discounted future net cash flows from our proved reserves on the 12-month first-day-of-the-month oil and natural gas average prices without giving effect to derivative transactions. Actual future net cash flows from our oil and natural gas properties will be affected by factors such as:

 

•

actual prices we receive for natural gas, NGLs and oil;

 

•

actual cost of development and production expenditures;

 

•

the effect of derivative transactions;

 

•

the amount and timing of actual production; and

 

•

changes in governmental regulations or taxation.

The timing of both our production and our incurrence of expenses in connection with the development and production of oil and natural gas properties will affect the timing and amount of actual future net revenues from proved reserves, and thus their actual present value. In addition, the 10% discount factor we use when calculating standardized measure 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. As a corporation, we are treated as a taxable entity for federal income tax purposes, and our income taxes are dependent on our taxable income. Actual future prices and costs may differ materially from those used in the present value estimates included in this Annual Report, which could have a material effect on the value of our reserves.

We may incur losses as a result of title defects in the properties in which we invest.

Leases in the Appalachian Basin are particularly vulnerable to title deficiencies due to the long history of land ownership in the area, resulting in extensive and complex chains of title. In the course of acquiring the rights to develop oil and natural gas, it is standard procedure for us and the lessor to execute a lease agreement with payment subject to title verification. In most cases, we incur the expense of retaining lawyers, title abstractors or landmen to verify the rightful owners of the oil and gas interests prior to payment of such lease bonus to the lessor. There is no certainty, however, that a lessor has valid title to its lease’s oil and gas interests. In those cases, such leases are generally voided, and payment is not remitted to the lessor. As such, title failures may result in fewer net acres to us. Prior to the drilling of an oil or natural gas well, however, it is the normal practice in our industry for the person or company acting as the operator of the well to obtain a preliminary title review to ensure there are no obvious defects in title to the well. Frequently, as a result of such examinations, curative work must be done to correct defects in the marketability of the title, and such curative work entails expense. Our failure to cure any title defects may delay or prevent us from utilizing the associated mineral interest, which may adversely impact our ability in the future to increase production and reserves. Accordingly, 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 could suffer a financial loss or an impairment of our assets.

The development of our estimated proved undeveloped reserves may take longer and may require higher levels of capital expenditures than we currently anticipate. Therefore, our estimated proved undeveloped reserves may not be ultimately developed or produced.

At December 31, 2019, we had 2,729.8 Bcfe of total estimated proved reserves, of which approximately 45% were classified as proved undeveloped. Our approximately 1,235.6 Bcfe of estimated proved undeveloped reserves will require an estimated $920.6 million of development capital over the next 5 years. Development of these undeveloped reserves may take longer and require higher levels of capital expenditures than we currently anticipate. Delays in the development of our reserves, increases in costs to drill and develop such reserves, or decreases in commodity prices will reduce the PV-10 value of our estimated proved undeveloped reserves and future net revenues estimated for such reserves and may result in some projects becoming uneconomic. In addition, delays in the development of reserves could cause us to have to reclassify our proved undeveloped reserves as unproved reserves.

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Unless we replace our reserves with new reserves and develop those reserves, our reserves and production will decline, which would adversely affect our future cash flows and results of operations.

Producing oil and natural gas reservoirs generally are characterized by declining production rates that vary depending upon reservoir characteristics and other factors. Unless we successfully conduct ongoing development and exploration activities or continually acquire properties containing proved reserves, our proved reserves will decline as those reserves are produced. Our future oil and natural gas reserves and production, and therefore our future cash flows and results of operations, are highly dependent on our success in efficiently developing and exploiting our current reserves and economically finding or acquiring additional recoverable reserves. We may not be able to develop, find or acquire sufficient additional reserves to replace our current and future production. If we are unable to replace our current and future production, the value of our reserves will decrease, and our business, financial condition and results of operations would be adversely affected.

Conservation measures and technological advances could reduce demand for natural gas, NGLs and oil.

Fuel conservation measures, alternative fuel requirements, increasing consumer demand for alternatives to natural gas, NGLs and oil, technological advances in fuel economy and energy generation devices could reduce demand for natural gas, NGLs and oil. The impact of the changing demand for natural gas, NGLs and oil services and products may have a material adverse effect on our business, financial condition, results of operations and cash flows.

Our derivative activities could result in financial losses or could reduce our earnings.

To achieve more predictable cash flows and reduce our exposure to adverse fluctuations in the prices of natural gas and oil, we have entered into derivative instrument contracts for a significant portion of our natural gas, NGLs and oil production, including fixed-price swaps, basis swaps, collars and firm sales agreements. Accordingly, our earnings may fluctuate significantly as a result of changes in fair value of our derivative instruments.

Derivative instruments also expose us to the risk of financial loss in some circumstances, including when:

 

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production is less than the volume covered by the derivative instruments;

 

•

the counterparty to the derivative instrument defaults on its contractual obligations;

 

•

there is an increase in the differential between the underlying price in the derivative instrument and actual prices received; or

 

•

there are issues with regard to legal enforceability of such instruments.

The use of derivatives may, in some cases, require the posting of cash collateral with counterparties. If we enter into derivative instruments that require cash collateral and commodity prices or interest rates change in a manner adverse to us, our cash otherwise available for use in our operations would be reduced which could limit our ability to make future capital expenditures and make payments on our indebtedness, and which could also limit the size of our borrowing base. Future collateral requirements will depend on arrangements with our counterparties, highly volatile oil and natural gas prices and interest rates.

Our hedging transactions expose us to risk of financial loss if a counterparty fails to perform under a derivative contract. Disruptions in the financial markets could lead to sudden decreases in a counterparty’s liquidity, which could make them unable to perform under the terms of the derivative contract and we may not be able to realize the benefit of the derivative contract. Any default by a counterparty to these derivative contracts when they become due would have a material adverse effect on our financial condition and results of operations.

In addition, derivative arrangements could limit the benefit we would receive from increases in the prices for natural gas, which could also have an adverse effect on our financial condition.

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The inability of our significant customers to meet their obligations to us may adversely affect our financial results.

In addition to credit risk related to receivables from commodity derivative contracts, our principal exposures to credit risk are through joint interest receivables ($12.2 million at December 31, 2019) and the sale of our natural gas and oil production ($63.7 million in receivables at December 31, 2019). Joint interest receivables arise from billing entities who own partial interest in the wells we operate. These entities participate in our wells primarily based on their ownership in leased properties on which we wish to drill. We can do very little to choose who participates in our wells. For the year ended December 31, 2019, two customers, BP and Marathon, accounted for approximately 23% and 20% of our revenues, respectively. We do not require our customers to post collateral. The inability or failure of our significant customers to meet their obligations to us or their insolvency or liquidation may adversely affect our financial results.

Our operating history is limited and as a result there is only limited historical financial and operating information available upon which to base an evaluation of our performance. Moreover, the historical financial and operating information included in this Annual Report may not be indicative of our future financial performance.

Our operating history is limited and as a result there is only limited historical financial and operating information available upon which to base an evaluation of our performance. Moreover, the historical financial and operating information included in this Annual Report may not be indicative of our future financial performance. Please see “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations— Factors That Significantly Affect Comparability of Our Financial Condition and Results of Operations” for a description of recent developments and transactions that may affect the comparability of our historical financial condition and results of operations for the periods presented to future periods.  There can be no assurance that we will operate profitably. If our current business strategy is not successful, and we are not able to operate profitably, investors may lose some or all of their investment.

Our operations are subject to governmental laws and regulations, which may expose us to significant costs and liabilities that could exceed current expectations.

Our operations are subject to various federal, state and local governmental regulations. Matters subject to regulation include wastewater disposal, the spacing of wells, unitization and pooling of properties and taxation. 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 the environment. Failure to comply with these laws, regulations and permits may result in the assessment of administrative, civil and criminal penalties, the imposition of remedial obligations, the imposition of stricter conditions on or revocation of permits, the issuance of injunctions limiting or preventing some or all of our operations, delays in granting permits and cancellation of leases. Moreover, these laws and regulations have continually imposed increasingly strict requirements for water and air pollution control and solid waste management. Significant expenditures may be required to comply with governmental laws and regulations applicable to us. We believe the trend of more expansive and stricter environmental legislation and regulations will continue for the foreseeable future. Please read “Items 1 and 2. Business and Properties—Regulation of the Oil and Natural Gas Industry” and “Items 1 and 2. Business and Properties—Regulation of Environmental and Occupational Safety and Health Matters” for a description of the laws and regulations that affect us.

We make assumptions and develop expectations about possible expenditures based on current laws and regulations and current interpretations of those laws and regulations. If the interpretation of laws or regulations, or the laws and regulations themselves, change, our assumptions may change, and new capital costs may be incurred to comply with such changes. In addition, new laws and regulations might adversely affect our operations and activities, including drilling, processing, storage and transportation, as well as waste management and air emissions.

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Recent Ohio court decisions interpreting the Ohio Dormant Mineral Act and the Ohio Marketable Title Act relating to preservation of mineral rights by surface owners and heirs of reserved mineral interests could complicate title review, delay drilling activities and increase leasehold expenses with respect to some of our leasehold acreage in Ohio.

In September 2016, the Ohio Supreme Court issued a series of decisions relating to the Ohio Dormant Mineral Act, which we refer to as the ODMA. In the lead case, Corban v. Chesapeake Exploration L.L.C., the court concluded that the 1989 version of the ODMA did not transfer ownership of dormant mineral rights automatically, by operation of law. Instead, prior to 2006, surface owners were required to bring a quiet title action in order to establish abandonment of mineral rights. After June 30, 2006 (the effective date of the 2006 version of the ODMA), surface owners are required to follow the statutory notice and recording procedures enacted in 2006. As a result, going forward, it will be more difficult for a surface owner to achieve an abandonment of mineral rights as the Ohio Supreme Court held that the statutory notice and recording provisions of the 2006 version of the ODMA will apply. In addition, mineral interests that may previously have been believed to be automatically abandoned by operation of law under the ODMA will now be valid pursuant to the Ohio Supreme Court’s rulings.

Following the Ohio Supreme Court’s decision in Corban, many landowners began using the Ohio Marketable Title Act, which we refer to as the OMTA, as an alternative means to terminate severed oil and gas interests.  The OMTA is self-executing and automatically extinguishes certain property interests created prior to a landowner’s chain of title to property.  In January 2020, the Ohio Supreme Court accepted jurisdiction over West v. Bode, an appeal from the Seventh District Court of Appeals, to decide whether the ODMA supersedes and controls over the OMTA for disputes involving severed oil and gas interests, or whether the OMTA may be used as an alternative means to terminate severed mineral interests.

These recent Ohio court decisions, and the uncertainty of the continued availability of the OMTA to terminate severed mineral interests, may complicate title review, delay drilling activities and increase leasehold expenses with respect to our operations in Ohio where the majority of our acreage and producing properties are located, any of which could have an adverse effect on our results of operations and financial condition.

Our operations may be exposed to significant delays, costs and liabilities as a result of environmental, health and safety requirements applicable to our business activities.

There is inherent risk of the incurrence of environmental costs and liabilities in our business, some of which may be material, due to the handling of our products as they are gathered, transported, processed and stored, air emissions related to our operations, historical industry operations, and water and waste disposal practices. Joint and several strict liability may be incurred without regard to fault under some environmental laws and regulations, including the Comprehensive Environmental Response, Compensation, and Liability Act, Resource Conservation and Recovery Act, the Oil Pollution Act, and analogous state laws, for the remediation of contaminated areas and in connection with spills or releases of natural gas, oil and wastes on, under, or from our properties and facilities. Private parties may have the right to pursue legal actions to enforce compliance as well as to seek damages for non-compliance with environmental laws and regulations or for personal injury or property damage arising from our operations. Some sites at which we operate may be located near current or former third-party oil and natural gas operations or facilities, and there is a risk that contamination has migrated from those sites to ours. In addition, increasingly strict laws, regulations and enforcement policies could materially increase our compliance costs and the cost of any remediation that may become necessary. Our insurance may not cover all environmental risks and costs or may not provide sufficient coverage if an environmental claim is made against us.

We may be held responsible for all liabilities associated with the environmental condition of our facilities and assets, whether acquired or developed, regardless of when the liabilities arose and whether they are known or unknown. In connection with acquisitions and divestitures, we could acquire, or be required to provide indemnification against, environmental liabilities that could expose us to material losses, which may not be covered by insurance. In addition, the steps we could be required to take to bring facilities into compliance could be prohibitively expensive, and we might be required to shut down, divest or alter the operation of those facilities, which might cause us to incur losses.

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Oil and natural gas producers’ operations, especially those using hydraulic fracturing, are substantially dependent on the availability of water and water disposal options. Restrictions on the ability to obtain water or dispose of wastewater may impact our operations.

Water is an essential component of oil and natural gas production during the drilling, and in particular, hydraulic fracturing, process. Our inability to locate sufficient amounts of water or dispose of or recycle water used in our exploration and production operations could adversely impact our operations.

In addition, various studies have identified potential links between increases in seismic activity and the injection/disposal of water associated with oil and natural gas production, which could result in the imposition of operational limits or closure of disposal wells in areas where such links are suspected. For example, the Ohio Department of Natural Resources (“ODNR”) adopted rules that, among other things, allow the ODNR to require submission of a seismic monitoring plan, and require continuous monitoring of injection and annulus pressures on new wells.

We are subject to risks associated with climate change.

In recent years, federal, state and local governments have taken steps to reduce emissions of greenhouse gases (“GHGs”). The EPA has issued a series of GHG monitoring, reporting and emissions control rules for the oil and natural gas industry, and the U.S. Congress has, from time to time, considered adopting legislation to reduce emissions. Almost one-half of the states have already taken measures to reduce emissions of GHGs primarily through the development of GHG emission inventories and/or regional GHG, cap-and-trade programs. While we are subject to certain federal GHG monitoring and reporting requirements, our operations currently are not adversely impacted by existing federal, state and local climate change initiatives, but this is potentially subject to change if new or more stringent requirements are imposed. In addition, the United States is currently a party to the Paris Agreement, an international agreement to reduce GHG emissions. Our business and our financial results could be adversely impacted to the extent that the United States implements any additional GHG regulations in accordance with such agreement.  The Trump administration has begun the process to formally withdraw from the Paris Agreement, but under the terms of the agreement the U.S. will remain a party until November 4, 2020.

The costs that may be associated with the impacts of climate change and the regulation of GHGs have the potential to affect our business in many ways, including negatively impacting the costs we incur in providing our products and services, and the demand for and consumption of our products and services (due to changes in both costs and weather patterns). If we are unable to recover or pass through a significant level of our costs related to complying with climate change regulatory requirements imposed on us, it could have a material adverse effect on our results of operations and financial condition. To the extent financial markets view climate change and GHG emissions as a financial risk, this could negatively impact our cost of and access to capital. At this time, however, it is not possible to estimate how future laws or regulations, or climatic changes may impact our business.

We may incur substantial losses and be subject to substantial liability claims as a result of our operations. Additionally, we may not be insured for, or our insurance may be inadequate to protect us against, these risks.

Our oil and natural gas exploration and production activities are subject to all of the operating risks associated with drilling for and producing oil and natural gas, including the possibility of:

 

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environmental hazards, such as uncontrollable releases of oil, natural gas, brine, well fluids, toxic gas or other pollution into the environment, including groundwater, air and shoreline or river contamination;

 

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abnormally pressured formations;

 

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mechanical difficulties, such as stuck oilfield drilling and service tools and casing collapse;

 

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fires, explosions and ruptures of pipelines or processing facilities;

 

•

personal injuries and death;

 

•

natural disasters; and

 

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terrorist (including eco-terrorist) attacks targeting natural gas and oil related facilities and infrastructure.

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Any of these risks could adversely affect our ability to conduct operations or result in substantial loss to us as a result of claims for:

 

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injury or loss of life;

 

•

damage to and destruction of property, natural resources and equipment;

 

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pollution and other environmental damage;

 

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regulatory investigations and penalties;

 

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suspension of our operations; and

 

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repair and remediation costs.

In accordance with what we believe to be customary industry practice, we maintain insurance against some, but not all, of our business risks. Our insurance may not be adequate to cover any or all of the losses or liabilities we may suffer. Also, insurance may no longer be available to us or, if it is, its availability may be at premium levels that do not justify its purchase. The occurrence of a significant uninsured claim, a claim in excess of the insurance coverage limits maintained by us or a claim at a time when we are not able to obtain liability insurance could have a material adverse effect on our ability to conduct normal business operations and on our financial condition, results of operations or cash flows. In addition, we may not be able to secure additional insurance or bonding that might be required by new governmental regulations. This may cause us to restrict our operations, which might severely impact our financial condition. We may also be liable for environmental damage caused by previous owners of properties purchased by us, which liabilities may not be covered by insurance.

Since hydraulic fracturing activities are a large part of our operations, they are covered by our insurance against claims made for bodily injury, property damage and cleanup costs stemming from a sudden and accidental pollution event. However, we may not have coverage if we are unaware of the pollution event and unable to report the “occurrence” to our insurance company within the time frame required under our insurance policy. We have no coverage for gradual, long-term pollution events. In addition, these policies do not provide coverage for all liabilities, and we cannot assure you that the insurance coverage will be adequate to cover claims that may arise, or that we will be able to maintain adequate insurance at rates we consider reasonable. A loss not fully covered by insurance could have a material adverse effect on our financial condition, results of operations and cash flows.

Market conditions or operational impediments may hinder our access to natural gas, NGLs or oil markets or delay our production.

Market conditions or the unavailability of satisfactory natural gas, NGLs or oil transportation arrangements may hinder our access to markets or delay our production. The availability of a ready market for our production depends on a number of factors, including the demand for and supply of natural gas, NGLs or oil and the proximity of reserves to pipelines and terminal facilities. Our ability to market our production depends in substantial part on the availability and capacity of gathering systems, pipelines and processing facilities owned and operated by third parties. Our failure to obtain such services on acceptable terms and concurrent with the completion of our wells could materially harm our business. We may be required to shut in wells due to lack of a market or inadequacy or unavailability of natural gas, NGLs or oil pipeline or gathering system capacity. In addition, if quality specifications for the third-party pipelines with which we connect change so as to restrict our ability to transport product, our access to markets could be impeded. If our production becomes shut in for any of these or other reasons, we would be unable to realize revenue from those wells until other arrangements were made to deliver the products to market.

The unavailability or high cost of additional drilling rigs, equipment, supplies, personnel and oilfield services could adversely affect our ability to execute our exploration and development plans within our budget and on a timely basis.

The demand for qualified and experienced field personnel to drill wells and conduct field operations, geologists, geophysicists, engineers and other professionals in the oil and natural gas industry can fluctuate significantly, often in correlation with natural gas and oil prices, causing periodic shortages. Some of the rigs performing work for us do so on a well-by-well basis and can refuse to provide such services at the conclusion of drilling on the current well. Historically, there have been shortages of drilling and workover rigs, pipe and other equipment as demand for rigs and equipment has increased along with the number of wells being drilled. We cannot

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predict whether these conditions will exist in the future and, if so, what their timing and duration will be. Such shortages could delay or cause us to incur significant expenditures that are not provided for in our capital budget, which could have a material adverse effect on our business, financial condition or results of operations.

Competition in the oil and natural gas industry is intense, making it more difficult for us to acquire properties, market natural gas, NGLs and oil and secure trained personnel.

Our ability to acquire additional prospects and to find and develop reserves in the future will depend on our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment for acquiring properties, marketing natural gas, NGLs and oil and securing trained personnel. Also, there is substantial competition for capital available for investment in the oil and natural gas industry. Many of our competitors possess and employ financial, technical and personnel resources substantially greater than ours. Those companies may be able to pay more for productive natural gas and oil properties and exploratory prospects and to evaluate, bid for and purchase a greater number of properties and prospects than our financial or personnel resources permit. In addition, other companies may be able to offer better compensation packages to attract and retain qualified personnel than we are able to offer. We may not be able to compete successfully in the future in acquiring prospective reserves, developing reserves, marketing hydrocarbons, attracting and retaining quality personnel and raising additional capital, which could have a material adverse effect on our business.

The past success of our senior management with developing public and private natural gas and oil enterprises, and the expertise of our senior management in the acquisition, exploration and development of unconventional natural gas and oil properties does not guarantee our success or profitability.

As described in this Annual Report, most of our executive officers and other key personnel, including our President and Chief Executive Officer, John K. Reinhart, our Executive Vice President and Chief Operating Officer, Oleg E. Tolmachev, our Executive Vice President and Chief Financial Officer, Michael L. Hodges, and our Executive Vice President, Resource Planning and Development, Matthew H. Rucker, have substantial past experience in the acquisition, exploration and development of unconventional natural gas and oil properties, including experience at Ascent Resources, LLC, Chesapeake Energy Corporation, PayRock Energy II, LLC, Ward Energy Partners, LLC, and Rex Energy Corporation. However, the past experience and success of our executive officers and other key personnel with respect to previous endeavors in the natural gas and oil industry is not a guarantee of our future success or profitability.

The loss of senior management or technical personnel could adversely affect operations.

We depend on the services of our senior management and technical personnel. We do not maintain, nor do we plan to obtain, any insurance against the loss of any of these individuals. The loss of the services of our senior management or technical personnel, including our President and Chief Executive Officer, John K. Reinhart, our Executive Vice President and Chief Operating Officer, Oleg E. Tolmachev, our Executive Vice President and Chief Financial Officer, Michael L. Hodges, our Executive Vice President, Resource Planning and Development, Matthew H. Rucker, and our Executive Vice President, General Counsel and Corporate Secretary, Paul M. Johnston, could have a material adverse effect on our business, financial condition and results of operations.

Seasonal weather conditions and regulations intended to protect certain species of wildlife may adversely affect our ability to conduct drilling activities in the areas where we operate.

Natural gas and oil operations in our operating areas can be adversely affected by seasonal weather conditions and regulations designed to protect certain species of wildlife. For example, we must comply with state and federal regulations aimed at protecting the Indiana and Northern Long-Eared bats, which have been listed as a protected species by both federal and state law, and those regulations restrict or increase the cost of our operations by, among other things, limiting our ability to clear trees to establish rights of way or pad locations on some of our acreage during certain periods of the year. See “Items 1 and 2. Business and Properties—Regulation of Environmental and Occupational Safety and Health Matters—Endangered Species Act and Migratory Bird Treaty Act.” Adverse seasonal weather conditions and wildlife regulations may limit our ability to operate in those areas and can intensify competition during those months for drilling rigs, oilfield equipment, services, supplies and qualified personnel, which may lead to periodic shortages. These constraints and the resulting shortages or high costs could delay our operations and materially increase our operating and capital costs. In addition, the designation of previously

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unprotected species in areas where we operate as threatened or endangered could cause us to incur increased costs arising from species protection measures or could result in limitations on our exploration, development and production activities.

Acts of terrorism (including eco-terrorism) could have a material adverse effect on our financial condition, results of operations and cash flows.

Our assets and operations, and the assets and operations of our providers of gas gathering, processing, transportation and fractionation services, may be targets of terrorist activities (including eco-terrorist activities) that could disrupt our business or cause significant harm to our operations, such as full or partial disruption to our ability to produce, process, transport, market or distribute natural gas, NGLs and oil. Acts of terrorism, as well as events occurring in response to or in connection with acts of terrorism, could cause environmental and other repercussions that could result in a significant decrease in revenues or significant reconstruction or remediation costs, which could have a material adverse effect on our financial condition, results of operations and cash flows. In addition, acts of terrorism, and the threat of such acts, could result in volatility in the prices for natural gas, NGLs and oil and could affect the markets for such commodities.

Cyber-attacks and threats could have a material adverse effect on our business, financial condition or results of operations.

Cyber-attacks may significantly affect the energy industry, including our operations and those of our suppliers and customers, as well as general economic conditions, consumer confidence and spending, and market liquidity.  Strategic targets, such as energy-related assets, may be at greater risk of future attacks than other targets in the United States.  Our insurance may not protect us against such occurrences.  We depend on digital technology in many areas of our business and operations, including, but not limited to, estimating quantities of oil and gas reserves, processing and recording financial and operating data, oversight and analysis of drilling operations, and communications with our employees and third-party customers or service providers.  Deliberate attacks on our assets, or security breaches in our systems or infrastructure, or the systems or infrastructure of third-parties or the cloud, could lead to the corruption or loss of our proprietary and potentially sensitive data, delays in production or delivery of our production to customers, difficulty in completing and settling transactions, challenges in maintaining our books and records, environmental damage, communication interruptions, or other operational disruptions and third-party liabilities. Cybersecurity attacks in particular are becoming more sophisticated and include, but are not limited to, malicious software, ransomware, attempts to gain unauthorized access to data and other electronic security breaches that could lead to disruptions in critical systems, unauthorized release of confidential or otherwise protected information and corruption of data.

As cyber-attacks continue to evolve, we may be required to expend significant additional resources to continue to modify or enhance our protective measures or to investigate and remediate any vulnerabilities to cyber-attacks.  In particular, our implementation of various procedures and controls to monitor and mitigate security threats and to increase security for our personnel, information, facilities and infrastructure may result in increased capital and operating costs.  To date we have not experienced any material losses relating to cyber-attacks; however, there can be no assurance that we will not suffer such losses in the future.  Consequently, it is possible that any of these occurrences, or a combination of them, could have a material adverse effect on our business, financial condition and results of operations

Increases in interest rates could adversely affect our business.

Our business and operating results can be harmed by factors such as the availability, terms of and cost of capital, increases in interest rates or a reduction in credit rating. These changes could cause our cost of doing business to increase, limit our ability to pursue acquisition opportunities, reduce cash flows used for drilling and place us at a competitive disadvantage. Recent and continuing disruptions and volatility in the global financial markets may lead to a contraction in credit availability impacting our ability to finance our operations. We require continued access to capital. A significant reduction in cash flows from operations or the availability of credit could materially adversely affect our ability to achieve our planned growth and operating results.

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The enactment of derivatives legislation, and the promulgation of regulations pursuant thereto, could adversely affect our ability to use derivative instruments to hedge risks associated with our business.

Title VII of the Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”) was enacted on July 21, 2010 and establishes federal oversight and regulation of the over-the-counter derivatives market and entities, such as us, that participate in that market. The Dodd-Frank Act requires the Commodity Futures Trading Commission (the “CFTC”) and the SEC to promulgate certain rules and regulations implementing the Dodd-Frank Act, with the CFTC responsible for the rules and regulations regarding derivatives of the type we may use to hedge certain risks. Although the CFTC has finalized most of its implementing regulations, others remain to be finalized and it is not possible at this time to predict when this will be accomplished. In addition, the CFTC and its staff regularly issue rule amendments and guidance, policy statements, and letters interpreting the derivatives provisions of the Dodd-Frank Act, the contents of which cannot be known in advance.

The Dodd-Frank Act enhanced the CFTC’s authority to establish rules and regulations setting position limits for certain futures and option contracts, including in the major energy markets, and, for the first time, swaps that are their economic equivalents. The CFTC’s initial position limits rules under the Dodd-Frank Act were vacated by the U.S. District Court for the District of Columbia in September 2012 before such rules took effect. However, the CFTC has proposed new rules that would place limits on positions in certain core futures, options and equivalent swaps contracts in certain physical commodities, subject to limited exceptions for certain bona fide hedging and other transactions. The CFTC has also adopted final rules regarding the aggregation of positions in determining compliance with federal position limits. While the position aggregation rules are final, the position limit rules themselves are not, and therefore the impact of those rules on our use of derivatives in commodities for which federal position limits would be imposed is uncertain at this time.

The CFTC has designated certain interest rate swaps and credit default swaps for mandatory clearing and execution on certain trading platforms. The CFTC has not yet proposed rules designating any other classes of swaps, including physical commodity swaps, for mandatory clearing or trade execution. Although we expect to qualify for the end-user exception from the mandatory clearing and trade execution requirements for swaps entered to hedge our commercial risks, the application of the mandatory clearing and trade execution requirements to other market participants, such as swap dealers, may change the cost and availability of the swaps that we use for hedging. In addition, margin rules for uncleared swaps could impact liquidity and therefore reduce our ability to execute hedges to reduce risk and protect cash flows. The margin rules are not in effect for all market participants, and therefore the impact of those provisions to us is uncertain.

The Dodd-Frank Act and regulations may have other effects, including requiring or causing the counterparties to our derivative instruments to spin off some of their derivatives activities to separate entities, which may not be as creditworthy as the current counterparties. The Dodd-Frank Act and regulations could significantly increase the cost of derivative contracts, materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks we encounter, and reduce our ability to monetize or restructure our existing derivative contracts. If we reduce our use of derivatives as a result of the Dodd-Frank Act and regulations, our results of operations may become more volatile and our cash flows may be less predictable, which, among other impacts, could adversely affect our ability to plan for and fund capital expenditures.

Finally, the Dodd-Frank Act was intended, in part, to reduce the volatility of oil and natural gas prices, which some legislators attributed to speculative trading in derivatives and physically settled instruments related to oil and natural gas. Our revenues could therefore be adversely affected to the extent that the Dodd-Frank Act and regulations contribute to lower commodity prices.

Any of these consequences could have a material adverse effect on us, our financial condition or our results of operations.

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Proposed changes to U.S. and state tax laws, if adopted, could have an adverse effect on our business, financial condition, results of operations and cash flows.

The elimination of tax deductions, as well as any other changes to or the imposition of new federal, state, local or non-US taxes (including the imposition of, or increases in production, severance or similar taxes) could also have a significant impact on our operations and financial performance. For example, the recently enacted U.S. federal income tax legislation commonly referred to as the “Tax Cuts and Jobs Act” is complex and far-reaching and made sweeping modifications to the Internal Revenue Code including lowering the corporate tax rate, changing credits and deductions, and moving to a semi-territorial system for corporations that have overseas earnings.

From time-to-time other U.S. and state tax legislative amendments may be proposed that, if enacted into law, would make additional significant changes to U.S. federal and state income tax laws, such as (i) the elimination of the immediate deduction for intangible drilling and development costs and (ii) an extension of the amortization period for certain geological and geophysical expenditures.

Additionally, we primarily operate in Ohio, Pennsylvania, and West Virginia.  Legislation in these jurisdictions has been proposed from time to time that would impose or increase severance taxes on natural gas and oil extraction.  For example, Ohio has previously considered, and, the Ohio Legislature continues to consider, proposals to increase the current severance tax imposed on production of natural gas or oil in Ohio.  The Commonwealth of Pennsylvania requires an impact fee to be paid on all unconventional wells spud based on a price tier calculation for a period of 15 years.  However, Pennsylvania’s governor and legislature have continued to discuss the imposition of a state severance tax on the extraction of natural resources, including natural gas produced from the Marcellus, Upper Devonian, and Utica Shale formations, either in replacement of or in addition to the existing impact fee.  If any legislation imposing or increasing severance taxes is enacted, or other similar changes occur that tax our production or reduce or eliminate deductions currently available with respect to natural gas and oil exploration and development, it could adversely affect our business, financial condition, results of operations and cash flows.

Changes to state tax laws in response to recently enacted U.S. federal tax legislation or to impose new or increased taxes or fees on natural gas and oil extraction may result in an increase in the state taxes we pay.

Currently, many states conform their calculation of corporate taxable income to the calculation of corporate taxable income at the U.S. federal level.  Due to recently enacted changes to U.S. federal income tax laws, certain states may change or modify the calculation of corporate taxable income at the state level.  Any resulting increase in cost due to such changes could have an adverse effect on our financial position, results of operations and cash flows.

Future regulations relating to and interpretations of recently enacted U.S. federal income tax legislation may vary from our current interpretation of such legislation.

The Tax Cuts and Jobs Act is highly complex and subject to interpretation.  The presentation of our financial condition and results of operations is based upon our current interpretation of the provisions contained in the Tax Cuts and Jobs Act.  In the future, the Treasury Department and the Internal Revenue Service are expected to release regulations relating to and interpretive guidance of the legislation contained in the Tax Cuts and Jobs Act.  Any significant variance of our current interpretation of such legislation from any future regulations or interpretive guidance could result in a change to the presentation of our financial condition and results of operations and could negatively affect our business.

Our ability to use our net operating loss carryforward to offset future taxable income is subject to certain limitations and therefore our future tax liability may be greater than expected.

As of December 31, 2019, we estimate that we have available to offset future U.S. federal taxable income approximately $1.4 billion of U.S. federal net operating loss carryforward, portions of which will begin to expire in 2034. Because of the Tax Cuts and Jobs Act, the anticipated federal net operating losses generated in 2018 and 2019 do not expire but may only offset 80% of our taxable income in any given year.

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Additionally, our ability to utilize this net operating loss carryforward is dependent upon our ability to generate taxable income in future periods and is limited due to restrictions imposed on the utilization of net operating losses subsequent to an “ownership change” within the meaning of Section 382 of the Internal Revenue Code of 1986, as amended (the “Code”).

Section 382 of the Code generally serves to limit a corporation’s use of its net operating losses after an “ownership change” in the stock of the corporation.  Net operating losses on hand at the time of an ownership change are referred to as “pre-change losses.”  These pre-change losses are subject to an annual limitation based upon the product of: (i) the fair market value of the loss corporation’s stock immediately before the ownership change multiplied by (ii) a federally published rate, which we refer to as the “long-term tax exempt rate”. Further, a loss corporation with a net unrealized built-in loss (“NUBIL”) at the time of the ownership change, meaning that the fair market value of its assets were less than their tax bases by more than 15%, must treat a disposition loss or similar depreciation/depletion within the 5 year post-ownership change period as a pre-change loss like a net operating loss for purposes of the Code Section 382 limitation.

BRMR underwent an ownership change under Section 382 of the Code when it emerged from bankruptcy on May 6, 2016, and incurred a second ownership change at the effective time of the BRMR Merger.  Also, as a result of the BRMR Merger, we incurred an ownership change. As such, our pre-change losses as well as those of BRMR will be subject to the annual limitations provided in Section 382 of the Code.

Because U.S. federal net operating losses incurred before 2018 generally may be carried forward for up to 20 years, the annual limitation may effectively provide a cap on the cumulative amount of pre-ownership change losses, including certain recognized built-in losses that may be utilized. Any pre-ownership change losses in excess of the annual limitation may be lost. It is possible that the annual limitation imposed on our ability to use pre-ownership change losses could cause a net increase in our U.S. federal income tax liability and require U.S. federal income taxes to be paid earlier than otherwise would be paid if such annual limitations were not in effect.

Risks Related to Our Common Stock

 

The price of our common stock has historically been volatile, and this volatility may affect the price at which you could sell your common stock.

Our common stock began trading on the New York Stock Exchange (“NYSE”) on June 20, 2014 and since such date the market price of our common stock has ranged (after adjusting such market prices retroactively to reflect the 15-to-1 reverse stock split effected February 28, 2019) from a low of $2.59 per share in August 2019 to a high of $407.70 per share in June 2014. This volatility may prevent you from being able to sell your common stock at or above the price you paid for your common stock. The market price for our common stock could continue to fluctuate significantly for various reasons, including:

 

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general market conditions, including fluctuations in commodity prices;

 

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our operating and financial performance and drilling locations, including reserve estimates;

 

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quarterly variations in the rate of growth of our financial indicators, such as net income per share, net income and revenues;

 

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the public reaction to our press releases, our other public announcements and our filings with the SEC;

 

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strategic actions by our competitors;

 

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our failure to meet revenue, reserves or earnings estimates;

 

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changes in revenue or earnings estimates, or changes in recommendations or withdrawal of research coverage, by equity research analysts;

 

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speculation in the press or investment community;

 

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the failure of research analysts to cover our common stock;

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sales of our common stock by us, certain investment funds (the “EnCap Funds”) managed by EnCap Investments L.P. (“EnCap”) or other stockholders, or the perception that such sales may occur;

 

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changes in accounting principles, policies, guidance, interpretations or standards;

 

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additions or departures of key management personnel;

 

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actions by our stockholders;

 

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domestic and international economic, legal and regulatory factors unrelated to our performance; and

 

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the realization of any risks described under this “Risk Factors” section.

The stock markets in general have experienced extreme volatility that has often been unrelated to the operating performance of particular companies. These broad market fluctuations may adversely affect the trading price of our common stock. Securities class action litigation has often been instituted against companies following periods of volatility in the overall market and in the market price of a company’s securities. Such litigation, if instituted against us, could result in very substantial costs, divert our management’s attention and resources and harm our business, operating results and financial condition.

The EnCap Funds hold a significant amount of our common stock.

The EnCap Funds, which are managed by EnCap, hold a significant percentage of the outstanding shares of our common stock.  So long as EnCap continues to control a significant amount of our common stock, it will continue to be able to strongly influence all matters requiring stockholder approval, regardless of whether or not other stockholders believe that a potential transaction is in their own best interests. In any of these matters, the interests of EnCap may differ or conflict with the interests of our other stockholders. The existence of a significant stockholder may also have the effect of deterring hostile takeovers, delaying or preventing changes in control or changes in management, or limiting the ability of our other stockholders to approve transactions that they may deem to be in the best interests of our company.  Moreover, this concentration of stock ownership may also adversely affect the trading price of our common stock to the extent investors perceive a disadvantage in owning stock of a company with a significant stockholder.

Conflicts of interest could arise in the future between us, on the one hand, and EnCap and its affiliates, including its portfolio companies, on the other hand, concerning, among other things, acquisitions and divestitures, potential competitive business activities or business opportunities.

EnCap is a leading provider of private equity to the independent sector of the U.S. oil and gas industry and manages investment funds that own a significant amount of our common stock.  From time to time, we may acquire assets from entities affiliated with EnCap, including its portfolio companies, such as our acquisition of certain oil and gas leases, wells and other oil and gas rights and interests covering approximately 44,500 net acres located in the counties of Tioga and Potter in the Commonwealth of Pennsylvania from Travis Peak Resources, LLC (“Travis Peak”), which was completed on January 18, 2018 (such transaction, the “Flat Castle Acquisition”), divest assets to such entities or otherwise transact business with such entities.  For example, EnCap has an interest in Caiman Energy II, LLC, which owns a significant interest in Blue Racer, a provider of firm gathering, processing and fractionation capacity for our operated acreage in the Rich Gas and Condensate Windows of the Utica Core Area. As a result, EnCap’s interests with respect to matters arising in connection with our arrangements with Blue Racer may not align with our interests. EnCap and its affiliates may also, from time to time, acquire interests in businesses that directly or indirectly compete with our business, or are significant existing or potential customers.  EnCap and its affiliates may acquire or seek to acquire assets we seek to acquire, and as a result, those acquisition opportunities may not be available to us or may be more expensive for us to pursue.  Any actual or perceived conflicts of interest with respect to the foregoing could make us susceptible to litigation, which could result in substantial costs or divert our management’s attention and resources or otherwise harm our business and adversely impact the trading price of our common stock.

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The requirements of being a public company, including compliance with the reporting requirements of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), and the requirements of the Sarbanes—Oxley Act of 2002 (the “Sarbanes—Oxley Act”), may strain our resources, increase our costs and distract management.

We completed our initial public offering in June 2014. As a public company, we incur significant legal, accounting and other expenses that we did not incur as a private company. We also incur costs associated with our public company reporting requirements and with corporate governance requirements, including requirements under the Sarbanes-Oxley Act, as well as rules implemented by the SEC and the Financial Industry Regulatory Authority, Inc. These rules and regulations have increased our legal and financial compliance costs and make some activities more time-consuming and costly. These rules and regulations also make it more difficult and more expensive for us to obtain director and officer liability insurance. As a result, it may be more difficult for us to attract and retain qualified individuals to serve on our Board of Directors or as executive officers.

If we fail to establish and maintain effective internal control over financial reporting, our ability to accurately report our financial results could be adversely affected.

Effective internal controls are necessary for us to provide reliable financial reports, prevent fraud and operate successfully as a public company. 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. 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 shares of common stock.

Future sales of our common stock could reduce our stock price, and any additional capital raised by us through the sale of equity or convertible securities may dilute our stockholders’ ownership in us.

We may sell additional shares of common stock in subsequent public or private offerings. We may also issue additional shares of common stock or convertible securities. As of March 5, 2020, we had 35,826,888 outstanding shares of common stock. The EnCap Funds beneficially own an aggregate of 14,051,904 shares of our common stock, or approximately 39% of our total outstanding shares, a substantial portion of which has been registered with the SEC for resale. Upon the closing of the Flat Castle Acquisition, we entered into a registration rights agreement with Travis Peak, pursuant to which we agreed to register the resale of the shares of our common stock issued to Travis Peak, an entity affiliated with EnCap, in the Flat Castle Acquisition.  Subject to compliance with the Securities Act or exemptions therefrom, certain of our employees may sell their shares of common stock into the public market.

Subject to the satisfaction of vesting conditions and Rule 144 restrictions applicable to our affiliates, shares registered under our registration statements on Form S-8 filed on July 2, 2014, June 2, 2017 and June 13, 2019 relating to our equity incentive plans are available for resale immediately in the public market without restriction.

We cannot predict the size of future issuances of our common stock or securities convertible into common stock or the effect, if any, that future issuances and sales of shares of our common stock will have on the market price of our common stock. Sales of substantial amounts of our common stock (including shares issued in connection with an acquisition), or the perception that such sales could occur, may adversely affect prevailing market prices of our common stock.

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Our second amended and restated certificate of incorporation and second amended and restated bylaws, as well as Delaware law, contain provisions that could discourage acquisition bids or merger proposals, which may adversely affect the market price of our common stock.

Our second amended and restated certificate of incorporation authorizes our Board of Directors to issue preferred stock without stockholder approval. If our Board of Directors elects to issue preferred stock, it could be more difficult for a third party to acquire us. In addition, some provisions of our second amended and restated certificate of incorporation and second amended and restated bylaws could make it more difficult for a third party to acquire control of us, even if the change of control would be beneficial to our stockholders, including:

 

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limitations on the ability of our stockholders to call special meetings;

 

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providing that, subject to the rights of holders of any class or series of preferred stock, any action required or permitted to be taken by our stockholders must be taken at a duly held annual or special meeting of stockholders and may not be taken by any consent in writing of such stockholders;

 

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providing that our Board of Directors is expressly authorized to adopt, or to alter or repeal our second amended and restated bylaws; and

 

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establishing advance notice and information requirements for nominations for election to our Board of Directors or for proposing matters that can be acted upon by stockholders at stockholder meetings.

Our second amended and restated certificate of incorporation designates the Court of Chancery of the State of Delaware as the sole and exclusive forum for certain types of actions and proceedings that may be initiated by our stockholders, which could limit our stockholders’ ability to obtain a favorable judicial forum for disputes with us or our directors, officers or other employees.

Our second amended and restated certificate of incorporation provides that, unless we consent in writing to the selection of an alternative forum, the Court of Chancery of the State of Delaware (or, if the Court of Chancery does not have jurisdiction, another state court or a federal court located within the State of Delaware) shall, to the fullest extent permitted by applicable law and subject to applicable jurisdictional requirements, be the sole and exclusive forum for any current or former stockholder (including any current or former beneficial owner) to bring claims, including claims in the right of the Company, (i) that are based upon a violation of a duty by a current or former director, officer, employee or stockholder in such capacity, or (ii) as to which the General Corporation Law of the State of Delaware confers jurisdiction upon the Court of Chancery. Any person or entity purchasing or otherwise acquiring any interest in shares of our common stock shall be deemed to have notice of and consented to the provisions of our second amended and restated certificate of incorporation described above. This choice of forum provision may limit a stockholder’s ability to bring a claim in a judicial forum that it finds favorable for disputes with us or our directors, officers or other employees, which may discourage such lawsuits against us and our directors, officers and other employees. Alternatively, if a court were to find these provisions of our second amended and restated certificate of incorporation inapplicable to, or unenforceable in respect of, one or more of the specified types of actions or proceedings, we may incur additional costs associated with resolving such matters in other jurisdictions, which could adversely affect our business, financial condition or results of operations.

We do not intend to pay cash dividends on our common stock, and the Credit Agreement and the indenture governing our senior unsecured notes place certain restrictions on our ability to do so. Consequently, your only opportunity to achieve a return on your investment is if the price of our common stock appreciates.

We do not plan to declare cash dividends on shares of our common stock in the foreseeable future. Additionally, the Credit Agreement and the indenture governing our senior unsecured notes place certain restrictions on our ability to pay cash dividends. Consequently, your only opportunity to achieve a return on your investment in us will be if you sell your common stock at a price greater than you paid for it.

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We may issue preferred stock whose terms could adversely affect the voting power or value of our common stock.

Our second amended and restated certificate of incorporation authorizes us to issue, without the approval of our stockholders, one or more classes or series of preferred stock having such designations, preferences, limitations and relative rights, including preferences over our common stock respecting dividends and distributions, as our Board of Directors may determine. The terms of one or more classes or series of preferred stock could adversely impact the voting power or value of our common stock. For example, we might grant holders of preferred stock the right to elect some number of our directors in all events or on the happening of specified events or the right to veto specified transactions. Similarly, the repurchase or redemption rights or liquidation preferences we might assign to holders of preferred stock could affect the residual value of our common stock.

We are a “smaller reporting company” and will be able to avail ourselves of reduced disclosure requirements applicable to smaller reporting companies, which could make our common stock less attractive to investors.

We are a “smaller reporting company,” as defined in the Exchange Act, and we intend to take advantage of certain exemptions from various reporting requirements that are applicable to other public companies that are not “smaller reporting companies,” including reduced disclosure obligations regarding executive compensation in our periodic reports and proxy statements. We cannot predict if investors will find our common stock less attractive because we may rely on these exemptions. If some investors find our common stock less attractive as a result, there may be a less active trading market for our common stock and our stock price may be more volatile.

If securities or industry analysts do not publish research or reports about our business, if they adversely change their recommendations regarding our common stock or if our operating results do not meet their expectations, our stock price could decline.

The trading market for our common stock is influenced by the research and reports that industry or securities analysts publish about us or our business. If one or more of these analysts cease coverage of our company or fail to publish reports on us regularly, we could lose visibility in the financial markets, which in turn could cause our stock price or trading volume to decline. Moreover, if one or more of the analysts who cover our company downgrades our common stock or if our operating results do not meet their expectations, our stock price could decline.

 

 

Item 1B.

Unresolved Staff Comments

Not applicable.

 

 

Item 3.

Information regarding the Company’s legal proceedings is set forth in “Note 14 —Commitments and Contingencies,” located in the notes to the Consolidated Financial Statements included in Part II Item 8 of this Annual Report and is incorporated herein by reference.

 

 

Item 4.

Mine Safety Disclosures

Not applicable.

 

50

PART II

 

 

Item 5.

Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.

Common Stock

We have one class of common shares outstanding, having a par value of $0.01 per share (“Common Stock”). Our Common Stock is traded on the NYSE under the symbol “MR”. As of March 5, 2020, our Common Stock was held by 20 holders of record. The number of holders does not include the shareholders for whom shares are held in a “nominee” or “street” name.

 

Dividend Policy

We have not paid any cash dividends since our inception, and we do not anticipate declaring or paying any cash dividends to holders of our common stock in the foreseeable future. We currently intend to retain future earnings, if any, to finance the growth of our business. Our future dividend policy is within the discretion of our Board of Directors and will depend upon then-existing conditions, including our results of operations, financial condition, capital requirements, investment opportunities, statutory restrictions on our ability to pay dividends and other factors our Board of Directors may deem relevant. In addition, certain of our debt instruments place restrictions on our ability to pay cash dividends.

 

Item 6.

Selected Financial Data

 

Non-GAAP Financial Measure

“Adjusted EBITDAX” is a non-GAAP financial measure that we define as net income (loss) before interest expense or interest income; income taxes; write-down of abandoned leases; impairments; depreciation, depletion, amortization and accretion (“DD&A”); amortization of deferred financing costs; gain (loss) on derivative instruments, net cash receipts (payments) on settled derivative instruments, and premiums (paid) received on options that settled during the period; non-cash compensation expense; gain or loss from sale of interest in gas properties; exploration expenses; and other unusual or infrequent items. Adjusted EBITDAX, as used and defined by us, may not be comparable to similarly titled measures employed by other companies and is not a measure of performance calculated in accordance with U.S. GAAP. Adjusted EBITDAX should not be considered in isolation or as a substitute for operating income, net income or loss, cash flows provided by operating, investing and financing activities, or other income or cash flow statement data prepared in accordance with U.S. GAAP. Adjusted EBITDAX provides no information regarding a company’s capital structure, borrowings, interest costs, capital expenditures, and working capital movement or tax position. Adjusted EBITDAX does not represent funds available for discretionary use because those funds may be required for debt service, capital expenditures, working capital, income taxes, franchise taxes, exploration expenses, and other commitments and obligations. However, our management team believes Adjusted EBITDAX is useful to an investor in evaluating our financial performance because this measure:

 

•

is widely used by investors in the oil and natural gas industry to measure a company’s operating performance without regard to items excluded from the calculation of such term, which can vary substantially from company to company depending upon accounting methods and book value of assets, capital structure and the method by which assets were acquired, among other factors;

 

•

helps investors to more meaningfully evaluate and compare the results of our operations from period to period by removing the effect of our capital structure from our operating structure; and

 

•

is used by our management team for various purposes, including as a measure of operating performance, in presentations to our Board of Directors, as a basis for strategic planning and forecasting and by our lenders pursuant to covenants under our revolving credit facility and the indenture governing our senior unsecured notes.

51

There are significant limitations to using Adjusted EBITDAX as a measure of performance, including the inability to analyze the effect of certain recurring and non-recurring items that materially affect our net income or loss, the lack of comparability of results of operations of different companies and the different methods of calculating Adjusted EBITDAX reported by different companies. The following table represents a reconciliation of our net income (loss) from operations to Adjusted EBITDAX for the periods presented:

 

 

 

Year Ended December 31,

 

 

 

2019

 

 

2018

 

 

2017

 

 

2016

 

 

2015

 

Net income (loss)

 

$

31,762

 

 

$

18,826

 

 

$

8,525

 

 

$

(206,735

)

 

$

(961,791

)

Depreciation, depletion, amortization and

   accretion

 

 

156,003

 

 

 

134,940

 

 

 

119,362

 

 

 

93,339

 

 

 

246,373

 

Exploration expense

 

 

58,917

 

 

 

49,563

 

 

 

50,208

 

 

 

52,775

 

 

 

116,211

 

Rig termination and standby

 

 

1,081

 

 

 

—

 

 

 

1

 

 

 

3,846

 

 

 

9,672

 

Stock-based compensation

 

 

8,784

 

 

 

7,891

 

 

 

9,301

 

 

 

6,216

 

 

 

4,635

 

Impairment of proved oil and gas properties

 

 

—

 

 

 

—

 

 

 

—

 

 

 

17,665

 

 

 

691,334

 

(Gain) loss on sale of assets

 

 

(476

)

 

 

(1,815

)

 

 

(179

)

 

 

6,936

 

 

 

(4,737

)

(Gain) loss on derivative instruments

 

 

(48,596

)

 

 

21,169

 

 

 

(45,365

)

 

 

52,338

 

 

 

(56,021

)

Net cash receipts (payments) on settled

   derivatives

 

 

20,323

 

 

 

(26,985

)

 

 

(2,224

)

 

 

38,696

 

 

 

37,074

 

Interest expense, net

 

 

59,055

 

 

 

53,990

 

 

 

49,490

 

 

 

50,789

 

 

 

53,400

 

(Gain) loss on early extinguishment of debt

 

 

—

 

 

 

—

 

 

 

—

 

 

 

(14,489

)

 

 

59,392

 

Merger related expenses

 

 

25,539

 

 

 

4,017

 

 

 

—

 

 

 

—

 

 

 

—

 

Other (income) expense

 

 

(16

)

 

 

1

 

 

 

19

 

 

 

149

 

 

 

(400

)

Income tax (benefit) expense

 

 

—

 

 

 

—

 

 

 

—

 

 

 

546

 

 

 

(74,166

)

Income from discontinued operations

 

 

(1,316

)

 

 

—

 

 

 

—

 

 

 

—

 

 

 

—

 

Adjusted EBITDAX

 

$

311,060

 

 

$

261,597

 

 

$

189,138

 

 

$

102,071

 

 

$

120,976

 

 

52

Item 7.

Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with our Consolidated Financial Statements and related notes appearing elsewhere in this Annual Report. The following discussion contains “forward-looking statements” that reflect our future plans, estimates, beliefs and expected performance. We caution that assumptions, expectations, projections, intentions, or beliefs about future events may, and often do, vary from actual results and the differences can be material. Some of the key factors which could cause actual results to vary from our expectations include changes in natural gas, NGLs and oil prices, the timing of planned capital expenditures, availability of acquisitions, uncertainties in estimating proved reserves and forecasting production results, operational factors affecting the commencement or maintenance of producing wells, the condition of the capital markets generally, as well as our ability to access them, and uncertainties regarding environmental regulations or litigation and other legal or regulatory developments affecting our business, as well as those factors discussed below and elsewhere in this Annual Report, all of which are difficult to predict. In light of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur. See “Cautionary Statement Regarding Forward-Looking Statements.” Also, see the risk factors and other cautionary statements described in “Item 1A. Risk Factors” of this Annual Report. We do not undertake any obligation to publicly update any forward-looking statements except as otherwise required by applicable law.

Overview of Our Business

We are an independent exploration and production company engaged in the acquisition and development of oil and natural gas properties in the Appalachian Basin. On February 28, 2019, we completed a business combination (the “BRMR Merger”) with Blue Ridge Mountain Resources, Inc. (“BRMR”), and immediately thereafter, we changed our legal name from “Eclipse Resources Corporation” to “Montage Resources Corporation.”  Except where the context indicates otherwise, the terms “we,” “us,” “our” or the “Company” as used herein refer, for periods prior to the completion of the BRMR Merger, to Eclipse Resources Corporation and its subsidiaries and, for periods following the completion of the BRMR Merger, to Montage Resources Corporation (“Montage”) and its subsidiaries.

As of December 31, 2019, we had assembled an acreage position approximating 233,800 net surface acres in Eastern Ohio, 38,700 net surface acres in Pennsylvania, and 49,700 net surface acres in West Virginia. Approximately 192,800 of our net acres are located in the Utica Shale fairway, which we refer to as the Utica Core Area, and approximately 55,300 net acres of stacked pay opportunity are also prospective for the highly liquids rich area of the Marcellus Shale in Eastern Ohio and West Virginia within what we refer to as our Marcellus Area.  Additionally, we own approximately 74,100 net acres (which are approximately 80% held by production) outside of the Utica Core Area that may be prospective for the oil window of the Utica Shale.

We are the operator of approximately 98% of our net acreage within the Utica Core Area and our Marcellus Area. We intend to focus on developing our substantial inventory of horizontal drilling locations during commodity price environments that will allow us to generate attractive returns and will continue to opportunistically add to this acreage position where we can acquire acreage at attractive prices.

Outside of the Utica Core Area and our Marcellus Area, we had 1,002 gross (975.3 net) conventional wells operated under multiple subsidiaries as of December 31, 2019.

The net assets of our subsidiary, Magnum Hunter Production, Inc. (“MHP”), are classified as assets held for sale and liabilities associated with assets held for sale as of December 31, 2019.  All operations of MHP are reflected as discontinued operations for all periods presented.

As of December 31, 2019:

 

•

we were operating one horizontal rig;

 

•

we had 370 gross (235.7 net) wells within the Utica Core Area and our Marcellus Area, of which 1 gross (0.7 net) were drilling, 6 gross (5.2 net) were awaiting completion, and 363 gross (229.8 net) had been turned to sales;

53

 

•

we had average daily production for the year ended December 31, 2019 of approximately 547.8 MMcfe, which was comprised of approximately 77% natural gas, 14% NGLs and 9% oil; and

 

•

our estimated proved reserves were 2,729.8 Bcfe, or 455.0 MMBoe, based on reserve reports prepared by SIS, our independent petroleum engineers for the year ended December 31, 2019, approximately 55% of which were proved developed reserves. Our estimated proved reserves were approximately 78% natural gas, 15% NGLs and 7% oil, as of December 31, 2019.

Factors That Significantly Affect Our Financial Condition and Results of Operations

We derive substantially all of our revenues from the production and sale of natural gas, NGLs and oil that are extracted from our natural gas during processing. During the year ended December 31, 2019, our revenues were derived approximately 57%, 13% and 23% from the production and sale of natural gas, NGLs and oil, respectively (with the remaining 7% of revenues primarily attributable to brokered natural gas and marketing revenue). Our revenues, cash flow from operations and future growth depend substantially on factors beyond our control, such as economic, political and regulatory developments and competition from other sources of energy. Natural gas, NGLs and oil prices have historically been volatile and may fluctuate widely in the future due to a variety of factors, including, but not limited to, prevailing economic conditions, supply and demand of hydrocarbons in the marketplace and geopolitical events such as wars or natural disasters. Sustained periods of low prices for these commodities would materially and adversely affect our financial condition, our results of operations, the quantities of natural gas, NGLs and oil that we can economically produce and our ability to access capital.

We use commodity derivative instruments to manage and reduce price volatility and other market risks associated with our production. These arrangements are structured to reduce our exposure to commodity price decreases, but they can also limit the benefit we might otherwise receive from commodity price increases. Our risk management activity is generally accomplished through over-the-counter commodity derivative contracts with large financial institutions.  Additional information regarding our commodity derivative contracts is set forth in Note 7— Derivative Instruments to our Consolidated Financial Statements.

Like other businesses engaged in the exploration and production of oil and natural gas, we face the challenge of natural production declines. As initial reservoir pressures are depleted, oil and natural gas production from a given well naturally decreases. Thus, an exploration and production company depletes part of its asset base with each unit of reserves it produces. We attempt to overcome this natural decline by drilling to find additional reserves and acquiring more reserves than we produce. Our future growth will depend on our ability to enhance production levels from our existing reserves and to continue to add reserves in excess of production in a cost-effective manner. Our ability to make capital expenditures to increase production from our existing reserves and to add reserves through drilling is dependent on our capital resources and can be limited by many factors, including our ability to access capital in a cost-effective manner and to timely obtain drilling permits and regulatory approvals.

Our financial condition and results of operations, including the growth of production, cash flows and reserves, are driven by several factors, including:

 

•

success in drilling new wells;

 

•

natural gas, NGLs and oil prices;

 

•

the availability of attractive acquisition opportunities and our ability to execute them;

 

•

the amount of capital we invest in the leasing and development of our properties;

 

•

facility or equipment availability and unexpected downtime;

 

•

delays imposed by or resulting from compliance with regulatory requirements; and

 

•

the rate at which production volumes on our wells naturally decline.

54

Factors That Significantly Affect Comparability of Our Financial Condition and Results of Operations

Our historical financial condition and results of operations for the periods presented may not be comparable, either from period to period or going forward, for the following reasons:

Drilling Joint Venture. On December 22, 2017, we entered into definitive agreements with Sequel Energy Group LLC (“Sequel”) (an affiliate of GSO Capital Partners LP) to establish a drilling joint venture on our Utica Shale acreage in Guernsey and Monroe counties in southeast Ohio.  We have committed funding from Sequel of up to $285 million to fund its proportionate share of two drilling programs comprising of 33 gross wells in aggregate.   We retained 50% of our pre-carry working interest in the first program and 30% of our pre-carry working interest in the second program.  We received a 15% carried interest on drilling and completion capital expenditures incurred in each well program, which was proportionately reduced based upon our retained pre-carry working interest in such well program, and a significant portion of Sequel’s working interest in each well program will revert to Montage once a certain return is realized by Sequel in each program.  We are the operator of all wells drilled within each well program.

Flat Castle Acquisition. On January 18, 2018, Eclipse Resources-PA, LP, a wholly owned subsidiary of the Company, completed its acquisition of certain oil and gas leases, wells and other oil and gas rights and interests covering approximately 44,500 net acres located in the counties of Tioga and Potter in the Commonwealth of Pennsylvania from Travis Peak.  The aggregate adjusted purchase price for the Flat Castle Acquisition was $92.2 million, which was paid entirely with approximately 2.5 million shares of the Company’s common stock.

BRMR Merger. On February 28, 2019, the Company completed its business combination transaction with Blue Ridge Mountain Resources, Inc. (“BRMR”) pursuant to that certain Agreement and Plan of Merger, dated as of August 25, 2018 and amended as of January 7, 2019 (the “Merger Agreement”), by and among the Company, Everest Merger Sub Inc., a Delaware corporation and a wholly owned subsidiary of the Company (“Merger Sub”), and BRMR. Pursuant to the Merger Agreement, Merger Sub merged with and into BRMR with BRMR continuing as the surviving corporation and a wholly owned subsidiary of the Company (the “BRMR Merger”).

As a result of the BRMR Merger, each share of common stock, par value $0.01 per share, of BRMR issued and outstanding immediately prior to the effective time of the BRMR Merger (the “Effective Time”), excluding certain Excluded Shares (as such term is defined in the Merger Agreement), was converted into the right to receive from the Company 0.29506 of a validly issued, fully-paid, and nonassessable share of common stock, par value $0.01 per share, of the Company. The exchange ratio reflects an adjustment to account for the 15-to-1 reverse stock split described below. Former stockholders of BRMR received cash for any fractional shares of the Company’s common stock to which they might have otherwise been entitled as a result of the BRMR Merger. In addition, upon completion of the BRMR Merger, all shares of BRMR restricted stock and all BRMR restricted stock units and performance interest awards were converted into the right to receive shares of common stock of the Company or cash, in each case as specified in the Merger Agreement.

Reverse Stock Split. Effective immediately prior to the Effective Time on February 28, 2019, the Company effected a 15-to-1 reverse stock split with respect to the issued and outstanding shares of its common stock. Holders of shares of the Company’s common stock immediately prior to the Effective Time received cash for any fractional shares of the Company’s common stock to which they might have otherwise been entitled as a result of the reverse stock split. The reverse stock split lowered the aggregate par value of the common stock reflected in the Consolidated Statements of Stockholders’ Equity to reflect the reduced shares with the offset to additional paid-in-capital.  All issued and outstanding share and per share amounts as of and for the periods prior to February 28, 2019 presented in this Annual Report have been adjusted retroactively to reflect the reverse stock split in accordance with ASC 505 “Equity”.

Please see “Items 1 and 2. Business and Properties—Recent Developments” for a description of other recent developments and transactions that may affect the comparability of our historical financial condition and results of operations for the periods presented to future periods.

55

Source of Our Revenues

Substantially all of our historical revenues are derived from the production and sale of natural gas, NGLs and oil, and do not include the effects of derivatives. Revenues from product sales are a function of the volumes produced, prevailing market prices, product quality, gas Btu content and transportation costs. We generally sell production at a specific delivery point, pay transportation costs to a third party and receive proceeds from the purchaser with no transportation deduction. We record transportation costs as transportation, gathering and compression expense. We also may derive revenue from brokered gas or revenue we receive as a result of selling natural gas that is not related to our production and from the release of firm transportation capacity, which we refer to as brokered natural gas and marketing revenue. Our revenues may vary significantly from period to period as a result of changes in volumes of production sold or changes in commodity prices.

Principal Components of Our Cost Structure

 

•

Lease operating. These are day-to-day costs incurred to bring hydrocarbons out of the ground along with the daily costs incurred to maintain our producing properties. Such costs include compensation of our field employees, maintenance, repairs and workovers expenses related to our natural gas and oil properties.

 

•

Transportation, gathering and compression. These are costs incurred to bring natural gas, NGLs, and oil to the market. Such costs include the costs to operate and maintain our low- and high-pressure gathering and compression systems as well as fees paid to third parties who operate gathering systems that transport our gas. They also include costs to process and extract NGLs from our produced gas and to transport our NGLs and oil to market. We often enter into fixed price long-term contracts that secure transportation and processing capacity which may include minimum volume commitments, the cost for which is included in these expenses to the extent that they are not excess capacity.

 

•

Production and ad valorem taxes. Production taxes are paid on produced natural gas and oil based on a percentage of market prices or at fixed rates established by the applicable federal, state or local taxing authorities. Ad valorem taxes are generally based on reserve values at the end of each year.

 

•

Brokered natural gas and marketing. These expenses are gas purchases for brokered natural gas that we buy and sell that is not related to our production and firm transportation capacity that is marketed to third parties.

 

•

Depreciation, depletion, amortization and accretion. This includes the expensing of the capitalized costs incurred to acquire, explore and develop natural gas, NGLs and oil. As a successful efforts company, we capitalize all costs associated with our acquisition and development efforts and all successful exploration efforts, and apportion these costs to each unit of production through depreciation, depletion and amortization expense.  This also includes the monthly accretion of the future abandonment costs of tangible assets such as wells, service assets, pipelines and other facilities.

 

•

Exploration. These are geological and geophysical costs, seismic costs, delay rentals and the costs of unsuccessful exploratory dry holes. This category also includes unproved property impairment and expenses associated with lease expirations.

 

•

General and administrative. These costs include overhead, including payroll and benefits for our corporate staff, costs of maintaining our headquarters, costs of managing our production and development operations, franchise taxes, audit and other professional fees and legal compliance. Included in this category are any overhead expense reimbursements we receive from working interest owners of properties, for which we serve as the operator. These reimbursements are received during both the drilling and operational stages of a property’s life.

 

•

Impairment of oil and gas properties. Properties are evaluated for impairment when circumstances indicate that the carrying value of an asset could exceed its fair value. When the carrying value exceeds the sum of the future undiscounted cash flows, an impairment loss is recognized for the difference between the fair market value and carrying value of the asset.

56

 

•

Gain (loss) on derivative instruments. We utilize commodity derivative contracts to reduce our exposure to fluctuations in the price of gas. None of our derivative contracts are designated as hedges for accounting purposes. Consequently, our derivative contracts are marked-to-market each quarter with changes in fair value recognized currently as a gain or loss in our results of operations. The amount of future gain or loss recognized on derivative instruments is dependent upon future gas prices, which will affect the value of the contracts. Cash flow is only impacted to the extent the actual settlements under the contracts result in making a payment to or receiving a payment from the counterparty. In addition to gains and losses recognized from changes in fair value of the derivative instruments, gain (loss) on derivative instruments includes actual amounts realized from settlement of derivative instruments upon expiration.

 

•

Interest expense. We have historically financed a portion of our cash requirements with proceeds from fixed-rate senior unsecured notes and our revolving credit facility. As a result, we incur interest expense that is affected by our financing decisions.

How We Evaluate Our Operations

In evaluating our current and future financial results, we focus on production and revenue growth, lease operating expense, general and administrative expense (both before and after non-cash stock compensation expense) and operating margin per unit of production. In addition to these metrics, we use Adjusted EBITDAX, a non-GAAP measure, to evaluate our financial results. “Adjusted EBITDAX” is a non-GAAP financial measure that we define as net income (loss) before interest expense or interest income; income taxes; write-down of abandoned leases; impairments; depreciation, depletion, amortization and accretion (“DD&A”); amortization of deferred financing costs; gain (loss) on derivative instruments, net cash receipts (payments) on settled derivative instruments, and premiums (paid) received on options that settled during the period; non-cash compensation expense; gain or loss from sale of interest in gas properties; exploration expenses; and other unusual or infrequent items. Adjusted EBITDAX, as used and defined by us, may not be comparable to similarly titled measures employed by other companies and is not a measure of performance calculated in accordance with U.S. GAAP. Adjusted EBITDAX should not be considered in isolation or as a substitute for operating income, net income or loss, cash flows provided by operating, investing and financing activities, or other income or cash flow statement data prepared in accordance with U.S. GAAP. Adjusted EBITDAX provides no information regarding a company’s capital structure, borrowings, interest costs, capital expenditures, and working capital movement or tax position. Adjusted EBITDAX does not represent funds available for discretionary use because those funds may be required for debt service, capital expenditures, working capital, income taxes, franchise taxes, exploration expenses, and other commitments and obligations.

In addition to the operating metrics above, as we grow our reserve base, we will assess our capital spending by calculating our operated proved developed reserves and our operated proved developed finding costs and development costs. We believe that operated proved developed finding and development costs are one of the key measurements of the performance of an oil and gas exploration and production company. We will focus on our operated properties as we control the location, spending and operations associated with drilling these properties. In determining our proved developed finding and development costs, only cash costs incurred in connection with exploration and development will be used in the calculation, while the costs of acquisitions will be excluded because our Board of Directors approves each material acquisition. In evaluating our proved developed reserve additions, any reserve revisions for changes in commodity prices between years will be excluded from the assessment, but any performance related reserve revisions are included.

We also continually evaluate our rates of return on invested capital in our wells. These rates of return calculations may include corporate level items such as land costs, general and administrative expenses, midstream costs and cash settled derivatives.  We believe the quality of our assets combined with our technical and managerial expertise can generate attractive rates of return as we develop our acreage in the Utica Core Area and our Marcellus Area. We review changes in drilling and completion costs, lease operating costs, natural gas, NGLs and oil prices, well productivity, and other factors in order to focus our drilling on the highest rate of return areas within our acreage on a per well basis.

57

As a result of the closing of the BRMR Merger on February 28, 2019, BRMR’s assets and liabilities are included in the Consolidated Balance Sheet as of December 31, 2019 and BRMR’s revenues and expenses are included in the Consolidated Statements of Operations and Comprehensive Income (Loss) for the period from March 1, 2019 to December 31, 2019. (See Note 3— Acquisition).

Overview of the Year Ended December 31, 2019 Results

Operationally, our performance during the year ended December 31, 2019 reflects continued development of our acreage, while focusing on capital preservation in the current commodity price environment. During the year ended December 31, 2019, we achieved the following financial and operating results:

 

•

increased our average daily net production for the year ended December 31, 2019 by 60% over the prior year, to 547.8 MMcfe per day;

 

•

commenced drilling 32 gross (28.2 net) operated wells, commenced completions of 36 gross (30.0 net) operated wells and turned-to-sales 39 gross (30.8 net) operated wells during the year ended December 31, 2019;

 

•

recognized net income of $31.8 million for the year ended December 31, 2019 compared to net income of $18.8 million for the year ended December 31, 2018; and

 

•

realized Adjusted EBITDAX of $311.1 million for the year ended December 31, 2019 compared to $261.6 million for the year ended December 31, 2018. Adjusted EBITDAX is a non-GAAP financial measure. See “Item 6. Selected Financial Data—Non-GAAP Financial Measure” for more information.

Market Conditions

Prices for various quantities of natural gas, NGLs and oil that we produce significantly impact our revenues and cash flows. Prices for commodities, such as hydrocarbons, are inherently volatile. The following table lists average daily, high, low and average monthly settled NYMEX Henry Hub prices for natural gas and average daily, high and low NYMEX WTI prices for oil for the years ended December 31, 2019, 2018, and 2017:

 

 

 

Year Ended December 31,

 

 

 

2019

 

 

2018

 

 

2017

 

NYMEX Henry Hub High ($/MMBtu)

 

$

4.25

 

 

$

6.24

 

 

$

3.71

 

NYMEX Henry Hub Low ($/MMBtu)

 

 

1.75

 

 

 

2.49

 

 

 

2.44

 

Average Daily NYMEX Henry Hub ($/MMBtu)

 

 

2.56

 

 

 

3.15

 

 

 

2.99

 

Average Monthly Settled NYMEX Henry Hub

   ($/MMBtu)

 

 

2.63

 

 

 

3.09

 

 

 

3.11

 

 

 

 

 

 

 

 

 

 

 

 

 

 

NYMEX WTI High ($/Bbl)

 

$

66.24

 

 

$

77.41

 

 

$

60.46

 

NYMEX WTI Low ($/Bbl)

 

 

46.31

 

 

 

44.48

 

 

 

42.48

 

Average Daily NYMEX WTI ($/Bbl)

 

 

56.98

 

 

 

65.23

 

 

 

50.80

 

 

Historically, commodity prices have been extremely volatile, and we expect this volatility to continue for the foreseeable future. A decline in commodity prices could materially and adversely affect our future business, financial condition, results of operations, liquidity or ability to finance planned capital expenditures. We make price assumptions that are used for planning purposes, and a significant portion of our cash outlays, including rent, salaries and noncancelable capital commitments, are largely fixed in nature. Accordingly, if commodity prices are below the expectations on which these commitments were based, our financial results are likely to be adversely and disproportionately affected because these cash outlays are not variable in the short term and cannot be quickly reduced to respond to unanticipated decreases in commodity prices.

The Company is committed to profitably developing its natural gas, NGLs and oil reserves through an environmentally responsible and cost-effective operational plan.  The Company’s revenues, earnings, liquidity and ability to grow are substantially dependent on the prices it receives for, and the Company’s ability to develop its reserves. Despite the continued low price commodity environment, the Company believes the long-term outlook for its business is favorable due to the Company's resource base, low cost structure, risk management strategies, and disciplined investment of capital.

58

It is difficult to quantify the impact of changes in future commodity prices on our reported estimated net proved reserves with any degree of certainty because of the various components and assumptions used in the process. However, the below sensitivity analysis demonstrates the potential impact of a 10% increase and decrease in commodity pricing to our reserves assuming all other inputs remain constant.

 

 

 

Oil

 

 

Natural Gas

 

 

Estimated Proved Reserves (Bcfe)

 

 

Discounted Future

Net Cash Flows (PV-10)(1)

 

Commodity Pricing - SEC

 

$

55.85

 

 

$

2.58

 

 

 

2,729.8

 

 

$

1,470.6

 

Reserves Sensitivity:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

10% Increase

 

$

61.44

 

 

$

2.84

 

 

 

2,812.4

 

 

$

1,896.6

 

10% Decrease

 

$

50.27

 

 

$

2.32

 

 

 

2,387.7

 

 

$

1,064.2

 

 

(1)

PV-10 is a non-GAAP financial measure. For a reconciliation of PV-10 to standardized measure, please see “Items 1 and 2. Business and Properties—Oil and Natural Gas Data— Proved Reserves Additions and Revisions.”

We consider future commodity prices when determining our development plan, but many other factors are also considered. To the extent there is a significant increase or decrease in commodity prices in the future, we will assess the impact on our development plan at that time, and we may respond to such changes by altering our capital budget or our development plan. We plan to fund our development budget with a portion of the cash on hand at December 31, 2019, cash flows from operations, borrowings under our revolving credit facility, and proceeds from asset sales.

Results of Operations

The following discussion pertains to our results of operations, including analysis of our continuing operations regarding natural gas, NGLs and oil revenues, production, average product prices and average production costs and expenses for the years ended December 31, 2019, 2018, and 2017.  The results of operations of MHP are reflected as discontinued operations for all periods presented.

 

Year Ended December 31, 2019 Compared to Year Ended December 31, 2018

Natural Gas, NGLs and Oil Sales, Production and Realized Price Calculations

The following table illustrates the revenue attributable to our operations for the years ended December 31, 2019 and 2018:

 

 

 

Year Ended

December 31,

 

 

 

 

 

 

 

2019

 

 

2018

 

 

Change

 

Revenues (in thousands)

 

 

 

 

 

 

 

 

 

 

 

 

Natural gas sales

 

$

361,318

 

 

$

274,239

 

 

$

87,079

 

NGL sales

 

 

84,552

 

 

 

86,152

 

 

 

(1,600

)

Oil sales

 

 

145,829

 

 

 

138,202

 

 

 

7,627

 

Brokered natural gas and marketing revenue

 

 

42,274

 

 

 

16,552

 

 

 

25,722

 

Other revenue

 

 

468

 

 

 

—

 

 

 

468

 

Total revenues

 

$

634,441

 

 

$

515,145

 

 

$

119,296

 

 

59

Our production grew by approximately 74.7 Bcfe for the year ended December 31, 2019 over the year ended December 31, 2018, due to increased drilling activity and from wells acquired as part of the BRMR Merger. Our production for the years ended December 31, 2019 and 2018 is set forth in the following table:

 

 

 

Year Ended

December 31,

 

 

 

 

 

 

 

2019

 

 

2018

 

 

Change

 

Production:

 

 

 

 

 

 

 

 

 

 

 

 

Natural gas (MMcf)

 

 

154,137.5

 

 

 

89,965.7

 

 

 

64,171.8

 

NGLs (Mbbls)

 

 

4,686.3

 

 

 

3,503.1

 

 

 

1,183.2

 

Oil (Mbbls)

 

 

2,950.8

 

 

 

2,378.0

 

 

 

572.8

 

Total (MMcfe)

 

 

199,960.1

 

 

 

125,252.3

 

 

 

74,707.8

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Average daily production volume:

 

 

 

 

 

 

 

 

 

 

 

 

Natural gas (Mcf/d)

 

 

422,295

 

 

 

246,481

 

 

 

175,814

 

NGLs (Bbls/d)

 

 

12,839

 

 

 

9,598

 

 

 

3,241

 

Oil (Bbls/d)

 

 

8,084

 

 

 

6,515

 

 

 

1,569

 

Total (Mcfe/d)

 

 

547,834

 

 

 

343,159

 

 

 

204,675

 

 

60

Our average realized price (including cash settled derivatives and firm transportation) received during the year ended December 31, 2019 was $2.70 per Mcfe compared to $3.37 per Mcfe during the year ended December 31, 2018. Because we record transportation costs on two separate bases, as required by U.S. GAAP, we believe computed final realized prices of production volumes should include the total impact of firm transportation expense. Our average realized price (including all cash settled derivatives and firm transportation) calculation also includes all cash settlements for derivatives. Average realized price (excluding cash settled derivatives and firm transportation) does not include derivative settlements or firm transportation, which are reported in transportation, gathering and compression expense on the accompanying Consolidated Statements of Operations. Average realized price (including firm transportation and excluding cash settled derivatives) does include firm transportation where we receive net revenue proceeds from purchasers. Average realized price calculations for the years ended December 31, 2019 and 2018 are shown below:

  

 

 

Year Ended

December 31,

 

 

 

 

 

 

 

2019

 

 

2018

 

 

Change

 

Average realized price (excluding cash settled

   derivatives and firm transportation)

 

 

 

 

 

 

 

 

 

 

 

 

Natural gas ($/Mcf)

 

$

2.34

 

 

$

3.05

 

 

$

(0.71

)

NGLs ($/Bbl)

 

 

18.04

 

 

 

24.59

 

 

 

(6.55

)

Oil ($/Bbl)

 

 

49.42

 

 

 

58.12

 

 

 

(8.70

)

Total average prices ($/Mcfe)

 

 

2.96

 

 

 

3.98

 

 

 

(1.02

)

 

 

 

 

 

 

 

 

 

 

 

 

 

Average realized price (including cash settled

   derivatives, excluding firm transportation)

 

 

 

 

 

 

 

 

 

 

 

 

Natural gas ($/Mcf)

 

$

2.45

 

 

$

2.96

 

 

$

(0.51

)

NGLs ($/Bbl)

 

 

18.45

 

 

 

24.32

 

 

 

(5.87

)

Oil ($/Bbl)

 

 

50.01

 

 

 

50.47

 

 

 

(0.46

)

Total average prices ($/Mcfe)

 

 

3.06

 

 

 

3.77

 

 

 

(0.71

)

 

 

 

 

 

 

 

 

 

 

 

 

 

Average realized price (including firm

   transportation, excluding cash settled

   derivatives)

 

 

 

 

 

 

 

 

 

 

 

 

Natural gas ($/Mcf)

 

$

1.88

 

 

$

2.50

 

 

$

(0.62

)

NGLs ($/Bbl)

 

 

18.04

 

 

 

24.59

 

 

 

(6.55

)

Oil ($/Bbl)

 

 

49.42

 

 

 

58.12

 

 

 

(8.70

)

Total average prices ($/Mcfe)

 

 

2.60

 

 

 

3.59

 

 

 

(0.99

)

 

 

 

 

 

 

 

 

 

 

 

 

 

Average realized price (including cash settled

   derivatives and firm transportation)

 

 

 

 

 

 

 

 

 

 

 

 

Natural gas ($/Mcf)

 

$

1.99

 

 

$

2.41

 

 

$

(0.42

)

NGLs ($/Bbl)

 

 

18.45

 

 

 

24.32

 

 

 

(5.87

)

Oil ($/Bbl)

 

 

50.01

 

 

 

50.47

 

 

 

(0.46

)

Total average prices ($/Mcfe)

 

 

2.70

 

 

 

3.37

 

 

 

(0.67

)

 

Brokered natural gas and marketing revenue was $42.3 million in the year ended December 31, 2019 compared to $16.6 million in the year ended December 31, 2018. Brokered natural gas and marketing revenue includes revenue we receive as a result of selling natural gas that is not related to our production and from the release of firm transportation capacity.  The increase from the year ended December 31, 2018 to the year ended December 31, 2019 was due to an increase in the amount of natural gas that was available for brokered gas transactions during the year ended December 31, 2019.

61

Costs and Expenses

We believe some of our expense fluctuations are best analyzed on a unit-of-production, or per Mcfe, basis. The following table presents information about certain of our expenses for the years ended December 31, 2019 and 2018:

 

 

 

Year Ended

December 31,

 

 

 

 

 

 

 

2019

 

 

2018

 

 

Change

 

Operating expenses (in thousands)

 

 

 

 

 

 

 

 

 

 

 

 

Lease operating

 

$

43,359

 

 

$

28,289

 

 

$

15,070

 

Transportation, gathering and compression

 

 

208,826

 

 

 

138,766

 

 

 

70,060

 

Production and ad valorem taxes

 

 

12,141

 

 

 

10,141

 

 

 

2,000

 

Depreciation, depletion, amortization and accretion

 

 

156,003

 

 

 

134,940

 

 

 

21,063

 

General and administrative

 

 

70,941

 

 

 

44,389

 

 

 

26,552

 

Operating expenses per Mcfe:

 

 

 

 

 

 

 

 

 

 

 

 

Lease operating

 

$

0.22

 

 

$

0.23

 

 

$

(0.01

)

Transportation, gathering and compression

 

 

1.04

 

 

 

1.10

 

 

 

(0.06

)

Production and ad valorem taxes

 

 

0.06

 

 

 

0.08

 

 

 

(0.02

)

Depreciation, depletion, amortization and accretion

 

 

0.77

 

 

 

1.07

 

 

 

(0.30

)

General and administrative

 

 

0.35

 

 

 

0.35

 

 

 

—

 

 

Lease operating expense was $43.4 million in the year ended December 31, 2019 compared to $28.3 million in the year ended December 31, 2018. Lease operating expense per Mcfe was $0.22 in the year ended December 31, 2019 compared to $0.23 in the year ended December 31, 2018.  The increase of $15.1 million was primarily attributable to an increase in producing wells during the year ended December 31, 2019.  The decrease of $0.01 per Mcfe was primarily due to a decrease in non-recurring workovers and fixed costs spread across increased production for the year ended December 31, 2019. Lease operating expenses include normally recurring expenses to operate our wells and non-recurring workovers and repairs.  

Transportation, gathering and compression expense was $208.8 million in the year ended December 31, 2019 compared to $138.8 million in the year ended December 31, 2018. Transportation, gathering and compression expense per Mcfe was $1.04 in the year ended December 31, 2019 compared to $1.10 in the year ended December 31, 2018.  The following table details our transportation, gathering and compression expenses for the years ended December 31, 2019 and 2018:

 

 

 

Year Ended

December 31,

 

 

 

 

 

 

 

2019

 

 

2018

 

 

Change

 

Transportation, gathering and compression (in thousands):

 

 

 

 

 

 

 

 

 

 

 

 

Gathering, compression and fuel

 

$

66,825

 

 

$

42,461

 

 

$

24,364

 

Processing and fractionation

 

 

63,009

 

 

 

39,132

 

 

 

23,877

 

Liquids transportation and stabilization

 

 

7,256

 

 

 

7,986

 

 

 

(730

)

Marketing

 

 

103

 

 

 

19

 

 

 

84

 

Firm transportation

 

 

71,633

 

 

 

49,168

 

 

 

22,465

 

 

 

$

208,826

 

 

$

138,766

 

 

$

70,060

 

Transportation, gathering and compression per Mcfe:

 

 

 

 

 

 

 

 

 

 

 

 

Gathering, compression and fuel

 

$

0.33

 

 

$

0.34

 

 

$

(0.01

)

Processing and fractionation

 

 

0.31

 

 

 

0.31

 

 

 

—

 

Liquids transportation and stabilization

 

 

0.04

 

 

 

0.06

 

 

 

(0.02

)

Marketing

 

 

—

 

 

 

—

 

 

 

—

 

Firm transportation

 

 

0.36

 

 

 

0.39

 

 

 

(0.03

)

 

 

$

1.04

 

 

$

1.10

 

 

$

(0.06

)

 

62

The increase of $70.1 million in the year ended December 31, 2019 was due to increased production and increased firm transportation capacity.  The decrease of $0.06 per Mcfe was primarily due to a higher percentage of production attributable to natural gas and fixed firm transportation costs spread across increased production during the year ended December 31, 2019.

 

Production and ad valorem taxes are paid based on market prices and applicable tax rates. Production and ad valorem taxes were $12.1 million in the year ended December 31, 2019 compared to $10.1 million in the year ended December 31, 2018. Production and ad valorem taxes per Mcfe was $0.06 in the year ended December 31, 2019 compared to $0.08 in the year ended December 31, 2018.  The increase of $2.0 million in aggregate production and ad valorem taxes was primarily due to increased production and well count.  The decrease of $0.02 per Mcfe was primarily due to the recognition of a refund for production taxes from a state taxing authority during the year ended December 31, 2019.

Depreciation, depletion, amortization and accretion was approximately $156.0 million in the year ended December 31, 2019 compared to $134.9 million in the year ended December 31, 2018.  This $21.2 million increase was primarily due to an increase in production and proved property costs during the year ended December 31, 2019.  On a per Mcfe basis, DD&A decreased to $0.77 in the year ended December 31, 2019 from $1.07 in the year ended December 31, 2018, which was primarily due to a lower depletion rate resulting from our reserves increasing at a higher rate than our capital costs.

General and administrative expense was $70.9 million for the year ended December 31, 2019 compared to $44.4 million for the year ended December 31, 2018.  General and administrative expense per Mcfe was $0.35 in each of the years ended December 31, 2019 and 2018.  The increase of $26.5 million was primarily related to approximately $21.5 million of expenses related to the BRMR Merger incurred during the year ended December 31, 2019.  Expenses were consistent on a per Mcfe basis due to the increase in expenses being offset by increased production for the year ended December 31, 2019 compared to December 31, 2018.  General and administrative expense includes $8.8 million and $7.9 million of stock-based compensation expense for the years ended December 31, 2019 and 2018, respectively.

Other Operating Expenses

Our total operating expenses also include other expenses that generally do not trend with production. These expenses include brokered natural gas and marketing expense, exploration, rig termination and standby and (gain) loss on sale of assets. The following table details our other operating expenses for the years ended December 31, 2019 and 2018:

  

 

 

Year Ended

December 31,

 

 

 

 

 

 

 

2019

 

 

2018

 

 

Change

 

Other operating expenses (in thousands):

 

 

 

 

 

 

 

 

 

 

 

 

Brokered natural gas and marketing expense

 

$

42,700

 

 

$

16,886

 

 

$

25,814

 

Exploration

 

 

58,917

 

 

 

49,563

 

 

 

9,354

 

Rig termination and standby

 

 

1,081

 

 

 

—

 

 

 

1,081

 

Gain on sale of assets

 

 

(476

)

 

 

(1,815

)

 

 

1,339

 

 

Brokered natural gas and marketing expense was $42.7 million for the year ended December 31, 2019 compared to $16.9 million in the year ended December 31, 2018.  Brokered natural gas and marketing expense relate to gas purchases for brokered natural gas that we buy and sell that is not related to our production and firm transportation capacity that is marketed to third parties.  The increase was primarily due to an increase in the amount of natural gas that was available for brokered gas transactions during the year ended December 31, 2019.

63

Exploration expense was $58.9 million in the year ended December 31, 2019 compared to $49.6 million in the year ended December 31, 2018. The following table details our exploration-related expenses for the years ended December 31, 2019 and 2018:

 

 

 

Year Ended

December 31,

 

 

 

 

 

 

 

2019

 

 

2018

 

 

Change

 

Exploration expenses (in thousands):

 

 

 

 

 

 

 

 

 

 

 

 

Geological and geophysical

 

$

812

 

 

$

1,510

 

 

$

(698

)

Delay rentals

 

 

10,330

 

 

 

19,729

 

 

 

(9,399

)

Impairment of unproved properties

 

 

45,757

 

 

 

27,608

 

 

 

18,149

 

Dry hole and other

 

 

2,018

 

 

 

716

 

 

 

1,302

 

 

 

$

58,917

 

 

$

49,563

 

 

$

9,354

 

 

Delay rentals was $10.3 million in the year ended December 31, 2019 compared to $19.7 million in the year ended December 31, 2018.  The decrease in delay rentals related to the reduction in future drilling activity and focusing renewals in our core acreage during the year ended December 31, 2019.

Impairment of unproved properties was $45.8 million in the year ended December 31, 2019 compared to $27.6 million in the year ended December 31, 2018.  The increase in impairment charges during the year ended December 31, 2019 was the result of an increase in expected lease expirations due to a reduction in planned future drilling activity. As we continue to review our acreage positions and high grade our drilling inventory based on the current commodity price environment, additional leasehold impairments and abandonments may be recorded.

Rig termination and standby expense was $1.1 million in the year ended December 31, 2019 primarily related to the reduction in development activity. There was no rig termination and standby expense in the year ended December 31, 2018.

Gain on sale of assets was $0.5 million in the year ended December 31, 2019 and $1.8 million in the year ended December 31, 2018, each due to the sale of certain non-core assets.

Other Income (Expense)

Gain (loss) on derivative instruments was $48.6 million for the year ended December 31, 2019 compared to ($21.2) million for the year ended December 31, 2018, primarily due to changes in commodity prices during each year.  Cash receipts (payments) were approximately $20.3 million and ($27.0) million for the derivative instruments that settled during the years ended December 31, 2019 and 2018, respectively.

Interest expense, net was $59.1 million for the year ended December 31, 2019 compared to $54.0 million for year ended December 31, 2018. The increase in interest expense was primarily due to our increased borrowings under our credit facility during the year ended December 31, 2019.

Income tax benefit (expense) was not recognized for the years ended December 31, 2019 and 2018 due to the Company recording a higher valuation allowance related to its pre-tax losses and reducing the valuation allowance to the extent of pre-tax income.

64

Year Ended December 31, 2018 Compared to Year Ended December 31, 2017

Natural Gas, NGLs and Oil Sales, Production and Realized Price Calculations

The following table illustrates the revenue attributable to our operations for the years ended December 31, 2018 and 2017:

 

 

 

Year Ended

December 31,

 

 

 

 

 

 

 

2018

 

 

2017

 

 

Change

 

Revenues (in thousands):

 

 

 

 

 

 

 

 

 

 

 

 

Natural gas sales

 

$

274,239

 

 

$

241,379

 

 

$

32,860

 

NGLs sales

 

 

86,152

 

 

 

64,109

 

 

 

22,043

 

Oil sales

 

 

138,202

 

 

 

74,690

 

 

 

63,512

 

Brokered natural gas and marketing revenue

 

 

16,552

 

 

 

3,481

 

 

 

13,071

 

Total revenues

 

$

515,145

 

 

$

383,659

 

 

$

131,486

 

 

Our production grew by approximately 11.8 Bcfe for the year ended December 31, 2018 over the year ended December 31, 2017, as we placed new wells into production, partially offset by natural declines in well production. Our production for the years ended December 31, 2018 and 2017 is set forth in the following table:

 

 

 

Year Ended

December 31,

 

 

 

 

 

 

 

2018

 

 

2017

 

 

Change

 

Production:

 

 

 

 

 

 

 

 

 

 

 

 

Natural gas (MMcf)

 

 

89,965.7

 

 

 

87,404.2

 

 

 

2,561.5

 

NGLs (Mbbls)

 

 

3,503.1

 

 

 

2,713.7

 

 

 

789.4

 

Oil (Mbbls)

 

 

2,378.0

 

 

 

1,622.4

 

 

 

755.6

 

Total (MMcfe)

 

 

125,252.3

 

 

 

113,420.8

 

 

 

11,831.5

 

Average daily production volume:

 

 

 

 

 

 

 

 

 

 

 

 

Natural gas (Mcf/d)

 

 

246,481

 

 

 

239,464

 

 

 

7,017

 

NGLs (Bbls/d)

 

 

9,598

 

 

 

7,435

 

 

 

2,163

 

Oil (Bbls/d)

 

 

6,515

 

 

 

4,445

 

 

 

2,070

 

Total (Mcfe/d)

 

 

343,159

 

 

 

310,744

 

 

 

32,415

 

 

65

Our average realized price (including cash settled derivatives and firm transportation) received during the year ended December 31, 2018 was $3.37 per Mcfe compared to $2.99 per Mcfe during the year ended December 31, 2017. Because we record transportation costs on two separate bases, as required by U.S. GAAP, we believe computed final realized prices of production volumes should include the total impact of firm transportation expense. Our average realized price (including all cash settled derivatives and firm transportation) calculation also includes all cash settlements for derivatives. Average realized price (excluding cash settled derivatives and firm transportation) does not include derivative settlements or firm transportation, which are reported in transportation, gathering and compression expense on the accompanying Consolidated Statements of Operations. Average realized price (including firm transportation and excluding cash settled derivatives) does include firm transportation where we receive net revenue proceeds from purchasers. Average realized price calculations for the years ended December 31, 2018 and 2017 are shown below:

 

 

 

Year Ended

December 31,

 

 

 

 

 

 

 

2018

 

 

2017

 

 

Change

 

Average realized price (excluding cash settled

   derivatives and firm transportation)

 

 

 

 

 

 

 

 

 

 

 

 

Natural gas ($/Mcf)

 

$

3.05

 

 

$

2.76

 

 

$

0.29

 

NGLs ($/Bbl)

 

 

24.59

 

 

 

23.62

 

 

 

0.97

 

Oil ($/Bbl)

 

 

58.12

 

 

 

46.04

 

 

 

12.08

 

Total average prices ($/Mcfe)

 

 

3.98

 

 

 

3.35

 

 

 

0.63

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Average realized price (including cash settled

   derivatives, excluding firm transportation)

 

 

 

 

 

 

 

 

 

 

 

 

Natural gas ($/Mcf)

 

$

2.96

 

 

$

2.79

 

 

$

0.17

 

NGLs ($/Bbl)

 

 

24.32

 

 

 

21.96

 

 

 

2.36

 

Oil ($/Bbl)

 

 

50.47

 

 

 

46.14

 

 

 

4.33

 

Total average prices ($/Mcfe)

 

 

3.77

 

 

 

3.33

 

 

 

0.44

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Average realized price (including firm

   transportation, excluding cash settled

   derivatives)

 

 

 

 

 

 

 

 

 

 

 

 

Natural gas ($/Mcf)

 

$

2.50

 

 

$

2.31

 

 

$

0.19

 

NGLs ($/Bbl)

 

 

24.59

 

 

 

23.62

 

 

 

0.97

 

Oil ($/Bbl)

 

 

58.12

 

 

 

46.04

 

 

 

12.08

 

Total average prices ($/Mcfe)

 

 

3.59

 

 

 

3.01

 

 

 

0.58

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Average realized price (including cash settled

   derivatives and firm transportation)

 

 

 

 

 

 

 

 

 

 

 

 

Natural gas ($/Mcf)

 

$

2.41

 

 

$

2.34

 

 

$

0.07

 

NGLs ($/Bbl)

 

 

24.32

 

 

 

21.96

 

 

 

2.36

 

Oil ($/Bbl)

 

 

50.47

 

 

 

46.14

 

 

 

4.33

 

Total average prices ($/Mcfe)

 

 

3.37

 

 

 

2.99

 

 

 

0.38

 

 

Brokered natural gas and marketing revenue was $16.6 million in the year ended December 31, 2018 compared to $3.5 million in the year ended December 31, 2017.  Brokered natural gas and marketing revenue includes revenue we receive as a result of selling natural gas that is not related to our production and from the release of firm transportation capacity.  The increase from the year ended December 31, 2017 to the year ended December 31, 2018 was due to an increase in the amount of firm transportation that was available for brokered gas transactions or release to third parties during the year ended December 31, 2018.

66

Costs and Expenses

We believe some of our expense fluctuations are best analyzed on a unit-of-production, or per Mcfe, basis. The following table presents information about certain of our expenses for the years ended December 31, 2018 and 2017:

 

 

 

Year Ended

December 31,

 

 

 

 

 

 

 

2018

 

 

2017

 

 

Change

 

Operating expenses (in thousands):

 

 

 

 

 

 

 

 

 

 

 

 

Lease operating

 

$

28,289

 

 

$

20,525

 

 

$

7,764

 

Transportation, gathering and compression

 

 

138,766

 

 

 

124,839

 

 

 

13,927

 

Production and ad valorem taxes

 

 

10,141

 

 

 

8,490

 

 

 

1,651

 

Depreciation, depletion, amortization and accretion

 

 

134,940

 

 

 

119,362

 

 

 

15,578

 

General and administrative

 

 

44,389

 

 

 

44,553

 

 

 

(164

)

Operating expenses per Mcfe:

 

 

 

 

 

 

 

 

 

 

 

 

Lease operating

 

$

0.23

 

 

$

0.18

 

 

$

0.05

 

Transportation, gathering and compression

 

 

1.10

 

 

 

1.10

 

 

 

—

 

Production and ad valorem taxes

 

 

0.08

 

 

 

0.07

 

 

 

0.01

 

Depreciation, depletion, amortization and accretion

 

 

1.07

 

 

 

1.05

 

 

 

0.02

 

General and administrative

 

 

0.35

 

 

 

0.39

 

 

 

(0.04

)

 

Lease operating expense was $28.3 million in the year ended December 31, 2018 compared to $20.5 million in the year ended December 31, 2017. Lease operating expense per Mcfe was $0.23 in the year ended December 31, 2018 compared to $0.18 in the year ended December 31, 2017.  The increase of $7.8 million and $0.05 per Mcfe was attributable to increases in producing wells and salt water disposal expenses during the year ended December 31, 2018.  Lease operating expenses include normally recurring expenses to operate our wells and non-recurring workovers and repairs.

Transportation, gathering and compression expense was $138.8 million in the year ended December 31, 2018 compared to $124.8 million in the year ended December 31, 2017.  Transportation, gathering and compression expense per Mcfe was $1.10 in each of the years ended December 31, 2018 and 2017.  The following table details our transportation, gathering and compression expenses for the years ended December 31, 2018 and 2017:

 

 

 

Year Ended

December 31,

 

 

 

 

 

 

 

2018

 

 

2017

 

 

Change

 

Transportation, gathering and compression

   (in thousands):

 

 

 

 

 

 

 

 

 

 

 

 

Gathering, compression and fuel

 

$

42,461

 

 

$

46,466

 

 

$

(4,005

)

Processing and fractionation

 

 

39,132

 

 

 

32,468

 

 

 

6,664

 

Liquids transportation and stabilization

 

 

7,986

 

 

 

6,746

 

 

 

1,240

 

Marketing

 

 

19

 

 

 

27

 

 

 

(8

)

Firm transportation

 

 

49,168

 

 

 

39,132

 

 

 

10,036

 

 

 

$

138,766

 

 

$

124,839

 

 

$

13,927

 

Transportation, gathering and compression per

   Mcfe:

 

 

 

 

 

 

 

 

 

 

 

 

Gathering, compression and fuel

 

$

0.34

 

 

$

0.41

 

 

$

(0.07

)

Processing and fractionation

 

 

0.31

 

 

 

0.29

 

 

 

0.02

 

Liquids transportation and stabilization

 

 

0.06

 

 

 

0.06

 

 

 

—

 

Marketing

 

 

—

 

 

 

—

 

 

 

—

 

Firm transportation

 

 

0.39

 

 

 

0.34

 

 

 

0.05

 

 

 

$

1.10

 

 

$

1.10

 

 

$

—

 

 

67

The increase of $13.9 million in the year ended December 31, 2018 was due to our production growth and increased firm transportation expenses, which increased primarily due to additional capacity that came online during the second half of 2018.  These expenses were consistent on a per unit basis as increased firm transportation and production costs were offset by lower contractual gathering rates.

Production and ad valorem taxes are paid based on market prices and applicable tax rates. Production and ad valorem taxes were $10.1 million in the year ended December 31, 2018 compared to $8.5 million in the year ended December 31, 2017.  Production and ad valorem taxes per Mcfe was $0.08 in the year ended December 31, 2018 compared to $0.07 in the year ended December 31, 2017.  The $1.6 million increase in aggregate production and ad valorem taxes was primarily due to increased production and well count.  The increase of $0.01 on a per unit basis was driven by increased severance taxes associated with our increased liquids production.

Depreciation, depletion, amortization and accretion was approximately $134.9 million for the year ended December 31, 2018 compared to $119.4 million in the year ended December 31, 2017. This $15.6 million increase was primarily due to an increase in production and proved property costs. On a per Mcfe basis, DD&A decreased to $1.07 in the year ended December 31, 2018 from $1.05 in the year ended December 31, 2017, which was primarily due to a higher depletion rate resulting from our reserves increasing at a lower rate than our capital cost.

General and administrative expense was $44.4 million for the year ended December 31, 2018 compared to $44.6 million for the year ended December 31, 2017.  General and administrative expense per Mcfe was $0.35 in the year ended December 31, 2018 compared to $0.39 in the year ended December 31, 2017.  The $0.2 million decrease was primarily due to lower salaries and benefits associated with decreased head count, and lower professional fees partially offset by approximately $4.0 million of expense related to the BRMR Merger.  The decrease of $0.04 per Mcfe was primarily due to fixed costs spread across increased levels of production as of December 31, 2018 compared to December 31, 2017.  General and administrative expense includes $7.9 million and $9.3 million of stock-based compensation expense for the years ended December 31, 2018 and 2017, respectively.

Other Operating Expenses

Our total operating expenses also include other expenses that generally do not trend with production. These expenses include brokered natural gas and marketing expense, exploration, rig termination and standby and (gain) loss on sale of assets. The following table details our other operating expenses for the years ended December 31, 2018 and 2017:

 

 

 

Year Ended

December 31,

 

 

 

 

 

 

 

2018

 

 

2017

 

 

Change

 

Other operating expenses (in thousands):

 

 

 

 

 

 

 

 

 

 

 

 

Brokered natural gas and marketing expense

 

$

16,886

 

 

$

3,191

 

 

$

13,695

 

Exploration

 

 

49,563

 

 

 

50,208

 

 

 

(645

)

Rig termination and standby

 

 

—

 

 

 

1

 

 

 

(1

)

(Gain) loss on sale of assets

 

 

(1,815

)

 

 

(179

)

 

 

(1,636

)

 

Brokered natural gas and marketing expense was $16.9 million in the year ended December 31, 2018 compared to $3.2 million in the year ended December 31, 2017.  Brokered natural gas and marketing expense relate to gas purchases for brokered natural gas that we buy and sell that is not related to our production and firm transportation capacity that is marketed to third parties.  The increase was primarily due to an increase in the amount of firm transportation that was available for brokered gas transactions or release to third parties during the year ended December 31, 2018.

 

68

Exploration expense decreased to $49.6 million in the year ended December 31, 2018 compared to $50.2 million in the year ended December 31, 2017. The following table details our exploration-related expenses for the years ended December 31, 2018 and 2017:

 

 

 

Year Ended

December 31,

 

 

 

 

 

 

 

2018

 

 

2017

 

 

Change

 

Exploration expenses (in thousands):

 

 

 

 

 

 

 

 

 

 

 

 

Geological and geophysical

 

$

1,510

 

 

$

1,098

 

 

$

412

 

Delay rentals

 

 

19,729

 

 

 

17,693

 

 

 

2,036

 

Impairment of unproved properties

 

 

27,608

 

 

 

28,291

 

 

 

(683

)

Dry hole and other

 

 

716

 

 

 

3,126

 

 

 

(2,410

)

 

 

$

49,563

 

 

$

50,208

 

 

$

(645

)

 

Delay rentals were $19.7 million for the year ended December 31, 2018 compared to $17.7 million for the year ended December 31, 2017.  The increase in delay rentals related to converting future lump-sum extension payments into annual delay rentals.

Impairment of unproved properties was $27.6 million for the year ended December 31, 2018 compared to $28.3 million for the year ended December 31, 2017. The decrease in impairment charges during the year ended December 31, 2018 was the result of a decrease in expected lease expirations due to the increase in our planned future drilling activity. As we continue to review our acreage positions and high grade our drilling inventory based on the current commodity price environment, additional leasehold impairments and abandonments may be recorded.

Rig termination and standby expense was less than $0.1 million for the year ended December 31, 2017.  There was no rig termination and standby expense for the year ended December 31, 2018.

Gain on sale of assets was $1.8 million for the year ended December 31, 2018 and $0.2 million for the year ended December 31, 2017, each due to the sale of certain non-core assets.

Other Income (Expense)

Gain (loss) on derivative instruments was ($21.2) million for the year ended December 31, 2018 compared to $45.4 million for the year ended December 31, 2017, primarily due to changes in commodity prices during each year.  Cash payments were approximately $27.0 million and $2.2 million for the derivative instruments that settled during the years ended December 31, 2018 and 2017, respectively.

Interest expense, net was $54.0 million for the year ended December 31, 2018 compared to $49.5 million for year ended December 31, 2017. The increase in interest expense was primarily due to our increased borrowings under our revolving credit facility during the year ended December 31, 2018.

Income tax benefit (expense) was not recognized for the years ended December 31, 2018 and 2017 due to the Company recording a higher valuation allowance related to its pre-tax losses and reducing the valuation allowance to the extent of pre-tax income.

Cash Flows, Capital Resources and Liquidity

Cash Flows

Cash flows from operations are primarily affected by production volumes and commodity prices. Our cash flows from operations also are impacted by changes in working capital. Short-term liquidity needs are satisfied by our operating cash flow, proceeds from asset sales, borrowings under our revolving credit facility, and proceeds from issuances of debt and equity securities. We sell a large portion of our production at the wellhead under floating market contracts.

69

Year Ended December 31, 2019 Compared to the Year Ended December 31, 2018

Net cash provided by operations in the year ended December 31, 2019 was $255.4 million compared to $225.1 million in the year ended December 31, 2018. The increase in cash provided from operating activities reflects working capital changes, operating income, timing of cash receipts and disbursements and the increase in our production during the year-over-year comparative periods.

Net cash used in investing activities in the year ended December 31, 2019 was $335.5 million compared to $266.3 million in the year ended December 31, 2018.

During the year ended December 31, 2019, we:

 

•

spent $349.7 million on capital expenditures for oil and natural gas properties;

 

•

received $2.0 million from assets sales; and

 

•

received $12.9 million as part of the assets acquired in the BRMR Merger.

During the year ended December 31, 2018, we:

 

•

spent $275.6 million on capital expenditures for oil and natural gas properties;

 

•

spent $1.0 million on property and equipment; and

 

•

received $10.4 million of proceeds relating to the sale of assets.

Net cash provided by financing activities in the year ended December 31, 2019 was $86.2 million compared to $29.9 million in the year ended December 31, 2018.

During the year ended December 31, 2019, we:

 

•

borrowed $97.5 million under our revolving credit facility;

 

•

withheld from employees’ shares totaling $6.7 million related to the settlement of equity compensation awards; and

 

•

paid $4.3 million of deferred financing costs related to the refinancing of our revolving credit facility and amendment to the Credit Agreement.

During the year ended December 31, 2018, we:

 

•

borrowed $32.5 million under our revolving credit facility; and

 

•

withheld from employees shares totaling $1.3 million related to the settlement of equity compensation awards.

Year Ended December 31, 2018 Compared to the Year Ended December 31, 2017

Net cash provided by operations in the year ended December 31, 2018 was $225.1 million compared to $112.7 million in the year ended December 31, 2017. The increase in cash provided from operating activities reflects  working capital changes, operating income and the timing of cash receipts and disbursements during the year-over-year comparative periods.

Net cash used in investing activities in the year ended December 31, 2018 was $266.3 million compared to $292.5 million in the year ended December 31, 2017.

During the year ended December 31, 2018, we:

 

•

spent $275.6 million on capital expenditures for oil and natural gas properties;

 

•

spent $1.0 million on property and equipment; and

70

 

•

received $10.4 million of proceeds relating to the sale of assets.

During the year ended December 31, 2017, we:

 

•

spent $291.8 million on capital expenditures for oil and natural gas properties;

 

•

spent $2.0 million on property and equipment; and

 

•

received $1.3 million of proceeds relating to the sale of assets.

Net cash provided by (used in) financing activities in the year ended December 31, 2018 was $29.9 million compared to ($4.3) million in the year ended December 31, 2017.

During the year ended December 31, 2018, we:

 

•

borrowed $32.5 million under our revolving credit facility; and

 

•

withheld from employees shares totaling $1.3 million related to the settlement of equity compensation awards.

During the year ended December 31, 2017, we:

 

•

paid $1.8 million in financing costs associated with an amendment to the Credit Agreement that, among other things, increased the borrowing base under the revolving credit facility; and

 

•

withheld from employees’ shares totaling $2.0 million related to the settlement of equity compensation awards.

Liquidity and Capital Resources

Our main sources of liquidity and capital resources are internally generated cash flow from operations, asset sales, borrowings under our revolving credit facility and access to the debt and equity capital markets. We must find new and develop existing reserves to maintain and grow our production and cash flows. We accomplish this primarily through successful drilling programs, which requires substantial capital expenditures. We periodically review capital expenditures and adjust our budget based on liquidity, drilling results, leasehold acquisition opportunities, and commodity prices. We believe that our existing cash on hand, operating cash flow and available proceeds under our revolving credit facility will be adequate to meet our capital and operating requirements for 2020.

Future success in growing reserves and production will be highly dependent on capital resources available and the success of finding or acquiring additional reserves. We will continue using net cash on hand, cash flows from operations and proceeds available under our revolving credit facility to satisfy near-term financial obligations and liquidity needs, and as necessary, we will seek additional sources of debt or equity to fund these requirements. Longer-term cash flows are subject to a number of variables including the level of production and prices we receive for our production as well as various economic conditions that have historically affected the natural gas and oil business. Our ability to expand our reserve base is, in part, dependent on obtaining sufficient capital through internal cash flow, bank borrowings, asset sales, joint venture transactions or the issuance of debt or equity securities. There can be no assurance that internal cash flow and other capital sources will provide sufficient funds to maintain capital expenditures that we believe are necessary to offset inherent declines in production and proven reserves.

As of December 31, 2019, we were in compliance with all of our debt covenants under the Credit Agreement and the indenture governing our 8.875% senior unsecured notes due 2023. Further, based on our current forecast and activity levels, we expect to remain in compliance with all such debt covenants for the next twelve months. However, if oil and natural gas prices decrease to lower levels, we are likely to generate lower operating cash flows, which would make it more difficult for us to remain in compliance with all of our debt covenants, including requirements with respect to working capital and interest coverage ratios. This could negatively impact our ability to maintain sufficient liquidity and access to capital resources.

71

Credit Arrangements

Long-term debt at December 31, 2019 and 2018, excluding discount, totaled $640.5 million and $543.0 million, respectively.  Long-term debt includes both the senior unsecured notes outstanding and any outstanding borrowings against our revolving credit facility.

Information related to our credit arrangements is described in Note 9— Debt to our Consolidated Financial Statements and is incorporated herein by reference.

Commodity Hedging Activities

Our primary market risk exposure is in the prices we receive for our natural gas, NGLs and oil production. Realized pricing is primarily driven by the spot regional market prices applicable to our U.S. natural gas, NGLs and oil production. Pricing for natural gas, NGLs and oil production has been volatile and unpredictable for several years, and we expect this volatility to continue in the future. The prices we receive for production depend on many factors outside of our control, including volatility in the differences between product prices at sales points and the applicable index price.

To mitigate the potential negative impact on our cash flow caused by changes in natural gas, NGLs and oil prices, we may enter into financial commodity derivative contracts to ensure that we receive minimum prices for a portion of our future natural gas production when management believes that favorable future prices can be secured. We typically hedge the NYMEX Henry Hub price for natural gas, the WTI price for oil and a NGLs basket based on prices at Mont Belvieu, Texas.

Our hedging activities are intended to support natural gas, NGLs and oil prices at targeted levels and to manage our exposure to price fluctuations. The counterparty is required to make a payment to us for the difference between the floor price specified in the contract and the settlement price, which is based on market prices on the settlement date, if the settlement price is below the floor price. We are required to make a payment to the counterparty for the difference between the ceiling price and the settlement price if the ceiling price is below the settlement price. These contracts may include price swaps whereby we will receive a fixed price for our production and pay a variable market price to the contract counterparty, zero cost collars that set a floor and ceiling price for the hedged production, and puts which require us to pay a premium either up front or at settlement and allow us to receive a fixed price at our option if the put price is above the market price. Information regarding the derivative contracts we had entered into as of December 31, 2019 is set forth in Note 7— Derivative Instruments to our Consolidated Financial Statements.

 

By using derivative instruments to hedge exposures to changes in commodity prices, we expose ourselves to the credit risk of our counterparties. Credit risk is the potential failure of the counterparty to perform under the terms of the derivative contract. When the fair value of a derivative contract is positive, the counterparty is expected to owe us, which creates credit risk. To minimize the credit risk in derivative instruments, it is our policy to enter into derivative contracts only with counterparties that are creditworthy financial institutions deemed by management as competent and competitive market makers. The creditworthiness of our counterparties is subject to periodic review. As of December 31, 2019, we had derivative instruments in place with Bank of Montreal, BP Energy Company, Capital One N.A., Citibank, Citizens Bank N.A., EDF Energy, J Aron, KeyBank N.A., Morgan Stanley, Royal Bank of Canada, and Wells Fargo. We believe all of such institutions currently are an acceptable credit risk. As of December 31, 2019, we did not have any past due receivables from counterparties.

Capital Requirements

Our primary needs for cash are for exploration, development and acquisition of natural gas and oil properties and repayment of principal and interest on outstanding debt.  Our Board of Directors recently approved an initial capital budget for 2020 of between approximately $190 - $210 million, allocated approximately 95% for drilling and completions activities and approximately 5% for land capital requirements. The 2020 capital budget is expected to be substantially funded through internally generated cash flows, the Company’s current cash balance and borrowings under the revolving credit facility.  The actual amount and timing of our future capital expenditures may differ materially from our estimates as a result of, among other things, natural gas, NGLs and oil prices, actual drilling results, the availability of drilling rigs and other services and equipment, and regulatory, technological and

72

competitive developments. A reduction in natural gas, NGLs or oil prices from current levels may result in a decrease in our actual capital expenditures, which would negatively impact our ability to grow production and our proved reserves as well as our ability to maintain compliance with our debt covenants. Our financing needs may require us to alter or increase our capitalization substantially through the issuance of debt or equity securities, additional borrowings under our revolving credit facility or the sale of assets.

In addition, we may from time to time seek to pay down, retire or repurchase our outstanding debt using cash or through exchanges of other debt or equity securities, in open market purchases, privately negotiated transactions or otherwise. Such repurchases or exchanges, if any, will depend on available funds, prevailing market conditions, our liquidity requirements, contractual restrictions in our Credit Agreement and other factors.

Capitalization

As of December 31, 2019 and 2018, our total debt, excluding debt discount and issuance costs, and capitalization were as follows (in millions):

 

 

 

December 31, 2019

 

 

December 31, 2018

 

Senior unsecured notes

 

$

510.5

 

 

$

510.5

 

Revolving credit facility

 

 

130.0

 

 

 

32.5

 

Stockholders' equity

 

 

997.1

 

 

 

687.5

 

Total capitalization

 

$

1,637.6

 

 

$

1,230.5

 

 

Cash Contractual Obligations

Our contractual obligations include long-term debt, operating leases, drilling commitments, firm transportation, gas processing, gathering and compressions services, and asset retirement obligations. As of December 31, 2019 and 2018, we did not have significant capital leases, any significant off-balance sheet debt or other such unrecorded obligations, and we have not guaranteed any debt of any unrelated party. Our Consolidated Balance Sheet at December 31, 2019 reflects accrued interest payable of $21.3 million, compared to $21.7 million as of December 31, 2018. We paid the accrued interest balance in January 2020.

We have a contract for the service of one rig, which expires in October 2021, with the option to extend.  We have also entered into firm transportation agreements with various pipelines in order to facilitate the delivery of production to market. These contracts commit us to transport minimum daily natural gas volumes at a negotiated rate or pay for any deficiencies at a specified reservation fee rate. We have also agreed to certain minimum commitments under long-term gas processing and gathering agreements as well as various gas compression agreements. For additional discussion, see “Items 1 and 2. Business and Properties—Midstream Agreements”.

Other

We lease acreage that is generally subject to lease expiration if operations are not commenced within a specified period, generally 5 years and approximately 56% of our leases in the Utica Core Area have a 3-5 year extension at our option. Based on our evaluation of prospective economics, including the cost of infrastructure to connect production, we have allowed acreage to expire and may allow additional acreage to expire in the future. To date, our expenditures to comply with environmental or safety regulations have not been a significant component of our cost structure and are not expected to be significant in the future. However, new regulations, enforcement policies, claims for damages or other events could result in significant future costs.

Interest Rates

At December 31, 2019 and 2018, we had $510.5 million of senior unsecured notes outstanding, excluding discounts, which bore interest at a fixed cash interest rate of 8.875%, due semi-annually from the date of issuance.

Information related to our interest rates is described in Note 9— Debt to our Consolidated Financial Statements and is incorporated herein by reference.

73

Off-Balance Sheet Arrangements

We do not currently utilize any off-balance sheet arrangements with unconsolidated entities to enhance our liquidity or capital resource position, or for any other purpose. However, as is customary in the oil and gas industry, we have various contractual work commitments which are described above under “—Cash Contractual Obligations”.

Inflation and Changes in Prices

Our revenues, the value of our assets and our ability to obtain bank loans or additional capital on attractive terms have been and will continue to be affected by changes in natural gas, NGLs and oil prices and the costs to produce our reserves. Natural gas, NGLs and oil prices are subject to significant fluctuations that are beyond our ability to control or predict. Although certain of our costs and expenses are affected by general inflation, it does not normally have a significant effect on our business. We expect costs in fiscal 2020 to continue to be a function of supply and demand.  Further strengthening of commodity prices could stimulate demand for ancillary services causing services costs to increase.  In the near term, the majority of our service costs are expected to remain flat in 2020 due to previously negotiated drilling, stimulation, and rentals contracts. Along with these contacts, we have secured quality service equipment and tenured personnel to limit our exposure to increasing service costs and improve operational efficiencies.

Critical Accounting Estimates

Our discussion and analysis of our financial condition and results of operations are based upon Consolidated Financial Statements, which have been prepared in accordance with GAAP. The preparation of our financial statements requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at year-end, the reported amounts of revenues and expenses during the year and proved natural gas and oil reserves. Some accounting policies involve judgments and uncertainties to such an extent there is a reasonable likelihood that materially different amounts could have been reported under different conditions, or if different assumptions had been used. We evaluate our estimates and assumptions on a regular basis. We base our estimates on historical experience and various other assumptions that we believe are reasonable under the circumstances, the results of which form the basis for making judgments about the carrying value of assets and liabilities that are not readily apparent from other sources. Actual results could differ from the estimates and assumptions used.

Certain accounting estimates are considered to be critical if (a) the nature of the estimates and assumptions is material due to the level of subjectivity and judgment necessary to account for highly uncertain matters or the susceptibility of such matters to changes; and (b) the impact of the estimates and assumptions on financial condition or operating performance is material.

Natural Gas and Oil Properties

We follow the successful efforts method of accounting for natural gas and oil producing activities. Unsuccessful exploration drilling costs are expensed and can have a significant effect on reported operating results. Successful exploration drilling costs and all development costs are capitalized and systematically charged to expense using the units of production method based on proved developed natural gas and oil reserves as estimated by our engineers and audited by independent engineers. Costs incurred for exploratory wells that find reserves that cannot yet be classified as proved are capitalized on our Consolidated Balance Sheet if (a) the well has found a sufficient quantity of reserves to justify its completion as a producing well; and (b) we are making sufficient progress assessing the reserves and the economic and operating viability of the project. Proven property leasehold costs are amortized to expense using the units of production method based on total proved reserves. Properties are assessed for impairment as circumstances warrant (at least annually) and impairments to value are charged to expense. The successful efforts method inherently relies upon the estimation of proved reserves, which includes proved developed and proved undeveloped volumes.

Proved reserves are defined by the SEC as those volumes of natural gas, NGLs, condensate and crude oil that geological and engineering data demonstrate with reasonable certainty are economically recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed reserves are volumes

74

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. Although our engineers are knowledgeable of and follow the guidelines for reserves established by the SEC, including the rule revisions designed to modernize the oil and gas company reserves reporting requirements which were adopted effective December 31, 2009, the estimation of reserves requires engineers to make a significant number of assumptions based on professional judgment. Reserve estimates are updated at least annually and consider recent production levels and other technical information. Estimated reserves are often subject to future revisions, which could be substantial, based on the availability of additional information, including: reservoir performance, new geological and geophysical data, additional drilling, technological advancements, price and cost changes and other economic factors. Changes in natural gas, NGLs and oil prices can lead to a decision to start-up or shut-in production, which can lead to revisions to reserve quantities. Reserve revisions in turn cause adjustments in our depletion rates. We cannot predict what reserve revisions may be required in future periods. Reserve estimates are reviewed and approved by our Executive Vice President, Resource Planning and Development who reports directly to our President and Chief Executive Officer. To further ensure the reliability of our reserve estimates, we engage independent petroleum engineers to prepare our estimates of proved reserves at least annually. SIS, our independent petroleum engineers for the years ended December 31, 2019 and 2018, prepared 100% of our reserves in 2019 and 2018 and NSAI, our independent petroleum engineers, for all prior years, prepared 100% of our reserves in 2017, 2016, 2015, and 2014. For additional discussion, “See Items 1 and 2. Business and Properties—Oil and Natural Gas Data—Proved Reserves”.

Depletion rates are determined based on reserve quantity estimates and the capitalized costs of producing properties. As the estimated reserves are adjusted, the depletion expense for a property will change, assuming no change in production volumes or the capitalized costs. While total depletion expense for the life of a property is limited to the property’s total cost, proved reserve revisions result in a change in the timing of when depletion expense is recognized. Downward revisions of proved reserves may result in an acceleration of depletion expense, while upward revisions tend to lower the rate of depletion expense recognition. Estimated reserves are used as the basis for calculating the expected future cash flows from property asset groups, which are used to determine whether that property may be impaired. Reserves are also used to estimate the supplemental disclosure of the standardized measure of discounted future net cash flows relating to natural gas and oil producing activities and reserve quantities in Note 19— Supplemental Oil and Gas Information to our Consolidated Financial Statements. Changes in the estimated reserves are considered a change in estimate for accounting purposes and are reflected on a prospective basis.

We monitor our long-lived assets recorded in natural gas and oil properties in our Consolidated Balance Sheets to ensure they are fairly presented. We must evaluate our properties for potential impairment when circumstances indicate that the carrying value of an asset could exceed its fair value. A significant amount of judgment is involved in performing these evaluations since the results are based on estimated future events. Such events include a projection of future natural gas, NGLs and oil prices, an estimate of the ultimate amount of recoverable natural gas, NGLs and oil reserves that will be produced from the property asset groups future production, future production costs, future abandonment costs, and future inflation. The need to test a property asset group for impairment can be based on several factors, including a significant reduction in sales prices for natural gas, NGLs and/or oil, unfavorable adjustments to reserves, physical damage to production equipment and facilities, a change in costs, or other changes to contracts or environmental regulations. Our natural gas and oil properties are reviewed for potential impairments at the lowest levels for which there are identifiable cash flows that are largely independent of other groups of assets. All of these factors must be considered when testing a property asset group carrying value for impairment.

75

The review is done by determining if the historical cost of proved and unproved properties less the applicable accumulated depreciation, depletion, amortization and accretion is less than the estimated undiscounted future net cash flows. The expected undiscounted future net cash flows are estimated based on our plans to produce and develop reserves. Expected undiscounted future net cash inflows from the sale of produced reserves are calculated based on estimated future prices and estimated operating and development costs. We estimate prices based upon market related information including published futures prices. The estimated future level of production, which is based on proved and risk adjusted probable reserves, has assumptions surrounding the future levels of prices and costs, field decline rates, market demand and supply and the economic and regulatory climates. In certain circumstances, we also consider potential sales of properties to third parties in our estimates of undiscounted future cash flows. When the carrying value exceeds the sum of undiscounted future net cash flows, an impairment loss is recognized for the difference between the estimated fair market value (as determined by discounted future net cash flows using a discount rate similar to that used by market participants) and the carrying value of the asset. We cannot predict whether impairment charges may be required in the future.

We believe that a sensitivity analysis regarding the effect of changes in assumptions on estimated impairment is impractical to provide because of the number of assumptions and variables involved which have interdependent effects on the potential outcome. If natural gas, NGLs and oil prices decrease or drilling efforts are unsuccessful, we may be required to record additional impairments.

We evaluate our unproved property investment periodically for impairment. The majority of these costs generally relate to the acquisition of leaseholds. The costs are capitalized and evaluated (at least quarterly) as to recoverability, based on changes brought about by economic factors and potential shifts in business strategy employed by management. Impairment of a significant portion of our unproved properties is assessed and amortized on an aggregate basis based on our average holding period, expected forfeiture rate and anticipated drilling success. Potential impairment of individually significant unproved property is assessed on a property-by-property basis considering a combination of time, geologic and engineering factors.

Acquisitions

As part of our business strategy, we periodically pursue the acquisition of oil and natural gas properties. The purchase price in an acquisition is allocated to the assets acquired and liabilities assumed based on their relative fair values as of the acquisition date, which may occur many months after the announcement date. Therefore, while the consideration to be paid may be fixed, the fair value of the assets acquired and liabilities assumed is subject to change during the period between the announcement date and the acquisition date. Our most significant estimates in our allocation typically relate to the value assigned to future recoverable oil and natural gas reserves and unproved properties. As the allocation of the purchase price is subject to significant estimates and subjective judgments, the accuracy of this assessment is inherently uncertain.

Asset Retirement Obligations

We have significant obligations to remove tangible equipment and restore land at the end of natural gas and oil production operations. Removal and restoration obligations are primarily associated with plugging and abandoning wells. Estimating the future asset removal costs is difficult and requires us to make estimates and judgments because most of the removal obligations are many years in the future and contracts and regulations often have vague descriptions of what constitutes removal. Asset removal technologies and costs are constantly changing, as are regulatory, political, environmental, safety and public relations considerations.

Inherent in the fair value calculation are numerous assumptions and judgments including the ultimate retirement costs, inflation factors, credit-adjusted discount rates, timing of retirement, and changes in the legal, regulatory, environmental and political environments. To the extent future revisions to these assumptions impact the present value of the existing asset retirement obligation (“ARO”), a corresponding adjustment is made to the natural gas and oil property balance. For example, as we analyze actual plugging and abandonment in formation, we may revise our estimate of current costs, the assumed annual inflation of the costs and/or the assumed productive lives of our wells. In addition, increases in the discounted ARO liability resulting from the passage of time are reflected as accretion expense, a component of depreciation, depletion, amortization and accretion in the accompanying Consolidated Statements of Operations. Because of the subjectivity of assumptions and the relatively long lives of most of our wells, the costs to ultimately retire our wells may vary significantly from prior estimates.

76

Revenue Recognition

Information related to revenue recognition is described in Note 2— Summary of Significant Accounting Policies to our Consolidated Financial Statements and is incorporated herein by reference.

Recent Accounting Pronouncements

Information related to recent accounting pronouncements is described in Note 2— Summary of Significant Accounting Policies to our Consolidated Financial Statements and is incorporated herein by reference.

 

 

Item 7A.

Quantitative and Qualitative Disclosures About Market Risk

Not applicable to smaller reporting companies.

 

 

Item 8.

Financial Statements and Supplementary Data

The Report of Independent Registered Public Accounting Firm, Consolidated Financial Statements and supplementary financial data required for this Item are set forth beginning on page F-1 of this report and are incorporated herein by reference.

 

 

Item 9.

Changes in and Disagreements With Accountants on Accounting and Financial Disclosure

Not applicable.

 

 

Item 9A.

Controls and Procedures

Evaluation of Disclosure Controls and Procedures

The Company’s management carried out an evaluation (as required by Rule 13a-15(b) of the Exchange Act), with the participation of the Company’s President and Chief Executive Officer and Executive Vice President and Chief Financial Officer, of the effectiveness of the design and operation of the Company’s disclosure controls and procedures (as defined in Rule 13a-15(e) of the Exchange Act), as of the end of the period covered by this Annual Report. Based upon this evaluation, the Company’s President and Chief Executive Officer and Executive Vice President and Chief Financial Officer concluded that the Company’s disclosure controls and procedures were effective as of the end of the period covered by this Annual Report, such that the information relating to the Company and its consolidated subsidiaries required to be disclosed by the Company in the reports that it files or submits under the Exchange Act (i) is recorded, processed, summarized, and reported, within the time periods specified in the SEC’s rules and forms, and (ii) is accumulated and communicated to the Company’s management, including its principal executive and financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure.

Changes in Internal Controls

There has been no change in our internal control over financial reporting (as defined in Rules 13a-15(f) and 15(d)-15(f) under the Exchange Act) during the fourth quarter of 2019 that has materially affected, or is reasonable likely to materially affect, the Company’s internal control over financial reporting.

Management’s Annual Report on Internal Control Over Financial Reporting

The management of the Company is responsible for establishing and maintaining adequate internal control over financial reporting. The Company’s internal control system is designed to provide reasonable assurance to its management and Board of Directors regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. All internal control systems, no matter how well designed, have inherent limitations. Accordingly, even effective controls can provide only reasonable assurance with respect to financial statement preparation and presentation.

77

The Company’s management assessed the effectiveness of its internal control over financial reporting as of December 31, 2019. In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission in Internal Control-Integrated Framework (2013). Based on this assessment, management concluded that the Company maintained effective internal control over financial reporting as of December 31, 2019.

Grant Thornton LLP, the independent registered public accounting firm that audited the Consolidated Financial Statements of the Company included in this annual report on Form 10-K, has issued its report on the effectiveness of the Company’s internal control over financial reporting at December 31, 2019. The report, which expresses an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting at December 31, 2019, is included in this Item under the heading “Report of Independent Registered Public Accounting Firm.”


78

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

 

Board of Directors and Stockholders

Montage Resources Corporation

Opinion on internal control over financial reporting

We have audited the internal control over financial reporting of Montage Resources Corporation (a Delaware corporation) and subsidiaries (the “Company”) as of December 31, 2019, based on criteria established in the 2013 Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”). In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2019, based on criteria established in the 2013 Internal Control—Integrated Framework issued by COSO.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”), the consolidated financial statements of the Company as of and for the year ended December 31, 2019, and our report dated March 10, 2020 expressed an unqualified opinion on those financial statements.

Basis for opinion

The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Annual Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

Definition and limitations of internal control over financial reporting

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

 

/s/ GRANT THORNTON LLP

 

Pittsburgh, Pennsylvania

March 10, 2020

 


79

Item 9B.

Other Information

Not applicable.

80

PART III

 

 

Item 10.

Directors, Executive Officers and Corporate Governance

Pursuant to General Instruction G(3) to Form 10-K, we incorporate by reference into this Item the information to be disclosed in our definitive proxy statement for our 2020 Annual Meeting of Stockholders.

 

 

Item 11.

Executive Compensation

Pursuant to General Instruction G(3) to Form 10-K, we incorporate by reference into this Item the information to be disclosed in our definitive proxy statement for our 2020 Annual Meeting of Stockholders.

 

 

Item 12.

Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

Pursuant to General Instruction G(3) to Form 10-K, we incorporate by reference into this Item the information to be disclosed in our definitive proxy statement for our 2020 Annual Meeting of Stockholders.

 

 

Item 13.

Pursuant to General Instruction G(3) to Form 10-K, we incorporate by reference into this Item the information to be disclosed in our definitive proxy statement for our 2020 Annual Meeting of Stockholders.

 

 

Item 14.

Principal Accounting Fees and Services

Pursuant to General Instruction G(3) to Form 10-K, we incorporate by reference into this Item the information to be disclosed in our definitive proxy statement for our 2020 Annual Meeting of Stockholders.

 

81

PART IV

 

Item 15.

Exhibits, Financial Statement Schedules

 

(1)

Financial Statements:

The Consolidated Financial Statements are listed on the Index to Financial Statements to this report beginning on page F-1.

 

(2)

Financial Statement Schedules:

No financial statement schedules are submitted because of the absence of the conditions under which they are required, the required information is insignificant or because the required information is included in the Consolidated Financial Statements.

 

(3)

Exhibits:

The following exhibits are filed as part of this Annual Report.

 

 

82

EXHIBIT INDEX

 

Exhibit No.

 

Description

 

 

 

    2.1#

 

Purchase and Sale Agreement, dated December 8, 2017, between Travis Peak Resources, LLC, Eclipse Resources-PA, LP, and Eclipse Resources Corporation (incorporated by reference to Exhibit 2.1 to the Company’s Current Report on Form 8-K filed with the SEC on December 12, 2017).

 

 

 

    2.2#

 

Option Agreement, dated as of December 8, 2017, by and among Cardinal Midstream II, LLC, Cardinal NE Holdings, LLC, Cardinal NE Midstream, LLC, Eclipse Resources Corporation, Eclipse Resources Midstream, LP, and Eclipse Resources-PA, LP (incorporated by reference to Exhibit 2.2 to the Company’s Current Report on Form 8-K filed with the SEC on December 12, 2017).

 

 

 

    2.3#

 

Participation Agreement, dated December 22, 2017, by and among Eclipse Resources I, LP, Eclipse Resources-Ohio, LLC, and SEG-ECR LLC (incorporated by reference to Exhibit 2.1 to the Company’s Current Report on Form 8-K filed with the SEC on December 28, 2017). +

 

 

 

    2.4#

 

Agreement and Plan of Merger, dated as of August 25, 2018, among Eclipse Resources Corporation, Everest Merger Sub Inc., and Blue Ridge Mountain Resources, Inc. (incorporated by reference to Exhibit 2.1 to the Company’s Current Report on Form 8-K filed with the SEC on August 27, 2018).

 

 

 

    2.5

 

Amendment No. 1 to Agreement and Plan of Merger, dated as of January 7, 2019, among Eclipse Resources Corporation, Everest Merger Sub Inc., and Blue Ridge Mountain Resources, Inc. (incorporated by reference to Exhibit 2.2 to the Company’s Current Report on Form 8-K filed with the SEC on January 7, 2019).

 

 

 

    3.1

 

Second Amended and Restated Certificate of Incorporation of Montage Resources Corporation (incorporated by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K filed with the SEC on March 6, 2019).

 

 

 

    3.2

 

Second Amended and Restated Bylaws of Montage Resources Corporation (incorporated by reference to Exhibit 3.2 to the Company’s Current Report on Form 8-K filed with the SEC on March 6, 2019).

 

 

 

    3.3

 

Certificate of Ownership and Merger, filed with the Secretary of State of the State of Delaware with an effective date of February 28, 2019 (incorporated by reference to Exhibit 3.3 to the Company’s Current Report on Form 8-K filed with the SEC on March 6, 2019).

 

 

 

    4.1

 

Amended and Restated Registration Rights Agreement, dated January 28, 2015, by and among Eclipse Resources Corporation, Eclipse Resources Holdings, L.P., CKH Partners II, L.P., The Hulburt Family II Limited Partnership, Kirkwood Capital, L.P., EnCap Energy Capital Fund VIII, L.P., EnCap Energy Capital Fund VIII Co-Investors, L.P., EnCap Energy Capital Fund IX, L.P., Eclipse Management, L.P., Buckeye Investors L.P., GSO Capital Opportunities Fund II (Luxembourg) S.à.r.l., Fir Tree Value Master Fund, L.P., Luxor Capital Partners, LP and Luxor Capital Partners Offshore Master Fund, LP (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the SEC on January 29, 2015).

 

 

 

    4.2

 

Specimen Common Stock Certificate of Montage Resources Corporation (incorporated by reference to Exhibit 4.2 to the Company’s Annual Report on Form 10-K filed with the SEC on March 15, 2019).

 

 

 

    4.3

 

Indenture, dated as of July 6, 2015, between Eclipse Resources Corporation, the guarantors party thereto and Deutsche Bank Trust Company Americas, as trustee (incorporated by reference to Exhibit 4.1 to the Company’s Current Report on Form 8-K filed with the SEC on July 8, 2015).

 

 

 

    4.4

 

Registration Rights Agreement, dated as of January 18, 2018, by and among Eclipse Resources Corporation, Eclipse Resources-PA, LP, and Travis Peak Resources, LLC (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the SEC on January 22, 2018).

 

 

 

    4.5*

 

Description of Securities Registered Under Section 12 of the Securities Exchange Act of 1934, as amended.

 

 

 

83

Exhibit No.

 

Description

 

 

 

  10.1

 

Second Amended and Restated Credit Agreement, dated as of June 11, 2015, by and among Eclipse Resources Corporation, as borrower, Bank of Montreal, as administrative agent, and each of the lenders party thereto (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the SEC on June 12, 2015).

 

 

 

  10.2

 

First Amendment to Second Amended and Restated Credit Agreement, dated January 21, 2016, by and among Eclipse Resources Corporation, as borrower, Bank of Montreal, as administrative agent, and each of the lenders party thereto (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the SEC on January 25, 2016).

 

 

 

  10.3

 

Second Amendment to Second Amended and Restated Credit Agreement, dated as of February 24, 2016, by and among Eclipse Resources Corporation, as borrower, Bank of Montreal, as administrative agent, and each of the lenders party thereto (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the SEC on February 26, 2016).

 

 

 

  10.4

 

Third Amendment to Second Amended and Restated Credit Agreement, dated as of February 24, 2017, by and among Eclipse Resources Corporation, as borrower, Bank of Montreal, as administrative agent, and each of the lenders party thereto (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the SEC on March 2, 2017).

 

 

 

  10.5

 

Fourth Amendment to Second Amended and Restated Credit Agreement, dated as of August 1, 2017, by and among Eclipse Resources Corporation, as borrower, Bank of Montreal, as administrative agent, and each of the lenders party thereto (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the SEC on August 7, 2017).

 

 

 

  10.6

 

Third Amended and Restated Credit Agreement, dated as of February 28, 2019, among Montage Resources Corporation, Bank of Montreal, as administrative agent, the lenders party thereto, and BMO Capital Markets Corp., Capital One, National Association, and KeyBank National Association, as joint lead arrangers and joint bookrunners  (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the SEC on March 6, 2019).  

 

 

 

  10.7

 

First Amendment to Third Amended and Restated Credit Agreement, dated as of September 19, 2019, by and among Montage Resources Corporation, as borrower, Bank of Montreal, as administrative agent, and each of the lenders party thereto (incorporated by reference to Exhibit 10.1 to the Company’s Quarterly Report on Form 10-Q filed with the SEC on November 8, 2019).

 

 

 

  10.8

 

Second Amendment to Third Amended and Restated Credit Agreement, dated as of November 11, 2019, by and among Montage Resources Corporation, as borrower, Bank of Montreal, as administrative agent, and each of the lenders party thereto (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the SEC on November 15, 2019).

 

 

 

  10.9†

 

Eclipse Resources Corporation 2014 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the SEC on June 24, 2014).

 

 

 

  10.10†

 

Eclipse Resources Corporation 2014 Long-Term Incentive Plan, as amended by the First Amendment (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the SEC on May 18, 2017).

 

 

 

  10.11†

 

Montage Resources Corporation 2019 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the SEC on June 20, 2019).

 

 

 

  10.12

 

Master Reorganization Agreement, dated June 6, 2014, by and among Eclipse Resources I, LP, Eclipse GP, LLC, EnCap Energy Capital Fund VIII, L.P., EnCap Energy Capital Fund VIII Co-Investors, L.P., EnCap Energy Capital Fund IX, L.P., CKH Partners II, L.P., The Hulburt Family II Limited Partnership, Kirkwood Capital, L.P., Eclipse Management, L.P., Eclipse Resources Holdings, L.P., Eclipse Resources Corporation and Benjamin W. Hulburt, Christopher K. Hulburt and Thomas S. Liberatore (incorporated by reference to Exhibit 10.9 to Amendment No. 2 to the Company’s Registration Statement on Form S-1 filed with the SEC on June 9, 2014).

 

 

 

  10.13†

 

Form of Indemnification Agreement for Eclipse Resources Corporation Officers and Directors (incorporated by reference to Exhibit 10.10 to Amendment No. 1 to the Company’s Registration Statement on Form S-1 filed with the SEC on June 2, 2014).

84

Exhibit No.

 

Description

 

 

 

 

 

 

  10.14†

 

Amended and Restated Executive Employment Agreement, dated as of August 17, 2017, by and between Eclipse Resources Corporation and Benjamin W. Hulburt (incorporated by referenced to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the SEC on August 18, 2017).

 

 

 

  10.15†

 

Amended and Restated Executive Employment Agreement, dated as of August 17, 2017, by and between Eclipse Resources Corporation and Matthew R. DeNezza (incorporated by referenced to Exhibit 10.2 to the Company’s Current Report on Form 8-K filed with the SEC on August 18, 2017).

 

 

 

  10.16†

 

Amended and Restated Executive Employment Agreement, dated as of August 17, 2017, by and between Eclipse Resources Corporation and Christopher K. Hulburt (incorporated by referenced to Exhibit 10.3 to the Company’s Current Report on Form 8-K filed with the SEC on August 18, 2017).

 

 

 

  10.17†

 

Amended and Restated Executive Employment Agreement, dated as of January 1, 2017, by and between Eclipse Resources Corporation and Oleg Tolmachev (incorporated by referenced to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the SEC on January 3, 2017).

 

 

 

  10.18†

 

Retention Agreement, dated as of February 28, 2019, by and between Montage Resources Corporation and Oleg Tolmachev (incorporated by reference to Exhibit 10.3 to the Company’s Quarterly Report on Form 10-Q filed with the SEC on May 9, 2019).

 

 

 

  10.19†

 

Executive Employment Agreement, effective as of March 1, 2019, by and between Montage Resources Corporation and John K. Reinhart (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the SEC on April 16, 2019).

 

 

 

  10.20†

 

Executive Employment Agreement, effective as of March 1, 2019, by and between Montage Resources Corporation and Michael L. Hodges (incorporated by reference to Exhibit 10.2 to the Company’s Current Report on Form 8-K filed with the SEC on April 16, 2019).

 

 

 

  10.21†

 

Executive Employment Agreement, effective as of June 25, 2019, by and between Montage Resources Corporation and Timothy J. Loos (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the SEC on June 28, 2019).

 

 

 

  10.22†

 

Executive Employment Agreement, effective as of March 1, 2019, by and between Montage Resources Corporation and Oleg E. Tolmachev (incorporated by reference to Exhibit 10.4 to the Company’s Quarterly Report on Form 10-Q filed with the SEC on August 8, 2019).

 

 

 

  10.23†

 

Executive Employment Agreement, effective as of March 1, 2019, by and between Montage Resources Corporation and Matthew H. Rucker (incorporated by reference to Exhibit 10.5 to the Company’s Quarterly Report on Form 10-Q filed with the SEC on August 8, 2019).

 

 

 

  10.24†

 

Executive Employment Agreement, effective as of March 1, 2019, by and between Montage Resources Corporation and Paul M. Johnston (incorporated by reference to Exhibit 10.6 to the Company’s Quarterly Report on Form 10-Q filed with the SEC on August 8, 2019).

 

 

 

  10.25†

 

Montage Resources Corporation Non-Employee Director Compensation Policy (incorporated by reference to Exhibit 10.8 to the Company’s Quarterly Report on Form 10-Q filed with the SEC on August 8, 2019).

 

 

 

  10.26†

 

Restricted Stock Award Agreement, effective as of February 28, 2019, by and between Montage Resources Corporation and Oleg E. Tolmachev (incorporated by reference to Exhibit 10.9 to the Company’s Quarterly Report on Form 10-Q filed with the SEC on August 8, 2019).

 

 

 

  10.27

 

Securities Purchase Agreement, dated as of December 27, 2014, by and between Eclipse Resources Corporation, CKH Partners II, L.P., The Hulburt Family II Limited Partnership, Kirkwood Capital, L.P., EnCap Energy Capital Fund VIII, L.P., EnCap Energy Capital Fund VIII Co-Investors, L.P., EnCap Energy Capital Fund IX, L.P., Buckeye Investors L.P., GSO Capital Opportunities Fund II L.P., GSO Eclipse Holdings I LP, Fir Tree Value Master Fund, L.P., Luxor Capital Partners, LP and Luxor Capital Partners Offshore Master Fund, LP. (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the SEC on December 29, 2014).

 

 

 

  10.28†

 

Form of Restricted Stock Unit Award Agreement for Employees (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the SEC on March 2, 2016).

85

Exhibit No.

 

Description

 

 

 

 

 

 

  10.29†

 

Form of Performance Unit Award Agreement for Employees (incorporated by reference to Exhibit 10.2 to the Company’s Current Report on Form 8-K filed with the SEC on March 2, 2016).

 

 

 

  10.30†

 

Form of Restricted Stock Unit Award Agreement for 2015 Bonuses (incorporated by reference to Exhibit 10.3 to the Company’s Current Report on Form 8-K filed with the SEC on March 2, 2016).

 

 

 

  10.31†

 

Form of Performance Unit Award Agreement for Employees (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the SEC on April 26, 2016).

 

 

 

  10.32†

 

Form of Restricted Stock Unit Award Agreement for Officers and Employees (incorporated by reference to Exhibit 10.2 to the Company’s Current Report on Form 8-K filed with the SEC on June 20, 2019).

 

 

 

  10.33†

 

Form of Performance Unit Award Agreement for Officers and Employees (incorporated by reference to Exhibit 10.3 to the Company’s Current Report on Form 8-K filed with the SEC on June 20, 2019).

 

 

 

  10.34†

 

Form of Restricted Stock Award Agreement for Non-Employee Directors (incorporated by reference to Exhibit 10.10 to the Company’s Quarterly Report on Form 10-Q filed with the SEC on August 8, 2019).

 

 

 

  10.35

 

Voting Agreement, dated as of August 25, 2018, among Eclipse Resources Corporation, Blue Ridge Mountain Resources, Inc., and the stockholders of Blue Ridge Mountain Resources, Inc. party thereto (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the SEC on August 27, 2018).

 

 

 

  10.36

 

Voting Agreement, dated as of August 25, 2018, among Eclipse Resources Corporation, Blue Ridge Mountain Resources, Inc., and the stockholders of Eclipse Resources Corporation party thereto (incorporated by reference to Exhibit 10.2 to the Company’s Current Report on Form 8-K filed with the SEC on August 27, 2018).

 

 

 

  10.37

 

Lock-Up Agreement, dated as of August 25, 2018, from the stockholders of Eclipse Resources Corporation party thereto (incorporated by reference to Exhibit 10.3 to the Company’s Current Report on Form 8-K filed with the SEC on August 27, 2018).

 

 

 

  10.38

 

Form of Lock-Up Agreement from the stockholders of Blue Ridge Mountain Resources, Inc. party thereto (incorporated by reference to Exhibit 10.4 to the Company’s Current Report on Form 8-K filed with the SEC on August 27, 2018).

 

 

 

  10.39

 

Board Observation Agreement, dated as of August 25, 2018, by and among Eclipse Resources Corporation, EnCap Energy Capital Fund VIII, L.P., EnCap Energy Capital Fund VIII Co-Investors, L.P., and EnCap Energy Capital Fund IX, L.P. (incorporated by reference to Exhibit 10.5 to the Company’s Current Report on Form 8-K filed with the SEC on August 27, 2018).

 

 

 

  10.40†

 

Separation and Release Agreement, dated as of August 24, 2018, by and between Eclipse Resources Corporation and Benjamin W. Hulburt (incorporated by reference to Exhibit 10.6 to the Company’s Current Report on Form 8-K filed with the SEC on August 27, 2018).

 

 

 

  10.41†

 

Separation and Release Agreement, dated as of August 24, 2018, by and between Eclipse Resources Corporation and Matthew R. DeNezza (incorporated by reference to Exhibit 10.7 to the Company’s Current Report on Form 8-K filed with the SEC on August 27, 2018).

 

 

 

  10.42†

 

Separation and Release Agreement, dated as of August 24, 2018, by and between Eclipse Resources Corporation and Christopher K. Hulburt (incorporated by reference to Exhibit 10.8 to the Company’s Current Report on Form 8-K filed with the SEC on August 27, 2018).

 

 

 

  10.43†

 

Amendment to Separation and Release Agreement, dated as of November 30, 2018, by and between Eclipse Resources Corporation and Matthew R. DeNezza (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the SEC on December 4, 2018).

 

 

 

  21.1*

 

List of Subsidiaries of Montage Resources Corporation

 

 

 

  23.1*

 

Consent of Grant Thornton LLP

 

 

 

86

Exhibit No.

 

Description

 

 

 

  23.2*

 

Consent of Software Integrated Solutions Division of Schlumberger Technology Corporation

 

 

 

  31.1*

 

Certification of the Company’s Chief Executive Officer Pursuant to Section 302 of the Sarbanes Oxley Act of 2002 (18 U.S.C. Section 7241)

 

 

 

  31.2*

 

Certification of the Company’s Chief Financial Officer Pursuant to Section 302 of the Sarbanes Oxley Act of 2002 (18 U.S.C. Section 7241)

 

 

 

  32.1**

 

Certification of the Company’s Chief Executive Officer Pursuant to Section 906 of the Sarbanes Oxley Act of 2002 (18 U.S.C. Section 1350)

 

 

 

  32.2**

 

Certification of the Company’s Chief Financial Officer Pursuant to Section 906 of the Sarbanes Oxley Act of 2002 (18 U.S.C. Section 1350)

 

 

 

  99.1*

 

Software Integrated Solutions Division of Schlumberger Technology Corporation, Summary of Reserves for Unconventional Properties as of December 31, 2019 (Montage Resources Corporation).

 

 

 

  99.2

 

Software Integrated Solutions Division of Schlumberger Technology Corporation, Summary of Reserves for Unconventional Properties as of December 31, 2018 (Eclipse Resources Corporation) (incorporated by reference to Exhibit 99.1 to the Company’s Annual Report on Form 10-K filed with the SEC on March 15, 2019).

 

 

 

  99.3

 

Netherland Sewell & Associates, Inc., Summary of Reserves for Unconventional Properties as of December 31, 2017 (Eclipse Resources Corporation) (incorporated by reference to Exhibit 99.1 to Amendment No. 1 on Form 10-K/A to the Company’s Annual Report on Form 10-K filed with the SEC on December 7, 2018).

 

 

 

101.INS*

 

Inline XBRL Instance Document – the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL Document

 

 

 

101.SCH*

 

Inline XBRL Taxonomy Extension Schema Document

 

 

 

101.CAL*

 

Inline XBRL Taxonomy Extension Calculation Linkbase Document

 

 

 

101.DEF*

 

Inline XBRL Taxonomy Extension Definition Linkbase Document

 

 

 

101.LAB*

 

Inline XBRL Taxonomy Extension Label Linkbase Document

 

 

 

101.PRE*

 

Inline XBRL Taxonomy Extension Presentation Linkbase Document

 

 

 

104*

 

Cover Page Interactive Data File (embedded within the Inline XBRL document)

 

#

Pursuant to Item 601(b)(2) of Regulation S-K, certain schedules and similar attachments to this agreement have been omitted. The registrant hereby agrees to furnish supplementally a copy of any omitted schedule or similar attachment to the Securities and Exchange Commission upon request.

*

Filed herewith.

**

These exhibits are furnished herewith and shall not be deemed “filed” for purposes of Section 18 of the Exchange Act, or otherwise subject to the liability of that section, and shall not be deemed to be incorporated by reference into any filing under the Securities Act or the Exchange Act.

+

Confidential treatment has been granted for certain portions of this Exhibit pursuant to Rule 24b-2 of the Exchange Act, which portions have been omitted and filed separately with the Securities and Exchange Commission.

†

Management contract or compensatory plan or arrangement.

 

 

Item 16.

Form 10-K Summary

None.

87

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

 

March 10, 2020

 

 

 

MONTAGE RESOURCES CORPORATION

(Registrant)

 

 

 

 

 

 

 

 

 

/s/ John K. Reinhart

 

 

 

 

John K. Reinhart

President and Chief Executive Officer

 

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed by the following persons on behalf of the registrant in the capacities and on the dates indicated.

 

Signature

 

 

 

Date

 

 

 

 

 

/s/ John K. Reinhart

 

 

 

March 10, 2020

John K. Reinhart

President, Chief Executive Officer and Director

 

 

 

 

 

 

 

 

 

/s/ Michael L. Hodges

 

 

 

March 10, 2020

Michael L. Hodges

Executive Vice President and Chief Financial Officer

 

 

 

 

 

 

 

 

 

/s/ Timothy J. Loos

 

 

 

March 10, 2020

Timothy J. Loos

Senior Vice President – Accounting and Finance

 

 

 

 

 

 

 

 

 

/s/ Randall M. Albert

 

 

 

March 10, 2020

Randall M. Albert

Chairman

 

 

 

 

 

 

 

 

 

/s/ Mark E. Burroughs, Jr.

 

 

 

March 10, 2020

Mark E. Burroughs, Jr.

Director

 

 

 

 

 

 

 

 

 

/s/ Eugene I. Davis

 

 

 

March 10, 2020

Eugene I. Davis

Director

 

 

 

 

 

 

 

 

 

/s/ Don Dimitrievich

 

 

 

March 10, 2020

Don Dimitrievich

Director

 

 

 

 

 

 

 

 

 

/s/ Richard D. Paterson

 

 

 

March 10, 2020

Richard D. Paterson

Director

 

 

 

 

 

 

 

 

 

/s/ D. Martin Phillips

 

 

 

March 10, 2020

D. Martin Phillips

Director

 

 

 

 

 

 

 

 

 

/s/ Douglas E. Swanson, Jr.

 

 

 

March 10, 2020

Douglas E. Swanson, Jr.

Director

 

 

 

 

 

 

 

 

 

/s/ Robert L. Zorich

 

 

 

March 10, 2020

Robert L. Zorich

Director

 

 

 

 

 

88

INDEX TO FINANCIAL STATEMENTS

 

 

 

Page

Audited Consolidated Financial Statements as of December 31, 2019 and 2018 and for the Years Ended December 31, 2019, 2018, and 2017

 

 

 

 

 

 

 

Report of Independent Registered Public Accounting Firm

 

 

F-1

 

 

 

 

Consolidated Balance Sheets

 

 

F-2

 

 

 

 

Consolidated Statements of Operations and Comprehensive Income (Loss)

 

 

F-3

 

 

 

 

Consolidated Statements of Stockholders’ Equity

 

 

F-4

 

 

 

 

Consolidated Statements of Cash Flows

 

 

F-5

 

 

 

 

Notes to Consolidated Financial Statements

 

 

F-6

 

 

 

89

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Board of Directors and Stockholders

Montage Resources Corporation

 

Opinion on the financial statements

We have audited the accompanying consolidated balance sheets of Montage Resources Corporation (a Delaware corporation) and subsidiaries (the “Company”) as of December 31, 2019 and 2018, the related consolidated statements of comprehensive income, changes in stockholders’ equity, and cash flows for each of the three years in the period ended December 31, 2019, and the related notes (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2019 and 2018, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2019, in conformity with accounting principles generally accepted in the United States of America.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”), the Company’s internal control over financial reporting as of December 31, 2019, based on criteria established in the 2013 Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”), and our report dated March 10, 2020 expressed an unqualified opinion.

Change in accounting principle

As discussed in Note 2 to the consolidated financial statements, the Company has changed its method of accounting for leases as of January 1, 2019, due to the adoption of Accounting Standards Codification Topic 842, Leases.

Basis for opinion

These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

/s/ GRANT THORNTON LLP

 

We have served as the Company’s auditor since 2011.

 

Pittsburgh, Pennsylvania

March 10, 2020

 

 

F-1

MONTAGE RESOURCES CORPORATION

CONSOLIDATED BALANCE SHEETS

(in thousands, except share and per share data)

 

 

 

December 31,

2019

 

 

December 31,

2018

 

ASSETS

 

 

 

 

 

 

 

 

CURRENT ASSETS

 

 

 

 

 

 

 

 

Cash and cash equivalents

 

$

12,056

 

 

$

5,959

 

Accounts receivable

 

 

77,402

 

 

 

119,332

 

Assets held for sale

 

 

1,047

 

 

 

—

 

Other current assets

 

 

35,509

 

 

 

8,639

 

Total current assets

 

 

126,014

 

 

 

133,930

 

 

 

 

 

 

 

 

 

 

PROPERTY AND EQUIPMENT

 

 

 

 

 

 

 

 

Oil and natural gas properties, successful efforts method:

 

 

 

 

 

 

 

 

Unproved properties

 

 

508,576

 

 

 

482,475

 

Proved oil and gas properties, net

 

 

1,251,105

 

 

 

807,583

 

Other property and equipment, net

 

 

11,226

 

 

 

6,300

 

Total property and equipment, net

 

 

1,770,907

 

 

 

1,296,358

 

 

 

 

 

 

 

 

 

 

OTHER NONCURRENT ASSETS

 

 

 

 

 

 

 

 

Other assets

 

 

7,616

 

 

 

3,481

 

Operating lease right-of-use assets

 

 

36,975

 

 

 

—

 

Assets held for sale

 

 

9,665

 

 

 

—

 

TOTAL ASSETS

 

$

1,951,177

 

 

$

1,433,769

 

 

 

 

 

 

 

 

 

 

LIABILITIES AND STOCKHOLDERS' EQUITY

 

 

 

 

 

 

 

 

CURRENT LIABILITIES

 

 

 

 

 

 

 

 

Accounts payable

 

$

119,907

 

 

$

116,735

 

Accrued capital expenditures

 

 

43,500

 

 

 

12,979

 

Accrued liabilities

 

 

53,866

 

 

 

56,909

 

Accrued interest payable

 

 

21,308

 

 

 

21,661

 

Liabilities associated with assets held for sale

 

 

2,815

 

 

 

—

 

Operating lease liability

 

 

12,666

 

 

 

—

 

Total current liabilities

 

 

254,062

 

 

 

208,284

 

 

 

 

 

 

 

 

 

 

NONCURRENT LIABILITIES

 

 

 

 

 

 

 

 

Debt, net of unamortized discount and debt issuance costs

 

 

500,541

 

 

 

497,778

 

Revolving credit facility

 

 

130,000

 

 

 

32,500

 

Asset retirement obligations

 

 

29,877

 

 

 

7,110

 

Other liabilities

 

 

8,029

 

 

 

611

 

Operating lease liability

 

 

24,569

 

 

 

—

 

Liabilities associated with assets held for sale

 

 

7,013

 

 

 

—

 

Total liabilities

 

 

954,091

 

 

 

746,283

 

COMMITMENTS AND CONTINGENCIES

 

 

 

 

 

 

 

 

STOCKHOLDERS' EQUITY

 

 

 

 

 

 

 

 

Preferred stock, 50,000,000 authorized, no shares issued and outstanding

 

 

—

 

 

 

—

 

Common stock, $0.01 par value, 1,000,000,000 authorized, 35,770,934

   and 20,169,063 shares issued and outstanding, respectively

 

 

383

 

 

 

3,043

 

Additional paid in capital

 

 

2,352,309

 

 

 

2,065,119

 

Treasury stock, shares at cost; 2,508,485 and 1,747,624 shares, respectively

 

 

(10,049

)

 

 

(3,357

)

Accumulated deficit

 

 

(1,345,557

)

 

 

(1,377,319

)

Total stockholders’ equity

 

 

997,086

 

 

 

687,486

 

TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY

 

$

1,951,177

 

 

$

1,433,769

 

 

The accompanying notes are an integral part of these Consolidated Financial Statements.

F-2

MONTAGE RESOURCES CORPORATION

CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME (LOSS)

(in thousands except per share data)

 

 

 

For the Year Ended December 31,

 

 

 

2019

 

 

2018

 

 

2017

 

REVENUES

 

 

 

 

 

 

 

 

 

 

 

 

Natural gas, oil and natural gas liquids sales

 

$

591,699

 

 

$

498,593

 

 

$

380,178

 

Brokered natural gas and marketing revenue

 

 

42,274

 

 

 

16,552

 

 

 

3,481

 

Other revenue

 

 

468

 

 

 

—

 

 

 

—

 

Total revenues

 

 

634,441

 

 

 

515,145

 

 

 

383,659

 

 

 

 

 

 

 

 

 

 

 

 

 

 

OPERATING EXPENSES

 

 

 

 

 

 

 

 

 

 

 

 

Lease operating

 

 

43,359

 

 

 

28,289

 

 

 

20,525

 

Transportation, gathering and compression

 

 

208,826

 

 

 

138,766

 

 

 

124,839

 

Production and ad valorem taxes

 

 

12,141

 

 

 

10,141

 

 

 

8,490

 

Brokered natural gas and marketing expense

 

 

42,700

 

 

 

16,886

 

 

 

3,191

 

Depreciation, depletion, amortization and accretion

 

 

156,003

 

 

 

134,940

 

 

 

119,362

 

Exploration

 

 

58,917

 

 

 

49,563

 

 

 

50,208

 

General and administrative

 

 

70,941

 

 

 

44,389

 

 

 

44,553

 

Rig termination and standby

 

 

1,081

 

 

 

—

 

 

 

1

 

Gain on sale of assets

 

 

(476

)

 

 

(1,815

)

 

 

(179

)

Other expense

 

 

60

 

 

 

—

 

 

 

—

 

Total operating expenses

 

 

593,552

 

 

 

421,159

 

 

 

370,990

 

OPERATING INCOME

 

 

40,889

 

 

 

93,986

 

 

 

12,669

 

OTHER INCOME (EXPENSE)

 

 

 

 

 

 

 

 

 

 

 

 

Gain (loss) on derivative instruments

 

 

48,596

 

 

 

(21,169

)

 

 

45,365

 

Interest expense, net

 

 

(59,055

)

 

 

(53,990

)

 

 

(49,490

)

Other income (expense)

 

 

16

 

 

 

(1

)

 

 

(19

)

Total other expense, net

 

 

(10,443

)

 

 

(75,160

)

 

 

(4,144

)

INCOME FROM CONTINUING OPERATIONS

   BEFORE INCOME TAXES

 

 

30,446

 

 

 

18,826

 

 

 

8,525

 

Income tax benefit (expense)

 

 

—

 

 

 

—

 

 

 

—

 

INCOME FROM CONTINUING OPERATIONS

 

 

30,446

 

 

 

18,826

 

 

 

8,525

 

Income from discontinued operations, net of income tax

 

 

1,316

 

 

 

—

 

 

 

—

 

NET INCOME

 

$

31,762

 

 

$

18,826

 

 

$

8,525

 

 

 

 

 

 

 

 

 

 

 

 

 

 

EARNINGS PER SHARE OF COMMON STOCK

 

 

 

 

 

 

 

 

 

 

 

 

Basic:

 

 

 

 

 

 

 

 

 

 

 

 

Weighted average common stock outstanding

 

 

33,211

 

 

 

19,999

 

 

 

17,479

 

Income from continuing operations

 

$

0.92

 

 

$

0.94

 

 

$

0.49

 

Income from discontinued operations

 

 

0.04

 

 

 

—

 

 

 

—

 

Net income

 

$

0.96

 

 

$

0.94

 

 

$

0.49

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Diluted:

 

 

 

 

 

 

 

 

 

 

 

 

Weighted average common stock outstanding

 

 

33,324

 

 

 

20,087

 

 

 

17,679

 

Income from continuing operations

 

$

0.91

 

 

$

0.94

 

 

$

0.48

 

Income from discontinued operations

 

 

0.04

 

 

 

—

 

 

 

—

 

Net income

 

$

0.95

 

 

$

0.94

 

 

$

0.48

 

 

The accompanying notes are an integral part of these Consolidated Financial Statements.

F-3

MONTAGE RESOURCES CORPORATION

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY

FOR THE YEARS ENDED DECEMBER 31, 2019, 2018, and 2017

(in thousands, except share and per share data)

 

 

 

Number of

Shares

 

 

Common

Stock

($0.01 Par)

 

 

Additional

Paid-in-

Capital

 

 

Treasury

Stock

 

 

Accumulated

Deficit

 

 

Total

 

Balances, December 31, 2016

 

 

17,372,793

 

 

$

2,607

 

 

$

1,958,731

 

 

$

(61

)

 

$

(1,404,670

)

 

$

556,607

 

Stock-based compensation

 

 

—

 

 

 

—

 

 

 

9,301

 

 

 

—

 

 

 

—

 

 

 

9,301

 

Equity issuance costs

 

 

—

 

 

 

—

 

 

 

(44

)

 

 

—

 

 

 

—

 

 

 

(44

)

Issuance of restricted stock

 

 

10,213

 

 

 

2

 

 

 

(2

)

 

 

—

 

 

 

—

 

 

 

—

 

Issuance of common stock upon vesting of

   equity-based compensation awards,

   net of shares withheld for income tax

   withholdings

 

 

133,018

 

 

 

28

 

 

 

(28

)

 

 

(2,035

)

 

 

—

 

 

 

(2,035

)

Net income

 

 

—

 

 

 

—

 

 

 

—

 

 

 

—

 

 

 

8,525

 

 

 

8,525

 

Balances, December 31, 2017

 

 

17,516,024

 

 

$

2,637

 

 

$

1,967,958

 

 

$

(2,096

)

 

$

(1,396,145

)

 

$

572,354

 

Stock-based compensation

 

 

—

 

 

 

—

 

 

 

7,891

 

 

 

—

 

 

 

—

 

 

 

7,891

 

Equity issuance costs

 

 

—

 

 

 

—

 

 

 

(344

)

 

 

—

 

 

 

—

 

 

 

(344

)

Shares of common stock issued in asset

   acquisition, net of equity issuance

   costs

 

 

2,521,573

 

 

 

378

 

 

 

89,642

 

 

 

—

 

 

 

—

 

 

 

90,020

 

Issuance of restricted stock

 

 

15,476

 

 

 

2

 

 

 

(2

)

 

 

—

 

 

 

—

 

 

 

—

 

Issuance of common stock upon vesting of

   equity-based compensation awards, net

   of shares withheld for income tax

   withholdings

 

 

115,990

 

 

 

26

 

 

 

(26

)

 

 

(1,261

)

 

 

—

 

 

 

(1,261

)

Net income

 

 

—

 

 

 

—

 

 

 

—

 

 

 

—

 

 

 

18,826

 

 

 

18,826

 

Balances, December 31, 2018

 

 

20,169,063

 

 

$

3,043

 

 

$

2,065,119

 

 

$

(3,357

)

 

$

(1,377,319

)

 

$

687,486

 

Stock-based compensation

 

 

—

 

 

 

—

 

 

 

8,784

 

 

 

—

 

 

 

—

 

 

 

8,784

 

Equity issuance costs

 

 

—

 

 

 

—

 

 

 

(30

)

 

 

—

 

 

 

—

 

 

 

(30

)

Shares of common stock issued in merger,

   net of equity issuance costs

 

 

15,013,520

 

 

 

150

 

 

 

275,609

 

 

 

—

 

 

 

—

 

 

 

275,759

 

Issuance of common stock upon vesting of

   equity-based compensation awards, net

   of shares withheld for income tax

   withholdings

 

 

588,351

 

 

 

23

 

 

 

(6

)

 

 

(6,692

)

 

 

—

 

 

 

(6,675

)

Reverse split 1:15

 

 

—

 

 

 

(2,833

)

 

 

2,833

 

 

 

—

 

 

 

—

 

 

 

—

 

Net income

 

 

—

 

 

 

—

 

 

 

—

 

 

 

—

 

 

 

31,762

 

 

 

31,762

 

Balances, December 31, 2019

 

 

35,770,934

 

 

$

383

 

 

$

2,352,309

 

 

$

(10,049

)

 

$

(1,345,557

)

 

$

997,086

 

 

The accompanying notes are an integral part of these Consolidated Financial Statements.

F-4

MONTAGE RESOURCES CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands)

 

 

 

For the Year Ended

December 31,

 

 

 

2019

 

 

2018

 

 

2017

 

CASH FLOWS FROM OPERATING ACTIVITIES

 

 

 

 

 

 

 

 

 

 

 

 

Net income

 

$

31,762

 

 

$

18,826

 

 

$

8,525

 

Adjustments to reconcile net income to net cash provided by operating

   activities

 

 

 

 

 

 

 

 

 

 

 

 

Depreciation, depletion, amortization and accretion

 

 

156,552

 

 

 

134,940

 

 

 

119,362

 

Exploration expense

 

 

47,775

 

 

 

28,324

 

 

 

31,417

 

Stock-based compensation

 

 

8,784

 

 

 

7,891

 

 

 

9,301

 

Net cash for plugging wells

 

 

(1,044

)

 

 

—

 

 

 

—

 

(Gain) loss on derivative instruments

 

 

(48,596

)

 

 

21,169

 

 

 

(45,365

)

Net cash receipts (payments) on settled derivatives

 

 

20,323

 

 

 

(26,985

)

 

 

(2,224

)

Gain on sale of assets

 

 

(601

)

 

 

(1,815

)

 

 

(179

)

Amortization of deferred financing costs

 

 

2,781

 

 

 

2,256

 

 

 

2,098

 

Amortization of debt discount

 

 

1,330

 

 

 

1,327

 

 

 

1,324

 

Changes in operating assets and liabilities:

 

 

 

 

 

 

 

 

 

 

 

 

Accounts receivable

 

 

67,652

 

 

 

(42,879

)

 

 

(31,780

)

Other assets

 

 

1,893

 

 

 

(2,192

)

 

 

1,863

 

Accounts payable and accrued liabilities

 

 

(33,182

)

 

 

84,231

 

 

 

18,404

 

Net cash provided by operating activities

 

 

255,429

 

 

 

225,093

 

 

 

112,746

 

CASH FLOWS FROM INVESTING ACTIVITIES

 

 

 

 

 

 

 

 

 

 

 

 

Capital expenditures for oil and gas properties

 

 

(349,710

)

 

 

(275,601

)

 

 

(291,779

)

Capital expenditures for other property and equipment

 

 

(632

)

 

 

(1,007

)

 

 

(2,007

)

Proceeds from sale of assets

 

 

1,959

 

 

 

10,358

 

 

 

1,317

 

Cash acquired in merger

 

 

12,894

 

 

 

—

 

 

 

—

 

Change in deposits and other long-term assets

 

 

(53

)

 

 

—

 

 

 

—

 

Net cash used in investing activities

 

 

(335,542

)

 

 

(266,250

)

 

 

(292,469

)

CASH FLOWS FROM FINANCING ACTIVITIES

 

 

 

 

 

 

 

 

 

 

 

 

Debt issuance costs

 

 

(4,264

)

 

 

(497

)

 

 

(1,750

)

Repayments of long-term debt

 

 

(321

)

 

 

(506

)

 

 

(453

)

Proceeds from revolving credit facility

 

 

97,500

 

 

 

32,500

 

 

 

—

 

Equity issuance costs

 

 

(30

)

 

 

(344

)

 

 

(44

)

Employee tax withholding for settlement of equity

   compensation awards

 

 

(6,675

)

 

 

(1,261

)

 

 

(2,035

)

Net cash provided by (used in) financing activities

 

 

86,210

 

 

 

29,892

 

 

 

(4,282

)

Net increase (decrease) in cash and cash equivalents

 

 

6,097

 

 

 

(11,265

)

 

 

(184,005

)

Cash and cash equivalents at beginning of period

 

 

5,959

 

 

 

17,224

 

 

 

201,229

 

Cash and cash equivalents at end of period

 

$

12,056

 

 

$

5,959

 

 

$

17,224

 

SUPPLEMENTAL DISCLOSURE OF CASH FLOW

   INFORMATION

 

 

 

 

 

 

 

 

 

 

 

 

Cash paid for interest

 

$

59,552

 

 

$

51,101

 

 

$

47,362

 

SUPPLEMENTAL DISCLOSURE OF NON-CASH ACTIVITIES

 

 

 

 

 

 

 

 

 

 

 

 

Asset retirement obligations incurred, including changes in

   estimate

 

$

2,898

 

 

$

418

 

 

$

679

 

Additions of other property through debt financing

 

$

—

 

 

$

173

 

 

$

183

 

Additions to oil and natural gas properties - changes in

   accounts payable, accrued liabilities,

   and accrued capital expenditures

 

$

17,725

 

 

$

(15,269

)

 

$

22,264

 

Assets held for sale

 

$

—

 

 

$

—

 

 

$

(262

)

Asset acquisition through stock issuance

 

$

—

 

 

$

90,020

 

 

$

—

 

BRMR Merger consideration

 

$

275,759

 

 

$

—

 

 

$

—

 

 

The accompanying notes are an integral part of these Consolidated Financial Statements.

F-5

MONTAGE RESOURCES CORPORATION

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

FOR THE YEARS ENDED DECEMBER 31, 2019, 2018, and 2017

 

 

Note 1—Organization and Nature of Operations

Montage Resources Corporation (the “Company”), is an independent exploration and production company engaged in the acquisition and development of oil and natural gas properties in the Appalachian Basin of the United States, which encompasses the Utica Shale, Indian Castle/Flat Creek Shales and Marcellus Shale prospective areas.

 

 

Note 2—Summary of Significant Accounting Policies

(a) Basis of Presentation

The accompanying Consolidated Financial Statements of the Company have been prepared in accordance with accounting principles generally accepted in the United States (“GAAP”).  In the opinion of management, the accompanying Consolidated Financial Statements include all adjustments (consisting of normal and recurring accruals) considered necessary to present fairly the Company’s financial position as of December 31, 2019 and 2018, and the results of its operations, comprehensive income (loss) and its cash flows for the years ended December 31, 2019, 2018, and 2017.

Preparation in accordance with U.S. GAAP requires the Company to (1) adopt accounting policies within accounting rules set by the Financial Accounting Standards Board (“FASB”) and (2) make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, expenses and other disclosed amounts. The Company’s management believes the major estimates and assumptions impacting the Consolidated Financial Statements are the following:

 

•

estimates of proved reserves of oil and natural gas, which affect the calculations of depreciation, depletion, amortization and accretion and impairment of capitalized costs of oil and natural gas properties;

 

•

estimates of asset retirement obligations;

 

•

estimates of the fair value of oil and natural gas properties the Company owns, particularly properties that the Company has not yet explored, or fully explored, by drilling and completing wells;

 

•

impairment of undeveloped properties and other assets; and

 

•

depreciation and depletion of property and equipment.

Actual results may differ from estimates and assumptions of future events and these revisions could be material. Future production may vary materially from estimated oil and natural gas proved reserves. Actual future prices may vary significantly from price assumptions.

(b) Cash and Cash Equivalents

Cash and cash equivalents are comprised of cash in banks and highly liquid instruments with original maturities of three months or less, primarily consisting of bank time deposits and investments in institutional money market funds. The carrying amounts approximate fair value due to the short-term nature of these items. Cash in bank accounts at times may exceed federally insured limits.

(c) Accounts Receivable

Accounts receivable are carried at estimated net realizable value. Trade credit is generally extended on a short-term basis, and therefore, accounts receivable do not bear interest, although a finance charge may be applied to such receivables that are past due. A valuation allowance is provided for those accounts for which collection is estimated as doubtful and uncollectible accounts are written off and charged against the allowance. In estimating the allowance, management considers, among other things, how recently and how frequently payments have been received and the financial position of the party. The Company had no significant accounts receivables determined to be uncollectable as of December 31, 2019 or December 31, 2018.

F-6

The Company accrues revenue due to timing differences between the delivery of natural gas, NGLs, and crude oil and the receipt of a delivery statement. These revenues are recorded based upon volumetric data from the Company’s records and management’s estimates of the related commodity sales and transportation and compression fees, which are, in turn, based upon applicable product prices.

(d) Property and Equipment

Oil and Natural Gas Properties

The Company follows the successful efforts method of accounting for its oil and natural gas operations. Acquisition costs for oil and natural gas properties, costs of drilling and equipping productive wells, and costs of unsuccessful development wells are capitalized and amortized on an equivalent unit-of-production basis over the life of the remaining related oil and gas reserves. The estimated future costs of dismantlement, restoration, plugging and abandonment of oil and gas properties and related disposal are capitalized when asset retirement obligations are incurred and amortized as part of depreciation, depletion, amortization and accretion expense (See “Depreciation, Depletion, Amortization and Accretion ” below).

Costs incurred to acquire producing and non-producing leaseholds are capitalized. All unproved leasehold acquisition costs are initially capitalized, including the cost of leasing agents, title work and due diligence. If the Company acquires leases in a prospective area, these costs are capitalized as unproved leasehold costs. If no leases are acquired by the Company with respect to the initial costs incurred or the Company discontinues leasing in a prospective area, the costs are charged to exploration expense. Unproved leasehold costs that are determined to have proved oil and gas reserves are transferred to proved leasehold costs.

Upon the sale or retirement of a complete field of a proved property, the cost is eliminated from the property accounts, and the resultant gain or loss is reclassified to the Company’s Consolidated Statements of Operations. Upon the sale of an individual well, the proceeds are credited to accumulated depreciation and depletion within the Company’s Consolidated Balance Sheets. Upon the sale of an entire interest in an unproved property where the property had been assessed for impairment individually, a gain or loss is recognized in the Company’s Consolidated Statements of Operations. Upon the sale of an entire interest in an unproved property where the property had been assessed for impairment on a group basis, no gain or loss is recognized in the Company’s Consolidated Statements of Operations unless the proceeds exceed the original cost of the property, in which case a gain is recognized in the amount of such excess. If a partial interest in an unproved property is sold, any funds received are accounted for as a reduction of the cost in the interest retained.

A summary of property and equipment including oil and natural gas properties is as follows (in thousands):

 

 

 

December 31, 2019

 

 

December 31, 2018

 

Oil and natural gas properties:

 

 

 

 

 

 

 

 

Unproved

 

$

508,576

 

 

$

482,475

 

Proved

 

 

2,783,232

 

 

 

2,188,233

 

Gross oil and natural gas properties

 

 

3,291,808

 

 

 

2,670,708

 

Less accumulated depreciation, depletion and

   amortization

 

 

(1,532,127

)

 

 

(1,380,650

)

Oil and natural gas properties, net

 

 

1,759,681

 

 

 

1,290,058

 

Other property and equipment

 

 

20,000

 

 

 

14,460

 

Less accumulated depreciation

 

 

(8,774

)

 

 

(8,160

)

Other property and equipment, net

 

 

11,226

 

 

 

6,300

 

Property and equipment, net

 

$

1,770,907

 

 

$

1,296,358

 

 

Exploration expenses, including geological and geophysical expenses and delay rentals for unevaluated oil and gas properties are charged to expense as incurred. Exploratory drilling costs are initially capitalized as unproved property, not subject to depletion, but charged to expense if and when the well is determined not to have found proved oil and gas reserves.

F-7

Other Property and Equipment

Other property and equipment include land, buildings, leasehold improvements, vehicles, computer equipment and software, telecommunications equipment, and furniture and fixtures. These items are recorded at cost, or fair value if acquired through a business acquisition.

(e) Accounts Payable and Accrued Liabilities

A summary of accounts payable is as follows (in thousands):

 

 

 

December 31, 2019

 

 

December 31, 2018

 

Trade payables

 

$

20,232

 

 

$

27,481

 

Royalty payables

 

 

76,642

 

 

 

70,019

 

Production & ad valorem taxes

 

 

1,025

 

 

 

1,811

 

Derivative payable

 

 

112

 

 

 

4,736

 

Other payables

 

 

21,896

 

 

 

12,688

 

Total accounts payable

 

$

119,907

 

 

$

116,735

 

 

A summary of accrued liabilities is as follows (in thousands):

 

 

 

December 31, 2019

 

 

December 31, 2018

 

Ad valorem and production taxes

 

$

9,830

 

 

$

6,193

 

Employee compensation

 

 

9,375

 

 

 

6,595

 

Royalties

 

 

23,311

 

 

 

39,969

 

Short term derivatives

 

 

1,362

 

 

 

—

 

Other

 

 

9,988

 

 

 

4,152

 

Total accrued liabilities

 

$

53,866

 

 

$

56,909

 

 

(f) Revenue Recognition

Product Revenue

The Company’s revenues are primarily derived from the sale of natural gas and oil production, as well as the sale of NGLs that are extracted from the natural gas. Sales of natural gas, NGLs, and oil are recognized when the Company satisfies a performance obligation by transferring control of a product to a customer. Payment is generally received one month after the sale has occurred.

Natural Gas

Under the Company’s natural gas sales contracts, the Company delivers natural gas to the purchaser at an agreed upon delivery point. Natural gas is transported from the wellhead to delivery points specified under sales contracts. To deliver natural gas to these points, the Company uses third parties to gather, compress, process and transport the natural gas.  The Company maintains control of the natural gas during gathering, compression, processing, and transportation. The Company’s sales contracts provide that it receives a specific index price adjusted for pricing differentials. The Company transfers control of the product at the delivery point and recognizes revenue based on the contract price. The costs to gather, compress, process and transport the natural gas are recorded as transportation, gathering and compression expense.

NGLs

The Company sells NGLs directly to the NGLs purchaser. For these NGLs, the sales contracts provide that the Company deliver the product to the purchaser at an agreed upon delivery point and that the Company receives a specific index price adjusted for pricing differentials.  The Company transfers control of the product to the purchaser at the delivery point and recognizes revenue based on the contract price. The costs to further process and transport NGLs are recorded as transportation, gathering and compression expense.

F-8

Oil

Under the Company’s oil sales contracts, the Company generally sells oil to the purchaser from storage tanks at central stabilization facilities and well pads and collects a contractually agreed upon index price, net of pricing differentials and certain costs incurred by third parties. The Company transfers control of the product from the central stabilization facilities and well pads to the purchaser and recognizes revenue based on the contract price.

Marketing Revenue

Brokered natural gas and marketing revenues are derived from activities to purchase and sell third-party natural gas and to market excess firm transportation capacity to third parties. The Company retains control of the purchased natural gas and NGLs prior to delivery to the purchaser. The Company has concluded that it is the principal in these arrangements and therefore the Company recognizes revenue on a gross basis, with costs to purchase and transport natural gas presented as brokered natural gas and marketing expense. Contracts to sell third party natural gas are generally subject to similar terms as contracts to sell the Company’s produced natural gas and NGLs.  The Company satisfies performance obligations to the purchaser by transferring control of the product at the delivery point and recognizes revenue based on the price received from the purchaser.

Disaggregation of Revenue

The following table illustrates the revenue disaggregated by type for the periods indicated:

 

 

 

For the Year Ended December 31,

 

 

 

2019

 

 

2018

 

 

2017

 

Revenues (in thousands)

 

 

 

 

 

 

 

 

 

 

 

 

Natural gas sales

 

$

361,318

 

 

$

274,239

 

 

$

241,379

 

NGL sales

 

 

84,552

 

 

 

86,152

 

 

 

64,109

 

Oil sales

 

 

145,829

 

 

 

138,202

 

 

 

74,690

 

Brokered natural gas and marketing revenue

 

 

42,274

 

 

 

16,552

 

 

 

3,481

 

Other revenue

 

 

468

 

 

 

—

 

 

 

—

 

Total revenues

 

$

634,441

 

 

$

515,145

 

 

$

383,659

 

 

 

Transaction Price Allocated to Remaining Performance Obligations

A significant number of the Company’s product sales are short-term in nature with a contract term of one year or less.  For those contracts, the Company has utilized the practical expedient allowed in the revenue accounting standard that exempts the Company from disclosure of the transaction price allocated to remaining performance obligations if the performance obligations are part of a contract that has an original expected duration of one year or less.

For any product sales that have a contract term greater than one year, the Company has also utilized the practical expedient that states that it is not required to disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation.  Under these product sales contracts, each unit of product generally represents a separate performance obligation; therefore, future volumes are wholly unsatisfied, and disclosure of the transaction price allocated to remaining performance obligations is not required.  Currently, any product sales that have a contractual term greater than one year have no long-term fixed considerations.

Contract Balances

Under the Company’s sales contracts, customers are invoiced once performance obligations have been satisfied, at which point payment is unconditional.  Accordingly, the Company’s product sales contracts do not give rise to contract assets or liabilities.  Accounts receivable attributable to the Company’s revenue contracts with customers was $63.7 million and $94.1 million at December 31, 2019 and December 31, 2018, respectively.

F-9

(g) Major Customers

The Company sells production volumes to various purchasers. For the years ended December 31, 2019, 2018, and 2017, there were two, one and two customers, respectively, that accounted for 10% or more of the total natural gas, NGLs and oil sales. The following table sets forth the Company’s major customers and associated percentage of revenue for the periods indicated:

 

 

 

For the Year Ended December 31,

 

 

 

2019

 

 

2018

 

 

2017

 

Purchaser

 

 

 

 

 

 

 

 

 

 

 

 

BP Energy Company

 

23%

 

 

 

—

 

 

 

—

 

Emera Energy Services

 

 

—

 

 

 

—

 

 

17%

 

Marathon Petroleum

 

20%

 

 

25%

 

 

10%

 

Total

 

43%

 

 

25%

 

 

27%

 

 

Management believes that the loss of any one customer would not have a material adverse effect on the Company’s ability to sell natural gas, NGLs and oil production because it believes that there are potential alternative purchasers although it may be necessary to establish relationships with new purchasers. However, there can be no assurance that the Company can establish such relationships or that those relationships will result in an increased number of purchasers.

(h) Concentration of Credit Risk

The following table summarizes concentration of receivables, net of allowances, by product or service as of December 31, 2019 and December 31, 2018 (in thousands):

 

 

 

December 31, 2019

 

 

December 31, 2018

 

Receivables by product or service:

 

 

 

 

 

 

 

 

Sale of oil and natural gas and related products

   and services

 

$

63,730

 

 

$

94,107

 

Joint interest owners

 

 

12,156

 

 

 

24,830

 

Derivatives

 

 

210

 

 

 

372

 

Other

 

 

1,306

 

 

 

23

 

Total

 

$

77,402

 

 

$

119,332

 

 

Oil and natural gas customers include pipelines, distribution companies, producers, gas marketers and industrial users primarily located in Ohio, Pennsylvania and West Virginia. As a general policy, collateral is not required for receivables, but customers’ financial condition and credit worthiness are evaluated regularly.

By using derivative instruments that are not traded on an exchange to hedge exposures to changes in commodity prices, the Company exposes itself to the credit risk of counterparties. Credit risk is the potential failure of the counterparty to perform under the terms of the derivative contract. When the fair value of a derivative contract is positive, the counterparty is expected to owe the Company, which creates credit risk. To minimize the credit risk in derivative instruments, it is the Company’s policy to enter into derivative contracts only with counterparties that are creditworthy financial institutions deemed by management as competent and competitive market makers. Additionally, the Company uses master netting agreements to minimize credit-risk exposure. The creditworthiness of the Company’s counterparties is subject to periodic review. The fair value of the Company’s commodity unsettled derivative contracts was a net asset position of $27.1 million and $5.7 million at December 31, 2019 and 2018, respectively. Other than as provided by the revolving credit facility, the Company is not required to provide credit support or collateral to any of its counterparties under the Company’s contracts, nor are they required to provide credit support to the Company. As of December 31, 2019, the Company did not have past-due receivables from or payables to any of the counterparties.

F-10

(i) Depreciation, Depletion, Amortization and Accretion

Oil and Natural Gas Properties

Depreciation, depletion, amortization and accretion (“DD&A”) of capitalized costs of proved oil and natural gas properties is computed using the unit-of-production method on a field level basis using total estimated proved reserves. The reserve base used to calculate DD&A for leasehold acquisition costs and the cost to acquire proved properties is the sum of proved developed reserves and proved undeveloped reserves. The reserve base used to calculate DD&A for drilling, completion and well equipment costs, which include development costs and successful exploration drilling costs, includes only proved developed reserves. DD&A expense relating to proved oil and natural gas properties for the years ended December 31, 2019, 2018, and 2017 totaled approximately $153.8 million, $133.2 million and $117.3 million, respectively, and is included in depreciation, depletion, amortization and accretion expense in the Consolidated Financial Statements.

Other Property and Equipment

Depreciation with respect to other property and equipment is calculated using straight-line methods based on expected lives of the individual assets or groups of assets ranging from 5 to 40 years. Depreciation for the years ended December 31, 2019, 2018, and 2017 totaled approximately $2.2 million, $1.8 million and $2.0 million, respectively. This amount is included in depreciation, depletion, amortization and accretion expense in the Consolidated Statements of Operations.

(j) Impairment of Long-Lived Assets

The Company reviews its long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. If it is determined that an asset’s estimated future cash flows will not be sufficient to recover its carrying amount, an impairment charge will be recorded to reduce the carrying amount for that asset to its estimated fair value if such carrying amount exceeds the fair value.

The review of the Company’s oil and gas properties is done by determining if the historical cost of proved and unproved properties less the applicable accumulated DD&A and abandonment is less than the estimated expected undiscounted future cash flows. The expected future cash flows are estimated based on the Company’s plans to continue to produce and develop proved reserves and a risk-adjusted portion of probable reserves. Expected future cash flow from the sale of production of reserves is calculated based on estimated future prices. The Company estimates prices based upon current contracts in place, adjusted for basis differentials and market-related information, including published futures prices. The estimated future level of production is based on assumptions surrounding future prices and costs, field decline rates, market demand and supply and the economic and regulatory climates. If the carrying value exceeds the expected future cash flows, an impairment loss is recognized for the difference between the estimated fair market value (as determined by discounted future cash flows) and the carrying value of the assets.  There were no impairments of proved properties for the years ended December 31, 2019, 2018, and 2017.

When an impairment charge is recognized it represents a significant Level 3 measurement in the fair value hierarchy. The primary input used is the Company’s forecasted discount net cash flows.

The determination of oil and natural gas reserve estimates is a subjective process, and the accuracy of any reserve estimate depends on the quality of available data and the application of engineering and geological interpretation and judgment. Estimates of economically recoverable reserves and future net cash flows depend on a number of variable factors and assumptions that are difficult to predict and may vary considerably from actual results.

Unproved oil and natural gas properties are periodically assessed for impairment by considering future drilling and exploration plans, results of exploration activities, commodity price outlooks, planned future sales and expiration of all or a portion of the properties. An impairment charge is recorded if conditions indicate the Company will not explore the acreage prior to expiration of the applicable leases. The Company recorded impairment charges of unproved oil and gas properties related to lease expirations of $45.8 million, $27.6 million, and $28.3 million for the years ended December 31, 2019, 2018, and 2017, respectively. These costs are included in exploration expense in the Consolidated Statements of Operations.

F-11

(k) Income Taxes

The Company accounts for income taxes, as required, under the liability method. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases and operating loss and tax credit carry-forwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date. Deferred tax assets are reduced by a valuation allowance when, in the opinion of management, it is more likely than not that some portion or all of the deferred tax assets will not be realized.

ASC Topic 740 “Income Taxes” provides that a tax benefit from an uncertain tax position may be recognized when it is more likely than not that the position will be sustained upon examination, including resolutions of any related appeals or litigation processes, based on the technical merits. Income tax positions must meet a more-likely-than-not recognition threshold at the effective date to be recognized upon the adoption of the uncertain tax position guidance and in subsequent periods. This interpretation also provides guidance on measurement, derecognition, classification, interest and penalties, accounting in interim periods, disclosure and transition. The Company has not recorded a reserve for any uncertain tax positions to date.

(l) Fair Value of Financial Instruments

The Company has established a hierarchy to measure its financial instruments at fair value, which requires it to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. The hierarchy defines three levels of inputs that may be used to measure fair value:

Level 1 —Unadjusted quoted prices in active markets for identical, unrestricted assets and liabilities that the reporting entity has the ability to access at the measurement date.

Level 2 —Inputs other than quoted prices included within Level 1 that are observable for the asset and liability or can be corroborated with observable market date for substantially the entire contractual term of the asset or liability.  The Company’s valuation models are primarily industry-standard models that consider various inputs including: (i) quoted forward prices for commodities, (ii) time value, (iii) current market and contractual prices for the underlying instruments and (iv) volatility factors, as well as other relevant economic measures.

Level 3 —Unobservable inputs that reflect the entity’s own assumptions about the assumption market participants would use in the pricing of the asset or liability and are consequently not based on market activity but rather through particular valuation techniques.

Valuation techniques that maximize the use of observable inputs are favored. Assets and liabilities are classified in their entirety based on the lowest priority level of input that is significant to the fair value measurement. The assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the placement of assets and liabilities within the levels of the fair value hierarchy.

(m) Derivative Financial Instruments

The Company uses derivative financial instruments to reduce exposure to fluctuations in the prices of the energy commodities it sells.

Derivatives are recorded at fair value and are included on the Consolidated Balance Sheets as current and noncurrent assets and liabilities. Derivatives are classified as current or noncurrent based on the contractual expiration date. Derivatives with expiration dates within the next 12 months are classified as current. The Company netted the fair value of derivatives by counterparty in the accompanying Consolidated Balance Sheets where the right to offset exists. The Company’s derivative instruments were not designated as hedges for accounting purposes for any of the periods presented. Accordingly, the changes in fair value are recognized in the Consolidated Statements of Operations in the period of change. Gains and losses on derivatives are included in cash flows from operating activities. Premiums for options are included in cash flows from operating activities.

F-12

The valuation of the Company’s derivative financial instruments represents a Level 2 measurement in the fair value hierarchy.

(n) Asset Retirement Obligation

The Company recognizes a legal liability for its asset retirement obligations (“ARO”) in accordance with Topic ASC 410, “Asset Retirement and Environmental Obligations,” associated with the retirement of a tangible long-lived asset, in the period in which it is incurred or becomes determinable, with an associated increase in the carrying amount of the related long-lived asset. The cost of the tangible asset, including the initially recognized asset retirement cost, is depreciated over the useful life of the asset and accretion expense is recognized over time as the discounted liability is accreted to its expected settlement value. The Company measures the fair value of its ARO using expected future cash outflows for abandonment discounted back to the date that the abandonment obligation was measured using an estimated credit adjusted rate.

Estimating the future ARO requires management to make estimates and judgments based on historical estimates regarding timing and existence of a liability, as well as what constitutes adequate restoration.  Inherent in the fair value calculation are numerous assumptions and judgments including the ultimate costs, inflation factors, credit adjusted discount rates, timing of settlement and changes in the legal, regulatory, environmental and political environments. To the extent future revisions to these assumptions impact the fair value of the existing ARO liability, a corresponding adjustment is made to the related asset.

The following table sets forth the changes in the Company’s ARO liability for the periods indicated (in thousands):

 

 

 

For the Year Ended December 31,

 

 

 

2019

 

 

2018

 

 

2017

 

Asset retirement obligations, beginning of period

 

$

7,110

 

 

$

6,029

 

 

$

4,806

 

Accretion

 

 

2,368

 

 

 

663

 

 

 

544

 

Additional liabilities incurred

 

 

2,379

 

 

 

418

 

 

 

679

 

Obligation for wells acquired

 

 

20,188

 

 

 

—

 

 

 

—

 

Obligation for wells drilled

 

 

519

 

 

 

—

 

 

 

—

 

Liabilities settled via plugging

 

 

(723

)

 

 

—

 

 

 

—

 

Less: current ARO portion (accrued liabilities)

 

 

(1,964

)

 

 

—

 

 

 

—

 

Asset retirement obligations, end of period

 

$

29,877

 

 

$

7,110

 

 

$

6,029

 

 

The inputs used to determine such fair value are primarily based upon costs incurred historically for similar work, as well as estimates from independent third parties for costs that would be incurred to restore leased property to the contractually stipulated condition. Additions to ARO represent a significant nonrecurring Level 3 measurement.

(o) Off-Balance Sheet Arrangements

The Company does not have any off-balance sheet arrangements.

(p) Segment Reporting

The Company operates in one industry segment: the oil and natural gas exploration and production industry in the United States. All of its operations are conducted in one geographic area of the United States. All revenues are derived from customers located in the United States.

F-13

(q) Debt Issuance Costs

The expenditures related to issuing debt are capitalized and reported as a reduction of the Company’s debt balance in the accompanying Consolidated Balance Sheets. These costs are amortized over the expected life of the related instruments using the effective interest rate method. When debt is retired before maturity or modifications significantly change the cash flows, related unamortized costs are expensed.

During the years ended December 31, 2019, 2018, and 2017, the Company amortized $4.1 million, $3.6 million and $3.4 million, respectively, of deferred financing costs and debt discount to interest expense using the effective interest method.

(r) Recent Accounting Pronouncements

Recently Adopted

In February 2016, the FASB issued ASU 2016-02, “Leases (Topic 842).” The new standard provides guidance to increase transparency and comparability among organizations and industries by recognizing lease assets and liabilities on the balance sheet and disclosing key information about leasing arrangements. Entities are required to recognize all leases in the statement of financial position as assets and liabilities regardless of the leases’ classification. These requirements are effective for annual reporting periods beginning after December 15, 2018, including interim periods within that reporting period with early adoption permitted. In July 2018, the FASB issued ASU 2018-11, “Leases: Targeted Improvements.” The update provided an optional transition method of adoption that permitted entities to initially apply the new leases standard at the adoption date and recognize a cumulative-effect adjustment to the opening balance of retained earnings in the period of adoption. Under the optional transition method, comparative financial information and disclosures are not required. The update also provided transition practical expedients. The standard required disclosures of the nature, maturity and value of an entity's lease liabilities and elections made by the entity. In March 2019, the FASB issued ASU 2019-01, “Leases: Codification Improvements,” which, among other things, clarified interim disclosure requirements in the year of ASU 2016-02 adoption.

The Company adopted these standards effective January 1, 2019 using the optional transition method of adoption. The Company implemented a third-party-sponsored lease accounting information system to facilitate the accounting and financial reporting requirements and implemented processes and controls to review new contracts and modifications to existing contracts that contain lease components for appropriate accounting treatment.  See Note 6 – Leases for the disclosures required by the standards.

Accounting Pronouncements Not Yet Adopted

In June 2016, the FASB issued ASU 2016-13, “Financial Instruments – Credit Losses: Measurement of Credit Losses on Financial Instruments”, and subsequently, the FASB issued several related ASUs to clarify the application of the credit loss standard.  Among other things, these amendments require the measurement of all expected credit losses for financial assets held at the reporting date based on historical experience, current conditions, and reasonable and supportable forecasts.  The amendments affect loans, debt securities, trade receivables, net investments in leases, off-balance sheet credit exposures, reinsurance receivables and any other financial assets not excluded from its scope that have a contractual right to receive cash. The amendments are effective for smaller reporting companies for fiscal years and interim periods within the fiscal years beginning after December 15, 2020.  Early adoption is permitted.  The Company is assessing the impact, if any, this guidance may have on our consolidated results of operations, financial position and financial disclosures, but does not currently anticipate a material impact.

 

Note 3—Acquisition

Eclipse Resources-PA, LP Acquisition

On January 18, 2018, Eclipse Resources-PA, LP, a wholly owned subsidiary of the Company, completed its acquisition of certain oil and gas leases, one producing well and other oil and gas rights and interests covering approximately 44,500 net acres located in Tioga and Potter Counties, Pennsylvania from Travis Peak Resources, LLC for an aggregate adjusted purchase price of $90 million, which was paid entirely with approximately 2.5

F-14

million shares of the Company’s common stock (the “Flat Castle Acquisition”).  The transaction was accounted for as an asset acquisition.  Approximately $86 million of the purchase price was allocated to unproved oil and natural gas properties and approximately $4 million was allocated to proved oil and gas properties associated with the producing well acquired.  In addition, the Company capitalized approximately $1 million of transaction costs related to the acquisition.  

During the year ended December 31, 2018, the Company assigned its option to purchase all of the outstanding equity interests of Cardinal NE Holdings, LLC (“Cardinal”), a wholly owned subsidiary of Cardinal Midstream II, LLC, which owns midstream infrastructure with associated gathering rights on acreage in the Indian Castle and Flat Creek Shales, to a third party.  The third party exercised its option to purchase all of the outstanding equity interests of Cardinal in July 2018.  

Merger with Blue Ridge Mountain Resources

On February 28, 2019, the Company completed its previously announced business combination transaction with Blue Ridge Mountain Resources, Inc. (“BRMR”) pursuant to that certain Agreement and Plan of Merger, dated as of August 25, 2018 and amended as of January 7, 2019 (the “Merger Agreement”), by and among the Company, Everest Merger Sub Inc., a Delaware corporation and a wholly owned subsidiary of the Company (“Merger Sub”), and BRMR. Pursuant to the Merger Agreement, Merger Sub merged with and into BRMR with BRMR continuing as the surviving corporation and a wholly owned subsidiary of the Company (the “BRMR Merger”).

As a result of the BRMR Merger, each share of common stock, par value $0.01 per share, of BRMR issued and outstanding immediately prior to the effective time of the BRMR Merger (the “Effective Time”), excluding certain Excluded Shares (as such term is defined in the Merger Agreement), was converted into the right to receive from the Company 0.29506 of a validly issued, fully-paid, and nonassessable share of common stock, par value $0.01 per share, of the Company. The exchange ratio reflects an adjustment to account for the 15-to-1 reverse stock (See Note 12— Net Income (Loss) Per Share). Former stockholders of BRMR will receive cash for any fractional shares of the Company’s common stock to which they might otherwise be entitled as a result of the BRMR Merger. In addition, upon completion of the BRMR Merger, all shares of BRMR restricted stock and all BRMR restricted stock units and performance interest awards were converted into the right to receive shares of common stock of the Company or cash, in each case as specified in the Merger Agreement.

In connection with the BRMR Merger, the Company incurred approximately $25.5 million and $4.0 million of costs for the years ended December 31, 2019 and 2018, respectively, which are included in General and administrative expense on the Consolidated Statements of Operations and Comprehensive Income (Loss).  Approximately $131.7 million of revenues and approximately $14.0 million of net income from continuing operations are attributed to the BRMR Merger are included in the Company’s Consolidated Statement of Operations and Comprehensive Income (Loss) for the period from March 1, 2019 to December 31, 2019.  Approximately $7.2 million of revenues and approximately $1.3 million of net income from discontinued operations are attributed to the BRMR Merger are included in the Company’s Consolidated Statement of Operations and Comprehensive Income (Loss) for the period from March 1, 2019 to December 31, 2019.

F-15

The following table summarizes the purchase price allocation and the values of assets acquired and liabilities assumed (in thousands):

 

Purchase Price

 

February 28, 2019

 

Fair value of the Company's common stock issued

 

$

263,487

 

Fair value of BRMR share-based and other

   compensation

 

 

12,272

 

Total Fair Value of Consideration

 

$

275,759

 

 

 

 

 

 

Cash and cash equivalents

 

 

12,894

 

Accounts receivable

 

 

25,884

 

Assets held for sale - current

 

 

2,296

 

Other current assets

 

 

1,702

 

Unproved properties

 

 

80,843

 

Proved oil and gas properties

 

 

218,866

 

Other property and equipment

 

 

7,059

 

Other assets

 

 

2,461

 

Operating lease right-of-use asset

 

 

7,900

 

Assets held for sale - long-term

 

 

9,611

 

Total assets acquired

 

$

369,516

 

Accounts payable

 

 

(16,571

)

Accrued capital expenditures

 

 

(5,807

)

Accrued liabilities

 

 

(28,824

)

Operating lease liability - current

 

 

(1,979

)

Liabilities associated with assets held for sale - current

 

 

(7,683

)

Asset retirement obligations

 

 

(20,188

)

Operating lease liability - noncurrent

 

 

(5,923

)

Liabilities associated with assets held for sale -

   long-term

 

 

(6,782

)

Total liabilities assumed

 

$

(93,757

)

 

 

 

 

 

Net identifiable assets

 

$

275,759

 

 

The fair value measurements of oil and natural gas properties and asset retirement obligations are based on inputs that are not observable in the market and therefore represent Level 3 inputs.  The fair values of proved oil and natural gas properties and asset retirement obligations were measured using valuation techniques that convert future cash flows to a single discounted amount.  Significant inputs to the valuation of oil and natural gas properties included estimates of: (i) recoverable reserves; (ii) production rates; (iii) future operating and development costs; (iv) future commodity prices; and (v) a market-based weighed average cost of capital rate.  The fair value of unproved properties was determined using a market approach utilizing recent transactions of a similar nature in the same basin.  These inputs required significant judgements and estimates by management at the time of the valuation and are the most sensitive to possible future changes.

F-16

The following unaudited pro forma financial information represents the combined results for the Company as though the BRMR Merger had been completed on January 1, 2018.  The pro forma combined financial information has been included for comparative purposes and is not necessarily indicative of the results that might have actually occurred had the BRMR Merger taken place on January 1, 2018; furthermore, the financial information is not intended to be a projection of future results.

 

 

 

For the Year Ended

December 31,

 

(in thousands, except per share data) (unaudited)

 

2019

 

 

2018

 

Pro forma total revenues

 

$

677,099

 

 

$

698,850

 

Pro forma net income

 

$

44,536

 

 

$

5,919

 

Pro forma net income per share (basic)

 

$

1.25

 

 

$

0.17

 

Pro forma net income per share (diluted)

 

$

1.24

 

 

$

0.16

 

 

 

 

Note 4—Sale of Oil and Natural Gas Property Interests

Asset Sales

During the year ended December 31, 2017, the Company received approximately $0.5 million from a completed asset sale with a third party totaling approximately 100 acres. No gain or loss was recognized for this transaction, which was recorded as a reduction of oil and natural gas properties.

During the year ended December 31, 2017, the Company received approximately $0.8 million from a completed asset sale with a third party totaling approximately 150 acres.  As a result of this sale, the Company recognized a gain of approximately $0.2 million.

During the year ended December 31, 2018, the Company received approximately $6.0 million from a completed asset sale of approximately 1,000 acres to a third party.  As a result of this sale, the Company recognized a gain of approximately $1.5 million.

During the year ended December 31, 2018, the Company received approximately $3.8 million from a completed asset sale of approximately 400 acres to a third party.  No gain or loss was recognized for this transaction, which was recorded as a reduction of oil and natural gas properties.

During the year ended December 31, 2018, the Company received approximately $0.3 million from a completed asset sale of approximately 50 acres to a third party.  As a result of this sale, the Company recognized a gain of approximately $0.3 million.

During the year ended December 31, 2018, the Company sold the $0.2 million of pipeline assets.  As a result of this sale, the Company recognized a loss of less than approximately $0.1 million.  These pipeline assets were classified as held for sale on the Consolidated Balance Sheets as of December 31, 2015.

 

Note 5—Assets Held for Sale and Discontinued Operations

Assets Held for Sale

As a result of the BRMR Merger, the Company acquired certain assets that met the criteria for assets held for sale at the acquisition date, comprised of the net assets of Magnum Hunter Production, Inc. (“MHP”), a wholly-owned subsidiary of BRMR.  These assets are located primarily in Kentucky and Tennessee.

F-17

The following summarizes assets and liabilities held for sale at December 31, 2019:

 

(in thousands)

 

December 31, 2019

 

Accounts receivable

 

$

343

 

Other current assets

 

 

704

 

Total current assets held for sale

 

$

1,047

 

 

 

 

 

 

Proved oil and gas properties, net

 

$

9,528

 

Other noncurrent assets

 

 

137

 

Total noncurrent assets held for sale

 

$

9,665

 

 

 

 

 

 

Accounts payable

 

$

2,067

 

Accrued liabilities

 

 

570

 

Other current liabilities

 

 

178

 

Total current liabilities associated with assets held

   for sale

 

$

2,815

 

 

 

 

 

 

Asset retirement obligations

 

$

6,488

 

Other liabilities

 

 

525

 

Total noncurrent liabilities associated with assets

   held for sale

 

$

7,013

 

 

Discontinued Operations

The Company determined that the planned divestiture of MHP met the assets held for sale criteria and the criteria for classification as discontinued operations as of December 31, 2019.  The Company included the results of operations for MHP for the year ended December 31, 2019 in discontinued operations as follows:

 

(in thousands)

 

For the Year Ended

December 31, 2019

 

Revenues

 

$

7,160

 

Depreciation, depletion, amortization and accretion

 

 

(550

)

Other operating expenses

 

 

(5,296

)

Other income

 

 

2

 

Income from discontinued operations, net of tax

 

 

1,316

 

Gain on disposal of discontinued operations, net of tax

 

 

—

 

Income from discontinued operations, net of tax

 

$

1,316

 

The Company had maintained an accrued liability of $3.5 million related to litigation involving MHP and a third-party regarding certain royalty and overriding royalty deductions and related payments under several farm-out agreements.  The litigation concluded in April 2019 and, as a result, the Company removed the accrued liability and recognized corresponding income from discontinued operations for the year ended December 31, 2019.

Total operating and investing cash flows of discontinued operations for the year ended December 31, 2019 were as follows:

 

(in thousands)

 

For the Year Ended

December 31, 2019

 

Net cash provided by operating activities

 

$

425

 

Net cash provided by investing activities

 

$

26

 

 

F-18

 

Note 6—Leases

The Company leases drilling rigs, compressors, vehicles, office space, and other equipment under non-cancelable operating leases expiring through 2036.  Certain lease agreements may include options to renew the lease, terminate the lease early, or purchase the underlying asset(s).  The Company determines the lease term at the lease commencement date as the non-cancelable period of the lease, including the options to extend or terminate the lease when such an option is reasonably certain to be exercised.

As discussed in Note 2—Summary of Significant Accounting Policies, the Company adopted ASU 2016-02, ASU 2018-11 and ASU 2019-01 “Leases (Topic 842)” on January 1, 2019 using the optional transition method of adoption.  The Company elected a package of practical expedients that together allows an entity to not reassess (i) whether a contract is or contains a lease, (ii) lease classification, and (iii) initial direct costs.  In addition, the Company elected the following practical expedients for all asset classes: (i) to not reassess certain land easements, (ii) to not apply the recognition requirements under the standard to short-term leases, and (iii) to combine and account for lease and nonlease contract components as a lease, which requires the capitalization of fixed nonlease payments on January 1, 2019 or lease effective date and recognition of variable nonlease payments as variable lease expense.

On January 1, 2019, the Company recorded a total of $10.4 million in right-of-use assets and corresponding new lease liabilities on its Consolidated Balance Sheets representing the present value of its future operating lease payments. Adoption of the standards did not require an adjustment to the opening balance of retained earnings. The discount rate used to determine present value was based on the rate of interest that the Company estimated it would have to pay to borrow (on a collateralized-basis over a similar term) an amount equal to the lease payments in a similar economic environment as of January 1, 2019. The Company is required to reassess the discount rate for any new and modified lease contracts as of the lease effective date.

The right-of-use assets and lease liabilities recognized upon adoption of ASU 2016-02 were based on the lease classifications, lease commitment amounts, and terms recognized under the prior lease accounting guidance. Leases with an initial term of 12 months or less, taking into account extensions if reasonably certain to be exercised, are considered short-term leases and are not recorded on the Consolidated Balance Sheet.

The Company incurred $16.0 million in operating lease cost during the year ended December 31, 2019.  The operating lease right-of-use assets were reported in other noncurrent assets and the current and noncurrent portions of the operating lease liabilities were reported in current liabilities and noncurrent liabilities, respectively, on the Consolidated Balance Sheets. As of December 31, 2019, the operating right-of-use assets were $37.0 million and operating lease liabilities were $37.2 million, of which $12.7 million was classified as current. As of December 31, 2019, the weighted average remaining lease term was 3.7 years and the weighted average discount rate was 5.4%.

Supplemental cash flow information related to the Company’s operating leases is included in the table below (in thousands):

 

 

 

For the Year Ended

December 31, 2019

 

Cash paid for amounts included in the measurement of

   lease liabilities:

 

 

 

 

Operating cash flows for operating leases

 

$

5,542

 

Investing cash flows for operating leases

 

$

10,489

 

ROU assets added in exchange for lease obligations

   (upon adoption)

 

$

10,434

 

ROU assets and lease obligations acquired in BRMR

   Merger

 

$

7,900

 

ROU assets added in exchange for lease obligations,

   net of terminations (since adoption)

 

$

31,714

 

F-19

 

The Company’s lease liabilities with enforceable contract terms that are greater than one year mature as follows (in thousands):

 

 

 

Operating

Leases

 

2020

 

$

14,424

 

2021

 

 

13,004

 

2022

 

 

5,524

 

2023

 

 

3,611

 

2024

 

 

2,110

 

Thereafter

 

 

2,631

 

Total lease payments

 

$

41,304

 

Less imputed interest

 

 

(4,069

)

Total lease liability

 

$

37,235

 

 

As discussed in Note 2—Summary of Significant Accounting Policies, the Company elected a transition method to recognize the effects of applying the new standard as a cumulative-effect adjustment to the opening balance of retained earnings.  Per ASU 2016-02, the entity electing this transition method should provide the required disclosures under Topic 840 for all periods that continue to be in accordance with Topic 840.  As such, the Company included the future minimum lease commitments table below as of December 31, 2018.  Future minimum lease commitments under non-cancellable leases at December 31, 2018 were as follows:

 

2019

 

 

1,360

 

2020

 

 

1,060

 

2021

 

 

929

 

2022

 

 

755

 

2023

 

 

755

 

Thereafter

 

 

1,619

 

Total minimum lease payments

 

$

6,478

 

 

 

Note 7—Derivative Instruments

Commodity derivatives

The Company is exposed to market risk from changes in energy commodity prices within its operations. The Company utilizes derivatives to manage exposure to the variability in expected future cash flows from forecasted sales of natural gas and oil. The Company currently uses a mix of over-the-counter fixed price swaps, basis swaps and put options spreads and collars to manage its exposure to commodity price fluctuations. All of the Company’s derivative instruments are used for risk management purposes and none are held for trading or speculative purposes.

By using derivative instruments to hedge exposures to changes in commodity prices, the Company is exposed to the credit risk of its counterparties. Credit risk is the potential failure of the counterparty to perform under the terms of the derivative contract. When the fair value of a derivative contract is positive, the counterparty is expected to owe the Company, which creates credit risk. To minimize the credit risk in derivative instruments, it is the Company’s policy to enter into derivative contracts only with counterparties that are creditworthy financial institutions deemed by management as competent and competitive market makers. The creditworthiness of counterparties is subject to periodic review. As of December 31, 2019, the Company’s derivative instruments were with Bank of Montreal, BP Energy Company, Capital One N.A., Citibank, Citizens Bank N.A., EDF Energy, J Aron, KeyBank, N.A., Morgan Stanley, Royal Bank of Canada, and Wells Fargo. The Company has not experienced any issues of non-performance by derivative counterparties. Below is a summary of the Company’s derivative instrument positions, as of December 31, 2019, for future production periods:

F-20

Natural Gas Derivatives:

  

Description

 

Volume

(MMBtu/d)

 

 

Production Period

 

Weighted Average

Price ($/MMBtu)

 

Natural Gas Swaps:

 

 

 

 

 

 

 

 

 

 

 

 

 

50,000

 

 

January 2020 – December 2020

 

$

2.67

 

 

 

 

20,000

 

 

January 2020 – March 2020

 

$

2.80

 

 

 

 

80,000

 

 

January 2020 – June 2020

 

$

2.67

 

 

 

 

20,000

 

 

April 2020 – June 2020

 

$

2.75

 

 

 

 

30,000

 

 

July 2020 – December 2020

 

$

2.60

 

 

 

 

25,000

 

 

January 2020 – March 2021

 

$

2.60

 

 

 

 

20,000

 

 

July 2020 – March 2021

 

$

2.58

 

Natural Gas Collars:

 

 

 

 

 

 

 

 

 

 

Floor purchase price (put)

 

 

50,000

 

 

January 2020 – December 2020

 

$

2.49

 

Ceiling sold price (call)

 

 

50,000

 

 

January 2020 – December 2020

 

$

2.88

 

Floor purchase price (put)

 

 

30,000

 

 

January 2020 – March 2020

 

$

2.65

 

Ceiling sold price (call)

 

 

30,000

 

 

January 2020 – March 2020

 

$

2.98

 

Floor purchase price (put)

 

 

15,000

 

 

April 2020 – June 2020

 

$

2.50

 

Ceiling sold price (call)

 

 

15,000

 

 

April 2020 – June 2020

 

$

2.80

 

Natural Gas Three-way Collars:

 

 

 

 

 

 

 

 

 

 

Floor purchase price (put)

 

 

30,000

 

 

January 2020 – December 2020

 

$

2.70

 

Floor sold price (put)

 

 

30,000

 

 

January 2020 – December 2020

 

$

2.40

 

Ceiling sold price (call)

 

 

30,000

 

 

January 2020 – December 2020

 

$

3.05

 

Floor purchase price (put)

 

 

30,000

 

 

January 2020 – March 2020

 

$

2.72

 

Floor sold price (put)

 

 

30,000

 

 

January 2020 – March 2020

 

$

2.25

 

Ceiling sold price (call)

 

 

30,000

 

 

January 2020 – March 2020

 

$

3.15

 

Floor purchase price (put)

 

 

50,000

 

 

January 2020 – June 2020

 

$

2.82

 

Floor sold price (put)

 

 

50,000

 

 

January 2020 – June 2020

 

$

2.40

 

Ceiling sold price (call)

 

 

50,000

 

 

January 2020 – June 2020

 

$

3.11

 

Floor purchase price (put)

 

 

45,000

 

 

January 2021 – December 2021

 

$

2.55

 

Floor sold price (put)

 

 

45,000

 

 

January 2021 – December 2021

 

$

2.25

 

Ceiling sold price (call)

 

 

45,000

 

 

January 2021 – December 2021

 

$

2.81

 

Natural Gas Call/Put Options:

 

 

 

 

 

 

 

 

 

 

Floor sold price (put)

 

 

50,000

 

 

January 2020 – December 2020

 

$

2.30

 

Floor sold price (put)

 

 

50,000

 

 

January 2020 – June 2020

 

$

2.25

 

Swaption sold price (call)

 

 

50,000

 

 

January 2021 – December 2021

 

$

2.75

 

Swaption sold price (call)

 

 

50,000

 

 

January 2022 – December 2022

 

$

3.00

 

Basis Swaps:

 

 

 

 

 

 

 

 

 

 

Appalachia - Dominion

 

 

12,500

 

 

April 2020 – October 2020

 

$

(0.52

)

Appalachia - Dominion

 

 

20,000

 

 

January 2020 – December 2020

 

$

(0.59

)

Appalachia - Dominion

 

 

20,000

 

 

January 2020 – March 2020

 

$

(0.39

)

F-21

Oil Derivatives:

  

Description

 

Volume

(Bbls/d)

 

 

Production Period

 

Weighted Average

Price ($/Bbl)

 

Oil Swaps:

 

 

 

 

 

 

 

 

 

 

 

 

 

1,500

 

 

January 2020 – December 2020

 

$

57.07

 

 

 

 

1,000

 

 

July 2020 – December 2020

 

$

56.53

 

 

 

 

250

 

 

July 2020 – March 2021

 

$

53.20

 

 

 

 

250

 

 

January 2021 – March 2021

 

$

53.00

 

Oil Collars:

 

 

 

 

 

 

 

 

 

 

Floor purchase price (put)

 

 

500

 

 

January 2020 – December 2020

 

$

50.00

 

Ceiling sold price (call)

 

 

500

 

 

January 2020 – December 2020

 

$

64.00

 

Floor purchase price (put)

 

 

500

 

 

July 2020 – December 2020

 

$

52.00

 

Ceiling sold price (call)

 

 

500

 

 

July 2020 – December 2020

 

$

60.00

 

Floor purchase price (put)

 

 

500

 

 

January 2020 – March 2020

 

$

60.00

 

Ceiling sold price (call)

 

 

500

 

 

January 2020 – March 2020

 

$

67.00

 

Oil Three-way Collars:

 

 

 

 

 

 

 

 

 

 

Floor purchase price (put)

 

 

2,000

 

 

January 2020 – June 2020

 

$

62.50

 

Floor sold price (put)

 

 

2,000

 

 

January 2020 – June 2020

 

$

55.00

 

Ceiling sold price (call)

 

 

2,000

 

 

January 2020 – June 2020

 

$

74.00

 

Oil Call/Put Options:

 

 

 

 

 

 

 

 

 

 

Swaption sold price (call)

 

 

500

 

 

January 2021 – December 2021

 

$

56.80

 

Floor sold price (put)

 

 

500

 

 

July 2020 – December 2020

 

$

45.00

 

NGL Derivatives:

 

Description

 

Volume

(Bbls/d)

 

 

Production Period

 

Weighted Average

Price ($/Bbl)

 

Propane Swaps:

 

 

 

 

 

 

 

 

 

 

 

 

 

750

 

 

January 2020 – December 2020

 

$

21.46

 

Fair values and gains (losses)

The following table summarizes the fair value of the Company’s derivative instruments on a gross basis and on a net basis as presented in the Consolidated Balance Sheets (in thousands). None of the derivative instruments are designated as hedges for accounting purposes.

 

As of December 31, 2019

 

Gross

Amount

 

 

Netting

Adjustments(a)

 

 

Net Amount

Presented in

Balance

Sheets

 

 

Balance

Sheet

Location

Assets

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Commodity derivatives - current

 

$

33,762

 

 

$

(3,719

)

 

 

30,043

 

 

Other

current assets

Commodity derivatives - noncurrent

 

 

833

 

 

 

(45

)

 

 

788

 

 

Other assets

Total assets

 

$

34,595

 

 

$

(3,764

)

 

$

30,831

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Liabilities

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Commodity derivatives - current

 

$

(5,081

)

 

$

3,719

 

 

$

(1,362

)

 

Accrued

liabilities

Commodity derivatives - noncurrent

 

 

(2,397

)

 

 

45

 

 

 

(2,352

)

 

Other liabilities

Total liabilities

 

$

(7,478

)

 

$

3,764

 

 

$

(3,714

)

 

 

F-22

 

As of December 31, 2018

 

Gross

Amount

 

 

Netting

Adjustments(a)

 

 

Net Amount

Presented in

Balance

Sheets

 

 

Balance

Sheet

Location

Assets

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Commodity derivatives - current

 

$

4,960

 

 

$

(845

)

 

$

4,115

 

 

Other

current assets

Commodity derivatives - noncurrent

 

 

1,910

 

 

 

—

 

 

 

1,910

 

 

Other assets

Total assets

 

$

6,870

 

 

$

(845

)

 

$

6,025

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Liabilities

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Commodity derivatives - current

 

$

(845

)

 

$

845

 

 

$

—

 

 

Accrued

liabilities

Commodity derivatives - noncurrent

 

 

(326

)

 

 

—

 

 

 

(326

)

 

Other liabilities

Total liabilities

 

$

(1,171

)

 

$

845

 

 

$

(326

)

 

 

 

(a)

The Company has agreements in place that allow for the financial right to offset for derivative assets and derivative liabilities at settlement or in the event of a default under the agreements.

The following table presents the Company’s reported gains and losses on derivative instruments and where such values are recorded in the Consolidated Statements of Operations for the periods presented (in thousands):

 

 

 

 

 

For the Year Ended December 31,

 

 

 

Location of Gain (Loss)

 

2019

 

 

2018

 

 

2017

 

Commodity derivatives

 

Gain (loss) on derivative instruments

 

$

48,596

 

 

$

(21,169

)

 

$

45,365

 

 

 

 

Note 8—Fair Value Measurements

Fair Value Measurement on a Recurring Basis

The following table presents, by level within the fair value hierarchy, the Company’s assets and liabilities that are measured at fair value on a recurring basis. The carrying amounts reported in the Consolidated Balance Sheets for cash and cash equivalents, accounts receivable, and accounts payable approximate fair value due to the nature of the instrument and/or the short-term maturity of these instruments.

The fair value of the Company’s derivatives is based on third-party pricing models, which utilize inputs that are readily available in the public market, such as natural gas forward curves. These values are compared to the values given by counterparties for reasonableness. Since natural gas swaps do not include optionality and therefore generally have no unobservable inputs, they are classified as Level 2.

 

 

 

Level 1

 

 

Level 2

 

 

Level 3

 

 

Total Fair

Value

 

As of December 31, 2019: (in thousands)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Commodity derivative instruments

 

$

—

 

 

$

27,117

 

 

$

—

 

 

$

27,117

 

Total

 

$

—

 

 

$

27,117

 

 

$

—

 

 

$

27,117

 

As of December 31, 2018: (in thousands)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Commodity derivative instruments

 

$

—

 

 

$

5,699

 

 

$

—

 

 

$

5,699

 

Total

 

$

—

 

 

$

5,699

 

 

$

—

 

 

$

5,699

 

 

Nonfinancial Assets and Liabilities

Assets and liabilities acquired in business combinations are recorded at their fair value on the date of acquisition. Significant Level 3 assumptions associated with the calculation of future cash flows used in the analysis

F-23

of fair value of the oil and natural gas property acquired include the Company’s estimate of future commodity prices, production costs, development expenditures, production, risk-adjusted discount rates, and other relevant data. (See Note 3— Acquisition).

Additionally, fair value is used to determine the inception value of the Company’s AROs. The inputs used to determine such fair value are primarily based upon costs incurred historically for similar work, as well as estimates from independent third parties for costs that would be incurred to restore leased property to the contractually stipulated condition. Additions to the Company’s ARO represent a nonrecurring Level 3 measurement. (See Note 2— Summary of Significant Accounting Policies).

The Company reviews its proved oil and natural gas properties for impairment purposes by comparing the expected undiscounted future cash flows at a producing field level to the unamortized capitalized cost of the asset. Significant assumptions associated with the calculation of future cash flows used in the impairment analysis include the estimate of future commodity prices, production costs, development expenditures, production, risk-adjusted discount rates and other relevant data. As such, the fair value of oil and natural gas properties used in estimating impairment represents a nonrecurring Level 3 measurement. (See Note 2— Summary of Significant Accounting Policies).

The estimated fair values of the Company’s financial instruments closely approximate the carrying amounts due, except for long-term debt. (See Note 9— Debt).

 

 

Note 9—Debt

8.875% Senior Unsecured Notes Due 2023

On July 6, 2015, the Company issued $550 million in aggregate principal amount of 8.875% senior unsecured notes due 2023 at an issue price of 97.903% of principal amount of the notes, plus accrued and unpaid interest, if any, to Deutsche Bank Securities Inc. and other initial purchasers. In this private offering, the senior unsecured notes were sold for cash to qualified institutional buyers in the United States pursuant to Rule 144A of the Securities Act and to persons outside of the United States in compliance with Rule S under the Securities Act. Upon closing, the Company received proceeds of approximately $525.5 million, after deducting original issue discount, the initial purchasers discounts and offering expenses, of which the Company used approximately $510.7 million to finance the redemption of all of its outstanding 12.0% Senior PIK notes. The Company used the remaining proceeds to fund its capital expenditure plan and for general corporate purposes.

The indenture governing the senior unsecured notes contains covenants that, among other things, limit the ability of the Company and its restricted subsidiaries to: (i) incur additional indebtedness, (ii) pay dividends on capital stock or redeem, repurchase or retire the Company’s capital stock or subordinated indebtedness, (iii) transfer or sell assets, (iv) make investments, (v) create certain liens, (vi) enter into agreements that restrict dividends or other payments to the Company from its restricted subsidiaries, (vii) consolidate, merge or transfer all or substantially all of the assets of the Company and its restricted subsidiaries, taken as a whole, (viii) engage in transactions with affiliates, and (ix) create unrestricted subsidiaries. These covenants are subject to a number of important exceptions and qualifications set forth in the indenture. In addition, if the senior unsecured notes achieve an investment grade rating from either Moody’s Investors Service, Inc. or Standard & Poor’s Ratings Services, and no default under the indenture has then occurred and is continuing, many of such covenants will be suspended. The indenture also contains events of default, which include, among others and subject in certain cases to grace and cure periods, nonpayment of principal or interest, failure by the Company to comply with its other obligations under the indenture, payment defaults and accelerations with respect to certain other indebtedness of the Company and its restricted subsidiaries, failure of any guarantee on the senior unsecured notes to be enforceable, and certain events of bankruptcy or insolvency. The Company was in compliance with all applicable covenants in the indenture at December 31, 2019.

F-24

Based on Level 2 market data inputs, the fair value of the senior unsecured notes at December 31, 2019 was approximately $471.1 million.

Revolving Credit Facility

During the first quarter of 2014, Eclipse Resources I, LP, a wholly owned subsidiary of the Company (“Eclipse I”) entered into a $500 million senior secured revolving bank credit facility (the “revolving credit facility”) that was scheduled to mature in 2018. Borrowings under the revolving credit facility are subject to borrowing base limitations based on the collateral value of the Company’s proved properties and commodity hedge positions and are subject to semiannual redeterminations (April and October).

The credit agreement governing the revolving credit facility (as amended and restated, the “Credit Agreement”) was amended on January 12, 2015. The primary change effected by such amendment was to add the Company as a party to the revolving credit facility and thereby subject the Company to the representations, warranties, covenants and events of default provisions thereof. Relative to the Eclipse I’s previous credit agreement, the Credit Agreement also (i) requires financial reporting regarding, and tests financial covenants with respect to, the Company rather than Eclipse I, (ii) increases the basket sizes under certain of the negative covenants, and (iii) includes certain other changes favorable to Eclipse I. Other terms of the Credit Agreement remain generally consistent with Eclipse I’s previous credit agreement.

On February 24, 2016, the Company amended its revolving credit facility to, among other things, adjust the quarterly minimum interest coverage ratio, which is the ratio of EBITDAX to Cash Interest Expense (as such terms are defined in the Credit Agreement), and to permit the sale of certain conventional properties. The amendment to the Credit Agreement also increased the Applicable Margin (as defined in the Credit Agreement) applicable to loans and letter of credit participation fees under the Credit Agreement by 0.5%.

On February 24, 2017, the Company entered into an additional amendment that increased the borrowing base from $125 million to $175 million, while extending the maturity of the revolving credit facility to February 2020.  In addition, the amendment modified the minimum interest coverage ratio covenant to a net leverage covenant of Net Debt (as defined in the Credit Agreement) to EBITDAX.  On August 1, 2017, the Company entered into an additional amendment to the Credit Agreement that increased the borrowing base from $175 million to $225 million.

On February 28, 2019, the Company amended and restated the Credit Agreement to increase its revolving credit facility from $500 million to $1 billion.  Further, the amended and restated Credit Agreement, among other things, increased the borrowing base from $225 million to $375 million (subject to scheduled and interim redeterminations based on the Company’s oil and natural gas reserves and other adjustments described therein) and extended the maturity date thereof to February 2024 (subject to earlier maturity in certain circumstances specified therein). The amended and restated Credit Agreement also adjusted the ratio of Consolidated Total Funded Net Debt to EBITDAX to provide that the Company will not, as of the last day of any fiscal quarter (commencing with the fiscal quarter ending March 31, 2019), permit its ratio of Consolidated Total Funded Net Debt to EBITDAX for the four previous fiscal quarters to be greater than 4.00 to 1.00.

On May 6, 2019, the borrowing base under the Credit Agreement was redetermined, which increased the borrowing base from $375 million to $400 million.

On September 19, 2019, the Company entered into an additional amendment to the Credit Agreement to, among other things, confirm the redetermination of the borrowing base under the Credit Agreement, which increased the borrowing base from $400 million to $500 million.

On November 11, 2019, the Company entered into an additional amendment to the Credit Agreement to, among other things, (a) provide that the Company, may under certain circumstances, voluntarily repurchase, prepay or otherwise redeem the Company’s outstanding 8.875% senior unsecured notes due 2023 and any Permitted Refinancing Debt thereof (as such term is defined in the Credit Agreement), provided that the aggregate amount spent for such repurchase, prepayment or redemption since November 11, 2019 does not exceed $50 million; and (b) reduce the ratio of Consolidated Total Funded Net Debt to EBITDAX that the Company is required to maintain in order to make certain Restricted Payments (as such terms are defined in the Credit Agreement) from 3:1 to 2.75:1.

F-25

At December 31, 2019, the borrowing base under the revolving credit facility was $500 million and the Company had $130.0 million in outstanding borrowings thereunder. After giving effect to outstanding letters of credit issued by the Company totaling $29.2 million, the Company had available borrowing capacity under the revolving credit facility of $340.8 million.    

The revolving credit facility is secured by mortgages on 85% of the value of the Company’s properties and guarantees from the Company’s operating subsidiaries. The revolving credit facility contains certain covenants, including restrictions on indebtedness and dividends, and requirements with respect to working capital and leverage coverage ratios. Interest is payable at a variable rate based on LIBOR or the prime rate based on the Company’s election at the time of borrowing. The Company was in compliance with all applicable covenants under the revolving credit facility as of December 31, 2019. Commitment fees on the unused portion of the revolving credit facility are due quarterly at 0.375%-0.500% of the unused facility based on utilization.

 

 

Note 10—Benefit Plans

Defined Contribution Plan

The Company currently maintains a retirement plan intended to provide benefits under section 401(k) of the Internal Revenue Code, as amended (“the Code”), under which employees are allowed to contribute portions of their compensation to a tax-qualified retirement account. Under the 401(k) plan, the Company provides matching contributions equal to 100% of the first 6% of employees’ eligible compensation contributed to the plan. The Company recorded compensation expense of $1.0 million, $0.9 million and $0.7 million related to matching contributions, classified under general and administrative, for the years ended December 31, 2019, 2018, and 2017, respectively.

 

 

Note 11—Stock-Based Compensation

At the Company’s 2019 Annual Meeting of Stockholders held on June 14, 2019, the Company’s stockholders approved the Company’s 2019 Long-Term Incentive Plan (the “2019 Plan”), which was previously approved by the Company’s Board of Directors.  The 2019 Plan replaces the Company’s 2014 Long-Term Incentive Plan, as amended (the “Prior Plan”).  Upon stockholder approval, (i) the 2019 Plan became effective, and (ii) the Prior Plan terminated, and no additional awards will be granted under the Prior Plan; provided that awards outstanding under the Prior Plan as of the date the 2019 Plan became effective will remain in full force and effect under the Prior Plan according to their respective terms.

The Company is authorized to grant up to 2,650,000 shares of common stock under the 2019 Plan.  The 2019 Plan allows stock-based compensation awards to be granted in a variety of forms, including stock options, stock appreciation rights, restricted stock awards, restricted stock unit awards, dividend equivalent rights, performance-based awards and other types of awards.  The terms and conditions of the awards granted are established by the Compensation Committee of the Company’s Board of Directors. A total of 1,745,810 shares were available for future grants under the Plan as of December 31, 2019.

Stock-based compensation expense was as follows for the years ended December 31, 2019, 2018, and 2017 (in thousands):

 

 

 

Year Ended December 31,

 

 

 

2019

 

 

2018

 

 

2017

 

Restricted stock units

 

$

4,141

 

 

$

4,014

 

 

$

5,301

 

Performance units

 

 

3,706

 

 

 

3,497

 

 

 

3,622

 

Restricted and unrestricted stock

 

 

937

 

 

 

380

 

 

 

378

 

Total expense

 

$

8,784

 

 

$

7,891

 

 

$

9,301

 

 

F-26

Restricted Stock Units

Restricted stock unit awards vest subject to the satisfaction of service requirements. The Company recognizes expense related to restricted stock unit awards on a straight-line basis over the requisite service period, which is three years. The grant date fair values of these awards are determined based on the closing price of the Company’s common stock on the date of the grant. As of December 31, 2019, there was $2.4 million of total unrecognized compensation cost related to restricted stock units.  The weighted average period for the units to vest is approximately one year.

A summary of employee restricted stock unit awards activity during the year ended December 31, 2019 is as follows:

 

 

 

Number of

shares

 

 

Weighted

average

grant

date fair

value

 

 

Aggregate

intrinsic

value (in

thousands)

 

Total awarded and unvested, December 31, 2018

 

 

233,960

 

 

$

29.27

 

 

$

3,685

 

Granted

 

 

417,584

 

 

 

6.46

 

 

 

 

 

Vested

 

 

(212,140

)

 

 

28.71

 

 

 

 

 

Forfeited

 

 

(1,845

)

 

 

13.11

 

 

 

 

 

Total awarded and unvested, December 31, 2019

 

 

437,559

 

 

$

7.83

 

 

$

3,474

 

 

Performance Units

Performance unit awards vest subject to the satisfaction of a three-year service requirement and based on Total Shareholder Return (“TSR”), as compared to an industry peer group over that same period. The performance unit awards are measured at the grant date at fair value using a Monte Carlo valuation method. As of December 31, 2019, there was $1.7 million of total unrecognized compensation cost related to performance units.  The weighted average period for the units to vest is approximately two years.

A summary of performance stock unit awards activity during the year ended December 31, 2019 is as follows:

 

 

 

Number of

shares

 

 

Weighted

average

grant

date fair

value

 

 

Aggregate

intrinsic

value (in

thousands)

 

Total awarded and unvested, December 31, 2018

 

 

346,589

 

 

$

27.68

 

 

$

716

 

Granted

 

 

261,139

 

 

 

7.25

 

 

 

 

 

Vested

 

 

(270,068

)

 

 

27.57

 

 

 

 

 

Forfeited

 

 

(17,540

)

 

 

24.86

 

 

 

 

 

Total awarded and unvested, December 31, 2019

 

 

320,120

 

 

$

11.26

 

 

$

2,522

 

 

The determination of the fair value of the performance unit awards noted above uses significant Level 3 assumptions in the fair value hierarchy including an estimate of the timing of forfeitures, the risk-free rate and a volatility estimate tied to the Company’s public peer group.  The following table presents the assumptions used to determine the fair value for performance stock units granted during the years ended December 31, 2019, 2018, and 2017:

 

 

 

Year Ended December 31,

 

 

 

2019

 

 

2018

 

 

2017

 

Volatility

 

 

65.10

%

 

 

89.70

%

 

 

50.41

%

Risk-free interest rate

 

 

1.83

%

 

 

2.37

%

 

 

1.34

%

 

F-27

The fair value of the performance stock units vested during the years ended December 31, 2019 and December 31, 2017 was approximately $3.7 million and $0.8 million, respectively.

Restricted Stock Issued to Directors

On May 18, 2016, the Company issued an aggregate of 9,963 restricted shares of common stock to its three non-employee members of its Board of Directors that were not affiliated with the Company’s then controlling stockholder, which became fully vested on May 18, 2017.

On May 17, 2017, the Company issued an aggregate of 10,212 restricted shares of common stock to its three non-employee members of its Board of Directors that were not affiliated with the Company’s then controlling stockholder, which became fully vested on May 17, 2018.

On May 16, 2018, the Company issued an aggregate of 15,476 restricted shares of common stock to its three non-employee members of its Board of Directors that were not affiliated with the Company’s then controlling stockholder, which became fully vested on May 16, 2019.

Effective February 28, 2019, the Company issued an aggregate of 70,409 restricted shares of common stock to two of its officers in connection with retention bonus arrangements entered into between the Company and each of these officers.  Twenty-five percent of the restricted shares vested on August 28, 2019, and the remaining 75% of the restricted shares vest in substantially equal installments on February 28, 2020, August 28, 2020 and February 28, 2021.

Pursuant to the Company’s Non-Employee Director Compensation Policy, on June 18, 2019, the Company awarded an aggregate of 53,328 restricted shares of common stock to eight of the non-employee members of its Board of Directors, which shares are scheduled to fully vest on June 18, 2020.  The other non-employee member of the Company’s Board of Directors declined to receive any compensation for his service on the Company’s Board of Directors for 2019.

Pursuant to the Company’s Non-Employee Director Compensation Policy, on August 2, 2019 and October 8, 2019, the Company issued an aggregate of 26,935 and 22,661 unrestricted shares of common stock, respectively, which vested immediately to four of the non-employee members of its Board of Directors.

As of December 31, 2019, there was $0.9 million of total unrecognized compensation cost related to restricted stock units issued to Directors.

 

 

Note 12—Net Income (Loss) Per Share

Net Income (Loss) Per Share

Basic earnings (loss) per share (“EPS”) is computed by dividing net income (loss) by the weighted-average number of shares of common stock outstanding during the period. Diluted EPS takes into account the dilutive effect of potential common stock that could be issued by the Company in conjunction with any stock awards that have been granted to directors and employees. In accordance with FASB ASC Topic 260, awards of non-vested shares shall be considered to be outstanding as of the grant date for purposes of computing diluted EPS even though their exercise is contingent upon vesting. During periods in which the Company incurs a net loss, diluted weighted-average shares outstanding are equal to basic weighted-average shares outstanding because the effect of all equity awards is antidilutive.

F-28

Reverse Stock Split

Effective immediately prior to the Effective Time on February 28, 2019 (See Note 3— Acquisition), the Company effected a 15-to-1 reverse stock split of its common stock.  Holders of shares of the Company’s common stock immediately prior to the Effective Time received cash for any fractional shares of the Company’s common stock to which they might otherwise have been entitled as a result of the reverse stock split. The reverse stock split lowered the aggregate par value of the common stock reflected in the Consolidated Statements of Stockholders’ Equity to reflect the reduced shares with the offset to additional paid-in-capital.  The table below retroactively reflects, in accordance with ASC 505 “Equity”, the stock split that occurred on February 28, 2019 for the years ended December 31, 2018 and 2017, respectively.  The following is a calculation of the basic and diluted weighted-average number of shares of common stock and EPS for the years ended December 31, 2019, 2018, and 2017:

 

 

 

Year Ended December 31,

 

(in thousands, except per share data)

 

2019

 

 

2018

 

 

2017

 

 

 

Income

 

 

Shares

 

 

Per

Share

 

 

Income

 

 

Shares

 

 

Per

Share

 

 

Income

 

 

Shares

 

 

Per

Share

 

Basic:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net income, shares, basic

 

$

31,762

 

 

 

33,211

 

 

$

0.96

 

 

$

18,826

 

 

 

19,999

 

 

$

0.94

 

 

$

8,525

 

 

 

17,479

 

 

$

0.49

 

Weighted-average number of

   shares of common

   stock-diluted:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Restricted stock and

   performance unit awards

 

 

—

 

 

 

113

 

 

 

 

 

 

 

—

 

 

 

88

 

 

 

 

 

 

 

—

 

 

 

200

 

 

 

 

 

Diluted:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net income, shares, diluted

 

$

31,762

 

 

 

33,324

 

 

$

0.95

 

 

$

18,826

 

 

 

20,087

 

 

$

0.94

 

 

$

8,525

 

 

 

17,679

 

 

$

0.48

 

 

 

Note 13—Related Party Transactions

During the years ended December 31, 2018 and 2017, the Company incurred approximately $0.6 million, respectively, related to flight charter services provided by BWH Air, LLC and BWH Air II, LLC, which were owned by the Company’s former Chairman, President and Chief Executive Officer. The Company incurred less than $0.1 million for these services for the year ended December 31, 2019.  The fees were paid in accordance with a standard service contract that did not obligate the Company to any minimum terms.  The Company no longer utilizes any flight charter services under this arrangement.

Travis Peak Resources, LLC, the seller from whom the Company acquired assets in the Flat Castle Acquisition, is an affiliate of EnCap Investments L.P. (“EnCap”).  EnCap has representatives on the Company’s Board of Directors, and affiliates of EnCap collectively beneficially own approximately 40% of the outstanding shares of the Company’s common stock.  (See Note 3— Acquisition).

 

 

Note 14—Commitments and Contingencies

(a) Legal Matters

From time to time, the Company may be a party to legal proceedings arising in the ordinary course of business. Management does not believe that a material loss is probable as a result of such proceedings.

During the year ended December 31, 2019, the Company removed an accrued liability related to certain litigation involving MHP (See Note 5— Assets Held for Sale and Discontinued Operations).

F-29

(b) Environmental Matters

The Company is subject to numerous laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. To the extent laws are enacted or other governmental action is taken that restricts drilling or imposes environmental protection requirements that result in increased costs to the oil and natural gas industry in general, the business and prospects of the Company could be adversely affected.

(c) Other Commitments (in thousands)

 

 

 

Firm

transportation(i)

 

 

Gas processing,

gathering, and

compression

services(ii)

 

 

Total

 

Year Ending December 31:

 

 

 

 

 

 

 

 

 

 

 

 

2020

 

$

100,101

 

 

$

40,811

 

 

$

140,912

 

2021

 

 

99,828

 

 

 

41,383

 

 

 

141,211

 

2022

 

 

99,828

 

 

 

43,399

 

 

 

143,227

 

2023

 

 

99,828

 

 

 

41,260

 

 

 

141,088

 

2024

 

 

100,101

 

 

 

39,498

 

 

 

139,599

 

Thereafter

 

 

722,369

 

 

 

211,001

 

 

 

933,370

 

Total

 

$

1,222,055

 

 

$

417,352

 

 

$

1,639,407

 

 

(i)

Firm transportation - The Company has entered into firm transportation agreements with various pipelines in order to facilitate the delivery of production to market. These contracts commit the Company to transport minimum daily natural gas volumes at a negotiated rate, or pay for any deficiencies at a specified reservation fee rate. The amounts in this table represent the minimum daily volumes at the reservation fee rate. The values in the table represent the gross amounts that the Company is committed to pay and does not deduct amounts that other parties are responsible for as a result of cost sharing arrangements with working interest partners. The Company will record in its Consolidated Financial Statements the Company’s proportionate share of costs based on its working interest.

(ii)

Gas processing, gathering, and compression services - Contractual commitments for gas processing, gathering and compression service agreements represent minimum commitments under long-term gas processing and gathering agreements as well as various gas compression agreements. The values in the table represent the gross amounts that the Company is committed to pay and does not deduct amounts that other parties are responsible for as a result of cost sharing arrangements with working interest partners. The Company will record in its Consolidated Financial Statements its proportionate share of costs based on the Company’s working interest.  

 

See Note 6— Leases for a summary of undiscounted future cash flows owed by the Company as lessee to lessors pursuant to contractual agreements in effect as of December 31, 2019.

 

F-30

Note 15—Income Tax

The components of the Company’s income tax expense from continuing operations are as follows (in thousands):

 

 

 

For the Year Ended December 31,

 

 

 

2019

 

 

2018

 

 

2017

 

Current

 

 

 

 

 

 

 

 

 

 

 

 

Federal

 

$

—

 

 

$

—

 

 

$

—

 

State

 

 

—

 

 

 

—

 

 

 

—

 

Total current

 

 

—

 

 

 

—

 

 

 

—

 

Deferred

 

 

 

 

 

 

 

 

 

 

 

 

Federal

 

 

—

 

 

 

—

 

 

 

—

 

State

 

 

—

 

 

 

—

 

 

 

—

 

Total deferred

 

 

—

 

 

 

—

 

 

 

—

 

Total income tax expense (benefit)

 

$

—

 

 

$

—

 

 

$

—

 

The Company’s income tax expense from continuing operations differs from the amount derived by applying the statutory federal rate to pretax loss principally due the effect of the following items (in thousands):

 

 

 

For the Year Ended December 31,

 

 

 

2019

 

 

2018

 

 

2017

 

Income from continuing operations

 

$

30,446

 

 

$

18,826

 

 

$

8,525

 

Statutory rate

 

 

21

%

 

 

21

%

 

 

35

%

Income tax benefit computed at statutory rate

 

 

6,394

 

 

 

3,953

 

 

 

2,984

 

Reconciling items:

 

 

 

 

 

 

 

 

 

 

 

 

State income taxes

 

 

200

 

 

 

—

 

 

 

—

 

Deferred true-up

 

 

(6,686

)

 

 

—

 

 

 

—

 

Share-based compensation

 

 

—

 

 

 

1,201

 

 

 

(576

)

Other permanent differences

 

 

2,376

 

 

 

54

 

 

 

50

 

Executive compensation limitation

 

 

1,263

 

 

 

268

 

 

 

496

 

Change in valuation allowance

 

 

7,959

 

 

 

(5,476

)

 

 

(145,449

)

Change in State tax rate

 

 

(11,506

)

 

 

—

 

 

 

142,495

 

Income tax expense (benefit)

 

$

—

 

 

$

—

 

 

$

—

 

F-31

Deferred income taxes primarily represent the net tax effect of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes. The components of the Company’s deferred taxes are detailed in the table below (in thousands):

 

 

 

For the Year Ended December 31,

 

 

 

2019

 

 

2018

 

 

2017

 

Deferred tax asset:

 

 

 

 

 

 

 

 

 

 

 

 

Oil and gas properties and equipment

 

$

11,613

 

 

$

62,616

 

 

$

93,854

 

Federal tax loss carryforwards

 

 

306,743

 

 

 

140,059

 

 

 

114,652

 

Derivative instruments and other

 

 

—

 

 

 

—

 

 

 

1,064

 

Interest expense limitation carryforward

 

 

25,932

 

 

 

—

 

 

 

—

 

Operating lease right-of-use liabilities

 

 

8,278

 

 

 

—

 

 

 

—

 

Other, net

 

 

5,240

 

 

 

7,398

 

 

 

4,639

 

Deferred tax asset

 

 

357,806

 

 

 

210,073

 

 

 

214,209

 

Valuation allowance

 

 

(343,577

)

 

 

(208,324

)

 

 

(213,800

)

Net deferred tax assets

 

$

14,229

 

 

$

1,749

 

 

$

409

 

Deferred tax liability:

 

 

 

 

 

 

 

 

 

 

 

 

Derivative instruments and other

 

$

6,009

 

 

$

1,197

 

 

$

—

 

Other, net

 

 

—

 

 

 

552

 

 

 

409

 

Operating lease right-of-use assets

 

 

8,220

 

 

 

—

 

 

 

—

 

Net deferred tax liability

 

$

14,229

 

 

$

1,749

 

 

$

409

 

Reflected in the accompanying Consolidated

   Balance Sheets as:

 

 

 

 

 

 

 

 

 

 

 

 

Net deferred tax asset

 

$

—

 

 

$

—

 

 

$

—

 

Net deferred tax liability

 

$

—

 

 

$

—

 

 

$

—

 

 

Deferred tax assets and liabilities are recognized for the estimated future tax effects of temporary differences between the tax basis of an asset or liability and its reported amount in the Consolidated Financial Statements. The measurement of deferred tax assets and liabilities is based on enacted tax laws and rates currently in effect in each of the jurisdictions in which we have operations.

In recording deferred income tax assets, the Company considers whether it is more likely than not that some portion or all of the deferred income tax assets will be realized. The ultimate realization of deferred income tax assets is dependent upon the generation of future taxable income of the appropriate character during the periods in which those deferred income tax assets would be deductible. The Company considers the scheduled reversal of deferred income tax liabilities and projected future taxable income for this determination. Due to the history of losses in recent years, management believes that it is more likely than not that the Company will not be able to realize our net deferred tax assets, and therefore a valuation allowance on the entire net deferred tax asset is maintained.

The Company has U.S. federal tax loss carryforwards (“NOL”) of approximately $1.4 billion as of December 31, 2019 of which $386 million could be permanently lost. The NOL carryforwards will begin to expire in 2034. In connection with the BRMR Merger (See Note 3— Acquisition), the Company experienced an ownership change as described in IRC Section 382.  As a result, the Company’s net operating losses as of December 31, 2019 as well as certain tax deductions are subject to an annual limitation imposed by Section 382 limitation. If a subsequent ownership change were to occur as a result of future transactions in the Company’s stock, the Company’s use of remaining U.S. tax attributes may be further limited.

The tax years ended December 31, 2016 through 2019 will remain open to examination under the applicable statute of limitations in the U.S. and other jurisdictions in which the Company and its subsidiaries file income tax returns. However, the statute of limitations for examination of NOLs and other similar attribute carryforwards does not commence until the year the attribute is utilized. In some instances, state statutes of limitations are longer than those under U.S. federal tax law.

F-32

As of December 31, 2019, 2018, and 2017 the Company has not recorded a reserve for any uncertain tax positions. No federal income tax payments are expected in the upcoming four quarterly reporting periods.  However, if interest or penalties were to be incurred related to uncertain tax positions, such amounts would be recognized in income tax expense.  In the Company’s major tax jurisdictions, the earliest year open to examination is 2007.

 

 

Note 16—Subsidiary Guarantors

Each subsidiary of the Company that guarantees the Company’s revolving credit facility is required to fully and unconditionally, joint and severally, guarantee the Company’s 8.875% senior unsecured notes.  Each such subsidiary of the Company in existence immediately prior to the BRMR Merger guaranteed the Company’s 8.875% senior unsecured notes.  As a result of the BRMR Merger, and within the timeframe required by the indenture governing the Company’s 8.875% senior unsecured notes, the Company caused BRMR and each of its subsidiaries that guaranteed the Company’s revolving credit facility to guarantee the Company’s 8.875% senior unsecured notes (See Note 9— Debt ). Montage Resources Corporation, standing alone, has no independent operations or (other than its equity interests in its subsidiaries) material assets. The Company’s wholly owned subsidiary guarantors are not restricted from transferring funds to Montage Resources Corporation or other wholly owned subsidiary guarantors. The Company’s wholly owned subsidiaries do not have any restricted net assets.

A subsidiary guarantor may be released from its obligations under the guarantee:

 

•

in the event of a sale or other disposition of all or substantially all of the assets of the subsidiary guarantor or a sale or other disposition of all the capital stock of the subsidiary guarantor, to any corporation or other person by way of merger, consolidation, or otherwise; or

 

•

if the Company designates any restricted subsidiary that is a guarantor to be an unrestricted subsidiary in accordance with the terms of the indenture governing the senior unsecured notes.

 

 

Note 17—Subsequent Events

Management has evaluated subsequent events and believes that there are no events that would have a material impact on the aforementioned financial statements and related disclosures in the accompanying notes to the Consolidated Financial Statements. 

 

F-33

Note 18—Quarterly Financial Information (unaudited)

Summarized quarterly financial data for the years ended December 31, 2019 and 2018 are presented in the following table.  Quarterly financial data for the year ended December 31, 2018 retroactively reflects the 15-to-1 reverse stock split at the close the BRMR Merger on February 28, 2019. In the following table, the sum of basic and diluted “Income (loss) per common share” for the four quarters may differ from the annual amounts due to the required method of computing weighted average number of shares in the respective periods. Additionally, due to the effect of rounding, the sum of the individual quarterly loss per share amounts may not equal the calculated year loss per share amount (in thousands, except per share data).

 

 

 

First

Quarter

 

 

Second

Quarter

 

 

Third

Quarter

 

 

Fourth

Quarter

 

Year ended December 31, 2019

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total operating revenues

 

$

141,497

 

 

$

155,540

 

 

$

163,295

 

 

$

174,109

 

Total operating expenses

 

 

136,642

 

 

 

145,370

 

 

 

158,394

 

 

 

153,146

 

Operating income

 

 

4,855

 

 

 

10,170

 

 

 

4,901

 

 

 

20,963

 

Income (loss) from continuing operations

 

 

(13,916

)

 

 

24,807

 

 

 

5,521

 

 

 

14,034

 

Income (loss) from discontinued operations

 

 

(182

)

 

 

2,705

 

 

 

(1,237

)

 

 

30

 

Net income (loss)

 

 

(14,098

)

 

 

27,512

 

 

 

4,284

 

 

 

14,064

 

Income (loss) per common share:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Basic and diluted from continuing operations

 

$

(0.54

)

 

$

0.69

 

 

$

0.15

 

 

$

0.39

 

Basic and diluted from discontinued operations

 

$

(0.01

)

 

$

0.08

 

 

$

(0.03

)

 

$

—

 

Basic and diluted

 

$

(0.55

)

 

$

0.77

 

 

$

0.12

 

 

$

0.39

 

 

 

 

First

Quarter

 

 

Second

Quarter

 

 

Third

Quarter

 

 

Fourth

Quarter

 

Year ended December 31, 2018

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total operating revenues

 

$

110,192

 

 

$

103,622

 

 

$

130,123

 

 

$

171,208

 

Total operating expenses

 

 

95,651

 

 

 

92,989

 

 

 

108,929

 

 

 

123,590

 

Operating income

 

 

14,541

 

 

 

10,633

 

 

 

21,194

 

 

 

47,618

 

Net income (loss)

 

 

(2,626

)

 

 

(19,036

)

 

 

3,998

 

 

 

36,490

 

Income (loss) per common share:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Basic

 

$

(0.13

)

 

$

(0.95

)

 

$

0.20

 

 

$

1.81

 

Diluted

 

$

(0.13

)

 

$

(0.95

)

 

$

0.20

 

 

$

1.80

 

 

Note 19—Supplemental Oil and Natural Gas Information (unaudited)

(a) Capitalized Costs

A summary of the Company’s capitalized costs are contained in the table below (in thousands):

 

 

 

December 31,

 

 

 

2019

 

 

2018

 

Oil and natural gas properties:

 

 

 

 

 

 

 

 

Unproved properties

 

$

508,576

 

 

$

482,475

 

Proved properties

 

 

2,783,232

 

 

 

2,188,233

 

Total oil and natural gas properties

 

 

3,291,808

 

 

 

2,670,708

 

Less accumulated depreciation, depletion and

   amortization

 

 

(1,532,127

)

 

 

(1,380,650

)

Net oil and natural gas properties

 

$

1,759,681

 

 

$

1,290,058

 

 

F-34

(b) Costs Incurred in Oil and Natural Gas Property Acquisition and Development Activities

A summary of the Company’s cost incurred in oil and natural gas property acquisition and development activities is set forth below (in thousands):

 

 

 

December 31,

 

 

 

2019

 

 

2018

 

 

2017

 

Acquisition costs:

 

 

 

 

 

 

 

 

 

 

 

 

Unproved properties

 

$

106,758

 

 

$

107,862

 

 

$

57,498

 

Proved properties

 

 

201,884

 

 

 

4,072

 

 

 

—

 

Development cost

 

 

339,628

 

 

 

239,467

 

 

 

257,119

 

Exploration cost

 

 

11,142

 

 

 

20,957

 

 

 

18,791

 

Asset retirement obligations

 

 

29,346

 

 

 

—

 

 

 

—

 

Total acquisition, development and

   exploration costs

 

$

688,758

 

 

$

372,358

 

 

$

333,408

 

 

(c) Reserve Quantity Information

The following information represents estimates of the Company’s proved reserves as of December 31, 2019 and December 31, 2018, which have been prepared and presented under SEC rules. These rules require companies to prepare their reserve estimates using specified reserve definitions and pricing based on a 12-month unweighted average of the first-day-of-the-month pricing. The pricing that was used for estimates of the Company’s reserves as of December 31, 2019, 2018, and 2017 was based on an unweighted average 12-month average West Texas Intermediate posted price per Bbl for oil and NGLs and a Henry Hub spot natural gas price per MMBtu for natural gas.

Subject to limited exceptions, proved undeveloped reserves may only be booked if they relate to wells scheduled to be drilled within five years of the date of booking. This requirement may limit the Company’s potential to record additional proved undeveloped reserves as it pursues its drilling program, particularly as it develops its significant acreage primarily in the Appalachian Basin of Ohio, Pennsylvania and West Virginia. Moreover, the Company may be required to write down its proved undeveloped reserves if it does not drill on those reserves within the required five-year timeframe. The Company does not have any proved undeveloped reserves which have remained undeveloped for five years or more.

The Company’s proved oil and natural gas reserves are all located in the United States, primarily within the States of Ohio, Pennsylvania and West Virginia. All of the estimates of the proved reserves at December 31, 2019 and 2018 and December 31, 2017, were prepared by SIS and NSAI, our independent petroleum engineers, respectively. Proved reserves were estimated in accordance with the guidelines established by the SEC and the FASB.

Oil and natural gas reserve quantity estimates are subject to numerous uncertainties inherent in the estimation of quantities of proved reserves and in the projection of future rates of production and the timing of development expenditures. The accuracy of such estimates is a function of the quality of available data and of engineering and geological interpretation and judgment. Results of subsequent drilling, testing and production may cause either upward or downward revision of previous estimates.

Further, the volumes considered to be commercially recoverable fluctuate with changes in prices and operating costs. The Company emphasizes that reserve estimates are inherently imprecise and that estimates of new discoveries are more imprecise than those of currently producing oil and natural gas properties. Accordingly, these estimates are expected to change as additional information becomes available in the future.

F-35

The following table provides a roll-forward of the total proved reserves for the year ended December 31, 2019, 2018, and 2017 as well as proved developed and proved undeveloped reserves at the beginning and end of each respective year:

 

 

 

Natural Gas

(Bcf)

 

 

Natural Gas

Liquids

(MBbl)

 

 

Oil (MBbl)

 

 

TOTAL

(Bcfe)

 

End of year, December 31, 2016

 

 

386.4

 

 

 

8,675.5

 

 

 

5,157.7

 

 

 

469.4

 

Revisions

 

 

515.1

 

 

 

20,327.3

 

 

 

9,746.8

 

 

 

695.6

 

Extensions and discoveries

 

 

274.4

 

 

 

15,598.8

 

 

 

6,192.9

 

 

 

405.1

 

Acquisitions

 

 

1.6

 

 

 

42.6

 

 

 

5.8

 

 

 

1.9

 

Production

 

 

(87.4

)

 

 

(2,713.6

)

 

 

(1,622.4

)

 

 

(113.4

)

End of year, December 31, 2017

 

 

1,090.1

 

 

 

41,930.6

 

 

 

19,480.8

 

 

 

1,458.6

 

Revisions

 

 

5.6

 

 

 

(8,307.5

)

 

 

231.2

 

 

 

(42.8

)

Extensions and discoveries

 

 

515.8

 

 

 

4,059.4

 

 

 

2,995.7

 

 

 

558.1

 

Acquisitions

 

 

9.9

 

 

 

551.4

 

 

 

522.2

 

 

 

16.3

 

Divestitures

 

 

(0.2

)

 

 

—

 

 

 

—

 

 

 

(0.2

)

Production

 

 

(90.0

)

 

 

(3,503.0

)

 

 

(2,377.8

)

 

 

(125.3

)

End of year, December 31, 2018

 

 

1,531.2

 

 

 

34,730.9

 

 

 

20,852.1

 

 

 

1,864.7

 

Revisions

 

 

(77.0

)

 

 

4,454.5

 

 

 

(1,569.8

)

 

 

(59.6

)

Extensions and discoveries

 

 

418.7

 

 

 

19,016.3

 

 

 

11,078.1

 

 

 

599.2

 

Acquisitions

 

 

418.9

 

 

 

14,844.0

 

 

 

2,915.2

 

 

 

525.5

 

Production

 

 

(154.1

)

 

 

(4,686.3

)

 

 

(2,950.8

)

 

 

(200.0

)

End of year, December 31, 2019

 

 

2,137.7

 

 

 

68,359.4

 

 

 

30,324.8

 

 

 

2,729.8

 

Proved developed reserves:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

December 31, 2016

 

 

226.1

 

 

 

7,520.0

 

 

 

4,439.5

 

 

 

297.8

 

December 31, 2017

 

 

334.6

 

 

 

13,782.9

 

 

 

6,449.6

 

 

 

456.0

 

December 31, 2018

 

 

501.0

 

 

 

20,213.8

 

 

 

8,058.7

 

 

 

670.7

 

December 31, 2019

 

 

1,183.2

 

 

 

39,316.3

 

 

 

12,512.6

 

 

 

1,494.2

 

Proved undeveloped reserves:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

December 31, 2016

 

 

160.4

 

 

 

1,155.5

 

 

 

718.1

 

 

 

171.6

 

December 31, 2017

 

 

755.5

 

 

 

28,147.7

 

 

 

13,031.2

 

 

 

1,002.6

 

December 31, 2018

 

 

1,030.2

 

 

 

14,517.2

 

 

 

12,793.4

 

 

 

1,194.1

 

December 31, 2019

 

 

954.5

 

 

 

29,043.2

 

 

 

17,812.2

 

 

 

1,235.6

 

 

2017 Changes in Reserves

 

•

Extensions of 405.1 Bcfe primarily from 361.0 Bcfe of development of the Company’s operated Utica asset. The Company also added 0.3 Bcfe from one non-operated Utica well through development. In addition, the Company proved 43.8 Bcfe from 3 Ohio Marcellus wells due to development in the Ohio Marcellus asset.

 

•

Positive revisions of 695.6 Bcfe as a result of a positive revision of 607.2 Bcfe due to improvements in SEC pricing, a positive revision of 61.4 Bcfe due to changes in pricing differentials, and a positive revision of 69.6 Bcfe primarily driven by proved developed producing wells in aggregate outperforming the previous estimate. This was offset by a negative revision of 42.6 Bcfe due a decision to not develop certain proved, undeveloped reserves within five years.

2018 Changes in Reserves

 

•

Extensions of 558.1 Bcfe from the development of 148.3 Bcfe of unproved wells to proved developed, 398.2 Bcfe from the development of the Company’s operated Utica asset and 11.6 Bcfe from the Company’s operated Marcellus asset.

 

•

16.3 Bcfe related to acquiring proved developed leasehold acreage in the Indian Castle/Flat Creek and Utica Shales.

F-36

 

•

0.2 Bcfe related to divesting a non-operated proved developed well in the Utica Shale.

 

•

Negative revisions of 42.8 Bcfe as a result of a positive revision of 15.0 Bcfe due to improvements in SEC pricing, a positive revision of 6.8 Bcfe due to changes in pricing differentials and a positive revision of 67.5 Bcfe primarily driven by proved developed producing wells outperforming the previous estimate.  This was offset by a negative revision of 98.0 Bcfe due to changes in well spacing and 34.1 Bcfe due to changes in the five year development plan.

2019 Changes in Reserves

 

•

Extensions of 599.2 Bcfe from the development of 100.5 Bcfe of unproved wells to proved developed, of which 70.2 Bcfe is from the development of the Company’s operated Marcellus asset, 23.3 Bcfe is from the Company’s operated Utica asset and 7.0 Bcfe was added from participation in non-operated wells. Extensions of 498.7 Bcfe from the development of unproved wells to proved undeveloped, of which 269.4 Bcfe is from the Company’s operated Utica asset and 229.3 Bcfe is from the Company’s operated Marcellus asset.

 

•

525.5 Bcfe related to acquiring proved assets from the merger with BRMR.

 

•

Revisions to previous estimates are comprised of 59.6 Bcfe of negative revisions primarily due to a negative adjustment of 277.3 due to downward SEC pricing and differentials and 44.2 Bcfe due adjustments in the drilling schedule. The negative revisions have been offset by a positive revision of 261.9 Bcfe due to well performance, capital allocation, and lease operating expense.

(d) Standardized Measure of Discounted Future Net Cash Flows

The standardized measure of discounted future net cash flows does not purport to be, nor should it be interpreted to present, the fair value of the oil and natural gas reserves of the property. An estimate of fair value would take into account, among other things, the recovery of reserves not presently classified as proved, the value of unproved properties, and consideration of expected future economic and operating conditions. The estimates of future cash flows and future production and development costs as of December 31, 2019 and 2018 are based on the unweighted arithmetic average first-day-of-the-month price for the preceding 12-month period. Estimated future production of proved reserves and estimated future production and development costs of proved reserves are based on current costs and economic conditions. All wellhead prices are held flat over the forecast period for all reserve categories. The estimated future net cash flows are then discounted at a rate of 10%. The standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves is as follows at December 31, 2019, 2018, and 2017 (in thousands):

 

 

 

December 31,

 

 

 

2019

 

 

2018

 

 

2017

 

Future cash inflows (total revenues)

 

$

8,212,521

 

 

$

6,730,000

 

 

$

4,750,238

 

Future production costs

 

 

(3,867,182

)

 

 

(2,964,098

)

 

 

(2,332,310

)

Future development costs (capital costs)

 

 

(982,321

)

 

 

(855,932

)

 

 

(879,399

)

Future income tax expense

 

 

(633,086

)

 

 

(136,472

)

 

 

—

 

Future net cash flows

 

 

2,729,932

 

 

 

2,773,498

 

 

 

1,538,529

 

10% annual discount for estimated timing of

   cash flows

 

 

(1,534,108

)

 

 

(1,444,188

)

 

 

(808,843

)

Standardized measure of Discounted Future Net

   Cash Flow

 

$

1,195,824

 

 

$

1,329,310

 

 

$

729,686

 

 

It is not intended that the FASB’s standardized measure of discounted future net cash flows represent the fair market value of the Company’s proved reserves. The Company cautions that the disclosures shown are based on estimates of proved reserve quantities and future production schedules which are inherently imprecise and subject to revision, and the 10% discount rate is arbitrary. In addition, costs and prices as of the measurement date are used in the determinations, and no value may be assigned to probable or possible reserves.

F-37

(e) Changes in the Standardized Measure of Discounted Future Net Cash Flows

A summary of the changes in the standardized measure of discounted future net cash flows are contained in the table below (in thousands):

 

 

 

December 31,

 

 

 

2019

 

 

2018

 

 

2017

 

Standardized Measure, beginning of the year

 

$

1,329,310

 

 

$

729,686

 

 

$

205,981

 

Net change in prices and production costs

 

 

(531,056

)

 

 

369,578

 

 

 

653,347

 

Net change in future development costs

 

 

28,481

 

 

 

87,466

 

 

 

(385,042

)

Sales, less production costs

 

 

(327,373

)

 

 

(321,802

)

 

 

(226,324

)

Extensions

 

 

251,343

 

 

 

363,708

 

 

 

135,734

 

Acquisitions

 

 

387,117

 

 

 

7,468

 

 

 

2,365

 

Divestitures

 

 

—

 

 

 

(20

)

 

 

—

 

Revisions of previous quantity estimates

 

 

7,345

 

 

 

19,910

 

 

 

322,917

 

Previously estimated development costs incurred

 

 

245,931

 

 

 

65,035

 

 

 

34,102

 

Net changes in taxes

 

 

(237,482

)

 

 

(37,345

)

 

 

—

 

Accretion of discount

 

 

132,931

 

 

 

72,969

 

 

 

20,598

 

Changes in timing and other

 

 

(90,723

)

 

 

(27,343

)

 

 

(33,992

)

Standardized Measure, end of year

 

$

1,195,824

 

 

$

1,329,310

 

 

$

729,686

 

 

F-38

 

Exhibit 4.5

 

DESCRIPTION OF SECURITIES REGISTERED UNDER
SECTION 12 OF THE SECURITIES EXCHANGE ACT OF 1934

The following summary of the common stock, par value $0.01 per share, of Montage Resources Corporation (the “Company,” “we,” “us,” and “our”) does not purport to be complete and is subject to and qualified by reference to our Second Amended and Restated Certificate of Incorporation, as amended (our “Certificate of Incorporation”) and Second Amended and Restated Bylaws, as amended (our “Bylaws”).

Authorized Capital Stock

Under our Certificate of Incorporation, our authorized capital stock consists of 1,000,000,000 shares of common stock, par value $0.01 per share (“common stock”), and 50,000,000 shares of preferred stock, par value $0.01 per share (“preferred stock”).

Common Stock

Voting rights. Each share of common stock is entitled to one vote for each share held of record on all matters submitted to a vote of stockholders and has the exclusive right to vote for the election of directors and for all other purposes. Stockholders do not have the right to vote cumulatively in the election of directors. Except as otherwise required by law, holders of common stock are not entitled to vote on any amendment to our Certificate of Incorporation (including any certificate of designations relating to any class or series of preferred stock) that relates solely to the terms of any outstanding classes or series of preferred stock if the holders of such affected class or series are entitled, either separately or together with the holders of one or more other classes or series, to vote thereon pursuant to our Certificate of Incorporation (including any certificate of designations relating to any class or series of preferred stock) or pursuant to the General Corporation Law of the State of Delaware (the “DGCL”).

Dividends, distributions and stock splits. Subject to prior rights and preferences that may be applicable to any outstanding shares of preferred stock or class or series thereof, holders of common stock are entitled to receive ratably in proportion to the shares of common stock held by them such dividends and distributions (payable in cash, securities or otherwise), if any, as may be declared from time to time by our board of directors out of funds legally available therefor.

Liquidation. In the event of any voluntary or involuntary liquidation, dissolution or winding-up of our affairs, holders of common stock will be entitled to share ratably in our assets in proportion to the shares of common stock held by them that are remaining after payment or provision for payment of all of our debts and obligations and after distribution in full of preferential amounts to be distributed to holders of outstanding shares of preferred stock or any class or series thereof, if any.

Fully paid. All shares of common stock outstanding are fully paid and non-assessable.

Other rights. Holders of common stock have no preferences or rights of conversion, exchange, preemption or other subscription rights. There are no redemption or sinking fund provisions applicable to the common stock.  

Preferred Stock

Our Certificate of Incorporation authorizes our board of directors, subject to any limitations prescribed by law, without further stockholder approval, to establish and to issue from time to time one or more classes or series of preferred stock. Each class or series of preferred stock will have the powers, preferences, rights, qualifications, limitations and restrictions determined by the board of directors, which may include, among others, dividend rights, liquidation preferences, voting rights, conversion rights, preemptive rights and redemption rights. Except as provided by law or in a preferred stock certificate of designations, the holders of preferred stock will not be entitled to vote at or receive notice of any meeting of stockholders. The issuance of any such preferred stock could adversely affect the rights of the holders of our common stock and therefore, reduce the value of the common stock.

 

 

Anti-Takeover Effects of Provisions of Our Certificate of Incorporation, Our Bylaws and Delaware Law

Some provisions of Delaware law, our Certificate of Incorporation and our Bylaws contain provisions that could make the following transactions more difficult: acquisitions of us by means of a tender offer, a proxy contest or otherwise, or the removal of our incumbent officers and directors. These provisions may also have the effect of preventing changes in control or changes in our management. It is possible that these provisions could make it more difficult to accomplish or could deter transactions that stockholders may otherwise consider to be in their best interest or in our best interests, including transactions that might result in a premium over the market price for our shares.

These provisions are expected to discourage coercive takeover practices and inadequate takeover bids. These provisions are also designed to encourage persons seeking to acquire control of us to first negotiate with us. We believe that the benefits of increased protection and our potential ability to negotiate with the proponent of an unfriendly or unsolicited proposal to acquire or restructure us outweigh the disadvantages of discouraging these proposals because, among other things, negotiation of these proposals could result in an improvement of their terms.

Delaware Law

Section 203 of the DGCL prohibits a Delaware corporation, including those whose securities are listed for trading on the New York Stock Exchange (the “NYSE”), from engaging in any business combination with any interested stockholder for a period of three years following the date that the stockholder became an interested stockholder, unless:

 

 

•

 

prior to the time that such stockholder became an interested stockholder, the board of directors approved the transaction which resulted in such stockholder becoming an interested stockholder;

 

 

•

 

upon consummation of the transaction that resulted in the stockholder becoming an interested stockholder, the interested stockholder owned at least 85% of the voting stock of the corporation outstanding at the time the transaction commenced, excluding for purposes of determining the voting stock outstanding (but not the outstanding voting stock owned by the interested stockholder) those shares owned (i) by persons who are directors and also officers and (ii) employee stock plans in which employee participants do not have the right to determine confidentially whether shares held subject to the plan will be tendered in a tender or exchange offer; or

 

 

•

 

on or after such time the business combination is approved by the board of directors and authorized at a meeting of stockholders, and not by written consent, by at least two-thirds of the outstanding voting stock that is not owned by the interested stockholder.

We have elected not to be subject to the provisions of Section 203 of the DGCL.

Certificate of Incorporation and Bylaws

Provisions of our Certificate of Incorporation and Bylaws may delay or discourage transactions involving an actual or potential change in control or change in our management, including transactions in which stockholders might otherwise receive a premium for their shares, or transactions that our stockholders might otherwise deem to be in their best interests.

Among other things, our Certificate of Incorporation and Bylaws:

 

 

 

 

•

 

Establish advance notice procedures with regard to stockholder proposals relating to the nomination of candidates for election as directors or new business to be brought before meetings of our stockholders. These procedures provide that notice of stockholder proposals must be timely given in writing to our corporate secretary prior to the meeting at which the action is to be taken. Generally, to be timely, notice must be received at our principal executive offices not less than 90 days nor more than 120 days prior to the first anniversary date of the annual meeting for the preceding year unless the date of the annual meeting is more than 30 days before or more than 60 days after such anniversary date, or no annual meeting was held in the preceding year. Our Bylaws specify the requirements as to form and content of all stockholders’ notices. These requirements may preclude stockholders from bringing matters before the stockholders at an annual or special meeting.

 

 

•

 

Provide our board of directors the ability to authorize preferred stock. This ability makes it possible for our board of directors to issue, without stockholder approval, preferred stock with voting or other rights or preferences that could impede the success of any attempt to change control of us.

 

 

•

 

Provide that the authorized number of directors may be changed only by resolution of the board of directors, subject to the rights of the holders of any class or series of preferred stock to elect directors under specified circumstances, if any.

 

 

•

 

Provide that all vacancies, including newly created directorships, shall be filled by the affirmative vote of a majority of directors then in office, even if less than a quorum, or by a sole remaining director and shall not be filled by the stockholders.

 

 

•

 

Provide that any action required or permitted to be taken by the stockholders must be taken at a duly held annual or special meeting of stockholders and may not be taken by any consent in writing in lieu of a meeting of such stockholders, subject to the rights of the holders of any class or series of preferred stock with respect to such class or series.

 

 

•

 

Provide that our Certificate of Incorporation may only be amended by the affirmative vote of the holders of at least two-thirds of the voting power of the outstanding shares of stock of the Company entitled to vote thereon, voting together as a single class, in addition to any other vote that may be required by law, our Certificate of Incorporation or our Bylaws.

 

 

•

 

Provide that our Bylaws may be amended by our board of directors without any action on the part of the stockholders, and our Bylaws shall not be amended by the stockholders except by the vote of holders of not less than two-thirds in voting power of the then-outstanding shares of stock of the Company entitled to vote thereon, voting together as a single class.

 

 

•

 

Provide that special meetings of our stockholders may only be called by the board of directors (pursuant to a resolution adopted by a majority of the total number of directors that the Company would have if there were no vacancies), the chief executive officer or the chairman of the board, subject to the rights of the holders of any class or series of preferred stock with respect to such class or series.

 

 

•

 

Provide that we renounce any interest in existing and future business opportunities of The Hulburt Family II Limited Partnership, EnCap Energy Capital Fund VIII, L.P., EnCap Energy Capital Fund VIII Co-Investors, L.P., and EnCap Energy Capital Fund IX, L.P. and their respective affiliates or any of their respective agents, stockholders, members, partners, directors, officers, employees, affiliates or subsidiaries (other than our directors and officers that are presented business opportunities in writing in their capacity as our directors or officers) and that they have no obligation to offer us those opportunities.

Forum Selection

Our Certificate of Incorporation provides that unless we consent in writing to the selection of an alternative forum, the Court of Chancery of the State of Delaware (or, if the Court of Chancery does not have jurisdiction, another state court or a federal court located within the State of Delaware) will, to the fullest extent permitted by applicable law and subject to applicable jurisdictional requirements, be the sole and exclusive forum for any current or former stockholder (including any current or former beneficial owner) to bring claims, including claims in the right of the Company, (i) that are based upon a violation of a duty by a current or former director, officer, employee or stockholder in such capacity, or (ii) as to which the DGCL confers jurisdiction upon the Court of Chancery.

 

 

Limitation of Liability and Indemnification Matters

Our Certificate of Incorporation limits the liability of our directors for monetary damages for breach of their fiduciary duty as directors, except for liability that cannot be eliminated under the DGCL. Therefore, pursuant to Delaware law, our Certificate of Incorporation provides that directors of the Company will not be personally liable for monetary damages for breach of their fiduciary duty as directors, except for liabilities:

 

 

•

 

for any breach of their duty of loyalty to us or our stockholders;

 

 

•

 

for acts or omissions not in good faith or which involve intentional misconduct or a knowing violation of law;

 

 

•

 

for unlawful payment of dividend or unlawful stock repurchase or redemption, as provided under Section 174 of the DGCL; or

 

 

•

 

for any transaction from which the director derived an improper personal benefit.

Any amendment, repeal, or modification of these provisions will be prospective only and would not affect any limitation on liability of a director for acts or omissions that occurred prior to any such amendment, repeal, or modification.

 

Our Bylaws also provide that we will generally indemnify our directors and officers to the fullest extent permitted by applicable law and permit us to purchase insurance on behalf of any officer, director, employee, or other agent for any liability arising out of that person’s actions as our officer, director, employee, or agent, regardless of whether Delaware law would permit indemnification. We have obtained directors’ and officers’ insurance to cover our directors, officers, and some of our employees for certain liabilities. We have entered into indemnification agreements with certain of our current directors and officers and intend to enter into indemnification agreements with future directors and officers. These agreements require us to indemnify these individuals to the fullest extent permitted under Delaware law against liability that may arise by reason of their service to us, and to advance expenses incurred as a result of any proceeding against them as to which they could be indemnified. We believe that the limitation of liability provisions in our Certificate of Incorporation, the indemnification provisions in our Bylaws and the indemnification agreements facilitate our ability to continue to attract and retain qualified individuals to serve as directors and officers.

Transfer Agent and Registrar

The transfer agent and registrar for our common stock is Computershare Trust Company, N.A.

Listing

Our common stock is listed on the NYSE under the symbol “MR.”

 

 

 

Exhibit 21.1

LIST OF SUBSIDIARIES OF MONTAGE RESOURCES CORPORATION

 

Name of Subsidiary

 

Jurisdiction of Organization

 

 

 

Eclipse GP, LLC

 

Delaware

 

 

 

Eclipse Resources I, LP

 

Delaware

 

 

 

Eclipse Resources Operating, LLC

 

Delaware

 

 

 

Eclipse Resources - Ohio, LLC

 

Delaware

 

 

 

Buckeye Minerals & Royalties, LLC

 

Delaware

 

 

 

Eclipse Resources Midstream, LP

 

Delaware

 

 

 

Eclipse Resources Marketing, LP

 

Delaware

 

 

 

Eclipse Resources – PA, LP

 

Delaware

 

 

 

Blue Ridge Mountain Resources, Inc.

 

Delaware

 

 

 

Magnum Hunter Resources GP, LLC

 

Delaware

 

 

 

Magnum Hunter Services, LLC

 

Delaware

 

 

 

Triad Hunter, LLC

 

Delaware

 

 

 

Shale Hunter, LLC

 

Delaware

 

 

 

NGAS Hunter, LLC

 

Delaware

 

 

 

Bakken Hunter, LLC

 

Delaware

 

 

 

Magnum Hunter Resources, LP

 

Delaware

 

 

 

Viking International Resources Co., Inc.

 

Delaware

 

 

 

Hunter Real Estate, LLC

 

Delaware

 

 

 

Alpha Hunter Drilling, LLC

 

Delaware

 

 

 

Triad Holdings, LLC

 

Ohio

 

 

 

Magnum Hunter Production, Inc.

 

Kentucky

 

 

 

VIRCO Pipeline of West Virginia, LLC

 

West Virginia

 

 

 

VIRCO Pipeline of Ohio, LLC

 

Ohio

 

 

 

NGAS Gathering, LLC

 

Kentucky

 

 

 

Daugherty Petroleum N.D. Ventures LLC

 

Delaware

 

 

 

Exhibit 23.1

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We have issued our reports dated March 10, 2020 with respect to the consolidated financial statements and internal control over financial reporting included in the Annual Report of Montage Resources Corporation on Form 10-K for the year ended December 31, 2019. We consent to the incorporation by reference of said reports in the Registration Statements of Montage Resources Corporation on Forms S-8 (File No. 333-197207, File No. 333-218445 and File No. 333-232101) and on Forms S-3 (File No. 333-202037 and File No. 333-223996).

/s/ GRANT THORNTON LLP

Pittsburgh, Pennsylvania

March 10, 2020

 

 

Exhibit 23.2

Software Integrated Solutions

 

 

Division of Schlumberger Technology Corporation

 

 

 

 

4600 J Barry Court

 

Suite 200

 

 

Canonsburg, Pennsylvania  15317 USA

 

 

Tel:  +1-724-416-9700

 

 

Fax:  +1-724-416-9705

 

 

 

 

 

CONSENT OF INDEPENDENT PETROLEUM ENGINEERS

 

As independent oil and gas consultants, Software Integrated Solutions, Division of Schlumberger Technology Corporation hereby consents (i) to the incorporation by reference in the Registration Statements on Form S-8 (File Nos. 333-197207, 333-218445 and 333-232101) and Form S-3 (File Nos. 333-202037 and 333-223996) of Montage Resources Corporation of all references to our firm and information from our reserves report dated 18 February 2020, included in or made a part of the Montage Resources Corporation Annual Report on Form 10-K for the year ended 31 December 2019, (ii) to the use in such Annual Report on Form 10-K of information from such report and the filing of such report as an exhibit to such Annual Report on Form 10-K, (iii) to the references to our firm in the form and context in which they appear in such Annual Report on Form 10-K, and (iv) to the references to our firm under the heading “Experts” in such Registration Statements.

 

 

 

Software Integrated Solutions

 

 

Division of Schlumberger Technology Corporation

 

 

 

 

 

/s/ Charles M. Boyer II

 

 

 

 

 

Charles M. Boyer II, PG, CPG

 

 

Advisor – Unconventional Reservoirs

 

 

Technical Team Leader

 

 

 

 

 

 

Canonsburg, Pennsylvania

 

 

10 March 2020

 

 

 

 

 

 

 

 

Exhibit 31.1

CERTIFICATION OF CHIEF EXECUTIVE OFFICER

PURSUANT TO RULE 13A-14(A) AND RULE 15D-14(A)

OF THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDED

I, John K. Reinhart, certify that:

1.

I have reviewed this Annual Report on Form 10-K for the year ended December 31, 2019 of Montage Resources Corporation (the “registrant”);

2.

Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.

Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.

The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

 

a.

Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

 

b.

Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

 

c.

Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

 

d.

Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.

The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

 

a.

All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

 

b.

Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: March 10, 2020

 

/s/ John K. Reinhart

John K. Reinhart

President and Chief Executive Officer

 

 

 

 

Exhibit 31.2

CERTIFICATION OF CHIEF FINANCIAL OFFICER

PURSUANT TO RULE 13A-14(A) AND RULE 15D-14(A)

OF THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDED

I, Michael L. Hodges, certify that:

1.

I have reviewed this Annual Report on Form 10-K for the year ended December 31, 2019 of Montage Resources Corporation (the “registrant”);

2.

Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.

Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.

The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

 

a.

Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

 

b.

Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

 

c.

Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

 

d.

Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.

The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

 

a.

All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

 

b.

Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: March 10, 2020

 

/s/ Michael L. Hodges

Michael L. Hodges

Executive Vice President and Chief Financial Officer

 

 

 

 

Exhibit 32.1

CERTIFICATION OF

CHIEF EXECUTIVE OFFICER

OF MONTAGE RESOURCES CORPORATION

PURSUANT TO 18 U.S.C. SECTION 1350

In connection with this Annual Report on Form 10-K of Montage Resources Corporation for the year ended December 31, 2019, I, John K. Reinhart, President and Chief Executive Officer of Montage Resources Corporation, hereby certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that to my knowledge:

 

1.

This Annual Report on Form 10-K for the year ended December 31, 2019 fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

 

2.

The information contained in this Annual Report on Form 10-K for the year ended December 31, 2019 fairly presents, in all material respects, the financial condition and results of operations of Montage Resources Corporation.

 

Date: March 10, 2020

 

/s/ John K. Reinhart

 

 

John K. Reinhart

 

 

President and Chief Executive Officer

 

 

 

Exhibit 32.2

CERTIFICATION OF

CHIEF FINANCIAL OFFICER

OF MONTAGE RESOURCES CORPORATION

PURSUANT TO 18 U.S.C. SECTION 1350

In connection with this Annual Report on Form 10-K of Montage Resources Corporation for the year ended December 31, 2019, I, Michael L. Hodges, Executive Vice President and Chief Financial Officer of Montage Resources Corporation, hereby certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that to my knowledge:

 

1.

This Annual Report on Form 10-K for the year ended December 31, 2019 fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

 

2.

The information contained in this Annual Report on Form 10-K for the year ended December 31, 2019 fairly presents, in all material respects, the financial condition and results of operations of Montage Resources Corporation.

 

Date: March 10, 2020

 

/s/ Michael L. Hodges

 

 

Michael L. Hodges

 

 

Executive Vice President and Chief Financial Officer

 

 

Exhibit 99.1

 

Software Integrated Solutions

Division of Schlumberger Technology Corporation

 

 

4600 J. Barry Court

Suite 200

Canonsburg, Pennsylvania 15317 USA

Tel: +1-724-416-9700

Fax: +1-724-416-9705

 

18 February 2020

 

Montage Resources Corporation

122 W. John Carpenter Fwy, Suite 300

Irving, Texas 75039

Dear Gentlemen:

At the request of Montage Resources Corporation (Montage), through their letter of engagement, Software Integrated Solutions (SIS) Division of Schlumberger Technology Corporation has evaluated the proved reserves of certain Montage operated and non-operated oil and gas interests producing from various fields in the United States (U.S.) as of 31 December 2019. The oil and gas reserves are grouped into four asset areas: Magnum Hunter Production, Shale Hunter, Triad Hunter, and Unconventional. This report was completed as of the date of this letter and has been prepared using constant prices and costs and conforms to our understanding of the U.S. Securities and Exchange Commission (SEC) guidelines and applicable financial accounting rules. All prices, costs, and cash flow estimates are expressed in U.S. dollars (US$). It is our understanding that the properties evaluated by SIS comprise approximately 100% of Montage’s total proved reserves. We prepared this report for Montage’s use in filing with the SEC and believe that the assumptions, data, methods, and procedures used in preparing this report are appropriate for the purpose of this report. The Lead Evaluator for this evaluation was Charles M. Boyer II, PG, CPG, and his qualifications, independence, objectivity, and confidentiality meet the 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.

The results of the Proved reserve evaluation are summarized in Table 1.

 

Table 1

Estimated Net Reserves And Income

Certain Proved Oil And Gas Interests

Summarized By Reserve Category

Montage Resources Corporation

As Of 31 December 2019

31 December 2019 SEC Pricing

 

Remaining Net Reserves

 

Proved

Producing

Reserves

 

Proved Non-

Producing

Reserves

 

Proved

Undeveloped

Reserves

 

Total

Proved

Reserves

Oil – Mbbls

 

12,509.86

 

2.74

 

17,812.23

 

30,324.83

NGL – Mbbls

 

39,316.26

 

0.00

 

29,043.18

 

68,359.44

Gas – MMscf

 

1,118,769.08

 

64,431.74

 

954,503.20

 

2,137,704.02

Gas Equiv. – MMscfe

 

1,429,725.79

 

64,448.18

 

1,235,635.68

 

2,729,809.66

 

 

 

 

 

 

 

 

 

Income Data (M$)

 

 

 

 

 

 

 

 

Future Net Revenue

 

4,226,642.51

 

153,095.79

 

3,832,783.16

 

8,212,521.47

Deductions

 

 

 

 

 

 

 

 

Operating Expense

 

2,073,458.42

 

60,417.13

 

1,435,237.23

 

3,569,112.78

Production Taxes

 

169,608.99

 

5,784.83

 

122,674.76

 

298,068.58

Abandonment Expense

 

55,542.23

 

618.74

 

16,228.13

 

72,389.10

Investment

 

0.00

 

5,577.42

 

904,354.39

 

909,931.80

Future Net Cashflow (FNC)

 

1,928,032.88

 

80,697.68

 

1,354,288.71

 

3,363,019.26

Discounted PV @ 10% (M$)

 

1,045,824.32

 

48,171.76

 

376,655.19

 

1,470,651.27

 

 

 

 

 

Software Integrated Solutions

 

 

Division of Schlumberger Technology Corporation

 

 

 

 

18 February 2020

 

 

Page 2

 

 

 

The values in the table above may not add up arithmetically due to rounding procedures in the computer software program used to prepare the economic projections. All hydrocarbon liquids are reported as 42 gallon barrels. Gas volumes are reported at the standard pressure and temperature bases of the area where the gas is sold.

 

We are independent with respect to Montage as provided in the SEC regulations. Neither the employment of nor the compensation received by SIS was contingent upon the values estimated for the properties included in this report.

 

Oil and gas reserves by definition fall into one of the following categories: proved, probable, and possible. The proved category is further divided into: developed and undeveloped. The developed reserve category is even further divided into the appropriate reserve status subcategories: producing and non-producing. Non-producing reserves include shut-in and behind-pipe reserves. The reserves included in this report include only proved reserves and do not include probable or possible reserves. Montage has an active exploration and development program to develop their interests in certain tracts not classified as proved at this time. Future drilling may result in the reclassification of additional volumes to the proved reserve category. However, changes in the regulatory requirements for oil and gas operations may impact future development plans and the ability of the company to recover the estimated proved undeveloped reserves. The reserves and income attributable to the various reserve categories included in this report have not been adjusted to reflect the varying degrees of risk associated with them.

 

Reserve estimates are strictly technical judgments. The accuracy of any reserve estimate is a function of the quality and quantity of data available and of the engineering and geological interpretations. The reserve estimates presented in this report are believed reasonable; however, they are estimates only and should be accepted with the understanding that reservoir performance subsequent to the date of the estimate may justify their revision. A portion of these reserves are for producing or non-producing wells that lack sufficient production history to utilize conventional performance-based reserve estimates. In these cases, the reserves are based on volumetric estimates and recovery efficiencies along with analogies to similar producing areas. These reserve estimates are subject to a greater degree of uncertainty than those based on substantial production and pressure data. As additional production and pressure data becomes available, these estimates may be revised up or down. Actual future prices may vary significantly from the prices used in this evaluation; therefore, future hydrocarbon volumes recovered and the income received from these volumes may vary significantly from those estimated in this report. The present worth is shown to indicate the effect of time on the value of money and should not be construed as being the fair market value of the properties.

 

Standard geological and engineering methods generally accepted by the petroleum industry were used in the estimation of Montage’s reserves. Deterministic methods were used for all reserves included in this report. The appropriate combination of conventional decline curve analysis (DCA), production data analysis, volumetrics, reservoir simulation, and type curves were used to estimate the remaining reserves in the various producing areas. Volumetric calculations were based on data and maps provided by Montage. Comparisons were made to similar properties for which more complete data were available for areas of new development.

 

All prices used in the preparation of this report were based on the twelve month unweighted arithmetic average of the first day of the month price for the period January through December 2019. This resulted in a price of $55.85/Bbl for oil (WTI), and $2.58/MMBtu for gas (Henry Hub). Henry Hub gas price and West Texas Intermediate oil price are common reference prices for natural gas and oil production in the U.S. The prices were adjusted for local differentials, gravity and Btu where applicable. As required by SEC guidelines, all pricing was held constant for the life of the projects (no escalation). Table 2 summarizes the 2019 reference prices and the resulting average prices used in this reserves evaluation. The average prices were calculated using the total future revenue by product prior to taxes and expenses divided by the total net reserves by product.

 

 

 

Software Integrated Solutions

 

 

Division of Schlumberger Technology Corporation

 

 

 

 

18 February 2020

 

 

Page 3

 

 

 

Table 2

Montage Resources Corporation Oil, Gas And NGL Prices

Year End 2019 Reserves Evaluation

 

Product

Reference Point

Year End 2019

Reference Price

Average Realized

Price

Oil

West Texas Intermediate

$55.85/Bbl

$48.71/Bbl

NGL

West Texas Intermediate

$55.85/Bbl

$22.36/Bbl

Natural Gas

Henry Hub

$2.58/MMBtu

$2.44/Mscf

 

Operating costs used in this report were based on values reported by Montage and reviewed by SIS. Operating cost assumptions were based on the historical averages by area. Montage’s estimates for capital costs for all non-producing and undeveloped wells are included in the evaluation. Montage has indicated to us that they have the ability and intent to implement their capital expenditure program as scheduled. Operating costs and capital costs were held constant for the life of the projects (no escalation).

 

Net revenue (sales) is defined as the total proceeds from the sale of oil, condensate, natural gas liquids (NGL), and gas adjusted for commodity price basis differential. Future net income (cashflow) is future net revenue less net lease operating expenses, gathering expenses, transportation expense, state severance or production taxes, operating/development capital expenses and net salvage. Future plugging, abandonment, and salvage costs are included at the economic life of each well or unit with proved reserves. No provisions for State or Federal income taxes have been made in this evaluation. The present worth (discounted cashflow) at various discount rates is calculated on a monthly basis.

 

In the conduct of our evaluation, we have not independently verified the accuracy and completeness of information and data furnished by Montage with respect to ownership interests, historical oil and gas production, costs of operation and development, product prices, payout balances, and agreements relating to current and future operations and sales of production. If in the course of our examination something came to our attention which brought into question the validity or sufficiency of any of the information or data provided by Montage, we did not rely on such information or data until we had satisfactorily resolved our questions relating thereto or independently verified such information or data.

 

In our opinion the above-described estimates of Montage’s proved reserves and supporting data are, in the aggregate, reasonable. It is also our opinion that the above-described estimates of Montage’s proved reserves conform to the definitions of proved oil and gas reserves promulgated by the Securities and Exchange Commission. These reserves definitions are provided at the conclusion of this letter.

 

All data used in this study were obtained from Montage, public industry information sources, or the non- confidential files of SIS. A field inspection of the properties was not made in connection with the preparation of this report. The potential environmental liabilities attendant to ownership and/or operation of the properties have not been addressed in this report. Abandonment and clean-up costs and possible salvage value of the equipment were considered in this report.

 

In evaluating the information at our disposal related to this report, we have excluded from our consideration all matters which require a legal or accounting interpretation, or any interpretation other than those of an engineering or geological nature. In assessing the conclusions expressed in this report pertaining to all aspects of oil and gas evaluations, especially pertaining to reserve evaluations, there are uncertainties inherent in the interpretation of engineering data, and such conclusions represent only informed professional judgments.

 

 

 

Software Integrated Solutions

 

 

Division of Schlumberger Technology Corporation

 

 

 

 

18 February 2020

 

 

Page 4

 

 

 

 

Data and worksheets used in the preparation of this evaluation will be maintained in our files in Canonsburg and will be available for inspection by anyone having proper authorization from Montage.

 

Sincerely yours,

 

/s/ Denise L. Delozier

 

/s/ Charles M. Boyer II

 

 

 

Denise L. Delozier

 

Charles M. Boyer II, PG, CPG

Principal Reservoir Engineer

 

Advisor – Unconventional Reservoirs

 

 

Technical Team Leader

 

 

 

 

 

 

SECURITIES AND EXCHANGE COMMISION

REGULATION S-X, RULE 210.4-10 (a)

RESERVES DEFINITIONS

(1)  Acquisition of properties. Costs incurred to purchase, lease or otherwise acquire a property, including costs of lease bonuses and options to purchase or lease properties, the portion of costs applicable to minerals when land including mineral rights is purchased in fee, brokers' fees, recording fees, legal costs, and other costs incurred in acquiring properties.

(2)  Analogous reservoir. Analogous reservoirs, as used in resources assessments, have similar rock and fluid properties, reservoir conditions (depth, temperature, and pressure) and drive mechanisms, but are typically at a more advanced stage of development than the reservoir of interest and thus may provide concepts to assist in the interpretation of more limited data and estimation of recovery. When used to support proved reserves, an “analogous reservoir” refers to a reservoir that shares the following characteristics with the reservoir of interest:

(i)  Same geological formation (but not necessarily in pressure communication with the reservoir of interest);

(ii)  Same environment of deposition;

(iii)  Similar geological structure; and

(iv)  Same drive mechanism.

Instruction to paragraph (a)(2): Reservoir properties must, in the aggregate, be no more favorable in the analog than in the reservoir of interest.

(3)  Bitumen. Bitumen, sometimes referred to as natural bitumen, is petroleum in a solid or semi- solid state in natural deposits with a viscosity greater than 10,000 centipoise measured at original temperature in the deposit and atmospheric pressure, on a gas free basis. In its natural state it usually contains sulfur, metals, and other non-hydrocarbons.

(4)  Condensate. Condensate is a mixture of hydrocarbons that exists in the gaseous phase at original reservoir temperature and pressure, but that, when produced, is in the liquid phase at surface pressure and temperature.

(5)  Deterministic estimate. The method of estimating reserves or resources is called deterministic when a single value for each parameter (from the geoscience, engineering, or economic data) in the reserves calculation is used in the reserves estimation procedure.

(6)  Developed oil and gas reserves. Developed oil and gas reserves are reserves of any category that can be expected to be recovered:

(i)  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; and

(ii)  Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

(7)  Development costs. Costs incurred to obtain access to proved reserves and to provide facilities for extracting, treating, gathering and storing the oil and gas. More specifically, development costs, including depreciation and applicable operating costs of support equipment and facilities and other costs of development activities, are costs incurred to:

(i)  Gain access to and prepare well locations for drilling, including surveying well locations for the purpose of determining specific development drilling sites, clearing ground, draining, road building, and relocating public roads, gas lines, and power lines, to the extent necessary in developing the proved reserves.

 

 

(ii)  Drill and equip development wells, development-type stratigraphic test wells, and service wells, including the costs of platforms and of well equipment such as casing, tubing, pumping equipment, and the wellhead assembly.

(iii)  Acquire, construct, and install production facilities such as lease flow lines, separators, treaters, heaters, manifolds, measuring devices, and production storage tanks, natural gas cycling and processing plants, and central utility and waste disposal systems.

(iv)  Provide improved recovery systems.

(8)  Development project. A development project is the means by which petroleum resources are brought to the status of economically producible. As examples, the development of a single reservoir or field, an incremental development in a producing field, or the integrated development of a group of several fields and associated facilities with a common ownership may constitute a development project.

(9)  Development well. A well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive.

(10)  Economically producible. The term economically producible, as it relates to a resource, means a resource which generates revenue that exceeds, or is reasonably expected to exceed, the costs of the operation. The value of the products that generate revenue shall be determined at the terminal point of oil and gas producing activities as defined in paragraph (a)(16) of this section.

(11)  Estimated ultimate recovery (EUR). Estimated ultimate recovery is the sum of reserves remaining as of a given date and cumulative production as of that date.

(12)  Exploration costs. Costs incurred in identifying areas that may warrant examination and in examining specific areas that are considered to have prospects of containing oil and gas reserves, including costs of drilling exploratory wells and exploratory-type stratigraphic test wells. Exploration costs may be incurred both before acquiring the related property (sometimes referred to in part as prospecting costs) and after acquiring the property. Principal types of exploration costs, which include depreciation and applicable operating costs of support equipment and facilities and other costs of exploration activities, are:

(i)  Costs of topographical, geographical and geophysical studies, rights of access to properties to conduct those studies, and salaries and other expenses of geologists, geophysical crews, and others conducting those studies. Collectively, these are sometimes referred to as geological and geophysical or G&G costs.

(ii)  Costs of carrying and retaining undeveloped properties, such as delay rentals, ad valorem taxes on properties, legal costs for title defense, and the maintenance of land and lease records.

(iii)  Dry hole contributions and bottom hole contributions.

(iv)  Costs of drilling and equipping exploratory wells.

(v)  Costs of drilling exploratory-type stratigraphic test wells.

(13)  Exploratory well. An exploratory well is a well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir. Generally, an exploratory well is any well that is not a development well, an extension well, a service well, or a stratigraphic test well as those items are defined in this section.

(14)  Extension well. An extension well is a well drilled to extend the limits of a known reservoir.

(15)  Field. An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition. There may be two or more reservoirs in a field that are separated vertically by intervening impervious, strata, or laterally by local geologic barriers, or by both. Reservoirs that are associated by being in overlapping or adjacent fields may be treated as a single or common operational field. The geological terms structural feature and stratigraphic condition are intended to identify localized geological features as opposed to the broader terms of basins, trends, provinces, plays, areas-of-interest, etc.

 

 

(16)  Oil and gas producing activities. (i) Oil and gas producing activities include:

(A)  The search for crude oil, including condensate and natural gas liquids, or natural gas (“oil and gas”) in their natural states and original locations;

(B)  The acquisition of property rights or properties for the purpose of further exploration or for the purpose of removing the oil or gas from such properties;

(C)  The construction, drilling, and production activities necessary to retrieve oil and gas from their natural reservoirs, including the acquisition, construction, installation, and maintenance of field gathering and storage systems, such as:

(1)  Lifting the oil and gas to the surface; and

(2)  Gathering, treating, and field processing (as in the case of processing gas to extract liquid hydrocarbons); and

(D)  Extraction of saleable hydrocarbons, in the solid, liquid, or gaseous state, from oil sands, shale, coalbeds, or other nonrenewable natural resources which are intended to be upgraded into synthetic oil or gas, and activities undertaken with a view to such extraction.

Instruction 1 to paragraph (a)(16)(i): The oil and gas production function shall be regarded as ending at a “terminal point”, which is the outlet valve on the lease or field storage tank. If unusual physical or operational circumstances exist, it may be appropriate to regard the terminal point for the production function as:

a.  The first point at which oil, gas, or gas liquids, natural or synthetic, are delivered to a main pipeline, a common carrier, a refinery, or a marine terminal; and

b.  In the case of natural resources that are intended to be upgraded into synthetic oil or gas, if those natural resources are delivered to a purchaser prior to upgrading, the first point at which the natural resources are delivered to a main pipeline, a common carrier, a refinery, a marine terminal, or a facility which upgrades such natural resources into synthetic oil or gas.

Instruction 2 to paragraph (a)(16)(i): For purposes of this paragraph (a)(16), the term saleable hydrocarbons means hydrocarbons that are saleable in the state in which the hydrocarbons are delivered.

(ii)  Oil and gas producing activities do not include:

(A) Transporting, refining, or marketing oil and gas;

(B)  Processing of produced oil, gas or natural resources that can be upgraded into synthetic oil or gas by a registrant that does not have the legal right to produce or a revenue interest in such production;

(C)  Activities relating to the production of natural resources other than oil, gas, or natural resources from which synthetic oil and gas can be extracted; or

(D) Production of geothermal steam.

(17)  Possible reserves. Possible reserves are those additional reserves that are less certain to be recovered than probable reserves.

(i)  When deterministic methods are used, the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves. When probabilistic methods are used, there should be at least a 10% probability that the total quantities ultimately recovered will equal or exceed the proved plus probable plus possible reserves estimates.

(ii)  Possible reserves may be assigned to areas of a reservoir adjacent to probable reserves where data control and interpretations of available data are progressively less certain. Frequently, this will be in areas where geoscience and engineering data are unable to define clearly the area and vertical limits of commercial production from the reservoir by a defined project.

(iii)  Possible reserves also include incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than the recovery quantities assumed for probable reserves.

 

 

(iv)  The proved plus probable and proved plus probable plus possible reserves estimates must be based on reasonable alternative technical and commercial interpretations within the reservoir or subject project that are clearly documented, including comparisons to results in successful similar projects.

(v)  Possible reserves may be assigned where geoscience and engineering data identify directly adjacent portions of a reservoir within the same accumulation that may be separated from proved areas by faults with displacement less than formation thickness or other geological discontinuities and that have not been penetrated by a wellbore, and the registrant believes that such adjacent portions are in communication with the known (proved) reservoir. Possible reserves may be assigned to areas that are structurally higher or lower than the proved area if these areas are in communication with the proved reservoir.

(vi)  Pursuant to paragraph (a)(22)(iii) of this section, where direct observation has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves should be assigned in the structurally higher portions of the reservoir above the HKO only if the higher contact can be established with reasonable certainty through reliable technology. Portions of the reservoir that do not meet this reasonable certainty criterion may be assigned as probable and possible oil or gas based on reservoir fluid properties and pressure gradient interpretations.

(18)  Probable reserves. Probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.

(i)  When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plus probable reserves. When probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the proved plus probable reserves estimates.

(ii)  Probable reserves may be assigned to areas of a reservoir adjacent to proved reserves where data control or interpretations of available data are less certain, even if the interpreted reservoir continuity of structure or productivity does not meet the reasonable certainty criterion. Probable reserves may be assigned to areas that are structurally higher than the proved area if these areas are in communication with the proved reservoir.

(iii)  Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than assumed for proved reserves.

(iv)  See also guidelines in paragraphs (a)(17)(iv) and (a)(17)(vi) of this section.

(19)  Probabilistic estimate. The method of estimation of reserves or resources is called probabilistic when the full range of values that could reasonably occur for each unknown parameter (from the geoscience and engineering data) is used to generate a full range of possible outcomes and their associated probabilities of occurrence.

(20)  Production costs. (i) Costs incurred to operate and maintain wells and related equipment and facilities, including depreciation and applicable operating costs of support equipment and facilities and other costs of operating and maintaining those wells and related equipment and facilities. They become part of the cost of oil and gas produced. Examples of production costs (sometimes called lifting costs) are:

(A)  Costs of labor to operate the wells and related equipment and facilities.

(B)  Repairs and maintenance.

(C)  Materials, supplies, and fuel consumed and supplies utilized in operating the wells and related equipment and facilities.

(D)  Property taxes and insurance applicable to proved properties and wells and related equipment and facilities.

(E)  Severance taxes.

 

 

(ii) Some support equipment or facilities may serve two or more oil and gas producing activities and may also serve transportation, refining, and marketing activities. To the extent that the support equipment and facilities are used in oil and gas producing activities, their depreciation and applicable operating costs become exploration, development or production costs, as appropriate. Depreciation, depletion, and amortization of capitalized acquisition, exploration, and development costs are not production costs but also become part of the cost of oil and gas produced along with production (lifting) costs identified above.

(21)  Proved area. The part of a property to which proved reserves have been specifically attributed.

(22)  Proved oil and gas reserves. Proved oil and gas 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—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. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

(i)  The area of the reservoir considered as proved includes:

(A)  The area identified by drilling and limited by fluid contacts, if any, and

(B)  Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.

(ii)  In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.

(iii)  Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.

(iv)  Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when:

(A)  Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and

(B)  The project has been approved for development by all necessary parties and entities, including governmental entities.

(v)  Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

(23)  Proved properties. Properties with proved reserves.

(24)  Reasonable certainty. If deterministic methods are used, reasonable certainty means a high degree of confidence that the quantities will be recovered. If probabilistic methods are used, there should be at least a 90% probability that the quantities actually recovered will equal or exceed the estimate. A high degree of confidence exists if the quantity is much more likely to be achieved than not, and, as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to estimated ultimate recovery (EUR) with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease.

 

 

(25)  Reliable technology. Reliable technology is a grouping of one or more technologies (including computational methods) that has been field tested and has been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.

(26)  Reserves. Reserves are estimated remaining quantities of oil and 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 gas or related substances to market, and all permits and financing required to implement the project.

NOTE TO PARAGRAPH (a)(26): 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).

(27)  Reservoir. A porous and permeable underground formation containing a natural accumulation of producible oil and/or gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.

(28)  Resources. Resources are quantities of oil and gas estimated to exist in naturally occurring accumulations. A portion of the resources may be estimated to be recoverable, and another portion may be considered to be unrecoverable. Resources include both discovered and undiscovered accumulations.

(29)  Service well. A well drilled or completed for the purpose of supporting production in an existing field. Specific purposes of service wells include gas injection, water injection, steam injection, air injection, salt-water disposal, water supply for injection, observation, or injection for in-situ combustion.

(30)  Stratigraphic test well. A stratigraphic test well is a drilling effort, geologically directed, to obtain information pertaining to a specific geologic condition. Such wells customarily are drilled without the intent of being completed for hydrocarbon production. The classification also includes tests identified as core tests and all types of expendable holes related to hydrocarbon exploration. Stratigraphic tests are classified as “exploratory type” if not drilled in a known area or “development type” if drilled in a known area.

(31)  Undeveloped oil and gas reserves. Undeveloped oil and gas reserves are reserves of any category 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.

(i)  Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.

(ii)  Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time.

(iii)  Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, as defined in paragraph (a)(2) of this section, or by other evidence using reliable technology establishing reasonable certainty.

(32)  Unproved properties. Properties with no proved reserves.