Overview

WildHorse Resource Development Corporation (the “Company”) is a Delaware corporation, the common stock, par value $0.01 per share, of which are listed on the New York Stock Exchange (“NYSE”) under the symbol “WRD.”  We completed our initial public offering on December 19, 2016.

We operate in one reportable segment engaged in the acquisition, exploitation, development and production of oil, natural gas and NGL resources. Our assets are characterized by concentrated acreage positions in East Texas and North Louisiana with multiple producing stratigraphic horizons, or stacked pay zones, and attractive single-well rates of return. In East Texas, we primarily operate in Burleson, Lee and Washington Counties where we primarily target the Eagle Ford Shale. In North Louisiana, we have historically operated in and around the highly prolific Terryville Complex, where we primarily targeted the overpressured Cotton Valley play. Following the NLA Divestiture (as defined below), our operations will be focused exclusively in East Texas, though all references to our assets and operations in this Annual Report do not give effect to the NLA Divestiture unless otherwise specified.

As of December 31, 2017, we had assembled a total leasehold position of approximately 585,941 gross (477,153 net) acres across our expanding acreage, including approximately 460,000 gross (387,091 net) acres in the Eagle Ford and approximately 125,941 gross (90,062 net) acres in North Louisiana. We have identified a total of approximately 6,069 gross (3,739 net) drilling locations across our acreage. For the year ended December 31, 2017, approximately 80%, 14% and 5% of our revenues were attributable to oil, natural gas and NGLs, respectively.

Recent Developments

Acquisition of Lee County Properties

On March 1, 2018, we through our wholly owned subsidiary WHR Eagle Ford LLC (“WHR EF”), closed on our acquisition of producing and non-producing properties in Lee County, Texas for approximately $18.6 million from an undisclosed seller. The properties consist of approximately 17,500 net acres immediately contiguous to our existing Eagle Ford properties and one operated (four non-operated) producing horizontal wells.

Pending Divestiture of North Louisiana Assets

        On February 12, 2018, WHR II entered into a Purchase and Sale Agreement with Tanos Energy Holdings III, LLC (“Tanos”) for the sale of all of our producing and non-producing oil and natural gas properties (including Oakfield), primarily located in Webster, Claiborne, Lincoln, Jackson and Ouachita Parishes, Louisiana (“NLA Assets”) for a total sales price of approximately $217.0 million (the “NLA Divestiture”), subject to customary purchase price adjustments.  The NLA Assets consist of all of our assets in our North Louisiana Acreage.  In addition, WRD could receive contingent payments of up to $35.0 million based on the number of wells spud over the next four years.  The effective date of the proposed sale is January 1, 2018, and we expect to close the transaction by the end of March 2018. The NLA Assets include approximately 90,000 net acres.  As of December 31, 2017, estimated proved reserves from these properties were approximately 68.7 MMBoe, or 15% of our estimated year-end 2017 proved reserves. The sale includes approximately 620 gross (356.8 net) wells that produced approximately 7.2 MBoe/d (96% gas) for the year ended December 31, 2017.  Our well count on these properties consisted of 473 gross (346.1 net) operated wells and 147 gross (10.7 net) non-operated wells.

        The sales price is subject to adjustments for (i) operating expenses, capital expenditures and revenues between the effective date and the closing date, (ii) title, casualty and environmental defects, and (iii) other purchase price adjustments customary in oil and gas purchase and sale agreements. Pursuant to the terms of the Purchase and Sale Agreement, Tanos paid WHR II a deposit of $21.7 million at signing, which amount will be applied to the sales price if the transaction closes.

        The completion of the NLA Divestiture is subject to customary closing conditions. The parties may terminate the Purchase and Sale Agreement by mutual written consent or if certain closing conditions have not been satisfied, if total adjustments to the sales price exceed 20% of the sales price, or approximately $43 million, or the transaction has not closed on or before April 30, 2018. If one or more of the closing conditions are not satisfied, or if the transaction is otherwise terminated, the divestiture may not be completed. There can be no assurance that we will sell the NLA Assets on the terms or timing described or at all. If the NLA Divestiture closes, we intend to use the net proceeds to repay amounts outstanding under our credit facility and for general corporate purposes. Please see Item 1A “Risk Factors—Risks Related to our Business—Our pending NLA Divestiture may not be consummated.”

Development of In-field Sand Mine

On February 12, 2018, we announced that Burleson Sand LLC, a wholly owned subsidiary had previously acquired surface and sand rights on approximately 727 acres in Burleson County, Texas to construct and operate an in-field sand mine.  We expect that the

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total capital expenditure for the full development of the sand mine will be approximately $65.0 - $75. 0 million in 2018, which includes the property acquisition and third-party engineering studies.

North Louisiana Settlement

On February 1, 2018, we settled a dispute related to a possible area of mutual interest (“AMI”) associated with our North Louisiana properties with a third party.  This settlement is referred to as the “North Louisiana Settlement.”  See Note 21 under “Item 8. Financial Statements and Supplementary Data” for additional information regarding the North Louisiana Settlement.

Tax Reform Legislation

On December 22, 2017, the United States ("U.S.") government enacted Public Law No. 115-97, commonly referred to as the Tax Cuts and Jobs Act (the “Tax Act”), which made significant changes to U.S. federal income tax law. We expect that certain aspects of these changes will positively impact our future after-tax earnings primarily due to the lower federal statutory income tax rate. We were required to recognize the effect of this rate change on our deferred tax assets and liabilities in 2017, the period the tax rate change was enacted. Key aspects of the Tax Act include, but are not limited to, (i) establishing a flat corporate income tax rate of 21% to replace previous rates that ranged from 15% to 35% and eliminating the corporate alternative minimum tax (“AMT”); (ii) reducing the maximum deduction for net operating loss (“NOL”) carryforwards arising in tax years beginning after December 31, 2017 to 80% of the taxpayer’s taxable income, allowing any NOLs generated in tax years beginning after December 31, 2017 to be carried forward indefinitely, and generally repealing carrybacks; (iii) limiting the deduction for net interest expense; (iv) allowing businesses to immediately expense the cost of new investments in certain qualified depreciable assets acquired after September 27,  2017 (with a phase-down of such expensing starting in 2023); and (v) repealing the Section 199 domestic production deduction beginning in 2018.; The Tax Act did not include any changes with respect to the current option to expense Intangible Drilling Costs or the Percentage Depletion deduction. See Note 17 under “Item 8. Financial Statements and Supplementary Data” for additional information regarding our income taxes.

2017 Developments

APC/KKR Acquisition

On May 10, 2017, we, through our wholly owned subsidiary, WHR EF,  entered into a Purchase and Sale Agreement (the “First Acquisition Agreement”) by and among WHR EF, as purchaser, and Anadarko E&P Onshore LLC (“APC”), Admiral A Holding L.P., TE Admiral A Holding L.P. and Aurora C-I Holding L.P. (collectively, “KKR” and, together with APC, the “First Sellers”), as sellers, to acquire certain acreage and associated production in Burleson, Brazos, Lee, Milam, Robertson and Washington Counties, Texas (the “Purchase”). Also on May 10, 2017, WHR EF entered into a Purchase and Sale Agreement (together, with the First Acquisition Agreement, the “Acquisition Agreements”), by and among WHR EF, as purchaser, and APC and Anadarko Energy Services Company (together, with APC, the “APC Subs” and together with the First Sellers, the “Sellers”), as sellers, to acquire certain acreage and associated production in Burleson, Brazos, Lee, Milam, Robertson, and Washington Counties, Texas (together, with the Purchase, the “Acquisition”).

Pursuant to the Acquisition Agreements, on June 30, 2017, we completed the acquisition of approximately 111,000 acres and the associated production therefrom. The aggregate purchase price for the assets, as described in the Acquisition Agreements, consisted of an aggregate of approximately $533.6 million of cash to the APC Subs and approximately 5.5 million shares of our common stock valued at approximately $60.8 million to KKR. The common stock portion of the purchase price payable to KKR was issued pursuant to a Stock Issuance Agreement that was executed, on May 10, 2017, by and among us and KKR.

Preferred Stock Issuance

We partially funded the Acquisition through the issuance of 435,000 shares of Preferred Stock in exchange for $435.0 million on June 30, 2017, pursuant to a Preferred Stock Purchase Agreement (the “Preferred Stock Purchase Agreement”), by and among us and CP VI Eagle Holdings, L.P. (the “Carlyle Investor”), an affiliate of The Carlyle Group, L.P.  See Note 10 under “Item 8. Financial Statements and Supplementary Data” for additional information regarding our preferred stock issuance.

Amendments to Credit Agreement

On June 30, 2017, the Company, each of the Company’s wholly owned subsidiaries (each as a guarantor), Wells Fargo Bank, National Association, as administrative agent (the “Administrative Agent”), and the lenders party thereto entered into a second amendment (the “Second Amendment”) to the Credit Agreement dated as of December 19, 2016, among the Company, the Administrative Agent and the other agents and lenders party thereto (as amended, the “Credit Agreement”).

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The Second Amendment, among other things, modified the Credit Agreement to (a) permit the Company to enter into the Acquisition, and the Preferred Stock Purchase Agreement, a nd perform its obligations under and in connection therewith, including the issuance of the Preferred Stock, (b) increase the Company’s borrowing base and elected commitment amount from $450 million to $650 million, (c) increase the annual cap on certain r estricted payments from $50 million to $75 million, and (d) modify the definition of net debt so that certain contingent obligations, accounts payable, obligations to make deliveries in respect of advance payments, take or pay obligations, disqualified cap ital stock and obligations in respect of production payments are excluded from net debt for purposes of the Company’s leverage covenant.

On October 4, 2017, the Company, each of the Company’s wholly owned subsidiaries (each as a guarantor), the Administrative Agent, and the lenders party thereto entered into a Third Amendment (the “Third Amendment”) to the Credit Agreement.  The Third Amendment, among other things, modified the Credit Agreement to (i) increase the aggregate maximum credit amount to $2.0 billion from $1.0 billion, (ii) increase the borrowing base from $612.5 million to $875.0 million and (iii) add additional lenders.

2025 Senior Notes Offering

On February 1, 2017, we completed a private placement of $350.0 million aggregate principal amount of 6.875% senior unsecured notes due 2025 (the “2025 Senior Notes”).  The 2025 Senior Notes were issued at a price of 99.244% of par and resulted in net proceeds of approximately $338.6 million.  In addition, on September 19, 2017, we completed another private placement of $150.0 million aggregate principal amount of the 2025 Senior Notes issued at 98.26% of par, which resulted in net proceeds of approximately $144.7 million. The notes issued in September 2017 are treated as a single class of debt securities with the 2025 Senior Notes issued in February 2017.   The 2025 Senior Notes will mature on February 1, 2025 and interest is payable on February 1 and August 1 of each year.  The 2025 Senior Notes are fully and unconditionally guaranteed on a joint and several basis by all of our existing and certain future subsidiaries (subject to customary release provisions).  We have no material assets or operations that are independent of our existing subsidiaries.   There are no restrictions on our ability to obtain funds from our subsidiaries through dividends or loans.  The net proceeds from each of the offerings of the 2025 Senior Notes were used to repay borrowings outstanding under our revolving credit facility and for general corporate purposes.

Pursuant to registration rights agreements entered into in connection with the offerings of the 2025 Senior Notes, we agreed to file a registration statement with the Securities and Exchange Commission (the “SEC”) so that holders of the 2025 Senior Notes could exchange the unregistered 2025 Senior Notes for registered notes with substantially identical terms. In addition, we agreed to exchange the unregistered guarantees related to the 2025 Senior Notes for registered guarantees with substantially identical terms.  On November 20, 2017, substantially all of the outstanding 2025 Senior Notes were exchanged for an equal principal amount of registered 6.875% senior notes due 2025 pursuant to an effective registration statement on Form S-4.

We may redeem all or any part of the 2025 Senior Notes at a “make-whole” redemption price, plus accrued and unpaid interest, at any time before February 1, 2020.  We may also redeem up to 35% of the aggregate principal amount of the 2025 Senior Notes prior to February 1, 2020 in an amount not greater than the net cash proceeds from one or more equity offerings at a redemption price of 106.875% of the principal amount of the 2025 Senior Notes, plus accrued and unpaid interest.

Exercise of Underwriters’ Over-allotment Option

On January 17, 2017, we issued and sold 2,297,100 shares of our common stock at an offering price of $15.00 per share pursuant to the partial exercise of the underwriters’ over-allotment option associated with our initial public offering (the “Option Exercise”). We received net proceeds of $32.6 million from the Option Exercise, all of which was used to repay outstanding borrowings under our revolving credit facility.

Our Properties

Eagle Ford Acreage

The Eagle Ford Shale is one of the most active unconventional shale trends in North America. According to weekly rig count metrics published by Baker Hughes, the Eagle Ford Shale has consistently been one of the most active basins in the United States since 2011 and currently has the second highest rig count of all major U.S. basins.  The Eagle Ford Shale trends across Texas from the Mexican border north into East Texas and is roughly 50 miles wide and 400 miles long. The Eagle Ford Shale rests between the Austin Chalk and the Buda Lime at a depth of approximately 4,000 to 14,000 feet. As of December 31, 2017, there were approximately 36,000 producing wells in the Eagle Ford with an average production of 2.1 MMBoe/d in December 2017.

We currently target a portion of the Eagle Ford Shale at depths between 6,000 feet and 13,000 feet primarily in Burleson, Lee, Brazos and Washington Counties, Texas. This portion of the Eagle Ford Shale averages 125 feet in thickness and contains 70% carbonate. We believe that the elevated carbonate percentages are in large part responsible for the brittleness of the Eagle Ford and successful completions which exhibit high productivity when fractured. The overall clay content of the Eagle Ford increases regionally as it continues progressively northeast into Brazos, Grimes and Madison Counties, Texas.

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We are focused on maximizing returns and expect operational efficiencies to extend beyond our existing drilling inventory to additional horizons. In addition, our acreage has been extensively developed for more than 40 years through the development of the Gi ddings Austin Chalk Trend. Based on analysis and interpretation of well results and other geologic and engineering data, we believe our acreage is also prospective for the Georgetown, Buda, Woodbine and Pecan Gap formations. Historical operators in the Gid dings Austin Chalk Trend have experienced drilling and production success during our industry’s pre-multistage frac era (1970s-2000s). Future development results achieved by us and offset operators may allow us to expand our existing location inventory thr oughout our leasehold.

We entered the Eagle Ford with the goal of redeveloping the area with horizontal drilling and modern completion techniques. Since that time, we have completed multiple bolt-on acquisitions and in-fill leases to build our current position in the Eagle Ford.  We have identified a substantial inventory of 4,675 gross drilling locations within our Eagle Ford Acreage across Burleson, Brazos, Lee, Robertson and Washington Counties.  The wells in our Eagle Ford Acreage have shown a strong track record of increasing EURs and a decreasing trend in drilling and completion capital costs.  

As of December 31, 2017, our Eagle Ford position included approximately 387,091 net acres. Also, as of December 31, 2017, approximately 69% of our Eagle Ford Acreage was held by production, with an average working interest of 84%, and, as of December 31, 2017, 22% of our 385.6 MMBoe of proved reserves were developed, 88% of which were liquids. Since January 2014, we and our previous owner have drilled and completed 125 wells, acquired 878 wells and participated in 26 wells resulting in total net production of approximately 23.5 MBoe/d (76% oil, 10% natural gas and 14% NGLs), including non-operated production.

North Louisiana Acreage

Within our North Louisiana Acreage we primarily target the overpressured Cotton Valley formation in the Terryville Complex. The Cotton Valley formation, extending across East Texas, North Louisiana and Southern Arkansas, has been under development since the 1930s and is characterized by thick, multi-zone natural gas and oil reservoirs with well-known geologic characteristics and long-lived, predictable production profiles. In 2005, operators started redeveloping the Cotton Valley using horizontal drilling and advanced hydraulic fracturing techniques. Some large, analogous redevelopment projects in the Terryville Complex include the Terryville play in Lincoln Parish, the Nan-Su-Gail area in Freestone County, East Texas and the Carthage Complex in Panola County, East Texas.

Our North Louisiana Acreage spans across the Webster, Claiborne, Bienville, Lincoln, Jackson and Ouachita Parishes, focusing on the Bear Creek field and the RCT and Weyerhaeuser Areas, where we are targeting overpressured Cotton Valley opportunities in multiple zones. We believe the Terryville Complex, which has been producing since 1954, is one of North America’s most prolific liquids rich natural gas plays, characterized by high recoveries relative to drilling and completion costs, high initial production rates with high liquids yields, long reserve life, multiple stacked pay zones, available infrastructure and a large number of service providers. The RCT Area is a direct offset of the Terryville Field and is part of the same Terryville Complex trend. Following the NLA Divestiture, we do not expect to continue operating in this area.

As of December 31, 2017, our North Louisiana Acreage included approximately 90,000 net acres. Also, as of December 31, 2017, 58% of our acreage was then held by production, with an average working interest of 72%, and 41% of our 68.7 MMBoe of proved reserves were developed, 97% of which were natural gas. Since the inception of our predecessor, we had drilled and completed 18 wells, acquired 597 wells and participated in 5 non-operated wells resulting in a total 2017 net production of approximately 7.2 MBoe/d (2% oil, 96% natural gas and 2% NGLs), including non-operated production. 

On February 12, 2018, WHR II entered into a Purchase and Sale Agreement with Tanos for the sale of the NLA Assets for a total sales price of approximately $217.0 million before customary adjustments. The NLA Divestiture is expected to close by the end of March 2018.

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Reserve Summary

Our estimated proved reserves of were prepared by our internal reserve engineers and audited by Cawley, Gillespie and Associates, Inc. (“Cawley”), our independent reserve engineers.  As of December 31, 2017, we had 454.3 MMBoe of estimated proved reserves.  As of this date, our proved reserves were 75% oil and NGLs and 25% natural gas.  The following table provides summary information regarding our estimated proved reserves data and our average net daily production by area based on our reserve reports as of December 31, 2017:

Business Strategies

To achieve our primary objective of delivering shareholder value, we intend to execute the following business strategies:

Grow production, reserves and cash flow through the development of our extensive drilling inventory. We believe our extensive inventory of drilling locations in the Eagle Ford and Austin Chalk formations following the consummation of the NLA Divestiture, combined with our operating expertise, will enable us to continue to deliver accretive production, reserves and cash flow growth and create shareholder value. We have identified a total of approximately 4,675 gross (3,097 net) drilling locations across our Eagle Ford acreage, with further upside potential given the multiple stacked pay zones across much of our acreage in addition to potential downspacing. We will continue to closely monitor offset operators as they delineate adjoining acreage and zones, providing us further data to optimize our development plan over time. We believe the location, concentration and scale of our core leasehold positions, coupled with our technical understanding of the reservoirs will allow us to efficiently develop our core areas and to allocate capital to maximize the value of our resource base.

Maximize returns by optimizing drilling and completion techniques and improving operating efficiencies. Our management is intently focused on driving efficiencies in the development of our resource base by maximizing our hydrocarbon recovery per well while minimizing our drilling, completion and operating costs. To achieve these efficiencies, we focus on:

In our Eagle Ford Acreage, we have reduced our drilling and completion costs per completed lateral foot by approximately 66%, from $2,958 per foot for our wells completed using Generation 1 hydraulic fracturing design to approximately $1,000 per foot for our wells completed using Generation 3 hydraulic fracturing design. Additionally, as we have transitioned our completion techniques in our Eagle Ford Acreage from Generation 1 to Generation 3 hydraulic fracturing designs, we have increased EURs by approximately 29% per completed lateral foot from an average of 76 Boe per foot to 99 Boe per foot. Our drilling and completion cost reductions coupled with our completion design improvements are generating enhanced single-well recoveries and attractive returns in the current commodity environment, and we believe we can further optimize our results through these and other technologies across our acreage position.

Capture additional horizontal development opportunities on current acreage. Our existing asset base provides numerous opportunities for our management team to create shareholder value by increasing our inventory beyond our currently identified drilling locations. Based on results from our horizontal drilling program and those of offset operators, including offset production trends, mud

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logs, 2-D and 3-D seismic, well data analysis a nd geologic trend mapping, we believe our acreage has multiple productive zones providing significant upside potential to our current inventory of identified drilling locations. We have excluded from our identified drilling locations potential opportunitie s associated with downspacing and with additional horizontal drilling locations in (i) the Austin Chalk trend in Burleson County, (ii) the Eagle Ford Shale in Washington County and (iii) the Buda, Woodbine, Georgetown and Pecan Gap zones that are present a cross much of our Eagle Ford Acreage.

Utilize extensive acquisition and technical expertise to grow our core acreage position. We have a demonstrated track record of identifying and cost effectively acquiring attractive resource development opportunities, including the recent acquisition and development highlighted under “—Recent Developments.”  To date, our management and technical teams have completed numerous acquisitions, and we expect to continue to identify and opportunistically lease or acquire additional acreage and producing assets to add to our multi-year drilling inventory. We have followed a geologically driven strategy to establish large, contiguous leasehold positions in our Eagle Ford Acreage and strategically expand those positions through bolt-on acquisitions over time. We believe our Eagle Ford Acreage creates a platform upon which we can add value by acquiring additional acreage and incremental drilling locations near our current acreage. In this regard, NGP and its affiliates are not limited in their ability to compete with us for future acquisitions, and we do not expect to enter into any agreements or arrangement to apportion future opportunities between us, on the one hand, and NGP and its affiliates, on the other hand.

Maintain a disciplined, growth-oriented financial strategy. We prudently manage our liquidity and leverage levels by monitoring cash flow, capital spending and debt capacity. We had approximately $588.6 million of available borrowing capacity under our revolving credit facility as of December 31, 2017. We intend to fund our growth primarily with internally generated cash flows and borrowings under our revolving credit facility while maintaining ample liquidity and access to the capital markets, which we believe will allow us to accelerate our development program and maximize the present value of our resource potential. Consistent with our disciplined approach to financial management, we have an active commodity hedging program that seeks to reduce our exposure to downside commodity price fluctuations, enabling us to protect cash flows and maintain liquidity to fund our capital program and investment opportunities.

Business Strengths

We believe that the following strengths will allow us to successfully execute our business strategies.

Extensive, contiguous acreage position in one of North America’s leading oil and gas plays . We own an extensive and substantially contiguous acreage position targeting one of the premier plays in North America, the Eagle Ford Shale formation. As of December 31, 2017, we had approximately 585,941 gross (477,153 net) acres and we had 454.3 MMBoe of proved reserves (62% oil, 25% natural gas and 13% NGLs) across our acreage. In February 2018, WHR II entered into a Purchase and Sale Agreement for the sale of the NLA Assets.  We believe that our recent well results demonstrate that many of the wells on our high-quality acreage are capable of producing single-well rates of return that are competitive with many of the top performing basins in the United States. Furthermore, the location of our acreage provides us with lower operating costs and better realized pricing than other companies operating in different basins around the country due to our acreage’s proximity to the end markets for oil, natural gas and NGLs.

Multi-year inventory of drilling opportunities across our acreage position. We have identified approximately 4,675 gross (3,097 net) drilling locations across our Eagle Ford Acreage, providing us with approximately 44.5 years gross (29.5 years net) of drilling inventory based on our 2018 drilling program. On our Eagle Ford Acreage, our horizontal drilling locations target the Eagle Ford Shale in Burleson and Lee Counties and the Austin Chalk in Washington County. In addition, we believe our acreage position includes a number of additional areas and zones that are prospective for hydrocarbons. For example, we believe we may identify additional horizontal drilling locations in (i) the Austin Chalk trend in Burleson County, (ii) the Eagle Ford Shale in Washington County and (iii) the Buda, Woodbine, Georgetown and Pecan Gap zones that are present across much of our Eagle Ford Acreage. Furthermore, we also believe that we may add horizontal drilling locations across our entire acreage position through downspacing.

Significant operational control over our assets with low-cost operations. As the operator of a majority of our acreage, we have significant operational control over our assets. We seek to allocate capital among projects in a manner that optimizes both costs and returns, which we believe results in a highly efficient drilling program. We believe maintaining operational control will enable us to enhance returns by implementing more efficient and cost-effective operating practices, such as through the selection of economic drilling locations, the opportunistic timing of development and ongoing improvement of drilling, completion and operating techniques. Our contiguous acreage blocks, and our practice and history of exchanging and consolidating acreage with adjacent operators, allow us to increase our working interest in our wells and provide flexibility to adjust our drilling and completion techniques, such as pad drilling and the length of our horizontal laterals, in order to optimize our well results, drilling costs and returns.

Management and technical teams with substantial technical and operational expertise. Our management and technical teams have significant industry experience and a long history of collaboration in the identification, execution and integration of acquisitions and in cost-efficient management of profitable, large-scale drilling programs. Additionally, we have substantial expertise in advanced drilling and completion technologies and decades of collective experience in operating in the Eagle Ford. Mr. Graham, our Chief Executive Officer, and Mr. Bahr, our President, co-founded one of the predecessors to, and Mr. Graham served as Chief Executive

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Officer of, Memorial Resource Development Corp. (“MRD”), which pioneered the horizontal redevelopment of the Terryville Complex, participating in the drilling of MRD’s initial 55 horizontal wells. Further, our management team has a proven track record of returning value to shareholders and a significant economic interest in us directly and th rough its equity interests in each of WildHorse Holdings and Esquisto Holdings.  We believe our management team is motivated to use its experience in identifying and creating value across our acreage and drilling highly productive wells to deliver attracti ve returns, maintain safe and reliable operations and create shareholder value.

Geographically advantaged assets with significant midstream infrastructure to service our production. Our acreage position is in close proximity to end markets for oil, natural gas and NGLs, providing us with a regional price advantage. For example, low oil and natural gas basis differentials along the Gulf Coast represent a competitive advantage when compared to other plays, such as the Bakken, Marcellus, Utica, Permian and DJ. Recently developed and low-cost legacy infrastructure is in place across significant portions of our acreage to support our development program. In addition, we own and operate a large portion of our necessary midstream infrastructure which provides us with improved netbacks. On our Eagle Ford Acreage, we own substantial fresh water supply and storage, developed saltwater disposal wells and are in the process of developing an in-field sand mine. Our midstream infrastructure allows us to realize lower operating costs and provides us with increased flexibility in our development program. In addition, while not currently contemplated, our midstream infrastructure could prove to be a future source of additional capital if monetized at an attractive valuation.

Our Principal Stockholders

WildHorse Holdings, Esquisto Holdings, Acquisition Co. Holdings, NGP XI US Holdings, L.P. (“NGP XI”), and management directly own 21.0%, 38.3%, 2.5%, 8.9% and 2.6%, respectively, of our common stock. WildHorse Holdings, Esquisto Holdings and Acquisition Co. Holdings are controlled by NGP.  Carlyle beneficially owned 435,000 shares of Preferred Stock, which, based on the conversion rate as of December 31, 2017, represented approximately 24.3% of our common stock on an as converted basis.  NGP and its affiliates (through WildHorse Holdings, Esquisto Holdings, Acquisition Co. Holdings and NGP XI) beneficially own approximately 70.7% of our common stock.  Based solely on the Schedule 13G filed on February 5, 2018 with the SEC by KKR, KKR owned approximately 5.5% of our common stock as of June 30, 2017.

Reserve Data

Preparation of Reserve Estimates

Our reserve estimates as of December 31, 2017 included in this Annual Report are based on evaluations prepared by our management and audited by the independent petroleum engineering firm of Cawley in accordance with Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Evaluation Engineers and definitions and guidelines established by the SEC. Our independent reserve engineers were selected for their historical experience and geographic expertise in engineering similar resources.

Proved reserves are reserves 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 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 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.  If deterministic methods are used, the term “reasonable certainty” implies a high degree of confidence that the quantities of oil or natural gas actually recovered will equal or exceed the estimate. If probabilistic methods are used, there should at least be a 90% probability that the quantities actually recovered will equal or exceed the estimate. The technical and economic data used in the estimation of our proved reserves include, but are not limited to, well logs, geologic maps, well-test data, production data (including flow rates), well data (including lateral lengths), historical price and cost information, and property ownership interests. Our independent reserve engineers use this technical data, together with standard engineering and geoscience methods, or a combination of methods, including performance analysis, volumetric analysis, and analogy. The proved developed reserves and EURs per well are estimated using performance analysis and volumetric analysis. The estimates of the proved developed reserves and EURs for each developed well are used to estimate the proved undeveloped reserves for each proved undeveloped location (utilizing type curves, statistical analysis, and analogy).

Internal Controls

Our internal staff of petroleum engineers and geoscience professionals works closely with our independent reserve engineers to ensure the integrity, accuracy and timeliness of data furnished to our independent reserve engineers in their reserve auditing process. Periodically, our technical team meets with the independent reserve engineers to review properties and discuss methods and assumptions used by us to prepare reserve estimates.

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

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and of engineering and geological interpretation. As a result, the estimates of different engineers often vary. In addition, the results of drilling, testing and production may justify revisions of such estimates. Accordingly, reserve estimates often differ from the quantities of oil, natural gas and NGLs that are ultimately recovered. Estimates of economically recoverable oil, natural gas and NGLs and of future net revenues are based on a number of variables and assumptions, a ll 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.

For the year ended December 31, 2017, our reserve estimates and related reports were prepared internally and reviewed and approved by Jason Pearce.  Mr. Pearce is our Senior Vice President, Reserves and has approximately 19 years of experience in oil and gas operations, reservoir engineering, reserve management, unconventional reservoir characterization and strategic planning.  Cawley performed audits of our internally prepared reserves estimates on our proved reserves as of December 31, 2017. Our proved reserves are, in the aggregate, reasonable and within the established audit tolerance guidelines of 10%. The report of Cawley contains further discussion of the reserves estimates and its audit procedure.

Cawley was founded in 1961 and performs consulting petroleum engineering services under Texas Board of Professional Engineers Registration No. F-693. Within Cawley, the technical person primarily responsible for preparing the estimates shown herein with respect to WHR II and Esquisto, was Todd Brooker. Prior to joining Cawley, Mr. Brooker worked in Gulf of Mexico drilling and production engineering at Chevron USA. Mr. Brooker has been an employee of Cawley since 1992. His responsibilities include reserve and economic evaluations, fair market valuations, field studies, pipeline resource studies and acquisition/divestiture analysis. His reserve reports are routinely used for public company SEC disclosures. His experience includes significant projects in both conventional and unconventional resources in every major U.S. producing basin and abroad, including oil and gas shale plays, coalbed methane fields, waterfloods and complex, faulted structures.  Mr. Brooker graduated with honors from the University of Texas at Austin in 1989 with a Bachelor of Science degree in Petroleum Engineering, and is a registered Professional Engineer in the State of Texas. He is also a member of the Society of Petroleum Engineers.

Development of Proved Undeveloped Reserves

As of December 31, 2017, we had 339.8 MMBoe of proved undeveloped reserves consisting of 217.8 MMBbls of oil, 462.3 MMcf of natural gas and 45.0 MBbls of NGLs, compared to 105.2 MMBoe of proved undeveloped reserves at December 31, 2016, consisting of 68.3 MMbbls of oil, 179.2 MMcf of natural gas and 7.1 MBbls of NGLs.  None of our PUDs as of December 31, 2017 are scheduled to be developed on a date more than five years from the date the reserves were initially booked to PUDs. PUDs will be converted from undeveloped to developed as the applicable wells begin production.

Our PUDs changed during 2017 as a result of:

We estimate that we incurred $91.9 million of costs to convert proved undeveloped reserves from 13 locations into proved developed reserves in 2017.

Reconciliation of PV-10 to Standardized Measure

PV-10 is a non-GAAP financial measure and differs from the Standardized measure of discounted future net cash flows, which is the most directly comparable GAAP financial measure. PV-10 is a computation of the Standardized Measure of discounted future net cash flows on a pre-tax basis. PV-10 is equal to the Standardized measure of discounted future net cash flows at the applicable date, before deducting future income taxes, discounted at 10 percent. We believe that the presentation of PV-10 is relevant and useful to

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investors because it presents the discounted future net cash flows attributable to o ur estimated net proved reserves prior to taking into account future corporate income taxes, and it is a useful measure for evaluating the relative monetary significance of our oil and natural gas properties. Further, investors may utilize the measure as a basis for comparison of the relative size and value of our reserves to other companies without regard to the specific tax characteristics of such entities. We use this measure when assessing the potential return on investment related to our oil and natura l gas properties. PV-10, however, is not a substitute for the S tandardized m easure of discounted future net cash flows. Our PV-10 measure and the S tandardized m easure of discounted future net cash flows do not purport to represent the fair value of our oil and natural gas reserves.

The following table provides a reconciliation of PV-10 of our proved reserves to the Standardized measure of discounted future net cash flows at December 31, 2017, 2016 and 2015:

Reserves Sensitivity

Historically, commodity prices have been extremely volatile and we expect this volatility to continue for the foreseeable future. For example, for the three years ended December 31, 2017, the NYMEX-WTI oil spot price ranged from a high of $61.36 per Bbl to a low of $26.19 per Bbl, while the NYMEX-Henry Hub natural gas spot price ranged from a high of $3.80 per MMBtu to a low of $1.49 per MMBtu. For the year ended December 31, 2017, the West Texas Intermediate posted price ranged from a high of $60.46 per Bbl on December 29, 2017 to a low of $42.48 per Bbl on June 21, 2017 and the Henry Hub spot market price ranged from a high of $3.71 per MMBtu on January 2, 2017 to a low of $2.44 per MMBtu on February 27, 2017. The continuation of low prices for oil or natural gas could materially and adversely affect our financial position, our results of operations, the quantities of oil and natural gas reserves that we can economically produce and our access to capital.

While it is difficult to quantify the impact of the continuation of low commodity prices on our estimated proved reserves with any degree of certainty because of the various components and assumptions used in the process of estimating reserves, the following sensitivity table is provided to illustrate the estimated impact of pricing changes on our estimated proved reserve volumes and Standardized measure. In addition to different price assumptions, the sensitivity cases below include assumed capital and operating expense changes we would expect to realize under each scenario. Sensitivity cases are used to demonstrate the impact that a change in price and cost environment may have on reserves volumes and Standardized measure. There is no assurance that these prices or cost savings will actually be achieved.

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Production, Revenue and Price History

For a description of ours, our predecessor’s and the previous owners’ combined historical production, revenues and average sales prices and unit costs, see “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Results of Operations.”  For certain financial information about our operations, see “Item 6. Selected Financial Data” and “Item 8. Financial Statements and Supplementary Data.”

The following tables summarize our average net production, average unhedged sales prices by product and average production costs by geographic region for the years ended December 31, 2017, 2016 and 2015, respectively:

Productive Wells

Productive wells consist of producing wells and wells capable of production, including natural gas wells awaiting pipeline connections to commence deliveries and oil wells awaiting connection to production facilities. Gross wells are the total number of producing wells in which we own an interest, and net wells are the sum of our fractional working interests owned in gross wells. The following table sets forth information relating to the productive wells in which we owned a working interest as of December 31, 2017.

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Approximately 69% of our net Eagle Ford Acreage and 58% of our net North Louisiana Acreage was held by production at December 31, 2017.  Included in our North Louisiana Acreage in the table above are approximately 12,848 net acres we have the right to lease pursuant to an oil and gas lease option agreement with affiliates of Weyerhaeuser Company (“Weyerhaeuser”). Pursuant to that agreement, we have the right, upon notice to Weyerhaeuser, to lease acreage in exchange for a specified bonus payment. Upon such notice and our payment of the applicable bonus payment, Weyerhaeuser is obligated under the option agreement to enter into a three-year lease with us for the acreage we specify in the notice. The purchase price of this option was $0.5 million, and in addition, we also made a prepayment of $0.4 million as an initial lease bonus for 1,285 unspecified net acres associated with leases under the option. In October 2016, we made a payment of $1.5 million to extend the option for one year.  In January 2018, we exercised our option to lease approximately 12,848 net acres from Weyerhaeuser and paid $3.9 million.  On February 12, 2018, WHR II entered into a Purchase and Sale Agreement with Tanos for the sale of the NLA Assets, which include the recently leased acreage from Weyerhaeuser, for a total sales price of approximately $217.0 million. The transaction is expected to close by the end of March 2018.

We intend to extend substantially all of the net acreage associated with our drilling locations through a combination of development drilling and leasehold extension and renewal payments. Of the 31,447 net acres expiring in 2018 across our Eagle Ford Acreage, we have the option to extend or renew the leases covering 13,124 net acres and have budgeted approximately $4.2 million in 2018 to execute extensions and renewals. With respect to the remaining 18,323 net acres for which we do not have an option to extend or renew in the Eagle Ford, 3,105 net acres are associated with 42 gross (30.0 net) wells of proved undeveloped reserves where the leases covering such expected wells will expire prior to our expected drilling date though we expect to extend or renew such leases. Further, with respect to the total remaining 18,323 net acres for which we do not have an option to extend or renew in the Eagle Ford, we intend to retain substantially all such acreage by negotiating lease extensions or renewals or drilling wells. Of the 23,694 net acres expiring in 2018 across our North Louisiana Acreage, we have the option to extend 19,101 of the 23,694 net acres in the RCT, Athens and Weyerhaeuser Areas, and we have budgeted approximately $6.8 million in 2018 to execute such extensions. As of December 31, 2017, 12,848 of the 23,694 net acres were related to the Weyerhaeuser Area.  In January 2018, we exercised our option to lease approximately 12,848 net acres from Weyerhaeuser for approximately $3.9 million.  We plan, in the event the NLA Divestiture is not consummated, to amend and extend or obtain new leases for the remaining approximately 4,593 net acres for an estimated cost of approximately $5.3 million. Please see Item 1A “Risk Factors—Risks Related to Our Business—Certain of our undeveloped leasehold acreage is subject to leases that will expire over the next several years unless production is established on units containing the acreage or the leases are renewed.”

Drilling Activities

The following table summarizes our approximate gross and net interest in wells completed during the periods indicated (including both operated and non-operated wells), regardless of when drilling was initiated. The information should not be considered indicative of future performance, nor should it be assumed that there is necessarily any correlation among the number of productive wells drilled, quantities of reserves found or economic value. A dry well is a well that proves to be incapable of producing either oil or gas in sufficient quantities to justify completion. A productive well is a well that is not a dry well. Completion refers to installation of permanent

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equipment for production of oil or gas, or, in the case of a dry well, to reporting to the app ropriate authority that the well has been abandoned.

At December 31, 2017, 16.0 gross (14.2 net) wells (including wells temporarily suspended) were in the process of being drilled.  We are currently running a six-rig program in our Eagle Ford Acreage and a one-rig program in North Louisiana Acreage, which we are utilizing on a well-to-well basis. We are not currently a party to any long-term drilling rig contracts. We plan to operate an average of 4.8 drilling rigs in the Eagle Ford and Austin Chalk in 2018.

Delivery Commitments

We have no commitments to deliver a fixed and determinable quantity of our oil or natural gas production to customers in the near future under our existing contracts.

We have a firm gas transportation service agreement with Regency Intrastate Gas LLC (“RIGS”) for properties in North Louisiana. Under the terms of the agreement, we are obligated to pay total daily transportation fees not to exceed $0.30 per MMBtu per day for quantities of 40,000 MMBtu per day to RIGS until March 5, 2019.  This agreement will be assigned to Tanos upon completion of the NLA Divestiture.

Our Operations

General

We have leased or acquired approximately 585,941 gross (477,153 net) acres where we had a weighted-average working interest of approximately 81%, as of December 31, 2017. As operator of a majority of our acreage, 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 petroleum 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.

Facilities

We maintain active development of our infrastructure to reduce lease operating costs and support our drilling schedule and production growth. Our production facilities are located near the producing well and consist of storage tanks, two-phase and three-phase

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separation equipment, flowlines, metering equipment and safety systems. Predominate artificial lift methods include foamer, gas, plunger and rod lift.  

In the Eagle Ford, our crude oil is trucked by third-party purchasers in a process that is actively managed to ensure the best available market for our oil. For gas gathering, processing and fractionation, our Eagle Ford assets are in proximity to active third-party low-pressure systems across our acreage. We have favorable long-term agreements in place with two gas gathering and processing companies with the benefit of minimal connection costs.  We own substantial fresh water supply and storage, have developed saltwater disposal wells and are in the process of developing an in-field sand mine.

In North Louisiana, approximately half of our gas production is gathered into a company owned, high-pressure pipeline system and then delivered and sold to various intrastate and interstate markets on a competitive pricing basis. The majority of our gas production is not currently processed due to current processing economics, but we have access to several third-party gas processors if processing is economically justified. We also own and operate a salt water disposal well, which currently receives the majority of our associated water production. We own another saltwater disposal well that is currently inactive.

We market the majority of our production from properties we operate for both our account and the account of the other working interest owners in these properties. We sell our oil, natural gas and NGL production to purchasers at market prices. We sell all of our oil and certain of our natural gas and NGLs under contracts with terms of twelve months or less and the remainder of our natural gas and NGLs under contracts with terms of greater than twelve months.

No other purchaser accounted for 10% or more of our revenue in the years ended December 31, 2017, 2016 or 2015. The loss of any such purchaser could adversely affect our revenues in the short term. However, based on the current demand for oil, natural gas and NGLs and the availability of other purchasers, we believe that the loss of any such purchaser as a purchaser would not have a material adverse effect on our financial condition and results of operations because crude oil and natural gas are fungible products with well-established markets and numerous purchasers.

Competition

The oil and natural gas industry is intensely competitive, and we compete with other companies that have greater resources. Many of these companies not only explore for and produce oil and natural gas, but also carry on midstream and 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 oil and natural gas properties and exploratory prospects or to define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit. In addition, these companies may have a greater ability to continue exploration activities during periods of low oil and natural gas market prices. Our larger or more integrated competitors may be able to absorb the burden of existing, and any changes to, federal, state and local laws and regulations more easily than we can, which would adversely affect our competitive position. 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 in our industry, we may be at a disadvantage in bidding for exploratory prospects and producing oil and natural gas properties.

There is also competition between oil and natural gas producers and other industries producing energy and fuel. Furthermore, competitive conditions may be substantially affected by various forms of energy legislation and/or regulation considered from time to time by the governments of the United States and the jurisdictions in which we operate. It is not possible to predict the nature of any such legislation or regulation which may ultimately be adopted or its effects upon our future operations. Such laws and regulations may substantially increase the costs of developing oil and natural gas and may prevent or delay the commencement or continuation of a given operation. 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.

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Seasonality of Business

Weather conditions can affect the demand for, and prices of, oil, natural gas and NGLs. Demand for natural gas is typically higher in the fourth and first quarters resulting in higher prices while the demand for oil is typically higher during the second and third quarters. Due to these seasonal fluctuations, results of operations for individual quarterly periods may not be indicative of the results that may be realized on an annual basis.

Title to Properties

As is customary in the oil and natural gas industry, we initially conduct only a cursory review of the title to our properties in connection with acquisition of leasehold acreage. At such time as we determine to conduct drilling operations on those properties, we conduct a thorough title examination and perform curative work with respect to significant defects prior to commencement of drilling operations. To the extent title opinions or other investigations reflect title defects on those properties, we are typically responsible for curing any title defects at our expense. We generally will not commence drilling operations on a property until we have cured any material title defects on such property. We have obtained title opinions on substantially all of our producing properties and believe that we have satisfactory title to our producing properties in accordance with standards generally accepted in the oil and natural gas industry.

Prior to completing an acquisition of producing oil and natural gas leases, we perform title reviews on the most significant leases and, depending on the materiality of properties, we may obtain a title opinion, obtain an updated title review or opinion or review previously obtained title opinions. Our oil and natural gas properties are subject to customary royalty and other interests, liens for current taxes and other burdens, which we believe do not materially interfere with the use of or affect our carrying value of the properties.

We believe that we have satisfactory title to all of our material assets. Although title to these properties is subject to encumbrances in some cases, such as customary interests generally retained in connection with the acquisition of real property, customary royalty interests and contract terms and restrictions, liens under operating agreements, liens related to environmental liabilities associated with historical operations, liens for current taxes and other burdens, easements, restrictions and minor encumbrances customary in the oil and natural gas industry, we believe that none of these liens, restrictions, easements, burdens and encumbrances will materially detract from the value of these properties or from our interest in these properties or materially interfere with our use of these properties in the operation of our business. In addition, we believe that we have obtained sufficient rights-of-way grants and permits from public authorities and private parties for us to operate our business in all material respects as described in this Annual Report.

Oil and Natural Gas Leases

The typical oil and natural gas lease agreement covering our properties provides for the payment of royalties to the mineral owner for all oil and natural gas produced from any wells drilled on the leased premises. The lessor royalties and other leasehold burdens on our properties generally range from approximately 20% to 30%.

Regulation of the Oil and Natural Gas Industry

Our operations are substantially affected by federal, state and local laws and regulations. In particular, oil and 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 oil and natural gas properties have statutory provisions regulating the development and production of oil and natural gas, 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 which 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. Such laws and regulations are frequently amended or reinterpreted. Therefore, we are unable to predict the future costs or impact of compliance. Additional proposals and proceedings that affect the oil and natural gas industry are regularly considered by Congress, the states, the Federal Energy Regulatory Commission (“FERC”), the United States Environmental Protection Agency (“EPA”), the Bureau of Land Management (“BLM”), the Department of Transportation (“DOT”), other federal and state agencies, and the courts. We cannot predict when or whether any such proposals may become effective.

In addition, unforeseen environmental incidents may occur or past non-compliance with environmental laws or regulations may be discovered.

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Regulation of Production of Oil and Natural Gas

The production of oil and natural gas 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. We own interests in properties located in Texas and Louisiana, which regulate drilling and operating activities by, among other things, requiring 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 both states also govern a number of conservation matters, including provisions for the unitization or pooling of oil and natural gas properties, the establishment of maximum allowable rates of production from oil and natural gas 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 oil and natural gas that we can produce from our wells and to limit the number of wells or the locations at which we can drill, although we can apply for exceptions to such regulations or to have reductions in well spacing or density. Moreover, various states impose a production or severance tax with respect to the production and sale of oil, natural gas and NGLs within its jurisdiction.

The failure to comply with these rules and regulations can result in substantial penalties. Our competitors in the oil and natural gas industry are subject to the same regulatory requirements and restrictions that affect our operations.

Regulation of Sales and Transportation of Oil

Sales of oil, condensate and NGLs are not currently regulated and are made at negotiated prices. Nevertheless, Congress could reenact price controls in the future.

Our sales of oil are affected by the availability, terms and cost of transportation. The transportation of oil in common carrier pipelines is also subject to rate and access regulation. FERC regulates interstate oil pipeline transportation rates under the Interstate Commerce Act. In general, interstate oil pipeline rates must be cost-based, although settlement rates agreed to by all shippers are permitted and market-based rates may be permitted in certain circumstances.

Intrastate oil pipeline transportation rates are subject to regulation by state regulatory commissions. The basis for intrastate oil pipeline regulation, and the degree of regulatory oversight and scrutiny given to intrastate oil pipeline rates, varies from state to state. Insofar as effective interstate and intrastate rates and regulations regarding access are equally applicable to all comparable shippers, we believe that the regulation of oil transportation will not affect our operations in any way that is of material difference from those of our competitors who are similarly situated.

Regulation of Transportation and Sales of Natural Gas

Historically, the transportation and sale for resale of natural gas in interstate commerce have been regulated by agencies of the U.S. federal government, primarily FERC. In the past, the federal government has regulated the prices at which natural gas could be sold. While sales by producers of natural gas can currently be made at uncontrolled market prices, Congress could reenact price controls in the future. Deregulation of wellhead natural gas sales began with the enactment of the NGPA, and culminated in adoption of the Natural Gas Wellhead Decontrol Act which removed controls affecting wellhead sales of natural gas effective January 1, 1993.

The transportation and sale for resale of natural gas in interstate commerce is regulated primarily under the NGA, and by regulations and orders promulgated under the NGA by FERC. In certain 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 EP Act of 2005 is a comprehensive compilation of tax incentives, authorized appropriations for grants and guaranteed loans, and significant changes to the statutory policy that affects all segments of the energy industry. Among other matters, the EP Act of 2005 amends the NGA to add an anti-market manipulation provision which makes it unlawful for any entity to engage in prohibited behavior to be prescribed by FERC, and furthermore provides FERC with additional civil penalty authority. The EP Act of 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 NGPA from $5,000 per violation per day to $1,000,000 per violation per day. The civil penalty provisions are applicable to entities that engage in the sale of natural gas for resale in interstate commerce. On January 19, 2006, FERC issued Order No. 670, a rule implementing the anti-market manipulation provision of the EP Act of 2005, and subsequently denied rehearing. The rules make it unlawful to, in connection with the purchase or sale of natural gas subject to the jurisdiction of FERC, or the purchase or sale of transportation services subject to the jurisdiction of FERC for any entity, directly or indirectly, to: (i) use or employ any device, scheme or artifice to defraud; (ii) make any untrue statement of material fact or omit to make any such statement necessary to make the statements made not misleading; or (iii) engage in any act or practice that operates as a fraud or deceit upon any person. The new anti-market manipulation rule does not apply to activities that relate only to intrastate or other non-jurisdictional sales or gathering, but does apply to activities of gas pipelines and storage companies that provide interstate services, as well as otherwise non-jurisdictional entities to the extent the activities are conducted “in connection with” gas sales, purchases or transportation subject to FERC jurisdiction, which now includes the annual reporting requirements under Order 704, described below. The anti-market manipulation rule and enhanced civil penalty authority reflect an expansion of FERC’s NGA enforcement authority.

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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 producers, gatherers and marketers, are now required to report, on May 1 of each year, ag gregate 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 determ ine 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 pol icy statement on price reporting.

Gathering service, which occurs upstream of jurisdictional transmission services, is regulated by the states onshore and in state waters. Section 1(b) of the NGA exempts natural gas gathering facilities from regulation by FERC as a natural gas company under the NGA. Although FERC has set forth a general test for determining whether facilities perform a non-jurisdictional gathering function or a jurisdictional transmission function, FERC’s determinations as to the classification of facilities are done on a case-by-case basis. To the extent that FERC issues an order that reclassifies certain jurisdictional transmission facilities as non-jurisdictional gathering facilities, and depending on the scope of that decision, our costs of getting gas to point of sale locations may increase. We believe that the natural gas pipelines in our gathering systems meet the traditional tests FERC has used to establish a pipeline’s status as a gatherer not subject to regulation as a natural gas company. However, the distinction between FERC-regulated transmission services and federally unregulated gathering services is the subject of ongoing litigation, so the classification and regulation of our gathering facilities are subject to change based on future determinations by FERC, the courts or Congress. State regulation of natural gas gathering facilities generally includes various occupational 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.

The price at which we sell natural gas is not currently subject to federal rate regulation and, for the most part, is not subject to state regulation. However, with regard to our physical sales of these energy commodities, we are required to observe anti-market manipulation laws and related regulations enforced by FERC under the EP Act of 2005 and under the Commodity Exchange Act (“CEA”), and regulations promulgated thereunder by the 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. Should we violate the anti-market manipulation laws and regulations, we could also be subject to related third-party damage claims by, among others, sellers, royalty owners and taxing authorities.

Intrastate natural gas transportation is also 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 or state policies and regulations may adversely affect the availability and reliability of firm and/or interruptible transportation service on interstate and intrastate pipelines, and we cannot predict what future action FERC or state regulatory bodies 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 natural gas producers and marketers with which we compete.

Regulation of Pipeline Safety and Maintenance

We are subject to regulation by the Pipeline and Hazardous Materials Safety Administration, (“PHMSA”), of the DOT, pursuant to the NGPSA, and the Pipeline Safety Improvement Act of 2002, or the PSIA, which was reauthorized and amended by the Pipeline Inspection, Protection, Enforcement and Safety Act of 2006. The NGPSA regulates safety requirements in the design, construction, operation and maintenance of gas pipeline facilities, while the PSIA establishes mandatory inspections for all U.S. oil and natural gas transportation pipelines and some gathering lines in high-consequence areas. PHMSA has developed regulations implementing the PSIA that require transportation pipeline operators to implement integrity management programs, including more frequent inspections and other measures to ensure pipeline safety in “high consequence areas,” such as high population areas, areas unusually sensitive to environmental damage and commercially navigable waterways.

On January 3, 2012, the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011, or the Pipeline Safety Act, was signed into law. In addition to reauthorizing the PSIA through 2015, the Pipeline Safety Act expanded the DOT’s authority under the PSIA and requires the DOT to evaluate whether integrity management programs should be expanded beyond high consequence areas, authorizes the DOT to promulgate regulations requiring the use of automatic and remote-controlled shut-off valves for new or replaced pipelines, and requires the DOT to promulgate regulations requiring the use of excess flow values where feasible. In addition, new pipeline safety legislation, the “Protecting Our Infrastructure of Pipelines and Enhancing Safety Act of 2016” (the “PIPES Act”), was signed into law in June 2016. The PIPES Act provides PHMSA with additional authority to address imminent hazards by imposing emergency restrictions, prohibitions, and safety measures on owners and operators of gas or hazardous liquids pipeline facilities. The

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Act also directs PHMSA to issue minimum safety standards for natural gas storage facilities by June 2018, and calls for a review, study, and analysis of a number of issues related to pipeline managemen t and safety.

PHMSA has also proposed additional regulations for gas pipeline safety. For example, in March 2016 PHMSA proposed a rule that would explain integrity management requirements beyond “High Consequence Areas” to apply to natural gas pipelines in newly defined “Moderate Consequence Areas.” Many gas pipelines that were in place before 1970, and thus grandfathered from certain pressure testing obligations, would be required to be pressure tested to determine their maximum allowable operating pressures. Many gathering lines in rural areas that are currently not regulated at the federal level would also be covered by this proposal. To date, no further action has been taken by PHMSA.  Any new or amended pipeline safety regulations may require us to incur additional capital expenditures and may increase our operating costs. We cannot predict what future action the DOT will take, but we do not believe that any regulatory changes will affect us in a way that materially differs from the way they will affect other natural gas gatherers with which we compete.

States are largely preempted by federal law from regulating pipeline safety for interstate lines but most are certified by the DOT to assume responsibility for enforcing federal intrastate pipeline regulations and inspection of intrastate pipelines. In practice, because states can adopt stricter standards for intrastate pipelines than those imposed by the federal government for interstate lines, states vary considerably in their authority and capacity to address pipeline safety. Changes in existing regulations or future pipeline construction activities may subject some of our pipelines to more stringent DOT regulations, and could adversely affect our business.

Regulation of Environmental and Occupational Safety and Health Matters

Our oil and natural gas development operations are subject to numerous stringent federal, state and local statutes and regulations governing occupational safety and health, the discharge of materials into the environment or otherwise relating to the protection of the environment or natural resources, some of which carry substantial administrative, civil and criminal fines and penalties for failure to comply. These laws and regulations may require the acquisition of a permit before drilling or other regulated activity commences; restrict the types, quantities and concentrations of various substances that can be released into the environment in connection with drilling, production and transporting oil and natural gas through pipelines; govern the sourcing and disposal of water used in the drilling and completion process; limit or prohibit drilling activities in certain areas and on certain lands lying within wilderness, wetlands, seismically active areas and other protected areas; require some form of remedial action to prevent or mitigate pollution from former operations such as plugging abandoned wells or closing earthen pits; establish specific safety and health criteria addressing worker protection; and impose substantial liabilities for pollution resulting from operations or failure to comply with regulatory filings. In addition, these laws and regulations may restrict the rate of production.

The following is a summary of the more significant existing environmental and occupational health and safety laws and regulations, as amended from time to time, to which our business operations are subject and for which compliance may have a material adverse impact on our capital expenditures, results of operations or financial position.

Hazardous Substances and Waste Handling

The Comprehensive Environmental Response, Compensation, and Liability Act of 1980 (“CERCLA”), also known as the “Superfund” law, and comparable state laws impose liability, without regard to fault or the legality of the original conduct, on certain classes of persons that are considered to have contributed to the release of a “hazardous substance” into the environment. These persons include the current and past owner or operator of the disposal site or the site where the release occurred and persons that disposed or arranged for the disposal of the hazardous substances at the site where the release occurred. Under CERCLA, such persons may be subject to joint and several strict 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 claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. We are able to control directly the operation of only those wells with respect to which we act as operator. Notwithstanding our lack of direct control over wells operated by others, the failure of an operator other than us to comply with applicable environmental regulations may, in certain circumstances, be attributed to us. We generate materials in the course of our operations that may be regulated as hazardous substances but we are unaware of any liabilities for which we may be held responsible that would materially and adversely affect us.

The Resource Conservation and Recovery Act (“RCRA”) and analogous state laws, impose detailed requirements for the generation, handling, storage, treatment and disposal of nonhazardous and hazardous solid wastes. RCRA specifically excludes drilling fluids, produced waters and other wastes associated with the development or production of crude oil, natural gas or geothermal energy from regulation as hazardous wastes. However, these wastes may be regulated by the EPA or state agencies under RCRA’s less stringent nonhazardous solid waste provisions, state laws or other federal laws. Moreover, it is possible that these particular oil and natural gas development and production wastes now classified as nonhazardous solid wastes could be classified as hazardous wastes in the future. For example, in December 2016, the EPA and certain environmental groups entered into a consent decree to address the EPA’s alleged failure to timely assess its RCRA Subtitle D criteria regulations exempting certain exploration and production related oil and natural gas wastes from regulation as hazardous wastes under RCRA. The consent decree requires the EPA to propose a rulemaking no later than March 15, 2019 for revision of certain Subtitle D criteria regulations pertaining to oil and natural gas wastes or to sign a determination that revision of the regulations is not necessary. Pursuant to the consent decree, the EPA must complete any revisions to RCRA's Subtitle

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D regulations b y 2021. A loss of the RCRA exclusion for drilling fluids, produced waters and related wastes could result in an increase in our costs to manage and dispose of generated wastes, which could have a material adverse effect on our results of operations and fin ancial position. In addition, in the course of our operations, we generate some amounts of ordinary industrial wastes, such as paint wastes, waste solvents, laboratory wastes and waste compressor oils that may be regulated as hazardous wastes if such waste s have hazardous characteristics. Although the costs of managing hazardous waste may be significant, we do not believe that our costs in this regard are materially more burdensome than those for similarly situated companies.

We currently own, lease or operate numerous properties that have been used for oil and natural gas development and production activities for many years. Although we believe that the operations on these properties have utilized operating and waste disposal practices that were standard in the industry at the time, hazardous substances, wastes or petroleum hydrocarbons may have been released on, under or from the properties owned or leased by us, or on, under or from other locations, including off-site locations, where such substances have been taken for recycling or disposal. In addition, some of our properties have been operated by third parties or by previous owners or operators whose treatment and disposal of hazardous substances, wastes or petroleum hydrocarbons was not under our control. These properties and the substances disposed or released on, under or from them may be subject to CERCLA, RCRA and analogous state laws. Under such laws, we could be required to undertake response or corrective measures, which could include removal of previously disposed substances and wastes, cleanup of contaminated property or performance of remedial plugging or pit closure operations to prevent future contamination.

Water Discharges

The Clean Water Act and comparable state laws impose restrictions and strict controls regarding the discharge of pollutants, including produced waters and other oil and natural gas wastes, into or near navigable waters. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or the state. The discharge of dredge and fill material in regulated waters, including wetlands, is also prohibited, unless authorized by a permit issued by the U.S. Army Corps of Engineers (the “Corps”). In September 2015, the EPA and the Corps issued new rules defining the scope of the EPA’s and the Corps’ jurisdiction under the Clean Water Act with respect to certain types of waterbodies and classifying these waterbodies as regulated wetlands. The 2015 rule was previously stayed nationwide to determine whether federal district or appellate courts had jurisdiction to hear cases in the matter. The EPA and Corps proposed a rulemaking in June 2017 to repeal the June 2015 rule and announced their intent to issue a new rule defining the Clean Water Act’s jurisdiction. Recently, in January 2018, the U.S. Supreme Court issued a decision finding that jurisdiction to hear challenges to the 2015 rule resides with the federal district courts; consequently, the previously-filed district court cases will be allowed to proceed. Following the Supreme Court’s decision, the EPA and the Corps stayed implementation of the 2015 rule for two years. As a result of these recent developments, future implementation of the June 2015 rule is uncertain at this time.  To the extent the rule expands the scope of the Clean Water Act’s jurisdiction, we could face increased costs and delays with respect to obtaining permits for dredge and fill activities in wetland areas.  Obtaining permits has the potential to delay the development of oil and natural gas projects. These laws and any implementing regulations provide for administrative, civil and criminal penalties for any unauthorized discharges of oil and other substances in reportable quantities and may impose substantial potential liability for the costs of removal, remediation and damages.

Pursuant to these laws and regulations, we may be required to obtain and maintain approvals or permits for the discharge of wastewater or storm water and are required to develop and implement spill prevention, control and countermeasure plans, also referred to as “SPCC plans,” in connection with on-site storage of significant quantities of oil.

The primary federal law related specifically to oil spill liability is the Oil Pollution Act of 1990 (“OPA”), which amends and augments the oil spill provisions of the Clean Water Act and imposes certain duties and liabilities on certain “responsible parties” related to the prevention of oil spills and damages resulting from such spills in or threatening waters of the United States or adjoining shorelines. For example, operators of certain oil and natural gas facilities must develop, implement and maintain facility response plans, conduct annual spill training for certain employees and provide varying degrees of financial assurance. Owners or operators of a facility, vessel or pipeline that is a source of an oil discharge or that poses the substantial threat of discharge is one type of “responsible party” who is liable. The OPA applies joint and several liability, without regard to fault, to each liable party for oil removal costs and a variety of public and private damages. Although defenses exist, they are limited. As such, a violation of the OPA has the potential to adversely affect our operations.

Air Emissions

The federal Clean Air Act and comparable state laws restrict the emission of air pollutants from many sources (e.g., compressor stations), through the imposition of air emissions standards, construction and operating permitting programs and other compliance requirements. These laws and regulations may require us to obtain pre-approval for the construction or modification of certain projects or facilities expected to produce or significantly increase air emissions, obtain and strictly comply with stringent air permit requirements or utilize specific equipment or technologies to control emissions of certain pollutants. For example, in October 2015, the EPA lowered the National Ambient Air Quality Standard (“NAAQS”) for ozone from 75 to 70 parts per billion.  Subsequently, in November 2017, the EPA published a list of areas that are in compliance with the new ozone standards and separately in December 2017 issued responses to state recommendation for designating non-attainment areas. States have the opportunity to submit new air

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quality monitoring to the EPA prior to the EPA finalizing any non-attainment designations.   The EPA has stated that it intends to issue final non-attainment designations during the first half of 2018.

State implementation of the revised NAAQS could result in stricter permitting requirements, delay or prohibit our ability to obtain such permits, and result in increased expenditures for pollution control equipment, the costs of which could be significant. Over the next several years, we may be required to incur certain capital expenditures for air pollution control equipment or other air emissions related issues.

In addition, the EPA has adopted new rules under the Clean Air Act that require the reduction of volatile organic compound and methane emissions from certain fractured and refractured oil and natural gas wells for which well completion operations are conducted and further require that most wells use reduced emission completions, also known as “green completions.” These regulations also establish specific new requirements regarding emissions from production-related wet seal and reciprocating compressors, and from pneumatic controllers and storage vessels. In addition, the regulations place new requirements to detect and repair volatile organic compound and methane at certain well sites and compressor stations. In May 2016, the EPA also finalized rules regarding criteria for aggregating multiple small surface sites into a single source for air-quality permitting purposes applicable to the oil and gas industry. This rule could cause small facilities, on an aggregate basis, to be deemed a major source, thereby triggering more stringent air permitting processes and requirements. Compliance with these and other air pollution control and permitting requirements has the potential to delay the development of oil and natural gas projects and increase our costs of development, which costs could be significant.

Regulation of GHG Emissions

The EPA has determined that emissions of carbon dioxide, methane and other greenhouse gasses (“GHGs”) present an endangerment to public health and the environment and has adopted regulations pursuant to the federal Clean Air Act to reduce GHG emissions from various sources. For example, the EPA requires certain large stationary sources to obtain preconstruction and operating permits for pollutants regulated under the Prevention of Significant Deterioration and Title V programs of the Clean Air Act. Facilities required to obtain preconstruction permits for such pollutants are also required to meet “best available control technology” standards that are being established by the states. These regulatory requirements could adversely affect our operations and restrict or delay our ability to obtain air permits for new or modified sources. The EPA has adopted rules requiring the monitoring and reporting of GHG emissions from specified onshore and offshore oil and natural gas production sources in the United States on an annual basis, which include certain of our operations. In June 2016, the EPA published performance standards that establish new controls for emissions of methane from new, modified or reconstructed sources in the oil and natural gas sector, including production, processing, transmission and storage activities. Compliance will require enhanced record-keeping practices, the purchase of new equipment, and increased frequency of maintenance and repair activities to address emissions leakage at certain well sites and compressor stations, and also may require hiring additional personnel to support these activities or the engagement of third-party contractors to assist with and verify compliance. However, over the past year the EPA has taken several steps to delay implementation of the June 2016 methane rule, and the agency proposed a separate rulemaking in June 2017 to stay the methane requirements for a period of two years and revisit implementation of the standards in their entirety. The EPA has not yet published a final rule but, even though the rule is currently in effect, future implementation and enforcement of the 2016 standards is uncertain at this time.

There has been no significant activity with respect to federal legislation to reduce GHG emissions in recent years. In the absence of such federal legislation, a number of state and regional efforts have emerged that are aimed at reducing GHG emissions by means of cap and trade programs, carbon taxes, or encouraging the use of renewable energy or alternative low-carbon fuels. Cap and trade programs typically require major sources of GHG emissions to acquire and surrender emission allowances in return for emitting those GHGs. In addition, efforts have been made and continue to be made in the international community toward the adoption of international treaties or protocols that would address global climate change issues. For example, in April 2016, the United States signed the Paris Agreement, which requires member countries to review and “represent a progression” in their intended nationally determined contributions, which set GHG emission reduction goals, every five years beginning in 2020. The Paris Agreement entered into force in November 2016 and includes non-binding pledges to limit or reduce future emissions. However, in June 2017, the President stated that the United States would withdraw from the Paris Agreement, but may enter into a future international agreement related to GHGs. The Paris Agreement provides for a four-year exit process beginning when it took effect in November 2016, resulting in an effective exit date of November 2020. The United States’ adherence to the exit process is uncertain and/or the terms on which the United States may reenter the Paris Agreement or a separately negotiated agreement are unclear at this time. Although it is not possible at this time to predict how legislation or new regulations that may be adopted to address GHG emissions would impact our business, any such future laws and regulations imposing reporting obligations on, or limiting emissions of GHGs from, our equipment and operations could require us to incur costs to reduce emissions of GHGs associated with our operations, as well as delay or restrict our ability to permit GHG emissions from new or modified sources. Substantial limitations on GHG emissions could adversely affect demand for the oil and natural gas we produce and lower the value of our reserves.

Recently, activists concerned about the potential effects of climate change have directed their attention at sources of funding for fossil-fuel energy companies, which has resulted in certain financial institutions, funds and other sources of capital restricting or eliminating their investment in oil and natural gas activities. Ultimately, this could make it more difficult to secure funding for exploration and production activities. Notwithstanding potential risks related to climate change, the International Energy Agency

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estimates that global energy demand will continue to rise and will not peak until after 2040 and that oil and gas will continue to represent a substantial percentage of global energy use over that time. Finally, increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, suc h as increased frequency and severity of storms, floods and other climatic events; if any such effects were to occur, they could have a material adverse effect on our operations.

Hydraulic Fracturing Activities

Hydraulic fracturing is an important and common practice that is used to stimulate production of oil and/or natural gas from dense subsurface rock formations. The hydraulic fracturing process involves the injection of water, proppants and chemicals under pressure into targeted subsurface formations to fracture the surrounding rock and stimulate production. We regularly use hydraulic fracturing as part of our operations. Hydraulic fracturing is typically regulated by state oil and natural gas commissions, but the EPA has asserted federal regulatory authority pursuant to the SDWA over certain hydraulic fracturing activities involving the use of diesel fuels and published permitting guidance in February 2014 addressing the performance of such activities using diesel fuels. The EPA has issued final regulations under the federal Clean Air Act establishing performance standards, including standards for the capture of air emissions released during hydraulic fracturing, and also finalized rules in June 2016 that prohibit the discharge of wastewater from hydraulic fracturing operations to publicly owned wastewater treatment plants.

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. For example, in May 2013, the Railroad Commission of Texas (the “Railroad Commission”) issued a “well integrity rule,” which updates the requirements for drilling, putting pipe down and cementing wells. The rule also includes new testing and reporting requirements, such as (i) the requirement to submit cementing reports after well completion or after cessation of drilling, whichever is later, and (ii) the imposition of additional testing on wells less than 1,000 feet below usable groundwater. The well integrity rule took effect in January 2014. Local governments also may seek to adopt ordinances within their jurisdictions regulating the time, place and manner of drilling activities in general or hydraulic fracturing activities in particular.

In December 2016, the EPA released its final report on the potential impacts of hydraulic fracturing on drinking water resources. The EPA report concluded that “water cycle” activities associated with hydraulic fracturing may impact drinking water resources “under some circumstances,” noting that the following hydraulic fracturing water cycle activities and local- or regional-scale factors are more likely than others to result in more frequent or more severe impacts:  water withdrawals for fracturing in times or areas of low water availability; surface spills during the management of fracturing fluids, chemicals or produced water; injection of fracturing fluids into wells with inadequate mechanical integrity; injection of fracturing fluids directly into groundwater resources; discharge of inadequately treated fracturing wastewater to surface waters; and disposal or storage of fracturing wastewater in unlined pits.

Compliance with existing laws has not had a material adverse effect on our operations or financial position, but 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 development activities, and perhaps even be precluded from drilling wells.

ESA and Migratory Birds

The Endangered Species Act (“ESA”) and (in some cases) comparable state laws were established to protect endangered and threatened species. Pursuant to the ESA, if a species is listed as threatened or endangered, restrictions may be imposed on activities adversely affecting that species’ habitat. We may conduct operations on oil and natural gas leases in areas where certain species that are or could be listed as threatened or endangered are known to exist. The U.S. Fish and Wildlife Service may designate critical habitat and suitable habitat areas that it believes are necessary for survival of a threatened or endangered species. A critical habitat or suitable habitat designation could result in further material restrictions to land use and may materially delay or prohibit land access for oil and natural gas development. Moreover, as a result of a settlement approved by the U.S. District Court for the District of Columbia in September 2011, the U.S. Fish and Wildlife Service is required to make a determination on listing of more than 250 species as endangered or threatened under the ESA by no later than completion of the agency’s 2017 fiscal year. The agency did not meet the deadline and continues to review additional species for listing under the ESA.  Similar protections are offered to migratory birds under the Migratory Bird Treaty Act. The identification or designation of previously unprotected species as threatened or endangered in areas where underlying property operations are conducted could cause us to incur increased costs arising from species protection measures or could result in limitations on our development activities that could have an adverse impact on our ability to develop and produce reserves. If we were to have a portion of our leases designated as critical or suitable habitat, it could adversely impact the value of our leases.

OSHA

We are subject to the requirements of the Occupational Safety and Health Act (“OSHA”) and comparable state statutes whose purpose is to protect the health and safety of workers. In addition, the OSHA hazard communication standard, the Emergency Planning and Community Right-to-Know Act and comparable state statutes and any implementing regulations require that we organize and/or disclose information about hazardous materials used or produced in our operations and that this information be provided to employees, state and local governmental authorities and citizens.

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Related Permits and Authorizations

Many environmental laws require us to obtain permits or other authorizations from state and/or federal agencies before initiating certain drilling, construction, production, operation or other oil and natural gas activities, and to maintain these permits and compliance with their requirements for on-going operations. These permits are generally subject to protest, appeal or litigation, which can in certain cases delay or halt projects and cease production or operation of wells, pipelines and other operations.

Related Insurance

We maintain insurance against some risks associated with above or underground contamination that may occur as a result of our development activities. However, this insurance is limited to activities at the well site and there can be no assurance that this insurance will continue to be commercially available or that this insurance will be available at premium levels that justify its purchase by us. The occurrence of a significant event that is not fully insured or indemnified against could have a materially adverse effect on our financial condition and operations. Further, we have no coverage for gradual, long-term pollution events.

Employees

As of December 31, 2017, we had 137 full-time employees. We hire independent contractors on an as needed basis. We have no collective bargaining agreements with our employees. We believe that our employee relationships are satisfactory.