10-K 1 jone-20171231x10k.htm 10-K jone_Current_Folio_10K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549


FORM 10‑K

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

 

For the fiscal year ended: December 31, 2017

 

 

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

 

For the transition period from                      to                    

 

 

Commission file number: 001‑36006


Jones Energy, Inc.

(Exact name of registrant as specified in its charter)

Delaware
(State or other jurisdiction of
incorporation or organization)

80‑0907968
(I.R.S. Employer
Identification No.)

 

 

807 Las Cimas Parkway, Suite 350

Austin, Texas 78746

(Address of principal executive offices) (Zip Code)

Tel: (512) 328‑2953

Registrant’s telephone number, including area code

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

Title of class

 

Name of each exchange on which registered

Class A Common Stock, $0.001 par value

 

New York Stock Exchange

 

 

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


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

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

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

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S‑T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes ☒  No ☐

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S‑K (§ 229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10‑K or any amendment to this Form 10‑K. ☐

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

 

 

Large accelerated filer ☐

Accelerated filer ☒

 

 

Non‑accelerated filer ☐
(Do not check if a
smaller reporting company)

Smaller reporting company ☐

 

 

Emerging growth company ☒

 

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

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

The aggregate market value of the voting and non-voting common stock held by non-affiliates of the registrant computed as of June 30, 2017 (the last business day of the Registrant’s most recently completed second fiscal quarter) based on the closing price of the Class A common stock on the New York Stock Exchange was $102.4 million.

There were 92,030,282 and 9,627,821 shares of the registrant’s Class A and Class B common stock, respectively, outstanding on February 21, 2018.


DOCUMENTS INCORPORATED BY REFERENCE

Portions of the registrant’s definitive proxy statement for the 2018 Annual Meeting of Stockholders, to be filed no later than 120 days after the end of the fiscal year, which we refer to as the Proxy Statement, are incorporated by reference into Part III of this Annual Report on Form 10‑K.

 

 


 

JONES ENERGY, INC.

 

TABLE OF CONTENTS

PART 1 

Item 1. Business 

3

Item 1A. Risk Factors 

23

Item 1B. Unresolved Staff Comments 

46

Item 2. Properties 

46

Item 3. Legal Proceedings 

46

Item 4. Mine Safety Disclosures 

46

PART II 

Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities 

47

Item 6. Selected Financial Data 

49

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations 

53

Item 7A. Quantitative and Qualitative Disclosures about Market Risk 

72

Item 8. Financial Statements and Supplementary Data 

73

Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure 

73

Item 9A. Controls and Procedures 

73

Item 9B. Other Information 

74

PART III 

Item 10. Directors, Executive Officers and Corporate Governance 

75

Item 11. Executive Compensation 

75

Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters 

75

Item 13. Certain Relationships and Related Transactions, and Director Independence 

75

Item 14. Principal Accounting Fees and Services 

75

PART IV 

Item 15. Exhibit Index 

76

Item 16. Form 10-K Summary 

80

Signatures 

81

Financial Statements 

 

Balance Sheets 

F‑3

Statements of Operations 

F‑4

Statement of Changes in Stockholders’ Equity 

F‑5

Statements of Cash Flows 

F‑6

Notes to the Consolidated Financial Statements 

F‑7

 

 

 

 

i


 

Cautionary Statement Regarding Forward‑Looking Statements

The information in this Annual Report on Form 10‑K (the “Annual Report”), includes “forward‑looking statements.” All statements, other than statements of historical fact included in this report, regarding our strategy, future operations, financial position, estimated revenues and losses, projected costs, prospects, plans and objectives of management are forward‑looking statements. When used in this Annual Report, the words “could,” “should,” “will,” “may,” “believe,” “anticipate,” “intend,” “estimate,” “expect,” “project” and similar expressions are intended to identify forward‑looking statements, although not all forward‑looking statements contain such identifying words. These forward‑looking statements are based on our current expectations and assumptions about future events and are based on currently available information as to the outcome and timing of future events. When considering forward‑looking statements, you should keep in mind the risk factors and other cautionary statements described under the heading “Risk Factors” included in this report. These forward‑looking statements are based on management’s current belief, based on currently available information, as to the outcome and timing of future events, actions and developments including:

·

business strategy;

·

estimated current and future net reserves and the present value thereof, and the likelihood of establishing production from such estimates;

·

drilling and completion of wells including our identified drilling locations;

·

cash flows, liquidity and our leverage;

·

financial strategy, capital and operating budgets, projections and operating results;

·

future prices and change in prices for oil, natural gas and NGLs;

·

customers’ elections to reject ethane and include it as part of the natural gas stream;

·

timing and amount of future production of oil and natural gas;

·

availability and cost of drilling, completion and production equipment;

·

availability and cost of oilfield labor;

·

the amount, nature and timing of capital expenditures, including future development costs;

·

ability to fund our 2018 capital expenditure budget;

·

availability and terms of capital;

·

development results from our identified drilling locations;

·

ability to generate returns and pursue opportunities;

·

marketing of oil, natural gas and NGLs;

·

property acquisitions and dispositions and realizing the expected benefits or effects of completed acquisitions and dispositions, including our ability to consummate a “DrillCo” in the Western Anadarko Basin;

·

the availability, cost and terms of, and competition for mineral leases and other permits and rights‑of‑way and our ability to maintain mineral leases;

·

costs of developing our properties and conducting other operations, including costs associated with our operations in the Merge area as compared to our operations in the Cleveland play;

·

general economic conditions, including the levels of supply and demand for oil, natural gas and NGLs, and the commodity price environment;

1


 

·

competitive conditions in our industry;

·

effectiveness and extent of our risk management activities;

·

estimates of future potential impairments;

·

environmental and endangered species regulations and liabilities;

·

counterparty credit risk;

·

the extent and effect of any hedging activities engaged in by us;

·

the impact of, and changes in, governmental regulation of the oil and natural gas industry, including tax laws and regulations, environmental, health and safety laws and regulations, and laws and regulations with respect to derivatives and hedging activities;

·

developments in oil‑producing and natural gas‑producing countries;

·

uncertainty regarding our future operating results;

·

weather, including its impact on oil and natural gas demand and weather‑related delays on operations;

·

changes and uncertainties regarding technology; and

·

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

We caution you that these forward‑looking statements are subject to all of the risks and uncertainties, most of which are difficult to predict and many of which are beyond our control, incident to the exploration for and development and production of oil and natural gas. These risks include, but are not limited to, commodity price levels and volatility, inflation, the cost of oil field equipment and services, lack of availability of drilling, completion and production equipment and services, environmental risks, drilling and other operating risks, regulatory changes, the uncertainty inherent in estimating oil and natural gas reserves and in projecting future rates of production, cash flow and access to capital, the timing of development expenditures, and the other risks described under “Risk Factors” in this report.

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

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

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

Except as otherwise required by applicable law, we disclaim any duty to update any forward‑looking statements, all of which are expressly qualified by the statements in this section, to reflect events or circumstances after the date of this report.

References

Unless indicated otherwise in this Annual Report or the context requires otherwise, all references to “Jones Energy,” the “Company,” “our company,” “we,” “our” and “us” refer to Jones Energy, Inc. and its subsidiaries, including Jones Energy Holdings, LLC (“JEH”). Jones Energy, Inc. is a holding company whose sole material asset is an equity interest in Jones Energy Holdings, LLC.

2


 

PART 1

Item 1.  Business

Organization

Jones Energy, Inc. was formed in March 2013 as a Delaware corporation to become a publicly-traded entity and the holding company of Jones Energy Holdings, LLC. As the sole managing member of JEH, the Company is responsible for all operational, management and administrative decisions relating to JEH’s business and consolidates the financial results of JEH and its subsidiaries.

The Company’s certificate of incorporation authorizes two classes of common stock, Class A common stock and Class B common stock. The Class B common stock is held by the remaining owners of JEH prior to the initial public offering (“IPO”) of the Company (collectively, the “Class B shareholders”) and can be exchanged (together with a corresponding number of common units representing membership interests in JEH (“JEH Units”)) for shares of Class A common stock on a one-for-one basis, subject to customary conversion rate adjustments for stock splits, stock dividends and reclassifications and other similar transactions. In addition, the Company’s certificate of incorporation also authorizes the Board of Directors of the Company to establish one or more series of preferred stock. On August 25, 2016, the Company issued 1,840,000 shares of its 8.0% Series A Perpetual Convertible Preferred Stock, par value $0.001 per share (the “Series A preferred stock”), pursuant to a registered public offering, of which 1,839,995 remained isused and outstanding as of December 31, 2017.

Jones Energy, Inc.’s Class A common stock has been listed on the New York Stock Exchange (“NYSE”) under the symbol “JONE” since July 2013. Neither the Class B common stock nor the Series A preferred stock is traded on a national securities exchange.

Overview

We are an independent oil and gas company engaged in the exploration, development, production and acquisition of oil and natural gas properties in the mid-continent United States, spanning areas of Oklahoma and Texas. Our Chairman and Chief Executive Officer, Jonny Jones, founded our predecessor company in 1988 in continuation of his family’s long history in the oil and gas business, which dates back to the 1920s. We have grown by leveraging our focus on low cost drilling and completion methods and our horizontal drilling expertise to develop our inventory and execute several strategic acquisitions. We have accumulated extensive knowledge and experience in developing the Anadarko Basin, having concentrated our operations there for over 25 years. We have drilled over 930 total wells as operator, including nearly 760 horizontal wells, since our formation. Our operations are focused on horizontal drilling within two distinct areas in Oklahoma and Texas:

·

the Eastern Anadarko Basin—targeting the liquids rich Woodford shale and Meramec formations in the Merge area of the STACK/SCOOP plays (the “Merge”); and

·

the Western Anadarko Basin—targeting the liquids rich Cleveland, Granite Wash, Tonkawa and Marmaton formations.

We seek to optimize returns through a disciplined emphasis on controlling costs and promoting operational efficiencies, and we have historically been recognized as one of the lowest cost drilling and completion operators in the Cleveland formation. Our low-cost drilling expertise has applied directly to our newer operations in the Merge, where the Company plans to spend the majority of its 2018 capital budget.

The Anadarko Basin is among the most prolific and largest onshore oil and natural gas basins in the United States, characterized by multiple producing horizons and extensive well control collected over 100 years of development. We leverage our extensive geologic experience in the basin and seek to identify the most profitable exploration and development opportunities to apply our operational expertise. The formations we target are generally characterized by oil and/or liquids‑rich natural gas content, extensive production histories, long‑lived reserves, high drilling success rates and attractive initial production rates. We focus on formations in our operating areas that we believe offer significant development potential and to which we can apply our technical experience and operational excellence to increase reserves, production and cash flows. Our goal is to build value through a disciplined balance between developing our current inventory of 7,180 gross (1,820 net) identified drilling locations, identifying new opportunities within our existing asset base, actively pursuing organic leasing, and acquisition opportunities.

3


 

As of December 31, 2017, our total estimated proved reserves were 104.8 MMBoe, of which 59% were classified as proved developed reserves. Approximately 28% of our total estimated proved reserves as of December 31, 2017 consisted of oil, 32% consisted of NGLs, and 41% consisted of natural gas. As of December 31, 2017, our properties included 1,044 gross producing wells. For the three years ended December 31, 2017, we drilled 168 wells as operator. The following table presents summary reserve, acreage and production data for each of our core operating areas:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Year Ended

 

 

 

As of December 31, 2017

 

December 31, 2017

 

 

 

Estimated Net

 

 

 

 

 

 

Average Daily Net

 

 

 

Proved Reserves

 

 

Acreage

 

Production

 

 

 

 

 

% Oil and

 

 

Gross

 

Net

 

 

 

% Oil and

 

 

    

MMBoe

    

NGLs

    

    

Acreage

    

Acreage

    

MBoe/d

    

NGLs

 

Western Anadarko (1)

 

76.4

 

58

%  

 

214,762

 

152,191

 

15.2

 

60

%

Eastern Anadarko (2)

 

28.3

 

64

%  

 

126,839

 

22,484

 

2.8

 

61

%

Other

 

0.1

 

24

%  

 

33,508

 

18,894

 

3.3

 

35

%

All properties

 

104.8

 

59

%  

 

375,109

 

193,569

 

21.3

 

56

%


(1)

Western Anadarko includes the Cleveland, Granite Wash, Tonkawa and Marmaton formations.

(2)

Eastern Anadarko consists of the Merge.

 

The following table presents summary well and drilling location data for each of our key formations for the date indicated:

 

 

 

 

 

 

 

 

 

 

 

 

As of December 31, 2017

 

 

 

 

 

 

 

Identified

 

 

 

Producing

 

Drilling

 

 

 

Wells

 

Locations (1)

 

 

    

Gross

    

Net

    

Gross

    

Net

 

Western Anadarko

    

944

 

571

 

1,737

 

893

 

Eastern Anadarko

    

69

 

14

 

5,443

 

927

 

Other

 

31

 

 6

 

 —

 

 —

 

All properties

 

1,044

 

591

 

7,180

 

1,820

 


(1)

Our total identified drilling locations include 3,499 gross total proved undeveloped, probable and possible drilling locations, of which 348 gross locations are associated with proved undeveloped reserves as of December 31, 2017. We have estimated our drilling locations based on well spacing assumptions for the areas in which we operate and other criteria. See “Business—Development of Proved Undeveloped Reserves” and “Business—Drilling Locations” for more information regarding our proved undeveloped reserves and the processes and criteria through which these drilling locations were identified.

 

Our 2017 capital expenditures totaled $248.0 million (excluding the impact of asset retirement costs, asset disposals and non-cash impairments of oil and gas properties), of which $205.7 million was utilized to drill and complete operated wells. The Company has established an initial capital budget of $150.0 million for 2018, including $134.0 million for drilling and completing wells and $16.0 million for leasing, workovers and other capital projects. The initial budget for 2018 in the Merge is based on estimated ranges of well costs between $5.4 million and $6.1 million per well in the Meramec formation and estimated well costs between $5.5 million and $6.0 million in the Woodford formation. Please see “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources.”

We expect to fund our 2018 budgeted capital expenditures with cash flow from operations and a portion of the net proceeds from our recent offering of 9.25% senior secured first lien notes due 2023 (the “2023 First Lien Notes”), as well as potential non-strategic asset sales or potentially accessing the debt and/or equity capital markets. In addition, we may, from time to time and subject to our assessment of market conditions, engage in liability management transactions in an effort to reduce indebtedness. Furthermore, we expect to develop all drilling locations classified as proved undeveloped reserves in the year‑end reserve report within five years of initial proved reserve booking. We consider projections of future commodity prices when determining our development plan, but many other factors are also considered. Should the commodity price environment or other material factors change significantly from current levels, we will re‑evaluate our development plan at that time. If the evaluation results in a shifting of capital expenditures into

4


 

future periods beyond five years from the initial proved reserve booking, it could potentially lead to a reduction in proved undeveloped reserves.

We have allocated our 2018 capital expenditure budget as follows:

 

 

 

 

 

 

 

(in millions of dollars)

 

2018 Capital Expenditure Budget

 

Drilling and completion

 

 

 

 

 

 

Eastern Anadarko, operated

 

$

108.0

 

 

 

Eastern Anadarko, non-operated

 

 

15.0

 

 

 

Western Anadarko

 

 

11.0

 

 

 

Total drilling and completion

 

$

134.0

 

 

Other activities (leasing, pooling, maintenance)

    

 

16.0

 

 

 

All properties and activities

 

$

150.0

 

 

 

Recent Developments

See Note 16, “Subsequent Events,” in the Notes to Consolidated Financial Statements for discussion of recent developments.

Our Operations

Our Area of Operations

We own leasehold interests in oil and natural gas producing properties, as well as in undeveloped acreage, substantially all of which are located in the Anadarko Basin in Oklahoma and Texas. The majority of our interests are in producing properties located in fields characterized by what we believe to be long‑lived, predictable production profiles and repeatable development opportunities. Specifically, our properties and wells are located in fields that generally have been developed over a long period of time, typically decades. Given the long productive history of these fields, there is substantial midstream and service infrastructure in place, including natural gas and NGL pipelines and natural gas processing plants. Observing the performance of these fields over many years allows for greater understanding of production and reservoir characteristics, making future performance more predictable. For a discussion of the risks inherent in oil and natural gas production, please read “Risk Factors—Drilling for and producing oil, natural gas and NGLs are high‑risk activities with many uncertainties that could adversely affect our business, financial condition or results of operations.”

Nearly 100% of our estimated proved reserves as of December 31, 2017 and approximately 84% of our average daily net production for the year ended December 31, 2017 were located in the Anadarko Basin. The Anadarko Basin is one of the most prolific oil and natural gas producing basins in the United States, covering approximately 50,000 square miles primarily in Oklahoma, but also including the upper Texas Panhandle, southwestern Kansas, and southeastern Colorado.

The Anadarko Basin has an especially well developed interval of productive Pennsylvanian age sedimentary rocks, up to 15,000 feet thick. Our wells in this area produce oil, natural gas and NGLs from various formations at depths from approximately 7,000 feet to 12,000 feet. We drilled 70 gross (58 net) wells as operator in the Anadarko Basin during 2017. Our operations in the Western Anadarko Basin have been primarily focused on the Cleveland formation where we have 671 producing wells. We also have acreage in the Tonkawa, Marmaton, Granite Wash, and various Pennsylvanian‑age shale formations located in western Oklahoma and the eastern portion of the Texas Panhandle. Since 2016, we have also been focused on the Woodford and Meramec formations in the Eastern Anadarko Basin.

Our production in the Anadarko Basin is currently derived primarily from the following formations, where we have 1,013 gross (585 net) producing wells and where we have identified 7,180 gross (1,820 net) drilling locations as of December 31, 2017, of which 348 have proved undeveloped reserves attributed to them as of December 31, 2017. See “Drilling Locations” for more information regarding the processes and criteria through which these drilling locations were identified.

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Western Anadarko Basin.    

·

Cleveland Formation.  Our Cleveland acreage is primarily located in Ochiltree, Lipscomb, Hutchinson, and Hemphill Counties in Texas and Ellis County in Oklahoma. The Cleveland formation ranges from depths of approximately 7,000 feet to 8,800 feet and is characterized by a tight, shaly sand with low permeability that lends itself to improved recovery through enhanced drilling and completion techniques.

As of December 31, 2017, we had 671 gross (482 net) producing wells in the formation with an average working interest of 72%, of which we operated 492 gross (416 net) producing wells. Our Cleveland properties contained 70.4 MMBoe of estimated net proved reserves as of December 31, 2017, 60% of which are oil and NGLs, and generated an average daily net production of 15.2 MBoe/d for the year ended December 31, 2017. We have identified 630 gross (422 net) drilling locations in the Cleveland formation as of December 31, 2017. Of these 630 locations, 194 locations (31%) have proved undeveloped reserves attributed to them as of December 31, 2017.

·

Tonkawa Formation.  As of December 31, 2017, we identified 279 gross (168 net) drilling locations in the Tonkawa formation primarily in Lipscomb and Hemphill Counties in Texas. In addition, the Tonkawa formation is present in the area of other properties we own located primarily in Ellis and Roger Mills Counties in Oklahoma. The Tonkawa is a horizontal oil formation at depths of approximately 6,000 feet to 8,000 feet and is characterized by fine to very fine‑grained shallow marine sandstone, ranging in thickness from 20 feet to 40 feet.

We drilled our first horizontal Tonkawa well in May 2010 and drilled two additional horizontal wells in the formation under a farm‑out with Samson Resources that is not part of our current leasehold. During 2014, we drilled six additional test wells in different areas of the Company’s leasehold acreage in the Tonkawa formation. As of December 31, 2017, our Tonkawa properties contained 0.3 MMBoe of estimated net proved reserves.

·

Marmaton Formation.  As of December 31, 2017, we identified 463 gross (278 net) drilling locations in the Marmaton formation. Our properties in the Marmaton formation are all undeveloped and span three sub‑ formations: properties located primarily in Ellis County, Oklahoma characterized by fluvio‑deltaic sands, properties located primarily in Northeast Ochiltree and Northwest Lipscomb Counties, Texas, characterized by shallow marine sands, and properties located primarily in Ochiltree County, Texas characterized by algal reef complex. The Marmaton sand is a tight, shaly sand with similar reservoir characteristics to the Cleveland. The Marmaton sand ranges in thickness from 40 feet to 80 feet while the reef ranges from 80 feet to 150 feet.

·

Granite Wash Formation.  Our Granite Wash acreage is primarily located in Roberts, Hemphill and Wheeler Counties in Texas and Roger Mills, Beckham, Custer and Washita Counties in Oklahoma. The Granite Wash spans multiple zones from depths of approximately 9,000 feet to 12,000 feet and is composed of stacked, low permeability, variable lithology alluvial fan deltaic deposits.

As of December 31, 2017, we had 75 gross (20 net) producing wells in the formation with an average working interest of 26%, of which we operated 23 gross (17 net) producing wells. Our Granite Wash properties contained 3.6 MMBoe of estimated net proved reserves as of December 31, 2017, approximately 48% of which are oil and NGLs. We have 362 gross (22 net) remaining drilling locations in the Granite Wash formation as of December 31, 2017.

Eastern Anadarko Basin.    

·

Merge Woodford Formation.  Our Merge Woodford acreage is located in Canadian, Grady and McClain Counties in Oklahoma. The Merge Woodford ranges in depths from approximately 8,500 feet to 13,000 feet and includes various fluids from black oil to gas/condensate. The Merge Woodford formation consists of siliceous, organic-rich shale, and thin bedded carbonates. The low permeability reservoir is naturally fractured with silica-rich brittle layers that are highly conducive to improved recovery from enhanced drilling and completion techniques.

6


 

Our Merge Woodford properties contained 15.0 MMBoe of estimated net proved reserves as of December 31, 2017, approximately 63% of which are oil and NGLs, and generated an average daily net production of 2.8 MBoe/d for the year ended December 31, 2017. We have identified 3,280 gross (548 net) drilling locations in the Merge Woodford formation as of December 31, 2017. Of these 3,280 locations, 85 locations (3%) have proved undeveloped reserves attributed to them as of December 31, 2017.

·

Meramec Formation.  Our Meramec acreage is located in Canadian, Grady and McClain Counties in Oklahoma. The Meramec is a horizontal liquid-rich reservoir that ranges in depths from approximately 8,000 feet to 12,500 feet. The reservoir includes various fluids from black oil to gas/condensate. The Meramec formation consist of siltstones, organic-rich shale, and limestones with gradations between rock types. Early results from laterals drilled in various landing points within the Meramec indicate the rock is highly conducive to improved recovery from enhanced drilling and completion techniques.

Our Meramec properties contained 13.3 MMBoe of estimated net proved reserves as of December 31, 2017, approximately 65% of which are oil and NGLs. We have identified 2,163 gross (379 net) drilling locations in the Meramec formation as of December 31, 2017. Of these 2,163 locations, 33 locations (2%) have proved undeveloped reserves attributed to them as of December 31, 2017.

Future Potential Opportunities.  Our current leasehold position provides longer term potential exposure to other prospective formations in the Anadarko Basin, including the Atoka, Cherokee, Douglas, Cottage Grove, and Upper and Lower Morrow formations in the Western Anadarko, and the Hunton, Osage, Chester, Caney, and Springer formations in the Eastern Anadarko. The Atoka and Cherokee formations, in particular, have attractive geologic properties, and we may elect to pursue their development in the future.

Arkoma Divestiture

On August 1, 2017, JEH sold its Arkoma Basin properties (the “Arkoma Assets”) for a sale price of $65.0 million, prior to customary effective date adjustments of $7.3 million, and subject to customary post-close adjustments (the “Arkoma Divestiture”). JEH may also receive up to $2.5 million in contingent payments based on natural gas prices. No amounts have been recorded related to this contingent payment as of December 31, 2017.

Drilling Locations

We have identified a total of 7,180 gross (1,820 net) drilling locations on our acreage, all of which are horizontal drilling locations. Of these total identified locations, 2,451 gross locations are attributable to acreage that is currently held by existing production and approximately 348 (5%) are attributable to proved undeveloped reserves as of December 31, 2017. In order to identify drilling locations, we apply geologic screening criteria based on the presence of a minimum threshold of reservoir thickness in a section and then consider the number of sections and the appropriate well density to develop the applicable field. In making these assessments, we include properties in which we hold operated and non‑operated interests, as well as redevelopment opportunities. Once we have identified acreage that is prospective for the targeted formations, well placement is determined primarily by the regulatory spacing rules prescribed by the governing body in each of our operating areas. Wells drilled in the Cleveland formation are developed ranging between 128 acre spacing (5 wells per section) and 213-acre spacing (3 wells per section). Wells drilled in the Merge Woodford formation and the Meramec formation are developed on 160‑acre spacing (4 wells per section). Wells drilled in the Granite Wash formation are developed on 128‑acre or 213‑acre spacing. Wells drilled in the Tonkawa and Marmaton formations are developed on 160‑acre spacing. We view the risk profiles for the Tonkawa and Marmaton formations as being higher than for our other drilling locations due to relatively less available production data and drilling history.

Our identified drilling locations are scheduled to be drilled over many years. The ultimate timing of the drilling of these locations will be influenced by multiple factors, including oil, natural gas and NGL prices, the availability and cost of capital, drilling, completion and production costs, the availability of drilling services and equipment, drilling results, lease expirations, gathering systems, processing, marketing and pipeline transportation constraints, regulatory approvals and other factors. In addition, a number of our identified drilling locations are associated with joint development agreements, and if we do not meet our obligation to drill the minimum number of wells specified in an agreement, we will lose the right to continue to develop certain acreage covered by that agreement. For a discussion of the risks associated with our drilling program, see “Risk Factors—Our identified drilling locations are scheduled to be drilled over many years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling, which in certain instances could prevent or delay associated expected production. In addition, we may not be

7


 

able to raise the amount of capital that would be necessary to drill a substantial portion of our identified drilling locations.”

Estimated Proved Reserves

The following table sets forth summary data with respect to our estimated net proved oil, natural gas and NGLs reserves as of December 31, 2017, 2016 and 2015, which are based upon reserve reports of Cawley, Gillespie & Associates, Inc., (“Cawley Gillespie”), our independent reserve engineers. Cawley Gillespie’s reports were prepared in accordance with the rules and regulations of the SEC regarding oil and natural gas reserve reporting in effect during such periods.

 

 

 

 

 

 

 

 

 

 

 

 

 

As of December 31, 

 

 

    

2017

    

2016

    

2015

 

Reserve Data:

 

 

 

 

 

 

 

 

 

 

Estimated proved reserves:

 

 

 

 

 

 

 

 

 

 

Oil (MBbls)

 

 

29,014

 

 

23,594

 

 

25,408

 

Natural gas (MMcf)

 

 

255,148

 

 

283,140

 

 

261,596

 

NGLs (MBbls)

 

 

33,273

 

 

34,425

 

 

32,649

 

Total estimated proved reserves (MBoe) (1)

 

 

104,812

 

 

105,209

 

 

101,657

 

Estimated proved developed reserves:

 

 

 

 

 

 

 

 

 

 

Oil (MBbls)

 

 

15,416

 

 

11,471

 

 

11,032

 

Natural gas (MMcf)

 

 

159,459

 

 

180,293

 

 

169,651

 

NGLs (MBbls)

 

 

20,181

 

 

20,941

 

 

19,670

 

Total estimated proved developed reserves (MBoe) (1)

 

 

62,173

 

 

62,461

 

 

58,977

 

Estimated proved undeveloped reserves:

 

 

 

 

 

 

 

 

 

 

Oil (MBbls)

 

 

13,598

 

 

12,123

 

 

14,376

 

Natural gas (MMcf)

 

 

95,689

 

 

102,847

 

 

91,945

 

NGLs (MBbls)

 

 

13,092

 

 

13,484

 

 

12,980

 

Total estimated proved undeveloped reserves (MBoe) (1)

 

 

42,639

 

 

42,748

 

 

42,680

 

Standardized measure (in millions) (2)

 

 

566

 

 

383

 

 

465

 

PV-10 (in millions) (3)

 

$

627

 

$

401

 

$

470

 


(1)

One Boe is equal to six Mcf of natural gas or one Bbl of oil or NGLs based on an approximate energy equivalency. This is a physical correlation and does not reflect a value or price relationship between the commodities.

(2)

Standardized measure is calculated in accordance with ASC Topic 932, Extractive Activities—Oil and Gas.

(3)

PV‑10 is a non‑GAAP financial measure and generally differs from Standardized Measure, the most directly comparable GAAP financial measure, because it does not include the effect of income taxes on discounted future net cash flows. Neither PV‑10 nor Standardized Measure represents an estimate of the fair market value of our oil and natural gas properties. The oil and gas industry uses PV‑10 as a measure to compare the relative size and value of proved reserves held by companies without regard to the specific tax characteristics of such entities. See “Reconciliation of PV‑10 to Standardized Measure” below.

8


 

The following table sets forth the benchmark prices used to determine our estimated proved reserves for the periods indicated.

 

 

 

 

 

 

 

 

 

 

 

 

 

As of December 31, 

 

 

    

2017

    

2016

    

2015

 

Oil, Natural Gas and NGLs Benchmark Prices:

 

 

 

 

 

 

 

 

 

 

Oil (per Bbl) (1)

 

$

51.34

 

$

42.75

 

$

50.25

 

Natural gas (per MMBtu) (2)

 

 

2.96

 

 

2.46

 

 

2.59

 

NGLs (per Bbl) (3)

 

 

18.92

 

 

17.73

 

 

17.63

 


(1)

Benchmark prices for oil reflect the unweighted arithmetic average first‑day‑of‑the‑month prices for the prior 12 months using WTI Cushing posted prices. These prices were utilized in the reserve reports prepared by Cawley Gillespie and in management’s internal estimates and are adjusted by well for content, quality, transportation fees, geographical differentials, marketing bonuses or deductions and other factors affecting the price received at the wellhead. As of December 31, 2017, 2016 and 2015, the average realized prices for oil were $47.45, $38.80 and $45.97 per Bbl, respectively.

(2)

Benchmark prices for natural gas in the table above reflect the unweighted arithmetic average first‑day‑of‑the‑month prices for the prior 12 months, respectively, using Henry Hub prices. These prices were utilized in the reserve reports prepared by Cawley Gillespie and in management’s internal estimates and are adjusted by well for content, quality, transportation fees, geographical differentials, marketing bonuses or deductions and other factors affecting the price received at the wellhead. As of December 31, 2017, 2016 and 2015, the average realized prices for natural gas were $2.10, $2.19 and $2.37 per MMBtu, respectively.

(3)

Prices for NGLs in the table above reflect the average realized prices for the prior 12 months assuming ethane is recovered from the natural gas stream. Benchmark prices for NGLs vary depending on the composition of the NGL basket and current prices for the various components thereof, such as butane, ethane, and propane, among others. Due to declines in ethane prices relative to natural gas prices, beginning in 2012 through the Arkoma Divestiture, purchasers of our Arkoma Woodford production were electing not to recover ethane from the natural gas stream and instead were paying us based on the natural gas price for the ethane left in the gas stream. As a result of the increased energy content associated with the returned ethane and the absence of plant shrinkage, this ethane rejection increased the incremental revenue and volumes that we received for our natural gas product relative to what we would have received if the ethane was separately recovered, but reduced physical barrels of liquid ethane that we sold.

Reserves Sensitivities

Assuming NYMEX strip pricing as of February 21, 2018 through 2022 and keeping pricing flat thereafter, instead of 2017 SEC pricing, and leaving all other parameters unchanged, the Company’s proved reserves would have been 104.9 MMBoe. This alternative pricing scenario is provided only to demonstrate the impact that the current pricing environment may have on reserves volumes. There is no assurance that these prices will actually be realized. The amount of our proved reserves as of December 31, 2017 calculated using SEC pricing is lower than the amount of our proved reserves calculated using current market prices. Using SEC pricing of December 31, 2017, our total estimated proved reserves were 104.8 MMBoe.

Reconciliation of PV‑10 to Standardized Measure

PV‑10 is derived 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 investors because it presents the discounted future net cash flows attributable to our 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 proved reserves to other companies. We use this measure when assessing the potential return on investment related to our oil and natural gas properties. PV‑10, however, is not a substitute for the Standardized Measure of discounted future net cash flows. Our PV‑10 measure and the

9


 

Standardized Measure 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 the components of the Standardized Measure of discounted future net cash flows to PV‑10 at December 31, 2017, 2016 and 2015.

 

 

 

 

 

 

 

 

 

 

 

 

 

As of December 31, 

 

(in millions of dollars)

    

2017

    

2016

    

2015

 

Standardized measure

 

$

566

 

$

383

 

$

465

 

Present value of future income taxes discounted at 10%

 

 

61

 

 

18

 

 

 5

 

PV-10

 

$

627

 

$

401

 

$

470

 

 

Internal Controls

Our proved reserves are estimated at the well or unit level and compiled for reporting purposes by our corporate reservoir engineering staff. We maintain internal evaluations of our reserves in a secure reserve engineering database. The corporate reservoir engineering staff interacts with our internal petroleum engineers and geoscience professionals in each of our operating areas and with operating, accounting and marketing employees to obtain the necessary data for the reserves estimation process. Reserves are reviewed and approved internally by our senior management team on a semi‑annual basis. We expect to have our reserve estimates evaluated by Cawley Gillespie, our independent third‑party reserve engineers, or another independent reserve engineering firm, at least annually.

Our internal professional staff works closely with Cawley Gillespie to ensure the integrity, accuracy and timeliness of data that is furnished to them for their reserve estimation process. We provide all of the reserve information maintained in our secure reserve engineering database to the external engineers, as well as other pertinent data, such as geologic maps, well logs, production tests, material balance calculations, well performance data, operating procedures and relevant economic criteria. We make all requested information, as well as our pertinent personnel, available to the external engineers as part of their evaluation of our reserves. Various procedures are used to ensure the accuracy of the data provided to our independent petroleum engineers, including review processes. Changes in reserves from the previous report are closely monitored. Reconciliation of reserves from the previous report, which includes an explanation of all significant changes, is reviewed by both the engineering department and management, including our Executive Vice President of Geosciences and Business Development. Our independent petroleum engineers prepare our annual reserves estimates, whereas interim estimates are internally prepared.

Technology Used to Establish Proved Reserves

Under SEC rules, proved reserves are those quantities of oil and natural gas that by analysis of geoscience and engineering data can be estimated with reasonable certainty to be economically producible from a given date forward from known reservoirs, and under existing economic conditions, operating methods and government regulations. The term “reasonable certainty” implies a high degree of confidence that the quantities of oil and natural gas actually recovered will equal or exceed the estimate. Reasonable certainty can be established using techniques that have been proven effective by actual production from projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology that establishes reasonable certainty. Reliable technology is a grouping of one or more technologies (including computational methods) that has been field tested and has been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.

To establish reasonable certainty with respect to our estimated proved reserves, our internal reserve engineers and Cawley Gillespie employed technologies that have been demonstrated to yield results with consistency and repeatability. The technologies and economic data used in the estimation of our proved reserves include, but are not limited to, electrical logs, radioactivity logs, core analyses, geologic maps and available downhole and production data, seismic data and well test data. Reserves attributable to producing wells with sufficient production history were estimated using appropriate decline curves or other performance relationships. Reserves attributable to producing wells with limited production history and for undeveloped locations were estimated using performance from analogous wells in the surrounding area and geologic data to assess the reservoir continuity. These wells were considered to be analogous based on production performance from the same formation and well completion using similar techniques.

10


 

Qualifications of Responsible Technical Persons

Internal technical specialist.  Jeff Tanner, our Executive Vice President of Geosciences and Business Development, is the technical specialist responsible for overseeing the preparation of our reserves estimates. He has over 30 years of diverse technical and managerial experience in the oil and gas industry. Prior to joining Jones Energy, Mr. Tanner was Vice President, Exploration for Southwestern Energy. During his career, Mr. Tanner has held a variety of management and technical positions for Laredo Petroleum, Cabot Oil and Gas, and Noble Energy. He began his career with Royal Dutch Shell plc in Houston. Mr. Tanner is a member of the American Association of Petroleum Geologists and the Houston Geological Society. He holds a B.S. in Geology from Texas A&M and an M.S. in Geology from the University of Houston.

Cawley Gillespie.  Cawley, Gillespie & Associates, Inc. is a Texas Registered Engineering Firm (F‑693), made up of independent registered professional engineers and geologists. The firm has provided petroleum consulting services to the oil and gas industry for over 50 years. No director, officer, or key employee of Cawley Gillespie has any financial ownership in us or any of our affiliates. Cawley Gillespie’s compensation for the required investigations and preparation of its report is not contingent upon the results obtained and reported, and Cawley Gillespie has not performed other work for us that would affect its objectivity. The engineering audit presented in the Cawley Gillespie report was supervised by W. Todd Brooker, President at Cawley Gillespie. Mr. Brooker is an experienced reservoir engineer having been a practicing petroleum engineer since 1989. He has more than 25 years of experience in reserves evaluation and joined Cawley Gillespie as a reserve engineer in 1992. He has a Bachelor’s of Science Degree in Petroleum Engineering from the University of Texas at Austin and is a Registered Professional Engineer in the State of Texas (License No. 83462).

Development of Proved Undeveloped Reserves

As of December 31, 2017, none of our proved undeveloped reserves at December 31, 2017 were scheduled to be developed on a date more than five years from the date the reserves were initially booked as proved undeveloped. However, certain of our proved undeveloped reserves are associated with joint development agreements with third parties that include obligations to drill a specified minimum number of wells in a time frame that is shorter than five years. If we do not meet our obligation to drill the minimum number of wells specified in a joint development agreement, we will lose the right to continue to develop the undeveloped acreage covered by the agreement, which in some cases would result in a reduction in our proved undeveloped reserves. Historically, our drilling and development programs were substantially funded from our cash flow from operations and the capital markets. Our expectation is to continue to fund our drilling and development programs primarily from our cash flow from operations and cash on our balance sheet, as well as potential non-strategic asset sales or potentially accessing the public debt and/or equity markets. Based on our current expectations of our cash resources and drilling and development programs, which include drilling of proved undeveloped locations, we believe that we will be able to fund the drilling of our current inventory of proved undeveloped locations in the next five years. For a more detailed discussion of our liquidity position, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources.”

 

 

 

 

 

    

Total

 

 

 

(MMBoe)

 

Estimated Proved Undeveloped Reserves

 

 

 

December 31, 2015

 

42.7

 

Extensions and discoveries

 

2.0

 

Conversion to proved developed

 

(5.9)

 

Purchases of minerals in place

 

9.2

 

Sales of minerals in place

 

 —

 

Revisions of previous estimates

 

(5.3)

 

December 31, 2016

 

42.7

 

Extensions and discoveries

 

13.8

 

Conversion to proved developed

 

(6.2)

 

Purchases of minerals in place

 

 —

 

Sales of minerals in place

 

(1.6)

 

Revisions of previous estimates

 

(6.1)

 

December 31, 2017

 

42.6

 

 

11


 

We have nearly maintained the volume of our proved undeveloped reserves year-over-year, from 42.7 MMBoe as of December 31, 2016 to 42.6 MMBoe as of December 31, 2017. The slight reduction was due to (i) negative revisions of 7.3 MMBoe of proved undeveloped reserves rescheduled outside of five years from their initial booking due to reduced Western Anadarko drilling and (ii) net negative revisions of 3.4 MMBoe due to lease expirations. These were offset by increases due to (iii) additions of 3.4 MMBoe from increased working interest and (iv) additions of 1.2 MMBoe from increased pricing. Proved undeveloped reserves remained constant as a percentage of total reserves at 41% for the years ended December 31, 2017 and 2016. Proved undeveloped reserves decreased as a percentage of total reserves from 42% for the year ended December 31, 2015 to 41% for the year ended December 31, 2016.

For the year ended December 31, 2017, we converted 6.2 MMBoe of proved undeveloped reserves to proved developed reserves or 15% of total proved undeveloped reserves booked at December 31, 2016. Our 2017 capital expenditures totaled $248.0 million (excluding the impact of asset retirement costs, asset disposals and non-cash impairments of oil and gas properties), of which $205.7 million was utilized to drill and complete operated wells, including wells that had no proved undeveloped reserves associated with them prior to drilling. The Company has established an initial capital budget of $150.0 million for 2018, with the majority dedicated to drilling and completion activities. Costs of proved undeveloped reserve development in 2017 do not represent the total costs of these conversions, as additional costs may have been incurred in previous years. Estimated future development costs relating to the development of 2017 year‑end proved undeveloped reserves is $400.0 million, all of which is scheduled to be incurred within five years of initial proved reserve booking. All drilling locations classified as proved undeveloped reserves in the year‑end reserve report are scheduled to be drilled within five years of initial proved reserve booking.

Operating Data

The following table sets forth summary data regarding production volumes, average prices and average production costs associated with our sale of oil and natural gas for the periods indicated.

 

 

 

 

 

 

 

 

 

 

 

 

 

Year Ended December 31, 

 

 

    

2017

    

2016

    

2015

 

Production and Operating Data:

 

 

 

 

 

 

 

 

 

 

Net Production Volumes:

 

 

 

 

 

 

 

 

 

 

Oil (MBbls)

 

 

1,964

 

 

1,685

 

 

2,583

 

Natural gas (MMcf)

 

 

20,425

 

 

18,842

 

 

23,839

 

NGLs (MBbls)

 

 

2,418

 

 

2,204

 

 

2,618

 

Total (MBoe)

 

 

7,786

 

 

7,029

 

 

9,174

 

Average net production (Boe/d)

 

 

21,332

 

 

19,205

 

 

25,134

 

Average Sales Price (1):

 

 

 

 

 

 

 

 

 

 

Oil (per Bbl)

 

$

47.46

 

$

37.83

 

$

44.15

 

Natural gas (per Mcf)

 

 

2.07

 

 

1.67

 

 

1.91

 

NGLs (per Bbl)

 

 

21.09

 

 

13.48

 

 

13.36

 

Combined (per Boe) realized

 

 

23.94

 

 

17.77

 

 

21.21

 

Average Costs per Boe:

 

 

 

 

 

 

 

 

 

 

Lease operating

 

$

4.71

 

$

4.64

 

$

4.47

 

Production and ad valorem taxes

 

 

0.88

 

 

1.11

 

 

1.32

 

Depreciation, depletion and amortization

 

 

21.48

 

 

21.90

 

 

22.40

 

General and administrative (2)

 

 

3.84

 

 

4.22

 

 

3.64

 


(1)

Prices do not include the effects of derivative cash settlements.

(2)

General and administrative includes non‑cash compensation of $6.5 million, $8.2 million and $8.0 million for the years ended December 31, 2017, 2016 and 2015, respectively. Excluding non-cash compensation from the above metric results in average cash general and administrative cost per Boe of $3.01, $3.05 and $2.77 for the years ended December 31, 2017, 2016 and 2015, respectively.

12


 

Drilling Activity

The following table sets forth information with respect to wells drilled during the periods indicated. The information should not be considered indicative of future performance, nor should a correlation be assumed between the number of productive wells drilled, quantities of reserves found or economic value.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Year Ended December 31, 

 

 

 

2017

 

2016

 

2015

 

 

    

Gross

    

Net

    

Gross

    

Net

    

Gross

    

Net

 

Development Wells:

 

 

 

 

 

 

 

 

 

 

 

 

 

Productive

 

68

 

56

 

42

 

37

 

51

 

47

 

Mechanical failure (1)

 

 —

 

 —

 

 3

 

 3

 

 1

 

 1

 

Dry

 

 1

 

 1

 

 —

 

 —

 

 —

 

 —

 

Exploratory Wells:

 

 

 

 

 

 

 

 

 

 

 

 

 

Productive

 

 1

 

 1

 

 1

 

 1

 

 —

 

 —

 

Dry

 

 —

 

 —

 

 —

 

 —

 

 —

 

 —

 

Total Wells:

 

 

 

 

 

 

 

 

 

 

 

 

 

Productive

 

69

 

57

 

43

 

38

 

51

 

47

 

Mechanical failure (1)

 

 —

 

 —

 

 3

 

 3

 

 1

 

 1

 

Dry

 

 1

 

 1

 

 —

 

 —

 

 —

 

 —

 

Total

 

70

 

58

 

46

 

41

 

52

 

48

 


(1)

Mechanical failures represent wells drilled during the year indicated which were classified as “Proved Developed Non-Producing” in the Reserve Report for that year, but are not currently in the process of completion at the end of the year.

For the three years ended December 31, 2017, we had one developmental or exploratory well that was deemed to be a dry well. As of December 31, 2017, there was one exploratory well drilled, but not yet completed. As of December 31, 2017, there were three development wells in the process of drilling and nine wells in the process of completions. For the three years ended December 31, 2017, we drilled 168 gross (147 net) wells as operator with over a 97% success rate.

During the twelve months ended December 31, 2017, we successfully drilled 69 gross proved undeveloped wells and completed 65 gross proved undeveloped wells.

Productive Wells

The following table sets forth our total gross and net productive wells by oil or natural gas classification as of December 31, 2017.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil

 

Natural Gas

 

Total

 

 

    

Gross

    

Net

    

Gross

    

Net

    

Gross

    

Net

 

Operated (1)

    

269

 

223

 

326

 

280

 

595

 

503

 

Non-operated

 

97

 

16

 

352

 

72

 

449

 

88

 

Total

 

366

 

239

 

678

 

352

 

1,044

 

591

 


(1)

Includes wells on which we act as contract operator.

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.

Acreage Data

The following table sets forth certain information regarding the developed and undeveloped acreage in which we have an interest as of December 31, 2017 for each of our producing areas. Acreage related to royalty, overriding royalty and

13


 

other similar interests is excluded from this summary. As of December 31, 2017, approximately 81% of our leasehold acreage was held by existing production.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Developed Acres

 

Undeveloped Acres

 

Total

 

 

    

Gross

    

Net

    

Gross

    

Net

    

Gross

    

Net

 

Western Anadarko

 

184,798

 

129,859

 

29,964

 

22,332

 

214,762

 

152,191

 

Eastern Anadarko

 

31,746

 

8,665

 

95,093

 

13,819

 

126,839

 

22,484

 

Other

 

33,191

 

18,887

 

317

 

 7

 

33,508

 

18,894

 

All properties

 

249,735

 

157,411

 

125,374

 

36,158

 

375,109

 

193,569

 

 

Undeveloped Acreage Expirations

The following table sets forth the number of gross and net undeveloped acres as of December 31, 2017 that will expire over the next three years by operating area unless production is established within the spacing units covering the acreage prior to the expiration dates or unless the existing leases are renewed prior to expiration.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Expiring 2018

 

Expiring 2019

 

Expiring 2020

 

Thereafter

 

 

    

Gross

    

Net

    

Gross

    

Net

    

Gross

    

Net

    

Gross

    

Net

 

Western Anadarko

 

17,253

 

12,777

 

6,285

 

5,041

 

4,456

 

3,985

 

1,970

 

528

 

Eastern Anadarko

 

35,396

 

6,715

 

45,636

 

5,363

 

14,061

 

1,742

 

 —

 

 —

 

Other

 

 —

 

 —

 

317

 

 7

 

 —

 

 —

 

 —

 

 —

 

All properties

 

52,649

 

19,492

 

52,238

 

10,411

 

18,517

 

5,727

 

1,970

 

528

 

 

A majority of the leases comprising the acreage set forth in the table above will expire at the end of their respective primary terms unless operations have commenced or production from the acreage has been established prior to such date, in which event the lease will remain in effect until the cessation of operations or production in commercial quantities. We also have options to extend some of our leases through payment of additional lease bonus payments prior to the expiration of the primary term of the leases. In addition, we may attempt to secure a new lease upon the expiration of certain of our acreage; however, there may be third‑party leases that become effective immediately if our leases expire at the end of their respective terms and production has not been established prior to such date. We do not have any of our proved undeveloped reserves as of December 31, 2017 attributed to acreage whose lease expiration date precedes the scheduled initial drilling date. Our leases are mainly fee leases with primary terms of three to five years. We believe that our lease terms are similar to our competitors’ fee lease terms as they relate to both primary term and royalty interests.

Competition

The oil and natural gas industry is highly competitive. We compete with numerous entities, including major domestic and foreign oil companies, other independent oil and natural gas concerns and individual producers and operators. Many of these competitors are large, well‑established companies and have financial and other resources substantially greater than ours. As a result, our competitors may be able to pay more for productive oil and natural gas properties and exploratory prospects, as well as evaluate, bid for and purchase a greater number of properties and prospects than our financial or personnel resources permit. Our ability to acquire additional properties and to find and develop reserves will depend on our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. Please read “Risk Factors—We may be unable to compete effectively with larger companies, which may adversely affect our ability to generate sufficient revenues.”

We are also affected by competition for drilling rigs, equipment, services, supplies and qualified personnel. Starting with the downturn in commodity prices in late 2014, the United States onshore oil and natural gas industry experienced a surplus of drilling and completion rigs, equipment, pipe and personnel, due to significantly lower commodity prices. Although this provided a temporary respite from the previous high demand environment, demand for such services and equipment have recently begun to increase as commodity prices have started to recover. If commodity prices continue to increase and exploration and production activity increases, market forces may revert to the previous situation that resulted in delayed development drilling and other exploration activities and caused significant increases in the prices for this equipment and personnel. We are unable to predict when, or if, such changes may occur or how they would affect our development and exploitation programs.

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Segment Information and Geographic Areas

The Company operates in one industry segment, which is the exploration, development and production of oil and natural gas, and all of its operations are conducted in one geographic area of the United States, as described under “—Our Operations—Our Areas of Operations.”

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 19% to 25%. Our net revenue interests average 55% for our operated leases and 23% including all operated and non‑operated leases.

Approximately 81% of our leases (based on net acreage) are held by existing production and do not require lease rental payments.

Marketing and Major Customers

Our oil is generally sold under short‑term, extendable and cancellable agreements with unaffiliated purchasers based on published price bulletins reflecting an established field posting price. As a consequence, the prices we receive for oil and liquids move up and down in direct correlation with the oil market as it reacts to supply and demand factors. We do not own any oil or liquids pipelines or other assets for the transportation of those commodities, and transportation costs related to moving oil are deducted from the price received for oil. In September of 2014, we signed a 10‑year oil gathering and transportation agreement with Monarch Oil Pipeline LLC, pursuant to which Monarch Oil Pipeline LLC built, at its expense, a new oil gathering system and connected the gathering system to our dedicated leases in Texas. The system began service during the fourth quarter of 2015 and provides connectivity to both a regional refinery market as well as the Cushing market hub. We have reserved capacity of up to 12,000 barrels per day on the system with the potential to increase throughput at a future date.

Our natural gas is sold under both long‑term and short‑term natural gas purchase agreements. Natural gas produced by us is sold at various delivery points at or near producing wells to natural gas gathering and marketing companies. We receive proceeds from prices that are based on various pipeline indices less any associated fees. On virtually all of our natural gas production, we are paid for the extracted NGLs based on a negotiated percentage of the proceeds that are generated from the customer’s sale of the liquids, or based on other negotiated pricing arrangements. We do not own any natural gas pipelines or other assets for the transportation of natural gas.

During the year ended December 31, 2017, the largest purchasers of our production were Plains Marketing LP (“Plains Marketing”) and ETC Field Services LLC, which accounted for approximately 40% and 22% of consolidated oil and gas sales, respectively. If we were to lose any one of our customers, the loss could temporarily delay production and sale of our oil and natural gas in the related producing region. If we were to lose any single customer, we believe we could identify a substitute customer to purchase the impacted production volumes. However, if one or more of our larger customers ceased purchasing oil or natural gas altogether, the loss of such customer could have a detrimental effect on our production volumes in general and on our ability to find substitute customers to purchase our production volumes. For a discussion of the risks associated with the loss of key customers, please read “Risk factors—Our customer base is concentrated, and the loss of any one of our key customers could, therefore, adversely affect our financial condition and results of operations.”

Seasonality

Generally, but not always, the demand for natural gas decreases during the summer months and increases during the winter months, resulting in seasonal fluctuations in the price we receive for our natural gas production. Seasonal anomalies such as mild winters sometimes lessen this fluctuation.

Title to Properties

Prior to completing an acquisition of producing oil and natural gas properties, we perform title reviews on significant leases, and depending on the materiality of properties, we may obtain a title opinion or review previously obtained title opinions. As a result, title examinations have been obtained on a significant portion of our properties.

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As is customary in the oil and natural gas industry, we initially conduct only a cursory review of the titles to our properties on which we do not have proved reserves. Prior to the commencement of drilling operations on those properties, we conduct a thorough title examination and perform curative work with respect to material defects. 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 conduct a portion of our operations through joint development agreements with third parties. Certain of our joint development agreements include complete‑to‑earn arrangements, whereby we are assigned title to properties from the third‑party after we complete wells. Occasionally, delivery of such assignments may be delayed. Furthermore, certain of our joint development agreements specify that assignments are only to occur when the wells are capable of producing hydrocarbons in paying quantities. These additional conditions to assignment of title may from time to time apply to wells of substantial value.

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 on Form 10‑K.

Regulations

Our operations are substantially affected by federal, state and local laws and regulations. In particular, natural gas production and related operations are, or have been, subject to price controls, taxes and numerous other laws and regulations. All of the jurisdictions in which we own or operate producing oil and natural gas properties have statutory provisions regulating the exploration for 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 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. The effect of these regulations is to limit the amount of oil and natural gas that we can produce from our wells and limit the number of wells or locations at which we can drill, although we can apply for exceptions to such regulations or to have reductions in well spacing. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of oil, natural gas and NGLs within its jurisdiction.

Failure to comply with applicable laws and regulations can result in substantial penalties. The regulatory burden on the industry increases the cost of doing business and affects profitability. Although we believe we are in substantial compliance with all applicable laws and regulations, such laws and regulations are frequently amended or reinterpreted. Therefore, we are unable to predict the future costs or impact of compliance. Additional proposals and proceedings that affect the oil and natural gas industry are regularly considered by Congress and federal agencies, the states, and the courts. We cannot predict when or whether any such proposals may become effective. Our competitors in the oil and natural gas industry are generally subject to the same regulatory requirements and restrictions that affect our operations.

Environmental Matters and Regulation

Our operations are subject to stringent and complex federal, state and local laws and regulations that govern the protection of the environment, as well as the discharge of materials into the environment. These laws and regulations may, among other things:

·

require the acquisition of various permits before drilling commences;

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·

require the installation of pollution control equipment in connection with operations;

·

restrict or prohibit our drilling and production activities during periods when such activities might affect protected wildlife;

·

place restrictions or regulations upon the types, quantities or concentrations of materials or substances used in our operations;

·

restrict the types, quantities or concentrations of various substances that can be released into the environment or used in connection with drilling, production and transportation activities;

·

limit or prohibit drilling activities on lands lying within wilderness, wetlands and other protected areas; and

·

require remedial measures to mitigate pollution from former and ongoing operations, such as site restoration, pit closure and plugging of abandoned wells.

These laws and regulations may also restrict the rate of oil and natural gas production below the rate that would otherwise be possible. The regulatory burden on the oil and natural gas industry increases the cost of doing business in the industry and consequently affects profitability. Additionally, federal, state and local lawmakers and agencies frequently revise environmental laws and regulations. Such changes could affect costs for environmental compliance, such as waste handling, permitting, or cleanup for the oil and natural gas industry and could have a significant impact on our operating costs.

The following is a summary of some of the existing laws and regulations to which our business operations are subject.

Solid and Hazardous Waste Handling and Releases

The federal Resource Conservation and Recovery Act, or RCRA, and comparable state statutes regulate the generation, transportation, treatment, storage, disposal and cleanup of hazardous and non‑hazardous waste. Drilling fluids, produced waters, and most of the other wastes associated with the exploration, development, production and transportation of oil and gas are currently excluded from regulation as hazardous wastes under RCRA. In the course of our operations, however, we generate some industrial wastes, such as paint wastes, waste solvents, and waste oils, which may be regulated as hazardous wastes. Although a substantial amount of the waste generated in our operations are regulated as non‑hazardous solid waste rather than hazardous waste, there is no guarantee that the U.S. Environmental Protection Agency, or the EPA, or individual states will not adopt more stringent requirements for the handling of non‑hazardous waste. Moreover, it is possible that certain oil and gas exploration and production wastes now classified as non‑hazardous could be classified as hazardous wastes in the future. Pursuant to a Consent Decree with environmental groups that filed suit in 2016, EPA must review the exemption of oil and gas exploration and production wastes under RCRA by March 2019 and either determine revisions to the exemption are not necessary or undertake rulemaking to be completed by July 2021. Any repeal or modification of this or similar exemptions in comparable state statutes, would increase the volume of hazardous waste we are required to manage and dispose of, and would cause us, as well as our competitors, to incur increased operating expenses. Any such change could result in an increase in our costs to manage and dispose of waste, which could have a material adverse effect on our results of operations and financial position.

The Comprehensive Environmental Response, Compensation, and Liability Act, or CERCLA, also known as “Superfund,” and comparable state laws and regulations impose liability without regard to fault or legality of the original conduct, on certain classes of persons with respect to the release into the environment of substances designated under CERCLA as hazardous substances. These classes of persons, or so‑called potentially responsible parties, or PRPs, include current and past owners or operators of a site where the release occurred and anyone who disposed or arranged for the disposal of a hazardous substance released at a site. Under CERCLA, such persons may be subject to joint and several, strict liability for the costs of cleaning up the hazardous substances released into the environment, for damages to natural resources and for the costs of certain health studies. CERCLA also authorizes the EPA and, in some instances, third parties to take actions in response to threats to public health or the environment and to seek to recover from the PRPs the costs of such action. Many states have adopted comparable or more stringent state statutes. In addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment.

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Although CERCLA generally exempts “petroleum” from the definition of hazardous substance, in the course of our operations, we have generated and will generate wastes that may fall within CERCLA’s definition of hazardous substances and may have disposed of these wastes at disposal sites owned and operated by others. We may also be the owner or operator of sites on which hazardous substances have been released. To our knowledge, neither we nor our predecessors have been designated as a PRP by the EPA under CERCLA; we also do not know of any prior owners or operators of our properties that are named as PRPs related to their ownership or operation of such properties. If contamination is discovered at a site on which we are or have been an owner or operator or to which we sent hazardous substances, we could be liable for the costs of investigation and remediation and natural resources damages.

We currently own, lease, or operate numerous properties that have been used for oil and natural gas exploration and production for many years. Although we believe we have utilized operating and waste disposal practices that were standard in the industry at the time, hazardous substances, wastes or hydrocarbons may have been released on or under the properties owned, leased or operated by us, or on or under other locations, including offsite locations, where such substances have been taken for disposal. In addition, some of these properties have been operated by third parties or by previous owners or operators whose treatment and disposal of hazardous substances, wastes, or hydrocarbons were not under our control. These properties and the substances disposed or released on them may be subject to RCRA, CERCLA, and analogous state laws. Spills or other contamination required to be remediated have not required material capital expenditures to date. In the future, we could be required to remediate property, including groundwater, containing or impacted by previously disposed wastes (including wastes disposed or released by prior owners or operators, or property contamination, including groundwater contamination by prior owners or operators) or to perform remedial plugging operations to prevent future or mitigate existing contamination.

Clean Water Act

The federal Water Pollution Control Act, or the Clean Water Act, and analogous state laws impose restrictions and strict controls with respect to the discharge of pollutants, including spills and leaks of produced water and other oil and natural gas wastes, into waters of the United States or waters of the state, both broadly defined terms. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or an analogous state agency. The Clean Water Act also prohibits the discharge of dredge and fill material in regulated waters, including wetlands, unless authorized by a permit issued by the U.S. Army Corps of Engineers. Federal and state regulatory agencies can impose administrative, civil and criminal penalties, as well as require remedial or mitigation measures, for non‑compliance with discharge permits or other requirements of the Clean Water Act and analogous state laws and regulations. In the event of an unauthorized discharge of pollutants, we may be liable for penalties and costs. The EPA and the U.S. Army Corps of Engineers adopted in June 2015 a rule redefining the term “waters of the United States,” which establishes the scope of regulated waters under the Clean Water Act. Pursuant to an Executive Order released February 28, 2017, the agencies are in the process of reviewing the 2015 rule for rescission or revision. In addition, the 2015 rule has been and remains the subject of litigation challenging the rule. A nationwide judicial stay of the 2015 rule is expected to be lifted in February 2018 due to a recent Supreme Court decision addressing whether federal circuit courts or district courts have jurisdiction over challenges to the 2015 rule. The agencies adopted a rule on February 6, 2018 delaying the applicability of this rule nationwide until February 6, 2020, to allow time for the anticipated new rulemaking. The rule delaying applicability of the 2015 rule until 2020, however, has also been challenged in federal courts. Therefore, Texas, Louisiana, and Mississippi have asked a federal district court for a nationwide preliminary injuction of the 2015 rule. The EPA also finalized regulations in 2016 under the Clean Water Act to set a zero-discharge standard for wastewater discharges from hydraulic fracturing and other natural gas production activities to publicly‑owned treatment works.

Safe Drinking Water Act

The Safe Drinking Water Act, or SDWA, regulates, among other things, underground injection operations. Congress in the past has considered legislation that would impose additional regulation under the SDWA upon the use of hydraulic fracturing fluids. If similar legislation is enacted in the future, it could impose on our hydraulic fracturing operations permit and financial assurance requirements, requirements that we adhere to construction specifications, fulfill monitoring, reporting and recordkeeping obligations, and meet plugging and abandonment requirements. In addition to subjecting the injection of hydraulic fracturing to the SDWA regulatory and permitting requirements, the previously proposed legislation would have required the disclosure of the chemicals within the hydraulic fluids. In addition, the EPA has taken the position that hydraulic fracturing with fluids containing diesel fuel is subject to the Underground Injection Control program in states in which the EPA is the permitting authority and released permitting guidance on the use of diesel fuel as an additive in hydraulic fracturing fluids. On December 13, 2016, the EPA released a study of the

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potential adverse effects that hydraulic fracturing may have on water quality and public health, concluding that there is scientific evidence that hydraulic fracturing activities can potentially impact drinking water resources in the United States under some circumstances. A committee of the U.S. House of Representatives conducted its own investigation into hydraulic fracturing practices. The U.S. Department of Energy also studied hydraulic fracturing and provided broad recommendations regarding best practices and other steps to enhance companies’ safety and environmental performance of hydraulic fracturing. Legislation or other new requirements or restrictions regarding hydraulic fracturing could substantially increase compliance costs and the requirements could negatively impact our ability to conduct fracturing activities on our assets.

Other Regulation of Hydraulic Fracturing

On May 19, 2014, the EPA published an advance notice of rulemaking under the Toxic Substances Control Act, to gather information regarding the potential regulation of chemical substances and mixtures used in oil and gas exploration and production. Also, effective June 24, 2015, the Bureau of Land Management, or BLM, adopted rules regarding well stimulation, chemical disclosures, water management, and other requirements for hydraulic fracturing on federal and Indian lands; however these rules were rescinded by rule in December 2017. BLM also adopted rules effective on January 17, 2017 to reduce venting, flaring, and leaks during oil and natural gas production activities on onshore federal and Indian leases. EPA issued a two-year stay of these requirements in December 2017 and on February 13, 2018 announced a rule proposal torescind several requirements and revise others. Effective December 5, 2016, the U.S. National Park Service, or NPS, finalized updates to its regulations governing non‑federal oil and gas rights, notably, eliminating exemptions affecting approval requirements for approximately 60% of the oil and gas operations located within the national park system and purporting to adopt under its own authority, the BLM rules on well stimulation invalidated by a district court. This regulation is targeted for agency review for potential rescission or revision purusant to the Executive Order No. 13783 titled “Promoting Energy Independence and Economic Growth” dated March 28, 2017.

Hydraulic fracturing is also subject to regulation at the state and local levels. Several states have proposed or adopted legislative or administrative rules regulating hydraulic fracturing operations. For example, in 2011 the Railroad Commission of Texas adopted the Hydraulic Fracturing Chemical Disclosure Rule. The rule requires public disclosure of chemicals in fluids used in the hydraulic fracturing process for drilling permits issued after February 1, 2012. Additionally, Texas has authorized the Texas Commission on Environmental Quality to suspend water use rights for oil and gas users in the event of serious drought conditions and has imposed more stringent emissions, monitoring, inspection, maintenance, and repair requirements on Barnett Shale operators to minimize Volatile Organic Compound, or VOC, releases. Other states that we operate in, including Oklahoma, have adopted similar chemical disclosure measures.

Some states, including Oklahoma and Texas, also assert the authority to shut down injection wells that are deemed to contribute to induced seismicity, or seismic activity that is caused by human activity. For example, on August 3, 2015, the Oklahoma Corporation Commission (“OKCC”) adopted a plan calling for mandatory reductions in oil and gas wastewater disposal well volumes to address potential induced seismicity in Oklahoma, which was implemented in 2015 and 2016 by ongoing reductions or shut ins of disposal wells. In February 2017, the OKCC issued a directive aimed at limiting the growth in future underground injection disposal rates into the Arbuckle formation in an area with seismicity issues. In December 2016, the OKCC announced seismicity guidelines for hydraulic fracturing operations, under which monitoring results can trigger a pause or suspension of hydraulic fracturing operations to evaluate seismic activity. Please see “Risk Factors—Federal and state legislative and regulatory initiatives relating to hydraulic fracturing and other oil and gas production activities as well as governmental reviews of such activities could result in increased costs, additional operating restrictions or delays, which could adversely affect our production” for a further discussion of state hydraulic fracturing regulation. In addition to state laws, local land use restrictions, such as city ordinances, may restrict or prohibit the performance of well drilling in general and/or hydraulic fracturing in particular.

Oil Pollution Act

The primary federal law related to oil spill liability is the Oil Pollution Act, or the OPA, which amends and augments 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 United States waters or adjoining shorelines. For example, operators of certain oil and gas facilities must develop, implement and maintain facility response plans, conduct annual spill training for certain employees and provide varying degrees of financial assurance. A liable “responsible party” includes the owner or operator of a facility, vessel or pipeline that is a source of an oil

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discharge or that poses the substantial threat of discharge, or in the case of offshore facilities, the lessee or permittee of the area in which a discharging facility is located. OPA assigns strict 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 to the liability imposed by OPA, they are limited. In the event of an oil discharge or substantial threat of discharge, we may be liable for costs and damages.

Air Emissions

Our operations may be subject to the Clean Air Act, or CAA, and comparable state and local requirements for the control of emissions from sources of air pollution. Federal and state laws require new and modified sources of air pollutants to obtain permits prior to commencing construction. Major sources of air pollutants are subject to more stringent, federally imposed requirements including additional permits. Federal and state laws designed to control hazardous (toxic) air pollutants, might require installation of additional controls. Administrative enforcement actions for failure to comply strictly with air pollution regulations or permits are generally resolved by payment of monetary fines and correction of any identified deficiencies. Alternatively, regulatory agencies could bring lawsuits for civil penalties or injunctions or require us to forego construction, modification or operation of certain air emission sources.

We may incur expenditures in the future for air pollution control equipment in connection with obtaining or maintaining operating permits and approvals for air emissions. For instance, effective October 15, 2012, final federal rules established new air emission controls for oil and natural gas production and natural gas processing operations, specifically addressing emissions of sulfur dioxide and volatile organic compounds, and hazardous air pollutants frequently associated with oil and natural gas production and processing activities. The rules establish specific requirements regarding emissions from compressors, dehydrators, storage tanks and other production equipment in addition to leak detection requirements for natural gas processing plants. In October 2012, several challenges to the EPA’s rules were filed by various parties, including environmental groups and industry associations. In a January 16, 2013 unopposed motion to hold this litigation in abeyance, the EPA indicated that it may reconsider some aspects of the rules. The case remains in abeyance. The EPA has since made several changes to the rules and has indicated that it may reconsider other aspects of the rules. Depending on the outcome of such judicial proceedings and regulatory actions, the rules may be further modified or rescinded or the EPA may issue new rules. These rules, as well as any modifications to these rules or additional rules, could require a number of modifications to our operations including the installation of new equipment. We have already reported some of our facilities as being subject to these rules and have incurred, and will continue to incur, costs to control emissions, and to satisfy reporting and other administrative requirements associated with these rules. Additionally, federal rules to regulate emissions of methane and volatile organic compounds from new and modified sources in the oil and gas sector and to establish the alternative criteria for aggregating multiple small surface sites into a single source for air‑quality permitting purposes became effective on August 2, 2016. This aggregation rule could cause small facilities, on an aggregate basis, to be deemed a major source, thereby triggering more stringent air permitting processes and requirements across the oil and gas industry. Further, in 2015, the EPA adopted a lower national ambient air quality standard for ozone. This lower standard may cause additional areas to be designated as ozone nonattainment areas, causing states to revise their implementation plans to require additional emissions control equipment and to impose more stringent permit requirements on facilities in those areas. EPA anticipates promulgating final area designations under the new standard in the first half of 2018.

Endangered Species and Migratory Birds

The Endangered Species Act, or ESA, restricts activities that may affect endangered or threatened species or their habitats. Pursuant to the ESA, if a species is listed as threatened or endangered, activities adversely affecting that species or its habitat may be considered “take” and may incur liability. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act. Criminal liability has been imposed in some jurisdictions for even an incidental taking of migratory birds, and the federal government recently issued indictments under the Migratory Bird Treaty Act to several oil and gas companies after dead migratory birds were found near reserve pits associated with drilling activities. However, on December 22, 2017, the U.S. Department of the Interior issued a new legal opinion that concludes that the Migratory Bird Treaty Act does not prohibit the accidental or “incidental” taking or killing of migratory birds.

We conduct operations in areas where certain species that are listed as threatened or endangered under the ESA may be present. On March 27, 2014, the U.S. Fish and Wildlife Service listed the Lesser Prairie Chicken as a threatened species under the Endangered Species Act. The designated habitat for the Lesser Prairie Chicken encompasses significant portions of our properties in the Anadarko Basin. On September 1, 2015 a federal district court in Texas vacated the listing of the Lesser Prairie Chicken as a threatened species, holding the Fish and Wildlife Service did not sufficiently

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account for voluntary range wide conservation efforts being implemented to protect the species. In July 2016, the Lesser Prairie Chicken was removed from the ESA List of Endangered and Threatened Wildlife following the court order. However, as of November 29, 2016, the Fish and Wildlife Service completed initial reviews of a petition filed by environmental groups to list the Lesser Prairie Chicken as endangered and found substantial information that the petitioned action may be warranted. An assessment of the biological status of the Lesser Prairie Chicken began in 2015 and further action remains pending.

In a special rule under ESA Section 4(d) released simultaneously with the decision to list the Lesser Prairie Chicken as threatened, the Fish and Wildlife Service exempted from “take” certain oil and gas and other activities conducted by a participant that could have resulted in an “incidental take” of the Lesser Prairie Chicken as long as the participant was enrolled in, and operating in compliance with, a range‑wide conservation plan endorsed by the Fish and Wildlife Service. The range‑wide conservation plan also included a Candidate Conservation Agreement with Assurances, or the CCAA, component that provides “take” coverage for properties enrolled into the CCAA before the listing was effective. Prior to the delisting, to mitigate the risk of liability from “incidental takes” of the Lesser Prairie Chicken, we enrolled affected leasehold interests in the CCAA. Given the delisted status of the Lesser Prairie Chicken, Jones may revisit its enrollment in the CCAA.

ESA issues remain dynamic. For example, the designation of previously unidentified endangered or threatened species could cause us to incur additional costs or limit future development activity in the affected areas. On August 23, 2016 an environmental group filed a Notice of Intent to sue the Fish and Wildlife Service for failure to act on 417 petitions to list species as threatened or endangered under the ESA. On November 21, 2016, the Fish and Wildlife Service issued its revised Mitigation Policy, providing a framework and goal to achieve a net gain in conservation outcomes, or at a minimum, no net loss of resources and their values, services, and functions resulting from proposed actions authorized under the ESA; however, this policy is being evaluated by the current administration and the outcome of that review remains unclear. We continue to evaluate the impact of these rules, agency actions, and legal challenges on our operations. The listing under the Endangered Species Act of species in areas that we operate could force us to incur additional costs and delay or otherwise limit or terminate our operations.

National Environmental Policy Act

Oil and natural gas exploration and production activities on federal lands may be subject to the National Environmental Policy Act, or NEPA, which requires federal agencies, including the Department of Interior, to evaluate major agency actions having the potential to significantly impact the environment. In the course of such evaluations, an agency will prepare an Environmental Assessment that assesses the potential direct, indirect and cumulative impacts of a proposed project and, if necessary, will prepare a more detailed Environmental Impact Statement that may be made available for public review and comment. All of our current production activities, as well as any exploration and development plans that may be proposed in the future, on federal lands require governmental permits that are subject to the requirements of NEPA. This process has the potential to delay or impose additional conditions upon the development of oil and natural gas projects.

Climate Change

More stringent laws and regulations relating to climate change and greenhouse gases, or GHGs, may be adopted in the future and could cause us to incur material expenses in complying with them. Both houses of Congress have in the past actively considered, but not passed, legislation to reduce emissions of GHGs. In the absence of comprehensive federal legislation on GHG emission control, the EPA is regulating GHGs as pollutants under the CAA. The EPA has adopted regulations affecting emissions of GHGs from motor vehicles and is also requiring permit review for GHGs from certain stationary sources that emit GHGs at levels above statutory and regulatory thresholds and are otherwise subject to CAA permitting requirements based on emissions of non‑GHG regulated air pollutants. We do not believe our operations are currently subject to these permitting requirements, but if our operations become subject to these or other similar requirements, we could incur significant costs to control our emissions and comply with regulatory requirements.

In addition, the EPA has adopted a mandatory GHG emissions reporting program that imposes reporting and monitoring requirements on various types of facilities and industries. In 2010, the EPA issued final rules to expand its existing GHG reporting rule to include onshore oil and natural gas production, processing, transmission, storage, and distribution facilities. The rule requires reporting of GHG emissions by regulated entities to the EPA on an annual basis. In 2015, the EPA added reporting of GHG emissions from gathering and boosting systems, completions and workovers of oil wells using hydraulic fracturing, and blowdowns of natural gas transmission pipelines to the GHG reporting rule. We are

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currently required to monitor and report GHG emissions under this rule, and operational and/or regulatory changes could increase the burden of compliance with GHG emissions monitoring and reporting requirements.

Because of the lack of any comprehensive legislative program addressing GHGs, there is continuing uncertainty regarding the further development of federal regulation of GHG‑emitting sources. Additionally, a number of states, either individually or as part of regional initiatives, have begun taking actions to control and/or reduce GHG emissions primarily through the planned development of GHG emission inventories and/or regional GHG cap and trade programs. Most of these cap and trade programs work by requiring major sources of emissions to acquire and surrender emission allowances. The international, federal, regional and local regulatory initiatives that target GHGs also could adversely affect the marketability of the oil and natural gas we produce. For example, in 2015, the United States participated in the United Nations Conference on Climate Change, which led to the creation of the Paris Agreement. The Paris Agreement entered into force November 4, 2016, and requires 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 United States has expressed an intention to withdraw from participation in the Paris Agreement, but some state and local governments have expressed intentions to take GHG-related actions. Due to the uncertainties surrounding the regulation of and other risks associated with GHG emissions, we cannot predict the financial impact of related developments on our operations, however, we do not expect our operations to be affected any differently than other similarly situated domestic competitors.

In addition to legislative and regulatory developments, plaintiffs have brought judicial actions under common law theories against greenhouse gas emitting companies in recent years. For example, environmental advocacy groups filed five nearly identical lawsuits in 2017 seeking to hold a wide variety of companies that produce fossil fuels liable for the alleged impacts of the greenhouse gas emissions attributable to those fuels. The lawsuits primarily assert that the companies’ products have caused a sea level rise that is damaging the plaintiffs. Jones is not a defendant in these cases and we are unable to predict the outcome or potential impact of these cases on the oil and gas industry.

The federal administration also issued a Climate Action Plan in June 2013. Among other things, the Climate Action Plan directs federal agencies to develop a strategy for the reduction of methane emissions, including emissions from the oil and natural gas industry. As previously mentioned, the EPA finalized a rule effective August 2016, setting standards for methane and volatile organic compound emissions from new and modified sources in the oil and gas sector. On November 10, 2016, the EPA issued a final Information Collection Request, or the ICR, that would have required numerous oil and gas companies to provide information regarding methane emissions from existing oil and gas facilities, but on March 2, 2017, EPA withdrew that ICR. The regulatory focus is shifting in the current administration, however, additional GHG regulation of the oil and gas industry remains a possibility. 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.

OSHA and Other Laws and Regulation

We are subject to the requirements of the federal Occupational Safety and Health Act, or OSHA, and comparable state statutes. These laws and regulations strictly govern the protection of the health and safety of employees. The OSHA hazard communication standard, the EPA community right‑to‑know regulations under Title III of CERCLA and similar state statutes 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 government authorities and citizens. We believe that we are in substantial compliance with these applicable requirements and with other OSHA and comparable requirements.

We believe that we are in substantial compliance with all existing environmental laws and regulations applicable to our current operations and that our continued compliance with existing requirements will not have a material adverse impact on our financial condition and results of operations. We did not incur any material capital expenditures for remediation or pollution control activities for the years ended December 31, 2017, 2016 or 2015. Additionally, we are not aware of any environmental issues or claims that will require material capital expenditures during 2018 or that will otherwise have a material impact on our financial position or results of operations in the future. However, we cannot assure you that the passage of more stringent laws and regulations in the future will not have a negative impact on our business activities, financial condition or results of operations.

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Offices

We currently lease approximately 43,000 square feet of office space in Austin, Texas at 807 Las Cimas Parkway, Austin, Texas 78746, where our principal offices are located. The primary lease expires in April 2020. We also lease approximately 9,000 square feet of office space in Oklahoma City, Oklahoma. Additionally, we lease field offices in Oklahoma City, Oklahoma and Canadian, Texas.

Employees

As of December 31, 2017, we had 94 employees, including 31 technical (geosciences, engineering, land), 33 field operations, 26 corporate (finance, accounting, business development, IT, human resources, office management) and 4 management. None of these employees are represented by labor unions or covered by any collective bargaining agreement. We consider our relations with our employees to be satisfactory. From time to time, we utilize the services of independent contractors to perform various field and other services as needed.

Available information

We are required to file annual, quarterly and current reports, proxy statements and other information with the SEC. Our reports filed with the SEC are made available to read and copy at the SEC’s Public Reference Room at 100 F Street, N.E., Washington, D.C., 20549. You may obtain information about the Public Reference Room by contacting the SEC at 1‑800‑SEC‑0330. Reports filed with the SEC are also made available on its website at www.sec.gov.

Our common stock is listed and traded on the New York Stock Exchange under the symbol “JONE.” Our reports, proxy statements and other information filed with the SEC can also be inspected and copied at the New York Stock Exchange, 20 Broad Street, New York, New York 10005.

Through our website, www.jonesenergy.com, you can access, free of charge, electronic copies of all of the documents that we file with the SEC, including our annual reports on Form 10‑K, quarterly reports on Form 10‑Q and current reports on Form 8‑K, as well as any amendments to these reports.

 

Item 1A.  Risk Factors

Our business involves a high degree of risk. If any of the following risks, or any risks described elsewhere in this Annual Report on Form 10‑K, were actually to occur, our business, financial condition or results of operations could be materially adversely affected and the trading price of our shares could decline resulting in the loss of part or all of your investment. The risks described below are not the only ones facing us. Additional risks not presently known to us or which we currently consider immaterial may also adversely affect us.

Risks Relating to the Oil and Natural Gas Industry and Our Business:

A substantial or extended decline in oil, natural gas or NGL prices would adversely affect our business, financial condition or results of operations and our ability to meet our capital expenditure obligations and financial commitments.

The price we receive for our oil, natural gas and NGLs heavily influences our revenue, profitability, access to capital and future rate of growth. Oil and natural gas are commodities and, therefore, their prices are subject to wide fluctuations in response to relatively minor changes in supply and demand. During the past seven years, the NYMEX WTI oil price has ranged from a low of $26.19 per Bbl in February 2016 to a high of $113.39 per Bbl in April 2011, and was $61.68 as of February 21, 2018. The NYMEX Henry Hub spot market price of gas has ranged from a high of $8.15 per MMBtu in February 2014 to a low of $1.49 in March 2016, and was $2.66 as of February 21, 2018. These markets will likely continue to be volatile in the future, especially given the current geopolitical conditions. The prices we receive for our production and the levels of our production depend on numerous factors beyond our control. These factors include the following:

·

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

·

the actions of the Organization of Petroleum Exporting Countries, or OPEC, including whether it meets the reduced output targets it has previously announced or may announce in the future;

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·

the level of production in non-OPEC countries;

·

the price and quantity of imports of foreign oil, natural gas and NGLs;

·

political conditions regionally, domestically or in other oil and gas‑producing regions;

·

the level of domestic and global oil and natural gas exploration and production;

·

the level of domestic and global oil and natural gas inventories;

·

localized supply and demand fundamentals and available pipeline and other oil and gas transportation capacity;

·

weather conditions and natural disasters;

·

domestic, local and foreign governmental regulations and taxes;

·

activities by non-governmental organizations to restrict the exploration, development and production of oil and gas so as to reduce the potential for harm to the environment from such activities, including emissions of carbon dioxide, a greenhouse gas;

·

speculation as to the future price of oil, natural gas and NGLs and the speculative trading of oil, natural gas and NGLs;

·

trading prices of futures contracts;

·

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

·

technological advances affecting energy consumption;

·

the price and availability of alternative fuels; and

·

the impact of energy conservation efforts.

NGLs are made up of ethane, propane, isobutane, butane and natural gasoline, all of which have different uses and different pricing characteristics. NGLs comprised 31% of our 2017 production, and we realized an average price of $21.09 per barrel, a 56.5% increase from the average realized price of our 2016 production. An extended decline in NGL prices could materially and adversely affect our future business, financial condition and results of operations.

Substantially all of our production is sold to purchasers under contracts with market‑based prices. Lower oil, natural gas and NGL prices will reduce our cash flows and the present value of our reserves. Additionally, prices could reduce our cash flows to a level that would require us to borrow to fund our planned capital budget. Lower oil, natural gas and NGL prices may also reduce the amount of oil, natural gas and NGLs that we can develop and produce economically. Substantial decreases in oil, natural gas and NGL prices could render uneconomic a significant portion of our identified drilling locations. This may result in significant downward adjustments to our estimated proved reserves. As a result, a substantial or extended decline in oil, natural gas or NGL prices may materially and adversely affect our future business, financial condition, results of operations, liquidity or ability to finance planned capital expenditures.

Drilling for and producing oil, natural gas and NGLs are high risk activities with many uncertainties that could adversely affect our business, financial condition or results of operations.

Our future financial condition and results of operations will depend on the success of our exploration, exploitation, development and production activities. Our oil, natural gas and NGLs exploitation, development and production activities are subject to numerous risks beyond our control, including the risk that drilling will not result in commercially viable oil and natural gas production. Our decisions to purchase, explore, develop or otherwise exploit locations or properties will depend in part on the evaluation of information obtained through geophysical and geological analyses, production data and engineering studies, the results of which are often inconclusive or subject to varying interpretations. We cannot assure you that the analogies we draw from available data from other wells, more fully explored prospectus or producing fields will be applicable to our drilling prospects. In addition, our cost of drilling, completing and operating

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wells is often uncertain before drilling commences, which ultimately results in uncertainty as to when the capital investment required to deploy rigs will create an acceptable return for our shareholders. Further, many factors may curtail, delay or cancel our scheduled drilling projects, including the following:

·

delays imposed by or resulting from compliance with regulatory and contractual requirements and related lawsuits, which may include limitations on hydraulic fracturing or the discharge of greenhouse gases;

·

pressure or irregularities in geological formations;

·

shortages of or delays in obtaining equipment and qualified personnel;

·

equipment failures or accidents;

·

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

·

lack of available capacity on interconnecting transmission pipelines;

·

fires and blowouts;

·

adverse weather conditions, such as hurricanes, blizzards and ice storms;

·

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

·

declines in oil, natural gas and NGL prices;

·

limited availability of financing at acceptable rates;

·

title problems; and

·

limitations in the market for oil, natural gas and NGLs.

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

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

·

effectively controlling the level of pressure flowing from particular wells;

·

landing our wellbore in the desired drilling zone;

·

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

·

running our casing the entire length of the wellbore; and

·

running tools and other equipment consistently through the horizontal wellbore.

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

·

the ability to effectively fracture stimulate the planned number of stages;

·

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

·

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

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The results of our drilling in new or emerging formations are more uncertain initially than drilling results in areas that are more developed and have a longer history of established production. Newer or emerging formations and areas have limited or no production history and, consequently, we are more limited in assessing future drilling results in these areas.

The value of our undeveloped acreage could decline if drilling results are unsuccessful.

The success of our horizontal drilling and completion techniques can only be evaluated over time as more wells are drilled and production profiles are established over a sufficiently long time period. If our drilling results are less than anticipated or we are unable to execute our drilling program because of capital constraints, lease expirations, access to gathering systems, declines in oil, natural gas and NGL prices and/or other factors, the return on our investment in these areas may not be as attractive as we anticipate. Further, as a result of any of these developments we could incur material write‑downs of our oil and gas properties and the value of our undeveloped acreage could decline in the future.

Our business requires substantial capital expenditures, and we may be unable to obtain needed capital or financing on satisfactory terms or at all.

Our exploration, exploitation, development and acquisition activities require substantial capital expenditures. Our 2017 capital expenditures totaled $248.0 million (excluding the impact of asset retirement costs, asset disposals and non-cash impairments of oil and gas properties), of which $205.7 million was utilized to drill and complete operated wells. The Company has established an initial capital budget of $150.0 million for 2018. Historically, we have funded development and operating activities primarily through a combination of equity capital raised from a private equity partner and public equity offerings, through borrowings under the Revolver, through the issuance of debt securities and through internal operating cash flows. We intend to finance the majority of our capital expenditures predominantly with cash flows from operations. If necessary, we may also access capital through proceeds from potential asset dispositions, cash on hand, borrowings under the Revolver, and the issuance of additional debt and equity securities. Our cash flow from operations and access to capital are subject to a number of variables, including:

·

the estimated quantities of our oil, natural gas and NGL reserves;

·

the amount of oil, natural gas and NGLs we produce from existing wells;

·

the prices at which we sell our production;

·

any gains or losses from our hedging activities;

·

the costs of developing and producing our oil, natural gas and NGL reserves;

·

take‑away capacity;

·

our ability to acquire, locate and produce new reserves;

·

the ability and willingness of banks and other lenders to lend to us; and

·

our ability to access the equity and debt capital markets.

If our cash flow from operations is not sufficient to fund our capital expenditure budget, we may have limited ability to obtain the additional capital necessary to conduct our operations at expected levels. The Revolver and the indentures governing our senior notes due 2022, or the 2022 Notes, and senior notes due 2023, or the 2023 Notes, and the 2023 First Lien Notes restrict our ability to obtain new debt financing. We may not be able to obtain debt or equity financing on terms favorable to us, or at all. The failure to obtain additional financing could result in a curtailment of our operations relating to exploration and development of our prospects, which in turn could lead to a decline in our oil, natural gas and NGLs production or reserves, and in some areas a loss of properties.

External financing may be required in the future to fund our growth. We may not be able to obtain additional financing, and financing under the Revolver and through the capital markets may not be available in the future. Without additional capital resources, we may be unable to pursue and consummate acquisition opportunities as they become available, and we may be forced to limit or defer our planned oil, natural gas and NGLs development program, which will adversely affect the recoverability and ultimate value of our oil, natural gas and NGLs properties, in turn negatively affecting our business, financial condition and results of operations.

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The development of our proved undeveloped reserves in our areas of operation may take longer and may require higher levels of capital expenditures than we currently anticipate. Therefore, our undeveloped reserves may not be ultimately developed or produced by us. In addition, there are no assurances that our proved undeveloped reserves will be converted into producing reserves by us.

Approximately 41% of our total estimated proved reserves were classified as proved undeveloped as of December 31, 2017. Development of these reserves may take longer and require higher levels of capital expenditures than we currently anticipate. In addition, declines in commodity prices could cause us to reevaluate our development plans and delay or cancel development. Delays in the development of our reserves, increases in costs to drill and develop such reserves or sustained periods of low commodity prices will reduce the future net revenues estimated for such reserves and may result in some projects becoming uneconomic. In addition, delays in the development of reserves or lower commodity prices could cause us to have to reclassify our proved reserves as unproved reserves. There is no certainty that we will be able to convert unproved reserves to developed reserves.

Our identified drilling locations are scheduled to be drilled over many years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling, which in certain instances could prevent or delay associated expected production. In addition, we may not be able to raise the amount of capital that would be necessary to drill a substantial portion of our identified drilling locations.

Our management team has identified and scheduled certain drilling locations as an estimation of our future multi‑year drilling activities on our existing acreage. These drilling locations represent a significant part of our growth strategy. Our drilling locations are in various stages of evaluation, ranging from a location that is ready to drill to a location that will require substantial additional interpretation. There is no way to predict in advance of drilling and testing whether any particular location will yield oil, natural gas or NGLs in sufficient quantities to recover drilling or completion costs or to be economically viable. Similarly, the use of technologies and the study of producing fields in the same area of producing wells will not enable us to know conclusively prior to drilling whether oil or natural gas will be present or, if present, whether oil or natural gas will be present in sufficient quantities to be economically viable. Even if sufficient quantities of oil or natural gas exist, we may damage the potentially productive hydrocarbon bearing formation or experience mechanical difficulties while drilling or completing the well, resulting in a reduction in production or abandonment of the well. If we drill additional wells that we identify as dry holes in our current and future drilling locations, our drilling success rate may decline and materially harm our business. In addition, our ability to drill and develop these drilling locations depends on a number of uncertainties, including oil, natural gas and NGL prices, the availability and cost of capital, drilling and production costs, the availability of drilling services and equipment, drilling results, lease expirations, gathering systems, marketing and pipeline transportation constraints, regulatory approvals and other factors. Because of the uncertainty inherent in these factors, we do not know if the numerous drilling locations we have identified will ever be drilled or if we will be able to produce oil, natural gas or NGLs from these or any other drilling locations.

Our use of 2D and 3D seismic data is subject to interpretation and may not accurately identify the presence of drilling hazards, including faults, or hydrocarbons, which could adversely affect the results of our drilling operations.

Even when properly used and interpreted, 2D and 3D seismic data and visualization techniques are only tools used to assist geoscientists in identifying subsurface structures and hydrocarbon indicators and do not enable the interpreter to know whether hydrocarbons or drilling hazards such as faults are, in fact, present in those structures. In addition, the use of 3D seismic and other advanced technologies requires greater predrilling expenditures than traditional drilling strategies, and we could incur greater drilling and testing expenses as a result of such expenditures, which may result in a reduction in our returns or losses. As a result, our drilling activities may not be successful or economical, and our overall drilling success rate or our drilling success rate for activities in a particular area could decline.

We often gather 3D seismic data over large areas. Our interpretation of seismic data delineates those portions of an area that we believe are desirable for drilling. Therefore, we may choose not to acquire option or lease rights prior to acquiring seismic data, and, in many cases, we may identify hydrocarbon indicators before seeking option or lease rights in the location. Conversely, we may incur substantial expenditures to acquire and analyze 3D seismic data but not be able to lease attractive locations on acceptable terms.

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Our hedging strategy may be ineffective in reducing the impact of commodity price volatility from our cash flows or may limit our ability to realize cash flows from commodity price increases, which could result in financial losses or could reduce our income.

To achieve more predictable cash flow and to reduce our exposure to adverse fluctuations in the prices of oil, natural gas and NGLs, we have historically entered into commodity derivative contracts for a significant portion of our oil, natural gas and NGL production that could result in both realized and unrealized hedging losses. The extent of our commodity price exposure is related largely to the effectiveness and scope of our commodity derivative contracts. For example, some of the commodity derivative contracts we utilize are based on quoted market prices, which may differ significantly from the actual prices we realize in our operations for oil, natural gas and NGLs. For the years ending December 31, 2018, 2019, and 2020, approximately 25%, 74%, and 78%, respectively, of our estimated total oil, natural gas and NGL production from proved reserves, based on our reserve report as of December 31, 2017, will not be covered by commodity derivative contracts.

Our policy has been to hedge a significant portion of our estimated oil, natural gas and NGLs production. However, our price hedging strategy and future hedging transactions will be determined at our discretion. We are not under an obligation to hedge a specific portion of our production. The prices at which we hedge our production in the future will be dependent upon commodity prices at the time we enter into these transactions, which may be substantially higher or lower than current oil, natural gas and NGLs prices. Accordingly, our price hedging strategy may not protect us from significant declines in oil, natural gas and NGL prices received for our future production. Conversely, our hedging strategy may limit our ability to realize cash flows from commodity price increases. For example, the estimated mark-to-market value of our commodity price hedges in 2018 and beyond represents a loss of $37.5 million, incorporating strip pricing as of February 21, 2018 but excluding adjustments for credit risk.

In addition, our actual future production may be significantly higher or lower than we estimate at the time we enter into commodity derivative contracts for such period. If the actual amount is higher than we estimate, we will have greater commodity price exposure than we projected. If the actual amount is lower than the notional amount of our commodity derivative contracts, we might be forced to satisfy all or a portion of our commodity derivative contracts without the benefit of the cash flow from our sale or purchase of the underlying physical commodity, substantially diminishing our liquidity. There may be a change in the expected differential between the underlying commodity price in the commodity derivative contract and the actual price received, which may result in payments to our derivative counterparty that are not offset by our receipt of payments for our production in the field.

As a result of these factors, our commodity derivative activities may not be as effective as we intend in reducing the volatility of our cash flows, and in certain circumstances may actually increase the volatility of our cash flows.

Our hedging transactions expose us to counterparty credit risk.

Our hedging transactions expose us to risk of financial loss if a counterparty fails to perform under a derivative contract. Disruptions in the financial markets could lead to sudden changes in a counterparty’s liquidity, which could impair their ability to perform under the terms of the derivative contract. We are unable to predict sudden changes in a counterparty’s creditworthiness or ability to perform. Even if we do accurately predict sudden changes, our ability to negate the risk may be limited depending upon market conditions. Currently our entire hedge portfolio is hedged directly with banks in our credit agreements, thus allowing hedging without any margin requirements.

During periods of falling commodity prices, our hedge receivable positions generally increase, which increases our counterparty credit exposure. If the creditworthiness of our counterparties deteriorates and results in their nonperformance, we could incur a significant loss.

Derivatives legislation and implementing rules could have an adverse effect on our ability to use derivatives to reduce the effect of commodity price risk, interest rate risk and other risks associated with our business.

We use commodity derivatives to manage our commodity price risk. The U.S. Congress adopted comprehensive financial reform legislation that, among other things, expands comprehensive federal oversight and regulation of derivatives and many of the entities that participate in that market. Although the Dodd‑Frank Wall Street Reform and Consumer Protection Act, or the Dodd‑Frank Act, was enacted on July 21, 2010, the Commodity Futures Trading Commission, or the CFTC, and the SEC, along with certain other regulators, must promulgate final rules and regulations to implement many of its provisions relating to derivatives. While some of these rules have been finalized, some have

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not. When fully implemented, the law and any new regulations could increase the operational and transactional cost of derivatives contracts and affect the number and/or creditworthiness of available counterparties.

In addition, we may transact with counterparties based in the European Union, Canada or other jurisdictions which, like the U.S., are in the process of implementing regulations to regulate derivatives transactions, some of which are currently in effect and impose operational and transactional costs on our derivatives activities.

Unless we replace our reserves, our reserves and production will naturally decline, which would adversely affect our business, financial condition and results of operations.

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

If we do not fulfill our obligation to drill minimum numbers of wells specified in our joint development agreements, we will lose the right to develop the undeveloped acreage associated with the agreement and any proved undeveloped reserves attributable to such undeveloped acreage.

If we do not meet our obligation to drill the minimum number of wells specified in a joint development agreement, we will lose the right to continue to develop the undeveloped acreage covered by the agreement, which would result in the loss of any proved undeveloped reserves attributable to such undeveloped acreage.

Future commodity price declines or downward reserve revisions may result in write‑downs of the carrying values of our properties.

Accounting rules require that we periodically review the carrying value of our properties for possible impairment. Based on prevailing commodity prices and specific market factors and circumstances at the time of prospective impairment reviews, and the continuing evaluation of development plans, production data, economics and other factors, we may be required to write down the carrying value of our properties. A write‑down constitutes a non‑cash charge to earnings. Such impairment may be accompanied by a reduction in proved reserves, thereby increasing future depletion charges per unit of production. We may incur impairment charges and related reductions in proved reserves in the future, which could have a material adverse effect on our results of operations for the periods in which such charges are taken. If commodity prices decline relative to their historical levels, we may incur future impairments to long‑lived assets.

Our estimated oil, natural gas and NGLs reserve quantities and future production rates are based on many assumptions that may prove to be inaccurate. Any significant inaccuracies in these reserve estimates or the underlying assumptions will materially affect the quantities and present value of our reserves.

Numerous uncertainties are inherent in estimating quantities of oil, natural gas and NGL reserves. Our estimates of our proved reserve quantities are based upon our reserve report as of December 31, 2017. Reserve estimation is a subjective process of evaluating underground accumulations of oil, natural gas and NGLs that cannot be measured in an exact manner. Reserves that are “proved reserves” are those estimated quantities of oil, natural gas and NGLs that geological and engineering data demonstrate with reasonable certainty are recoverable in future years from known reservoirs under existing economic and operating conditions and that relate to projects for which the extraction of hydrocarbons must have commenced or the operator must be reasonably certain will commence within a reasonable time.

The process of estimating oil, natural gas and NGL reserves is complex, requiring significant decisions and assumptions in the evaluation of available geological, engineering and economic data for each reservoir, and these reports rely upon various assumptions, including assumptions regarding future oil, natural gas and NGL prices, production levels, and operating and development costs. As a result, estimated quantities of proved reserves and projections of future production rates and the timing of development expenditures may prove to be inaccurate. Quantities of proved reserves are estimated based on pricing conditions in existence during the period of assessment and costs at the end of the period of assessment. Changes to oil, natural gas and NGL prices in the markets for such commodities may have the impact of

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shortening the economic lives of certain fields, because it becomes uneconomic to produce all recoverable reserves on such fields, which reduces proved property reserve estimates.

Over time, we may make material changes to reserve estimates taking into account the results of actual drilling and production. Any significant variance in our assumptions and actual results could greatly affect our estimates of reserves, the economically recoverable quantities of oil, natural gas and NGLs attributable to any particular group of properties, the classifications of reserves based on risk of recovery, and estimates of the future net cash flows. In addition, changes in future production cost assumptions could have a significant effect on our proved reserve quantities.

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

You should not assume that the standardized measure of discounted future net cash flows from our proved reserves is the current market value of our estimated oil, natural gas and NGL reserves. In accordance with SEC requirements, we based the discounted future net cash flows from our proved reserves on the 12‑ month unweighted arithmetic average of the first‑day‑of‑the‑ month commodities prices for the preceding 12 months without giving effect to derivative transactions. Actual future net cash flows from our oil and natural gas properties will be affected by factors such as:

·

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

·

actual cost of development and production expenditures;

·

the amount and timing of actual development and production; and

·

changes in governmental regulations or taxation.

The timing of both our production and our incurrence of expenses in connection with the development and production of oil and natural gas properties will affect the timing and amount of actual future net revenues from proved reserves, and thus their actual present value. In addition, the 10% discount factor we use when calculating standardized measure may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with our company or the oil and natural gas industry in general.

If oil prices decline by $10.00 per Bbl, then our standardized measure as of December 31, 2017 excluding hedging impacts would decrease approximately $163.5 million holding all costs constant. If natural gas prices decline by $1.00 per Mcf, then our standardized measure as of December 31, 2017 excluding hedging impacts would decrease by approximately $98.1 million holding all costs constant.

Over 72% of our estimated proved reserves are located in the Western Anadarko Basin in the Texas Panhandle and Oklahoma; however, our 2018 drilling plan is primarily focused on the development of our assets in the Merge play located in the Eastern Anadarko Basin in Oklahoma. Drilling, exploring for and producing, oil, natural gas and NGLs in a different play than the location of our historical operations subjects us to uncertainties that could adversely affect our business, financial condition or results of operations.

Over 72% of our estimated proved reserves as of December 31, 2017 were located in the Western Anadarko Basin in the Texas Panhandle and Oklahoma, and approximately 71% of our 2017 production was from the Cleveland formation where properties are located in four contiguous counties of Texas and Oklahoma. During the fourth quarter of 2017, however, we released our last remaining rig in the Cleveland formation. In 2018, we plan to target the liquids rich Woodford shale and Meramec formations with our rig program in the Merge. As a result of this change in the area of our significant operations, we may be exposed to the impact of different supply and demand factors, regulations, processing or transportation capacity constraints, availability of equipment, facilities, personnel or services market limitations than we have been exposed to previously in our historical operations in the Western Anadarko Basin. These uncertainties and others inherent in allocating our capital resources to operations in a new geographic area could have a material adverse effect on our financial condition and results of operations.

Our customer base is concentrated, and the loss of any one of our key customers could, therefore, adversely affect our financial condition and results of operations.

Historically, we have been dependent on a few customers for a significant portion of our revenue. For the year ended December 31, 2017 purchases by our top five customers accounted for approximately 40%, 22%, 8%, 6% and 5%,

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respectively, of our total oil, natural gas and NGL sales. This concentration of customers may increase our overall exposure to credit risk, and customers will likely be similarly affected by changes in economic and industry conditions. To the extent that any of our major purchasers reduces their purchases of oil, natural gas or NGLs or defaults on their obligations to us, our financial condition and results of operations could be adversely affected.

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

In the future we may make acquisitions of businesses that complement or expand our current business. We may not be able to identify attractive acquisition opportunities. In addition, increased competition in the areas in which we operate, including the Merge play, may make it more difficult for us to identify or complete acquisitions. Even if we do identify attractive acquisition opportunities, we may not be able to complete the acquisition or do so on commercially acceptable terms.

Any acquisition involves potential risks, including, among other things:

·

the validity of our assumptions about estimated proved reserves, future production, commodity prices, revenues, capital expenditures, operating expenses and costs;

·

an inability to successfully integrate the assets we acquire;

·

an inability to obtain satisfactory title to the assets we acquire;

·

a decrease in our liquidity by using a significant portion of our available cash or borrowing capacity to finance acquisitions;

·

a significant increase in our interest expense or financial leverage if we incur additional debt to finance acquisitions;

·

the assumption of unknown liabilities, losses or costs for which we obtain no or limited indemnity or other recourse;

·

the diversion of management’s attention from other business concerns;

·

an inability to hire, train or retain qualified personnel to manage and operate our growing assets; and

·

the occurrence of other significant changes, such as impairment of oil and natural gas properties, goodwill or other intangible assets, asset devaluation or restructuring charges.

Our decision to acquire a property will depend in part on the evaluation of data obtained from production reports and engineering studies, geophysical and geological analyses and seismic data and other information, the results of which are often inconclusive and subject to various interpretations.

The success of any completed acquisition will depend on our ability to integrate effectively the acquired assets into our existing operations. The process of integrating acquired assets may involve unforeseen difficulties and may require a disproportionate amount of our managerial and financial resources. In addition, even if we successfully integrate an acquisition, it may not be possible to realize the full benefits we may expect in estimated proved reserves, production volume, cost savings from operating synergies or other benefits anticipated from an acquisition or realize these benefits within the expected time frame. Anticipated benefits of an acquisition may be offset by operating losses relating to changes in commodity prices in oil and natural gas industry conditions, risks and uncertainties relating to the exploratory prospects of the combined assets or operations, or an increase in operating or other costs or other difficulties. If we fail to realize the benefits we anticipate from an acquisition, our results of operations may be adversely affected.

Deficiencies of title to our leased interests could significantly affect our financial condition.

It is our practice, in acquiring oil and natural gas leases or undivided interests in oil and natural gas leases or other developed rights, not to incur the expense of retaining lawyers to examine the title to the mineral interest to be acquired. Rather, we rely upon the judgment of oil and natural gas lease brokers or landmen who perform the fieldwork in

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examining records in the appropriate governmental or county clerk’s office to determine mineral ownership before we acquire an oil and gas lease or other developed rights in a specific mineral interest.

Prior to the drilling of an oil or gas well, it is the normal practice in our industry for the operator of the well to obtain a drilling title opinion from a qualified title attorney to ensure there are no obvious title defects on the property on which the well is to be located. The title attorney would typically research documents that are of record, including liens, taxes and all applicable contracts that burden the property. Frequently, as a result of such examinations, certain curative work must be undertaken to correct defects in the marketability of the title, and such curative work entails expense. Our failure to completely cure any title defects may invalidate our title to the subject property and adversely impact our ability in the future to increase production and reserves. Additionally, because a less strenuous title review is conducted on lands where a well has not yet been scheduled, undeveloped acreage has greater risk of title defects than developed acreage. Any title defects or defects in assignment of leasehold rights in properties in which we hold an interest may adversely impact our ability in the future to increase production and reserves, which could have a material adverse effect on our business, financial condition and results of operations.

We conduct a substantial portion of our operations through joint development agreements with third parties. Certain of our joint development agreements include complete‑to‑earn arrangements, whereby we are assigned title to properties from the third‑party after we complete wells and, in the case of certain counterparties, after completion reports relating to the wells have been approved by regulatory authorities whose approval may be delayed. Furthermore, certain of our joint development agreements specify that assignments are only to occur when the wells are capable of producing hydrocarbons in paying quantities. These additional conditions to assignment of title may from time to time apply to wells of substantial value. If one of our counterparties assigned title to a well in which we had earned an interest (according to our joint development agreement) to a third‑party, our title to such a well could be adversely impacted. In addition, if one of our counterparties becomes a debtor in a bankruptcy proceeding, or is placed into receivership, or enters into an assignment for the benefit of creditors, after we had earned ownership of, but before we had received title to, a well, certain creditors of the counterparty may have rights in that well that would rank prior to ours.

Recently enacted tax legislation may impact our ability to fully utilize our interest expense deductions and net operating loss carryovers to fully offset our taxable income in future periods.

Recently enacted legislation commonly known as the Tax Cuts and Jobs Act includes provisions that, beginning in 2018, generally will (i) limit our annual deductions for interest expense to no more than 30% of our “adjusted taxable income” (plus 100% of our business interest income) for the year and (ii) permit us to offset only 80% (rather than 100%) of our taxable income with net operating losses we generate after 2017. Interest expense and net operating losses subject to these limitations may be carried forward by us for use in later years, subject to these limitations. Additionally, the Tax Cuts and Jobs Act repealed the domestic manufacturing tax deduction for oil and gas companies. These tax law changes could have the effect of causing us to incur income tax liability and/or obligations under our Tax Receivable Agreement (the “Tax Receivable Agreement”) sooner than we otherwise would have incurred such liability or, in certain cases, could cause us to incur income tax liability that we might otherwise not have incurred, in the absence of these tax law changes. The Tax Cuts and Jobs Act also includes provisions that, beginning in 2018, reduce the maximum federal corporate income tax rate from 35% to 21% and eliminate the alternative minimum tax, which would lessen any adverse impact of the limitations described in the preceding sentences.

Certain federal income tax deductions currently available with respect to oil and natural gas exploration and development may be eliminated and new taxes may be imposed as a result of future legislation.

From time to time, legislation is introduced that would, if enacted, make significant changes to U.S. tax laws. These proposed changes have included repealing many tax incentives and deductions that are currently used by U.S. oil and gas companies and imposing new fees. Among others, proposed changes have included: elimination of the ability to fully deduct intangible drilling costs in the year incurred; repeal of the percentage depletion deduction for oil and gas properties; repeal of the domestic manufacturing tax deduction for oil and gas companies; increase in the geological and geophysical cost amortization period for independent producers; imposing a per barrel fee on domestically produced oil; and implementation of a fee on non‑producing federal oil and gas leases. The recently enacted Tax Cuts and Jobs Act did not include any of these proposals, except for the repeal of the domestic manufacturing tax deduction for oil and gas companies. However, it is possible that such provisions could be proposed in the future. The passage of legislation containing some or all of these provisions or any other similar change in U.S. federal income tax law could eliminate or postpone certain tax deductions that are currently available to us with respect to oil and natural gas exploration and

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development, and any such change could have a material adverse effect on our business, financial condition and results of operations.

We may be unable to compete effectively with larger companies, which may adversely affect our ability to generate sufficient revenues.

The oil and natural gas industry is intensely competitive, and we compete with other companies that have more resources than us. Many of our larger competitors not only drill for and produce oil and natural gas, but also engage in refining operations and market petroleum and other products on a regional, national or worldwide basis. These companies may have a greater ability to continue drilling activities during periods of low oil, natural gas and NGL prices, to contract for drilling equipment, to secure trained personnel, and to absorb the burden of present and future federal, state, local and other laws and regulations. The oil and natural gas industry has periodically experienced shortages of drilling rigs, equipment, pipe and personnel, which has delayed development drilling and other exploitation activities and has caused significant price increases. Competition for hiring experienced personnel, particularly in the engineering and technical, accounting and financial reporting, tax and land departments continues to be strong. In addition, competition for attractive oil and natural gas producing properties, oil and natural gas companies, and undeveloped leases and drilling rights remains robust. Any inability to compete effectively with larger companies could have a material adverse impact on our financial condition and results of operations.

The oil and natural gas industry is characterized by rapid and significant technological advancements and introductions of new products and services using new technologies. As others use or develop new technologies, we may be placed at a competitive disadvantage or competitive pressures may force us to implement those new technologies at substantial costs. In addition, other oil and natural gas companies may have greater financial, technical, and personnel resources that allow them to enjoy technological advantages and may in the future allow them to implement new technologies before we can. We may not be able to respond to these competitive pressures and implement new technologies on a timely basis or at an acceptable cost. If one or more of the technologies we use now or in the future were to become obsolete or if we are unable to use the most advanced commercially available technology, our business, financial condition and results of operations could be materially adversely affected.

We participate in oil and gas leases with third parties who may not be able to fulfill their commitments to our projects.

We frequently own less than 100% of the working interest in the oil and gas leases on which we conduct operations, and other parties will own the remaining portion of the working interest. Financial risks are inherent in any operation where the cost of drilling, equipping, completing and operating wells is shared by more than one person. We could be held liable for joint activity obligations of other working interest owners, such as nonpayment of costs and liabilities arising from the actions of other working interest owners. In addition, declines in oil, natural gas and NGL prices may increase the likelihood that some of these working interest owners, particularly those that are smaller and less established, are not able to fulfill their joint activity obligations. A partner may be unable or unwilling to pay its share of project costs, and, in some cases, a partner may declare bankruptcy. In the event any of our project partners do not pay their share of such costs, we would likely have to pay those costs, and we may be unsuccessful in any efforts to recover these costs from our partners, which could materially adversely affect our financial position.

The unavailability or high cost of drilling rigs, equipment, supplies, personnel and oil field services as well as fees for the cancellation of such services could adversely affect our ability to execute development and exploitation plans on a timely basis and within budget, and consequently could adversely affect our anticipated cash flow.

We utilize third‑party services to maximize the efficiency of our operation. The cost of oil field services typically fluctuates based on demand for those services. We may not be able to contract for such services on a timely basis, or the cost of such services may not remain at a satisfactory or affordable level. Shortages or the high cost of drilling rigs, equipment, supplies or personnel, including hydraulic fracturing equipment, supplies and personnel necessary for horizontal drilling, could delay or adversely affect our development and exploitation operations, which could have a material adverse effect on our financial condition and results of operations.

Our business depends in part on pipelines, transportation and gathering systems and processing facilities owned by others. Any limitation in the availability of those facilities could interfere with our ability to market our oil, natural gas and NGLs production and could harm our business.

The marketability of our oil, natural gas and NGLs production depends in part on the availability, proximity and capacity of pipelines and other transportation methods, such as trucks, gathering systems and processing facilities owned by third

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parties. The amount of oil, natural gas and NGLs that can be produced and sold is subject to curtailment in certain circumstances, such as pipeline interruptions due to scheduled and unscheduled maintenance, excessive pressure, physical damage or lack of contracted capacity on such systems. Also, the transfer of our oil, natural gas and NGLs on third‑party pipelines may be curtailed or delayed if it does not meet the quality specifications of the pipeline owners. Our access to transportation options, including trucks owned by third parties, can also be affected by U.S. federal and state regulation of oil and gas production and transportation, general economic conditions and changes in supply and demand. The curtailments arising from these and similar circumstances may last from a few days to several months. In many cases, we are provided only with limited, if any, notice as to when these circumstances will arise and their duration. Any significant curtailment in gathering system or transportation or processing facility capacity could reduce our ability to market our oil, natural gas and NGLs production and harm our business.

We could experience periods of higher costs if commodity prices continue to rise. These increases could reduce our profitability, cash flow and ability to complete development activities as planned.

Historically, our capital and operating costs have risen during periods of increasing oil, natural gas and NGL prices. These cost increases result from a variety of factors beyond our control, such as increases in the cost of electricity, steel and other raw materials that we and our vendors rely upon; increased demand for labor, services and materials as drilling activity increases; and increased taxes. Decreased levels of drilling activity in the oil and natural gas industry in recent periods have led to declining costs of some drilling equipment, materials and supplies. However, with the recent increase in commodity prices, such costs may rise faster than increases in our revenue, thereby negatively impacting the profitability of our wells. This impact may be magnified to the extent that our ability to participate in the commodity price increases is limited by our derivative activities.

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

We are not insured against all risks. Losses and liabilities arising from uninsured and underinsured events could materially and adversely affect our business, financial condition or results of operations. We may elect not to obtain insurance if we believe that the cost of available insurance is excessive relative to the risks presented. In addition, pollution and environmental risks generally are not fully insurable. Our oil and natural gas exploration and production activities are subject to all of the operating risks associated with drilling for and producing oil and natural gas, including the possibility of:

·

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

·

adverse weather conditions and natural disasters;

·

encountering abnormally pressured formations;

·

facility or equipment malfunctions;

·

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

·

fires, explosions and ruptures of pipelines;

·

personal injuries and death; and

·

terrorist attacks targeting oil and natural gas related facilities and infrastructure.

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

·

injury or loss of life;

·

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

·

pollution and other environmental damage and associated clean‑up responsibilities;

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·

regulatory investigations, penalties or other sanctions;

·

suspension of our operations; and

·

repair and remediation costs.

We are subject to complex federal, state, local and other laws and regulations that could adversely affect the cost, manner or feasibility of conducting our operations.

Our oil and natural gas exploration and production operations are subject to complex and stringent laws and regulations. In order to conduct our operations in compliance with these laws and regulations, we must obtain and maintain numerous permits, approvals and certificates from various federal, state and local governmental authorities. Failure or delay in obtaining regulatory approvals or drilling permits could have a material adverse effect on our ability to develop our properties, and receipt of drilling permits with onerous conditions could increase our compliance costs. In addition, regulations regarding conservation practices and the protection of correlative rights affect our operations by limiting the quantity of oil, natural gas and NGLs we may produce and sell.

We are subject to federal, state and local laws and regulations as interpreted and enforced by governmental authorities possessing jurisdiction over various aspects of the exploration, production and transportation of oil, natural gas and NGLs, as well as safety matters. Legal requirements are frequently changed and subject to interpretation, and we are unable to predict the ultimate cost of compliance with these requirements or their ultimate effect on our operations. We may be required to make significant expenditures to comply with governmental laws and regulations. The discharge of oil, natural gas, NGLs or other pollutants into the air, soil or water may give rise to significant liabilities on our part to the government, and third parties and may require us to incur substantial costs for remediation.

See “Item 1. Business—Regulations” for a further description of the laws and regulations that affect us.

Our ability to pursue our business strategies may be adversely affected if we incur costs and liabilities due to a failure to comply with environmental regulations or a release of hazardous substances into the environment.

We may incur significant costs and liabilities as a result of environmental requirements applicable to the operation of our wells, gathering systems and other facilities. These costs and liabilities could arise under a wide range of federal, state and local environmental laws and regulations, including, for example:

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the Clean Air Act, or CAA, and comparable state laws and regulations that impose obligations related to air emissions;

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the Clean Water Act and Oil Pollution Act, or OPA, and comparable state laws and regulations that impose obligations related to discharges of pollutants into regulated bodies of water;

·

the Resource Conservation and Recovery Act, or RCRA, and comparable state laws that impose requirements for the handling and disposal of waste from our facilities;

·

the Comprehensive Environmental Response, Compensation, and Liability Act, or CERCLA, and comparable state laws that regulate the cleanup of hazardous substances that may have been released at properties currently or previously owned or operated by us or at locations to which we have sent waste for disposal;

·

the Environmental Protection Agency’s, or the EPA’s, community right to know regulations under the Title III of CERCLA and comparable state laws that require that we organize and/or disclose information about hazardous materials used or produced in our operations;

·

the Occupational Safety and Health Act, or OSHA, which establishes workplace standards for the protection of the health and safety of employees, including the implementation of hazard communications programs designed to inform employees about hazardous substances in the workplace, potential harmful effects of these substances, and appropriate control measures;

·

the National Environmental Policy Act, or NEPA, which requires federal agencies to evaluate major agency actions having the potential to significantly impact the environment and which may require the

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preparation of Environmental Assessments and more detailed Environmental Impact Statements that may be made available for public review and comment;

·

the Migratory Bird Treaty Act, which implements various treaties and conventions between the United States and certain other nations for the protection of migratory birds and, pursuant to which the taking, killing, or possessing of migratory birds is unlawful without a permit, thereby potentially requiring the implementation of operating restrictions or a temporary, seasonal, or permanent ban on operations in affected areas; and

·

the Endangered Species Act, or ESA, and analogous state laws, which seek to ensure that activities do not jeopardize endangered or threatened animals, fish and plant species, nor destroy or modify the critical habitat of such species.

We may incur significant delays, costs and liabilities as a result of federal, state and local environmental, health and safety requirements applicable to exploration, development and production activities. These laws and regulations may require us to obtain a variety of permits or other authorizations governing our air emissions, water discharges, waste disposal, development in regulated wetlands or waters, or other environmental impacts associated with drilling, production and product transportation pipelines or other operations; regulate the sourcing and disposal of water used in the drilling, fracturing and completion processes; limit or prohibit drilling activities in certain areas and on certain lands lying within wilderness, frontier and other protected areas or that contain regulated wetlands or other waters; require remedial action to prevent or mitigate pollution from former operations such as plugging abandoned wells or closing earthen pits; and/or impose substantial liabilities for spills, pollution or failure to comply with regulatory filing requirements. In addition, these laws and regulations are complex, change frequently and have tended to become increasingly stringent over time; however, future changes to environmental laws and regulations remain uncertain. Failure to comply with these laws and regulations may trigger a variety of administrative, civil and criminal enforcement measures, including the assessment of monetary penalties, the imposition of remedial requirements, and the issuance of orders enjoining future operations. Certain environmental statutes, including the RCRA, CERCLA, the federal OPA and analogous state laws and regulations, impose strict joint and several liability for costs required to clean up and restore sites where petroleum or hazardous substances or other waste products have been disposed of or otherwise released. More stringent laws and regulations, including laws related to climate change and greenhouse gases, may be adopted in the future. If there are more expensive and stringent environmental legislation and regulations applied to the oil and natural gas industry, it could result in increased costs of doing business and consequently affect profitability. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances or other waste products into the environment. We are also subject to many other environmental requirements delineated in “Business—Environmental Matters and Regulation.”

Federal and state legislative and regulatory initiatives relating to hydraulic fracturing and other oil and gas production activities as well as governmental reviews of such activities could result in increased costs, additional operating restrictions or delays, which could adversely affect our production.

Hydraulic fracturing is an important and common practice that is used to stimulate production of natural gas and/or oil from dense subsurface rock formations. The process involves the injection of water, sand and chemicals under pressure into the formation to fracture the surrounding rock and stimulate production. We routinely utilize hydraulic fracturing techniques in our oil and natural gas drilling and completion programs. The process is typically regulated by state oil and natural gas commissions. However, the EPA has asserted federal regulatory authority over certain hydraulic fracturing activities involving diesel under the federal Safe Drinking Water Act, or SDWA, in states where the EPA is the permitting authority and released guidance in February 2014 on regulatory requirements for companies that plan to conduct hydraulic fracturing using diesel in those states. In addition, the EPA issued a notice of rulemaking under the Toxic Substances Control Act relating to chemical substances and mixtures used in oil and gas exploration and production. Congress has also considered legislation to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the fracturing process.

Some states, including those in which we operate, have adopted, and other states are considering adopting, regulations that could impose more stringent permitting, disclosure and well construction requirements on hydraulic fracturing operations under certain circumstances. For example, in 2011 Texas adopted the Hydraulic Fracturing Chemical Disclosure Rule, requiring public disclosure of chemicals in fluids used in the hydraulic fracturing process for drilling permits issued after February 1, 2012. In addition, the OKCC has adopted rules prohibiting water pollution resulting

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from hydraulic fracturing operations and requiring disclosure of chemicals used in hydraulic fracturing. The mandatory disclosure of information regarding the constituents of hydraulic fracturing fluids could make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings based upon allegations that specific chemicals used in the fracturing process could adversely affect the environment.

Texas has also authorized the Texas Commission on Environmental Quality to suspend water use rights for oil and gas users in the event of serious drought conditions and has imposed more stringent emissions, monitoring, inspection, maintenance, and repair requirements on Barnett Shale operators to minimize Volatile Organic Compound, or VOC, releases. Also, Louisiana requires operators to minimize releases of gases into the open air after hydraulic fracturing in certain urban areas.

In addition to state laws, local land use restrictions, such as city ordinances, may restrict or prohibit the performance of well drilling in general and/or hydraulic fracturing in particular. If state, local, or municipal legal restrictions are adopted in areas where we are currently conducting operations, or in the future plan to conduct operations, we may incur additional costs to comply with such requirements that may be significant in nature, experience delays or curtailment in the pursuit of exploration, development, or production activities, and perhaps even be precluded from drilling wells.

There are also certain governmental reviews conducted that focus on environmental aspects of hydraulic fracturing practices. The White House Council on Environmental Quality coordinated an administration‑wide review of hydraulic fracturing practices, and a committee of the United States House of Representatives has conducted an investigation of hydraulic fracturing practices. Furthermore, a number of federal agencies are analyzing, or have been requested to review, a variety of environmental issues associated with hydraulic fracturing. On December 13, 2016, the EPA released a study of the potential adverse effects that hydraulic fracturing activities (including water acquisition, chemical mixing, well injection, and disposal and reuse) may have on water quality and public health, concluding that there is scientific evidence that hydraulic fracturing activities could impact drinking water resources in the United States under some circumstances.

The EPA finalized a rule prohibiting discharges of wastewater resulting from hydraulic fracturing to publicly‑owned treatment works. The EPA is also conducting a study of private wastewater treatment facilities, referred to as centralized waste treatment, or CWT, facilities, accepting oil and gas extraction wastewater and will evaluate whether to revise discharge limits from CWT facilities. In addition, the U.S. Department of Energy’s Natural Gas Subcommittee of the Secretary of Energy Advisory Board conducted a review of hydraulic fracturing issues and practices and made recommendations to better protect the environment from drilling using hydraulic fracturing completion methods. Ongoing or proposed studies, depending on their degree of pursuit and any meaningful results obtained, could spur initiatives to further regulate hydraulic fracturing under the Safe Drinking Water Act, the Toxic Substances Control Act, or other statutory and/or regulatory mechanisms. Executive Order on April 13, 2012 created the Interagency Working Group on Unconventional Natural Gas and Oil, which is charged with coordinating and aligning federal agency research and scientific studies on unconventional oil and natural gas resources.

Also, in 2015, the U.S. Department of the Interior’s Bureau of Land Management, or BLM, adopted rules regarding well stimulation, chemical disclosures and other requirements for hydraulic fracturing on federal and Indian lands; however, these rules were rescinded by rule in December 2017. Effective December 2016, the NPS, finalized updates to its regulations governing non-federal oil and gas rights, affecting various approval exemptions and addressing well stimulation, chemical disclosures and other requirements for hydraulic fracturing. However, this regulation is targeted for agency review for potential rescission or revision pursuant to Executive Order No. 13783 titled “Promoting Energy Independence and Economic Growth,” dated March 28, 2017.

In addition, as discussed further below, state and federal regulatory agencies recently have focused on seismic events potentially associated with oil and gas operations, including injection well disposal and the hydraulic fracturing process.

Further, since 2012, oil and gas operations (production, processing, transmission, storage and distribution) have been subject to regulation under the New Source Performance Standards, or NSPS, and National Emission Standards for Hazardous Air Pollutants, or NESHAPS, programs. The EPA rules also include NSPS standards for completions of hydraulically‑fractured gas wells. These standards include the reduced emission completion techniques developed in the EPA’s Natural Gas STAR program along with pit flaring of gas not sent to the gathering line. The standards are applicable to newly drilled and fractured wells as well as existing wells that are refractured. Further, the regulations under NESHAPS include maximum achievable control technology, or MACT, standards for those glycol dehydrators and storage vessels at major sources of hazardous air pollutants not currently subject to MACT standards. In October

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2012, several challenges to the EPA’s rules were filed by various parties, including environmental groups and industry associations. In a January 16, 2013 unopposed motion to hold this litigation in abeyance, the EPA indicated that it may reconsider some aspects of the rules. The EPA has since reconsidered several aspects of the rules and may continue to make changes. For example in 2015, the EPA finalized a final rule defining “low pressure gas well” and removing “connected in parallel” from the definition of storage vessels in the New Source Performance Standard. Depending on the outcome of such judicial proceedings and regulatory actions, the rules may be further modified or rescinded or the EPA may issue new rules. We have reported some of our facilities as being subject to these rules and have incurred, and will continue to incur, costs to control emissions, and to satisfy reporting and other administrative requirements associated with these rules. We continue to evaluate the effect these rules will have on our business. In addition, the EPA finalized new rules to regulate emissions of methane and volatile organic compounds from new and modified sources in the oil and gas sector effective August 2, 2016. The EPA also finalized a rule regarding the alternative criteria for aggregating multiple small surface sites into a single source for air‑quality permitting purposes. 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 across the oil and gas industry. BLM adopted rules effective on January 17, 2017 to reduce venting, flaring, and leaks during oil and natural gas production activities on onshore federal and Indian leases. EPA issued a two-year stay of these requirements in December 2017 and on February 13, 2018 announced a rule proposal to rescind several requirements and significantly revise others. Increased regulation and attention given to the hydraulic‑fracturing process could lead to greater opposition, including litigation, to oil and gas production activities using hydraulic‑fracturing techniques. Additional legislation or regulation could also lead to operational delays or increased operating costs in the production of oil and natural gas, including from the developing shale formations, or could make it more difficult to perform hydraulic fracturing. The adoption of any federal, state or local laws or the implementation of regulations regarding hydraulic fracturing could potentially cause a decrease in the completion of new oil and gas wells, increased compliance costs and time, which could adversely affect our financial position, results of operations and cash flows.

Federal and state legislative and regulatory initiatives relating to induced seismicity in connection with oil and gas activities could result in increased costs, additional operating restrictions or delays, and litigation risks which could adversely affect our operations

State and federal regulatory agencies recently have focused on a possible connection between an observed increase in minor seismic activity and tremors and both the operation of injection wells used for oil and gas waste waters and the hydraulic fracturing process. When caused by human activity, such events are called induced seismicity. In some instances, operators of injection wells in the vicinity of minor seismic events have reduced injection volumes or suspended operations, often voluntarily. A 2012 report published by the National Academy of Sciences concluded that only a very small fraction of the tens of thousands of injection wells have been suspected to be, or have been, the likely cause of induced seismicity. However, some state regulatory agencies have modified their regulations to account for induced seismicity. For example, the Texas Railroad Commission rules allow the Commission to modify, suspend, or terminate a permit based on a determination that the permitted injection well activity is likely to be contributing to seismic activity. The OKCC also asserts authority to shut down injection wells that it considers linked to induced seismicity, and has recently taken other steps to regulate injection wells that may contribute to induced seismicity. For example, on August 3, 2015, the OKCC adopted a plan calling for mandatory reductions in oil and gas wastewater disposal well volumes to address potential induced seismicity in Oklahoma; implementation has involved reductions of injection or shut-ins of disposal wells in 2015 and 2016. In February 2017, the OKCC issued a directive aimed at limiting the growth in future underground injection disposal rates into the Arbuckle formation in an area with seismicity issues. In December 2016, the OKCC announced seismicity guidelines for hydraulic fracturing operations, under which monitoring results can trigger a pause or suspension of hydraulic fracturing operations to evaluate seismic activity. Regulatory agencies are continuing to study possible linkage between injection activity and induced seismicity and also possible linkages of induced seismicity to the hydraulic fracturing process. Third-party lawsuits for property damage and other remedies based on allegations of induced seismicity have been brought against other energy companies.

Climate change legislation or regulations restricting emissions of greenhouse gases could result in increased operating costs and reduced demand for the oil, natural gas and NGLs we produce; and actual impacts of climate change like extreme weather conditions could adversely affect our operations.

In December 2009, the EPA officially published its findings that emissions of carbon dioxide, methane and other greenhouse gases, or GHGs, present an endangerment to public health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the earth’s atmosphere and other climatic changes. Based on its findings, the EPA promulgated regulations to restrict emissions of GHGs under existing provisions of the federal

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Clean Air Act, including one rule that requires a reduction in emissions of GHGs from motor vehicles and another that regulates emissions of GHGs from certain large stationary sources. In addition, on October 30, 2009, the EPA published a final rule requiring the reporting of GHG emissions from specified large GHG emission sources in the United States. On November 9, 2010, the EPA issued final rules to expand its existing GHG reporting rule to include onshore oil and natural gas production, processing, transmission, storage and distribution facilities with reporting of GHG emissions from such facilities required on an annual basis. The first reports were due in 2012 for emissions occurring in 2011. In 2015, the EPA added reporting of GHG emissions from gathering and boosting systems, completions and workovers of oil wells using hydraulic fracturing, and blowdowns of natural gas transmission pipelines to the GHG reporting rule. We are currently required to monitor and report GHG emissions under this rule, and operational and/or regulatory changes could increase the burden of compliance with GHG emissions monitoring and reporting requirements.

As previously mentioned, federal regulations require methane reductions from new or modified oil and gas sources. On November 10, 2016, the EPA issued a final ICR that would have required numerous oil and gas companies to provide information regarding methane emissions from existing oil and gas facilities, but EPA withdrew the ICR on March 2, 2017. The U.S. Congress has from time to time considered adopting legislation to reduce emissions of GHGs and almost one‑half of the states have already taken legal measures to reduce emissions of GHGs primarily through the planned development of GHG emission inventories and/or regional GHG cap and trade programs. The adoption of legislation or regulatory programs to reduce emissions of GHGs could require us to incur increased operating costs, such as costs to purchase and operate emissions control systems, to acquire emissions allowances or comply with new regulatory or reporting requirements. Any such legislation or regulatory programs could also increase the cost of consuming, and thereby reduce demand for, the oil, natural gas and NGLs we produce. In addition, international, federal, regional and local regulatory initiatives that target GHGs could adversely affect the marketability of the oil and natural gas we produce. In 2015, the United States participated in the United Nations Conference on Climate Change, which led to the creation of the Paris Agreement. The Paris Agreement came into force on November 4, 2016, requiring, 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 United States’ has expressed an intention to withdraw from participation in the Paris Agreement, but some state and local governments have expressed intentions to take GHG-related actions. Due to the uncertainties surrounding the regulation of and other risks associated with GHG emissions, we cannot predict the financial impact of related developments on our operations. To the extent adopted, legislation and regulatory programs to reduce emissions of GHGs could have an adverse effect on our business, financial condition and results of operations.

In addition, there has been public discussion that climate change may be associated with extreme weather conditions such as more intense hurricanes, thunderstorms, tornados and snow or ice storms, as well as rising sea levels. Another possible consequence of climate change is increased volatility in seasonal temperatures. Some studies indicate that climate change could cause some areas to experience temperatures substantially colder than their historical averages. Extreme weather conditions can interfere with our production and increase our costs and damage resulting from extreme weather may not be fully insured. However, at this time we are unable to determine the extent to which climate change may lead to increased storm or weather hazards affecting our operations.

We may face unanticipated water and other waste disposal costs.

We may be subject to regulation that restricts our ability to discharge water produced as part of our oil or gas production operations. Productive zones frequently contain water that must be removed in order for the oil or gas to produce, and our ability to remove and dispose of sufficient quantities of water from the various zones will determine whether we can produce oil or gas in commercial quantities. The produced water currently is transported from the lease and injected into disposal wells. Some states, including Oklahoma and Texas, also assert the authority to shut down disposal wells that are deemed to contribute to induced seismicity, or seismic activity that is caused by human activity. In 2015, the OKCC adopted a plan calling for mandatory reductions in oil and gas wastewater disposal well volumes to address potential induced seismicity in Oklahoma. Further, in February 2017, the OKCC issued a directive aimed at limiting the growth in future underground injection disposal rates into the Arbuckle formation in an area with seismicity issues. The availability of disposal wells with sufficient capacity to receive all of the water produced from our wells may affect our ability to produce our wells. Also, the EPA has prohibited the disposal of wastewater from hydraulic fracturing into publicly owned treatment facilities through a “zero discharge” pretreatment standard. The EPA is also conducting a study of private wastewater treatment facilities, referred to as centralized waste treatment, or CWT, facilities, accepting oil and gas extraction wastewater and will evaluate whether to revise discharge limits from CWT facilities. Therefore, across the oil and gas industry, the cost to transport and dispose of that water, including the cost of complying with regulations concerning water disposal, may increase. This increase may reduce our profitability.

39


 

If water produced from our projects fails to meet the quality requirements of applicable regulatory agencies, our wells produce water in excess of the applicable volumetric permit limits, the disposal wells fail to meet the requirements of all applicable regulatory agencies, or we are unable to secure access to disposal wells with sufficient capacity to accept all of the produced water, we may have to shut in wells, reduce drilling activities, or upgrade facilities for water handling or treatment. The costs to dispose of this produced water may increase if any of the following occur:

·

we cannot obtain future permits from applicable regulatory agencies;

·

water of lesser quality or requiring additional treatment is produced;

·

our wells produce excess water;

·

new laws and regulations require water to be disposed in a different manner; or

·

costs to transport the produced water to the disposal wells increase.

We conduct a substantial portion of our operations through farm‑outs, areas of mutual interest and other joint development agreements. These agreements subject us to additional risks that could have a material adverse effect on the success of these operations, our financial position and our results of operations.

We conduct a substantial portion of our operations through joint development agreements with third parties, including ExxonMobil. We may also enter into other joint development agreements in the future. These third parties may have obligations that are important to the success of the joint development agreement, such as the obligation to contribute capital or pay carried or other costs associated with the joint development agreement. The performance of these third‑party obligations, including the ability of the third parties to satisfy their obligations under these arrangements, is outside our control. If these parties do not satisfy their obligations under these arrangements, our business may be adversely affected.

Our joint development agreements may involve risks not otherwise present when exploring and developing properties directly, including, for example:

·

our joint development partners may share certain approval rights over major decisions;

·

our joint development partners may not pay their share of the joint development agreement obligations, leaving us liable for their share of joint development liabilities;

·

we may incur liabilities as a result of an action taken by our joint development partners;

·

our joint development partners may be in a position to take actions contrary to our instructions or requests or contrary to our policies or objectives; and

·

disputes between us and our joint development partners may result in delays, litigation or operational impasses.

The risks described above, the failure to continue our joint ventures or to resolve disagreements with our joint development partners could adversely affect our ability to transact the business of such joint development, which would in turn negatively affect our financial condition and results of operations.

40


 

Risks Relating to Financings and Ownership:

Future sales of our common stock in the public market or the issuance of securities senior to our common stock, or the perception that these sales may occur, could adversely affect the trading price of our common stock and our ability to raise funds in stock offerings.

A large percentage of our shares of common stock are held by a relatively small number of investors. Further, we entered into registration rights agreements with certain of those investors pursuant to which we have filed a registration statement with the SEC to facilitate potential future sales of such shares by them. Sales by us or our stockholders of a substantial number of shares of our common stock in the public markets, or even the perception that these sales might occur, could cause the market price of our Class A common stock to decline or could impair our ability to raise capital through a future sale of, or pay for acquisitions using, our equity securities.

We may issue common stock or other equity securities senior to our common stock in the future for a number of reasons, including to finance acquisitions, to adjust our leverage ratio, and to satisfy our obligations upon the exercise of warrants and options, or for other reasons. We cannot predict the effect, if any, that future sales or issuances of shares of our common stock or other equity securities, or the availability of shares of common stock or such other equity securities for future sale or issuance, will have on the trading price of our common stock.

Increases in interest rates could adversely affect our business.

Our business and operating results can be harmed by factors such as the availability, terms and cost of capital, increases in interest rates or a reduction in credit rating. These changes could cause our cost of doing business to increase, limit our ability to pursue acquisition opportunities, reduce our cash flow available for drilling and place us at a competitive disadvantage. For example, as of February 21, 2018, following the issuance and sale of the 2023 First Lien Notes, we had an unused borrowing capacity of approximately $25.0 million under the Revolver, subject to compliance with financial covenants. The impact of a 1.0% increase in interest rates on an assumed borrowing of the full $50.0 million available under the Revolver would result in increased annual interest expense of approximately $0.5 million and a corresponding decrease in our net income. Recent and continuing disruptions and volatility in the global financial markets may lead to a contraction in credit availability impacting our ability to finance our operations. A significant reduction in our cash flows from operations or the availability of credit could materially and adversely affect our ability to achieve our planned growth and operating results.

Our indebtedness could adversely affect our financial condition. Our annual interest expense is large related to our cash flow.

As of December 31, 2017, we had $770.1 million of total long-term debt obligations, including $211.0 million drawn on the Revolver. As of February 21, 2018, after giving effect to the issuance and sale of the 2023 First Lien Notes, we had approximately $1.0 billion of total long-term debt obligations, including $25.0 million drawn on the Revolver. Our indebtedness may significantly affect our financial flexibility in the future, including by making it more difficult for us to borrow in the future, making us more vulnerable to adverse economic or industry conditions and deterring third parties from material transactions with us. In addition, a reduction in the borrowing base for the Revolver will reduce our liquidity. If such a reduction results in the outstanding amount under the Revolver exceeding the borrowing base, we will be required to repay the deficiency within a short period of time. Our business may not continue to generate sufficient cash flow from operations to repay our indebtedness. If we are unable to generate sufficient cash flow from operations, we may be required to sell assets, to refinance all or a portion of our indebtedness or to obtain additional financing.

The borrowing base under the Revolver will be redetermined at least semi-annually on or about April 1 and October 1 of each year, with such redetermination based primarily on reserve reports using lender commodity price expectations at such time. JEH and the administrative agent (acting at the direction of lenders holding at least 662/3% of the outstanding loans) may each request one unscheduled borrowing base redetermination between each scheduled redetermination. In addition, the lenders may elect to redetermine the borrowing base upon the occurrence of certain defaults under our material operating agreements or upon the cancellation or termination of certain of our joint development agreements. The borrowing base may also be reduced as a result of our issuance of secured or unsecured notes, our termination of material hedging positions or our consummation of significant asset sales. If current low commodity prices continue through such redetermination events, the borrowing base under the Revolver may be reduced.

Certain federal regulatory agencies, including the Office of the Comptroller of the Currency, the Federal Reserve, and the Federal Deposit Insurance Corp., have recently focused on oil and gas lenders’ examinations and ratings of reserve

41


 

based loans, with a view towards encouraging such lenders to reduce their exposure to potentially substandard loans to oil and gas companies. In April 2014, the Office of the Comptroller of the Currency issued the “Oil and Gas Production Lending” bank examination booklet, which details potential regulatory requirements related to reserve based lending. Whether or not these regulatory agencies are successful in implementing stricter requirements related to reserve based lending, oil and gas lenders may respond to these discussions by taking a more conservative approach in their lending practices, which could adversely impact future borrowing base redeterminations under the Revolver.

For more information on our indebtedness, see “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources.”

We may be unable to maintain compliance with certain financial ratio covenants of our outstanding indebtedness which could result in an event of default that, if not cured or waived, would have a material adverse effect on our business, financial condition and results of operations.

The Revolver requires us to maintain certain financial ratios, including (i) commencing with the fiscal quarter ending March 31, 2019, a senior secured leverage ratio, consisting of consolidated secured funded debt to EBITDAX, of not greater than 2.25 to 1.00 as of the last day of any fiscal quarter, (ii) a current ratio, consisting of consolidated current assets, including the unused amounts of the total commitments, to consolidated current liabilities, of not less than 1.00 to 1.00 as of the last day of any fiscal quarter, and (iii) commencing with the fiscal quarter ending March 31, 2019, a total leverage ratio, consisting of consolidated debt to EBITDAX, of not greater than 5.25 to 1.00 as of March 31, 2019, 5.00 to 1.00 as of June 30, 2019, 4.75 to 1.00 as of September 30, 2019, 4.50 to 1.00 as of December 31, 2019 and 4.00 to 1.00 as of the last day of each fiscal quarter ending thereafter.

As of December 31, 2017, we were in compliance with our financial covenants. However, we cannot guarantee that we will be able to comply with such terms at all times in the future. Any failure to comply with the conditions and covenants in the Revolver that is not waived by our lenders or otherwise cured could lead to a termination of the Revolver, acceleration of all amounts due under the Revolver, or trigger cross default provisions under other financing arrangements. These restrictions may limit our ability to obtain future financings to withstand a future downturn in our business or the economy in general, or to otherwise conduct necessary corporate activities. We may also be prevented from taking advantage of business opportunities that arise because of the limitations that the restrictive covenants under our indebtedness impose on us.

The Jones family and certain other stockholders control a significant percentage of Jones Energy, Inc.’s voting power and have the ability to take actions that may conflict with your interests.

As of December 31, 2017, the Jones family, Metalmark Capital and affiliates of JVL Advisors, L.L.C. held approximately 44.5% of the combined voting power of Jones Energy, Inc. These stockholders are entitled to act separately in their own respective interests with respect to their ownership interests in Jones Energy, Inc., and collectively have the ability to substantially influence the election of the members of our board of directors, thereby potentially controlling our management and affairs. In addition, they have significant influence over all matters that require approval by our stockholders, including mergers and other material transactions.

If we fail to develop or maintain an effective system of internal controls, we may not be able to report our financial results accurately or prevent fraud, which would likely have a negative impact on the market price of our common stock.

Effective internal controls are necessary for us to provide reliable financial reports, prevent fraud and to operate successfully as a publicly traded company. To comply with the requirements of being a publicly traded company, we may need to implement additional financial and management controls, reporting systems and procedures and hire additional accounting, finance, tax and legal staff. Our efforts to develop and maintain our internal controls may not be successful, and we may be unable to maintain effective controls over our financial processes and reporting in the future or to comply with our obligations under Section 404 of the Sarbanes‑Oxley Act of 2002, which we refer to as Section 404. For example, Section 404 requires us, among other things, to annually review and report on the effectiveness of our internal controls over financial reporting. Any failure to develop, implement or maintain effective internal controls or to improve our internal controls could harm our operating results or cause us to fail to meet our reporting obligations. Given the difficulties inherent in the design and operation of internal controls over financial reporting, we can provide no assurance as to our conclusions about the effectiveness of our internal controls, and we may incur significant costs in our efforts to comply with Section 404. If one or more material weaknesses persist or if we fail

42


 

to establish and maintain effective internal control over financial reporting, our ability to accurately report our financial results could be adversely affected. Ineffective internal controls could also subject us to regulatory scrutiny and a loss of confidence in our reported financial information, which could have an adverse effect on our business.

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

Our success will depend to a large extent upon the efforts and abilities of our executive officers and key operations personnel. The loss of the services of one or more of these key employees could have a material adverse effect on us. We do not maintain insurance against the loss of any of these individuals. Our business will also be dependent upon our ability to attract and retain qualified personnel. Since the fourth quarter of 2014, the prices of oil, natural gas and NGLs were extremely volatile and declined significantly. Key employees may depart because of uncertainty during times of commodity price volatility. Acquiring and keeping these personnel could prove more difficult or cost substantially more than estimated. This could cause us to incur greater costs, or prevent us from pursuing our development and exploitation strategy as quickly as we would otherwise wish to do.

We currently have no plans to pay regular dividends on our common stock, so you may not receive funds without selling your common stock.

We currently have no plans to pay regular dividends on our Class A common stock. Any payment of dividends in the future will be at the discretion of our board of directors and will depend on, among other things, our earnings, financial condition and business opportunities, the restrictions in our debt agreements, and other considerations that our board of directors deems relevant. Accordingly, you may have to sell some or all of your Class A common stock in order to generate cash flow from your investment.

We will incur corporate income tax liabilities on taxable income allocated to us by JEH with respect to JEH Units we own, which may be substantial. JEH is required to make cash tax distributions under its operating agreement. JEH’s ability to make tax distributions, and our ability to pay taxes and the Tax Receviable Agreement liability may be limited by our structure and available liquidity. To the extent that we incur cash income tax liabilities or JEH is required to make cash tax distributions and cash payments of the Tax Receviable Agreement liability it would impact our liquidity and reduce cash available for other uses.

Under the terms of its operating agreement, JEH is generally required to make quarterly pro rata cash tax distributions to its unitholders (including us) based on income allocated to such unitholders through the end of each relevant quarter, as adjusted to take into account our good faith projections of taxable income or loss for the remainder of the calendar year, to the extent JEH has cash available for such distributions and subject to certain other restrictions described below. During 2016, JEH generated taxable income, resulting in the payment during 2016 of $17.3 million in cash tax distributions to JEH unitholders (other than us). As a result of JEH’s 2016 taxable income (all of which is passed-through and taxed to us and JEH’s other unitholders), during 2017 we made further income tax payments to federal and state taxing authorities of $2.3 million and JEH made further tax distributions to JEH unitholders (other than us) of $0.6 million. During 2017, JEH did not generate taxable income, therefore we did not make any additional tax payments nor did JEH make any additional tax distributions other than those made as a result of 2016 JEH taxable income. Based on our initial 2018 operating budget and information available as of this filing, we do not anticipate that we will be required to make any additional tax payments or that JEH will make any additional tax distributions during 2018. Estimating the tax distributions required under the operating agreement is imprecise by nature, highly uncertain, and dependent upon a variety of factors.

We are classified as a corporation for U.S. federal income tax purposes and, in most states in which JEH does business, for state income tax purposes. Under current law, we are subject to U.S. federal income tax at rates of up to 21%, and to state income tax at rates that vary from state to state, on the net income allocated to us by JEH with respect to the JEH Units we own. We are a holding company with our sole asset consisting of our ownership in JEH and have no independent means of generating revenue. JEH is classified as a partnership for federal income tax purposes and as such is not subject to federal income tax (other than as a withholding agent). Instead, taxable income is allocated to holders of JEH Units, including the JEH Units we own. Under the terms of its operating agreement, JEH is obligated to make tax distributions to holders of its units, including us, subject to the conditions described below. Our ability to cause JEH to make tax distributions, which generally will be pro rata with respect to all outstanding JEH Units, in an amount sufficient to allow us to pay our taxes and make any payments due under the Tax Receivable Agreement, is subject to various factors, including the cash requirements and financial condition of JEH, compliance by JEH or its subsidiaries with restrictions, covenants and financial ratios related to existing or future indebtedness, including under our notes and

43


 

the Revolver, and other agreements entered into with third parties. As a result, it is possible that Jones Energy, Inc. will not have sufficient cash to pay taxes and make payments under the Tax Receviable Agreement liability.

See “Risk Factors—We will be required to make payments under the Tax Receivable Agreement for certain tax benefits we may receive (or be deemed to receive), and the amounts of such payments could be significant.”

We will be required to make payments under the Tax Receivable Agreement for certain tax benefits we may receive (or be deemed to receive), and the amounts of such payments could be significant.

We entered into the Tax Receivable Agreement with JEH and the Class B shareholders. This agreement generally provides for the payment by us of 85% of the amount of cash savings, if any, in U.S. federal, state and local income tax or franchise tax that we actually realize (or are deemed to realize in certain circumstances) as a result of (i) the tax basis increases resulting from the Class B shareholders’ exchange of JEH Units for shares of Class A common stock (or resulting from a sale of JEH Units to us for cash) and (ii) imputed interest deemed to be paid by us as a result of, and additional tax basis arising from, any payments we make under the Tax Receivable Agreement. In addition, payments we make under the Tax Receivable Agreement will be increased by any interest accrued from the due date (without extensions) of the corresponding tax return.

The payment obligations under the Tax Receivable Agreement are our obligations and not obligations of JEH. For purposes of the Tax Receivable Agreement, cash savings in tax generally are calculated by comparing our actual tax liability to the amount we would have been required to pay had we not been able to utilize any of the tax benefits subject to the Tax Receivable Agreement. Any payments are made within a designated period of time following the filing of the tax return where we utilize such tax benefits to reduce taxes in a given year. The term of the Tax Receivable Agreement will continue until all such tax benefits have been utilized or expired, unless we exercise our right to terminate the Tax Receivable Agreement by making the termination payment specified in the agreement.

The actual increase in tax basis, as well as the amount and timing of any payments under the Tax Receivable Agreement, will vary depending upon a number of factors, including the timing of the exchanges of JEH Units, the price of Class A common stock at the time of each exchange, the extent to which such exchanges are taxable, the amount and timing of the taxable income we generate in the future and the tax rate then applicable, and the portion of our payments under the Tax Receivable Agreement constituting imputed interest or depletable, depreciable or amortizable basis. We expect that the payments that we will be required to make under the Tax Receivable Agreement could be substantial.

The payments under the Tax Receivable Agreement will not be conditioned upon a holder of rights under the Tax Receivable Agreement having a continued ownership interest in either JEH or us.

In certain circumstances including transactions involving a change in control, significant payments under the Tax Receivable Agreement may be accelerated and/or significantly exceed the actual benefits, if any, we realize in respect of the tax attributes subject to the Tax Receivable Agreement.

Under certain circumstances, we could become obligated to make significant payments under our Tax Receivable Agreement that could exceed or represent a substantial portion of our liquidity and market capitalization. These payment obligations could be to persons without significant equity ownership in us at the time such obligation arises. If we elect to terminate the Tax Receivable Agreement early or it is terminated early due to certain mergers or other changes of control, we would be required to make an immediate payment equal to the present value of the anticipated future tax benefits subject to the Tax Receivable Agreement. Such calculation of anticipated future tax benefits will be based upon certain assumptions and deemed events set forth in the Tax Receivable Agreement, including the assumptions that (i) we have sufficient taxable income to fully utilize such benefits, (ii) any JEH Units that the Class B shareholders or their permitted transferees own on the termination date are exchanged for shares of our Class A common stock on the termination date and (iii) the amount of future depletion deductions to which we are entitled is based on recoverable reserves and rates of recovery reflected in the most recent reserve reports and estimates available on the termination date. Any early termination payment may be made significantly in advance of the actual realization, if any, of such future benefits.

In these situations, our obligations under the Tax Receivable Agreement could have a substantial negative impact on our liquidity and could have the effect of delaying, deferring or preventing certain mergers, asset sales, other forms of business combinations or other changes of control due to the additional transaction cost a potential acquirer may attribute to satisfying such obligations. For example, if the Tax Receivable Agreement had been terminated at December 31, 2017, we estimate that the termination payment would be approximately $58.4 million (calculated based on the 21%

44


 

U.S. federal corporate income tax rate under the recently enacted Tax Cuts and Jobs Act, and applicable state and local income tax rates and using a discount rate equal to LIBOR, plus 100 basis points, applied against the anticipated undiscounted liability and assuming a market value of our Class A common stock equal to $1.10 per share, the closing price on December 29, 2017). The foregoing is merely an estimate and the actual payment could differ materially. There can be no assurance that we will be able to finance our obligations under the Tax Receivable Agreement.

Payments under the Tax Receivable Agreement will be based on the tax reporting positions that we will determine. The holders of rights under the Tax Receivable Agreement will not reimburse us for any payments previously made under the Tax Receivable Agreement if such basis increases or other benefits are subsequently disallowed, except that excess payments made to any Class B shareholder will be netted against payments otherwise to be made, if any, to such Class B shareholder after our determination of such excess. As a result, in such circumstances, we could make payments that are greater than our actual cash tax savings, if any, and may not be able to recoup those payments, which could adversely affect our liquidity.

 

For as long as we are an emerging growth company, we will not be required to comply with certain requirements that apply to other public companies.

 

We continue to qualify as an “emerging growth company” under the Jumpstart Our Business Startups Act, or the JOBS Act. As a result, we may take advantage of certain exemptions from various reporting requirements that are applicable to other public companies that are not emerging growth companies, including not being required to provide an auditor’s attestation report on management’s assessment of the effectiveness of our system of internal control over financial reporting pursuant to Section 404 and reduced disclosure obligations regarding executive compensation in our periodic reports. We will remain an emerging growth company for up to five years from our initial public offering, although we will lose that status sooner if we have more than $1.0 billion of revenues in a fiscal year, have more than $700 million in market value of our Class A common stock held by non-affiliates, or issue more than $1.0 billion of non-convertible debt over a three year period.

 

To the extent that we rely on any of the exemptions available to emerging growth companies, you will receive less information about our executive compensation and internal control over financial reporting than issuers that are not emerging growth companies.

 

We are subject to cyber security risks. A cyber incident could occur and result in information theft, data corruption, operational disruption or financial loss.

 

The oil and gas industry has become increasingly dependent on digital technologies to conduct certain exploration, development, production, processing and distribution activities. For example, we depend on digital technologies to interpret seismic data, manage drilling rigs, production equipment and gathering and transportation systems, conduct reservoir modeling and reserves estimation and process and record financial and operating data. As an oil and natural gas producer, we face various security threats, including cyber security threats. Cyber security attacks in particular are increasing and include, but are not limited to, malicious software, attempts to gain unauthorized access to data, and other electronic security breaches that could lead to disruptions in critical systems, unauthorized release of confidential or otherwise protected information and corruption of data. Although to date we have not experienced any material losses related to cyber security attacks, we may suffer such losses in the future. Moreover, the various procedures and controls we use to monitor and protect against these threats and to mitigate our exposure to such threats may not be sufficient in preventing security threats from materializing. If any of these events were to materialize, they could lead to losses of sensitive information, critical infrastructure, personnel or capabilities essential to our operations and could have a material adverse effect on our reputation, financial position, results of operations or cash flows.

 

Loss of our information and computer systems could adversely affect our business.

 

We are heavily dependent on our information systems and computer based programs, including our well operations information, seismic data, electronic data processing and accounting data. If any of such programs or systems were to fail or create erroneous information in our hardware or software network infrastructure, possible consequences include our loss of communication links, inability to find, produce, process and sell oil, natural gas and NGLs and inability to automatically process commercial transactions or engage in similar automated or computerized business activities. Any such consequence could have a material adverse effect on our business.

 

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We were recently out of compliance with the NYSE’s minimum share price requirement and, if we cease to be compliant in the future, we are at risk of the NYSE delisting our Class A common stock, which would have a material adverse effect on our business, financial condition, prospects and liquidity and value of our common stock.

 

Our Class A common stock is currently listed on the NYSE, and the continued listing of our Class A common stock is subject to our compliance with a number of listing standards. On December 26, 2017, we were notified by the NYSE that we were no longer in compliance with the continued listing standards because the average closing price of our Class A common stock had fallen below $1.00 per share over a period of 30 consecutive trading days. While we were notified by the NYSE on February 1, 2018 that we had fully regained compliance with the NYSE’s continued listing standards because the price of the our Class A common stock was above $1.00 per share on the last trading day of January and was on average over $1.00 for the 30 trading days preceding January 31, 2018, if we are unable to maintain compliance the NYSE may initiate procedures to suspend and delist the Class A common stock.

 

If our Class A common stock ultimately were to be delisted for any reason, it could negatively impact us by (i) reducing the liquidity and market price of our Class A common stock; (ii) reducing the number of investors willing to hold or acquire our Class A common stock, which could negatively impact our ability to raise equity financing; (iii) limiting our ability to use a registration statement to offer and sell freely tradeable securities, thereby preventing us from accessing the public capital markets; and (iv) impairing our ability to provide equity incentives to our employees.

 

Item 1B.  Unresolved Staff Comments

None.

 

Item 2.  Properties

The information required by Item 2. is contained in Item 1. Business.

 

Item 3.  Legal Proceedings

We are from time to time subject to, and are presently involved in, litigation or other legal proceedings arising out of the ordinary course of business. None of these legal proceedings are expected to have a material adverse effect on our financial condition, results of operations or cash flow. With respect to these proceedings, our management believes that we will either prevail, have adequate insurance coverage or have established appropriate reserves to cover potential liabilities. Any costs that management estimates may be paid related to these proceedings or claims are accrued when the liability is considered probable and the amount can be reasonably estimated. There can be no assurance, however, as to the ultimate outcome of any of these matters, and if all or substantially all of these legal proceedings were to be determined adversely to us, there could be a material adverse effect on our financial condition, results of operations and cash flow.

 

See Note 15, “Commitments and Contingencies—Litigation,” in the Notes to Consolidated Financial Statements for further discussion.

 

Item 4.  Mine Safety Disclosures

Not applicable.

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Part II

Item 5.  Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

Our Class A common stock is listed on the New York Stock Exchange (“NYSE”) under the symbol “JONE.”

The following table sets forth the range of high and low sales prices of our common stock as reported by the NYSE for the periods indicated.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

2017

 

2016

 

 

    

High

    

Low

    

High

    

Low

 

1st Quarter

 

$

5.20

 

$

2.20

 

$

4.01

 

$

1.16

 

2nd Quarter

 

$

2.70

 

$

1.40

 

$

5.30

 

$

2.84

 

3rd Quarter

 

$

2.21

 

$

0.85

 

$

4.49

 

$

2.55

 

4th Quarter

 

$

1.90

 

$

0.73

 

$

5.34

 

$

3.35

 

 

On February 21, 2018, the last sale price of our Class A common stock, as reported on the NYSE, was $0.92 per share. As of February 21, 2018, there were 92,030,282 shares of Class A common stock outstanding held by approximately nineteen stockholders of record and 9,627,821 shares of Class B common stock outstanding held by approximately three stockholders of record.

On December 26, 2017, we were notified by the NYSE that we were no longer in compliance with the continued listing standards because the average closing price of our Class A common stock had fallen below $1.00 per share over a period of 30 consecuti