UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10‑K

Commission file number: 001‑36006

Jones Energy, Inc.

(Exact name of registrant as specified in its charter)

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:

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” and “smaller reporting company” in Rule 12b‑2 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, 2016 (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 $126.4 million.

There were 57,193,106 and 29,832,098 shares of the registrant’s Class A and Class B common stock, respectively, outstanding on March 1, 2017.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the registrant’s definitive proxy statement for the 2017 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

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:

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.

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 owners of JEH prior to the Company’s initial public offering (“IPO”) 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 1.84 million shares of its 8.0% Series A Perpetual Convertible preferred stock, par value $0.001 per share (the “Series A preferred stock”), in a registered public offering.

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.

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 Texas and Oklahoma. Our Chairman and CEO, 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 1920’s. We have grown rapidly 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 and Arkoma basins, having concentrated our operations in the Anadarko basin for over 25 years and applied our knowledge to the Arkoma basin since 2011. We have drilled over 840 total wells as operator, including nearly 670 horizontal wells, since our formation and delivered compelling rates of return over various commodity price cycles. Our operations are focused on horizontal drilling and completions within three distinct areas in the Texas Panhandle and Oklahoma:

We seek to optimize returns through a disciplined emphasis on controlling costs and promoting operational efficiencies, and we are recognized as one of the lowest-cost drilling and completion operators in the Cleveland and Arkoma Woodford shale formations. We believe that our low-cost drilling expertise will apply directly to our new drilling in the Merge area, which is located approximately 150 miles to the east of our Cleveland play.

The Anadarko and Arkoma basins are among the most prolific and largest onshore producing 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 and acquisition opportunities and to which we can apply our technical experience and operational excellence to increase proved reserves and production to deliver attractive economic rates of return. Our goal is to build value through a disciplined balance between developing our current inventory of 6,923 gross (1,659 net)

identified drilling locations, identifying new opportunities within our existing asset base, and actively pursuing organic leasing and acquisitions.

On August 18, 2016, we entered into a definitive purchase and sale agreement with SCOOP Energy Company, LLC to acquire oil and gas properties located in the Merge area of the STACK/SCOOP play in Central Oklahoma (the “Merge Acquisition”). The oil and gas properties acquired in the Merge Acquisition principally consist of approximately 18,000 undeveloped net acres in Canadian, Grady and McClain Counties, Oklahoma. We closed the Merge Acquisition on September 22, 2016. This acquisition represents a natural eastward expansion of our Anadarko platform. The position contatins multiple target zones providing significant stacked pay potential. We spud our first well in this new play on December 8, 2016.

As of December 31, 2016, our total estimated proved reserves were 105.2 MMBoe, of which 59% were classified as proved developed reserves. Approximately 22% of our total estimated proved reserves as of December 31, 2016 consisted of oil, 33% consisted of NGLs, and 45% consisted of natural gas. As of December 31, 2016, our properties included 1,170 gross producing wells. For the three years ended December 31, 2016, we drilled 234 wells as operator. The following table presents summary reserve, acreage and production data for each of our core operating areas:

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

Our 2016 capital expenditures totaled $268.8 million (excluding the impact of asset retirement costs), of which $72.2 million was utilized to drill and complete operated wells and $163.0 million was related to acquisition activity. The Company has established an initial capital budget of $275.0 million for 2017, including $232 million for drilling and completion, $25 million for leasing and $18 million for workovers and efficiency projects. 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 2017 budgeted capital expenditures with cash flow from operations and borrowings under our credit facility, as well as potential non-strategic asset sales or potentially accessing the public debt and/or equity markets. 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 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 2017 capital expenditure budget as follows:

Business Strategies

Our goal is to increase shareholder value by managing our capital expenditures and level of activity to maximize returns through commodity price cycles while also evaluating and executing opportunities for growth of reserves, production, and cash flow through potential partnerships, acquisitions, leasing and pooling opportunities. We seek to achieve this goal by executing a combination of the following strategies:

Maintain the Lowest Cost Structure in the Plays Where We Operate.

Decades of experience in the mid-continent United States and emphasis on operational execution and cost control have allowed us to drill and complete wells at significantly lower cost than most other operators and, as a result, to realize compelling economic returns. In the Cleveland, for example, from 2005 to 2015 we reduced our average well spud‑to‑rig release time, which directly affects drilling costs, from 30 days to 17 days, and in 2016 we further reduced that metric to an average of 15 days. During that same timeframe, we have more than doubled the lateral lengths of wells we drilled, which directly affects production, from approximately 2,000 feet to approximately 4,500 feet per well. We will continue to apply this expertise while also leveraging our leading position in our focus areas to obtain the best possible pricing from service providers which we expect will further reduce capital costs and ultimately enhance returns. Our cost structure is particularly important in periods of low commodity prices and may give us an advantage over other operators as we compete for acquisitions, leases, and strategic partnerships.

Develop Our Multi‑Year Inventory.

We intend to add production and reserves through the development of our existing drilling inventory, which we believe to be repeatable and low‑risk. The Company has a long history in the mid-continent United States, having drilled over 840 wells in the area since 1988. We believe our historical drilling experience, together with the results of substantial industry activity within our operating areas, reduces the risk and uncertainty associated with drilling horizontal wells in these areas. As of December 31, 2016, we had identified 6,923 gross (1,659 net) drilling locations, which gives us many years of development drilling based on our current development plan.

Opportunistically Grow Through Exploration, Acquisitions and Strategic Partnerships.

As a complement to our development program, we look to execute acquisitions, leases and partnerships where our operating experience can be leveraged. Given the Company’s ability to decrease costs and ramp up drilling activity, we seek opportunities that have less proved developed producing reserves and a large number of high‑quality drilling

locations. Since 2009, we have successfully executed five significant property acquisitions and several bolt‑on acquisitions in our operating areas, for an aggregate purchase price of approximately $1.0 billion. The Merge Acquisition, which closed in September 2016, is an example of this strategy with the acreage being an Eastern extension of our Anadarko footprint.

We also continue to seek new leasing opportunities to expand our acreage position and complement our existing drilling inventory, as we believe that targeted organic leasing around our existing acreage provides the ability for greater returns due to cost and operating synergies in overlapping areas of operation.

In calendar year 2016, we leased and/or acquired over 53,000 net acres.

Joint development opportunities complement our acquisition strategy by providing a capital efficient and risk‑lowering approach to acquiring drilling opportunities. These agreements give us control over the drilling and completion phase of the well, where we can add value by applying our low-cost structure. In this regard, we have a history of developed relationships with several large exploration and production companies such as BP, ConocoPhillips, and ExxonMobil, in which they have farmed out portions of their basin operations to us. We have drilled nearly 330 wells in connection with these types of agreements, of which approximately 200 have been drilled in connection with an active 16‑year farm‑out and development agreement with ExxonMobil.

Exploit Upside Within Our Existing Assets.

The stacked reservoirs within our asset base provide exposure to additional upside potential in several emerging resource plays. We expect to engage in additional development activity throughout the Anadarko basin as commodity prices continue to improve. Based upon our recent assessment, we believe that we have approximately 752 gross potential drilling locations in the Tonkawa and Marmaton formations that provide us with additional resource potential. Further, our current leasehold position provides longer term potential exposure to other prospective formations found in the Anadarko basin, including the Douglas, Cottage Grove, Cherokee Shale, Atoka Shale, and the Upper, Middle and Lower Morrow formations. In our newly acquired Merge acreage, we have additional upside potential beyond the Merge Woodford and Sycamore, including the Hunton, Osage, Chester, Caney, and Spinger formations, along with numerous prospective Pennsylvanian-age sandstone and carbonate reservoirs identified from logs and offset production. In addition, we continue to apply our proven geoscience expertise in the search for new exploration opportunities in the greater mid-continent United States region.

Maintain Operational Control.

We operated substantially all of the wells that we drilled and completed during 2016, allowing us to effectively manage the timing and levels of our development spending, overall well costs and operating expenses. With over 76% of our total acreage held by existing production, and, over 83% of our acreage held by existing production exluding our newly acquired Merge acreage, we also will not be required to expend significant capital to hold acreage in our portfolio. We believe that continuing to exercise a high degree of control over our acreage position will provide us with flexibility to manage our drilling program and optimize our returns and profitability.

Focus on Well‑Level Returns.

Our management and technical teams are focused on maximizing well‑level returns, which we believe drives shareholder value. In addition to our focus on costs and optimizing drilling and completion techniques, our team maximizes returns by allocating capital to areas with the highest rates of return based on commodity mix. Our drilling inventory comprises oil, natural gas and NGLs, which enables us to adjust our development approach based on prevailing commodity prices. In light of current commodity prices, we will continue to focus our drilling activity on locations which present the best commodity mix coupled with the most operational efficiency from a development program standpoint. In addition, we expect that continuing to operate the substantial majority of our drilling locations will allow us to reallocate our capital and resources opportunistically in response to market conditions. Our disciplined focus on well‑level returns in allocating our capital and resources has been a key component of our ability to deliver successful results through various commodity price cycles.

Competitive Strengths

We possess a number of competitive strengths that we believe will allow us to successfully execute our business strategy:

Geographic Focus in the Prolific Mid-Continent United States.

Our operations are focused in the mid-continent United States region, targeting liquids‑ rich opportunities in the Anadarko and Arkoma basins of Texas and Oklahoma. We generally focus on formations characterized by oil and liquids‑rich natural gas content, extensive production histories, long‑lived reserves, high drilling success rates, and attractive initial production rates. Furthermore, our areas of operation are proximate to well‑developed natural gas and liquids midstream infrastructure and oilfield services providers, which we believe reduces the risk of production delays and facilitates adequate takeaway capacity.

Multi‑Year Drilling Inventory in Existing and Emerging Resource Plays.

Our drilling inventory consists of approximately 6,923 gross identified drilling locations in the Anadarko and Arkoma basins, and our development plans target locations that we believe are low‑cost, provide attractive economics, present low risk, and support a relatively predictable production profile. As of December 31, 2016, we had identified 1,903 gross drilling locations in the Western Anadarko basin, 4,746 gross drilling locations in the Eastern Anadarko basin, and 274 gross drilling locations in the Arkoma basin. Our concentrated leasehold position has been delineated largely through drilling on our Cleveland leasehold, which we expanded substantially through our Chalker and Sabine acquisitions and more recently through our leasing efforts. We have also expanded, in prior years, through joint development agreements with large independent producers and major oil and gas companies in the Cleveland and Arkoma Woodford formations.

Extensive Operational Expertise and Low‑Cost Operating Structure.

Drilling horizontal wells has been our primary approach to field development since 1998. Having drilled nearly 670 horizontal wells in nine formations in our areas of operation since 1996, we have established systematic protocols that we believe provide repeatable results. We also have established relationships with oilfield services providers, allowing for continued cost efficiencies. As an example, we have consistently drilled horizontal Cleveland wells at a meaningfully lower cost than most of our competition in the same area. Through our focus on drilling, completion and operational efficiencies, we are able to effectively control costs and deliver attractive rates of return and profitability.

Strong Financial Position and Conservative Policies.

We are committed to maintaining a conservative financial profile in order to preserve operational flexibility and financial stability. We believe that our operating cash flow, together with projected availability under our senior secured revolving credit facility, provide us with the financial flexibility to pursue acquisitions, joint development agreements and organic leasing opportunities. In addition, we have historically hedged a significant amount of our production from oil, gas and NGLs. For the three years ended December 31, 2016, approximately 81% of our total production was protected by commodity hedges. Our hedge position is reviewed frequently to evaluate the impact of new wells coming online and changes to our development program. We intend to continue to actively hedge our future production in order to reduce the impact of commodity price volatility on our cash flows and secure our rates of return for up to five years. As of December 31, 2016, the market value of our existing hedges was approximately $43.0 million.

High Caliber Management Team with Deep Operating Experience and a Proven Track Record.

Our top five executives average more than 29 years of industry experience and have worked together developing assets for many years, resulting in a high degree of continuity. We have assembled a strong technical staff of geoscientists, field operations managers and engineers with significant experience drilling horizontal wells and with fracture stimulation of unconventional formations, which has resulted in a successful track record of reserve and production growth. In addition, our management team has extensive expertise and operational experience in the oil and natural gas industry with a proven track record of successfully negotiating, executing and integrating acquisitions. Members of our management team and staff have previously held positions with both major and large independent oil and natural gas companies, including ExxonMobil, BP, Shell, Southwestern Energy, Marathon Oil, Chesapeake Energy, Apache, EOG Resources, Chevron, Devon Energy, and Conoco Phillips.

Alignment of Management Team.

Our predecessor company was founded in 1988 by our CEO, Jonny Jones, in continuation of his family’s history in the oil and gas business, which dates back to the 1920’s. Jones family members and our management team controlled approximately 15.5% of our combined voting power and economic interest as of December 31, 2016. We believe the

equity interests of our officers and directors align their interests and provide substantial incentive to grow the value of our business.

Recent Developments

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

Our Operations

Our Areas 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 and Arkoma basins in Texas and Oklahoma. 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.”

Anadarko Basin

Approximately 86% of our estimated proved reserves as of December 31, 2016 and approximately 83% of our average daily net production for the year ended December 31, 2016 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 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 46 gross (41 net) wells as operator in the Anadarko basin during 2016. Our operations in the Anadarko basin have been primarily focused on the Cleveland formation where we have 669 producing wells. We also have acreage in the Tonkawa, Marmaton, Granite Wash, and various Pennsylvanian‑age shale formations located in the eastern portion of the Texas Panhandle and western Oklahoma.

Our production in the Anadarko basin is currently derived primarily from the following formations, where we have 782 gross (502 net) producing wells and where we have identified 6,649 gross (1,618 net) drilling locations as of December 31, 2016, of which 429 have proved undeveloped reserves attributed to them as of December 31, 2016. See “Drilling Locations” for more information regarding the processes and criteria through which these drilling locations were identified.

Western Anadarko Basin.    

As of December 31, 2016, we had 669 gross (474 net) producing wells in the formation with an average working interest of 71%, of which we operated 484 gross (403 net) producing wells. Our Cleveland properties contained 82.1 MMBoe of estimated net proved reserves as of December 31, 2016, 60% of which are oil and NGLs, and generated an average daily net production of 13.9 MBoe/d for the year ended December 31, 2016. We have identified 788 gross (540 net) drilling locations in the Cleveland formation as of December 31, 2016. Of these 788 locations, 310 locations (39%) have proved undeveloped reserves attributed to them as of December 31, 2016.

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, 2016, our Tonkawa properties contained 0.2 MMBoe of estimated net proved reserves.

As of December 31, 2016, we had 30 gross (18 net) producing wells in the formation with an average working interest of 59%, of which we operated 23 gross (17 net) producing wells. Our Granite Wash properties contained 2.4 MMBoe of estimated net proved reserves as of December 31, 2016, approximately 45% of which are oil and NGLs. We have 363 gross (22 net) remaining drilling locations in the Granite Wash formation as of December 31, 2016.

Eastern Anadarko Basin.    

Our Merge Woodford properties contained 1.1 MMBoe of estimated net proved reserves as of December 31, 2016, approximately 63% of which are oil and NGLs. We have identified 3,363 gross (407 net) drilling locations in the Merge Woodford formation as of December 31, 2016. Of these 3,363 locations, 51 locations (2%) have proved undeveloped reserves attributed to them as of December 31, 2016.

Our Sycamore properties contained 1.3 MMBoe of estimated net proved reserves as of December 31, 2016, approximately 63% of which are oil and NGLs. We have identified 1,383 gross (198 net) drilling locations

in the Sycamore formation as of December 31, 2016. Of these 1,383 locations, 18 locations (1%) have proved undeveloped reserves attributed to them as of December 31, 2016.

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 Basin

Approximately 14% of our estimated proved reserves as of December 31, 2016, and approximately 17% of our average daily net production for the year ended December 2016, were located in the Arkoma basin. The Arkoma basin is a historically prolific, largely gas‑prone basin extending from eastern Oklahoma into western Arkansas. The basin produces natural gas, oil and NGLs from multiple horizons, which range in depth from 500 to 21,000 feet.

As of December 31, 2016, we operated approximately 42% of our properties in the Arkoma basin and produce primarily from the Arkoma Woodford formation.

As of December 31, 2016, we have 152 gross (60 net) producing wells in the formation with an average working interest of 39%, of which we operated 78 gross (45 net) producing wells. Our Arkoma Woodford shale formation properties contained 14.2 MMBoe of estimated net proved reserves as of December 31, 2016, 33% of which are oil and NGLs, and generated an average daily net production of 3.0 MBoe/d for the year ended December 31, 2016. We identified 274 gross (41 net) drilling locations in the Arkoma Woodford shale formation as of December 31, 2016, of which 20% had proved undeveloped reserves attributed to them.

Drilling Locations

We have identified a total of 6,923 gross (1,659 net) drilling locations, all of which are horizontal drilling locations. Of these total identified locations, 2,047 gross locations are attributable to acreage that is currently held by production and approximately 485 (7%) are attributable to proved undeveloped reserves as of December 31, 2016. 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 on 128‑acre spacing (5 wells per section). Wells drilled in the Merge Woodford formation adhere to 160‑acre spacing (4 wells per section). Wells drilled in the Sycamore formation are developed on 213‑acre spacing (3 wells per section). Wells drilled in the Arkoma Woodford shale formation adhere to 80‑acre and 120‑acre spacing, depending on the area. Wells drilled in the Granite Wash formation are developed on 128‑acre or 213‑acre spacing. Wells drilled in the Tonkawa and Marmaton formations adhere to 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 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, 2016, 2015 and 2014, 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.

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

Reserves Sensitivities

Assuming NYMEX strip pricing as of March 1, 2017 through 2021 and keeping pricing flat thereafter, instead of 2016 SEC pricing, and leaving all other parameters unchanged, the Company’s proved reserves would have been 113.2 MMBoe and the PV‑10 value of proved reserves would have been $682.0 million. This alternative pricing scenario is provided only to demonstrate the impact that the current pricing environment may have on reserves volumes and PV‑10. There is no assurance that these prices will actually be realized. The value of our proved reserves as of December 31, 2016 calculated using SEC pricing is lower than the value of our proved reserves calculated using current market prices. Using SEC pricing of December 31, 2016, our total estimated proved reserves were 105.2 MMBoe and the PV‑10 value of proved reserves was $401.4 million.

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 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 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, 2016, 2015 and 2014.

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 upper management, including our chief operating officer. 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.

Qualifications of Responsible Technical Persons

Internal engineer.  Eric Niccum, our Executive Vice President and Chief Operating Officer, is the technical specialist primarily responsible for overseeing the preparation of our reserves estimates. Mr. Niccum is also responsible for liaising with and oversight of our third‑party reserve engineer. Mr. Niccum is a graduate of Purdue University with a Bachelor of Science degree in Mechanical Engineering. He has 23 years of energy experience.

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, Senior Vice 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, 2016, none of our proved undeveloped reserves at December 31, 2016 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 projected availability under our senior secured revolving credit facility, 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 flows 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 and our expansion activities 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.”

We have maintained the volume of our proved undeveloped reserves year-over-year at 42.7 MMBoe as of December 31, 2015 and 2016. Reductions were due to (i) the conversion of 5.9 MMBoe of proved undeveloped reserves to proved developed reserves and (ii) net negative revisions of 5.3 MMBoe, primarily due to forecast revisions. These were offset

by increases due to (i) additions of 2.0 MMBoe from extensions and discoveries and (ii) additions of 9.2 MMBoe from the purchase of minerals in place. 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. Proved undeveloped reserves decreased as a percentage of total reserves from 48% for the year ended December 31, 2014 to 42% for the year ended December 31, 2015.

For the year ended December 31, 2016, we converted 5.9 MMBoe of proved undeveloped reserves to proved developed reserves or 14% of total proved undeveloped reserves booked at December 31, 2015. We incurred approximately $73.7 million in capital to convert undeveloped reserves to proved developed reserves during the year ended December 31, 2016. Our 2016 capital expenditures totaled $268.8 million excluding the impact of asset retirement costs, of which $72.2 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 $275.0 million for 2017, with the majority dedicated to drilling and completion activities. Costs of proved undeveloped reserve development in 2016 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 2016 year‑end proved undeveloped reserves is $401.4 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.

Drilling Activity

The following table sets forth information with respect to wells drilled and completed 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.

For the three years ended December 31, 2016, we had one gross (one net) developmental or exploratory well that was deemed to be a dry well. As of December 31, 2016, there were four development wells in the process of drilling and two wells in the process of completions. For the three years ended December 31, 2016, we drilled 234 gross (198 net) wells as operator with over a 97% success rate.

During the twelve months ended December 31, 2016, we successfully drilled 43 gross proved undeveloped wells and completed 32 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, 2016.

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, 2016 for each of our producing areas. Acreage related to royalty, overriding royalty and

other similar interests is excluded from this summary. As of December 31, 2016, over 76% of our leasehold acreage was held by existing production.

Undeveloped Acreage Expirations

The following table sets forth the number of gross and net undeveloped acres as of December 31, 2016 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.

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, 2016 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 recovered and stabilized. 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.

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 61% for our operated leases and 40% including all operated and non‑operated leases.

Over 76% of our leases (based on net acreage) are held by 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, 2016, the largest purchasers of our production were Plains Marketing LP (“Plains Marketing”) and ETC Field Services LLC, which accounted for approximately 37% and 24% 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.

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:

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. On May 4, 2016, environmental groups filed a declaratory judgment action in federal district court for the District of Columbia seeking to compel the EPA to review the exemption of oil and gas exploration and production wastes under RCRA in formal rulemaking; the case to compel a rulemaking schedule remains pending. 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.

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. In the event 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 wastes, 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. The rule has been challenged and was stayed by federal courts. The agencies released a notice on February 28, 2017 that they intend to revisit and potentially repeal and replace this rule, and will give consideration to a narrowing of federal jurisdiction as directed in an Executive Order released that same day. 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, which could make it easier for third parties opposing hydraulic fracturing to initiate legal proceedings based on allegations that specific chemicals used in the process could adversely affect ground water. 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 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 has commenced 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. If the pending or similar legislation is enacted or other new requirements or restrictions regarding hydraulic fracturing are adopted as a result of these studies, we could incur substantial 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, a federal district court invalidated these BLM rules in June 2016 and an appeal is pending. BLM also adopted new rules on November 15, 2016, to be effective on January 17, 2017, to reduce venting, flaring, and leaks during oil and natural gas production activities on onshore federal and Indian leases. On November 4, 2016 and 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. The Interagency Working Group on Unconventional Natural Gas and Oil created by Executive Order on April 13, 2012 is charged with coordinating and aligning federal agency research and scientific studies on unconventional natural gas and oil resources.

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, the Railroad Commission of Texas, implementing a state law passed in June 2011, adopted the Hydraulic Fracturing Chemical Disclosure Rule on December 13, 2011. 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 Texas and Oklahoma, 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 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. 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 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 that took effect on October 15, 2012, 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, new 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. The 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.

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 can attach 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.

We conduct operations in areas where certain species that are listed as threatened or endangered under the ESA may be present. For example, our operations in the Arkoma basin of Oklahoma overlap with the range of the American Burying Beetle, which is listed as endangered. The presence of endangered or threatened species may force us to modify or terminate our operations in certain areas. Additionally, 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 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 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 has 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, which began in 2015, remains ongoing and is not expected to be completed until at least the summer of 2017.

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 (CCAA) component that provides “take” coverage for properties enrolled into the CCAA before the listing was effective. To mitigate the risk of liability from “incidental takes” of the Lesser Prairie Chicken, prior to delisting, we enrolled affected leasehold interests in the CCAA.

EPA issues remain dynamic. For example, 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 will be evaluated by the new 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 actively considered legislation to reduce emissions of GHGs, but no legislation has yet passed. 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. 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. The rule requires reporting of GHG emissions by regulated entities to the EPA on an annual basis. Reporting was first required 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.

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, on October 23, 2015, the EPA published the final Clean Power Plan rule. While the rule directly applies to power plants, the Clean Power Plan is targeted at creating a shift from fossil fuels toward renewable power generation; however, the rule has been stayed, is not effective during the judicial review, and is likely to be revisited by the new administration. Also, 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. With the change in administration, the United States’ continued participation in the Paris Agreement is uncertain. 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, municipal plaintiffs in Kivalina v. ExxonMobil Corporation, et al, alleged that the defendant corporations’ contributions to global warming caused property damage associated with rising sea levels. Although the plaintiffs in Kivalina were ultimately unsuccessful, there is a continuing litigation risk associated with greenhouse gas‑emitting activities.

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 (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. It is likely that the regulatory focus is shifting in the new 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, 2016, 2015 or 2014. Additionally, we are not aware of any environmental issues or claims that will require material capital expenditures during 2017 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.

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 5,500 square feet of office space in Oklahoma City, Oklahoma. Additionally, we lease field offices in Canadian, Texas and McAlester, Oklahoma.

Employees

As of December 31, 2016, we had 90 employees, including 26 technical (geosciences, engineering, land), 34 field operations, 25 corporate (finance, accounting, business development, IT, human resources, office management) and 5 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 may 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 six 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. The NYMEX Henry Hub spot market price of gas has ranged from $7.51 per MMBtu in January 2010 to a high of $8.15 per MMBtu in February 2014 and a low of $1.49 in March 2016. 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:

NGLs are made up of ethane, propane, isobutane, butane and natural gasoline, all of which have different uses and different pricing characteristics. NGLs comprised 32% of our 2016 production, and we realized an average price of $13.48 per barrel, a 0.9% increase from the average realized price of our 2015 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. If oil, natural gas and NGL prices continue to deteriorate or remain at depressed levels, we anticipate that the borrowing base under our senior secured revolving credit facility, which is revised periodically, will be reduced at some point, which would negatively impact our borrowing ability. Additionally, prices could reduce our cash flows to a level that would require us to borrow to fund our capital budget. Lower oil, natural gas and NGL prices may also reduce the amount of oil, natural gas and NGLs that we can 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. In addition, our cost of drilling, completing and operating 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:

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:

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

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 total capital expenditures for 2016 were $268.8 million excluding the impact of asset retirement costs. The Company has established an initial capital budget of $275.0 million for 2017. 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 our senior secured revolving credit facility, 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, borrowings under our senior secured revolving credit facility 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:

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. Our senior secured revolving credit facility and the indentures governing our senior notes due 2022 (the “2022 Notes”) and senior notes due 2023 (the “2023 Notes”) may 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 our senior secured revolving credit facility 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.

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.

Approximately 41% of our total estimated proved reserves were classified as proved undeveloped as of December 31, 2016. Development of these reserves may take longer and require higher levels of capital expenditures than we currently anticipate. In addition, continued 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.

Our hedging strategy may be ineffective in reducing the impact of commodity price volatility from our cash flows, 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 enter 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. In addition, our senior secured revolving credit facility limits the aggregate notional volume of commodities that can be covered under commodity derivative contracts we can enter into and, as a result, we will continue to have direct commodity price exposure on the unhedged portion of our production volumes. For the years ending December 31, 2017, 2018, and 2019, approximately 36%, 66%, and 80%, respectively, of our estimated total oil, natural gas and NGL production from proved reserves, based on our reserve report as of December 31, 2016, 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.

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 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.

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. 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. 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 initial capital budget for 2017 is $275.0 million.

Continued low commodity prices or future 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 remain low 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, 2016. 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 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.

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.

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:

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, 2016 excluding hedging impacts would decrease approximately $140.6 million holding all costs constant. If natural gas prices decline by $1.00 per Mcf, then our standardized measure as of December 31, 2016 excluding hedging impacts would decrease by approximately $91.6 million holding all costs constant.

Over 99% of our estimated proved reserves are located in the Anadarko and Arkoma basins in the Texas Panhandle and Oklahoma, making us vulnerable to risks associated with operating in one geographic area.

Over 99% of our estimated proved reserves as of December 31, 2016 were located in the Anadarko and Arkoma basins in the Texas Panhandle and Oklahoma. Approximately 72% of our 2016 production was from the Cleveland formation where properties are located in four contiguous counties of Texas and Oklahoma. As a result of this concentration, we may be disproportionately exposed to the impact of regional supply and demand factors, delays or interruptions of production from wells in this area caused by governmental regulation, processing or transportation capacity constraints, availability of equipment, facilities, personnel or services market limitations or interruption of the processing or transportation of oil, natural gas or NGLs. In addition, the effect of fluctuations on supply and demand may become more pronounced within specific geographic oil and natural gas producing areas such as our properties producing from the Cleveland formation, which may cause these conditions to occur with greater frequency or magnify the effects of these conditions. Due to the concentrated nature of our portfolio of properties, a number of our properties could experience any of the same conditions at the same time, resulting in a relatively greater impact on our results of operations than they might have on other companies that have a more diversified portfolio of properties. Such delays or interruptions 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, 2016 purchases by our top five customers accounted for approximately 37%, 24%, 7%, 7% and 7%, 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. Even if we do identify attractive acquisition opportunities, we may not be able to complete the acquisition or do so on commercially acceptable terms. 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.

In addition, our senior secured revolving credit facility impose certain limitations on our ability to enter into mergers or combination transactions. Our senior secured revolving credit facility also limits our ability to incur certain indebtedness, which could indirectly limit our ability to engage in acquisitions of businesses.

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

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 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.

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 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 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 greater 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 has been strong in hiring experienced personnel, particularly in the engineering and technical, accounting and financial reporting, tax and land departments. In addition, competition is strong for attractive oil and natural gas producing properties, oil and natural gas companies, and undeveloped leases and drilling rights. 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 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 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:

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

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.