UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10‑K

(Mark One)

For the transition period from            to

Commission file number: 1‑35372

Sanchez Energy Corporation

(Exact name of Registrant as specified in its charter)

Registrant’s telephone number, including area code (713) 783‑8000

Securities Registered Pursuant to Section 12(b) of the Act:

Securities Registered Pursuant to Section 12(g) of the Act: None

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

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

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

Indicate by check mark whether the Registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the Registrant was required to submit 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 Act). Yes ☐  No ☒

Aggregate market value of the voting and non‑voting common equity held by non‑affiliates of Registrant as of June 30, 2016: $392,858,811

Number of shares of Registrant’s common stock outstanding as of February 24, 2017: 78,648,272.

Documents Incorporated By Reference:

Portions of the Registrant’s definitive proxy statement for its 2017 Annual Meeting of Stockholders or an amendment to this Form 10-K, which will be filed with the Securities and Exchange Commission within 120 days of December 31, 2016, are incorporated by reference into Part III of this report for the year ended December 31, 2016.

SANCHEZ ENERGY CORPORATION

FORM 10‑K

FOR THE YEAR ENDED DECEMBER 31, 2016

Table of Contents

CAUTIONARY NOTE REGARDING FORWARD‑LOOKING STATEMENTS

This Annual Report on Form 10‑K contains “forward‑looking statements” within the meaning of the safe harbor provisions of the Private Securities Litigation Reform Act of 1995. All statements, other than statements of historical facts, included in this Annual Report on Form 10‑K that address activities, events, conditions or developments that we expect, believe or anticipate will or may occur in the future are forward‑looking statements. These statements are based on certain assumptions we made based on management’s experience, perception of historical trends and technical analyses, current conditions, anticipated future developments and other factors believed to be appropriate and reasonable by management. When used in this Annual Report on Form 10‑K, words such as “will,” “potential,” “believe,” “estimate,” “intend,” “expect,” “may,” “should,” “anticipate,” “could,” “plan,” “predict,” “project,” “profile,” “model,” “strategy,” “future” or their negatives or the statements that include these words or other words that convey the uncertainty of future events or outcomes, are intended to identify forward‑looking statements, although not all forward‑looking statements contain such identifying words. In particular, statements, express or implied, concerning our future operating results and returns, our strategy and plans or view of the market, or our ability to replace or increase reserves, increase production, or generate income or cash flows are forward‑looking statements. Forward‑looking statements are not guarantees of performance. Such statements are subject to a number of assumptions, risks and uncertainties, many of which are beyond our control. Although we believe that the expectations reflected in our forward‑looking statements are reasonable and are based on reasonable assumptions, no assurance can be given that these assumptions are accurate or that any of these expectations will be achieved (in full or at all) or will prove to have been correct. Important factors that could cause our actual results to differ materially from the expectations reflected in the forward‑looking statements include, among others:

In light of these risks, uncertainties and assumptions, the events anticipated by our forward‑looking statements may not occur, and, if any of such events do, we may not have correctly anticipated the timing of their occurrence or the extent of their impact on our actual results. Accordingly, you should not place any undue reliance on any of our forward‑looking statements. Any forward‑looking statement speaks only as of the date on which such statement is made, and we undertake no obligation to correct or update any forward‑looking statement, whether as a result of new information, future events or otherwise, except as required by applicable law. These cautionary statements qualify all forward-looking statements attributable to us or persons acting on our behalf.

PART I

Item 1.  Business

Overview

Sanchez Energy Corporation (together with our consolidated subsidiaries, “Sanchez Energy,” the “Company,” “we,” “our,” “us” or similar terms), a Delaware corporation formed in August 2011, is an independent exploration and production company focused on the acquisition and development of U.S. onshore unconventional oil and natural gas resources, with a current focus on the horizontal development of significant resource potential from the Eagle Ford Shale in South Texas. We also hold an undeveloped acreage position in the Tuscaloosa Marine Shale (“TMS”) in Mississippi and Louisiana, which offers future upside opportunity. As of December 31, 2016, we have assembled approximately 278,000 net leasehold acres with an approximate 94% average working interest in the Eagle Ford Shale. For the year 2017, we plan to invest substantially all of our capital budget in the Eagle Ford Shale. We continue to evaluate opportunities to increase both our acreage and our producing assets through acquisitions. Our successful acquisition of such assets will depend on both the opportunities and the financing alternatives available to us at the time we consider such opportunities. We have included definitions of some of the oil and natural gas terms used in this Annual Report on Form 10‑K in the “Glossary of Selected Oil and Natural Gas Terms.”

Listed below is a table of our significant consummated transactions since January 1, 2014:

* On December 14, 2016, we completed the initial closing of the Cotulla Disposition for cash consideration of approximately $153.5 million. Subsequently, a second closing on an additional portion of the assets was completed for cash consideration of approximately $7.1 million, and the Cotulla Disposition remains subject to post-closing adjustments and potential future closings.

On December 14, 2016, the Company completed the initial closing of the Cotulla Disposition (as defined in “Item 8. Financial Statements and Supplementary Data — Note 3, Acquisitions and Divestitures”) for cash consideration of approximately $153.5 million. Subsequent to December 31, 2016, a second closing on an additional portion of the Cotulla Assets was completed for cash consideration of approximately $7.1 million, and the Cotulla Disposition remains subject to post-closing adjustments and potential future closings. The assets sold included (based on the Company’s internal estimates) estimated net proved reserves, as of the effective date of June 1, 2016, of approximately 6.9 MMBoe.  Proved developed reserves are estimated to account for approximately 90% of the total net proved reserves. As of the effective date of June 1, 2016, the Cotulla Assets consisted of approximately 15,000 net acres with 112 gross (93 net) wells producing approximately 3,000 Boe/d.

On November 22, 2016, the Company completed the disposition of its 50% equity interests in Carnero Processing, LLC (“Carnero Processing”) to SPP, a joint venture that is 50% owned by Targa Resources Corp. (NYSE: TRGP) (“Targa”).  The Company received aggregate cash consideration of approximately $55.5 million and SPP agreed to assume approximately $24.5 million of the Company’s remaining capital contribution commitments in connection

with the acquisition (the “Carnero Processing Disposition”). The purchase price was determined through arm’s length negotiations between the Company and SPP, including independent committees of both entities.

On November 22, 2016, the Company also completed the Production Asset Transaction (as defined in “Item 8. Financial Statements and Supplementary Data — Note 3, Acquisitions and Divestitures”) cash consideration of $25.6 million after $1.4 million in normal and customary closing adjustments. The purchase price was determined through arm’s length negotiations between the Company and SPP, including independent committees of both entities. The Production Asset Transaction included the disposition of working interests in 23 producing Eagle Ford wellbores located in Dimmit and Zavala counties in South Texas together with escalating working interests in an additional 11 producing wellbores located in the Palmetto Field in Gonzales County, Texas to SPP. The effective date of the Production Asset Transaction was July 1, 2016.

On July 5, 2016, the Company completed the disposition of its 50% equity interest in Carnero Gathering, LLC (“Carnero Gathering”) a joint venture that is 50% owned by Targa, to SPP for an initial payment of approximately $37.0 million and the assumption by SPP of the Company’s remaining capital commitments to Carnero Gathering, estimated at approximately $7.4 million as of that date (the “Carnero Gathering Disposition”). In addition, SPP is required to pay the Company an earnout based on natural gas received above a threshold volume and tariff at Carnero Gathering’s delivery points from the Company and other producers. Carnero Gathering owns a total of approximately 45 miles (10 miles of which remain under construction as of December 31, 2016) of high pressure natural gas gathering pipelines that currently connect SPP’s Western Catarina Midstream system to nearby pipelines in South Texas. The Carnero Gathering System is designed to directly connect to a cryogenic natural gas processing plant in South Texas that is expected to be operational in the spring of 2017. The Company’s 50% equity interest in this processing plant was conveyed to SPP in the Carnero Processing Disposition.

On October 14, 2015, the Company completed the Western Catarina Midstream Divestiture (as defined in “Item 8. Financial Statements and Supplementary Data — Note 3, Acquisitions and Divestitures”) for an adjusted purchase price of $345.8 million in cash. In connection with the closing of the Western Catarina Midstream Divestiture, the Company entered into a Firm Gathering and Processing Agreement (the “Gathering Agreement”) on October 14, 2015 for an initial term of 15 years under which production from approximately 35,000 acres in Dimmit County and Webb County, Texas will be dedicated for gathering by Catarina Midstream, LLC (“Catarina Midstream”). In addition, for the first five years of the Gathering Agreement, SN Catarina, LLC will be required to meet a minimum quarterly volume delivery commitment of 10,200 barrels per day of crude oil and condensate and 142,000 Mcf per day of natural gas, subject to certain adjustments. 

On March 31, 2015, we completed the Palmetto Disposition (as defined in “Item 8. Financial Statements and Supplementary Data —Note 3, Acquisitions and Divestitures”) for an adjusted purchase price of approximately $83.4 million. The effective date of the transaction was January 1, 2015. The aggregate average working interest percentage initially conveyed was 18.25% per wellbore and, upon January 1 of each subsequent year after the closing, the working interest of the purchaser, a wholly owned subsidiary of SPP, will automatically increase in incremental amounts according to the purchase agreement until January 1, 2019, at which point the purchaser will own a 47.5% working interest, and we will own a 2.5% working interest in each of the wellbores.

On June 30, 2014, we completed our acquisition of 106,000 net contiguous acres in Dimmit, LaSalle and Webb Counties, Texas (the “Catarina Acquisition”) in the Eagle Ford Shale with an effective date of January 1, 2014. All proved reserves in the Catarina area are covered under lease acreage that is held by production, which acreage amounted to approximately 29,000 acres. Under the lease we have a 100% working interest and 75% net revenue interest in the lease acreage over the Eagle Ford Shale formation from the top of the Austin Chalk formation to the base of the Buda Lime formation. The 77,000 acres of undeveloped acreage that were included in the Catarina Acquisition are subject to a continuous drilling obligation. Such drilling obligation requires us to drill (i) 50 wells in each annual period commencing on July 1, 2014 and (ii) at least one well in any consecutive 120‑day period in order to maintain rights to any future undeveloped acreage. Up to 30 wells drilled in excess of the minimum 50 wells in a given annual period can be carried over to satisfy part of the 50 well requirement in the subsequent annual period on a well for well basis. The lease also created a customary security interest in the production therefrom in order to secure royalty payments to the lessor and

other lease obligations. Our current capital budget and plans include drilling at least the minimum annual well requirement necessary to maintain access to such undeveloped acreage.

Our Business Strategies

Our primary business objective is to increase reserves, production and cash flows at an attractive return on invested capital. Our business strategy is currently focused on exploiting long‑life, unconventional oil, condensate, NGL and natural gas reserves from the Eagle Ford Shale as well as other projects that directly enhance the profitability of our oil and gas development activities. Key elements of our business strategy include:

Our Competitive Strengths

We believe the following competitive strengths will allow us to successfully execute our business strategies:

Core Properties

Eagle Ford Shale

We and our predecessor entities have a long history in the Eagle Ford Shale, where, as of December 31, 2016, we have assembled approximately 278,000 net leasehold acres with an approximate 94% average working interest and have over 3,300 gross (3,050 net) locations for potential future drilling. For the year 2017, we plan to invest substantially all of our capital budget in the Eagle Ford Shale.

In our Catarina area, we have approximately 106,000 net acres in Dimmit, LaSalle and Webb Counties, Texas with a 100% working interest. We anticipate drilling, completion and facilities costs on our acreage to be between $2.9 million and $3.3 million per well based on our current estimates and historical well costs. Current Estimated Ultimate Recovery (“EUR”) per well in Catarina is expected to range between 400 MBoe and 1,200 MBoe. We have identified between 1,300 and 1,650 gross and net locations for potential future drilling on our Catarina acreage. For the year 2017, we plan to spend $160 million to $170 million to spud 49 net wells and complete 53 net wells in our Catarina area.

In our Maverick area, we have approximately 100,000 net acres in Dimmit, Frio, LaSalle, Zavala, and McMullen Counties, Texas with an average working interest of approximately 96%. We believe that our Maverick acreage lies in the black oil window, where we anticipate drilling, completion and facilities costs on our acreage to be between $3.0 million and $4.0 million per well based on our current estimates and historical well costs. Current EUR per well in Maverick is expected to range between 300 MBoe and 400 MBoe. We have identified up to 1,100 gross (1,000 net) locations based on 75 acre well‑spacing for potential future drilling on our Maverick area. For the year 2017, we plan to spend $100 million to $110 million to spud 35 net wells and complete 35 net wells in our Maverick area.

In our Javelina area, we have approximately 39,500 net acres in LaSalle and Webb Counties, Texas with an average working interest of 100%. Our Javelina acreage encompasses proven Eagle Ford down-dip areas. We currently anticipate drilling, completion and facilities costs on our acreage to be between $6.0 million and $7.5 million per well based on our current estimates. We expect average EUR per well in Javelina to range between 1,500 MBoe and 2,500 MBoe. We have identified up to 265 gross (265 net) locations based on 120 acre well-spacing for potential future drilling on our Javelina area. For the year 2017, we do not plan to drill any wells in this area.

In our Palmetto area, we have approximately 8,000 net acres in Gonzales County, Texas with an average working interest of approximately 49%. We believe that our Palmetto acreage lies in the volatile oil window where we anticipate drilling, completion and facilities costs on our acreage to be between $5.5 and $6.0 million per well based on our current estimates and historical well costs. Current EUR per well in Palmetto is expected to range between 500 MBoe and 600 MBoe. We have identified up to 295 gross (143 net) locations based on 40 acre well‑spacing for potential future drilling in our Palmetto area. For the year 2017, we plan to spend $5 million to $10 million to spud 2 net wells and complete three net wells in our Palmetto area.

In our Marquis area, we have approximately 21,000 net acres, the majority of which are in southwest Fayette and northeast Lavaca Counties, Texas with a 100% working interest. We believe that our Marquis acreage lies in the volatile oil window, where we anticipate drilling, completion and facilities costs on our acreage to be between $4.0 million and $5.0 million per well based on our current estimates and historical well costs. Current EUR per well in Marquis is expected to range between 275 MBoe and 375 MBoe. We have identified up to 200 gross and net locations based on 60 acre well‑spacing for potential future drilling on our Marquis acreage. For the year 2017, we do not have any planned capital spending on drilling and completions in our Marquis area.

Tuscaloosa Marine Shale

In August 2013, we acquired approximately 40,000 net undeveloped acres in what we believe to be the core of the TMS for cash and shares of our common stock (the “TMS Transaction”). In connection with the TMS Transaction, we established an area of mutual interest (“AMI”) in the TMS with SR Acquisition I, LLC (“SR”), a subsidiary of our affiliate Sanchez Resources, LLC (“Sanchez Resources”), which included a carry on drilling costs for up to 6 gross (3 net) wells. As part of the TMS Transaction, we acquired all of the working interests in the AMI owned at closing from three sellers (two third parties and one related party of the Company, SR), resulting in our owning an undivided 50% working interest across the AMI through the TMS formation.

Total consideration for the transactions consisted of approximately $70 million in cash and the issuance of 342,760 common shares of the Company, valued at approximately $7.5 million. The total cash consideration provided to SR, an affiliate of the Company, was $14.4 million, before consideration of any well carries. The acquisitions were accounted for as the purchase of assets at cost at the acquisition date. We also committed, as a part of the total consideration, to carry SR for its 50% working interest in an initial 3 gross (1.5 net) TMS wells to be drilled within the AMI (the “Initial Well Carry”) with an option to drill an additional 6 gross (3 net) TMS wells (“Additional Wells”) within the AMI. In August 2015, after completing the Initial Well Carry, the Company signed an agreement with SR whereby the Company paid SR approximately $8 million in lieu of drilling the remaining two Additional Wells (the “Buyout Agreement”). The Buyout Agreement stipulates that SN has earned full rights to all acreage stated in the TMS Transaction and effectively terminates any future well carry commitments.

As of December 31, 2016, the AMI held rights to approximately 98,000 (64,000 net) acres, of which we owned approximately 45,600 net acres. The TMS development is currently challenged due to high well costs and depressed commodity prices. We believe that the TMS play has significant development potential and still has significant upside as changes in technology, commodity prices, and service prices occur. The average remaining lease term on the acreage is over 2 years, giving us ample time to allow other industry participants to further de‑risk the play.

Oil and Natural Gas Reserves and Production

Internal Controls

Our estimated reserves at December 31, 2016 were prepared by Ryder Scott Company, L.P. (“Ryder Scott”), our independent third-party reserve engineers pursuant to their report dated January 24, 2017, which is filed as an exhibit to this Annual Report on Form 10-K. We expect to continue to have our reserve estimates prepared semi‑annually by Ryder Scott. Our internal professional staff works closely with Ryder Scott to ensure the integrity, accuracy and timeliness of data that is furnished to them for their reserve estimation process. All of the reserve information maintained in our reserve engineering database is provided to the external engineers. In addition, we provide Ryder Scott other pertinent data, such as seismic information, 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. The estimated proved reserves attributable to the Comanche Assets (as defined in “Item 1A. Risk Factors—There can be no assurance that the Comanche Acquisition will be consummated in the anticipated timeframe, on the terms described herein, or at all.”) are as of June 30, 2016, are based on our internal evaluation and interpretation of reserve and other information provided to us in the course of our due diligence with respect to the Comanche Acquisition (as defined in “Item 1A. Risk Factors—There can be no assurance that the Comanche Acquisition will be consummated in the anticipated timeframe, on the terms described herein, or at all.”) and have not been independently verified or estimated.

Technology Used to Establish Reserves

Under the rules of the Securities and Exchange Commission (the “SEC”), 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, Ryder Scott employed technologies that have been demonstrated to yield results with consistency and repeatability. The technologies and economic data used in the estimation of our 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 completion using similar techniques.

Qualifications of Responsible Technical Persons

Internal SOG Engineers.  Daniel Furbee is the technical person primarily responsible for overseeing the preparation of our reserve estimates. Mr. Furbee has over a decade of industry experience with positions of increasing responsibility in engineering and evaluations with companies such as Baker Hughes and LINN Energy. He holds a Bachelor of Science Petroleum Engineering degree from Marietta College and a Masters of Business Administration from the University of Houston. Mr. Furbee is a Registered Professional Engineer in the State of Texas.

Independent Reserve Engineers.  Ryder Scott is an independent oil and natural gas consulting firm. No director, officer or key employee of Ryder Scott has any financial ownership in any member of the Sanchez Group or us. Ryder Scott’s compensation for the required investigations and preparation of its report is not contingent upon the results obtained and reported, and Ryder Scott has not performed other work for SOG or us that would affect its objectivity. The engineering information presented in Ryder Scott’s report was overseen by Michael F. Stell, P.E. Mr. Stell is an experienced reservoir engineer having been a practicing petroleum engineer since 1981. He has more than 24 years of experience in reserves evaluation with Ryder Scott. He has a Bachelor of Science degree in Chemical Engineering from Purdue University and Master of Science degree in Chemical Engineering from University of California - Berkeley. Mr. Stell is a Registered Professional Engineer in the State of Texas.

Estimated Proved Reserves

The following table presents the estimated net proved oil and natural gas reserves attributable to our properties and the standardized measure amounts associated with the estimated proved reserves attributable to our properties as of December 31, 2016, based on a reserve report prepared by Ryder Scott, our independent reserve engineers. The standardized measure amounts shown in the table are not intended to represent the current market value of our estimated oil and natural gas reserves.

(1)Our estimated net proved reserves and related standardized measure were determined using index prices for oil and natural gas, without giving effect to commodity derivative contracts, held constant throughout the life of our properties. The unweighted arithmetic average first‑day‑of‑the‑month prices for the prior twelve months were $42.75/Bbl for WTI Cushing oil, $19.97/Bbl for NGLs and $2.49/MMBtu for Henry Hub natural gas at December 31, 2016. These prices were adjusted by lease for quality, transportation fees, geographical differentials, marketing bonuses or deductions and other factors affecting the price realized at the wellhead. For the year ended December 31, 2016, the average realized prices for oil, NGLs and natural gas were $37.95 per Bbl, $13.72 per Bbl and $2.50 per Mcf, respectively. For a description of our commodity derivative contracts, please read “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Results of Operations—Operating Costs and Expenses—Commodity Derivative Transactions” and “Item 7. Management’s Discussion and

Analysis of Financial Condition and Results of Operations—Critical Accounting Policies and Estimates—Derivative Instruments.”

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

(3)  Standardized measure is calculated in accordance with Accounting Standards Codification (“ASC”), Topic 932, Extractive Activities—Oil and Gas. For further information regarding the calculation of the standardized measure, see “Supplementary Information on Oil and Natural Gas Exploration, Development and Production Activities (Unaudited)” included in “Item 8. Financial Statements and Supplementary Data.”

The data in the table above represents estimates only. Oil, NGLs and natural gas reserve engineering is inherently a subjective process of estimating underground accumulations of oil, NGLs and natural gas that cannot be measured exactly. The accuracy of any reserve estimate is a function of the quality of available data and engineering and geological interpretation and judgment. Accordingly, reserve estimates may vary from the quantities of oil, NGLs and natural gas that are ultimately recovered. For a discussion of risks associated with reserve estimates, please read “Item 1A. Risk Factors—Our estimated reserves and future production rates are based on many assumptions that may prove to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our estimated reserves.”

Future prices realized for production and costs may vary, perhaps significantly, from the prices and costs assumed for purposes of these estimates. The standardized measure amounts shown above should not be construed as the current market value of our estimated oil and natural gas reserves. The 10% discount factor used to calculate standardized measure, which is required by Financial Accounting Standard Board (“FASB”) pronouncements, is not necessarily the most appropriate discount rate. The present value, no matter what discount rate is used, is materially affected by assumptions as to timing of future production, which may prove to be inaccurate.

Development of Proved Undeveloped Reserves

None of our proved undeveloped reserves (“PUD”) at December 31, 2016 are scheduled to be developed on a date more than five years from the date the reserves were initially booked as proved undeveloped. Historically, our drilling and development programs were substantially funded from capital contributions, cash flow from operations and the issuance of debt and equity securities. Based on our current expectations of our cash flows and drilling and development programs, which includes drilling of proved undeveloped locations, we believe that we can fund the drilling of our current inventory of proved undeveloped locations and our expansions and extensions in the next five years from our cash on hand combined with cash flow from operations and utilization of available borrowing capacity under our credit facility.

At a pace of approximately 30 wells per rig per year, our current 293 PUD drilling locations will all be developed within the next five years by running an average gross rig count of two rigs. As of December 31, 2016, we were running two active rigs and have an approved annual budget that allows for approximately six rigs to be run through 2017. For a more detailed discussion of our liquidity position, please read “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources.”

As of December 31, 2016, we identified 293 gross (282 net) PUD drilling locations which we anticipate drilling within the next five years. The table below details the activity in our PUD locations from December 31, 2015 to December 31, 2016:

Excluding acquisitions, we expect to make capital expenditures related to drilling and completion of wells of approximately $265 million to $290 million during the year ended December 31, 2017. We plan to spend approximately 80% to 88% of these capital expenditures on development of PUDs in 2017. Technical revisions of PUD estimates are the result of changes in forecasted performance. There are net positive changes on our PUD forecast driven by better performance on our Catarina asset. As a result of price change, 131 PUD locations were removed. The total PUD volume impacted by price changes are 37.2 MMBoe as a result of locations that were removed from our Catarina, Cotulla, Marquis and Palmetto assets. 

For more information about our historical costs associated with the development of proved undeveloped reserves, please read “Supplementary Information on Oil and Natural Gas Exploration, Development and Production Activities (Unaudited)” included in “Item 8. Financial Statements and Supplementary Data.”

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 financial measure in accordance with accounting principles generally accepted in the United States of America (“U.S. GAAP”). PV‑10 is a computation of the Standardized Measure on a pre‑tax basis. PV‑10 is equal to the Standardized Measure at the applicable date, before deducting future income taxes, discounted at 10%. 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. Our PV‑10 measure and the Standardized Measure do not purport to present the fair value of our oil and natural gas reserves.

The following table provides a reconciliation of PV‑10 to the Standardized Measure at December 31, 2016 for our proved reserves (in millions):

(1)Standardized measure is calculated in accordance with ASC Topic 932, Extractive Activities—Oil and Gas. For further information regarding the calculation of the standardized measure, see “Supplementary Information on Oil and Natural Gas Exploration, Development and Production Activities (Unaudited)” included in “Item 8. Financial Statements and Supplementary Data.”

Production, Revenues and Price History

The following table sets forth information regarding combined net production of oil, NGLs, and natural gas and certain price and cost information attributable to our properties for each of the periods presented:

(1)Excludes the impact of derivative instruments.

(2)For the years ended December 31, 2016, 2015 and 2014, Adjusted general and administrative (“G&A”) expense excludes stock-based compensation expense of approximately $37.1 million ($1.90 per Boe), $14.8 million ($0.77 per Boe) and $12.8 million ($1.15 per Boe), respectively.

(3)For the years ended December 31, 2016, 2015 and 2014, Adjusted G&A expense excludes acquisition and divestiture costs included in G&A expense of $8.1 million ($0.42 per Boe), $3.8 million ($0.20 per Boe) and $1.8 million ($0.16 per Boe), respectively.

The table above in addition to other areas throughout this Annual Report on Form 10-K contains disclosures of G&A expenses excluding expenses related to stock-based compensation expense and certain costs related to acquisitions and divestitures, which is referred to as “Adjusted G&A.” Adjusted G&A is a “non-GAAP financial measure,” as defined in SEC rules. Please see “Item 6. Selected Financial Data -- Non-GAAP Financial Measures,” for a reconciliation of G&A and G&A per Boe to Adjusted G&A and Adjusted G&A per Boe, respectively. 

Drilling Activities

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. At December 31, 2016, 25 gross (22 net) wells were in various stages of completion.

(1)The Company encountered mechanical malfunctions during drilling and was unable to complete the well.

The following table sets forth information at December 31, 2016 relating to the productive wells in which we owned a working interest as of that date. Productive wells consist of producing wells and wells capable of production, including natural gas wells awaiting pipeline connections to commence deliveries and oil wells awaiting connection to production facilities. Gross wells are the total number of producing wells in which we own an interest, and net wells are the sum of our fractional working interests owned in gross wells.

Developed and Undeveloped Acreage

The following table sets forth information as of December 31, 2016 relating to our leasehold acreage. Acreage related to royalty, overriding royalty and other similar interests is excluded from this summary.

As of December 31, 2016, approximately 58% of our acreage was held by production. As of December 31, 2016, we have leases that were not held by production and not impaired representing 8,768 net acres (all which were in the Eagle Ford Shale) expiring in 2017, 15,539 net acres (all of which were in the Eagle Ford Shale) expiring in 2018, and 105,859 net acres (94,088 of which were in the Eagle Ford Shale) expiring in 2019 and beyond. We anticipate that our current and future drilling plans along with selected lease extensions will address the majority of our leases expiring in the Eagle Ford Shale in 2017 and beyond. In addition to these lease expirations, we also have a continuous development obligation in our Catarina area that requires us to drill, but not complete, (i) 50 wells in each annual period commencing on July 1, 2014 and (ii) at least one well in any consecutive 120 day period in order to maintain rights to any future undeveloped acreage.

Delivery Commitments

We have made commitments to certain purchasers to deliver a portion of our natural gas production from our Catarina area.

As of December 31, 2016, in our Catarina area, we have three contracts that require us to deliver portions of our natural gas, with delivery requirements through 2020, 2021 and 2022, respectively. Under our contract expiring in 2020, we are required to deliver 207 Bcf of natural gas through the Catarina Midstream gathering facilities. Under our contract expiring in 2021, we are required to deliver approximately 79 Bcf of natural gas. Under our contract expiring in 2021, which begins in 2017, we are required to deliver approximately 228 Bcf of natural gas. During 2016, we recorded expenses related to deficiencies on delivery commitments of approximately $1.6 million. These amounts were recorded to natural gas production expenses in our consolidated statement of operations and were not considered material to the financial statement line item or to the consolidated financial statements as a whole. We do not expect to have additional expenses in 2017 related to deficiencies on our natural gas delivery commitments.

Also in our Catarina area, we have one contract that requires us to deliver a portion of our oil production through the Catarina Midstream gathering facilities. This contract expires in 2020 and requires us to deliver approximately 15 MMBbls of oil. We do not expect to have additional expenses in 2017 related to deficiencies on our oil delivery commitments.

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 well drilled on the lease premises. The lessor royalties

and other leasehold burdens on our Eagle Ford properties range from 20.8% to 36.7%, resulting in a net revenue interest to us ranging from 63.3% to 79.2%.

Marketing and Major Customers

For the year ended December 31, 2016, purchases by three of our customers accounted for more than 10% (33%, 20%, and 14%, respectively) of our total revenues. The three customers, who are not affiliates of the Company, purchased oil, NGLs and natural gas production from us pursuant to existing marketing agreements with terms that are currently on “evergreen” status and renew on a month‑to‑month basis until either party gives 30‑day advance written notice of non‑renewal.

Since the oil, NGLs and natural gas that we sell are commodities for which there are a large number of potential buyers and because of the adequacy of the infrastructure to transport oil, NGLs and natural gas in the areas in which we operate, if we were to lose one or more customers, we believe that we could readily procure substitute or additional customers such that our production volumes would not be materially affected for any significant period of time.

Hedging Activities

We enter into commodity derivative contracts with unaffiliated third parties to achieve more predictable cash flows and to reduce our exposure to short‑term fluctuations in oil and natural gas prices. For a more detailed discussion of our hedging activities, please read “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Results of Operations—Operating Costs and Expenses—Commodity Derivative Transactions,” “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Critical Accounting Policies and Estimates—Derivative Instruments” and “Item 7A. Quantitative and Qualitative Disclosures about Market Risk.”

Competition

We operate in a highly competitive environment for leasing and acquiring properties and in securing trained personnel. Our competitors specifically include major and independent oil and natural gas companies that operate in our project areas. These competitors include, but are not limited to, Carrizo Oil & Gas, Inc., Chesapeake Energy Corporation, EOG Resources, Inc., Marathon Oil Corporation, SM Energy Company and Noble Energy, Inc. Many of our competitors possess and employ financial, technical and personnel resources substantially greater than ours, which can be particularly important in the areas in which we operate. 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. In addition, there is substantial competition for capital available for investment in the oil and natural gas industry.

We are also affected by the competition for and the availability of equipment, including drilling rigs, completion equipment and materials. We are unable to predict when, or if, shortages of such equipment may occur or how they would affect our development and exploitation programs.

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. After an acquisition, we review the assignments from the seller for scrivener’s and other errors and execute and record corrective assignments as necessary.

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 significant 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 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.

Seasonal Nature of Business

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 or hot summers sometimes lessen this fluctuation. In addition, certain natural gas users utilize natural gas storage facilities and purchase some of their anticipated winter requirements during the summer, which can lessen seasonal demand fluctuations.

Environmental Matters and Regulation

General

Our operations are subject to stringent and complex federal, state and local laws and regulations governing environmental protection as well as the discharge of materials into the environment or otherwise relating to protection of the environment or occupational health and safety. Numerous governmental agencies, such as the Environmental Protection Agency (the “EPA”) and the Texas Railroad Commission (“Commission”), issue regulations, which often require difficult and costly compliance measures that carry substantial administrative, civil and criminal penalties and may result in injunctive obligations for failure to comply. These laws and regulations may, among other things (i) require the acquisition of permits to conduct exploration, drilling and production operations; (ii) restrict the types, quantities and concentration of various substances that can be released into the environment or injected into formations in connection with oil and natural gas drilling, production and transportation activities; (iii) govern the sourcing and disposal of water used in the drilling and completion process; (iv) limit or prohibit drilling or injection activities on certain lands lying within wilderness, wetlands, seismically active areas, and other protected areas; (v) require remedial measures to mitigate pollution from former and ongoing operations, such as requirements to close pits and plug abandoned wells; (vi) result in the suspension or revocation of necessary permits, licenses and authorizations; (vii) impose substantial liabilities for pollution resulting from drilling and production operations; and (viii) require that additional pollution controls be installed. Any failure to comply with these laws and regulations may result in the assessment of administrative, civil, and criminal penalties, the imposition of corrective or remedial obligations, and the issuance of orders enjoining performance of some or all of our operations. Furthermore, liability under such laws and regulations is often strict (i.e., no showing of “fault” is required) and can be joint and several.

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, The U.S. Congress and federal and state agencies frequently revise environmental laws and regulations, and any changes that result in more stringent and costly waste handling, disposal and cleanup requirements for the oil and natural gas industry could have a significant impact on our operating costs.

The trend in environmental regulation has been to place more restrictions and limitations on activities that may affect the environment. Any changes in environmental laws and regulations or re-interpretation of enforcement policies that result in more stringent and costly waste handling, storage transport, disposal, or remediation requirements could have a material adverse effect on our financial position and results of operations. Moreover, accidental releases or spills may occur in the course of our operations, and we could incur significant costs and liabilities as a result of such releases or spills, including any third-party claims for damage to property, natural resources or persons. While we believe that we are in substantial compliance with existing laws and regulations and that continued compliance with existing

requirements will not materially affect us, there is no assurance that this situation will continue in the future.

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

Hazardous Substances and Waste Handling

Our operations are subject to environmental laws and regulations relating to the management and release of hazardous substances, solid and hazardous wastes and petroleum hydrocarbons. These laws generally regulate the generation, storage, treatment, transportation and disposal of solid and hazardous waste and may impose strict and, in some cases, joint and several liability for the investigation and remediation of affected areas where hazardous substances may have been released or disposed. The Comprehensive Environmental Response, Compensation and Liability Act, as amended, or CERCLA, also known as the Superfund law, and comparable state laws impose liability, without regard to fault or legality of conduct, on classes of persons considered to be responsible for the release, deemed “responsible parties,” of a “hazardous substance” into the environment. These persons include the current owner or operator of the site where the release occurred, past owners or operators at the time a hazardous substance was released at the site, and anyone who disposed or arranged for the disposal of a hazardous substance released at the site. Under CERCLA, such persons are subject to strict liability that, in some circumstances, may be joint and several for the costs of cleaning up the hazardous substances that have been 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 act in response to threats to the public health or the environment and to seek to recover the costs they incur from the responsible classes of persons. It is not uncommon for neighboring landowners and other third parties to file common law-based claims for personal injury and property damage allegedly caused by hazardous substances or other pollutants released into the environment. We generate materials in the course of our operations that may be regulated as hazardous substances, and despite the “petroleum exclusion” of Section 101(14) of CERCLA, which currently encompasses natural gas, we may nonetheless handle hazardous substances within the meaning of CERCLA, or similar state statutes, in the course of our ordinary operations and, as a result, may be jointly and severally liable under CERCLA for all or part of the costs required to clean up sites at which these hazardous substances have been released into the environment. In addition, we may have liability for releases of hazardous substances at our properties by prior owners or operators or other third parties.

The Resource Conservation and Recovery Act, as amended, or RCRA, and comparable state statutes and their implementing regulations, regulate the generation, transportation, treatment, storage, disposal and cleanup of hazardous and non-hazardous wastes. Under the auspices of the EPA, most states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. Federal and state regulatory agencies can seek to impose administrative, civil and criminal penalties for alleged non-compliance with RCRA and analogous state requirements. Drilling fluids, produced waters, and most of the other wastes associated with the exploration, development, and production of oil or natural gas, if properly handled, are exempt from regulation as hazardous waste under Subtitle C of RCRA. These wastes, instead, are regulated under RCRA's less stringent solid waste provisions, state laws or other federal laws. It is possible, however, that certain oil and natural gas exploration, development and production wastes now classified as non-hazardous could be classified as hazardous wastes in the future and therefore be subject to more rigorous and costly disposal requirements. Indeed, legislation has been proposed from time to time in The U.S. Congress to re-categorize certain oil and natural gas exploration and production wastes as “hazardous wastes.” Also, in December 2016, the EPA agreed in a consent decree to review its regulations of oil and gas waste.  It has until March 2019 to determine whether any revisions are necessary. Any such change could result in an increase in our costs

to manage and dispose of wastes, which could have a material adverse effect on our results of operations and financial position.

We currently own, lease, or operate numerous properties that have been used for oil and natural gas exploration, production and processing for many years. Although we believe that we are in substantial compliance with the requirements of CERCLA, RCRA, and related state and local laws and regulations, that we hold all necessary and up-to-date permits, registrations and other authorizations required under such laws and regulations and that 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, under or from the properties owned or leased by us, or on, under or from other locations, including off-site locations, where such substances have been taken for disposal. In addition, some of our properties have been operated by third parties or by previous owners or operators whose treatment and disposal of hazardous substances, wastes, or hydrocarbons was not under our control. These properties and the substances disposed or released on, under or from them may be subject to CERCLA, RCRA and analogous state laws. Under such laws, we could be required to undertake response or corrective measures, which could include removal of previously disposed substances and wastes, cleanup of contaminated property or performance of remedial plugging or pit closure operations to prevent future contamination.

Water and Other Water Discharges and Spills

The Federal Water Pollution Control Act, as amended, also known as the Clean Water Act, the Safe Drinking Water Act, or the SDWA, the Oil Pollution Act of 1990, or the OPA, and analogous state laws, impose restrictions and strict controls with respect to the discharge of pollutants, including oil, produced waters and other hazardous substances, into federal and state waters. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by EPA or an analogous state agency. The discharge of dredge and fill material in regulated waters, including wetlands, is also prohibited, unless authorized by a permit issued by the U.S. Army Corps of Engineers. The EPA has also adopted regulations requiring certain oil and natural gas exploration and production facilities to obtain individual permits or coverage under general permits for storm water discharges. Some states also maintain groundwater protection programs that require permits for discharges or operations that may impact groundwater conditions. The underground injection of fluids is subject to permitting and other requirements under state laws and regulation.

Furthermore, the EPA is examining regulatory requirements for “indirect dischargers” of wastewater – i.e., those that send their discharges to private or publicly owned treatment facilities, which treat the wastewater before discharging it to regulated waters. On June 28, 2016, the EPA published a final rule prohibiting the discharge of wastewater from onshore unconventional oil and gas extraction facilities to publicly owned wastewater treatment plants. The EPA is also conducting a study of private wastewater treatment facilities (also known as centralized waste treatment, or CWT, facilities) accepting oil and gas extraction wastewater. The EPA is collecting data and information related to the extent to which CWT facilities accept such wastewater, available treatment technologies (and their associated costs), discharge characteristics, financial characteristics of CWT facilities, and the environmental impacts of discharges from CWT facilities.

Costs may be associated with the treatment of wastewater or developing and implementing storm water pollution prevention plans, as well as for monitoring and sampling the storm water runoff from certain of our facilities. Obtaining permits also has the potential to delay the development of oil and natural gas projects. These same regulatory programs also limit the total volume of water that can be discharged, hence limiting the rate of development, and require us to incur compliance costs.

The OPA amends the Clean Water Act and establishes strict liability and natural resource damages liability for unauthorized discharges of oil into waters of the United States. The OPA is the primary federal law imposing oil spill liability. The OPA contains numerous requirements relating to the prevention of and response to petroleum releases into waters of the United States, including the requirement that operators of offshore facilities and certain onshore facilities near or crossing waterways must maintain certain significant levels of financial assurance to cover potential environmental cleanup and restoration costs.  The OPA subjects owners of facilities to strict liability that, in some circumstances, may be joint and several for all containment and cleanup costs and certain other damages arising from a

release, including, but not limited to, the costs of responding to a release of oil to surface waters.

Pursuant to these laws and regulations, we may be required to obtain and maintain approvals or permits for the discharge of wastewater or storm water and the underground injection of fluids and are required to develop and implement spill prevention, control and countermeasure, or SPCC plans, in connection with on-site storage of significant quantities of oil. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with discharge permits or other requirements of the Clean Water Act and analogous state laws and regulations.  We maintain all required discharge permits necessary to conduct our operations, and we believe we are in substantial compliance with their terms.

Regulation of Hydraulic Fracturing

Hydraulic fracturing is an important and common process used by oil and natural gas exploration and

production operators in the completion of certain oil and natural gas wells whereby water, sand and chemicals are injected under pressure into subsurface formations to stimulate production of oil and/or natural gas. The federal Safe Drinking Water Act, or SDWA, regulates the underground injection of substances through the Underground Injection Control, or UIC, Program.  Hydraulic fracturing is generally exempt from regulation under the UIC Program, and thus the hydraulic fracturing process is typically regulated by state oil and natural gas commissions. The EPA, however, has asserted federal regulatory authority over hydraulic fracturing involving diesel additives under the UIC Program. On February 12, 2014, the EPA published a revised UIC Program guidance for oil and natural gas hydraulic fracturing activities using diesel fuel. The guidance document describes how regulations of Class II wells, which are those wells injecting fluids associated with oil and natural gas production activities, may be tailored to address the purported unique risks of diesel fuel injection during the hydraulic fracturing process. Although the EPA is not the permitting authority for UIC Class II programs in Texas, Mississippi, and Louisiana, where we maintain acreage, the EPA is encouraging state programs to review and consider use of the above-mentioned guidance.  In addition, the EPA plans to develop a Notice of Proposed Rulemaking by June 2018, which would describe a proposed mechanism - regulatory, voluntary, or a combination of both - to collect data on hydraulic fracturing chemical substances and mixtures.  Furthermore, legislation to amend the SDWA to repeal the exemption for hydraulic fracturing from the definition of “underground injection” and require federal permitting and regulatory control of hydraulic fracturing, as well as legislative proposals to require disclosure of the chemical constituents of the fluids used in the fracturing process, have been proposed in recent sessions of The U.S. Congress.

The protection of groundwater quality is extremely important to us. We believe that we follow all state and federal regulations and apply industry standard practices for groundwater protection in our operations. These measures are subject to close supervision by state and federal regulators. Our policy and practice is to follow all applicable guidelines and regulations in the areas where we conduct hydraulic fracturing. Accordingly, we set surface casing strings below the deepest usable quality fresh water zones and cement them back to the surface in accordance with applicable regulations, potential lease requirements and other legal requirements to ensure protection of existing fresh water zones. Also, prior to commencing drilling operations for the production portion of the hole, the surface casing strings are pressure tested to ensure mechanical integrity.

Although not presently relevant to our current 2017 development plans, on March 26, 2015, the Bureau of Land Management (“BLM”) published a final rule governing hydraulic fracturing on federal and Indian lands. The rule requires public disclosure of chemicals used in hydraulic fracturing, implementation of a casing and cementing program, management of recovered fluids, and submission to BLM of detailed information about the proposed operation, including wellbore geology, the location of faults and fractures, and the depths of all usable water. On June 21, 2016, the United States District Court for Wyoming set aside the rule, holding that the BLM lacked Congressional authority to promulgate the rule. The BLM has appealed to the Tenth Circuit Court of Appeals.

Furthermore, there are certain governmental reviews either underway or being proposed that focus on environmental aspects of hydraulic fracturing practices. For example, on December 13, 2016, the EPA released a study examining the potential for hydraulic fracturing to impact drinking water resources finding that, under some circumstances, the use of water in hydraulic fracturing activities can impact drinking water resources. Also, on February 6, 2015, the EPA released a report with findings and recommendations related to public concern about induced seismic

activity from disposal wells. The report recommends strategies for managing and minimizing the potential for significant injection-induced seismic events. Other governmental agencies, including the U.S. Department of Energy, the U.S. Geological Survey, and the U.S. Government Accountability Office, have evaluated or are evaluating various other aspects of hydraulic fracturing.

These ongoing or proposed studies, depending on their degree of pursuit and any meaningful results obtained, could spur initiatives to further regulate hydraulic fracturing or the disposal of produced water and flowback fluid in underground injection wells under the SDWA or other regulatory mechanism.

Also, some states have adopted, and other states are considering adopting, regulations that could restrict hydraulic fracturing in certain circumstances or otherwise require the public disclosure of chemicals used in the hydraulic fracturing process. For example, in December 2011, the Commission adopted rules and regulations requiring that oil and gas operators publicly disclose the chemicals used in the hydraulic fracturing process. Also, in May 2013, the Commission adopted new rules governing well casing, cementing and other standards for ensuring that hydraulic fracturing operations do not contaminate nearby water resources. The new rules took effect in January 2014. Additionally, on October 28, 2014, the Commission adopted disposal well rule amendments designed, amongst other things, to require applicants for new disposal wells that will receive non-hazardous produced water and hydraulic fracturing flowback fluid to conduct seismic activity searches utilizing the U.S. Geological Survey. The searches are intended to determine the potential for earthquakes within a circular area of 100 square miles around a proposed, new disposal well. The disposal well rule amendments, which became effective on November 17, 2014, also clarify the Commission's authority to modify, suspend or terminate a disposal well permit if scientific data indicates a disposal well is likely to contribute to seismic activity. The Commission has used this authority to deny permits for waste disposal sites.

A number of lawsuits and enforcement actions have been initiated across the country alleging that hydraulic fracturing practices have induced seismic activity and adversely impacted drinking water supplies, use of surface water, and the environment generally. Several states and municipalities have adopted, or are considering adopting, regulations that could restrict or prohibit hydraulic fracturing in certain circumstances.  These or any other new laws or regulations that significantly restrict hydraulic fracturing or the disposal of produced water and flowback fluid in underground injection wells could make it more difficult or costly for us to drill and produce from conventional and tight formations as well as make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings.

Further federal, state and/or local laws governing hydraulic fracturing could result in additional permitting and financial assurance requirements, more stringent construction specifications, increased monitoring, reporting and recordkeeping obligations, plugging and abandonment requirements and also to attendant permitting delays and potential increases in costs. Such changes could cause us to incur substantial compliance costs, and compliance or the consequences of failure to comply by us could have a material adverse effect on our financial condition and results of operations. At this time, it is not possible to estimate the potential impact on our business that may arise if additional federal or state and/or local laws are enacted.

Air Emissions

The federal Clean Air Act, as amended, or the CAA, and comparable state laws, regulate emissions of various air pollutants through air emissions standards, construction and operating permitting programs and the imposition of other compliance requirements. In addition, the EPA has developed, and continues to develop, stringent regulations governing emissions of toxic air pollutants at specified sources. On August 16, 2012, the EPA published final rules that subject oil and natural gas production, processing, transmission, and storage operations to regulation under the New Source Performance Standards (“NSPS”) and National Emission Standards for Hazardous Air Pollutants (“NESHAP”) programs. The rule includes NSPS for completions of hydraulically fractured gas wells and establishes specific new requirements for emissions from compressors, controllers, dehydrators, storage vessels, natural gas processing plants and certain other equipment. The final rule seeks to achieve a 95% reduction in Volatile Organic Compounds (“VOCs”) emitted by requiring the use of reduced emission completions or "green completions" on all hydraulically fractured wells constructed or refractured after January 1, 2015. The EPA received numerous requests for reconsideration of these rules from both industry and the environmental community, and court challenges to the rules were also filed. In response, the

EPA has issued, and will likely continue to issue, revised rules responsive to some of the requests for reconsideration. In particular, on May 12, 2016, the EPA amended its regulations to impose new standards for methane and VOC emissions for certain new, modified, and reconstructed equipment, processes, and activities across the oil and natural gas sector. On the same day, the EPA finalized a plan to implement its minor new source review program in Indian country for oil and natural gas production, and it issued for public comment an information request that will require companies to provide extensive information instrumental for the development of regulations to reduce methane emissions from existing oil and gas sources.

Also, on November 15, 2016, the BLM finalized a rule to reduce the flaring, venting and leaking of methane from oil and gas operations on federal and Indian lands. The rule requires operators to use currently available technologies and equipment to reduce flaring, periodically inspect their operations for leaks, and replace outdated equipment that vents large quantities of gas into the air. The rule also clarifies when operators owe the government royalties for flared gas.  State and industry groups have challenged this rule in federal court, asserting that the BLM lacks authority to prescribe air quality regulations. In addition, Congress has taken certain initial steps to repeal the rule pursuant to the Congressional Review Act, though it remains uncertain whether the rule will ultimately be repealed.

These laws and regulations may require us to obtain pre-approval for the construction or modification of certain projects or facilities expected to produce or significantly increase air emissions, obtain and strictly comply with stringent air permit requirements or utilize specific equipment or technologies to control emissions. The need to obtain permits has the potential to delay the development of oil and natural gas projects, and our failure to comply with these requirements could subject us to monetary penalties, injunctions, conditions or restrictions on operations and, potentially, criminal enforcement actions. While we may be required to incur certain capital expenditures in the next few years for air pollution control equipment or other air emissions-related issues, we do not believe that such requirements will have a material adverse effect on our operations.

Climate Change

In recent years, federal, state and local governments have taken steps to reduce emissions of GHGs. The EPA has finalized a series of GHG monitoring, reporting and emission control rules for the oil and natural gas industry, and the U.S. Congress has, from time to time, considered adopting legislation to reduce emissions. Almost one-half of the states have already taken measures to reduce emissions of GHGs primarily through the development of GHG emission inventories and/or regional GHG cap-and-trade programs.

Furthermore, in December 2015, the United States participated in the 21st Conference of the Parties (COP-21) of the United Nations Framework Convention on Climate Change in Paris, France. The resulting Paris Agreement calls for the parties to undertake “ambitious efforts” to limit the average global temperature, and to conserve and enhance sinks and reservoirs of GHGs. The Agreement went into effect on November 4, 2016 and establishes a framework for the parties to cooperate and report actions to reduce GHG emissions.  Also, on June 29, 2016, the leaders of the United States, Canada and Mexico announced an Action Plan to, among other things, boost clean energy, improve energy efficiency, and reduce greenhouse gas emissions. The Action Plan specifically calls for a reduction in methane emissions from the oil and gas sector by 40 to 45 percent by 2025. It remains unclear whether and how the results of the 2016 U.S. election could impact the regulation of greenhouse gas emissions at the federal and state level.

Restrictions on GHG emissions that may be imposed could adversely affect the oil and natural gas industry. The adoption of any legislation or regulations that otherwise limit emissions of GHGs from our equipment and operations, could require us to incur increased operating costs to monitor and report on GHG emissions or reduce emissions of GHGs associated with our operations, such as costs to purchase and operate emissions control systems, to acquire emissions allowances or comply with new regulatory requirements. Any GHG emissions legislation or regulatory programs applicable to power plants or refineries could also increase the cost of consuming, and thereby adversely affect demand for the oil and natural gas that we produce. Consequently, legislation and regulatory programs to reduce GHG emissions could have an adverse effect on our business, financial condition and results of operations.

In addition, claims have been made against certain energy companies alleging that GHG emissions from oil and natural gas operations constitute a public nuisance under federal and/or state common law. As a result, private individuals may seek to enforce environmental laws and regulations against us and could allege personal injury or

property damages. While our business is not a party to any such litigation, we could be named in actions making similar allegations. An unfavorable ruling in any such case could significantly impact our operations and could have an adverse impact on our financial condition.

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

National Environmental Policy Act

Oil and natural gas exploration, development and production activities on federal lands are subject to the National Environmental Policy Act, as amended, or NEPA. NEPA requires federal agencies, including the DOI, 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 to evaluate 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. Currently, we have minimal exploration and production activities on federal lands. However, to the extent our current or future activities on federal lands are subject to the requirements of NEPA, this process has the potential to delay the receipt of governmental permits and the development of oil and natural gas projects. Authorizations under NEPA also are subject to protest, appeal or litigation, which can delay or halt projects.

Endangered Species Act

The Federal Endangered Species Act, or the ESA, and analogous state statutes restrict activities that may adversely threatened or endangered species or their habitat. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act. Federal agencies are required to insure that any action authorized, funded or carried out by them is not likely to jeopardize the continued existence of listed species or modify their critical habitat. While some of our facilities on federal lands may be located in areas that are designated as habitat for endangered or threatened species, we believe that we are in substantial compliance with the ESA. The U.S. Fish and Wildlife Service may identify, however, previously unidentified endangered or threatened species or may designate critical habitat and suitable habitat areas that it believes are necessary for survival of a threatened or endangered species, which could cause us to incur additional costs or become subject to operating restrictions or bans in the affected areas.

Occupational Safety and Health Act

We are also subject to the requirements of OSHA and comparable state laws that regulate the protection of the health and safety of employees. In addition, OSHA's hazard communication standard requires that information be maintained 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 our operations are in substantial compliance with the OSHA requirements.

Other Regulation of the Oil and Natural Gas Industry

The oil and natural gas industry is extensively regulated by numerous federal, state and local authorities. Legislation affecting the oil and natural gas industry is under constant review for amendment or expansion, frequently increasing the regulatory burden. Additionally, numerous departments and agencies, both federal and state, are authorized by statute to issue rules and regulations that are binding on the oil and natural gas industry and its individual members, some of which carry substantial penalties for failure to comply. Although the regulatory burden on the oil and natural gas industry increases our cost of doing business and, consequently, affects our profitability, these burdens generally do not affect us any differently or to any greater or lesser extent than they affect other companies in the oil and natural gas industry with similar types, quantities and locations of production.

Drilling and Production

Our operations are subject to various types of regulation at federal, state and local levels. These types of regulation include requiring permits for the drilling of wells, drilling bonds and reports concerning operations. Most states, and some counties and municipalities, in which we operate also regulate one or more of the following:

State laws regulate the size and shape of drilling and spacing units or proration units governing the pooling of oil and natural gas properties. Some states allow forced pooling or integration of tracts to facilitate exploration, while other states rely on voluntary pooling of lands and leases. In some instances, forced pooling or unitization may be implemented by third parties and may reduce our interest in the unitized properties. In addition, state conservation laws establish maximum rates of production from oil and natural gas wells, generally prohibit the venting or flaring of natural gas and impose requirements regarding the ratability of production. These laws and regulations may limit the amount of oil and natural gas we can produce from our wells or limit the number of wells or the locations at which we can drill. 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.

Natural Gas Regulation

The availability, terms and cost of transportation significantly affect sales of natural gas. The interstate transportation and sale for resale of natural gas is subject to federal regulation, including regulation of the terms, conditions and rates for interstate transportation, storage and various other matters, primarily by the Federal Energy Regulatory Commission, or FERC. Federal and state regulations govern the price and terms for access to natural gas pipeline transportation. FERC's regulations for interstate natural gas transmission in some circumstances may also affect the intrastate transportation of natural gas.

The FERC also possesses regulatory oversight over natural gas markets, including the purchase, sale and transportation activities of non-interstate pipelines and other natural gas market participants. FERC possesses substantial enforcement authority for violations of the Natural Gas Act, or NGA, including the ability to assess civil penalties, order disgorgement of profits and recommend criminal penalties. The Energy Policy Act of 2005 amended the NGA to grant FERC new authority to facilitate price transparency in markets for the sale or transportation of physical natural gas in interstate commerce, and to prohibit market manipulation. FERC's anti-manipulation regulations apply to FERC jurisdictional activities, which have been broadly construed by the FERC. Should we fail to comply with all applicable FERC-administered statutes, rules, regulations and orders, we could be subject to substantial civil and criminal penalties, including civil penalties of up to $1.0 million per day, per violation.

In 2008, FERC took additional steps to enhance its market oversight and monitoring of the natural gas industry. Order No. 704, as clarified in orders on rehearing, requires buyers and sellers of natural gas above a de minimis level, including entities not otherwise subject to FERC jurisdiction, to submit an annual report to FERC describing their wholesale physical natural gas transactions that use an index or that contribute to or may contribute to the formation of a gas index. The FERC also contemplated expanding the industry's reporting requirements. On November 15, 2012, the FERC issued a Notice of Inquiry seeking comments whether requiring quarterly reporting of every gas transaction within the FERC's jurisdiction that entails physical delivery for the next day or the next month would provide useful information for improving natural gas market transparency.  The FERC ultimately determined that imposing a quarterly

reporting requirement is not necessary at this time and exercised its discretion to terminate the Notice of Inquiry on November 17, 2015.

Although natural gas prices are currently unregulated, The U.S. Congress historically has been active in the area of natural gas regulation. We cannot predict whether new legislation to regulate natural gas might be proposed, what proposals, if any, might actually be enacted by The U.S. Congress or the various state legislatures, and what effect, if any, the proposals might have on the operations of our properties. Sales of condensate and NGLs are not currently regulated and are made at market prices.

State Regulation

The various states regulate the drilling for, and the production, gathering and sale of, oil and natural gas, including imposing severance taxes and requirements for obtaining drilling permits. For example, Texas currently imposes a 4.6% severance tax on oil production and a 7.5% severance tax on natural gas production. States also regulate the method of developing new fields, the spacing and operation of wells and the prevention of waste of natural gas resources. States may regulate rates of production and may establish maximum daily production allowables from natural gas wells based on market demand or resource conservation, or both. States do not regulate wellhead prices or engage in other similar direct economic regulation, but there can be no assurance that they will not do so in the future. The effect of these regulations may be to limit the amount of natural gas that may be produced from our wells and to limit the number of wells or locations we can drill.

The oil and natural gas industry is also subject to compliance with various other federal, state and local regulations and laws. Some of those laws relate to resource conservation and equal employment opportunity. We do not believe that compliance with these laws will have a material adverse effect on us.

Employees

We currently do not have any employees. Pursuant to our Services Agreement with SOG (the “Services Agreement”), SOG performs services for us, including the operation of our properties. Please also read “Item 8. Financial Statements and Supplementary Data —Note 9, Related Party Transactions.” As of December 31, 2016, SOG had approximately 235 employees, including 27 engineers, 13 geoscientists and 13 land professionals. None of these employees are represented by labor unions or covered by any collective bargaining agreement. We believe that SOG’s relations with its employees are satisfactory.

We also contract for the services of independent consultants involved in land, engineering, regulatory, accounting, financial and other disciplines as needed.

Offices

For our principal offices, we currently share offices with other members of the Sanchez Group under leases entered into by the Company covering approximately 90,000 square feet of office space in Houston, Texas at 1000 Main Street, Suite 3000, Houston, Texas 77002, expiring in 2025. In addition, SOG maintains offices in Laredo and San Antonio, Texas.

Available Information

We are required to file annual, quarterly and current reports, proxy statements and other information with the SEC. You may read and copy any documents filed by us with the SEC at the SEC’s Public Reference Room at 100 F Street, N.E., Washington, D.C. 20549. You may obtain information on the operation of the Public Reference Room by calling the SEC at 1‑800‑SEC‑0330. Our filings with the SEC are also available to the public from commercial document retrieval services and at the SEC’s website at http://www.sec.gov.

Our common stock is listed and traded on the New York Stock Exchange (“NYSE”) under the symbol “SN.” 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.

We also make available on our website at http://www.sanchezenergycorp.com all of the documents that we file with the SEC, free of charge, as soon as reasonably practicable after we electronically file such material with the SEC. Information contained on our website is not incorporated by reference into this Annual Report on Form 10‑K.

Item 1A.  Risk Factors

Our business involves a high degree of risk. You should consider and read carefully all of the risks and uncertainties described below, together with all of the other information contained in this Annual Report on Form 10‑K, including the financial statements and the related notes appearing at the end of this Annual Report on Form 10‑K. If any of the following risks, or any risk described elsewhere in this Annual Report on Form 10‑K, actually occurs, our business, business prospects, financial condition, results of operations or cash flows could be materially adversely affected. The risks below are not the only ones facing the Company. Additional risks not currently known to us or that we currently deem immaterial may also adversely affect us. This Annual Report on Form 10‑K also contains forward‑looking statements, estimates and projections that involve risks and uncertainties. Our actual results could differ materially from those anticipated in the forward‑looking statements as a result of specific factors, including the risks described below.  Also, please read “Cautionary Note Regarding Forward-Looking Statements.”

Risks Related to Our Business

Market conditions for oil, natural gas and NGLs are highly volatile.  A sustained decline in prices for these commodities could adversely affect our revenue, cash flows, profitability and growth.

Prices for oil, natural gas and NGLs fluctuate widely in response to a variety of factors that are beyond our control, such as:

Governmental actions may also affect oil, natural gas and NGL prices.  It is uncertain what impact the election of President Trump and the new Congress may have on the exploration for and production of oil, natural gas and NGLs. In the past, oil, natural gas and NGL prices have been extremely volatile, and we expect this volatility to continue.  Beginning in the latter half of 2014, oil prices declined precipitously, and continued to decline throughout 2015 as well as the start of 2016. The West Texas Intermediate posted price used to calculate the full cost ceiling in accordance with SEC rules declined from an annual high of $105.34 per Boe on July 1, 2014 to $69.00 per Boe on December 1, 2014, $41.85 per Boe on December 1, 2015 and $31.62 per Boe on February 1, 2016. Such volatility has negatively affected the amount of our net estimated proved reserves and has negatively affected the standardized measure of discounted future net cash flows of our net estimated proved reserves. We recorded a full cost ceiling test impairment after income taxes of $169 million for the year ended December 31, 2016, and we recorded a full cost ceiling impairment test impairment after income taxes of $1,365 million for the year ended December 31, 2015. The impact of lower commodity prices adversely affecting proved reserve values primarily contributed to the ceiling impairment. Changes in production rates, prices, levels of reserves, future development costs, transfers of unevaluated properties, and other factors will determine our actual ceiling test calculation and impairment analyses in future periods. The 12‑month average commodity price could continue to decline, which could result in additional impairments being recorded during 2017.

In addition, our revenue, profitability and cash flow depend upon the prices of and demand for oil, natural gas and NGL reserves, and continued price volatility and low commodity prices, or a sustained drop in prices could negatively affect our financial results and impede our growth. In particular, sustained declines in commodity prices will:

An increase in the differential between the NYMEX or other benchmark prices of oil, natural gas and NGLs and the wellhead price we receive for our production could adversely affect our business, financial condition and results of operations.

The prices that we receive for our oil, natural gas and NGL production sometimes reflect differences between the relevant benchmark prices, such as NYMEX, that are used for calculating hedge positions. The difference between the benchmark price and the price we receive is called a basis differential. Increases in the basis differential between the benchmark prices for oil, natural gas and NGLs and the wellhead price we receive could adversely affect our business, financial condition and results of operations. We do not have or currently plan to have any commodity derivative contracts covering the amount of the basis differentials we experience in respect of our production. As such, we will be exposed to any increase in such differentials, which could adversely affect our business, financial condition and results of operations.

As of February 27, 2017, we had commodity derivative contracts in place covering approximately 36% and 98% of the mid‑point of our estimated oil and natural gas production, respectively, for 2017. The contracts consist of swaps and put spreads covering crude oil and natural gas production. In the future, we expect to continue to enter into commodity derivative contracts for a portion of our estimated production, which could result in net gains or losses on commodity derivatives. Our hedging strategy and future hedging transactions will be determined by our management,

which is not under any obligation to enter into commodity derivative contracts covering any specific portion of our production.

The prices at which we enter into commodity derivative contracts covering our production in the future will be dependent upon oil, natural gas and NGL prices at the time we enter into these transactions, which may be substantially higher or lower than past or current oil, natural gas and NGL prices. Accordingly, our price hedging strategy may not protect us from significant declines in oil, natural gas and NGL prices realized for our future production. Conversely, our hedging strategy may limit our ability to realize incremental cash flows from commodity price increases. As such, our hedging strategy may not protect us from changes in oil, natural gas and NGL prices that could have a significant adverse effect on our liquidity, business, financial condition and results of operations.

Lower oil, natural gas and NGL prices have caused us to record ceiling limitation impairments, reducing our earnings and our stockholders’ equity and further declines in commodity prices may cause us to record further impairments, which would reduce our earnings and stockholders’ equity.

We use the full‑cost method of accounting and accordingly, we capitalize all costs associated with the acquisition, exploration and development of oil, natural gas and NGL properties, including unproved and unevaluated property costs. Under full cost accounting rules, the net capitalized cost of oil, natural gas and NGL properties may not exceed a “ceiling limit” that is based upon the present value of estimated future net revenues from net proved reserves, discounted at 10%, plus the lower of the cost or fair market value of unproved properties and other adjustments as required by SEC rules. If net capitalized costs of oil, natural gas and NGL properties exceed the ceiling limit, we must charge the amount of the excess to earnings, which could have a material adverse effect on our results of operations for the periods in which such charges are taken. This is called a “ceiling limitation impairment.” The risk that we will experience a ceiling limitation impairment increases when oil, natural gas or NGL prices are depressed as in the current environment, if we have substantial downward revisions in estimated net proved reserves or if estimates of future development costs increase significantly. Based upon current price trends we could experience ceiling limitation impairments in future periods.

Beginning in the latter half of 2014, oil prices declined precipitously, and continued to decline throughout 2015 as well as the start of 2016. Given this decline in commodity prices, the net book value of our oil and natural gas properties exceeded our ceiling amount using the WTI unweighted 12‑month average price adjusted by lease for quality, transportation fees, geographical differentials, marketing bonuses or deductions and other factors affecting the price realized at the wellhead, resulting in a total write‑downs of our oil and natural gas properties of $1,365 million after income taxes during 2015 and $169.0 million after income taxes during 2016. As ceiling test computations depend upon the calculated unweighted arithmetic average prices, it is difficult to predict the likelihood, timing and magnitude of any future impairments. However, a decline in 12‑month average commodity prices could result in additional impairments recorded during 2017. A ceiling test write down would negatively affect our results of operations.

Costs associated with unevaluated properties are not initially subject to the ceiling test limitation. Rather, we assess all items classified as unevaluated property on a quarterly basis for possible impairment or reduction in value based upon our intentions, as approved by our board of directors and management, with respect to drilling on such properties, the remaining lease term, geological and geophysical evaluations, drilling results, the assignment of proved reserves, and the economic viability of development if proved reserves are assigned. These factors are significantly influenced by our expectations regarding future commodity prices, development costs, and access to capital at acceptable cost. During any period in which these factors indicate impairment, the cumulative drilling costs incurred to date for such property and all or a portion of the associated leasehold costs are transferred to the full cost pool and are then subject to amortization and the ceiling test limitation. Accordingly, a significant change in these factors, many of which are beyond our control, may shift a significant amount of cost from unevaluated properties into the full cost pool that is subject to amortization and the ceiling test limitation.

Lower oil and natural gas prices also reduces the amount of oil and natural gas that we can produce economically. Substantial and sustained decreases in oil and natural gas prices would render uneconomic a significant portion of our development and exploitation projects. This may result in our having to make downward adjustments to our estimated proved reserves. As a result, substantial and sustained declines in oil and natural gas prices may materially

and adversely affect our future business, financial condition, results of operations, liquidity or ability to finance planned capital expenditures.

The Company’s derivative risk management activities could result in financial losses.

To mitigate the effect of commodity price volatility on the Company’s net cash provided by operating activities, support the Company’s annual capital budgeting and expenditure plans and reduce commodity price risk associated with certain capital projects, the Company’s strategy is to enter into derivative arrangements covering a portion of its oil, NGL and natural gas production. These derivative arrangements are subject to mark‑to‑market accounting treatment, and the changes in fair market value of the contracts are reported in the Company’s statements of operations each quarter, which may result in significant non‑cash gains or losses. After the current hedges expire, there is significant uncertainty that we will be able to put new hedges in place that will provide us with the same benefit. These derivative contracts may also expose the Company to risk of financial loss in certain circumstances, including when:

Such financial losses could materially impact our liquidity, business, financial condition and results of operations.

There can be no assurance that the Comanche Acquisition will be consummated in the anticipated timeframe, on the terms described herein, or at all.

On January 12, 2017, the Company, through two of our subsidiaries, SN EF UnSub, LP (“SN UnSub”) and SN EF Maverick, LLC (“SN Maverick”), along with an entity controlled by The Blackstone Group, L.P., Gavilan Resources, LLC (“Blackstone”), signed a purchase and sale agreement (the “Comanche Purchase Agreement”) to acquire assets (the “Comanche Assets”) from Anadarko E&P Onshore LLC and Kerr-McGee Oil and Gas Onshore LP (together, “Anadarko”) for $2,275 million in cash, subject to customary closing adjustments (the “Comanche Acquisition”). The consummation of the Comanche Acquisition is subject to certain closing conditions, including conditions that must be met by Anadarko and that are beyond our control. In addition, under certain circumstances, we, Blackstone or Anadarko are able to terminate the Comanche Purchase Agreement. In addition, we may be required to seek or utilize additional or other financing sources to consummate the Comanche Acquisition, if we do not have sufficient liquidity at closing or if our anticipated financing sources, including the preferred unit investment by affiliates of GSO Capital Partners LP (individually or collectively, as the context requires, “GSO”) in SN UnSub or the credit facility to be entered into by SN UnSub at the closing of the Comanche Acquisition, are not available, and we cannot assure you that such additional or other financing sources will be available on terms acceptable to us, or at all. There can be no assurances that the Comanche Acquisition will be consummated in the anticipated timeframe, on the terms described herein, or at all.

If the Comanche Acquisition is not consummated, under certain circumstances, we may be required to forfeit our approximate $56.9 million deposit under the Comanche Purchase Agreement. Furthermore, our stock price could be negatively impacted if we fail to complete the Comanche Acquisition.

There are a number of risks and uncertainties relating to the Comanche Acquisition. There can be no assurance that events will not intervene to delay or result in the failure to close the Comanche Acquisition. In addition, we, Blackstone and Anadarko have the ability to terminate the Comanche Purchase Agreement under certain circumstances. Failure to complete the Comanche Acquisition would prevent us from realizing the anticipated benefits of the Comanche Acquisition. We would also remain liable for significant transaction costs, including legal, accounting and financial advisory fees. In addition, the market price of our common stock may reflect various market assumptions as to whether the Comanche Acquisition will be completed. Consequently, the failure to complete or any delay in the closing of the Comanche Acquisition could result in a significant change in the market price of our common stock.

The Comanche Acquisition or any other acquisition we may undertake involve risks associated with acquisitions and integration of acquired assets, and the intended benefits of the Comanche Acquisition or any other acquisition we may undertake may not be realized.

The Comanche Acquisition or any other acquisition we may undertake involve risks associated with acquisitions and integrating acquired assets into existing operations, including that:

Even if we successfully integrate the assets acquired in the Comanche Acquisition or any other acquisition we may undertake into our operations, it may not be possible to realize the full benefits we anticipate or we may not realize these benefits within the expected timeframe. If we fail to realize the benefits we anticipate from the Comanche Acquisition or any other acquisition we may undertake, our business, results of operations and financial condition may be adversely affected.

Under the terms of the lease with respect to the Catarina assets and under the terms of the Comanche Development Agreement, we are subject to annual drilling and development requirements and failure to comply with these requirements may result in loss of our interests in the Catarina area that are not held by production or sizable default payments to Anadarko, respectively.

In order to protect our exploration and development rights in the Catarina area, we are required to drill 50 wells per year (measured from July 1 to June 30). If we fail to meet the minimum drilling commitment under the terms of the Catarina Lease, we could forfeit our acreage under the Catarina Lease and rights to develop land not held by production (excluding, in certain instances, associated rights such as midstream assets). If we drill more than 50 wells in a prescribed twelve month period, we may apply such additional wells (up to a maximum of 30 additional wells) toward the following prescribed twelve month period’s 50-well requirements. In addition, the Catarina Lease requires us to go no longer than 120 days without spudding a well, and, under the terms of the Catarina Lease, failure to do so could result in the forfeiture of our acreage under the Catarina Lease and rights to develop land not held by production (excluding, in certain instances, acreage upon which associated midstream assets are located). Our drilling plans for our undeveloped leasehold acreage are subject to change based upon various factors, including factors that are beyond our control, such as drilling results, oil, natural gas and NGL prices, the availability and cost of capital, drilling and production costs,

availability of drilling services and equipment, gathering system and pipeline transportation constraints and regulatory approvals. Because of these uncertainties, we cannot assure you that we will be able meet our obligations under the Catarina Lease. If the Catarina Lease expires, we will lose our right to develop the related properties on this acreage, which could adversely affect our business, financial condition and results of operations.

At the closing of the Comanche Acquisition, we will enter into a development agreement (the “Development Agreement”) with Anadarko pursuant to which we will commit to completing and equipping 60 wells per year for 5 years. If we complete and equip more than 60 wells in a year, we may apply such additional wells (up to a maximum of 30 additional wells) toward the following years’ 60-well requirements. If we fail to complete and equip the required number of wells in a given year (after applying any qualifying additional wells from previous years), we must pay Anadarko a default fee of $200,000 for each well we fail to timely complete and equip. The drilling plan is subject to change based upon various factors, including factors that are beyond our control, such as drilling results, oil, natural gas and NGL prices, the availability and cost of capital, drilling and production costs, availability of drilling services and equipment, gathering system and pipeline transportation constraints and regulatory approvals. Because of these uncertainties, we cannot assure you that we will be able meet our obligations under the Development Agreement following the closing of the Comanche Acquisition.

Our agreements with Blackstone and GSO will restrict us from transferring our right, title and interest to the Comanche Assets.

At the closing of the Comanche Acquisition, we will enter into a joint development agreement with Blackstone (the “JDA”) that provides for the administration, operation and transfer of the jointly-owned Comanche Assets.  Under the terms of the JDA, except under limited circumstances, neither we nor Blackstone can transfer any of our rights, title or interest to any asset or related assets (including any working interests) prior to the third anniversary of the JDA.  In addition, under our agreements with GSO, following the closing of the Comanche Acquisition, we will not be able to dispose of all or a substantial portion of the Comanche Assets without GSO’s consent.  These restrictions may prohibit us from taking advantage of certain opportunities, including our ability to sell these assets, which may arise from time to time.

The JDA will contain right of first offer (“ROFO”) and tag-along provisions that may hinder our ability to sell our interest in the Comanche Assets within our desired time frame or on our desired terms, and could delay or prevent an acquisition of us, even if the acquisition would be beneficial to our stockholders.

Under the terms of the JDA, both parties have a ROFO in the event that the other party intends to sell or otherwise transfer its interests.  In addition, the JDA provides both parties with a tag-along right in the event that the other party intends to sell at least 35% of its total interests to a third-party purchaser (including upon a change of control transaction involving us). These features could limit third-party offers, inhibit our ability to sell our interests or adversely affect the timing of any sale of our interests and our ability to obtain the highest price possible in the event that we decide to market or sell our interests. In addition, the tag-along provisions of the JDA may also frustrate or prevent any attempts by our stockholders or a third party to replace or remove our current management or to acquire an interest in or engage in other corporate transactions with us, by subjecting certain corporate change of control transactions to a tag-along provision pursuant to which a third party may be required to acquire Blackstone’s interest in the Comanche Assets if it desires to enter into a corporate transaction with us.

Upon closing the Comanche Acquisition, we will enter into the JDA with Blackstone and amend and restate the limited partnership agreement of one of our subsidiaries, SN UnSub and the limited liability company agreement of SN UnSub’s general partner, SN EF UnSub GP, LLC, to admit GSO as a limited partner and member, respectively, therein, which involves risk.

At the closing of the transactions contemplated by the Comanche Acquisition, we will enter into the JDA that provides for the administration, operation and transfer of the jointly-owned Comanche Assets. The JDA provides for the parties to establish an operating committee, which will control the timing, scope and budgeting of operations on the Comanche Assets (subject to certain exceptions). Although we will be designated as operator of the Comanche Assets

under the JDA, under certain circumstances we may be removed as operator and, furthermore, because we will not control the operating committee we will not have unilateral control over many key variables of the operation and development of the Comanche Assets, including the establishment of the budget and development plan for the Comanche Assets. There can be no assurance that Blackstone will continue its relationship with us in the future or that we will be able to pursue our stated strategies with respect to the Comanche Assets. Furthermore, Blackstone may (a) have economic or business interests or goals that are inconsistent with ours; (b) take actions contrary to our policies or objectives; (c) undergo a change of control; (d) experience financial and other difficulties; or (e) be unable or unwilling to fulfill their obligations under the JDA, which may affect our financial conditions or results of operations.