10-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

(Mark one)

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

For the fiscal year ended December 31, 2016

or

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

For the transition period from             to             

Commission file number: 001-33801

APPROACH RESOURCES INC.

(Exact name of registrant as specified in its charter)

Delaware	51-0424817
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification Number)
One Ridgmar Centre 6500 West Freeway, Suite 800 Fort Worth, Texas	76116
(Address of principal executive offices)	(Zip Code)

Registrant’s telephone number, including area code

(817) 989-9000

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

Title of each class	Name of each exchange on which registered
Common stock, par value $0.01 per share	NASDAQ Global Select Market

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 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 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.

Large accelerated filer	☐	Accelerated filer	☑
Non-accelerated filer	☐	Smaller reporting company	☐

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

The aggregate market value of the voting and non-voting common equity held by non-affiliates (excluding voting shares held by officers and directors) as of June 30, 2016 was $80.3 million. This amount is based on the closing price of the registrant’s common stock on the NASDAQ Global Select Market on that date.

The number of shares of the registrant’s common stock, par value $0.01, outstanding as of March 6, 2017, was 80,903,376.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the registrant’s proxy statement for its 2017 annual meeting of stockholders, which will be filed with the Securities and Exchange Commission within 120 days of December 31, 2016, are incorporated by reference in Part III, Items 10-14 of this report.

Certain exhibits previously filed with the Securities and Exchange Commission are incorporated by reference into Part IV of this report.

APPROACH RESOURCES INC.

Unless the context otherwise indicates, all references in this report to “Approach,” the “Company,” “we,” “us,” “our” or “ours” are to Approach Resources Inc. and its subsidiaries. Unless otherwise noted, (i) all information in this report relating to oil, NGLs and natural gas reserves and the estimated future net cash flows attributable to reserves is based on estimates and is net to our interest, and (ii) all information in this report relating to oil, NGLs and natural gas production is net to our interest. Natural gas is converted throughout this report at a rate of six Mcf of gas to one barrel of oil equivalent (“Boe”). NGLs are converted throughout this report at a rate of one barrel of NGLs to one Boe. The ratios of six Mcf of gas to one Boe and one barrel of NGLs to one Boe do not assume price equivalency and, given price differentials, the price for a Boe of natural gas or NGLs may differ significantly from the price of a barrel of oil. If you are not familiar with the oil and gas terms or abbreviations used in this report, please refer to the definitions of these terms and abbreviations under the caption “Glossary” after Item 16 of this report.

TABLE OF CONTENTS

		Page
PART I
Item 1.	Business	1
Item 1A.	Risk Factors	14
Item 1B.	Unresolved Staff Comments	30
Item 2.	Properties	31
Item 3.	Legal Proceedings	38
Item 4.	Mine Safety Disclosures	38
PART II
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	39
Item 6.	Selected Financial Data	42
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	43
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	60
Item 8.	Financial Statements and Supplementary Data	62
Item 9.	Changes in and Disagreements With Accountants on Accounting and Financial Disclosure	62
Item 9A.	Controls and Procedures	63
Item 9B.	Other Information	63
PART III
Item 10.	Directors, Executive Officers and Corporate Governance	64
Item 11.	Executive Compensation	64
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	64
Item 13.	Certain Relationships and Related Transactions, and Director Independence	64
Item 14.	Principal Accounting Fees and Services	64
PART IV
Item 15.	Exhibits, Financial Statement Schedules	65
Item 16.	Form 10-K Summary	65
Signatures		71
Index to Consolidated Financial Statements of Approach Resources Inc.		F-1
Index to Exhibits		72

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Cautionary Statement Regarding Forward-Looking Statements

Various statements in this report, including those that express a belief, expectation or intention, as well as those that are not statements of historical fact, are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”), and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). The forward-looking statements may include projections and estimates concerning the timing and success of specific projects, typical well economics and our future reserves, production, revenues, costs, income, capital spending, 3-D seismic operations, interpretation and results and obtaining permits and regulatory approvals. When used in this report, the words “will,” “believe,” “intend,” “expect,” “may,” “should,” “anticipate,” “could,” “estimate,” “plan,” “predict,” “project,” “potential” or their negatives, other similar expressions or the statements that include those words, are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words.

These forward-looking statements are largely based on our expectations, which reflect estimates and assumptions made by our management. These estimates and assumptions reflect our best judgment based on currently known market conditions and other factors. Although we believe such estimates and assumptions to be reasonable, they are inherently uncertain and involve a number of risks and uncertainties that are beyond our control. In addition, management’s assumptions about future events may prove to be inaccurate. We caution all readers that the forward-looking statements contained in this report are not guarantees of future performance, and we cannot assure any reader that such statements will be realized or the forward-looking events and circumstances will occur. Actual results may differ materially from those anticipated or implied in the forward-looking statements due to the factors listed in the “Risk Factors” section and elsewhere in this report. All forward-looking statements speak only as of the date of this report. We disclaim any obligation to publicly update or revise any forward-looking statements as a result of new information, future events or otherwise, unless required by law. These cautionary statements qualify all forward-looking statements attributable to us, or persons acting on our behalf. The risks, contingencies and uncertainties relate to, among other matters, the following:

• uncertainties in drilling, exploring for and producing oil and gas;

• oil, NGLs and natural gas prices;

• overall United States and global economic and financial market conditions;

• issuance of our common stock in connection with the Exchange Transactions (defined below) causing substantial dilution;

• our leverage negatively affecting our semi-annual redetermination of our revolving credit facility;

• domestic and foreign demand and supply for oil, NGLs, natural gas and the products derived from such hydrocarbons;

• actions of the Organization of Petroleum Exporting Countries (“OPEC”), its members and other state-controlled oil companies relating to oil price and production controls;

• our ability to obtain additional financing necessary to fund our operations and capital expenditures and to meet our other obligations;

• our ability to maintain a sound financial position;

• our cash flows and liquidity;

• the effects of government regulation and permitting and other legal requirements, including laws or regulations that could restrict or prohibit hydraulic fracturing;

• disruption of credit and capital markets;

• disruptions to, capacity constraints in or other limitations on the pipeline systems that deliver our oil, NGLs and natural gas and other processing and transportation considerations;

• marketing of oil, NGLs and natural gas;

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• high costs, shortages, delivery delays or unavailability of drilling and completion equipment, materials, labor or other services;

• competition in the oil and gas industry;

• uncertainty regarding our future operating results;

• profitability of drilling locations;

• interpretation of 3-D seismic data;

• replacing our oil, NGLs and natural gas reserves;

• our ability to retain and attract key personnel;

• our business strategy, including our ability to recover oil, NGLs and natural gas in place associated with our Wolfcamp shale oil resource play in the Permian Basin;

• development of our current asset base or property acquisitions;

• estimated quantities of oil, NGLs and natural gas reserves and present value thereof;

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

• other factors discussed under Item 1A. “Risk Factors” in this report.

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PART I

ITEM 1. BUSINESS

General

Approach Resources Inc. is an independent energy company focused on the exploration, development, production and acquisition of unconventional oil and gas reserves in the Midland Basin of the greater Permian Basin in West Texas, where we lease approximately 123,000 net acres as of December 31, 2016. We believe our concentrated acreage position and extensive, integrated field infrastructure system provides us an opportunity to achieve cost, operating and recovery efficiencies in the development of our drilling inventory. Our long-term business strategy is to develop resource potential from the Wolfcamp shale oil formation and pursue acquisitions that meet our strategic and financial objectives. See “— Our Business Strategy” below. Additional drilling targets could include the Clearfork, Canyon Sands, Strawn and Ellenburger zones. We sometimes refer to our development project in the Permian Basin as “Project Pangea,” which includes “Pangea West.” Our management and technical team have a proven track record of finding and developing reserves through advanced drilling and completion techniques. As the operator of all of our estimated proved reserves and production, we have a high degree of control over capital expenditures and other operating matters.

At December 31, 2016, our estimated proved reserves were 156.4 million barrels of oil equivalent (“MMBoe”). Substantially all of our proved reserves are located in Crockett and Schleicher Counties, Texas. The following are important characteristics of our proved reserves at December 31, 2016:

• 32% oil, 30% NGLs and 38% natural gas;

• 38% proved developed;

• 100% operated;

• Reserve life of approximately 34 years based on 2016 production of 4.5 MMBoe;

• Standardized measure of discounted future net cash flows (“standardized measure”) of $297.8 million; and

• PV-10 (non-GAAP) of $307.9 million.

PV-10 is our estimate of the present value of future net revenues from proved oil, NGLs and natural gas reserves after deducting estimated production and ad valorem taxes, future capital costs and operating expenses, but before deducting any estimates for future income taxes. Estimated future net revenues are discounted at an annual rate of 10% to determine their present value. PV-10 is a financial measure that is not determined in accordance with accounting principles generally accepted in the United States (“GAAP”), and generally differs from the standardized measure, the most directly comparable GAAP financial measure, because it does not include the effects of income taxes on future cash flows. PV-10 should not be considered as an alternative to the standardized measure, as computed under GAAP. See Item 2. “Properties — Proved Oil and Gas Reserves” for a reconciliation of PV-10 to the standardized measure.

At December 31, 2016, we owned and operated 806 producing oil and gas wells in the Permian Basin. During 2016, we produced 4.5 MMBoe, or 12.4 MBoe/d. Production for 2016 was 28% oil, 34% NGLs and 38% natural gas.

Our History

Approach Resources Inc. was incorporated in September 2002. Our common stock began trading on the NASDAQ Global Market in the United States under the symbol “AREX” on November 8, 2007, and is now listed on the NASDAQ Global Select Market (“NASDAQ”). Our principal executive offices are located at One Ridgmar Centre, 6500 West Freeway, Suite 800, Fort Worth, Texas 76116. Our telephone number is (817) 989-9000.

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Our Business Strategy

Our long-term business strategy is to create value by growing reserves and production in a cost efficient manner and at attractive rates of return by pursuing the strategies discussed below. However, the rate of growth of our reserves and production, as well as achievable rates of return, depend on commodity prices. During 2014 and 2015, we experienced dramatic price decreases in the commodities we produce. As a result, we substantially reduced our drilling activity beginning in 2015 and throughout 2016, which led to a natural decline in production in 2016. Commodity prices were volatile in 2016 but improved throughout the year. We have positioned ourselves to increase our drilling activity at a measured and disciplined pace, and potentially resume production growth, in the event of a continued commodity price recovery, by focusing on the following strategies:

• Develop our Wolfcamp shale oil resource play. We believe our current acreage position provides us the long-term ability to increase reserves and production at competitive costs and at attractive rates of return in a normalized commodity price environment. During 2016, we drilled six, and completed five, horizontal Wolfcamp wells. With our 2017 drilling plan, we expect to continue to develop our core properties in Project Pangea at an increased pace compared to 2016 due to a strengthened balance sheet resulting from the Exchange Transactions and recent commodity price improvement. Focusing on the Wolfcamp shale oil play allows us to use our operating, technical and regional expertise important to interpreting geological and operating trends, enhancing production rates and maximizing well recovery.

• Operate our business at or near cash-flow breakeven. In 2016, we generated $26.1 million in cash flow from operations and had capital expenditures of $19.8 million. In 2017, we have increased our expected capital expenditure budget to a range of $50 million to $70 million in response to increasing commodity prices and anticipated interest expense savings from the Initial Exchange (defined below) and the Follow-On Exchange (defined below) (together, the “Exchange Transactions”). We believe that over the long term we will be able to maintain and grow production out of operating cash flow. We have the operational flexibility to adjust our capital spending upward in response to a continued commodity price recovery. Operating our business at or near operating cash flow allows us to preserve liquidity so that we will be able to accelerate execution of our long-term strategy should commodity prices further recover. Because we operate 100% of our reserve base, we also have the flexibility to adjust our capital budget downward in response to commodity price decreases.

• Operate our properties as a low-cost producer. We believe our concentrated acreage position in the Midland Basin enables us to capture economies of scale and operating efficiencies. Through our investment in extensive integrated field infrastructure, including water transportation and recycling systems, centralized production facilities, gas lift lines and salt water disposal wells, we have significantly reduced drilling and completion costs, per-unit lease operating expenses and our fresh water use over the last three years. In addition, because we operate 100% of our reserve base, we are able to better manage timing and scope of capital expenditures and control costs.

• Further strengthen our balance sheet and preserve financial flexibility. On November 2, 2016, we entered into an exchange agreement (the “Exchange Agreement”) with the largest holder of our 7% Senior Notes due 2021 (the “Senior Notes”) under which we exchanged $130,552,000 principal amount of our Senior Notes for 39,165,600 newly issued shares of our common stock (the “Initial Exchange”). We also have offered to exchange our remaining $99,768,000 principal amount of outstanding Senior Notes for shares of our common stock at a ratio of 276 shares of common stock for each $1,000 principal amount of the Senior Notes (the “Follow-On Exchange”). The Initial Exchange closed on January 27, 2017, resulting in future interest savings of approximately $40 million, which will provide us the flexibility to increase our capital budget out of operating cash flow. We anticipate the Follow-On Exchange will close on or around March 22, 2017.

• Acquire strategic and complementary assets. We continually review opportunities to acquire producing properties, undeveloped acreage and drilling prospects. We focus particularly on opportunities where we believe our operational efficiency, reservoir management and geological expertise in unconventional oil and gas properties will enhance value and performance. We remain focused on unconventional resource opportunities, but we will also look at conventional opportunities based on individual project economics.

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• Mitigate commodity price volatility. We enter into commodity derivative contracts to partially mitigate the risk of commodity price volatility. For 2016, we hedged approximately 59% and 65% of our oil and gas production, respectively, which resulted in a realized gain on commodity derivatives of $6.1 million. For 2017, we currently have 8,400,000 MMBtu of gas hedged at an average floor price of $2.79 per MMBtu and an average ceiling price of $3.15 per MMBtu and 709,750 Bbls of NGLs hedged at average prices of $11.34 per Bbl (C2-ethane), $27.92 per Bbl (C3-propane), $36.73 per Bbl (IC4-isobutane) and $35.92 per Bbl (NC4-butane). For 2018, we currently have 5,400,000 MMBtu of gas hedged at an average price of $3.08 per MMBtu.

Our Competitive Strengths

We have a number of competitive strengths, which we believe will help us to successfully execute our business strategies:

• Lower-risk, liquids-rich asset base. We have assembled a strong asset base within the Midland Basin, where we have a long history of operating. We have drilled more than 790 wells in the area since 2004. Our acreage position of 137,000 gross, primarily contiguous acres in the Midland Basin provides us with a multi-year inventory of repeatable, horizontal and vertical drilling locations that we believe create the opportunity for us to deliver long-term reserve, production and cash flow growth. Production for 2016 was 62% liquids (28% oil and 34% NGLs) and 38% natural gas.  With a liquids-rich but diverse production base, we are able to capture the upside of improvement in commodity prices in any one of our three production streams.

• High degree of operational control.  We operate 100% of our estimated proved reserves, and we have approximately 100% working interest in Project Pangea. This allows us to more effectively manage and control the timing of capital spending on our development activities, as well as maximize benefits from operating cost efficiencies and field infrastructure systems.

• Proactive financial management.  In 2016, we generated $26.1 million in operating cash flow, incurred $19.8 million of capital expenditures and had no increase in the principal balance of our debt outstanding.  As of December 31, 2016, we had liquidity of approximately $51.4 million. In addition, we are committed to a disciplined capital program and improving our operating cash flow. We are strengthening our balance sheet through the Exchange Transactions, which will enhance our liquidity position. We also enter into commodity derivative contracts to partially mitigate the risk of commodity price volatility.

• Experienced management team with track record of growth. Our management team has extensive industry experience, including significant technical and exploration expertise. Our management team has specific expertise in the Permian Basin and in successfully executing multi-year development drilling programs.

2016 Activity

Our 2016 activity focused on operating within cash flow while managing production declines, improving our cost structure and strengthening our balance sheet. We drilled six, and completed five, horizontal wells in 2016 in the Wolfcamp shale oil resource play in the Midland Basin. We plan to continue to develop the Wolfcamp shale in Project Pangea in 2017, at a measured, but increased pace from 2016, subject to commodity prices. Our activities in 2016 included:

• Managed production decline. In 2016, we reduced our capital expenditures by $131.4 million, to $19.8 million. During the first quarter of 2016, our production declined by 12% compared to the prior quarter due to no new well completions from August 2015 through the first quarter of 2016 and natural production decline. Our production decreased by 1%, 3% and 1% in the second, third and fourth quarters of 2016, respectively. We managed our natural production decline through operating efficiencies and investment in well repairs, workovers and maintenance. Production for 2016 totaled 4.5 MMBoe (12.4 MBoe/d), compared to 5.5 MMBoe (15.2 MBoe/d) in 2015. Production for 2016 was 28% oil, 34% NGLs and 38% natural gas. At December 31, 2016, six wells were waiting on completion.

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• Operated within operating cashflow. In 2016, we generated $26.1 million in operating cash flow, incurred $19.8 million of capital expenditures and had no increase in the principal balance of our debt outstanding.

• Reduced operating expenses to improve operating cash flow. In 2016, through our cost saving initiatives, we reduced lease operating expenses by $9.7 million, general and administrative expenses by $3.6 million and production and ad valorem taxes by $2.9 million.  

• Strengthened our balance sheet.  On November 2, 2016, we entered into the Exchange Agreement. In January 2017, we closed the Initial Exchange and launched the Follow-On Exchange. The Initial Exchange reduced our long-term debt by $130.6 million and will result in future interest savings of approximately $40 million. The Follow-On Exchange, if closed, is expected to further reduce our debt and improve our operating cash flow through the reduction of interest expense.

• Delineation of the multi-zone potential of the Wolfcamp shale. The Wolfcamp shale has a gross pay thickness of approximately 1,000 to 1,200 feet, which allows for stacked wellbores targeting three different zones that we call “benches.” We believe effectively developing the Wolfcamp shale may involve up to three lateral wellbores, each targeting a different bench, which we refer to as the Wolfcamp A, B and C. As of December 31, 2016, we had drilled and completed a total of 17 wells targeting the Wolfcamp A bench, 106 wells targeting the Wolfcamp B bench and 46 wells targeting the Wolfcamp C bench. We have successful wells targeting each of the Wolfcamp benches, and we continued development of the Wolfcamp shale in 2016.

• Installation of field infrastructure and water handling systems. Our large, mostly contiguous acreage position and our success in the Wolfcamp shale oil play led us to invest over $115 million in building field infrastructure since 2012. We now have an extensive network of centralized production facilities, water transportation, handling and recycling systems, gas lift lines and salt water disposal wells. In addition, we believe the infrastructure reduces the need for trucks, reduces fresh water usage, improves drilling and completion efficiencies and drives down drilling and completion and operating costs. In large part due to this infrastructure investment, we were able to reduce our lease operating expenses per Boe by 19% to $4.24, and our drilling and completion cost by 22% to $3.5 million, in 2016.

Plans for 2017

In January 2017, we closed the Initial Exchange and issued 39,165,600 shares of common stock in exchange for Senior Notes with a principal amount of $130,552,000. Additionally, we launched the Follow-On Exchange offering shares of our common stock, at a ratio of 276 shares of common stock per $1,000 principal amount of our Senior Notes, to the holders of our remaining $99,768,000 principal amount of outstanding Senior Notes. We anticipate closing the Follow-On Exchange on or around March 22, 2017. Assuming full participation in the Follow-On Exchange, together with the Initial Exchange, we would reduce our cash interest payments by $13.9 million in 2017 and by $69.5 million over the term of the Senior Notes. This will provide us the flexibility to use the interest savings to invest in our capital budget, to continue to reduce long-term debt or for other corporate purposes. There are no minimum subscription requirements for the Follow-On Exchange, and we cannot predict participation levels.

For 2017, we increased our capital expenditure budget to a range of $50 million to $70 million, compared to $19.8 million of capital expenditures in 2016. We currently have one rig running. Our 2017 capital budget excludes acquisitions and lease extensions and renewals and is subject to change depending upon a number of factors, including prevailing and anticipated prices for oil, NGLs and gas, results of horizontal drilling and completions, economic and industry conditions at the time of drilling, the availability of sufficient capital resources for drilling prospects, our financial results and the availability of lease extensions and renewals on reasonable terms. Although the impact of changes in these collective factors in the current commodity price environment is difficult to estimate, we currently expect to execute our development plan based on current conditions. To the extent there is a significant increase or decrease in commodity prices in the future, we will assess the impact on our development plan at that time, and we may respond to such changes by altering our capital budget or our development plan.

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Markets and Customers

The revenues generated by our operations are highly dependent upon the prices of oil, NGLs and natural gas. Oil, NGLs and natural gas are commodities, and therefore, we receive market-based pricing. The price we receive for our oil, NGLs and natural gas production depends on numerous factors beyond our control, including supply and demand for oil, NGLs and gas, seasonality, the condition of the domestic and global economies, particularly in the manufacturing sectors, political conditions in other oil and gas producing countries, the extent of domestic production and imports of oil, NGLs and gas, the proximity and capacity of gas pipelines and other transportation facilities, seasonality, the marketing of competitive fuels and the effects of federal, state and local regulation. The oil and gas industry also competes with other industries in supplying the energy and fuel requirements of industrial, commercial and individual consumers.

For the year ended December 31, 2016, sales to JP Energy Development, LP (“JP Energy”) and DCP Midstream, LP (“DCP”) accounted for approximately 54% and 46%, respectively, of our total sales. As of December 31, 2016, we had dedicated all of our oil production from northern Project Pangea and Pangea West through September 2022 to JP Energy. In addition, as of December 31, 2016, we had dedicated all of our NGLs and natural gas production from Project Pangea to DCP through August 2023.

Commodity Derivative Activity

We enter into commodity swap and collar contracts to mitigate portions of the risk of market price fluctuations related to future oil, NGLs and gas production. Our derivative contracts are recorded as derivative assets and liabilities at fair value on our balance sheet, and the change in a derivative contract’s fair value is recognized as current income or expense on our consolidated statements of operations.

In 2016, we realized $6.1 million in gains from our derivatives contracts, and the estimated fair value of our derivatives contracts at December 31, 2016, was a liability of $4.9 million. For 2017, we currently have 8,400,000 MMBtu of gas hedged at an average floor price of $2.79 per MMBtu and an average ceiling price of $3.15 per MMBtu and 709,750 Bbls of NGLs at average prices of $11.34 per Bbl (C2-ethane), $27.92 per Bbl (C3-propane), $36.73 per Bbl (IC4-isobutane) and $35.92 per Bbl (NC4-butane). For 2018, we currently have 5,400,000 MMBtu of gas hedged at an average price of $3.08 per MMBtu.

Title to Properties

Our properties are subject to customary royalty interests, liens incident to operating agreements, liens for current taxes and other burdens, including other mineral encumbrances and restrictions. We do not believe that any of these burdens materially interfere with our use of the properties in the operation of our business.

We believe that we generally have satisfactory title to or rights in all of our producing properties. As is customary in the oil and gas industry, we make a general investigation of title at the time we acquire undeveloped properties. We receive title opinions of counsel before we commence drilling operations. We believe that we have satisfactory title to all of our other assets. Although title to our properties is subject to encumbrances in certain cases, we believe that none of these burdens will materially detract from the value of our properties or from our interest therein or will materially interfere with our use of the properties in the operation of our business.

Oil and 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, NGLs and natural gas produced from any wells drilled on the leased premises. The lessor royalties and other leasehold burdens on our properties generally range from 20% to 25%, resulting in a net revenue interest to us generally ranging from 80% to 75%.

Seasonality

Demand for NGLs and natural gas generally decreases during the spring and fall months and increases during the summer and winter months. However, seasonal anomalies such as mild winters or mild summers sometimes

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lessen this fluctuation. In addition, certain natural gas users utilize storage facilities and purchase some of their anticipated winter requirements during the summer. This can also lessen seasonal demand fluctuations. These seasonal anomalies can increase competition for equipment, supplies and personnel during the spring and summer months, which could lead to shortages and increase costs or delay our operations.

Competition

The oil and gas industry is highly competitive, and we compete for personnel, prospective properties, producing properties and services with a substantial number of other companies that have greater resources. Many of these companies explore for, produce and market oil and gas, carry on refining operations and market the end products on a worldwide basis. We also face competition from alternative fuel sources, including coal, heating oil, imported LNG, nuclear and other nonrenewable fuel sources, and renewable fuel sources such as wind, solar, geothermal, hydropower and biomass. Competitive conditions may also be substantially affected by various forms of energy legislation and/or regulation considered from time-to-time by the United States government. It is not possible to predict whether such legislation or regulation may ultimately be adopted or its precise effects upon our future operations. Such laws and regulations may, however, substantially increase the costs of exploring for, developing or producing oil, NGLs and gas and may prevent or delay the commencement or continuation of our operations.

Hydraulic Fracturing

Hydraulic fracturing is an important process in oil and gas production and has been commonly used in the completion of unconventional oil and gas wells in shale and tight sand formations since the 1950s. Hydraulic fracturing involves the injection of water, sand and chemical additives under pressure into rock formations to stimulate oil and gas production. It is important to us because it provides access to oil and gas reserves that previously were uneconomical to produce.

We have used hydraulic fracturing to complete both horizontal and vertical wells in the Permian Basin. We engage third parties to provide hydraulic fracturing services to us for completion of these wells. While hydraulic fracturing is not required to maintain our leasehold acreage that is currently held by production from existing wells, it will be required in the future to develop the proved undeveloped reserves associated with this acreage. All of our proved undeveloped reserves associated with future drilling will require hydraulic fracturing.

We believe we have followed, and intend to continue to follow, applicable industry standard practices and legal requirements for groundwater protection in our operations that are subject to supervision by state regulators. These protective measures include setting surface casing at a depth sufficient to protect fresh water zones as determined by applicable state regulatory agencies and cementing the well to create a permanent isolating barrier between the casing pipe and surrounding geological formations. This aspect of well design is intended to prevent contact between the fracturing fluid and any aquifers during the hydraulic fracturing operations. For recompletions of existing wells, the production casing is pressure-tested before perforating the new completion interval.

Injection rates and pressures are monitored at the surface during our hydraulic fracturing operations. Pressure is monitored on both the injection string and the immediate annulus to the injection string. We believe we have adequate procedures in place to address abrupt changes to the injection pressure or annular pressure.

Texas regulations currently require disclosure of the components in the solutions used in hydraulic fracturing operations. More than 99% (by mass) of the ingredients we use in hydraulic fracturing are water and sand. The remainder of the ingredients are chemical additives that are managed and used in accordance with applicable requirements.

Hydraulic fracturing requires the use of a significant amount of water. Upon flowback of the water, we dispose of it in a way that we believe minimizes the impact to nearby surface water by disposing into approved disposal facilities or injection wells. Currently our primary sources of water in Project Pangea are the nonpotable Santa Rosa and potable Edwards-Trinity (Plateau) aquifers. We use water from on-lease water wells that we have

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drilled, and we purchase water from off-lease water wells. We have historically reused and recycled flowback and produced water and intend to do so in the future.

For information regarding existing and proposed governmental regulations regarding hydraulic fracturing and related environmental matters, please read “Business — Regulation — Environmental Laws and Regulation.” For related risks to our stockholders, please read “Risk Factors — Federal and state legislation and regulatory initiatives and private litigation relating to hydraulic fracturing could stop or delay our development project and result in materially increased costs and additional operating restrictions.”

Regulation

The oil and gas industry in the United States is subject to extensive regulation by federal, state and local authorities. At the federal level, various federal rules, regulations and procedures apply, including those issued by the U.S. Department of Interior, the U.S. Department of Transportation (the “DOT”) (Office of Pipeline Safety) and the U.S. Environmental Protection Agency (the “EPA”). At the state and local level, various agencies and commissions regulate drilling, production and midstream activities. These federal, state and local authorities have various permitting, licensing and bonding requirements. Various remedies are available for enforcement of these federal, state and local rules, regulations and procedures, including fines, penalties, revocation of permits and licenses, actions affecting the value of leases, wells or other assets, suspension of production, and, in certain cases, criminal prosecution. As a result, there can be no assurance that we will not incur liability for fines, penalties or other remedies that are available to these federal, state and local authorities. However, we believe that we are currently in material compliance with federal, state and local rules, regulations and procedures, and that continued substantial compliance with existing requirements will not have a material adverse effect on our financial position, cash flows or results of operations.

Transportation and Sale of Oil

Sales of crude oil and condensate are not currently regulated and are made at negotiated prices. Our sales of crude oil are affected by the availability, terms and cost of transportation. Interstate transportation of oil by pipeline is regulated by the Federal Energy Regulation Commission (“FERC”) pursuant to the Interstate Commerce Act (“ICA”), Energy Policy Act of 1992 (“EPAct 1992”), and the rules and regulations promulgated under those laws. The ICA and its regulations require that tariff rates for interstate service on oil pipelines, including interstate pipelines that transport crude oil and refined products, be just and reasonable and non-discriminatory and that such rates, terms and conditions of service be filed with FERC.

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

Further, interstate and intrastate common carrier oil pipelines must provide service on a non-discriminatory basis. Under this open access standard, common carriers must offer service to all similarly situated shippers requesting service on the same terms and under the same rates. When oil pipelines operate at full capacity, access is governed by prorationing provisions set forth in the pipelines’ published tariffs. Accordingly, we believe that access to oil pipeline transportation services generally will be available to us to the same extent as to our similarly situated competitors.

The transportation of oil by truck is also subject to federal, state and local rules and regulations, including the Federal Motor Carrier Safety Act and the Homeland Security Act of 2002. Regulations under these statutes cover the security and transportation of hazardous materials and are administered by the DOT.

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Transportation and Sale of Natural Gas and NGLs

FERC regulates interstate gas pipeline transportation rates and service conditions under the Natural Gas Act of 1938, the Natural Gas Policy Act of 1978 and regulations issued under those statutes. FERC also regulates interstate NGLs pipelines under various federal laws and regulations. Although FERC does not regulate oil and gas producers such as Approach, FERC’s actions are intended to facilitate increased competition within all phases of the oil and gas industry and its regulation of third-party pipelines and facilities could indirectly affect our ability to transport or market our production. To date, FERC’s policies have not materially affected our business or operations.

Regulation of Production

Oil, NGLs and gas production is regulated under a wide range of federal and state statutes, rules, orders and regulations. State and federal statutes and regulations require permits for drilling operations, drilling bonds and reports concerning operations. The state in which we operate, Texas, has regulations governing conservation matters, including provisions for the unitization or pooling of oil and gas properties, the establishment of maximum rates of production from oil and gas wells, the regulation of spacing, and requirements for plugging and abandonment of wells. Also, Texas imposes a severance tax on production and sales of oil, NGLs and gas within its jurisdiction. The failure to comply with these rules and regulations can result in substantial penalties. Our competitors in the oil and gas industry are subject to the same regulatory requirements and restrictions that affect our operations.

Environmental Laws and Regulations

In the United States, the exploration for and development of oil and gas and the drilling and operation of wells, fields and gathering systems are subject to extensive federal, state and local laws and regulations governing environmental protection and the release of materials into the environment. These laws and regulations may, among other things:

• require the acquisition of various permits or authorizations before drilling begins;

• require the installation of expensive pollution controls or emissions monitoring equipment;

• restrict the types, quantities and concentration of various substances that can be released into the environment in connection with oil and gas drilling, completion, production, transportation and processing activities;

• suspend, limit or prohibit construction, drilling and other activities in certain lands lying within wilderness, wetlands, endangered species habitat and other protected areas; and

• require remedial measures to mitigate and remediate pollution from historical and ongoing operations, such as the closure of waste pits and plugging of abandoned wells.

These laws, rules and regulations may also restrict the rate of oil and gas production below the rate that would otherwise be possible. The regulatory burden on the oil and gas industry increases the cost of doing business in the industry and consequently affects profitability.

Governmental authorities have the power to enforce compliance with environmental laws, regulations and permits, and violations are subject to injunction, as well as administrative, civil and criminal penalties. The effects of existing and future laws and regulations could have a material adverse impact on our business, financial condition and results of operations. The clear trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment. Any changes in environmental laws and regulations or re-interpretations 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 business, financial condition or results of operations. Moreover, accidental releases or spills and ground water or surface water contamination may occur in the course of our operations, and we may incur significant costs and liabilities as a result of such releases, spills or contamination, including any third-party claims for damage to property, natural resources or persons. We maintain insurance against costs of clean-up operations, but we are not fully insured against all such risks. While we believe that we are in substantial compliance with existing environmental laws and regulations and that continued

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compliance with current requirements would not have a material adverse effect on us, there is no assurance that this will continue in the future.

The following is a summary of some of the existing environmental laws, rules and regulations that apply to our business operations. It remains unclear what actions, if any, the Trump administration will undertake related to these laws, rules and regulations.

Hazardous Substance Release

The Comprehensive Environmental Response, Compensation and Liability Act of 1980 (“CERCLA”), also known as the Superfund law, and comparable state statutes impose strict liability, and under certain circumstances, joint and several liability, on classes of persons who are considered to be responsible for the release of a hazardous substance into the environment. These persons include the owner or operator of the site where the release occurred, and anyone who disposed or arranged for the disposal of a hazardous substance released at the site, regardless of whether the disposal of hazardous substances was lawful at the time of the disposal. Under CERCLA, such persons may be subject to strict, joint and several liabilities for the costs of investigating releases of hazardous substances, 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. In addition, it is not uncommon for neighboring landowners and other third-parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. Crude oil and fractions of crude oil are excluded from regulation under CERCLA. Nevertheless, many chemicals commonly used at oil and gas production facilities fall outside of the CERCLA petroleum exclusion. While we generate materials in the course of our operations that may be regulated as hazardous substances, we have not received notification that we may be potentially responsible for cleanup costs under CERCLA.

Waste Handling

The Resource Conservation and Recovery Act (“RCRA”) and comparable state statutes regulate the generation, transportation, treatment, storage, disposal and cleanup of hazardous and non-hazardous wastes. Under the auspices of the EPA, the individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. Drilling fluids, produced water and most of the other wastes associated with the exploration, development and production of oil or gas are currently regulated under RCRA’s non-hazardous waste provisions. However, it is possible that certain oil and gas exploration and production wastes now classified as non-hazardous could be classified as hazardous wastes in the future. Any such change could increase our operating expenses, which could have a material adverse effect on our business, financial condition and results of operations.

We currently own or lease properties that for many years have been used for oil and gas exploration, production and development activities. Although we used operating and disposal practices that were standard in the industry at the time, petroleum hydrocarbons or wastes may have been disposed of or released on, under or from the properties owned or leased by us or on, under or from other locations where such wastes have been taken for disposal. In addition, some of these properties have been operated by third parties whose treatment and disposal or release of petroleum hydrocarbons and wastes was not under our control. These properties and the materials disposed or released on, at, under or from them may be subject to CERCLA, RCRA and analogous state laws. Under such laws, we could be required to remove or remediate previously disposed wastes or contamination, or to perform remedial activities to prevent future contamination.

Air Emissions

The federal Clean Air Act (“CAA”) and comparable state laws regulate emissions of various air pollutants through air emissions, permitting programs and other requirements. In addition, the EPA has developed, and continues to develop, stringent regulations governing emissions at specified sources. For example,  under the EPA’s New Source Performance Standards (“NSPS”) and National Emission Standards for Hazardous Air Pollutants (“NESHAP”) regulations,  since January 1, 2015, owners and operators of hydraulically fractured natural gas wells (wells drilled principally for the production of natural gas) have been required to use so-called “green completion” technology to recover natural gas that formerly would have been flared or vented. On May 12, 2016, the EPA issued

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three additional rules for the oil and gas industry to reduce emissions of methane, volatile organic compounds (“VOCs”) and other compounds.  These rules apply to all new, reconstructed, and modified processes and equipment since September 2015.  Among other things, the new rules impose green completion requirements on new hydraulically fractured oil wells and reduce allowable emissions of methane and VOCs. We do not expect that the NSPS or NESHAP will have a material adverse effect on our business, financial condition or results of operations. However, any future laws and their implementing regulations, may require us to obtain pre-approval for the expansion or modification of existing facilities or the construction of new facilities expected to produce air emissions, impose stringent air permit requirements or use specific equipment or technologies to control emissions. Our failure to comply with existing or new requirements could subject us to monetary penalties, injunctions, conditions or restrictions on operations and, potentially, criminal enforcement actions. We believe that we currently are in substantial compliance with all air emissions regulations and that we hold all necessary and valid construction and operating permits for our current operations.

Greenhouse Gas Emissions

While Congress has, from time-to-time, considered legislation to reduce emissions of greenhouse gases (“GHGs”), there has not been significant activity in the form of adopted legislation to reduce GHG emissions at the federal level in recent years. In the absence of such federal legislation, a number of states have taken legal measures to reduce emissions of GHGs through the planned development of GHG emission inventories and/or regional GHG cap-and-trade programs or other mechanisms. Most cap-and-trade programs work by requiring major sources of emissions, such as electric power plants, or major producers of fuels such as refineries and gas processing plants, to acquire and surrender emission allowances corresponding with their annual emissions of GHGs. The number of allowances available for purchase is reduced each year until the overall GHG emission reduction goal is achieved. As the number of GHG emission allowances declines each year, the cost or value of allowances is expected to escalate significantly. Many states have enacted renewable portfolio standards, which require utilities to purchase a certain percentage of their energy from renewable fuel sources.

In response to findings that emissions of carbon dioxide, methane and other GHGs present an endangerment to human health and the environment, the EPA has adopted regulations under existing provisions of the federal CAA. The EPA has adopted two sets of rules regarding possible future regulation of GHG emissions under the CAA, one of which purports to regulate emissions of GHGs from motor vehicles and the other of which would regulate emissions of GHGs from large stationary sources of emissions, such as power plants or industrial facilities. The motor vehicle rule was finalized in April 2010 and became effective in January 2011, but it does not require immediate reductions in GHG emissions. On August 3, 2015, the EPA issued a final rule to limit GHG emissions from new power plants. The agency simultaneously released a final rule to limit carbon emissions from existing power plants. While these regulations are currently the subject of litigation, including a stay issued by the U.S. Supreme Court, if the regulation ultimately is upheld it could have a significant impact on the electrical generation industry and may favor the use of natural gas over other fossil fuels such as coal in new plants. The EPA has also indicated that it will propose new GHG emissions standards for refineries, but we do not know when the agency will issue specific regulations.

In December 2010, the EPA enacted final rules on mandatory reporting of GHGs. In 2011, the EPA published amendments to the rule containing technical and clarifying changes to certain GHG reporting requirements and a six-month extension for reporting GHG emissions from petroleum and natural gas industry sources. Under the amended rule, certain onshore oil and natural gas production, processing, transmission, storage and distribution facilities are required to report their GHG emissions on an annual basis. Our operations in the Permian Basin are subject to the EPA’s mandatory reporting rules, and we believe that we are in substantial compliance with such rules. We do not expect that the EPA’s mandatory GHG reporting requirements will have a material adverse effect on our business, financial condition or results of operations.

The adoption of additional legislation or regulatory programs to monitor or reduce GHG emissions could require us to incur increased operating costs, such as costs to purchase and operate emissions control systems, acquire emissions allowances or comply with new regulatory requirements. In addition, the EPA has stated that the data collected from GHG emissions reporting programs may be the basis for future regulatory action to establish substantive GHG emissions factors. Any GHG emissions legislation or regulatory programs applicable to power plants or refineries could increase the cost of consuming, and thereby reduce demand for, the oil and natural gas we

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produce. Consequently, legislation and regulatory programs to reduce GHG emissions could have an adverse effect on our future business, financial condition and results of operations.

Water Discharges

The Federal Water Pollution Control Act (the “Clean Water Act”) and analogous state laws, impose restrictions and strict controls on the discharge of pollutants and fill material, including spills and leaks of oil and other substances into regulated waters, including wetlands. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA, an analogous state agency, or, in the case of fill material, the United States Army Corps of Engineers. 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.

In June 2016, the EPA issued a final rule banning the disposal of wastewater from unconventional oil and gas wells to public wastewater and sewage treatment plants. Produced and other flowback water from our current operations in the Permian Basin is typically not discharged to wastewater treatment plants but is re-injected into underground formations that do not contain potable water.

The Safe Drinking Water Act, Groundwater Protection and the Underground Injection Control Program

Fluids associated with oil and gas production result from operations on the Company’s properties and are disposed by injection in underground disposal wells. The federal Safe Drinking Water Act (“SDWA”) and the Underground Injection Control program (the “UIC program”) promulgated under the SDWA and state programs regulate the drilling and operation of salt water disposal wells. The EPA has delegated administration of the UIC program in Texas to the Railroad Commission of Texas (“RRC”). Permits must be obtained before drilling salt water disposal wells, and casing integrity monitoring must be conducted periodically to ensure the casing is not leaking saltwater to groundwater. Contamination of groundwater by oil and gas drilling, production and related operations may result in fines, penalties and remediation costs, among other sanctions and liabilities under the SDWA and state laws. In addition, third-party claims may be filed by landowners and other parties claiming damages for alternative water supplies, property damages and bodily injury.

Currently, the Company believes that disposal well operations on its properties substantially comply with all applicable requirements under the SDWA and RRC rules. However, a change in the regulations or the inability to obtain permits for new disposal wells in the future may affect the Company’s ability to dispose of produced waters and ultimately increase the cost of the Company’s operations. For example, there exists a growing concern that the injection of salt water and other fluids into underground disposal wells triggers seismic activity in certain areas, including in some parts of Texas. In response to these concerns, in October 2014, the RRC published a final rule governing permitting or re-permitting of disposal wells that would require, among other things, the submission of information on seismic events occurring within a specified radius of the disposal well location, as well as logs, geologic cross sections and structure maps relating to the disposal area in question. If the permittee or an applicant of a disposal well permit fails to demonstrate that the injected fluids are confined to the disposal zone or if scientific data indicates such a disposal well is likely to be or determined to be contributing to seismic activity, then the RRC may deny, modify, suspend or terminate the permit application or existing operating permit for that well. These new seismic permitting requirements applicable to disposal wells impose more stringent permitting requirements and are likely to result in added costs to comply or perhaps may require alternative methods of disposing of salt water and other fluids, which could delay production schedules and also result in increased costs.

Hydraulic Fracturing

Hydraulic fracturing is the subject of significant focus among some environmentalists, regulators and the general public. Concerns over potential hazards associated with the use of hydraulic fracturing and its impact on the environment have been raised at all levels, including federal, state and local, as well as internationally. There have been claims that hydraulic fracturing may contaminate groundwater, reduce air quality or cause earthquakes. Hydraulic fracturing requires the use and disposal of water, and public concern has been growing over the adequacy of water supply.

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The Energy Policy Act of 2005, which exempts hydraulic fracturing from regulation under the SDWA, prohibits the use of diesel fuel in the fracturing process without a UIC permit. In the past, legislation has been introduced in, but not passed by, Congress that would amend the SDWA to repeal this exemption. Specifically, the Fracturing Responsibility and Awareness of Chemicals Act (“FRAC Act”) has been introduced in each Congress since 2008 to accomplish these purposes. If legislation repealing the exemption were enacted, it could require hydraulic fracturing operations to meet permitting and financial assurance requirements, adhere to certain construction specifications, fulfill monitoring, reporting and recordkeeping obligations and meet plugging and abandonment requirements beyond those currently required by state regulatory agencies.

In 2010, the EPA asserted federal regulatory authority over hydraulic fracturing involving diesel additives under the UIC program by posting a requirement on its website that requires facilities to obtain permits to use diesel fuel in hydraulic fracturing operations. Following a legal challenge by industry groups and a subsequent settlement, in February 2014, the EPA issued revised guidance on the use of diesel in hydraulic fracturing operations. Under the guidance, EPA broadly defined “diesel” to include fuels such as kerosene that have not traditionally been considered diesel. The EPA’s continued assertion of its regulatory authority under the SDWA could result in extensive requirements that could cause additional costs and delays in the hydraulic fracturing process.

In addition to the above actions of the EPA, certain members of Congress have, in the past, called upon government agencies to investigate various aspects of hydraulic fracturing. Federal agencies that have been involved in hydraulic fracturing research include the White House Council on Environmental Quality, the Department of Energy, the Department of Interior and the Energy Information Administration. The EPA has also studied the potential environmental impacts of hydraulic fracturing on water resources, publishing a final report in December 2016. These and future investigations and studies, depending on their degree of pursuit and any meaningful results obtained, could facilitate initiatives to further regulate hydraulic fracturing.

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 hydraulic fracturing. For example, pursuant to legislation adopted by the State of Texas in June 2011, the RRC enacted a rule in December 2011, requiring disclosure to the RRC and the public of certain information regarding additives, chemical ingredients, concentrations and water volumes used in hydraulic fracturing. In 2015, the Texas Legislature enacted House Bill 40, which prohibits local governments from prohibiting hydraulic fracturing but allows for commercially reasonable regulations of certain activities associated with oil and gas development. If future laws or regulations that significantly restrict hydraulic fracturing or that allow greater local government regulation of hydraulic fracturing are adopted, it could become more difficult or costly for us to drill and produce oil and gas from shale and tight sands formations and become easier for third parties opposing hydraulic fracturing to initiate legal proceedings. In addition, if hydraulic fracturing is regulated at the federal level, fracturing activities could become subject to delays, additional permitting and financial assurance requirements, more stringent construction specifications, increased monitoring, reporting and recordkeeping obligations, plugging and abandonment requirements and higher costs. These new laws or regulations could cause us to incur substantial delays or suspensions of operations and compliance costs and could have a material adverse effect on our business, financial condition and results of operations.

Compliance

We believe that we are in substantial compliance with all existing environmental laws and regulations that apply to our current operations and that our ongoing compliance with existing requirements will not have a material adverse effect on our business, financial condition or results of operations. We did not incur any material expenditures for remediation or pollution control activities for the year ended December 31, 2016. In addition, as of the date of this report, we are not aware of any environmental issues or claims that will require material capital or operating expenditures during 2017. However, the passage of additional or more stringent laws or regulations in the future could have a negative effect on our business, financial condition and results of operations, including our ability to develop our undeveloped acreage.

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Threatened and Endangered Species, Migratory Birds and Natural Resources

Various state and federal statutes prohibit certain actions that adversely affect endangered or threatened species and their habitat, migratory birds, wetlands and natural resources. These statutes include the Endangered Species Act, the Migratory Bird Treaty Act, the Clean Water Act and CERCLA. The United States Fish and Wildlife Service may designate critical habitat and suitable habitat areas that it believes are necessary for the survival of threatened or endangered species. A critical habitat or suitable habitat designation could result in further material restrictions to federal land use and private land use and could delay or prohibit land access or development. Where takings of, or harm to, species or damages to wetlands, habitat or natural resources occur or may occur, government entities or at times private parties may act to prevent oil and gas exploration activities or seek damages for harm to species, habitat or natural resources resulting from drilling or construction or releases of oil, wastes, hazardous substances or other regulated materials, and may seek natural resources damages and, in some cases, criminal penalties.

OSHA and Other Laws and Regulations

We are subject to the requirements of the federal Occupational Safety and Health Act (“OSHA”) and comparable state statutes. The OSHA hazard communication standard, the EPA community right-to-know regulations under Title III of CERCLA and similar state statutes require that we organize and/or disclose information about hazardous materials used or produced in our operations. These laws also require the development of risk management plans for certain facilities to prevent accidental releases of pollutants. We believe that we are in substantial compliance with these applicable requirements and with other OSHA and comparable requirements.

Employees

As of February 22, 2017, we had 100 full-time employees, 61 of whom are field personnel. We regularly use independent contractors and consultants to perform various field and other services. None of our employees are represented by a labor union or covered by any collective bargaining agreement. We believe that our relations with our employees are excellent.

Insurance Matters

As is common in the oil and gas industry, we will not insure fully against all risks associated with our business either because such insurance is not available or because premium costs are considered prohibitive. A loss not fully covered by insurance could have a material adverse effect on our business, financial condition and results of operations.

Available Information

We maintain an internet website under the name www.approachresources.com. The information on our website is not a part of this report. We make available, free of charge, on our website, our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports, as soon as reasonably practical after providing such reports to the SEC. Also, the charters of our Audit Committee, Compensation Committee and Nominating and Corporate Governance Committee, our Lead Independent Director Charter, our Governance Guidelines and our Code of Conduct are available on our website and in print to any stockholder who provides a written request to the Corporate Secretary at One Ridgmar Centre, 6500 West Freeway, Suite 800, Fort Worth, Texas 76116.

We file annual reports on Form 10-K, quarterly reports on Form 10-Q and current reports on Form 8-K, proxy statements and other documents with the SEC under the Exchange Act. The public may read and copy any materials that we file with the SEC at the SEC’s Public Reference Room at 100 F Street, NE, Washington DC 20549. The public may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. Also, the SEC maintains an internet website that contains reports, proxy and information statements, and other information regarding issuers, including Approach, that file electronically with the SEC. The public can obtain any document we file with the SEC at www.sec.gov. Information contained on or connected to our website is not

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incorporated by reference into this Form 10-K and should not be considered part of this report or any other filing that we make with the SEC.

ITEM 1A. RISK FACTORS

You should carefully consider the risk factors set forth below as well as the other information contained in this report before investing in our common stock. Any of the following risks could materially and adversely affect our business, financial condition and results of operations. In such a case, you may lose all or part of your investment. The risks described below are not the only ones we face. Additional risks and uncertainties not currently known to us, or those we currently view as immaterial, may also materially adversely affect our business, financial condition and results of operations.

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

Our future financial condition and results of operations will depend on commodity prices and the success of our drilling, exploration and production activities. These factors are subject to numerous risks beyond our control, including the risk that drilling will not result in economic oil and gas production or increases in reserves. Many factors may curtail, delay or cancel our scheduled development projects, including:

• declines in oil, NGLs and gas prices;

• inadequate capital resources or liquidity to maintain current production levels or further develop our assets;

• compliance with governmental regulations, which may include limitations on hydraulic fracturing, access to water or the discharge of GHGs;

• limited transportation services and infrastructure to deliver the oil, NGLs and natural gas we produce to market;

• inability to attract and retain qualified personnel;

• unavailability or high cost of drilling and completion equipment, services or materials;

• unexpected drilling conditions, pressure or irregularities in formations, equipment failures or accidents;

• lack of acceptable prospective acreage;

• adverse weather conditions;

• surface access restrictions;

• title problems;

• mechanical difficulties;

• natural disasters; and

• civil unrest or protest activities.

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Oil, NGLs and gas prices are volatile and have declined significantly in recent years. Sustained declines in oil, NGLs or gas prices from current levels would adversely affect our business, financial condition and results of operations and our ability to meet our capital expenditure requirements and financial commitments.

Our revenues, profitability and cash flow depend on the prices and demand for oil, NGLs and gas. The markets for these commodities are volatile, and even relatively modest drops in prices can affect significantly our financial results and impede our growth. Prices for oil, NGLs and gas fluctuate widely in response to changes in the supply and demand for these commodities, market uncertainty and a variety of additional factors beyond our control, such as:

• domestic and foreign supply of oil, NGLs and gas;

• domestic and foreign consumer demand for oil, NGLs and gas;

• overall United States and global economic conditions impacting the global supply of and demand for oil, NGLs and gas;

• actions of OPEC, its members and other state-controlled oil companies relating to oil price and production controls;

• commodity processing, gathering and transportation availability, the availability of refining capacity and other factors that result in differentials to benchmark prices;

• price and availability of alternative fuels;

• price and quantity of foreign imports;

• domestic and foreign governmental regulations;

• political conditions in or affecting other oil and natural gas producing countries;

• weather conditions, including unseasonably warm winter weather and tropical storms; and

• technological advances affecting oil, NGLs and gas consumption.

Advanced drilling and completion technologies, such as horizontal drilling and hydraulic fracturing, have resulted in increased investment by oil and gas producers in developing U.S. shale oil and gas projects and, therefore, has resulted in increased production from these projects. The results of higher investment in the exploration for and production of U.S. shale oil and gas, maintenance of production levels of oil from the Middle East, and other factors, such as global economic and financial conditions, have caused the price of oil and gas to be volatile. For example, prices for NYMEX-WTI ranged from a high of $54.06 per Bbl to a low of $26.21 per Bbl in 2016. NYMEX-Henry Hub natural gas prices ranged from a high of $3.93 per MMBtu to a low of $1.64 per MMBtu in 2016. While prices have increased from recent lows, they are still significantly below previous highs. Declines in oil and natural gas prices from current levels may further reduce our level of exploration, drilling and production activity and cash flows.

The Company’s financial position, results of operations, access to capital and the amount of oil and gas that may be economically produced would be negatively impacted if oil and gas prices decline from current levels for an extended period of time.

The ways that a decline in oil and gas prices from current levels could affect us include the following:

• Cash flows would be reduced, decreasing funds available for capital expenditures needed to maintain or increase production and replace reserves;

• We may breach covenants in our revolving credit facility;

• Future net cash flows from our properties would decrease, which could result in significant impairment expenses;

• Some reserves would no longer be economic to produce, leading to lower proved reserves, production and cash flows;

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• Access to capital, such as equity or long-term debt markets and current reserve-based lending levels, would be severely limited or unavailable; and

• The borrowing base under our revolving credit facility could be reduced as further discussed below, and if the amount outstanding under our revolving credit facility exceeds the borrowing base, we may be required to repay a portion of our outstanding borrowings.

If commodity prices decline from the current levels, our future cash flows will not be sufficient to fund the capital expenditure levels necessary to maintain current production and reserve levels over the long term and our results of operations will be adversely affected.

Low oil and gas prices not only cause our revenues and cash flows to decrease but also reduce the amount of oil and gas that we can produce economically. Decreases in oil and gas prices will render uneconomic some or all of our drilling locations. This may result in our having to impair our oil and gas properties further and could have a material adverse effect on our business, financial condition and results of operations. In addition, if oil, NGLs or gas prices further decline or fail to recover from their current levels for an extended period of time, we may, among other things, be unable to maintain or increase our borrowing capacity, repay current or future debt or obtain additional capital on attractive terms, all of which can affect the value of our common stock. The amount available for borrowing under our revolving credit facility is subject to a borrowing base, which is determined by our lenders taking into account our estimated proved reserves and is subject to semi-annual redeterminations based on pricing models determined by the lenders at such time. The decline in oil and gas prices has adversely impacted the value of our estimated proved reserves and, in turn, the market values used by our lenders to determine our borrowing base.

If the Follow-On Exchange is not successful, we may seek alternative refinancing transactions.

We have been actively engaged in the process of analyzing various options to address our liquidity as well as assessing our overall capital structure. On January 27, 2017, we closed the Initial Exchange of $130,552,000 principal amount of our Senior Notes for 39,165,600 shares of newly issued shares of common stock, par value $0.01 per share. On January 30, 2017, we launched the Follow-On Exchange. If the Follow-On Exchange is not successful, we may determine to evaluate alternative transactions designed to reduce leverage and increase liquidity and operating cash flow. These alternative transactions may not be as advantageous to the existing holders of our common stock as the Follow-On Exchange. Some of these alternatives may include additional debt buybacks, debt-for-debt or debt-for-equity exchanges or refinancings, strategic investments and joint ventures, sales of assets or working interests, private or public equity raises or rights offerings or transactions which may have a more dilutive effect on our existing stockholders than the Follow-On Exchange.

The issuance of our common stock in connection with the Follow-On Exchange may cause substantial dilution, which could materially affect the trading price of our Common Stock.

If the maximum number of shares of common stock issuable is issued in connection with the Follow-On Exchange, these shares would represent approximately 25% of our outstanding shares of common stock.  These issuances could result in substantial decreases to our stock price.  In addition, subject to the terms of the Stockholders Agreement between the former largest holder of our Senior Notes (the “Equitizing Noteholder”) and the Company (the “Stockholders Agreement”), our existing stockholders may have reduced input on matters for which a stockholder vote is requested or required.

The Initial Exchange transaction concentrated significant voting power in the hands of one stockholder.

The Initial Exchange transaction resulted in a significant concentration of voting power held by the Equitizing Noteholder.  Even assuming full participation in the Follow-On Exchange, the Equitizing Noteholder will continue to be the Company’s largest individual stockholder immediately after the Follow-On Exchange.  Subject to the restrictions set forth in the Stockholders Agreement, the Equitizing Noteholder may have significant input on matters for which a stockholder vote is requested or required.

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The completion of the Follow-On Exchange is expected to result in a significant limitation on the use of our federal net operating loss carryforwards (“NOLs”), which could have a material adverse effect on our tax position.

A change in ownership of our common stock by more than 50% within a three-year period would result in a substantial portion of our NOLs being eliminated or becoming restricted, and we would need to reduce our deferred tax assets reflecting the restricted use of these NOLs when such an ownership change occurs. An ownership change would establish an annual limitation on the amount of our pre-change NOLs that we could use to offset our taxable income in any future taxable year to an amount generally equal to the value of our common stock immediately before the ownership change multiplied by the federal long-term tax exempt rate for the month of the ownership change. We do not expect that the Initial Exchange resulted in a change of ownership of 50% or more of our common stock; however, the Follow-On Exchange, or another significant acquisition of our common stock, may result in such an ownership change. We believe that we may be able to offset, in part, such limitation through our potential to generate NOLs in the future, and may be able to use otherwise limited NOLs to the extent we recognize, or are treated as recognizing, built-in gain on assets owned before the ownership change. If such an ownership change occurs as a result of the Follow-On Exchange, we estimate that we could recognize a non-recurring non-cash charge, in our statement of operations for the three months ended March 31, 2017, in the range of $100 million to $130 million, due to change in our deferred tax assets.

Our business requires significant capital expenditures, and we may not be able to obtain needed capital or financing on satisfactory terms or at all.

Our exploration, development and acquisition activities require substantial capital expenditures. For example, according to our year-end 2016 reserve report, the estimated future capital required to develop our current proved oil and gas reserves is $808.8 million. Historically, we have funded our capital expenditures through a combination of cash flows from operations, borrowings under our revolving credit facility and public equity and debt financings. In 2016, we funded our capital expenditures through cash flows from operations. Future cash flows are subject to a number of variables, including the production from existing wells, prices of oil, NGLs and gas and our success in developing and producing new reserves. If commodity prices decline from current levels, our cash flow from operations may not be sufficient to cover our current or future capital expenditure budgets, and we may have limited ability to obtain the additional capital necessary to fully develop our proved reserves. In addition we may not be able to obtain debt or equity financing on favorable terms or at all. The failure to obtain additional financing could cause us to scale back our exploration and development operations, which in turn would lead to a decline in our oil and gas production and reserves, and in some areas a loss of properties.

We may not be able to generate enough cash flow to meet our debt obligations.

We expect our earnings and cash flow to vary significantly from year to year due to the nature of our industry. As a result, the amount of debt that we can manage in some periods may not be appropriate for us in other periods. Additionally, our future cash flow may be insufficient to meet our debt obligations and other commitments, including our obligations under our $99.8 million principal amount of Senior Notes, after the Initial Exchange, and $273 million in outstanding borrowings under our revolving credit facility. A range of economic, competitive, business and industry factors will affect our future financial performance, and, as a result, our ability to generate cash flow from operations and to pay our debt. Many of these factors, such as oil and gas prices, economic and financial conditions in our industry and the global economy and initiatives of our competitors, are beyond our control. If we do not generate enough cash flow from operations to satisfy our debt obligations, we may have to undertake alternative financing plans, such as:

• selling assets;

• reducing or delaying capital investments;

• seeking to raise additional capital; or

• refinancing or restructuring our remaining debt.

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If, for any reason, we are unable to meet our debt service and repayment obligations, we would be in default under the terms of the agreements governing our debt, which would allow our creditors at that time to declare all outstanding indebtedness to be due and payable, which could in turn trigger cross-acceleration or cross-default rights between the relevant agreements. In addition, our lenders could compel us to apply all of our available cash to repay our borrowings, or they could prevent us from making payments on the Senior Notes. If amounts outstanding under our revolving credit facility or the Senior Notes were to be accelerated, we cannot be certain that our assets would be sufficient to repay in full the money owed to the lenders or to our other debt holders.

Our lenders can limit our borrowing capabilities, which may materially impact our operations.

At December 31, 2016, we had $273 million in borrowings outstanding under our revolving credit facility, and our borrowing base was $325 million. The borrowing base under our revolving credit facility is redetermined semi-annually based upon a number of factors, including commodity prices and reserve levels. In addition to such semi-annual redeterminations, our lenders may request one additional redetermination during any 12-month period. We expect that our borrowing base will be redetermined in the second quarter of 2017. Upon such redetermination, our borrowing base could be reduced, and if the amount outstanding under our revolving credit facility at any time exceeds the borrowing base at such time, we may be required to repay a portion of our outstanding borrowings. If commodity prices decrease significantly, it is likely that our borrowing base will be reduced further in the next semi-annual borrowing base redetermination. We use cash flow from operations and bank borrowings to fund our exploration, development and acquisition activities. A reduction in our borrowing base could limit those activities. In addition, we may significantly change our capital structure to cover our working capital needs, make future acquisitions or develop our properties. Changes in capital structure may significantly increase our debt. If we incur additional debt for these or other purposes, the related risks that we now face could intensify. A higher level of debt also increases the risk that we may default on our debt obligations. Our ability to meet our debt obligations and to reduce our level of debt depends on our future performance, which is affected by general economic conditions and financial, business and other factors, many of which are beyond our control.

Our revolving credit facility borrowing base is subject to semi-annual redetermination, and current Office of the Comptroller of the Currency (“OCC”) guidelines may incentivize lenders to limit our borrowing capabilities.

In March 2016, the OCC issued revised guidelines for exploration and production companies that specify target leverage metrics that we currently exceed.  The lower a loan’s credit rating, the more reserves a bank must set aside. This makes it more expensive for the bank to keep a negatively-rated, or classified, loan on its books.  Low participation in the Follow-On Exchange transaction would result in our continuing with leverage in excess of OCC guidelines, which would increase our risk of a negative semi-annual borrowing base redetermination, which could in turn materially decrease our liquidity or cause our borrowings to exceed our borrowing base and cause us to be in default under our credit agreement.

Our revolving credit facility contains operating and financial restrictions and covenants that may restrict our business and financing activities or that economic conditions and commodity prices may cause us to breach.

Our revolving credit facility contains, and any future indebtedness we incur may contain, a number of restrictive covenants that will impose significant operating and financial restrictions on us, including restrictions on our ability to, among other things:

• sell assets, including equity interests in our subsidiaries;

• consolidate, merge or transfer all or substantially all of our assets;

• incur or guarantee additional indebtedness or issue preferred stock;

• redeem or prepay other debt;

• pay distributions on, redeem or repurchase our common stock or redeem or repurchase our subordinated debt;

• create or incur certain liens;

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• make certain acquisitions and investments;

• enter into agreements that restrict distributions or other payments from our restricted subsidiaries to us;

• engage in transactions with affiliates;

• create unrestricted subsidiaries;

• enter into financing transactions; and

• engage in certain business activities.

As a result of these covenants, we will be limited in the manner in which we conduct our business, and we may be unable to engage in favorable business activities or finance future operations or capital needs.

Our revolving credit facility also contains financial covenants. Our ability to comply with some of the covenants and restrictions contained in our revolving credit facility may be affected by events beyond our control. If commodity prices decline from current levels, our ability to comply with these covenants may be impaired. A failure to comply with the covenants, ratios or tests in our revolving credit facility, or any future indebtedness could result in an event of default, which, if not cured or waived, could have a material adverse effect on our business, financial condition and results of operations. If an event of default under our revolving credit facility occurs and remains uncured, the lenders:

• would not be required to lend any additional amounts to us;

• could elect to declare all borrowings outstanding, together with accrued and unpaid interest and fees, to be due and payable;

• may have the ability to require us to apply all of our available cash to repay these borrowings; or

• may prevent us from making debt service payments under our other agreements.

If commodity prices decline to a level such that our future undiscounted cash flows from our properties are less than their carrying value, we may be required to write down the carrying values of our properties. Additionally, current SEC rules also could require us to write down our proved undeveloped reserves in the future.

Accounting rules require that we periodically review the carrying value of our properties for possible impairment. Based on prevailing commodity prices and specific market factors and circumstances at the time of impairment reviews, and the continuing evaluation of development plans, production data, economics and other factors, we may be required to write down the carrying value of our properties. A write-down is a non-cash charge to earnings. We recorded no impairment of our proved properties for the year ended December 31, 2016. For the year ended December 31, 2015, we recorded an impairment loss of $220.2 million. We may incur impairment charges in the future, which could have a material adverse effect on our results of operations for the periods in which such charges are taken. The risk that we will be required to write down the carrying value of our properties increases when oil and gas prices are low or volatile.

In addition, current SEC rules require that proved undeveloped reserves may only be booked if they relate to wells scheduled to be drilled within five years, unless specific circumstances justify a longer time. This rule may limit our potential to book additional proved undeveloped reserves as we pursue our development projects. Moreover, we may be required to write down our proved undeveloped reserves if we do not drill those wells within the required timeframe or if commodity prices cause us to change our development plan to decrease the number of wells to be drilled over the five-year period. For example, for the year ended December 31, 2016, we reclassified 22.4 MMBoe of proved reserves to unproved reserves attributable to horizontal well locations in Project Pangea that are no longer expected to be developed within five years from their initial booking, as required by SEC rules.

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The estimated volumes, standardized measure and present value of future net revenues (“PV-10”) from our proved reserves as of December 31, 2016, should not be considered as the current market value of the estimated oil and gas reserves attributable to our properties.

Standardized measure is a reporting convention that provides a common basis for comparing oil and gas companies subject to the rules and regulations of the SEC. On December 31, 2016, our standardized measure of discounted cash flows was $297.8 million. Standardized measure requires the use of specific pricing as required by the SEC as well as operating and development costs prevailing as of the date of computation. The non-GAAP financial measure, PV-10, is based on the average of the closing price on the first day of the month for the 12-month period prior to fiscal year end, while actual future prices and costs may be materially higher or lower.

Our estimated proved reserves as of December 31, 2016, and related standardized measure and PV-10, were calculated under the SEC rules using 12-month trailing average benchmark prices of $42.69 per Bbl of oil, $14.12 per Bbl of NGLs and $2.47 per MMBtu of gas. If oil, NGLs and gas prices decline by 10% from $42.69 per Bbl of oil, $14.12 per Bbl of NGLs and $2.47 per MMBtu of gas, to $38.42 per Bbl of oil, $12.71 per Bbl of NGLs and $2.22 per MMBtu of gas, then our PV-10 as of December 31, 2016, would decrease from $307.9 million to approximately $263.1 million. The average market price received for our production for the three months ended December 31, 2016 was $46.02 per Bbl of oil, $15.25 per Bbl of NGLs and $2.65 per Mcf of gas (after basis differential and Btu adjustments). Actual future net revenues also will be affected by factors such as the amount and timing of actual production, prevailing operating and development costs, supply and demand for oil and gas, increases or decreases in consumption and changes in governmental regulations or taxation. For a reconciliation of PV-10, a measure not calculated in accordance with GAAP, to our standardized measure of discounted future cash flows and related disclosures, see “Reconciliation of PV-10 to Standardized Measure.”

Consequently, these measures may not reflect the prices ordinarily received or that will be received for oil and gas production because of varying market conditions, nor may they reflect the actual costs that will be required to produce or develop the oil and gas properties. Accordingly, estimates of future net cash flow may be materially different from the future net cash flows that are ultimately received. Therefore, the standardized measure of our estimated reserves and PV-10 included in this report should not be construed as accurate estimates of the current fair value of our proved reserves. In addition, the 10% discount factor we use when calculating PV-10 may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the oil and gas industry in general.

The issuance of shares in the future could reduce the market price of our common stock.

In the future, we may issue common stock or other securities to raise cash for further debt reduction, working capital or acquisitions. We also may acquire interests in other companies by using a combination of cash and our common stock or just our common stock. We also may issue securities convertible into, or exchangeable for, or that represent the right to receive, our common stock. Any of these events may dilute your ownership interest in our company, reduce our earnings per share and have an adverse impact on the price of our common stock. In addition, sales or issuances of a substantial amount of our common stock, or the perception that these sales or issuances may occur, could reduce the market price of our common stock. This could also impair our ability to raise additional capital through the sale of our securities.

Our stock price has been and could remain volatile, which further could adversely affect the market price of our stock and our ability to raise additional capital and cause us to be subject to securities class action litigation.

The market price of our common stock has experienced and may continue to experience significant volatility. In 2016, the price of our common stock fluctuated from a high of $4.35 per share to a low of $0.60 per share. In addition, in recent years, the stock market has experienced significant price and volume fluctuations. This volatility has affected the market prices of securities issued by many companies in the energy sector, and particularly in the upstream sector. Such market price volatility could adversely affect our ability to raise additional capital. In addition, we may be subject to securities class action litigation as a result of the decline in the price of our common stock, which could result in substantial costs and diversion of management’s attention and resources and could harm our stock price, business, prospects, results of operations and financial condition.

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We may experience differentials to benchmark prices in the future, which may be material.

Substantially all of our production is sold to purchasers at prices that reflect a discount to other relevant benchmark prices, such as NYMEX-WTI. The difference between a benchmark price and the price we reference in our sales contracts is called a basis differential. Basis differentials result from variances in regional prices compared to benchmark prices as a result of regional supply and demand factors. We may experience differentials to benchmark prices in the future, which may be material.

We engage in commodity derivative transactions which involve risks that can harm our business.

To manage our exposure to price risks in the marketing of our production, we enter into commodity derivative agreements. While intended to reduce the effects of volatile commodity prices, such transactions may limit our potential gains and increase our potential losses if commodity prices were to rise substantially over the price established by the commodity derivative. In addition, such transactions may expose us to the risk of loss in certain circumstances, including instances in which our production is lower than expected. We are also exposed to the risk of non-performance by the counterparties to the commodity derivative agreements.

Due to the enactment of the Dodd-Frank Wall Street Reform and Consumer Protection Act (“Dodd-Frank”), the derivative transactions we execute are undertaken in a highly regulated market. While many of the rules implementing the Dodd-Frank statute are in place at this time, some significant components of the Dodd-Frank regulatory regime remain subject to rulemaking by the Commodity Futures Trading Commission and other regulators.

Although we have hedged a portion of our estimated 2017 and 2018 production, our hedging program may be inadequate to protect us against continuing and prolonged declines in the price of oil and natural gas.

Currently we have commodity price derivative agreements on approximately 8,400,000 MMBtu of natural gas hedged with swaps and collars in 2017 at an average floor price of $2.79 per MMBtu and an average ceiling price of $3.15 per MMBtu and 709,750 BBls of NGLs at average prices of $11.34 per Bbl (C2-ethane), $27.92 per Bbl (C3-propane), $36.73 per Bbl (IC4-isobutane), and $35.92 per Bbl (NC4-butane). These derivative contracts will not protect us from a continuing and prolonged decline in the price of oil and natural gas for the unhedged portion of our production in 2017 or our production after 2017. We have entered into derivative contracts for approximately 5,400,000 MMbtu of natural gas hedged with swaps at average prices of $3.08 per MMBtu for 2018. To the extent that the prices for oil and gas decline, we will not be able to hedge future production at the same level as our current hedges, and our results of operations and financial condition would be negatively impacted.

We are subject to complex governmental laws and regulations that may adversely affect the cost, manner and feasibility of doing business.

Our oil and gas drilling, production and gathering operations are subject to complex and stringent laws and regulations. To operate in compliance with these laws and regulations, we must obtain and maintain numerous permits and approvals from various federal, state and local governmental authorities. We may incur substantial costs to comply with these existing laws and regulations. In addition, our costs of compliance may increase if existing laws and regulations are revised or reinterpreted, or if new laws and regulations apply to our operations. Such costs could have a material adverse effect on our business, financial condition and results of operations. Failure to comply with laws and regulations applicable to our operations, including any evolving interpretation and enforcement by government authorities, could have a material adverse effect on our business, financial condition and results of operations. See “Business — Regulation” for a further description of the laws and regulations that affect us.

Federal and state legislation and regulatory initiatives and private litigation relating to hydraulic fracturing could stop or delay our development project and result in materially increased costs and additional operating restrictions.

All of our proved undeveloped reserves associated with future drilling and completion projects will require hydraulic fracturing. See Item 1. “Business — Hydraulic Fracturing” for a discussion of the importance of hydraulic fracturing to our business, and Item 1. “Business — Regulation —Hydraulic Fracturing” for a discussion of

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regulatory developments regarding hydraulic fracturing. If these or any other new laws or regulations that significantly restrict hydraulic fracturing are adopted, such laws could make it more difficult or costly for us to drill and produce from our proved reserves, as well as make it easier for third parties opposing hydraulic fracturing to initiate legal proceedings. In addition, if hydraulic fracturing is regulated at the federal level, fracturing activities could become subject to additional permitting and financial assurance requirements, more stringent construction specifications, increased monitoring, reporting and recordkeeping obligations, plugging and abandonment requirements and also permitting delays and increases in costs. The EPA and other federal agencies, including the United States Bureau of Land Management (“BLM”), have made proposals that would subject hydraulic fracturing to further regulation and could restrict the practice of hydraulic fracturing. For example, the EPA has issued final regulations under the federal Clean Air Act establishing performance standards for oil and gas activities, including standards for the capture of air emissions released during hydraulic fracturing, and, in June 2016, the EPA finalized regulations that prohibit the discharge of wastewater from hydraulic fracturing operations to publicly owned wastewater treatment plants. The EPA also released a study in December 2016 finding that certain aspects of hydraulic fracturing, such as water withdrawals and wastewater management practices, could result in impacts to water resources, although the report did not identify a direct link between hydraulic fracturing and impacts to groundwater resources. While the BLM’s final rule regarding hydraulic fracturing was struck down by the United States District Court for the District of Wyoming in June 2016, an appeal is currently pending in the Tenth Circuit Court of Appeals.   However, several states have already adopted, and more states are considering adopting, laws and/or regulations that require disclosure of chemicals used in hydraulic fracturing and impose more stringent permitting, disclosure and well-construction requirements on hydraulic fracturing operations. In addition, some states and municipalities have significantly limited drilling activities and/or hydraulic fracturing or are considering doing so. Although it is not possible at this time to predict the final outcome of these proposals, any new federal, state or local restrictions on hydraulic fracturing that may be imposed in areas in which we conduct business could cause us to incur substantial compliance costs, and compliance or the consequences of our failure to comply could have a material adverse effect on our financial condition and results of operations. In addition, if we are unable to use hydraulic fracturing in completing our wells or hydraulic fracturing becomes prohibited or significantly regulated or restricted, we could lose the ability to drill and complete the projects for our proved reserves and maintain our current leasehold acreage, which would have a material adverse effect on our future business, financial condition and results of operations.

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

Our industry is cyclical, and, from time-to-time, during periods of improving and high commodity prices, there is a shortage of drilling rigs, hydraulic fracturing services, equipment, supplies or qualified service personnel. During these periods, the costs and delivery times of equipment, oilfield services and supplies are substantially greater. In addition, the demand for, and wage rates of, qualified drilling and completion crews rise as the number of active rigs in service increases. Increasing levels of exploration and production will increase the demand for oilfield services, and the costs of these services may increase, while the quality of these services may suffer. If the availability of equipment, crews, materials and services in the Permian Basin is particularly severe, our business, results of operations and financial condition could be materially and adversely affected because our operations and properties are concentrated in the Permian Basin.

Our operations substantially depend on the availability of water. Restrictions on our ability to obtain, dispose of or recycle water may impact our ability to execute our drilling and development plans in a timely or cost-effective manner.

Water is an essential component of our drilling and hydraulic fracturing processes. Historically, we have been able to secure water from local landowners and other sources for use in our operations. From 2011 through 2014, West Texas experienced extreme drought conditions. As a result of the severe drought, governmental authorities restricted the use of water subject to their jurisdiction for drilling and hydraulic fracturing to protect the local water supply. Although such restrictions have been lifted, if West Texas experiences further drought conditions the restrictions may return. If we are unable to obtain water to use in our operations, we may be unable to economically produce oil, NGLs and gas, which could have an adverse effect on our business, financial condition and results of operations.

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Moreover, new environmental initiatives and regulations could include restrictions on disposal of waste, including, but not limited to, produced water, drilling fluids and other wastes associated with the exploration,development or production of oil and gas. For example, in October 2014, the RRC published a final rule governing permitting or re-permitting of disposal wells that would require, among other things, the submission of information on seismic events occurring within a specified radius of the disposal well location, as well as logs, geologic cross sections and structure maps relating to the disposal area in question. In March 2016, the United States Geological Survey identified at least six states, including Texas, with areas of increased rates of induced seismicity that could be attributed to fluid injection or oil and gas extraction.  Furthermore, ongoing lawsuits allege that disposal well operations have caused damage to neighboring properties or otherwise violated state and federal rules regulating waste disposal. These developments could result in additional regulation and restrictions on the use of injection wells by the Company or by commercial disposal well vendors whom the Company may use from time to time to dispose of produced water. Compliance with environmental regulations and permit requirements for the disposal, withdrawal, storage and use of surface water or ground water necessary for hydraulic fracturing may increase our operating costs and cause delays, interruptions or cessation of our operations, the extent of which cannot be predicted, and all of which would have an adverse effect on our business, financial condition and results of operations.

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

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

Climate change legislation or regulations regulating emissions of GHGs and VOCs could result in increased operating costs and reduced demand for the oil and gas we produce.

In response to findings that emissions of carbon dioxide, methane and other GHGs present an endangerment to human health and the environment, the EPA adopted regulations that restrict emissions of GHGs under existing provisions of the federal CAA. The EPA also issued final regulations under the NSPS and NESHAP designed to reduce VOCs. See Item 1. “Business — Regulation — Environmental Laws and Regulations — Greenhouse Gas Emissions” and “ — Air Emissions” for a discussion of regulatory developments regarding GHG and VOC emissions.

While Congress has from time-to-time considered legislation to reduce emissions of GHGs, no significant legislation has been adopted to reduce GHG emissions at the federal level in recent years. In the absence of such federal climate legislation, a number of state and regional efforts have emerged that are aimed at tracking and/or reducing GHG emissions by means of GHG cap-and-trade programs. Most of these cap-and-trade programs require either major sources of emissions or major producers of fuels to acquire and surrender emission allowances, with the number of allowances available for purchase reduced each year until the overall GHG emission reduction goal is achieved. These allowances are expected to escalate significantly in cost over time.

In November 2016, the EPA issued a final Information Collection Request seeking information about methane emissions from facilities and operators in the oil and gas industry. The EPA has indicated that it intends to use the information from this request to develop Existing Source Performance Standards for the oil and gas industry. If adopted, these standards would not be imposed directly on regulated entities. Instead, they would become guidelines that the states must consider in developing their own rules for regulating sources within their borders. The EPA has indicated that this information may also be used to develop standards for certain kinds of new and modified equipment and facilities not currently covered under the NSPS.

The adoption of legislation or regulatory programs to reduce GHG or VOC emissions could require us to incur increased operating costs, such as costs to purchase and operate emissions control systems, to acquire emissions allowances or comply with new regulatory requirements. Any GHG emissions legislation or regulatory programs applicable to power plants or refineries could also increase the cost of consuming, and thereby reduce demand for, the oil and natural gas we produce. Consequently, legislation and regulatory programs to reduce GHG or VOC emissions could have a material adverse effect on our business, financial condition and results of operations.

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Environmental laws and regulations may expose us to significant costs and liabilities.

There is inherent risk of incurring significant environmental costs and liabilities in our oil and gas operations due to the handling of petroleum hydrocarbons and generated wastes, the occurrence of air emissions and water discharges from work-related activities and the legacy of pollution from historical industry operations and waste disposal practices. We may incur joint and several or strict liability under these environmental laws and regulations in connection with spills, leaks or releases of petroleum hydrocarbons and wastes on, under or from our properties and facilities, some of which have been used for exploration, production or development activities for many years and by third parties not under our control. In particular, the number of private, civil lawsuits involving hydraulic fracturing has risen in recent years. Since late 2009, multiple private lawsuits alleging ground water contamination have been filed in the U.S. against oil and gas companies, primarily by landowners who leased oil and gas rights to defendants, or by landowners who live close to areas where hydraulic fracturing has taken place. In addition, changes in environmental laws and regulations occur frequently, and any such changes that result in more stringent and costly waste handling, storage, transport, disposal or remediation requirements could have a material adverse effect on our business, financial condition and results of operations. We may not be able to recover some or any of these costs from insurance.

Changes in tax laws or fees may adversely affect our results of operations and cash flows.

Potential legislation, if enacted into law, could make significant changes to U.S. federal and state income tax laws, including the elimination of certain key U.S. federal income tax incentives currently available to oil and natural gas exploration and production companies. These changes include, but are not limited to, (i) the repeal of the percentage depletion allowance for oil and natural gas properties, (ii) the elimination of current deductions for intangible drilling and development costs, (iii) the elimination of the deduction for certain U.S. production activities and (iv) an extension of the amortization period for certain geological and geophysical expenditures. It is unclear whether these or similar changes will be enacted and, if enacted, how soon any such changes could become effective. The passage of this legislation or any other similar changes in U.S. federal income tax laws, as well as any similar changes in state law, could eliminate or postpone certain tax deductions that are currently available with respect to oil and natural gas exploration and development, and any such change could negatively affect our financial condition and results of operations. Additionally, future legislation could be enacted that increases the taxes or fees imposed on oil and natural gas extraction. Any such legislation could result in increased operating costs and/or reduced consumer demand for petroleum products, which in turn could affect the prices we receive for our oil, NGLs and gas.

Our future reserve and production growth depends on the success of our horizontal Wolfcamp oil shale resource play, which has a limited operational history and is subject to change.

We began drilling horizontal wells in the Wolfcamp play in late 2010. The wells that have been drilled or recompleted in these areas represent a small sample of our large acreage position, and we cannot assure you that our new wells will be successful. We continue to gather data about our prospects in the Wolfcamp play, and it is possible that additional information may cause us to change our drilling schedule or determine that prospects in some portion of our acreage position should not be developed at all.

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

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

• landing our wellbore in the desired drilling zone;

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

• running our casing the entire length of the wellbore; and

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

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

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

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

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

The results of our drilling in new or emerging formations are more uncertain initially than drilling results in areas that are more developed and have a longer history of established production. Newer or emerging formations and areas have limited or no production history and, consequently, we are more limited in assessing future drilling results in these areas. If our drilling results are less than anticipated, the return on our investment for a particular project may not be as attractive as we anticipated and we could incur material write-downs of unevaluated properties and the value of our undeveloped acreage could decline in the future.

Failure to effectively execute and manage our single major development project, Project Pangea, could result in significant delays, cost overruns, limitation of our growth, damage to our reputation and a material adverse effect on our business, financial condition and results of operations.

We believe we have an extensive inventory of identified drilling locations in our development project (Project Pangea) in the Wolfcamp shale oil resource play; however, Project Pangea is our core asset and our only development project. As we achieve more results in Project Pangea, we have expanded our horizontal development project there. This level of development activity requires significant effort from our management and technical personnel and places additional requirements on our financial resources and internal operating and financial controls. Our ability to successfully develop and manage this project will depend on, among other things:

• our ability to finance development of the project;

• the extent of our success in drilling and completing horizontal Wolfcamp wells;

• our ability to control costs and manage drilling and completion risks;

• our ability to attract, retain and train qualified personnel with the skills required to develop the project in a timely and cost-effective manner; and

• our ability to implement and maintain effective operating and financial controls and reporting systems necessary to develop and operate the project.

We may not be able to compensate for, or fully mitigate, these risks.

Currently, substantially all of our producing properties are located in two counties in Texas, making us vulnerable to risks associated with operating in one primary area.

Substantially all of our producing properties and estimated proved reserves are concentrated in Crockett and Schleicher Counties, Texas. As a result of this concentration, we are disproportionately exposed to the natural decline of production from these fields as well as the impact of delays or interruptions of production from these wells caused by significant governmental regulation, transportation capacity constraints, curtailments of production, service delays, natural disasters or other events that impact this area.

Because of our geographic concentration, our purchaser base is limited, and the loss of one of our key purchasers or their inability to take our oil, NGLs or gas could adversely affect our financial results.

In 2016, JP Energy and DCP collectively accounted for more than 99% of our total oil, NGLs and gas sales, excluding realized commodity derivative settlements. As of December 31, 2016, we had dedicated all of our oil production from northern Project Pangea and Pangea West through September 2022 to JP Energy. In addition, as of December 31, 2016, we had dedicated all of our NGLs and natural gas production from Project Pangea to DCP through August 2023. To the extent that any of our major purchasers reduces their purchases of oil, NGLs or gas, is unable to take our oil, NGLs or gas due to infrastructure or capacity limitations or defaults on their obligations to us, we would be adversely affected unless we were able to make comparably favorable arrangements with other

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purchasers. These purchasers’ default or non-performance could be caused by factors beyond our control. A default could occur as a result of circumstances relating directly to one or more of these customers or due to circumstances related to other market participants with which the customer has a direct or indirect relationship.

We depend on our management team and other key personnel. The loss of any of these individuals, or the inability to attract, train and retain additional qualified personnel, could adversely affect our business, financial condition and the results of operations and future growth.

Our success largely depends on the skills, experience and efforts of our management team and other key personnel and the ability to attract, train and retain additional qualified personnel. The loss of the services of one or more members of our senior management team or of our other employees with critical skills needed to operate our business could have a negative effect on our business, financial condition, results of operations and future growth. In January 2011, we entered into an amended and restated employment agreement with J. Ross Craft, P.E., our Chairman and Chief Executive Officer. On January 3, 2014, we entered into an employment agreement with Sergei Krylov as the Company’s Executive Vice President and Chief Financial Officer. In January 2017, we amended our employment agreements with Qingming Yang, our President and Chief Operating Officer; and J. Curtis Henderson, our Chief Administrative Officer. If any of these officers or other key personnel resign or become unable to continue in their present roles and are not adequately replaced, our business operations could be materially adversely affected. In addition, our ability to manage our growth, if any, will require us to effectively train, motivate and manage our existing employees and to attract, motivate and retain additional qualified personnel. Competition for these types of personnel is intense, and we may not be successful in attracting, assimilating and retaining the personnel required to grow and operate our business profitably.

Market conditions or transportation and infrastructure impediments may hinder our access to oil, NGLs and gas markets or delay our production or sales.

Market conditions or the unavailability of satisfactory oil, NGLs and gas processing and transportation services and infrastructure may hinder our access to oil, NGLs and gas markets or delay our production or sales. Although currently we control the gathering systems for our operations in the Permian Basin, we do not have such control over the regional or downstream pipelines in and out of the Permian Basin. The availability of a ready market for our oil, NGLs and gas production depends on a number of factors, including market demand and the proximity of our reserves to pipelines or trucking and rail terminal facilities.

In addition, the amount of oil, NGLs and gas that can be produced and sold is subject to curtailment in certain circumstances, such as pipeline interruptions due to maintenance, excessive line pressure, excessive vapor pressure, ability of downstream processing facilities to accept unprocessed gas or NGLs, physical damage or operational interruptions to the gathering or transportation system or downstream processing and fractionation facilities or lack of contracted capacity on such systems or facilities.

The curtailments arising from these and similar circumstances may last from a few days to several months, and in many cases, we are provided with limited, if any, notice as to when these circumstances will arise and their duration. As a result, we may not be able to sell, or may have to transport by more expensive means, the oil, NGLs and gas that we produce, or we may be required to shut in oil or gas wells or delay initial production until the necessary gathering and transportation systems are available. Any significant curtailment in gathering systems, transportation, pipeline capacity or significant delay in construction of necessary gathering and transportation facilities, could adversely affect our business, financial condition and results of operations.

Loss of our information and computer systems could adversely affect our business, financial condition and results of operations.

We heavily depend on our information systems and computer-based programs, including drilling, completion and production data, seismic data, electronic data processing and accounting data. If any of these programs or systems were to fail or create erroneous information in our hardware or software network infrastructure, possible consequences include our loss of communication links, inability to find, produce, process and sell oil, NGLs and gas and inability to automatically process commercial transactions or engage in similar automated or computerized business activities. In addition, the U.S. government has issued public warnings that indicate that energy assets

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might be specific targets of cyber security threats. A cyber incident involving our information systems and related infrastructure could disrupt our business plans and result in information theft, data corruption, operational disruption and/or financial loss. Any such consequence could have a material adverse effect on our business, financial condition and results of operations.

Competition in the oil and gas industry is intense, and many of our competitors have resources that are greater than ours.

We operate in a highly competitive environment for acquiring prospects and productive properties, marketing oil and gas and securing equipment and skilled personnel. Many of our competitors are major and large independent oil and gas companies that have financial, technical and personnel resources substantially greater than ours. Those companies may be able to develop and acquire more prospects and productive properties than our financial or personnel resources permit. Our ability to develop and operate our current project, acquire additional prospects and discover reserves in the future will depend on our ability to hire and retain qualified personnel, evaluate and select suitable properties and consummate transactions in a highly competitive environment. Also, there is substantial competition for capital available for investment in the oil and gas industry. Larger competitors may be better able to withstand sustained periods of low commodity prices and unsuccessful drilling and absorb the burden of changes in laws and regulations more easily than we can, which would adversely affect our competitive position. We may not be able to compete successfully in the future in attracting and retaining qualified personnel, acquiring prospective reserves, developing reserves, marketing oil, NGLs and gas and raising additional capital.

Our identified drilling locations are scheduled to be drilled over many years, making them susceptible to uncertainties that could prevent them from being drilled or delay their drilling. In certain instances, this could prevent drilling and production before the expiration date of leases for such locations.

Our management team has identified drilling locations as an estimation of our future development activities on our existing acreage. These identified drilling locations represent a significant part of our growth strategy. Our ability to drill and develop these identified drilling locations depends on a number of uncertainties, including oil, NGLs and gas prices, the availability and cost of capital, drilling and production costs, availability of drilling services and equipment, drilling results, lease expirations, gathering system, marketing and transportation constraints, regulatory approvals and other factors. Because of these uncertain factors, we do not know if the identified drilling locations will ever be drilled or if we will be able to produce oil or gas from these or any other identified drilling locations. In addition, unless production is established within the spacing units covering the undeveloped acres on which some of the identified locations are obtained, the leases for such acreage will expire. Therefore, our actual drilling activities may materially differ from those presently identified.

The use of geoscientific, petrophysical and engineering analyses and other technical or operating data to evaluate drilling prospects is uncertain and does not guarantee drilling success or recovery of economically producible reserves.

Our decisions to explore, develop and acquire prospects or properties targeting Wolfcamp and other zones in the Permian Basin and other areas depend on data obtained through geoscientific, petrophysical and engineering analyses, the results of which can be uncertain. Even when properly used and interpreted, data from whole cores, regional well log analyses, 3-D seismic and micro-seismic only assist our technical team in identifying hydrocarbon indicators and subsurface structures and estimating hydrocarbons in place. They do not allow us to know conclusively the amount of hydrocarbons in place and if those hydrocarbons are producible economically. In addition, the use of advanced drilling and completion technologies for our Wolfcamp development, such as horizontal drilling and multi-stage fracture stimulations, requires greater expenditures than our traditional development drilling strategies. Our ability to commercially recover and produce the hydrocarbons that we believe are in place and attributable to the Wolfcamp and other zones will depend on the effective use of advanced drilling and completion techniques, the scope of our development project (which will be directly affected by the availability of capital), drilling and production costs, availability of drilling and completion services and equipment, drilling results, lease expirations, regulatory approval and geological and mechanical factors affecting recovery rates. Our estimates of unproved reserves, estimated ultimate recoveries per well, hydrocarbons in place and resource potential may change significantly as development of our oil and gas assets provides additional data.

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Unless we replace our oil and gas reserves, our reserves and production will decline.

Our future oil and gas production depends on our success in finding or acquiring additional reserves. If we fail to replace reserves through drilling or acquisitions, our production, revenues and cash flows will be adversely affected. In general, production from oil and gas properties declines as reserves are depleted, with the rate of decline depending on reservoir characteristics. Our total proved reserves will decline as reserves are produced, unless we conduct other successful exploration and development activities or acquire properties containing proved reserves, or both. Our ability to make the necessary capital investment to maintain or expand our asset base of oil and gas reserves would be limited to the extent cash flow from operations is reduced and external sources of capital become limited or unavailable. We may not be successful in exploring for, developing or acquiring additional reserves.

We have leases for undeveloped acreage that may expire in the near future.

As of December 31, 2016, we held mineral leases in each of our areas of operation that are still within their original lease term and are not currently held by production. Leases not held by production represent 27% of our net acreage, and 3% of our proved undeveloped reserves. Unless we continue to develop and produce on the properties subject to these leases, these leases may expire in 2017. If these leases expire, we will lose our right to develop the related properties, unless we renew such leases. The cost to renew such leases may increase significantly, and we may not be able to renew such leases on commercially reasonable terms or at all. See Item 2. “Properties — Undeveloped Acreage Expirations” for a table summarizing the expiration schedule of our undeveloped acreage over the next three years.

Our actual production, revenues and expenditures related to our reserves are likely to differ from our estimates of our proved reserves. We may experience production that is less than estimated and drilling costs that are greater than estimated in our reserve reports. These differences may be material.

The proved oil, NGLs and gas reserves data included in this report are estimates. Petroleum engineering is a subjective process of estimating underground accumulations of oil and gas that cannot be measured in an exact manner. Estimates of economically recoverable oil, NGLs and gas reserves and of future net cash flows necessarily depend upon a number of variable factors and assumptions, including:

• historical production from the area compared with production from other similar producing areas;

• the assumed effects of regulations by governmental agencies;

• assumptions concerning future oil, NGLs and gas prices; and

• assumptions concerning future operating costs, severance and excise taxes, development costs and workover and remedial costs.

Because all reserves estimates are to some degree subjective, each of the following items may differ materially from those assumed in estimating proved reserves:

• the quantities of oil, NGLs and gas that are ultimately recovered;

• the production and operating costs incurred;

• the amount and timing of future development expenditures; and

• future oil, NGLs and gas prices.

As of December 31, 2016, approximately 62% of our proved reserves were proved undeveloped. Estimates of proved undeveloped reserves are even less reliable than estimates of proved developed reserves. Furthermore, different reserve engineers may make different estimates of reserves and future net revenues based on the same available data. Our actual production, revenues and expenditures with respect to reserves will likely be different from estimates and the differences may be material.

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

In the future, we may make acquisitions of businesses that complement or expand our current business. We may not be able to identify attractive acquisition opportunities. Even if we do identify attractive acquisition opportunities, we may not be able to complete the acquisition or do so on commercially acceptable terms. Competition for acquisitions may also increase the cost of, or cause us to refrain from, completing acquisitions.

The success of any completed acquisition will depend on our ability to integrate effectively the acquired business into our existing operations. The process of integrating acquired businesses may involve unforeseen difficulties and may require a disproportionate amount of our managerial and financial resources. No assurance can be given that we will be able to identify suitable acquisition opportunities, negotiate acceptable terms, obtain financing for acquisitions on acceptable terms or successfully acquire identified targets. Our failure to achieve consolidation savings, to integrate the acquired businesses and assets into our existing operations successfully or to minimize any unforeseen operational difficulties could have a material adverse effect on our financial condition and results of operations.

Severe weather could have a material adverse impact on our business.

Our business could be materially and adversely affected by severe weather. Repercussions of severe weather conditions may include:

• curtailment of services, including oil, NGLs and gas pipelines, processing plants and trucking services;

• weather-related damage to drilling rigs, resulting in a temporary suspension of operations;

• weather-related damage to our producing wells or facilities;

• inability to deliver materials to jobsites in accordance with contract schedules; and

• loss of production.

Operating hazards or other interruptions of our operations could result in potential liabilities, which may not be fully covered by our insurance.

The oil and gas business involves certain operating hazards such as well blowouts, cratering, explosions, uncontrollable flows of gas, oil or well fluids, fires, surface and subsurface pollution and contamination, and releases of toxic gas. The occurrence of one of the above may result in injury, loss of life, suspension of operations, environmental damage and remediation and/or governmental investigations and penalties. Consistent with insurance coverage generally available to the industry, our insurance policies provide limited coverage for losses or liabilities relating to pollution, with broader coverage for sudden and accidental occurrences. Our insurance might be inadequate to cover our liabilities. The insurance market, in general, and the energy insurance market, in particular, have been difficult markets over the past several years. Insurance costs are expected to continue to increase over the next few years, and we may decrease coverage and retain more risk to mitigate future cost increases. If we incur substantial liability and the damages are not covered by insurance or are in excess of policy limits, or if we incur liability at a time when we are not able to obtain liability insurance, then our business, results of operations and financial condition could be materially adversely affected.

Our results are subject to quarterly and seasonal fluctuations.

Our quarterly operating results have fluctuated in the past and could be negatively impacted in the future as a result of a number of factors, including seasonal variations in oil, NGLs and gas prices, variations in levels of production and the completion of development projects.

We have renounced any interest in specified business opportunities, and certain members of our board of directors and certain of our stockholders generally have no obligation to offer us those opportunities.

In accordance with Delaware law, we have renounced any interest or expectancy in any business opportunity, transaction or other matter in which our outside directors and certain of our stockholders, each referred to as a

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Designated Party, participates or desires to participate in, that involves any aspect of the exploration and production business in the oil and gas industry. If any such business opportunity is presented to a Designated Party who also serves as a member of our board of directors, the Designated Party has no obligation to communicate or offer that opportunity to us, and the Designated Party may pursue the opportunity as he sees fit, unless:

• it was presented to the Designated Party solely in that person’s capacity as a director of our Company and with respect to which, at the time of such presentment, no other Designated Party has independently received notice of, or otherwise identified the business opportunity; or

• the opportunity was identified by the Designated Party solely through the disclosure of information by or on behalf of us.

As a result of this renunciation, our outside directors should not be deemed to have breached any fiduciary duty to us if they or their affiliates or associates pursue opportunities as described above and our future competitive position and growth potential could be adversely affected.

ITEM 1B. UNRESOLVED STAFF COMMENTS

As of the date of this filing, we have no unresolved comments from the staff of the SEC.

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ITEM 2. PROPERTIES

Permian Basin — Project Pangea

Our properties in the Permian Basin are located in Crockett and Schleicher Counties, Texas. We began operations in the Permian Basin through a farm-in agreement for 27,000 net acres in 2004 and have since increased our total acreage position to approximately 137,000 gross (123,000 net) acres as of year-end 2016. At December 31, 2016, we owned interests in approximately 806 gross (794 net) wells, all of which we operate. As of December 31, 2016, we had working and net revenue interests of approximately 100% and 76%, respectively, across Project Pangea.

Our acreage position in the Permian Basin is characterized by several commercial hydrocarbon zones, including the Clearfork, Dean, Wolfcamp shale, Canyon Sands, Strawn and Ellenburger zones. When we began drilling our Permian Basin properties in 2004, we targeted the Canyon Sands, Strawn and Ellenburger zones at depths ranging from 7,250 feet to 8,900 feet with vertical wells.

In 2010, we performed a detailed geological and petrophysical evaluation of the Clearfork, Dean and Wolfcamp shale formations above the Canyon Sands, Strawn and Ellenburger, and in 2010, we began drilling horizontal wells targeting the Wolfcamp shale. The Wolfcamp shale is a source rock that we believe has significant potential for hydrocarbons. The Wolfcamp shale is located in the oil-to-wet gas window across our Permian acreage position and is naturally fractured due to its proximity to the Ouachita-Marathon thrust belt and mineralogy, specifically the carbonate and quartz minerals.

The Wolfcamp shale has gross pay thickness of approximately 1,000 to 1,200 feet across our acreage position, which allows for horizontal drilling and stacked horizontal wellbores targeting varied zones that we call “benches.” We believe effectively developing the Wolfcamp shale may involve up to three lateral wellbores, each targeting a different bench, which we refer to as the Wolfcamp A, B and C. Since we began drilling horizontal Wolfcamp wells in 2011 through December 31, 2016, we have drilled and completed a total of 17 wells targeting the Wolfcamp A bench, 106 wells targeting the Wolfcamp B bench and 46 wells targeting the Wolfcamp C bench. As of December 31, 2016, estimated proved reserves attributable to the horizontal Wolfcamp shale oil play accounted for 93% of our total proved reserves.

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During 2016, we incurred costs of approximately $17.8 million to drill six, and complete five, horizontal Wolfcamp wells. At December 31, 2016, we had six horizontal Wolfcamp wells waiting on completion. We currently have one rig running in Project Pangea.

East Texas Basin — North Bald Prairie

In July 2007, we entered into a joint venture with EnCana Oil & Gas (USA) Inc. (“EnCana”) in Limestone and Robertson Counties, Texas, in the East Texas Cotton Valley trend. We began drilling operations in August 2007. We have drilled and completed 11 gross wells, including one well completed as a saltwater disposal well. We have a 50% working interest and approximately 40% net revenue interest in the approximately 3,000 gross (2,000 net) acre project. In 2012, EnCana assigned its interest in the project to a third party. As of December 31, 2016, we had estimated proved reserves of 512 MMcf in North Bald Prairie. Our primary targets in North Bald Prairie are the Cotton Valley Sands and Cotton Valley Lime. We currently have no rigs running in North Bald Prairie.

Proved Oil and Gas Reserves

The following table sets forth summary information regarding our estimated proved reserves as of December 31, 2016. See Note 10 to our consolidated financial statements in this report for additional information. Our reserve estimates and our calculation of standardized measure and PV-10 are based on the 12-month average of the first-day-of-the-month pricing of $42.69 per Bbl West Texas Intermediate posted oil price, $14.12 per Bbl received for NGLs and $2.47 per MMBtu Henry Hub spot natural gas price during 2016. All prices were adjusted for energy content, quality and basis differentials by area and were held constant through the lives of the properties. Natural gas is converted at a rate of six Mcf of gas to one barrel of oil equivalent (“Boe”). NGLs are converted at a rate of one barrel of NGLs to one Boe. The ratios of six Mcf of gas to one Boe and one barrel of NGLs to one Boe do not assume price equivalency and, given price differentials, the price for a Boe of natural gas or NGLs may differ significantly from the price of a barrel of oil. The information in the following table is not intended to represent the current market value of our proved reserves nor does it give any effect to or reflect our commodity derivatives or current commodity prices.

Summary of Oil and Gas Reserves as of Fiscal-Year End

Based on Average Fiscal-Year Prices

	Proved Reserves
Reserves Category	Oil (MBbls)		NGLs (MBbls)		Natural Gas (MMcf)(1)		Total (MBoe)		Percent (%)			PV-10 (in millions)(2)
Proved Developed
Permian Basin		13,466		20,375		149,696		58,790		37.6	%	$	295.5
East Texas Basin		—		—		512		85		0.0			0.3
Proved Undeveloped
Permian Basin		36,565		27,259		202,069		97,502		62.4			12.1
Total Proved Reserves		50,031		47,634		352,277		156,377		100.0	%	$	307.9

(1) The gas reserves contain 44,178 MMcf of gas that will be produced and used as field fuel (primarily for compressors and artificial lifts) before the gas is delivered to a sales point.

(2) See “Reconciliation of PV-10 to Standardized Measure” below for a reconciliation of PV-10 to the standardized measure.

Our estimated total proved reserves of oil, NGLs and natural gas as of December 31, 2016, were 156.4 MMBoe, made up of 32% oil, 30% NGLs and 38% natural gas. The proved developed portion of total proved reserves at year-end 2016 was 38%.

Extensions and discoveries for 2016 were 16.7 MMBoe, primarily attributable to our development project in the Wolfcamp shale oil resource play in the Permian Basin. During 2016, we reclassified 22.4 MMBoe of proved

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undeveloped reserves to unproved reserves. The reserves reclassified are attributable to horizontal well locations in Project Pangea that are no longer expected to be developed within five years from their initial booking, as required by SEC rules. Revisions included an increase of 2.1 MMBoe resulting from cost reductions, updated well performance and technical parameters, offset by a decrease of 1.9 MMBoe due to lower commodity prices. We produced 4.8 MMBoe during 2016. This production included 1,330 MMcf of gas that was produced and used as field fuel (primarily for compressors and artificial lift) before the gas was delivered to a sales point.

Reconciliation of PV-10 to Standardized Measure

PV-10 is our estimate of the present value of future net revenues from proved oil and gas reserves after deducting estimated production and ad valorem taxes, future capital costs and operating expenses, but before deducting any estimates of future income taxes. PV-10 is a non-GAAP, financial measure and generally differs from the standardized measure, the most directly comparable GAAP financial measure, because it does not include the effects of income taxes on future cash flows. PV-10 should not be considered as an alternative to the standardized measure as computed under GAAP.

We believe PV-10 to be an important measure for evaluating the relative significance of our oil and gas properties and that the presentation of PV-10 provides useful information to investors because it is widely used by professional analysts and sophisticated investors in evaluating oil and gas companies. Because there are many unique factors that can impact an individual company when estimating the amount of future income taxes to be paid, we believe the use of a pre-tax measure is valuable for evaluating our company. We believe that most other companies in the oil and gas industry calculate PV-10 on the same basis.

The following table provides a reconciliation of PV-10 to the standardized measure of discounted future net cash flows at December 31, 2016:

	December 31, 2016 (in millions)
PV-10	$	307.9
Present value of future income tax discounted at 10%		(10.1	)
Standardized measure of discounted future net    cash flows	$	297.8

Proved Undeveloped Reserves

As of December 31, 2016, we had 97.5 MMBoe of proved undeveloped (“PUD”) reserves, which is a decrease of 7.3 MMBoe, or 7%, compared with 104.8 MMBoe of PUD reserves at December 31, 2015. All of our PUD reserves at December 31, 2016, were associated with our core development project, Project Pangea.

The following table summarizes the changes in our PUD reserves during 2016.

	Oil (MBbls)			NGLs (MBbls)			Natural Gas (MMcf)			Total (MBoe)
Balance — December 31, 2015		38,829			29,072			221,336			104,790
Extensions and discoveries		6,221			4,372			31,906			15,910
Revisions to previous estimates		(8,066	)		(5,752	)		(48,033	)		(21,822	)
Conversion to proved developed reserves		(419	)		(433	)		(3,140	)		(1,376	)
Balance — December 31, 2016		36,565			27,259			202,069			97,502

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The following table sets forth our PUD reserves converted to proved developed reserves during 2016, 2015 and 2014 and the net investment required to convert PUD reserves to proved developed reserves during each year.

	Proved Undeveloped Reserves Converted to Proved Developed Reserves								Investment in Conversion of Proved Undeveloped Reserves to Proved Developed Reserves
Year Ended December 31,	Oil (MBbls)		NGLs (MBbls)		Natural Gas (MMcf)		Total (MBoe)		(in thousands)
2014		3,430		1,645		10,753		6,867	$	106,309
2015		2,485		1,627		11,737		6,068		84,071
2016		419		433		3,140		1,376		11,008
Total		6,334		3,705		25,630		14,311	$	201,388

Estimated future development costs relating to the development of PUD reserves are projected to be approximately $55 million in 2017, $154 million in 2018 and $262 million in 2019. We monitor fluctuations in commodity prices, drilling and completion costs, operating expenses and drilling success to determine adjustments to our drilling and development project.

Preparation of Proved Reserves Estimates

Internal Controls Over Preparation of Proved Reserves Estimates

Our policies regarding internal controls over the recording of reserve estimates require reserve estimates to be in compliance with SEC rules, regulations and guidance and prepared in accordance with “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information (Revision as of February 19, 2007)” promulgated by the Society of Petroleum Engineers (“SPE standards”). Our proved reserves are estimated at the property level and compiled for reporting purposes by our corporate reservoir engineering staff, all of whom are independent of our operations team. We maintain our internal evaluations of our reserves in a secure reserve engineering database. The corporate reservoir engineering staff interacts with our internal staff of operations engineers and geoscience professionals and with accounting employees to obtain the necessary data for the reserves estimation process. Our internal professional staff works closely with our external engineers 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 secure reserve engineering database is provided to the external engineers. In addition, other pertinent data is provided such as seismic information, geologic maps, well logs, production tests, material balance calculations, well performance data, operating procedures and relevant economic criteria. We make available all information requested, including our pertinent personnel, to the external engineers as part of their evaluation of our reserves.

Our Senior Vice President of Engineering, Troy Hoefer, is the individual responsible for overseeing the preparation of our reserve estimates and for internal compliance of our reserve estimates with SEC rules, regulations and SPE standards. Mr. Hoefer has a Bachelor of Science degree in Petroleum Engineering from the Colorado School of Mines and more than 25 years of industry experience. Mr. Hoefer reports to our President and Chief Operating Officer. Our executive management, including our Chief Executive Officer and our President and Chief Operating Officer, reviews and approves our reserves estimates, including future development costs, before these estimates are finalized and disclosed in a public filing or presentation. Our Chief Executive Officer, J. Ross Craft, P.E., is a licensed Professional Engineer with a Bachelor of Science Degree in Petroleum Engineering from Texas A&M University and more than 30 years of industry experience. Our President and Chief Operating Officer, Qingming Yang, earned his B.S. in Petroleum Geology from Chengdu University of Technology in the People’s Republic of China, his M.A. in Geology from George Washington University and his Ph.D. in Structural Geology from the University of Texas at Dallas. Dr. Yang has more than 25 years of industry experience.

For the years ended December 31, 2016, 2015 and 2014, we engaged DeGolyer and MacNaughton, independent petroleum engineers, to prepare independent estimates of the extent and value of the proved reserves associated with certain of our oil and gas properties. In 2016, DeGolyer and MacNaughton reported to the Audit Committee of our Board of Directors and to our Senior Vice President of Engineering. The Audit Committee meets with the independent engineering firm to, among other things, review and consider the processes used by the

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engineers in the preparation of the report and any matters of importance that arose in the preparation of the report, including whether the independent engineering firm encountered any material problems or difficulties in the preparation of their report. The Audit Committee’s review specifically includes difficulties with the scope or timeliness of the information furnished to them by the Company or any restrictions on access to information placed upon them by any Company personnel, any other difficulties in dealing with any Company personnel in the preparation of the report and any other matters of concern relating to the preparation of the report. The Audit Committee also determines whether the Company or its management or senior engineering personnel had similar or other problems or concerns regarding the independent engineering firm and the preparation of their report. See Third-Party Reports below for further information regarding DeGolyer and MacNaughton’s report.

Technologies Used in Preparation of Proved Reserves Estimates

Estimates of reserves were prepared in compliance with SEC rules, regulations and guidance and SPE standards. The method or combination of methods used in the analysis of each reservoir was tempered by experience with similar reservoirs, stage of development, quality and completeness of basic data and production history. For our properties, structure and isopach maps were constructed to delineate each reservoir. Electrical logs, radioactivity logs, seismic data and other available data were used to prepare these maps. Parameters of area, porosity and water saturation were estimated and applied to the isopach maps to obtain estimates of original oil in place or original gas in place. For developed producing wells whose performance disclosed a reliable decline in producing-rate trends or other diagnostic characteristics, reserves were determined using decline curve analysis. Reserves for producing wells whose performance was not yet established and for undeveloped locations were estimated using type curves. The parameters needed to develop these type curves such as initial decline rate, “b” factor and final decline rate were based on nearby wells producing from the same reservoir and with a similar completion for which more data were available.

Reporting of NGLs

We produce NGLs as part of the processing of our natural gas. The extraction of NGLs in the processing of natural gas reduces the volume of natural gas available for sale. At December 31, 2016, NGLs represented approximately 30% of our total proved reserves on a Boe basis. NGLs are products sold by the gallon. In reporting proved reserves and production of NGLs, we include these volumes and production as Boe. The prices we received for a standard barrel of NGLs in 2016 averaged approximately 66% lower than the average prices for equivalent volumes of oil. We report all production information related to natural gas net of the effect of any reduction in natural gas volumes resulting from the processing of NGLs.

Third-Party Reports

For the years ended December 31, 2016, 2015 and 2014, we engaged DeGolyer and MacNaughton, independent petroleum engineers, to prepare estimates of the extent and value of the proved reserves of certain of our oil and gas properties, including 100% of our total reported proved reserves. DeGolyer and MacNaughton’s report for 2016 is included as Exhibit 99.1 to this annual report on Form 10-K.

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Oil and Gas Production, Production Prices and Production Costs

The following table sets forth summary information regarding oil, NGLs and gas production, average sales prices and average production costs for the last three years. We determined the Boe using the ratio of six Mcf of natural gas to one Boe, and one barrel of NGLs to one Boe. The ratios of six Mcf of natural gas to one Boe and one barrel of NGLs to one Boe do not assume price equivalency and, given price differentials, the price for a Boe for natural gas or NGLs may differ significantly from the price for a barrel of oil.

	Years Ended December 31,
Production	2016		2015		2014
Oil (MBbls)		1,275		1,882		2,024
NGLs (MBbls)		1,529		1,694		1,461
Gas (MMcf)(1)		10,404		11,732		9,383
Total (MBoe)		4,537		5,532		5,049
Total (MBoe/d)		12.4		15.2		13.8
Average prices
Oil (per Bbl)	$	37.90	$	43.65	$	87.69
NGLs (per Bbl)		12.93		12.06		28.74
Gas (per Mcf)		2.14		2.45		4.16
Total (per Boe)		19.90		23.74		51.20
Realized gain on commodity derivatives (per Boe)		1.35		9.49		0.47
Total including derivative impact (per Boe)	$	21.25	$	33.23	$	51.67
Production costs (per Boe)(2)	$	4.24	$	5.24	$	6.48

(1) Gas production excludes gas produced and used as field fuel (primarily for compressors and artificial lifts) before the gas was delivered to a sales point.

(2) Production cost per Boe is made up of lease operating expenses and excludes production and ad valorem taxes.

Drilling Activity — Prior Three Years

The following table sets forth information on our drilling activity for the last three years. The information should not be considered indicative of future performance, nor should it be assumed that there is necessarily any correlation between the number of productive wells drilled, quantities of reserves found or economic value.

	Years Ended December 31,
	2016				2015				2014
	Gross		Net		Gross		Net		Gross		Net
Development wells:
Productive		6.0		6.0		20.0		20.0		68.0		68.0
Dry(1)		—		—		1.0		1.0		2.0		2.0
Exploratory wells:
Productive		—		—		—		—		—		—
Dry		—		—		—		—		—		—
Total wells:
Productive		6.0		6.0		20.0		20.0		68.0		68.0
Dry		—		—		1.0		1.0		2.0		2.0

(1) The Company encountered mechanical issues while drilling the wells classified as dry in 2015 and 2014.

In 2016, we drilled six horizontal wells and completed five horizontal wells. At December 31, 2016, six wells were waiting on completion. The Company encountered mechanical issues while drilling one well in 2015 and two wells in 2014, and these wells cost $2.4 million and $5.6 million, respectively.

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Although a well may be classified as productive upon completion, future changes in oil, NGLs and gas prices, operating costs and production may result in the well becoming uneconomical.

Drilling Activity — Current

As of the date of this report, we had one horizontal rig running in the Permian Basin targeting the Wolfcamp shale oil resource play.

Delivery Commitments

We are not committed to provide a fixed and determinable quantity of oil, NGLs or gas under existing agreements. However, as of December 31, 2016, we had dedicated all of our oil production from northern Project Pangea and Pangea West through September 2022 to JP Energy and had dedicated all of our NGLs and natural gas production from Project Pangea to DCP through August 2023.

Producing Wells

The following table sets forth the number of producing wells in which we owned a working interest at December 31, 2016. Wells are classified as natural gas or oil according to their predominant production stream.

	Natural Gas Wells				Oil Wells				Total Wells				Average Working Interest
	Gross		Net		Gross		Net		Gross		Net
Permian Basin		534		523		272		271		806		794		98.5	%
East Texas Basin		9		4.5		—		—		9		4.5		49.9	%
Total		543		527.5		272		271		815		798.5		98.0	%

Acreage

The following table summarizes our developed and undeveloped acreage as of December 31, 2016.

	Developed Acres				Undeveloped Acres				Total Acres
	Gross		Net		Gross		Net		Gross		Net
Permian Basin		90,127		81,630		46,680		41,777		136,807		123,407
East Texas Basin		3,481		1,687		—		—		3,481		1,687
Total		93,608		83,317		46,680		41,777		140,288		125,094

Undeveloped Acreage Expirations

The following table sets forth the number of gross and net undeveloped acres as of December 31, 2016, which will expire over the next three years by project area, unless production is established before lease expiration dates. Net amounts may be greater than gross amounts in a particular year due to timing of expirations.

	2017				2018				2019
	Gross		Net		Gross		Net		Gross		Net
Permian Basin		33,495		34,022		107		11		—		40
East Texas Basin		—		—		—		—		—		—
Total		33,495		34,022		107		11		—		40

The expiring acreage set forth in the table above accounts for 27% of our net acreage, and 3% of our PUD reserves. Of the 34,022 net acres scheduled to expire in 2017, 16,844 net acres are leased from The Board for Lease of University Lands (“University Lands”) under a Drilling and Development Unit Agreement (“D&D agreement”). Under the D&D agreement, we are required to drill and complete two wells per calendar year until September 2017, and in September 2017, we will present a development plan to University Lands that will outline a proposed capital

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budget and drilling schedule for the following year. Upon approval of the plan of development by University Lands (not to be unreasonably withheld), the development plan will become the drilling obligation for the following year. We are generally engaged in a combination of drilling and development and discussions with mineral lessors for lease extensions and renewals to address the expiration of undeveloped acreage that occurs in the normal course of our business.

ITEM 3. LEGAL PROCEEDINGS

We are involved in various legal and regulatory proceedings arising in the normal course of business. While we cannot predict the outcome of these proceedings with certainty, we do not believe that an adverse result in any pending legal or regulatory proceeding, individually or in the aggregate, would be material to our business, financial condition and results of operations.

ITEM 4. MINE SAFETY DISCLOSURES

Not applicable.

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PART II

ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

Market Information

Our common stock is traded on NASDAQ Global Select Market in the United States under the symbol “AREX.” During 2016, trading volume averaged 1,015,691 shares per day. The following table shows the quarterly high and low sale prices of our common stock as reported on NASDAQ for the past two years.

	Price Per Share
	High		Low
2016
First quarter	$	2.05	$	0.60
Second quarter		3.10		1.13
Third quarter		4.35		1.35
Fourth quarter		4.33		2.51
2015
First quarter	$	9.15	$	5.01
Second quarter		9.57		6.35
Third quarter		6.95		1.65
Fourth quarter		3.19		1.23

Holders

As of February 21, 2017, there were 161 record holders of our common stock. A record holder may be a broker or other entity holding shares in street name for one or more customers who beneficially own the shares.

Dividends

We have not paid any cash dividends on our common stock. We do not expect to pay any cash or other dividends in the foreseeable future on our common stock, as we intend to reinvest cash flow generated by operations into our business. Our revolving credit facility currently restricts our ability to pay cash dividends on our common stock, and we may also enter into credit agreements or other borrowing arrangements in the future that restrict or limit our ability to pay cash dividends on our common stock.

Securities Authorized for Issuance under Equity Compensation Plans

The following table sets forth information regarding securities authorized for issuance under equity compensation plans and individual compensation arrangements as of December 31, 2016.

Plan Category	Number of Securities to be Issued Upon Exercise of Outstanding Options, Warrants and Rights (a)		Weighted-Average Exercise Price of Outstanding Options, Warrants and Rights (b)		Number of Securities Remaining Available for Future Issuance under Equity Compensation Plans (Excluding Securities Reflected in Column (a))(1) (c)
Equity compensation plans    approved by stockholders		38,525	$	12.00		2,742,394
Equity compensation plans not    approved by stockholders		—		—		—

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Performance Graph

The following graph compares the cumulative return on a $100 investment in our common stock from December 31, 2011, through December 31, 2016, to that of the cumulative return on a $100 investment in the Standard & Poor’s 500 (“S&P 500”) index, and Standard & Poor’s 600 Small Cap Energy index for the same period. In calculating the cumulative return, reinvestment of dividends, if any, is assumed. This graph is not “soliciting material,” is not deemed filed with the SEC and is not to be incorporated by reference in any of our filings under the Securities Act or the Exchange Act, whether made before or after the date hereof and irrespective of any general incorporation language in any such filing. This graph is included in accordance with the SEC’s disclosure rules. This historic stock performance is not indicative of future stock performance.

COMPARISON OF FIVE-YEAR CUMULATIVE TOTAL RETURN

Among Approach Resources Inc., the S&P 500 Index and the S&P 600 Small Cap Energy Index

	12/31/2011		12/31/2012		12/31/2013		12/31/2014		12/31/2015		12/31/2016
Approach Resources Inc.	$	100.00	$	85.04	$	65.62	$	21.73	$	6.26	$	11.39
S&P 500		100.00		113.41		146.98		163.72		162.53		178.02
S&P 600 Small Cap Energy Index		100.00		99.48		137.08		88.18		46.18		63.52

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Issuer Repurchases of Equity Securities

Our 2007 Stock Incentive Plan (the “2007 Plan”) allows us to withhold shares of common stock to pay withholding taxes payable upon vesting of a restricted stock grant. The following table shows the number of shares of common stock withheld to satisfy the income tax withholding obligations arising upon the vesting of restricted shares issued to employees under the 2007 Plan.

Period	(a) Total Number of Shares Purchased		(b) Average Price Paid per Share		(c) Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs		(d) Maximum Number (or Approximate Dollar Value) of Shares that May Yet Be Purchased Under the Plans or Programs
October 1, 2016 — October 31, 2016		—	$	—		—		—
November 1, 2016 — November 30,    2016		1,781		2.85		—		—
December 1, 2016 — December 31,    2016		224,242		3.47		—		—
Total		226,023	$	3.47		—		—

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ITEM 6. SELECTED FINANCIAL DATA

The following table sets forth selected financial information for the five years ended December 31, 2016. This information should be read in conjunction with Item 7 of this report, “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” and our consolidated financial statements, related notes and other financial information included in this report.

	Years Ended December 31,
	2016			2015			2014			2013			2012
	(in thousands, except per-share data)
Operating Results Data
Revenues
Oil, NGLs and gas sales	$	90,302		$	131,336		$	258,529		$	181,302		$	128,892
Expenses
Lease operating		19,250			28,972			32,701			19,152			19,002
Production and ad valorem taxes		8,217			11,085			15,934			12,840			9,255
Exploration		3,923			4,439			3,831			2,238			4,550
Impairment of oil and gas properties		—			220,197			—			—			—
General and administrative		24,734			28,341			32,104			26,524			24,903
Termination costs		—			1,436			—			—			—
Depletion, depreciation and amortization		79,044			109,319			106,802			76,956			60,381
Total expenses		135,168			403,789			191,372			137,710			118,091
Operating (loss) income		(44,866	)		(272,453	)		67,157			43,592			10,801
Other
Interest expense, net		(27,259	)		(25,066	)		(21,651	)		(14,084	)		(4,737	)
Gain on debt extinguishment		—			10,563			—			—			—
Write-off of debt issuance costs		(563	)		—			—			—			—
Equity in (losses) earnings of investee		—			—			(181	)		156			(108	)
Gain on sale of equity method investment		—			—			—			90,743			—
Realized gain (loss) on commodity derivatives		6,132			52,489			2,359			(1,048	)		(108	)
Unrealized (loss) gain on commodity derivatives		(11,616	)		(33,214	)		42,113			(4,596	)		3,874
Other income		1,511			172			67			—			—
(Loss) Income before provision for income tax    (benefit) provision		(76,661	)		(267,509	)		89,864			114,763			9,722
Income tax (benefit) provision		(24,418	)		(93,405	)		33,692			42,507			3,338
Net (loss) income	$	(52,243	)	$	(174,104	)	$	56,172		$	72,256		$	6,384
(Loss) Earnings per share
Basic	$	(1.26	)	$	(4.30	)	$	1.43		$	1.85		$	0.18
Diluted	$	(1.26	)	$	(4.30	)	$	1.42		$	1.85		$	0.18
Statement of Cash Flows Data
Net cash provided by (used in)
Operating activities	$	26,081		$	102,716		$	171,604		$	110,695		$	72,089
Investing activities		(23,890	)		(217,347	)		(377,172	)		(187,324	)		(291,963	)
Financing activities		(2,770	)		114,799			147,239			134,623			214,250
Balance Sheet Data
Cash and cash equivalents	$	21		$	600		$	432		$	58,761		$	767
Restricted cash		—			—			—			7,350			—
Other current assets		12,473			19,838			60,647			24,302			14,889
Property, equipment, net, successful efforts method, net		1,092,061			1,154,546			1,331,659			1,047,030			828,467
Equity method investment		—			—			—			—			9,892
Other assets		—			—			—			1,388			881
Total assets	$	1,104,555		$	1,174,984		$	1,392,738		$	1,138,831		$	854,896
Current liabilities	$	26,369		$	28,508		$	106,852		$	84,441		$	60,247
Long-term debt, net		498,349			496,587			391,311			243,347			105,157
Other long-term liabilities		16,885			41,922			120,248			100,548			56,024
Stockholders’ equity		562,952			607,967			774,327			710,495			633,468
Total liabilities and stockholders’ equity	$	1,104,555		$	1,174,984		$	1,392,738		$	1,138,831		$	854,896

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ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion is intended to assist in understanding our results of operations and our financial condition. Our consolidated financial statements and the accompanying notes included elsewhere in this report contain additional information that should be referred to when reviewing this material. Statements in this discussion may be forward-looking. These forward-looking statements involve risks and uncertainties, which could cause actual results to differ from those expressed. See “Cautionary Statement Regarding Forward-Looking Statements” at the beginning of this report and “Risk Factors” in Item 1A. for additional discussion of some of these factors and risks.

Overview

Approach Resources Inc. is an independent energy company focused on the exploration, development, production and acquisition of unconventional oil and gas reserves in the Midland Basin of the greater Permian Basin in West Texas, where we lease approximately 123,000 net acres as of December 31, 2016. We believe our concentrated acreage position and extensive, integrated field infrastructure system provides us an opportunity to achieve cost, operating and recovery efficiencies in the development of our drilling inventory. Our long-term business strategy is to develop resource potential from the Wolfcamp shale oil formation and pursue acquisitions that meet our strategic and financial objectives. See “Item 1 — Business — Our Business Strategy”. Additional drilling targets could include the Clearfork, Canyon Sands, Strawn and Ellenburger zones. We sometimes refer to our development project in the Permian Basin as “Project Pangea,” which includes “Pangea West.” Our management and technical team have a proven track record of finding and developing reserves through advanced drilling and completion techniques. As the operator of all of our estimated proved reserves and production, we have a high degree of control over capital expenditures and other operating matters.

At December 31, 2016, our estimated proved reserves were 156.4 million barrels of oil equivalent (“MMBoe”). Substantially all of our proved reserves are located in Crockett and Schleicher Counties, Texas. The following are important characteristics of our proved reserves at December 31, 2016:

• 32% oil, 30% NGLs and 38% natural gas;

• 38% proved developed;

• 100% operated;

• Reserve life of approximately 34 years based on 2016 production of 4.5 MMBoe;

• Standardized measure of discounted future net cash flows (“standardized measure”) of $297.8 million; and

• PV-10 (non-GAAP) of $307.9 million.

PV-10 is our estimate of the present value of future net revenues from proved oil, NGLs and natural gas reserves after deducting estimated production and ad valorem taxes, future capital costs and operating expenses, but before deducting any estimates for future income taxes. Estimated future net revenues are discounted at an annual rate of 10% to determine their present value. PV-10 is a financial measure that is not determined in accordance with accounting principles generally accepted in the United States (“GAAP”), and generally differs from the standardized measure, the most directly comparable GAAP financial measure, because it does not include the effects of income taxes on future cash flows. PV-10 should not be considered as an alternative to the standardized measure, as computed under GAAP. See Item 2. “Properties — Proved Oil and Gas Reserves” for a reconciliation of PV-10 to the standardized measure.

At December 31, 2016, we owned and operated 806 producing oil and gas wells in the Permian Basin. During 2016, we produced 4.5 MMBoe, or 12.4 MBoe/d. Production for 2016 was 28% oil, 34% NGLs and 38% natural gas.

Our financial results depend on many factors, but particularly on the price of oil, NGLs and gas. Commodity prices are affected by changes in market demand, which is impacted by factors outside of our control, including

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domestic and foreign supply of oil, NGLs and gas, overall domestic and global economic conditions, commodity processing, gathering and transportation availability and the availability of refining capacity, price and availability of alternative fuels, price and quantity of foreign imports, domestic and foreign governmental regulations, political conditions in or affecting other oil and gas producing countries, weather and technological advances affecting oil, NGLs and gas consumption. As a result, we cannot accurately predict future oil, NGLs and gas prices, and therefore, we cannot determine what effect increases or decreases will have on our capital program, production volumes and future revenues. For example, in 2016, NYMEX-WTI oil prices ranged from a high of $54.06 per Bbl to a low of $26.21 per Bbl, NYMEX-Henry Hub natural gas prices ranged from a high of $3.93 per MMBtu to a low of $1.64 per MMBtu, and our realized prices for NGLs ranged from a high of $17.19 per Bbl to a low of $7.09 per Bbl. If the current oil or natural gas prices decline from current levels, they could have a material adverse effect on our business, financial condition and results of operations and quantities of oil, natural gas and NGLs reserves that may be economically produced and liquidity that may be accessed through our borrowing base under our revolving credit facility and through capital markets.

We also face the challenge of financing exploration, development and future acquisitions. We believe we have adequate liquidity for current, near-term working capital needs from cash generated from operations and, to the extent available, unused borrowing capacity under our revolving credit facility. However, we may choose to issue new equity, long-term debt or other convertible debt or equity securities in the capital markets, depending on market conditions and availability, to address our near-term funding requirements, or as an alternative to borrowing under our revolving credit facility. In the longer term, the Company expects a portion of its funding needs to be covered by cash flows from operations, and may issue debt or equity or monetize assets to cover any difference between cash flow from operations and capital or liquidity needs. We cannot guarantee that such financing will be available on acceptable terms or at all.

In addition to production volumes, financing and commodity prices, finding and developing sufficient amounts of oil and gas reserves at economical costs is critical to our long-term success. Future finding and development costs are subject to changes in the industry, including the costs of acquiring, drilling and completing our projects. We focus our efforts on increasing oil and gas reserves and production while controlling costs at a level that is appropriate for long-term operations. Our future cash flow from operations will depend on our ability to manage our overall cost structure.

Like all oil and gas production companies, we face the challenge of natural production declines. Oil and gas production from a given well naturally decreases over time. Additionally, our wells have a rapid initial production decline. We attempt to overcome this natural decline by drilling to develop and identify additional reserves, farm-ins or other joint drilling ventures and by acquisitions. However, during times of severe price declines, we may reduce current capital expenditures and curtail drilling operations in order to preserve liquidity. A material reduction in capital expenditures and drilling activities could materially reduce our production volumes and revenues.

2016 Activity

Our 2016 activity focused on operating within cash flow while managing production declines, improving cost structure and strengthening our balance sheet. We drilled six, and completed five, horizontal wells in 2016 in the Wolfcamp shale oil resource play in the Midland Basin. We plan to continue to develop the Wolfcamp shale in Project Pangea in 2017, at a measured, but increased pace from 2016, subject to commodity prices. Our activities in 2016 included:

• Managed production decline. In 2016, we reduced our capital expenditures by $131.4 million, to $19.8 million. During the first quarter of 2016, our production declined by 12% compared to the prior quarter due to no new well completions from August 2015 through the first quarter of 2016 and natural production decline. Our production decreased by 1%, 3% and 1% in the second, third and fourth quarters of 2016, respectively. We managed our natural production decline through operating efficiencies and investment in well repairs, workovers and maintenance. Production for 2016 totaled 4.5 MMBoe (12.4 MBoe/d), compared to 5.5 MMBoe (15.2 MBoe/d) in 2015. Production for 2016 was 28% oil, 34% NGLs and 38% natural gas. At December 31, 2016, six wells were waiting on completion.

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• Operated within operating cashflow. In 2016, we generated $26.1 million in operating cash flow, incurred $19.8 million of capital expenditures and had no increase in the principal balance of our debt outstanding.

• Reduced operating expenses to improve operating cash flow. In 2016, through our cost saving initiatives, we reduced lease operating expenses by $9.7 million, general and administrative expenses by $3.6 million and production and ad valorem taxes by $2.9 million.  

• Strengthened our balance sheet.  On November 2, 2016, we entered into the Exchange Agreement. In January 2017, we closed the Initial Exchange and launched the Follow-On Exchange. The Initial Exchange reduced our long-term debt by $130.6 million and will result in future interest savings of approximately $40 million. The Follow-On Exchange, if closed, is expected to further reduce our debt and improve our operating cash flow through the reduction of interest expense.

• Delineation of the multi-zone potential of the Wolfcamp shale. The Wolfcamp shale has a gross pay thickness of approximately 1,000 to 1,200 feet, which allows for stacked wellbores targeting three different zones that we call “benches.” We believe effectively developing the Wolfcamp shale may involve up to three lateral wellbores, each targeting a different bench, which we refer to as the Wolfcamp A, B and C. As of December 31, 2016, we had drilled and completed a total of 17 wells targeting the Wolfcamp A bench, 106 wells targeting the Wolfcamp B bench and 46 wells targeting the Wolfcamp C bench. We have successful wells targeting each of the Wolfcamp benches, and we continued development of the Wolfcamp shale in 2016.

• Installation of field infrastructure and water handling systems. Our large, mostly contiguous acreage position and our success in the Wolfcamp shale oil play led us to invest over $115 million in building field infrastructure since 2012. We now have an extensive network of centralized production facilities, water transportation, handling and recycling systems, gas lift lines and salt water disposal wells. In addition, we believe the infrastructure reduces the need for trucks, reduces fresh water usage, improves drilling and completion efficiencies and drives down drilling and completion and operating costs. In large part due to this infrastructure investment, we were able to reduce our lease operating expenses per Boe by 19% to $4.24, and our drilling and completion cost by 22% to $3.5 million, in 2016.

Plans for 2017

In January 2017, we closed the Initial Exchange and issued 39,165,600 shares of common stock in exchange for 7% Senior Notes due 2021 (the “Senior Notes”) with a principal amount of $130,552,000. Additionally, we launched the Follow-On Exchange offering shares of our common stock, at a ratio of 276 shares of common stock per $1,000 principal amount of our Senior Notes, to the holders of our remaining $99,768,000 principal amount of outstanding Senior Notes. We anticipate closing the Follow-On Exchange on or around March 22, 2017. Assuming full participation in the Follow-On Exchange, together with the Initial Exchange, we would reduce our cash interest payments by $13.9 million in 2017 and by $69.5 million over the term of the Senior Notes. This will provide us the flexibility to use the interest savings to invest in our capital budget, to continue to reduce long-term debt or for other corporate purposes. There are no minimum subscription requirements for the Follow-On Exchange, and we cannot predict participation levels.

For 2017, we increased our capital expenditure budget to a range of $50 million to $70 million, compared to $19.8 million of capital expenditures in 2016. We currently have one rig running. Our 2017 capital budget excludes acquisitions and lease extensions and renewals and is subject to change depending upon a number of factors, including prevailing and anticipated prices for oil, NGLs and gas, results of horizontal drilling and completions, economic and industry conditions at the time of drilling, the availability of sufficient capital resources for drilling prospects, our financial results and the availability of lease extensions and renewals on reasonable terms. Although the impact of changes in these collective factors in the current commodity price environment is difficult to estimate, we currently expect to execute our development plan based on current conditions. To the extent there is a significant increase or decrease in commodity prices in the future, we will assess the impact on our development plan at that time, and we may respond to such changes by altering our capital budget or our development plan.

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Results of Operations

The following table sets forth summary information regarding oil, NGLs and gas revenues, production, average product prices and average production costs and expenses for the last three years. We determined the Boe using the ratio of six Mcf of natural gas to one Boe, and one barrel of NGLs to one Boe. The ratios of six Mcf of natural gas to one Boe and one barrel of NGLs to one Boe do not assume price equivalency and, given price differentials, the price for a Boe for natural gas or NGLs may differ significantly from the price for a barrel of oil.

	Years Ended December 31,
	2016		2015		2014
Revenues (in thousands)
Oil	$	48,311	$	82,170	$	177,491
NGLs		19,761		20,437		41,998
Gas		22,230		28,729		39,040
Total oil, NGLs and gas sales		90,302		131,336		258,529
Realized gain on commodity derivatives		6,132		52,489		2,359
Total oil, NGLs and gas sales including    derivative impact	$	96,434	$	183,825	$	260,888
Production
Oil (MBbls)		1,275		1,882		2,024
NGLs (MBbls)		1,529		1,694		1,461
Gas (MMcf)		10,404		11,732		9,383
Total (MBoe)		4,537		5,532		5,049
Total (MBoe/d)		12.4		15.2		13.8
Average prices
Oil (per Bbl)	$	37.90	$	43.65	$	87.69
NGLs (per Bbl)		12.93		12.06		28.74
Gas (per Mcf)		2.14		2.45		4.16
Total (per Boe)	$	19.90	$	23.74	$	51.20
Realized gain on commodity derivatives (per Boe)		1.35		9.49		0.47
Total including derivative impact (per Boe)	$	21.25	$	33.23	$	51.67
Costs and expenses (per Boe)
Lease operating	$	4.24	$	5.24	$	6.48
Production and ad valorem taxes		1.81		2.00		3.16
Exploration		0.86		0.80		0.76
General and administrative		5.45		5.12		6.36
Depletion, depreciation and amortization		17.42		19.76		21.15

Oil, NGLs and gas sales.     Oil, NGLs and gas sales for 2016 decreased $41 million, or 31%, to $90.3 million from $131.3 million in 2015. The decrease in oil, NGLs and gas sales was due to a decrease in average realized commodity prices ($17.4 million) and a decrease in production volumes ($23.6 million). In 2016, the average price we received for our production, before the effect of commodity derivatives, decreased 16% to $19.90 per Boe, down from $23.74 per Boe in the prior year. Production volumes decreased from 2015, as a result of reduced drilling and completion activity.  We expect oil, NGLs and gas sales to increase in 2017 due to improved commodity prices.

Oil, NGLs and gas sales for 2015 decreased $127.2 million, or 49%, to $131.3 million from $258.5 million in 2014. The decrease in oil, NGLs and gas sales was due to a decrease in average realized commodity prices ($131.3 million), offset by an increase in production volumes ($4.1 million). In 2015, the average price we received for our production, before the effect of commodity derivatives, decreased 54% to $23.74 per Boe, down from $51.20 per Boe in the prior year. Production volumes increased as a result of completing 28 wells in Project Pangea in 2015.

Net (loss) income .    Net loss for 2016 was $52.2 million, or $1.26 per diluted share, compared to $174.1 million, or $4.30 per diluted share, for 2015. Net loss for 2016 included an unrealized loss on commodity derivatives of $11.6 million and a realized gain on commodity derivatives of $6.1 million. The decrease in the net loss for 2016 was primarily due to the impairment loss ($220.2 million) in 2015 and lower operating expenses excluding

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impairment ($48.4 million), partially offset by lower revenues ($41 million) due to depressed commodity prices and lower production and a decrease in income tax benefit ($69 million).

Net loss for 2015 was $174.1 million, or $4.30 per diluted share, compared to net income of $56.2 million, or $1.42 per diluted share, for 2014. Net loss for 2015 included an impairment loss of $220.2 million, a tax benefit of $93.4 million primarily related to the impairment loss, a realized gain on commodity derivatives of $52.5 million, an unrealized loss on commodity derivatives of $33.2 million, a gain on debt extinguishment of $10.6 million and termination costs of $1.4 million. Net loss for 2015 was primarily due to lower commodity prices, which resulted in a decrease in revenues of $127.2 million and an impairment loss of $220.2 million, partially offset by a change in income taxes of $127.1 million.

Oil, NGLs and gas production.     Production for 2016 totaled 4,537 MBoe (12.4 MBoe/d), compared to 5,532 MBoe (15.2 MBoe/d) in 2015, a decrease of 18%. Production for 2016 was 28% oil, 34% NGLs and 38% natural gas, compared to 34% oil, 31% NGLs and 35% natural gas in 2015. The decrease in production in 2016 was the result of our reduced drilling and completion activity in 2016. We expect production to slightly decrease in 2017 as a result of our reduced capital expenditures in 2016.

Production for 2015 totaled 5,532 MBoe (15.2 MBoe/d), compared to 5,049 MBoe (13.8 MBoe/d) in 2014, an increase of 10%. Production for 2015 was 34% oil, 31% NGLs and 35% natural gas, compared to 40% oil, 29% NGLs and 31% natural gas in 2014. The increase in production in 2015 was the result of our continued development of our Permian Basin properties.

Commodity derivative activities.     Realized gains from our commodity derivative activities increased our earnings by $6.1 million for 2016, compared to $52.5 million and $2.4 million for 2015 and 2014, respectively. Realized gains and losses are derived from the relative movement of commodity prices in relation to the fixed notional pricing in our derivative contracts for the respective years. The unrealized loss on commodity derivatives was $11.6 million for 2016. This is compared to an unrealized loss of $33.2 million for 2015 and an unrealized gain of $42.1 million in 2014. As commodity prices increase or decrease, the fair value of the open portion of those positions decreases or increases, respectively. For 2017, we currently have 709,750 Bbls of NGLs hedged at an average price of $20.98 per Bbl and 8,400,000 MMBtu of gas hedged at an average floor price of $2.79 per MMBtu and an average ceiling price of $3.15 per MMBtu.

Historically, we have not designated our derivative instruments as cash-flow hedges. We record our open derivative instruments at fair value on our consolidated balance sheets as either unrealized gains or losses on commodity derivatives. We record changes in such fair value in earnings on our consolidated statements of operations under the caption entitled “unrealized (loss) gain on commodity derivatives.”

Lease operating expenses.     Our lease operating expenses (“LOE”) decreased $9.7 million, or 34%, for 2016, to $19.3 million ($4.24 per Boe) from $29 million ($5.24 per Boe) for 2015. LOE per Boe in 2016 decreased $1.00, or 19%, from 2015. The decrease in LOE per Boe in 2016 over 2015 was primarily due to increased efficiency in our water hauling operations, lower pumpers and supervision costs due to a reduction in our workforce and a decrease in compressor rental and repair due to cost saving initiatives, partially offset by an increase in well repairs, workovers and maintenance to manage production declines. We expect LOE per Boe in 2017 to slightly increase due to natural production decline.

Our LOE decreased $3.7 million, or 11%, for 2015, to $29 million ($5.24 per Boe) from $32.7 million ($6.48 per Boe) for 2014. LOE per Boe in 2015 decreased $1.24, or 19%, from 2014. The decrease in LOE per Boe in 2015 over 2014 was primarily due to a decrease in well repairs, workovers and maintenance, increased efficiency in our water hauling and overall operations and other cost-saving initiatives.

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The following tables summarize LOE (in millions) and LOE per Boe.

	Year Ended December 31,
	2016				2015				Change						% Change
	$MM		Boe		$MM		Boe		$MM			Boe			(Boe)
Compressor rental and repair	$	7.2	$	1.58	$	10.2	$	1.84	$	(3.0	)	$	(0.26	)		(14.1	)%
Water hauling and other		5.0		1.09		9.2		1.66		(4.2	)		(0.57	)		(34.3	)
Pumpers and supervision		2.8		0.62		5.3		0.95		(2.5	)		(0.33	)		(34.7	)
Well repairs, workovers and    maintenance		4.3		0.95		4.3		0.79		—			0.16			20.3
Total	$	19.3	$	4.24	$	29.0	$	5.24	$	(9.7	)	$	(1.00	)		(19.1	)%

	Year Ended December 31,
	2015				2014				Change						% Change
	$MM		Boe		$MM		Boe		$MM			Boe			(Boe)
Compressor rental and repair	$	10.2	$	1.84	$	9.6	$	1.90	$	0.6		$	(0.06	)		(3.2	)%
Water hauling and other		9.2		1.66		9.6		1.90		(0.4	)		(0.24	)		(12.6	)
Pumpers and supervision		5.3		0.95		5.0		0.99		0.3			(0.04	)		(4.0	)
Well repairs, workovers and    maintenance		4.3		0.79		8.5		1.69		(4.2	)		(0.90	)		(53.3	)
Total	$	29.0	$	5.24	$	32.7	$	6.48	$	(3.7	)	$	(1.24	)		(19.1	)%

Production and ad valorem taxes.     Our 2016 production and ad valorem taxes decreased approximately $2.9 million, or 26%, to $8.2 million from $11.1 million for 2015. The decrease in production and ad valorem taxes was primarily the result of a decrease in oil, NGLs and gas sales over 2015. Production and ad valorem taxes were approximately 9.1% and 8.4% of oil, NGLs and gas sales for the respective periods. Production and ad valorem taxes as a percentage of revenue increased in 2016 due to an increase in ad valorem tax rates in 2016.

Our 2015 production and ad valorem taxes decreased approximately $4.8 million, or 30%, to $11.1 million from $15.9 million for 2014. The decrease in production and ad valorem taxes was primarily the result of a decrease in oil, NGLs and gas sales over 2014. Production and ad valorem taxes were approximately 8.4% and 6.2% of oil, NGLs and gas sales for the respective periods. Production and ad valorem taxes as a percentage of revenue increased in 2015 due to a refund from the state of Texas for production taxes on natural gas properties of approximately $1 million relating to tax reimbursements in 2014.

Exploration expense.     We recorded $3.9 million, $4.4 million and $3.8 million of exploration expense for 2016, 2015 and 2014, respectively. The decrease in exploration expense in 2016 was primarily due to the early termination fees of drilling contracts for $2.2 million in 2015, partially offset by an increase in lease expirations in the current year. Exploration expense for 2014 resulted primarily from lease expirations in the Permian Basin.

General and administrative expenses.     Our general and administrative expenses (“G&A”) decreased $3.6 million, or 13%, to $24.7 million ($5.45 per Boe) for 2016 from $28.3 million ($5.12 per Boe) for 2015. The decrease in G&A was primarily due to lower share-based compensation, professional fees and other cost saving initiatives. In 2016, G&A included $1.3 million in expense related to cash-settled performance awards; these awards are re-measured each interim reporting period based on the fair market value of our common stock. Significant changes in the fair market value of our common stock will impact G&A per Boe. We expect G&A per Boe in 2017 to slightly increase due to natural production decline.

Our G&A decreased $3.8 million, or 12%, to $28.3 million ($5.12 per Boe) for 2015 from $32.1 million ($6.36 per Boe) for 2014. The decrease in G&A and G&A per Boe was primarily due to lower salaries and benefits, share-based compensation and other cost saving initiatives.

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The following table summarizes G&A (in millions) and G&A per Boe.

	Year Ended December 31,
	2016				2015				Change						% Change
	$MM		Boe		$MM		Boe		$MM			Boe			(Boe)
Salaries and benefits	$	12.1	$	2.68	$	12.1	$	2.19	$	0.0		$	0.49			22.4	%
Share-based compensation		6.3		1.38		8.0		1.44		(1.7	)		(0.06	)		(4.2	)
Professional fees		1.6		0.36		2.9		0.52		(1.3	)		(0.16	)		(30.8	)
Other		4.7		1.03		5.3		0.97		(0.6	)		0.06			6.2
Total	$	24.7	$	5.45	$	28.3	$	5.12	$	(3.6	)	$	0.33			6.4	%

	Year Ended December 31,
	2015				2014				Change						% Change
	$MM		Boe		$MM		Boe		$MM			Boe			(Boe)
Salaries and benefits	$	12.1	$	2.19	$	15.4	$	3.05	$	(3.3	)	$	(0.86	)		(28.2	)%
Share-based compensation		8.0		1.44		8.2		1.63		(0.2	)		(0.19	)		(11.7	)
Professional fees		2.9		0.52		2.6		0.52		0.3			—			—
Other		5.3		0.97		5.9		1.16		(0.6	)		(0.19	)		(16.4	)
Total	$	28.3	$	5.12	$	32.1	$	6.36	$	(3.8	)	$	(1.24	)		(19.5	)%

Termination costs.     We did not recognize termination costs in 2016. In 2015, we recorded $1.4 million of termination costs in connection with a reduction in our workforce.

Depletion, depreciation and amortization expense.      Our depletion, depreciation and amortization expense (“DD&A”) decreased $30.3 million, or 28%, to $79 million for 2016, from $109.3 million for 2015. The decrease in DD&A in 2016 over 2015 was primarily attributable to a decrease in production. Our DD&A per Boe decreased by $2.34, or 12%, to $17.42 per Boe for 2016, compared to $19.76 per Boe for 2015. The decrease in DD&A per Boe over the prior-year period was primarily due to lower oil and gas property carrying costs relative to estimated proved developed reserves.

DD&A increased $2.5 million, or 2%, to $109.3 million for 2015, from $106.8 million for 2014. The increase in DD&A in 2015 over 2014 was primarily attributable to an increase in production. Our DD&A per Boe decreased by $1.39, or 7%, to $19.76 per Boe for 2015, compared to $21.15 per Boe for 2014. The decrease in DD&A per Boe over the prior-year period was primarily due to lower oil and gas property carrying costs relative to estimated proved developed reserves.

Impairment of oil and gas properties.     We did not recognize an impairment on our oil and gas properties in 2016. We recognized a non-cash impairment loss of $220.2 million in 2015, due primarily to a decrease in our estimated future cash flows related to forward commodity prices. The impairment loss was primarily attributable to vertical Canyon wells in Ozona Northeast. Significant inputs used to assess proved property impairment include estimates of (i) future sales prices for oil and gas based on NYMEX strip prices, (ii) pricing adjustments for differentials, (iii) production costs, (iv) capital expenditures, (v) future oil and gas reserves to be recovered and the timing of recovery and (vi) discount rate.

Interest expense, net.     The following table sets forth interest expense, weighted average interest rates and weighted average debt balances for the years ended December 31, 2016, 2015 and 2014 (dollars in thousands).

	Year Ended December 31,
	2016			2015			2014
Interest expense	$	27,259		$	25,066		$	21,651
Weighted average interest rate		5.4	%		5.1	%		6.9	%
Weighted average debt balance	$	507,605		$	491,528		$	315,575

Interest expense for the years ended December 31, 2016, 2015 and 2014 includes amortization of debt issuance costs of $1.4 million, $1.6 million and $1.5 million, respectively. Interest expense, net, increased $2.2

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million or 9%, to $27.3 million for 2016, compared to $25.1 million for 2015. This increase was due to higher interest expense from an increased weighted average debt balance and the applicable margin rates under our revolving credit facility, partially offset by interest savings of $1.3 million from our 2015 repurchase of $19.7 million aggregate face value of our Senior Notes on the open market.

Interest expense, net, increased $3.4 million or 16%, to $25.1 million for 2015, compared to $21.7 million for 2014. This increase was due to higher interest expense from increased borrowings under our revolving credit facility. We expect our interest expense to decrease in 2017 due to the reduction in our outstanding long-term debt from the Initial Exchange and the anticipated completion of the Follow-On Exchange.

Write-off of debt issuance costs.    In 2016, we recorded a $0.6 million write-off of unamortized debt issuance costs, related to the third amendment of our revolving credit facility, due to the reduction in our borrowing base from $450 million to $325 million.

Gain on extinguishment of debt.     In 2016, we did not repurchase any outstanding debt. In 2015, we repurchased a portion of our Senior Notes in the open market with an aggregate face value of $19.7 million for a purchase price of $8.8 million, including accrued interest. This resulted in a gain on extinguishment of debt of $10.6 million.

Other income.     In 2016, we recorded other income of $1.5 million primarily related to a contractual settlement of $1.4 million.

Income taxes.     Our effective income tax rate for 2016, 2015 and 2014 was 31.9%, 34.9% and 37.5%, respectively. Our effective income tax rates differ from the statutory rate primarily due to deferred tax asset reversals related to share-based compensation.  In 2016 and 2015, this reduced our effective tax rates by 2.4% and 0.7%, respectively. In 2014, this increased our effective tax rate by 1.9%. Additionally, in 2016, state taxes reduced our effective tax rate by 0.8%, compared to an increase of 0.5% and 1.1% in 2015 and 2014, respectively.

The Follow-On Exchange may result in a change in ownership of our common stock by more than 50% within a three-year period. An ownership change would establish an annual limitation on the amount of our pre-change NOLs that we could use to offset our taxable income in any future taxable year to an amount generally equal to the value of our common stock immediately before the ownership change, multiplied by the federal long-term tax exempt rate for the month of the ownership change. We believe that we may be able to offset, in part, such limitation through our potential to generate NOLs in the future, and may be able to use otherwise limited NOLs to the extent we recognize, or are treated as recognizing, built-in gain on assets owned before the ownership change. If such an ownership change occurs, we estimate that we could recognize a non-recurring charge, in our statement of operations for the three months ended March 31, 2017, in the range of $100 million to $130 million, in connection with the closing of the Follow-On Exchange.

Liquidity and Capital Resources

We generally will rely on cash generated from operations, to the extent available, borrowings under our revolving credit facility and, to the extent that credit and capital market conditions will allow, future public equity and debt offerings to satisfy our liquidity needs. Our ability to fund planned capital expenditures and to make acquisitions depends upon commodity prices, our future operating performance, availability of borrowings under our revolving credit facility, and more broadly, on the availability of equity and debt financing, which is affected by prevailing economic conditions in our industry and financial, business and other factors, some of which are beyond our control. We cannot predict whether additional liquidity from equity or debt financings beyond our revolving credit facility will be available on acceptable terms, or at all, in the foreseeable future.

Our cash flow from operations is driven by commodity prices, production volumes and the effect of commodity derivatives. Cash flows from operations are primarily used to fund exploration and development of our oil and gas properties. If commodity prices decline from current levels, our operating cash flows will decrease and our lenders may further reduce our borrowing base, thus limiting the amounts available to fund future capital expenditures. If we are unable to replace our oil, NGLs and gas reserves through acquisition, development and exploration, we may also suffer a reduction in operating cash flows and access to funds under our revolving credit

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facility. At December 31, 2016, we were in compliance with all required covenants under our revolving credit facility. If commodity prices decline from current levels, this may trigger non-compliance with required debt covenants in the future and otherwise adversely impact our ability to operate.

We believe we have adequate liquidity from cash generated from operations and unused borrowing capacity under our revolving credit facility for current working capital needs and maintenance of our current development plan. However, we may determine to use various financing sources, including the issuance of common stock, preferred stock, debt, convertible securities and other securities for future development of reserves, acquisitions, additional working capital or other liquidity needs, if such financing is available on acceptable terms. We cannot guarantee that such financing will be available on acceptable terms or at all. Using some of these financing sources may require approval from the lenders under our revolving credit facility.

On November 2, 2016, we entered into the Exchange Agreement. In January 2017, we closed the Initial Exchange and launched the Follow-On Exchange. The Initial Exchange reduced our long-term debt by $130.6 million and will result in future interest savings of approximately $40 million. The Follow-On Exchange, if closed, is expected to further reduce our long-term debt and improve our operating cash flow through the reduction of interest expense.

Liquidity

We define liquidity as funds available under our revolving credit facility plus year-end net cash and cash equivalents. At December 31, 2016, we had $273 million in borrowings outstanding under our revolving credit facility and $21,000 in cash and cash equivalents, compared to $273 million and $150 million in borrowings outstanding under our revolving credit facility and $0.6 million and $0.4 million in cash and cash equivalents at December 31, 2015, and 2014, respectively. Our liquidity position at December 31, 2016, decreased compared to December 31, 2015, due to a decrease in the borrowing base under our revolving credit facility to $325 million in May 2016. In November 2016, the lenders under our revolving credit facility completed their semi-annual borrowing base redetermination, which reaffirmed the aggregate lender commitments of $325 million.

The borrowing base under our revolving credit facility is redetermined semi-annually based on our oil, NGLs and gas reserves. In May 2016, the borrowing base decreased from $450 million to $325 million. In April 2015, the borrowing base decreased from $600 million to $525 million. In September 2015, the borrowing base decreased from $525 million to $450 million. As of December 31, 2014, the borrowing base under our revolving credit facility was $600 million. The reductions in our borrowing base in 2016 and 2015 were primarily attributable to decreases in commodity prices. We expect that our borrowing base review process will be completed in the second quarter of 2017.

The following table summarizes our liquidity position at December 31, 2016, 2015 and 2014 (in thousands).

	Year Ended December 31,
	2016			2015			2014
Credit Facility commitments	$	325,000		$	450,000		$	450,000
Cash and cash equivalents		21			600			432
Long-term debt — Credit Facility		(273,000	)		(273,000	)		(150,000	)
Undrawn letters of credit		(575	)		(325	)		(325	)
Liquidity	$	51,446		$	177,275		$	300,107

Working Capital

Our working capital is affected primarily by the fair value of our commodity derivative positions and our capital spending program. At December 31, 2016, we had a working capital deficit of $13.9 million, compared to a working capital deficit of $8.1 million and $45.8 million at December 31, 2015 and 2014, respectively. The change in working capital during 2016 was primarily attributable to changes in fair value of our commodity derivatives partially offset by a decrease in accounts payable and accrued liabilities due to a decrease in capital expenditures and cost reductions. The change in working capital during 2015 was primarily attributable to a decrease in accounts

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payable and accrued liabilities due to a decrease in our capital expenditures. The change in working capital during 2014 was primarily attributable to the decrease in cash to fund capital expended on our development project offset by changes in fair value of our commodity derivatives.To the extent we operate or end 2017 with a working capital deficit, we expect such deficit to be offset by liquidity available under our revolving credit facility.

Cash Flows

The following table summarizes our sources and uses of funds for the periods noted (in thousands).

	Year Ended December 31,
	2016			2015			2014
Cash flows provided by operating activities	$	26,081		$	102,716		$	171,604
Cash flows used in investing activities		(23,890	)		(217,347	)		(377,172	)
Cash flows (used in) provided by financing activities		(2,770	)		114,799			147,239
Net (decrease) increase in cash and cash equivalents	$	(579	)	$	168		$	(58,329	)

For 2016, our primary source of cash was from operating activities. Approximately $23.9 million of cash from operations was used to fund our $19.8 million of capital expenditures in 2016 for our development project in the Permian Basin and $4.1 million for changes in working capital related to investing activities. Cash flows used in investing activities were lower in 2016 compared to 2015, primarily due to a decrease in capital expenditures of $131.4 million as a result of depressed commodity prices. Cash flows used in financing activities were lower in 2016 primarily due to no net borrowings on our revolving credit facility in 2016, compared to $123 million in net borrowing on our credit facility in 2015.

For 2015, our primary sources of cash were from operating activities and financing activities. Approximately $102.7 million of cash from operations and $114.8 million of cash from financing activities were used to fund our development project in the Permian Basin. Cash flows used in investing activities were lower in 2015 compared to 2014, primarily due to a decrease in capital expenditures of $239.3 million as a result of depressed commodity prices.

For 2014, our primary sources of cash were from operating activities, financing activities and cash on hand. Approximately $171.6 million of cash from operations and $147.2 million of cash from financing activities were used to fund our development project in the Permian Basin. Cash flows used in investing activities were higher in 2014 compared to 2013, primarily due to an increase in capital expenditures of $94.1 million to fund the development of our Wolfcamp shale oil resource play.

Operating Activities

For 2016, our cash flows from operations were used primarily for drilling and development activities in the Permian Basin. Cash flows from operating activities decreased by $76.6 million, or 75%, to $26.1 million in 2016 from $102.7 million in 2015. The decrease in cash flows from operating activities in 2016 from 2015 was primarily due to a decrease in oil, NGLs and gas sales as a result of lower commodity prices and production, a decrease in realized gains from our commodity derivative activity, partially offset by a decrease in operating expenses.

For 2015, our cash flows from operations were used primarily for drilling and development activities in the Permian Basin. Cash flows from operating activities decreased by $68.9 million, or 40%, to $102.7 million in 2015 from $171.6 million in 2014. The decrease in cash flows from operating activities in 2015 from 2014 was primarily due to a decrease in oil, NGLs and gas sales as a result of lower commodity prices and the timing of receipts and payments of working capital components.

For 2014, our cash flows from operations and available cash were used primarily for drilling and development activities in the Permian Basin. Cash flows from operating activities increased by $60.9 million, or 55%, to $171.6 million in 2014 from $110.7 million in 2013. The increase in cash flows from operating activities in 2014 versus 2013 was primarily due to an increase in oil, NGLs and gas sales due to our development project in the Wolfcamp

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shale oil resource play and the timing of receipts and payments of working capital components, partially offset by an increase in total expenses.

Investing Activities

During the years ended December 31, 2016, 2015 and 2014, we invested $19.8 million, $151.2 million and $390.5 million, respectively, for capital expenditures on oil and gas properties. Cash flows used in investing activities was lower in 2016 compared to 2015 primarily due to a reduction in capital expenditures. Our capital expenditures for 2016 were primarily attributable to drilling and development ($17.8 million) and infrastructure projects and equipment ($3.1 million), partially offset by a legal settlement with a service provider ($1.1 million). Cash used in investing activities also included changes in working capital associated with investing activities ($4.1 million) related to 2015 capital expenditures that were paid in 2016. Cash flows used in investing activities were lower in 2015 compared to 2014, primarily due to a decrease in capital expenditures of $239.3 million as a result of depressed commodity prices.

The following table is a summary of capital expenditures related to our oil and gas properties (in thousands).

	Years Ended December 31,
	2016		2015		2014
Permian Basin	$	16,692	$	139,103	$	364,046
Permian Basin acquisitions		—		—		—
Subtotal		16,692		139,103		364,046
East Texas Basin		—		—		—
Exploratory projects		—		—		—
Infrastructure projects, equipment and 3-D seismic		3,079		11,422		21,882
Lease acquisitions and extensions		17		653		4,578
Total	$	19,788	$	151,178	$	390,506

Financing Activities

The following is a description of our financing activities in 2016, 2015 and 2014.

• In May 2016, the lenders under our revolving credit facility completed their semi-annual borrowing base redetermination and decreased the aggregate lender commitments to $325 million from $450 million.  In November 2016, the lenders under our revolving credit facility completed their semi-annual borrowing base redetermination, reaffirming the aggregate lender commitments of $325 million.

• In 2015, we repurchased a portion of our Senior Notes in the open market with an aggregate face value of $19.7 million for a purchase price of $8.8 million, including accrued interest.

• In May 2014, we entered into an amended and restated credit agreement, which provided for our revolving credit facility in the stated principal amount of $1 billion.

On November 2, 2016, we entered into the Exchange Agreement. In January 2017, we closed the Initial Exchange and launched the Follow-On Exchange. The Initial Exchange reduced our long-term debt by $130.6 million and will result in future interest savings of approximately $40 million. The Follow-On Exchange, if closed, is expected to further reduce our long-term debt and improve our operating cash flow through the reduction of interest expense. There are no minimum subscription requirements for the Follow-On Exchange, and we cannot predict participation levels.

In 2016, we did not increase the net outstanding balance under our revolving credit facility, compared to net borrowings of $123 million and $150 million in 2015 and 2014, respectively.

As market conditions warrant and subject to our contractual restrictions in our revolving credit facility or otherwise, liquidity position and other factors, we may from time to time seek to recapitalize, refinance or otherwise restructure our capital structure. We may accomplish this through open market or privately negotiated transactions,

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which may include, among other things, repurchases of our common stock or outstanding debt, debt for debt or debt for equity exchanges or refinancings, and private or public equity raises and rights offerings. Many of these alternatives may require the consent of current lenders, stockholders or bond holders, and there is no assurance that we will be able to execute any of these alternatives on acceptable terms or at all. The amounts involved in any such transaction, individually or in the aggregate, may be material.

Revolving Credit Facility

We have a $1 billion revolving credit facility with a borrowing base and aggregate lender commitments of $325 million. The borrowing base is redetermined semi-annually based on our oil and gas reserves. We or the lenders can each request one additional borrowing base redetermination each calendar year. We expect that our borrowing base review process will be completed in the second quarter of 2017.

The maturity date under our revolving credit facility is May 7, 2019. Borrowings bear interest based on the agent bank’s prime rate plus an applicable margin ranging from 1.50% to 2.50%, or the sum of the London Interbank Offered Rate (“LIBOR”) rate plus an applicable margin ranging from 2.50% to 3.50%. Margins vary based on the borrowings outstanding compared to the borrowing base. In addition, we pay an annual commitment fee of 0.50% of unused borrowings available under our revolving credit facility.

We had outstanding borrowings of $273 million under our revolving credit facility at December 31, 2016 and 2015. The weighted average interest rate applicable to borrowings under our revolving credit facility in 2016 was 3.3%. We also had outstanding unused letters of credit under our revolving credit facility totaling $0.6 million at December 31, 2016, which reduce amounts available for borrowing under our revolving credit facility.

Obligations under our revolving credit facility are secured by mortgages on substantially all of the oil and gas properties of the Company and its subsidiaries. The Company is required to maintain liens covering the oil and gas properties of the Company and its subsidiaries representing at least 90% of the total value of all oil and gas properties of the Company and its subsidiaries.

On May 3, 2016, we entered into a third amendment to our revolving credit facility.  Specifically, the third amendment modified our interest coverage ratio covenant (as defined in our revolving credit facility) to 1.25 to 1.0 (or 1.0 to 1.0 following the issuance of second lien indebtedness), through December 31, 2017, 1.5 to 1.0 through December 31, 2018, and 2.0 to 1.0 thereafter (from previous ratio of 2.5 to 1.0).  Additionally, the third amendment (a) decreased the borrowing base to $325 million from $450 million, (b) increased the applicable margin rates on borrowings by 100 basis points, (c) permits the Company to issue up to $150 million of second lien indebtedness, subject to various conditions and limitations, and (d) permits the Company to repurchase outstanding debt with proceeds of certain asset sales, equity issuances or second lien indebtedness. 

On December 30, 2014, we entered into a second amendment to our revolving credit facility. The second amendment, among other things, modified the negative covenant allowing optional redemption of unsecured notes.

Covenants

Our revolving credit facility contains two principal financial covenants:

• a consolidated interest coverage ratio covenant (as defined in our revolving credit facility) that requires us to maintain a ratio of consolidated EBITDAX to cash Interest Expense (as defined in the revolving credit facility) as of the last day of any fiscal quarter of not less than 1.25 to 1.0 (or 1.0 to 1.0 following the issuance of second lien indebtedness) through December 31, 2017, a ratio of not less than 1.5 to 1.0 through December 31, 2018, and a ratio of not less than 2.0 to 1.0 thereafter, and

• a consolidated modified current ratio covenant (as defined in our revolving credit facility) that requires us to maintain a ratio of not less than 1.0 to 1.0 as of the last day of any fiscal quarter.

Our revolving credit facility also contains covenants restricting cash distributions and other restricted payments, transactions with affiliates, incurrence of other debt, consolidations and mergers, the level of operating leases, asset sales, investment in other entities and liens on properties.

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The obligations of the Company may be accelerated upon the occurrence of an Event of Default (as defined in our revolving credit facility). Events of default include customary events for a financing agreement of this type, including, without limitation, payment defaults, the inaccuracy of representations and warranties, defaults in the performance of affirmative or negative covenants, defaults on other indebtedness of the Company or its subsidiaries, bankruptcy or related defaults, defaults related to judgments and the occurrence of a Change of Control (as defined in our revolving credit facility), which includes instances where a third party becomes the beneficial owner of more than 50% of the Company’s outstanding equity interests entitled to vote.

To date, we have experienced no disruptions in our ability to access our revolving credit facility. However, our lenders have substantial ability to reduce our borrowing base on the basis of subjective factors, including the loan collateral value that each lender, in its discretion and using the methodology, assumptions and discount rates as such lender customarily uses in evaluating oil and gas properties, assigns to our properties. We expect that our borrowing base review process will be completed in the second quarter of 2017.

Senior Notes

In June 2013, we completed our public offering of $250 million principal amount of 7% Senior Notes due 2021. Annual interest on the Senior Notes is payable semi-annually on June 15 and December 15. We received net proceeds from the issuance of the Senior Notes of approximately $243 million, after deducting fees and expenses. We used a portion of the net proceeds from the offering to repay all outstanding borrowings under our revolving credit facility. In 2014, we used the remaining net proceeds to fund our capital expenditures and for general working capital needs. During the year ended December 31, 2015, we repurchased Senior Notes in the open market with an aggregate face value of $19.7 million for a purchase price of $8.8 million, including accrued interest. This resulted in a gain on extinguishment of debt of $10.6 million.

On November 2, 2016, we entered into the Initial Exchange. In January 2017, we closed the Initial Exchange and launched the Follow-On Exchange. The Initial Exchange reduced our Senior Notes outstanding by $130.6 million and will result in future interest savings of approximately $40 million. The Follow-On Exchange, if closed, is expected to further reduce our long-term debt and improve our operating cash flow through the reduction of interest expense.

We issued the Senior Notes under a senior indenture dated June 11, 2013, among the Company, our subsidiary guarantors and Wilmington Trust, National Association, as successor trustee to Wells Fargo Bank, National Association. The senior indenture, as supplemented by a supplemental indenture dated June 11, 2013, is referred to as the “Indenture.”

On December 20, 2016, we entered in to the second supplemental indenture (the “Second Supplemental Indenture”), which became effective in connection with the closing of the Initial Exchange. The Second Supplemental Indenture (i) eliminated certain definitions and references to definitions contained in the Indenture; (ii) eliminated and revised, as applicable, certain events of default contained in the Indenture; (iii) eliminated certain conditions to consolidation, merger, conveyance, transfer or lease contained in the Indenture; (iv) eliminated certain covenants contained in the Indenture, including substantially all of the restrictive covenants set forth therein; and (v) supplemented and amended the Senior Notes and the securities guarantees, as and to the same extent as the Indenture has been amended and supplemented in accordance with the preceding clauses (i), (ii), (iii) and (iv).

We may redeem some or all of the Senior Notes at specified redemption prices, plus accrued and unpaid interest to the redemption date. The Senior Notes are fully and unconditionally guaranteed on a senior unsecured basis by each of our subsidiaries, subject to certain customary release provisions. A subsidiary guarantor may be released from its obligations under the guarantee:

• in connection with any sale or other disposition of all or substantially all of the assets of that guarantor (including by way of merger or consolidation) to a person that is not (either before or after giving effect to such transaction) the Company or a subsidiary guarantor, if the sale or other disposition otherwise complies with the indenture;

• in connection with any sale or other disposition of the capital stock of that guarantor to a person that is not (either before or after giving effect to such transaction) the Company or a subsidiary guarantor, if

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that guarantor no longer qualifies as a subsidiary of the Company as a result of such disposition and the sale or other disposition otherwise complies with the indenture;

• if the Company designates any restricted subsidiary that is a guarantor to be an unrestricted subsidiary in accordance with the indenture;

• upon defeasance or covenant defeasance of the notes or satisfaction and discharge of the indenture, in each case, in accordance with the indenture;

• upon the liquidation or dissolution of that guarantor, provided that no default or event of default occurs under the indenture as a result thereof or shall have occurred and is continuing; or

• in the case of any restricted subsidiary that, after the issue date of the notes is required under the indenture to guarantee the notes because it becomes a guarantor of indebtedness issued or an obligor under the revolving credit facility with respect to the Company and/or its subsidiaries, upon the release or discharge in full from its (x) guarantee of such indebtedness or (y) obligation under such revolving credit facility, in each case, which resulted in such restricted subsidiary’s obligation to guarantee the notes.

As a result of the Second Supplemental Indenture, the Indenture contains limited events of default.

At December 31, 2016, we were in compliance with all of our covenants, and there were no existing defaults or events of default, under our debt instruments.

Contractual Obligations

As of December 31, 2016, our contractual obligations include long-term debt, operating lease obligations, asset retirement obligations and employment agreements with our executive officers.

In April 2007, we signed a five-year lease for approximately 13,000 square feet of office space in Fort Worth, Texas. Since that time, we have expanded the lease to approximately 40,000 square feet and extended the term to March 31, 2020. In January 2017, we reduced the lease by approximately 5,500 square feet and extended the term to September 30, 2021. This amendment reduced our contractual obligations by approximately $0.4 million during the next three years, while increasing our total contractual obligations by $0.9 million over the extended term of the lease.

Our asset retirement obligation primarily represents the estimated present value of the amount we will incur to plug, abandon and remediate our producing properties at the end of their productive lives, in accordance with applicable federal, state and local laws. We determine our asset retirement obligation by calculating the present value of estimated cash flows related to the liability. The retirement obligation is recorded as a liability at its estimated present value as of the asset’s inception, with an offsetting increase to proved properties. Periodic accretion of discount of the estimated liability is recorded as an expense in the income statement.

At December 31, 2016, we had outstanding employment agreements with all four of our executive officers that contained automatic renewal provisions providing that such agreements may be automatically renewed for successive terms of one year unless the employment is terminated at the end of the term by written notice given to the employee not less than 60 days prior to the end of such term. Our maximum commitment under the employment agreements, which would apply if the employees covered by these agreements were each terminated without cause, was approximately $5.7 million at December 31, 2016. This estimate assumes the maximum potential bonus for 2017 is earned by each executive officer during 2017. In 2017, we amended the employment agreements with two of our executive officers which, among other things, increased the maximum commitment under the employment agreements, which would apply if the employees covered by these agreements were each terminated without cause, by approximately $0.6 million.

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The following table summarizes these commitments as of December 31, 2016 (in thousands).

	Payments Due By Period
Contractual Obligations	Total		Less than 1 year		1-3 years		3-5 years		More than 5 years
Credit agreement(1)	$	273,000	$	—	$	273,000	$	—	$	—
Senior Notes(2)		230,320		—		—		230,320		—
Operating lease obligations(3)		3,198		989		1,959		250		—
Asset retirement obligations(4)		10,607		—		—		—		10,607
Employment agreements with executive officers      and cash-settled performance awards (5)		9,627		7,034		2,593		—		—
Total	$	526,752	$	8,023	$	277,552	$	230,570	$	10,607

(1) Credit agreement matures on May 7, 2019.

(2) 7% Senior Notes due 2021. On January 27, 2017, the Initial Exchange closed, reducing our Senior Notes outstanding by $130.6 million.

(3) Operating lease obligations are for office space and equipment.

(4) See Note 1 to our consolidated financial statements for a discussion of our asset retirement obligations.

(5) See Note 5 to our consolidated financial statements for a discussion of our cash-settled performance awards. The amount above assumes that performance criteria of the cash-settled performance awards are met.

Critical Accounting Policies and Estimates

The discussion and analysis of our financial condition and results of operations are based upon our consolidated financial statements, which have been prepared in accordance with GAAP. The preparation of our consolidated financial statements requires us to make estimates and assumptions that affect our reported results of operations and the amount of reported assets, liabilities and proved oil and gas reserves. Some accounting policies involve judgments and uncertainties to such an extent that there is reasonable likelihood that materially different amounts could have been reported under different conditions, or if different assumptions had been used. Actual results may differ from the estimates and assumptions used in the preparation of our consolidated financial statements. Described below are the most significant policies we apply in preparing our consolidated financial statements, some of which are subject to alternative treatments under GAAP. We also describe the most significant estimates and assumptions we make in applying these policies. See Note 1 to our consolidated financial statements.

Segment reporting is not applicable to us as we have a single, company-wide management team that administers all significant properties as a whole, rather than by discrete operating segments. We track only basic operational data by area. We do not maintain complete separate financial statement information by area. We measure financial performance as a single enterprise and not on an area-by-area basis. We use the successful efforts method of accounting for our oil and gas activities.

Successful Efforts Method of Accounting

Accounting for oil and gas activities is subject to special, unique rules. We use the successful efforts method of accounting for our oil and gas activities. The significant principles for this method are:

• costs to acquire mineral interests in oil and gas properties and to drill and equip development wells and related asset retirement costs are capitalized. Costs to drill exploratory wells are capitalized pending determination of whether the wells have proved reserves;

• dry holes for exploratory wells are expensed and dry holes for development wells are capitalized;

• geological and geophysical evaluation costs are expensed as incurred; and

• capitalized costs related to proved oil and gas properties, including wells and related equipment and facilities, are evaluated for impairment based on an analysis of undiscounted future net cash flows in

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accordance with ASC 360. If undiscounted cash flows are insufficient to recover the net capitalized costs related to proved properties, then we recognize an impairment charge in income from operations equal to the difference between the net capitalized costs related to proved properties and their estimated fair values based on the present value of the related future net cash flows.

Proved Reserves

For the year ended December 31, 2016, we engaged DeGolyer and MacNaughton, independent petroleum engineers, to prepare independent estimates of the extent and value of 100% of our reported proved reserves, in accordance with rules and guidelines established by the SEC.

Estimates of proved oil and gas reserves directly impact financial accounting estimates including DD&A, evaluation of impairment of properties and the calculation of plugging and abandonment liabilities. Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods and government regulations. The process of estimating quantities of proved reserves is very complex, requiring significant subjective decisions in the evaluation of all geological, engineering and economic data for each reservoir. The data for any reservoir may change substantially over time due to results from operational activity. Proved reserve volumes at December 31, 2016, were estimated based on the average of the closing price on the first day of each month for the 12-month period prior to December 31, 2016, for oil, NGLs and gas in accordance with SEC rules. Changes in commodity prices and operations costs may increase or decrease estimates of proved oil, NGLs and natural gas reserves. Depletion expense for our oil and gas properties is determined using our estimates of proved oil, NGLs and gas reserves.

See also Item 2. “Properties — Proved Oil and Gas Reserves” and Note 10 to our consolidated financial statements in this report for additional information regarding our estimated proved reserves.

Derivative Instruments and Commodity Derivative Activities

Unrealized gains and losses on our commodity derivative contracts, at fair value, are included on our consolidated balance sheets as current or non-current assets or liabilities based on the anticipated timing of cash settlements under the related contracts. Changes in the fair value of our commodity derivative contracts are recorded in earnings as they occur and included in income (expense) on our consolidated statements of operations. We estimate the fair values of swap contracts based on the present value of the difference in exchange-quoted forward price curves and contractual settlement prices multiplied by notional quantities. We internally valued the option contracts using industry-standard option pricing models and observable market inputs. We use our internal valuations to determine the fair values of the contracts that are reflected on our consolidated balance sheets. Realized gains and losses are also included in income (expense) on our consolidated statements of operations.

We are exposed to credit losses in the event of nonperformance by the counterparties on our commodity derivatives positions and have considered the exposure in our internal valuations. However, we do not anticipate nonperformance by the counterparties over the term of the commodity derivatives positions.

We enter into financial swaps and collars to mitigate portions of the risk of market price fluctuations related to future oil, NGLs and gas production. All derivative instruments are recorded as derivative assets and liabilities at fair value in the balance sheet, and the changes in derivative’s fair value are recognized as current income or expense in the consolidated statement of operations.

For the years ended December 31, 2016, 2015 and 2014, we recognized unrealized losses on commodity derivatives of $11.6 million and $33.2 million, and an unrealized gain of $42.1 million, respectively. For the years ended December 31, 2016, 2015 and 2014, we recognized realized gains on commodity derivatives of $6.1 million, $52.5 million and $2.4 million, respectively.

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Asset Retirement Obligation

Our asset retirement obligation primarily represents the estimated present value of the amount we will incur to plug, abandon and remediate our producing properties at the end of their productive lives, in accordance with applicable federal, state and local laws. We determine our asset retirement obligation by calculating the present value of estimated cash flows related to the liability. The retirement obligation is recorded as a liability at its estimated present value as of the asset’s inception, with an offsetting increase to proved properties. Periodic accretion of discount of the estimated liability is recorded as an expense in the income statement.

Our liability is determined using significant assumptions, including current estimates of plugging and abandonment costs, annual inflation of these costs, the productive lives of wells and our risk-adjusted interest rate. Changes in any of these assumptions can result in significant revisions to the estimated asset retirement obligation.

Impairment of Long-Lived Assets

All of our long-lived assets are monitored for potential impairment when circumstances indicate that the carrying value of an asset may be greater than its future net cash flows. The evaluations involve a significant amount of judgment since the results are based on estimated future events, such as future sales prices for oil, NGLs and gas, future costs to produce these products, estimates of future oil and gas reserves to be recovered and the timing thereof, the economic and regulatory climates and other factors. The need to test an asset for impairment may result from significant declines in commodity prices or downward revisions to estimated quantities of oil and gas reserves. Any assets held for sale are reviewed for impairment when we approve the plan to sell. Estimates of anticipated sales prices are highly judgmental and subject to material revision in future periods. Because of the uncertainty inherent in these factors, we cannot predict when or if future impairment charges will be recorded. We recorded no impairment of our proved properties for the year ended December 31, 2016. For the year ended December 31, 2015, we recognized a non-cash impairment loss of $220.2 million, primarily attributable to vertical Canyon wells in Ozona Northeast. See Note 7 to our consolidated financial statements in this report for additional information regarding the significant inputs and methodology used in determining the impairment loss.

Provision for Income Taxes

We estimate our provision for income taxes using historical tax basis information from prior years’ income tax returns, along with the estimated changes to such bases from current-period activity and enacted tax rates. When tax returns are filed, it is highly certain that some positions taken would be sustained upon examination by the taxing authorities, while others are subject to uncertainty about the merits of the position taken or the amount of the position that would be ultimately sustained. The benefit of a tax position is recognized in the financial statements in the period during which, based on all available evidence, management believes it is more likely than not that the position will be sustained upon examination, including the resolution of appeals or litigation processes, if any. Tax positions taken are not offset or aggregated with other positions. Tax positions that meet the more-likely-than-not recognition threshold are measured as the largest amount of tax benefit that is more than 50% likely of being realized upon settlement with the applicable taxing authority. The portion of the benefits associated with tax positions taken that exceeds the amount measured as described above is reflected as a liability for unrecognized tax benefits in the accompanying balance sheet along with any associated interest and penalties that would be payable to the taxing authorities upon examination. Interest and penalties associated with unrecognized tax benefits are classified as additional income taxes in our consolidated statements of operations. Additionally, we compare liabilities to actual settlements of such assets or liabilities during the current period to identify considerations that might affect the current period’s estimate.

We monitor our deferred tax assets by jurisdiction to assess their potential realization, and a valuation allowance is recognized on deferred tax assets when we believe that certain of these assets are more likely than not to be realized. In performing this review, we make estimates and assumptions regarding projected future taxable income, the expected timing of reversals of existing temporary differences and the implementation of tax planning strategies. To the extent that a valuation allowance is established or changed during any period, we would recognize expense or benefit within our consolidated tax expense. We do not currently have a valuation allowance on our federal net operating loss carryforwards.

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Valuation of Share-Based Compensation

Our 2007 Plan allows grants of stock and options to employees and outside directors. Granting of awards may increase our G&A, subject to the size and timing of the grants. See Note 5 to our consolidated financial statements in this report for additional information.

In accordance with GAAP, we calculate the fair value of share-based compensation using various valuation methods. The valuation methods require the use of estimates to derive the inputs necessary to determine fair value. We use (i) the closing stock price on the date of grant for the fair value of restricted stock awards, including performance-based awards, (ii) the Monte Carlo simulation method for the fair value of market-based awards, (iii) the fair market value of our common stock on the valuation date for cash-settled performance awards and (iv) the Black-Scholes option price model to measure the fair value of stock options.

Effects of Inflation

Inflation in the United States has been relatively low in recent years and did not have a material impact on our results of operations for the years ended December 31, 2016, 2015 or 2014. Although the impact of inflation has been insignificant in recent years, it is still a factor in the United States economy and may increase the cost to acquire or replace property and equipment. It may also increase the cost of labor or supplies.

Off-Balance Sheet Arrangements

From time-to-time, we enter into off-balance sheet arrangements and transactions that can give rise to off-balance sheet obligations. As of December 31, 2016, the off-balance sheet arrangements and transactions that we have entered into include undrawn letters of credit and operating lease agreements. We do not believe that these arrangements are reasonably likely to materially affect our liquidity or availability of, or requirements for, capital resources.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Some of the information below contains forward-looking statements. The primary objective of the following information is to provide forward-looking quantitative and qualitative information about our potential exposure to market risks. The term “market risk” refers to the risk of loss arising from adverse changes in oil, NGLs and gas prices, and other related factors. The disclosure is not meant to be a precise indicator of expected future losses, but rather an indicator of reasonably possible losses. This forward-looking information provides an indicator of how we view and manage our ongoing market risk exposures. Our market risk sensitive instruments were entered into for commodity derivative and investment purposes, not for trading purposes.

Proved Reserves

Estimates of proved oil and gas reserves directly impact financial accounting estimates including DD&A, evaluation of impairment of properties and the calculation of plugging and abandonment liabilities. Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods and government regulations. The process of estimating quantities of proved reserves is very complex, requiring significant subjective decisions in the evaluation of all geological, engineering and economic data for each reservoir. The data for any reservoir may change substantially over time due to results from operational activity. Proved reserve volumes at December 31, 2016, were estimated based on the average of the closing price on the first day of each month for the 12-month period prior to December 31, 2016, for oil, NGLs and natural gas in accordance with SEC rules. Changes in commodity prices and operations costs may increase or decrease estimates of proved oil, NGLs and natural gas reserves.

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We expect that reductions in oil, NGLs and gas prices will not only decrease our revenues, but will also reduce the amount of oil, NGLs and gas that we can produce economically and therefore lower our oil, NGLs and gas reserves. A decrease of 10% in the oil, NGLs and gas prices used in our reserve report as of December 31, 2016, holding production and development costs constant, would result in:

• a decrease in our PV-10 as of December 31, 2016 of 15%;

• a decrease in our total proved reserves of 61%; and

• a decrease in our proved undeveloped reserves of 97%.

Actual future net revenues and reserve volumes also will be affected by factors such as the amount and timing of actual production, prevailing operating and development costs, supply and demand for oil and gas, increases or decreases in consumption and changes in governmental regulations or taxation. Additionally, depletion expense for our oil and gas properties is determined using our estimates of proved oil, NGLs and natural gas reserves. A hypothetical 10% decline in our December 31, 2016, estimated proved reserves would have increased our depletion expense by approximately $2.1 million for the year ended December 31, 2016.

Commodity Price Risk

Given the current economic outlook, we expect commodity prices to remain volatile. Even modest decreases in commodity prices can materially affect our revenues and cash flow. In addition, if commodity prices remain suppressed for a significant amount of time, we could be required under successful efforts accounting rules to write down our oil and gas properties.

In the year ended December 31, 2016, the NYMEX WTI spot price averaged $43.41 per barrel and ranged from a low of $26.21 per barrel to a high of $54.06 per barrel. In the year ended December 31, 2015, the NYMEX WTI spot price averaged $48.84 per barrel and ranged from a low of $34.73 per barrel to a high of $61.43 per barrel.

In the year ended December 31, 2016, the Henry Hub natural gas spot price averaged $2.56 per MMBtu and ranged from a low of $1.64 per MMBtu to a high of $3.93 per MMBtu. In the year ended December 31, 2015, the Henry Hub natural gas spot price averaged $2.63 per MMBtu and ranged from a low of $1.76 per MMBtu to a high of $3.23 per MMBtu.

We enter into financial swaps and options to reduce the risk of commodity price fluctuations. We do not designate such instruments as cash flow hedges. Accordingly, we record open commodity derivative positions on our consolidated balance sheets at fair value and recognize changes in such fair values as income (expense) on our consolidated statements of operations as they occur.

The table below summarizes our commodity derivatives positions outstanding at December 31, 2016.

Commodity and Period	Contract Type	Volume Transacted	Contract Price
Natural Gas
January 2017 — March 2017	Swap	100,000 MMBtu/month	$2.463/MMBtu
January 2017 — March 2017	Swap	300,000 MMBtu/month	$2.45/MMBtu
January 2017 — March 2017	Swap	200,000 MMBtu/month	$3.287/MMBtu
January 2017 — December 2017	Collar	100,000 MMBtu/month	$3.00/MMBtu - $3.65/MMBtu
April 2017 — December 2017	Collar	200,000 MMBtu/month	$2.30/MMBtu - $2.60/MMBtu
April 2017 — December 2017	Collar	200,000 MMBtu/month	$3.00/MMBtu - $3.44/MMBtu
April 2017 — December 2017	Collar	200,000 MMBtu/month	$3.00/MMBtu - $3.50/MMBtu

After December 31, 2016, we entered into the following commodity derivative positions:

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Commodity and Period	Contract Type	Volume Transacted	Contract Price
Natural Gas
January 2018 — December 2018	Swap	200,000 MMBtu/month	$3.085/MMBtu
January 2018 — December 2018	Swap	250,000 MMBtu/month	$3.084/MMBtu
NGL (C2 - Ethane)
February 2017 — December 2017	Swap	1,050 Bbls/day	$11.34/Bbl
NGL (C3 - Propane)
February 2017 — December 2017	Swap	750 Bbls/day	$27.916/Bbl
NGL (IC4 - Isobutane)
February 2017 — December 2017	Swap	75 Bbls/day	$36.7325/Bbl
NGL (NC4 - Butane)
February 2017 — December 2017	Swap	250 Bbls/day	$35.9205/Bbl

At December 31, 2016, the fair value of our open derivative contracts was a liability of approximately $4.9 million, compared to an asset of $6.7 million at December 31, 2015.

We are exposed to credit losses in the event of nonperformance by counterparties on our commodity derivatives positions. We do not anticipate nonperformance by the counterparties over the term of the commodity derivatives positions; however, we cannot be certain that we will not experience such losses in the future. All of the counterparties to our commodity derivative positions are participants in our revolving credit facility, and the collateral for the outstanding borrowings under our revolving credit facility is used as collateral for our commodity derivatives.

Unrealized gains and losses, at fair value, are included on our consolidated balance sheets as current or non-current assets or liabilities based on the anticipated timing of cash settlements under the related contracts. Changes in the fair value of our commodity derivative contracts are recorded in earnings as they occur and included in other income (expense) on our consolidated statements of operations. We estimate the fair values of swap contracts based on the present value of the difference in exchange-quoted forward price curves and contractual settlement prices multiplied by notional quantities. We internally valued the option contracts using industry-standard option pricing models and observable market inputs. We use our internal valuations to determine the fair values of the contracts that are reflected on our consolidated balance sheets. Realized gains and losses are also included in other income (expense) on our consolidated statements of operations.

For the years ended December 31, 2016, 2015 and 2014, we recognized unrealized losses of $11.6 million and $33.2 million, and an unrealized gain of $42.1 million, respectively. A hypothetical 10% increase in the NYMEX floating prices would have resulted in a $2.4 million decrease in the fair value recorded of our commodity derivative positions on our balance sheet at December 31, 2016, and a corresponding increase to the unrealized loss on commodity derivatives on our statement of operations for the year ended December 31, 2016.

See Note 7 to our consolidated financial statements for a discussion of our fair value measurements.

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Our consolidated financial statements and supplemental data are included in this report beginning on page F-1.

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

We had no changes in, and no disagreements with, our accountants on accounting and financial disclosure.

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ITEM 9A. CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

Our management, with the participation of our Chief Executive Officer and Chief Financial Officer, has evaluated the effectiveness of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of December 31, 2016. Based on this evaluation, our Chief Executive Officer and Chief Financial Officer have concluded that, as of December 31, 2016, our disclosure controls and procedures were effective, in that they ensure that information required to be disclosed by us in the reports that we file or submit under the Exchange Act is (1) recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and (2) accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure.

Internal Control over Financial Reporting

Management’s Annual Report on Internal Control Over Financial Reporting and Attestation Report of Registered Public Accounting Firm

Pursuant to Section 404 of the Sarbanes-Oxley Act of 2002, we have included a report of management’s assessment of the design and effectiveness of our internal controls as part of this annual report on Form 10-K for the fiscal year ended December 31, 2016. Hein & Associates LLP (“Hein”), our independent registered public accounting firm, also attested to, and reported on, our internal control over financial reporting. Management’s report and Hein’s attestation report are referenced on page F-1 under the captions “Management’s Report on Internal Control over Financial Reporting” and “Report of Independent Registered Public Accounting Firm —Internal Control over Financial Reporting” and are incorporated herein by reference.

Changes in Internal Control over Financial Reporting

No changes to our internal control over financial reporting occurred during the quarter ended December 31, 2016, that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act).

ITEM 9B. OTHER INFORMATION

None.

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PART III

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

Information required under Item 10 of this report will be contained under the captions “Election of Directors–Directors,” “Executive Officers” and “Corporate Governance” to be provided in our proxy statement for our 2017 annual meeting of stockholders to be filed with the SEC within 120 days of December 31, 2016, which is incorporated herein by reference. Also, the charters of our Audit Committee, Compensation Committee and Nominating and Corporate Governance Committee, our Lead Independent Director Charter, our Governance Guidelines and our Code of Conduct may be found on our website at www.approachresources.com.

ITEM 11. EXECUTIVE COMPENSATION

Information required by Item 11 of this report will be contained under the caption “Executive Compensation” in our definitive proxy statement for our 2017 annual meeting of stockholders to be filed with the SEC within 120 days of December 31, 2016, which is incorporated herein by reference.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

Information required by Item 12 of this report will be contained under the caption “Stock Ownership Matters” in our definitive proxy statement for our 2017 annual meeting of stockholders to be filed with the SEC within 120 days of December 31, 2016, which is incorporated herein by reference.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

Information required by Item 13 of this report will be contained under the captions “Certain Relationships and Related-Party Transactions” and “Corporate Governance–Board Independence” in our definitive proxy statement for our 2017 annual meeting of stockholders to be filed with the SEC within 120 days of December 31, 2016, which are incorporated herein by reference.

ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES

Information required by Item 14 of this report will be contained under the caption “Independent Registered Public Accountants” in our definitive proxy statement for our 2017 annual meeting of stockholders to be filed with the SEC within 120 days of December 31, 2016, which is incorporated herein by reference.

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PART IV

ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES

(a) Documents filed as part of this report

(1) and (2) Financial Statements.

See “Index to Consolidated Financial Statements” on page F-1.

All financial statement schedules are omitted because they are not applicable, or are immaterial or the required information is presented in the consolidated financial statements or the related notes.

(3) Exhibits.

See “Index to Exhibits” on page 72 for a description of the exhibits filed as part of this report.

ITEM 16. FORM 10-K SUMMARY

None.

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GLOSSARY AND SELECTED ABBREVIATIONS

The following is a description of the meanings of some of the oil and gas industry terms used in this report.

3-D seismic	(Three Dimensional Seismic Data) Geophysical data that depicts the subsurface strata in three dimensions. 3-D seismic data typically provides a more detailed and accurate interpretation of the subsurface strata than two dimensional seismic data.
Basin	A large natural depression on the earth’s surface in which sediments generally brought by water accumulate.
Bbl	One stock tank barrel, of 42 U.S. gallons liquid volume, used to reference oil, condensate or NGLs.
Boe	Barrel of oil equivalent, determined using the ratio of six Mcf of gas to one Boe, and one Bbl of NGLs to one Boe.
Btu or British Thermal Unit	The quantity of heat required to raise the temperature of one pound of water by one degree Fahrenheit.
Completion	The installation of permanent equipment for production of oil or gas, or, in the case of a dry well, for reporting to the appropriate authority that the well has been abandoned.
Developed acreage	The number of acres that are allocated or assignable to productive wells or wells that are capable of production.
Developed oil and gas reserves	Has the meaning given to such term in Rule 4-10(a)(6) of Regulation S-X, as follows:
	Developed oil and gas reserves are reserves of any category that can be expected to be recovered:
	(i)	Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and
	(ii)	Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.
Development project	The means by which petroleum resources are brought to the status of economically producible. As examples, the development of a single reservoir or field, an incremental development in a producing field or the integrated development of a group of several fields and associated facilities with a common ownership may constitute a development project.
Development well	A well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive.
Dry hole or well	An exploratory, development or extension well that proved to be incapable of producing either oil or gas in sufficient quantities to justify completion as an oil or gas well.
Dry hole costs	Costs incurred in drilling a well, assuming a well is not successful, including plugging and abandonment costs.
Exploratory well	A well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir.
Extension well	A well drilled to extend the limits of a known reservoir.

66

Farm-in	An arrangement in which the owner or lessee of mineral rights (the first party) assigns a working interest to an operator (the second party), the consideration for which is specified exploration and/or development activities. The first party retains an overriding royalty, working interest or other type of economic interest in the mineral production. The arrangement from the viewpoint of the second party is termed a “farm-in” arrangement.
Field	An area consisting of either a single reservoir or multiple reservoirs, all grouped on or related to the same individual geological structural feature and/or stratigraphic condition.
Field fuel	Gas consumed to operate field equipment (primarily for compressors and artificial lifts).
Hydraulic fracturing	The technique designed to improve a well’s production rates by pumping a mixture of water and sand (in our case, over 99% by mass) and chemical additives (in our case, less than 1% by mass) into the formation and rupturing the rock, creating an artificial channel.
Henry Hub	Henry Hub is the major exchange for pricing for natural gas futures on the NYMEX.
Gross acres or gross wells	The total acres or wells, as the case may be, in which a working interest is owned.
Lease operating expenses	The expenses of lifting oil or gas from a producing formation to the surface, and the transportation and marketing thereof, constituting part of the current operating expenses of a working interest, and also including labor, superintendence, supplies, repairs, short-lived assets, maintenance, allocated overhead costs and other expenses incidental to production, but excluding lease acquisition or drilling or completion expenses.
LNG	Liquefied natural gas.
MBbls	Thousand barrels of oil or other liquid hydrocarbons.
MBoe	Thousand barrels of oil equivalent, determined using the ratio of six Mcf of gas to one Boe, and one Bbl of NGLs to one Boe.
Mcf	Thousand cubic feet of natural gas.
MMBoe	Million barrels of oil equivalent, determined using the ratio of six Mcf of gas to one Boe, and one Bbl of NGLs to one Boe.
MMBtu	Million British thermal units.
MMcf	Million cubic feet of gas.
Net acres or net wells	The sum of the fractional working interests owned in gross acres or wells, as the case may be.
NGLs	Natural gas liquids. The portions of gas from a reservoir that are liquefied at the surface in separators, field facilities or gas processing plants.
NYMEX	New York Mercantile Exchange.
Play	A set of known or postulated oil and/or gas accumulations sharing similar geologic, geographic and temporal properties, such as source rock, migration pathways, timing, trapping mechanism and hydrocarbon type.
Productive well	An exploratory, development or extension well that is not a dry well.

67

Prospect	A specific geographic area which, based on supporting geological, geophysical or other data and also preliminary economic analysis using reasonably anticipated prices and costs, is deemed to have potential for the discovery of commercial hydrocarbons.
Proved developed producing reserves	Proved developed oil and gas reserves that are expected to be recovered:
	(i)	Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and
	(ii)	Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.
Proved oil and gas reserves	Has the meaning given to such term in Rule 4-10(a)(22) of Regulation S-X, as follows:
	Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.
	(i)	The area of the reservoir considered as proved includes:
		(A)	The area identified by drilling and limited by fluid contacts, if any, and
		(B)	Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.
	(ii)	In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.
	(iii)	Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.
	(iv)	Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when:
		(A)	Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and

68

		(B)	The project has been approved for development by all necessary parties and entities, including governmental entities.
	(v)	Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.
PV-10	An estimate of the present value of the future net revenues from proved oil and gas reserves after deducting estimated production and ad valorem taxes, future capital costs and operating expenses, but before deducting any estimates of federal income taxes. The estimated future net revenues are discounted at an annual rate of 10% to determine their “present value.” The present value is shown to indicate the effect of time on the value of the revenue stream and should not be construed as being the fair market value of the properties. Estimates of PV-10 are made using oil and gas prices and operating costs at the date indicated and held constant for the life of the reserves.
“Recompletion” or to “recomplete” a well	The addition of production from another interval or formation in an existing wellbore.
Reserve life	This index is calculated by dividing year-end 2016 estimated proved reserves by 2016 production of 4.5 MMBoe to estimate the number of years of remaining production.
Reservoir	A porous and permeable underground formation containing a natural accumulation of producible oil and/or gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.
Spacing	The distance between wells producing from the same reservoir. Spacing is expressed in terms of acres (e.g., 40-acre spacing) and is established by regulatory agencies.
Standardized measure	The present value of estimated future net revenues to be generated from the production of proved reserves, determined in accordance with the rules and regulations of the SEC (using prices and costs in effect as of the period end date) without giving effect to non-property related expenses such as general and administrative expenses, debt service and future income tax expenses or to depletion, depreciation and amortization and discounted using an annual discount rate of 10%. Standardized measure does not give effect to derivative transactions.
Tight gas sands	A sandstone formation with low permeability that produces natural gas with low flow rates for long periods of time.
Unconventional resources or reserves	Natural gas or oil resources or reserves from (i) low-permeability sandstone and shale formations and (ii) coalbed methane.
Undeveloped acreage	Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil or gas regardless of whether such acreage contains proved reserves.
Undeveloped oil and gas reserves	Has the meaning given to such term in Rule 4-10(a)(31) of Regulation S-X, which defines proved undeveloped reserves as follows:

69

	Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.
	(i)	Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.
	(ii)	Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances justify a longer time.
	(iii)	Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir, an analogous reservoir or by other evidence using reliable technology establishing reasonable certainty.
Working interest	The operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and receive a share of production.
Workover	Operations on a producing well to restore or increase production.
WTI	West Texas Intermediate, a grade of crude oil used as a benchmark in oil pricing.
/d	“Per day” when used with volumetric units or dollars.

70

SIGNATURES

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

APPROACH RESOURCES INC.
By:	/s/ J. Ross Craft
	J. Ross Craft
	Chairman of the Board and Chief Executive Officer

Date: March 10, 2017

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities indicated and on March 10, 2017.

Signature	Title
/s/ J. Ross Craft	Chairman of the Board and Chief Executive Officer,
J. Ross Craft	(Principal Executive Officer)
/s/ Sergei Krylov	Executive Vice President and Chief Financial Officer
Sergei Krylov	(Principal Financial Officer)
/s/ Uma L. Datla	Chief Accounting Officer
Uma L. Datla	(Principal Accounting Officer)
/s/ Vean J. Gregg III	Lead Independent Director
Vean J. Gregg III
/s/ Alan D. Bell	Director
Alan D. Bell
/s/ James H. Brandi	Director
James H. Brandi
/s/ James C. Crain	Director
James C. Crain
/s/ Matthew R. Kahn	Director
Matthew R. Kahn
/s/ Morgan D. Neff	Director
Morgan D. Neff
/s/ Matthew D. Wilks	Director
Matthew D. Wilks

71

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS OF APPROACH RESOURCES INC.

	Page
Management’s Report on Internal Control Over Financial Reporting	F-2
Report of Independent Registered Public Accounting Firm — Internal Control Over Financial Reporting	F-3
Report of Independent Registered Public Accounting Firm — Financial Statements	F-4
Consolidated Balance Sheets as of December 31, 2016 and 2015	F-5
Consolidated Statements of Operations for the years ended December 31, 2016, 2015 and 2014	F-6
Consolidated Statements of Changes in Stockholders’ Equity for the years ended December  31, 2016, 2015 and 2014	F-7
Consolidated Statements of Cash Flows for the years ended December 31, 2016, 2015 and 2014	F-8
Notes to Consolidated Financial Statements	F-9

F-1

MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

Management is responsible for establishing and maintaining adequate internal control over financial reporting (as defined in Rule 13a-15(f) under the Securities Exchange Act of 1934). Our internal control over financial reporting is designed to provide reasonable assurance to management and our board of directors regarding the preparation and fair presentation of published financial statements. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation. Management assessed the effectiveness of our internal control over financial reporting as of December 31, 2016. In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control —Integrated Framework in 2013. Based on our assessment, we believe that, as of December 31, 2016, our internal control over financial reporting is effective based on those criteria.

Hein and Associates LLP, the independent registered public accounting firm that audited our financial statements included in this annual report, has issued an attestation report on our internal control over financial reporting as of December 31, 2016. This report appears on the following page.

By:	/s/ J. Ross Craft	By:	/s/ Sergei Krylov
	J. Ross Craft		Sergei Krylov
	Chairman of the Board and Chief Executive Officer		Executive Vice President and Chief Financial Officer

Fort Worth, Texas

March 10, 2017

F-2

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders

Approach Resources Inc.

We have audited Approach Resources, Inc. and subsidiaries’ (collectively, the “Company”) internal control over financial reporting as of December 31, 2016, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission in 2013. The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the company’s internal control over financial reporting based on our audit.

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

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

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

In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2016, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission in 2013.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Approach Resources, Inc. and subsidiaries as of December 31, 2016 and 2015, and the related consolidated statements of operations, changes in stockholders’ equity, and cash flows for each of the three years in the period ended December 31, 2016 and our report dated March 10, 2017, expressed an unqualified opinion.

/s/    Hein & Associates LLP

Dallas, Texas

March 10, 2017

F-3

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders

Approach Resources Inc.

We have audited the accompanying consolidated balance sheets of Approach Resources Inc. and subsidiaries (collectively, the “Company”) as of December 31, 2016 and 2015, and the related consolidated statements of operations, changes in stockholders’ equity, and cash flows for each of the three years in the period ended December 31, 2016. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Approach Resources Inc. and subsidiaries as of December 31, 2016 and 2015, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2016, in conformity with U.S. generally accepted accounting principles.

We have also audited, in accordance with standards of the Public Company Accounting Oversight Board (United States), the Company’s internal control over financial reporting as of December 31, 2016, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission in 2013, and our report dated March 10, 2017, expressed an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.

/s/    Hein & Associates LLP

Dallas, Texas

March 10, 2017

F-4

Approach Resources Inc. and Subsidiaries

Consolidated Balance Sheets

(In thousands, except shares and per-share amounts)

	December 31,
	2016			2015
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	21		$	600
Accounts receivable:
Joint interest owners		92			142
Oil, NGLs and gas sales		9,547			11,747
Unrealized gain on commodity derivatives		—			6,737
Prepaid expenses and other current assets		2,834			1,212
Total current assets		12,494			20,438
PROPERTIES AND EQUIPMENT:
Oil and gas properties, at cost, using the successful efforts method of    accounting		1,869,774			1,853,781
Furniture, fixtures and equipment		5,644			5,628
Total oil and gas properties and equipment		1,875,418			1,859,409
Less accumulated depletion, depreciation and amortization		(783,357	)		(704,863	)
Net oil and gas properties and equipment		1,092,061			1,154,546
Total assets	$	1,104,555		$	1,174,984
LIABILITIES AND STOCKHOLDERS’ EQUITY
CURRENT LIABILITIES:
Accounts payable	$	9,482		$	10,799
Oil, NGLs and gas sales payable		4,190			4,245
Unrealized loss on commodity derivatives		4,880			—
Accrued liabilities		7,817			13,464
Total current liabilities		26,369			28,508
NON-CURRENT LIABILITIES:
Senior secured credit facility, net		271,696			270,748
Senior notes, net		226,653			225,839
Deferred income taxes		5,615			31,779
Asset retirement obligations		10,607			10,143
Other non-current liabilities		663			—
Total liabilities		541,603			567,017
COMMITMENTS AND CONTINGENCIES (Note 8)
STOCKHOLDERS’ EQUITY :
Preferred stock, $0.01 par value, 10,000,000 shares authorized none    outstanding		—			—
Common stock, $0.01 par value, 90,000,000 shares authorized,    41,764,770 and 40,788,705 issued and outstanding, respectively		418			408
Additional paid-in capital		586,095			580,623
Accumulated (deficit) earnings		(23,561	)		26,936
Total stockholders’ equity		562,952			607,967
Total liabilities and stockholders’ equity	$	1,104,555		$	1,174,984

See accompanying notes to these consolidated financial statements.

F-5

Approach Resources Inc. and Subsidiaries

Consolidated Statements of Operations

(In thousands, except shares and per-share amounts)

	Years Ended December 31,
	2016			2015			2014
REVENUES:
Oil, NGLs and gas sales	$	90,302		$	131,336		$	258,529
EXPENSES:
Lease operating		19,250			28,972			32,701
Production and ad valorem taxes		8,217			11,085			15,934
Exploration		3,923			4,439			3,831
General and administrative(1)		24,734			28,341			32,104
Termination costs		—			1,436			—
Impairment of oil and gas properties		—			220,197			—
Depletion, depreciation and amortization		79,044			109,319			106,802
Total expenses		135,168			403,789			191,372
OPERATING (LOSS) INCOME		(44,866	)		(272,453	)		67,157
OTHER:
Interest expense, net		(27,259	)		(25,066	)		(21,651	)
Gain on debt extinguishment		—			10,563			—
Write-off of debt issuance costs		(563	)		—			—
Equity in losses of investee		—			—			(181	)
Realized gain on commodity derivatives		6,132			52,489			2,359
Unrealized (loss) gain on commodity derivatives		(11,616	)		(33,214	)		42,113
Other income		1,511			172			67
(LOSS) INCOME BEFORE INCOME TAX (BENEFIT)    PROVISION		(76,661	)		(267,509	)		89,864
INCOME TAX (BENEFIT) PROVISION:
Current		—			(265	)		(25	)
Deferred		(24,418	)		(93,140	)		33,717
NET (LOSS) INCOME	$	(52,243	)	$	(174,104	)	$	56,172
(LOSS) EARNINGS PER SHARE:
Basic	$	(1.26	)	$	(4.30	)	$	1.43
Diluted	$	(1.26	)	$	(4.30	)	$	1.42
WEIGHTED AVERAGE SHARES OUTSTANDING:
Basic		41,488,206			40,464,283			39,407,733
Diluted		41,488,206			40,464,283			39,419,865
(1)Includes non-cash share-based compensation expense as follows:
		6,279			7,954			8,247

See accompanying notes to these consolidated financial statements.

F-6

Approach Resources Inc. and Subsidiaries

Consolidated Statements of Changes in Stockholders’ Equity

for the Years Ended December 31, 2014, 2015 and 2016

(In thousands, except shares and per-share amounts)

	Common Stock						Additional Paid-in Capital			Accumulated (Deficit) Earnings			Total
	Shares			Amount
BALANCES, January 1, 2014		39,047,699		$	390		$	565,237		$	144,868		$	710,495
Issuance of common shares to directors for    compensation		40,898			1			748			—			749
Restricted stock issuance, net of cancellations		782,708			8			(8	)		—			—
Share-based compensation expense		—			—			7,498			—			7,498
Surrender of restricted shares for payment of    income taxes		(57,106	)		—			(587	)		—			(587	)
Net income		—			—			—			56,172			56,172
BALANCES, December 31, 2014		39,814,199		$	399		$	572,888		$	201,040		$	774,327
Issuance of common shares to directors for    compensation		134,783			1			734			—			735
Restricted stock issuance, net of cancellations		897,285			8			(8	)		—			—
Share-based compensation expense		—			—			7,219			—			7,219
Surrender of restricted shares for payment of    income taxes		(57,562	)		—			(210	)		—			(210	)
Net loss		—			—			—			(174,104	)		(174,104	)
BALANCES, December 31, 2015		40,788,705		$	408		$	580,623		$	26,936		$	607,967
Cumulative effect of change in accounting principal		—			—			—			1,746			1,746
Issuance of common shares to directors for    compensation		196,287			2			212			—			214
Restricted stock issuance, net of cancellations		1,013,982			10			(10	)		—			—
Share-based compensation expense		—			—			6,065			—			6,065
Surrender of restricted shares for payment of    income taxes		(234,204	)		(2	)		(795	)		—			(797	)
Net loss		—			—			—			(52,243	)		(52,243	)
BALANCES, December 31, 2016		41,764,770		$	418		$	586,095		$	(23,561	)	$	562,952

See accompanying notes to these consolidated financial statements.

F-7

Approach Resources Inc. and Subsidiaries

Consolidated Statements of Cash Flows

(In thousands, except shares and per-share amounts)

	For the Years Ended December 31,
	2016			2015			2014
OPERATING ACTIVITIES:
Net (loss) income	$	(52,243	)	$	(174,104	)	$	56,172
Adjustments to reconcile net (loss) income to net cash provided by operating    activities:
Depletion, depreciation and amortization		79,044			109,319			106,802
Impairment of oil and gas properties		—			220,197			—
Amortization of debt issuance costs		1,396			1,561			1,546
Gain on debt extinguishment		—			(10,563	)		—
Write-off of debt issuance costs		563			—			—
Unrealized loss (gain) on commodity derivatives		11,616			33,214			(42,113	)
Exploration expense		3,753			1,836			3,831
Share-based compensation expense		6,279			7,954			8,247
Deferred income tax (benefit) expense		(24,418	)		(93,140	)		33,717
Equity in losses of investee		—			—			181
Other non-cash items		(92	)		(172	)		(179	)
Changes in operating assets and liabilities:
Accounts receivable		2,250			7,878			3,262
Prepaid expenses and other current assets		534			(325	)		(179	)
Accounts payable		358			964			(2,262	)
Oil, NGLs and gas sales payable		(55	)		(4,291	)		2,435
Accrued liabilities		(2,904	)		2,388			144
Cash provided by operating activities		26,081			102,716			171,604
INVESTING ACTIVITIES:
Additions to oil and gas properties		(19,788	)		(151,178	)		(390,506	)
Proceeds from sale of equity method investment, net of contributions		—			—			(181	)
Change in restricted cash		—			—			7,350
Additions to furniture, fixtures and equipment, net		(16	)		(67	)		(3,024	)
Change in working capital related to investing activities		(4,086	)		(66,102	)		9,189
Cash used in investing activities		(23,890	)		(217,347	)		(377,172	)
FINANCING ACTIVITIES:
Borrowings under credit facility		50,100			272,000			353,921
Repayment of amounts outstanding under credit facility		(50,100	)		(149,000	)		(203,921	)
Extinguishment of senior notes		—			(8,722	)		—
Tax withholdings related to restricted stock		(797	)		(210	)		(587	)
Debt issuance costs		(197	)		—			(2,174	)
Change in working capital related to financing activities		(1,776	)		731			—
Cash (used in) provided by financing activities		(2,770	)		114,799			147,239
CHANGE IN CASH AND CASH EQUIVALENTS		(579	)		168			(58,329	)
CASH AND CASH EQUIVALENTS , beginning of year		600			432			58,761
CASH AND CASH EQUIVALENTS , end of year	$	21		$	600		$	432
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:
Cash paid for income taxes	$	—		$	—		$	404
Cash paid for interest	$	25,972		$	23,634		$	20,232
SUPPLEMENTAL DISCLOSURE OF NON-CASH TRANSACTION:
Acquisition of oil and gas properties	$	—		$	—		$	510
Asset retirement obligations capitalized	$	36		$	151		$	898

See accompanying notes to these consolidated financial statements.

F-8

Approach Resources Inc. and Subsidiaries

Notes to Consolidated Financial Statements

1. Summary of Significant Accounting Policies

Organization and Nature of Operations

Approach Resources Inc. (“Approach,” the “Company,” “we,” “us” or “our”) is an independent energy company focused on the exploration, development, production and acquisition of unconventional oil and gas properties. We focus on finding and developing oil and natural gas reserves in oil shale and tight gas sands. Our properties are primarily located in the Permian Basin in West Texas. We also own interests in the East Texas Basin.

Consolidation, Basis of Presentation and Significant Estimates

The accompanying consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America and include the accounts of the Company and its wholly owned subsidiaries. Intercompany accounts and transactions are eliminated. In preparing the accompanying financial statements, management has made certain estimates and assumptions that affect reported amounts in the financial statements and disclosures of contingencies. Actual results may differ from those estimates. Significant assumptions are required in the valuation of proved oil and natural gas reserves, which affect our estimate of depletion expense as well as our impairment analyses. Significant assumptions also are required in our estimation of accrued liabilities, commodity derivatives, income tax provision, share-based compensation and asset retirement obligations. It is at least reasonably possible these estimates could be revised in the near term, and these revisions could be material. Certain prior-year amounts have been reclassified to conform to current-year presentation. These classifications have no impact on the net loss reported.

Cash and Cash Equivalents

We consider all highly liquid debt instruments purchased with an original maturity of three months or less to be cash equivalents. At times, the amount of cash and cash equivalents on deposit in financial institutions exceeds federally insured limits. We monitor the soundness of the financial institutions and believe the Company’s risk is negligible.

Oil and Gas Properties

Capitalized Costs.     Our oil and gas properties comprised the following (in thousands):

	December 31,
	2016			2015
Mineral interests in properties:
Unproved leasehold costs	$	33,596		$	37,853
Proved leasehold costs		44,643			44,122
Wells and related equipment and facilities		1,774,314			1,753,649
Support equipment		8,002			9,545
Uncompleted wells, equipment and facilities		9,219			8,612
Total costs		1,869,774			1,853,781
Less accumulated depreciation, depletion and    amortization		(780,412	)		(702,139	)
Net capitalized costs	$	1,089,362		$	1,151,642

F-9

Approach Resources Inc. and Subsidiaries

Notes to Consolidated Financial Statements — (Continued)

We follow the successful efforts method of accounting for our oil and gas producing activities. Costs to acquire mineral interests in oil and gas properties and to drill and equip development wells and related asset retirement costs are capitalized. Costs to drill exploratory wells are capitalized pending determination of whether the wells have proved reserves. If we determine that the wells do not have proved reserves, the costs are charged to exploration expense. There were no exploratory wells capitalized, pending determination of whether the wells have proved reserves, at December 31, 2016 or 2015. Geological and geophysical costs, including seismic studies are charged to exploration expense as incurred. We capitalize interest on expenditures for significant exploration and development projects that last more than six months while activities are in progress to bring the assets to their intended use and while these expenditures are excluded from our depletable base. Through December 31, 2016, we have capitalized no interest costs because our individual wells and infrastructure projects are generally developed in less than six months. Costs incurred to maintain wells and related equipment are charged to expense as incurred.

On the sale or retirement of a complete unit of a proved property, the cost and related accumulated depreciation, depletion and amortization are eliminated from the property accounts, and the resulting gain or loss is recognized. On the retirement or sale of a partial unit of proved property, the cost is charged to accumulated depreciation, depletion and amortization with no gain or loss recognized in income.

Capitalized amounts attributable to proved oil and gas properties are depleted by the unit-of-production method over proved reserves using the unit conversion ratio of six Mcf of gas to one barrel of oil equivalent (“Boe”), and one barrel of NGLs to one Boe. The ratios of six Mcf of natural gas to one Boe and one barrel of NGLs to one Boe do not assume price equivalency and, given price differentials, the price for a Boe for natural gas may differ significantly from the price for a barrel of oil. Depreciation, depletion and amortization expense for oil and gas producing property and related equipment was $78.7 million, $108.8 million and $106.2 million for the years ended December 31, 2016, 2015 and 2014, respectively.

Capitalized costs related to proved oil and gas properties, including wells and related equipment and facilities, are periodically evaluated for impairment based on an analysis of undiscounted future net cash flows in accordance with ASC 360, Accounting for the Impairment or Disposal of Long-Lived Assets, as events or changes in circumstances indicate that the carrying values of those assets may not be recoverable. If undiscounted cash flows are insufficient to recover the net capitalized costs related to proved properties, then we recognize an impairment charge equal to the difference between the net capitalized costs related to proved properties and their estimated fair values based on the present value of the related future net cash flows. Estimating future net cash flows involves the use of judgments, including estimation of the proved and unproved oil and natural gas reserve quantities, timing of development and production, expected future commodity prices, capital expenditures and production costs. We recorded no impairment of our proved properties for the years ended December 31, 2016 and 2014. During the year ended December 31, 2015, we recognized an impairment loss of $214.7 million related primarily to our vertical Canyon wells. See Note 7 for proved property impairment disclosures.

Unproved oil and gas properties that are individually significant are periodically assessed for impairment of value, and a loss is recognized at the time of impairment by providing an impairment allowance. We recorded no impairment of our unproved properties for the years ended December 31, 2016 and 2014. Certain leases that we consider non-core to our development of Project Pangea were impaired during the year ended December 31, 2015, as we did not plan to develop them. As a result, we recorded a non-cash impairment loss of unproved property of $5.5 million for the year ended December 31, 2015.

The total impairment loss of $220.2 million for the year ended December 31, 2015, is recorded in impairment of oil and gas properties on our consolidated statements of operations, and in accumulated depletion, depreciation and amortization on our consolidated balance sheets.

On the sale of an entire interest in an unproved property for cash or cash equivalents, gain or loss on the sale is recognized, taking into consideration the amount of any recorded impairment if the property had been assessed individually. If a partial interest in an unproved property is sold, the amount received is treated as a reduction of the cost of the interest retained.

F-10

Approach Resources Inc. and Subsidiaries

Notes to Consolidated Financial Statements — (Continued)

Other Property

Furniture, fixtures and equipment are carried at cost. Depreciation of furniture, fixtures and equipment is provided using the straight-line method over estimated useful lives ranging from three to 15 years. Gain or loss on retirement or sale or other disposition of assets is included in income in the period of disposition. Depreciation expense for other property and equipment was $343,000, $563,000 and $588,000 for the years ended December 31, 2016, 2015 and 2014, respectively.

Financial Instruments

The carrying amounts of financial instruments including cash and cash equivalents, accounts receivable, accounts payable and accrued liabilities approximate fair value, as of December 31, 2016 and 2015. See Note 7 for fair value disclosures.

Income Taxes

We are subject to U.S. federal income taxes along with state income taxes in Texas. When tax returns are filed, it is highly certain that some positions taken would be sustained upon examination by the taxing authorities, while others are subject to uncertainty about the merits of the position taken or the amount of the position that would be ultimately sustained. The benefit of a tax position is recognized in the financial statements in the period during which, based on all available evidence, management believes it is more likely than not that the position will be sustained upon examination, including the resolution of appeals or litigation processes, if any. Tax positions taken are not offset or aggregated with other positions. Tax positions that meet the more-likely-than-not recognition threshold are measured as the largest amount of tax benefit that is more than 50% likely of being realized upon settlement with the applicable taxing authority. The portion of the benefits associated with tax positions taken that exceeds the amount measured as described above is reflected as a liability for unrecognized tax benefits in the accompanying balance sheet along with any associated interest and penalties that would be payable to the taxing authorities upon examination. Interest and penalties associated with unrecognized tax benefits are classified as additional income taxes on the consolidated statements of operations.

Based on our analysis, we did not have any uncertain tax positions as of December 31, 2016 or 2015. The Company’s income tax returns are subject to examination by the relevant taxing authorities as follows: U.S. Federal income tax returns for tax years 2013 and forward and Texas income and margin tax returns for tax years 2013 and forward. There are currently no income tax examinations underway for these jurisdictions.

Deferred tax assets and liabilities are recognized for the estimated future tax consequences attributable to the differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are measured using the tax rate in effect for the year in which those temporary differences are expected to be recovered or settled. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in income in the year of the enacted tax rate change.

We monitor our deferred tax assets by jurisdiction to assess their potential realization, and a valuation allowance is recognized on deferred tax assets when we believe that certain of these assets are more likely than not to be realized. In performing this review, we make estimates and assumptions regarding projected future taxable income, the expected timing of reversals of existing temporary differences and the implementation of tax planning strategies. To the extent that a valuation allowance is established or changed during any period, we would recognize expense or benefit within our consolidated tax expense. We do not currently have a valuation allowance on our federal net operating loss carryforwards (“NOLs”).

Derivative Activity

We record our open derivative instruments at fair value on our consolidated balance sheets as either unrealized gains or losses on commodity derivatives. We record changes in such fair value in earnings on our consolidated statements of operations under the caption entitled “unrealized (loss) gain on commodity derivatives.”

F-11

Approach Resources Inc. and Subsidiaries

Notes to Consolidated Financial Statements — (Continued)

Although we have not designated our derivative instruments as cash-flow hedges, we use those instruments to reduce our exposure to fluctuations in commodity prices related to our natural gas and oil production. Unrealized gains and losses, at fair value, are included on our consolidated balance sheets as current or non-current assets or liabilities based on the anticipated timing of cash settlements under the related contracts. Changes in the fair value of our commodity derivative contracts are recorded in earnings as they occur and included in income (expense) on our consolidated statements of operations. Realized gains and losses are also included in income (expense) on our consolidated statements of operations.

Accrued Liabilities

The following is a summary of our accrued liabilities at December 31, 2016 and 2015 (in thousands):

	2016		2015
Capital expenditures accrual	$	1,067	$	3,476
Operating expenses and other		6,750		9,988
Total	$	7,817	$	13,464

Asset Retirement Obligations

Our asset retirement obligations relate to future plugging and abandonment expenses on oil and gas properties. Based on the expected timing of payments, the full asset retirement obligation is classified as non-current. There were no significant changes to the asset retirement obligations for the years ended December 31, 2016, 2015 and 2014.

Share-Based Compensation

We measure and record compensation expense for share-based payment awards to employees and outside directors based on estimated grant date fair values. We recognize compensation costs for awards granted over the requisite service period based on the grant date fair value in general and administrative expenses on our consolidated statements of operations.

In 2016, we awarded cash-settled performance awards, subject to certain performance conditions, to our executive officers. The cash-settled performance awards represent a non-equity unit with a conversion value equal to the fair market value of a share of the Company’s common stock at the vesting date. These awards are classified as liability awards due to the cash settlement feature. Compensation costs associated with the cash-settled performance awards are re-measured at each interim reporting period and an adjustment is recorded in general and administrative expenses on our consolidated statements of operations.

F-12

Approach Resources Inc. and Subsidiaries

Notes to Consolidated Financial Statements — (Continued)

Earnings Per Common Share

We report basic earnings per common share, which excludes the effect of potentially dilutive securities, and diluted earnings per common share, which includes the effect of all potentially dilutive securities unless their impact is antidilutive. The following are reconciliations of the numerators and denominators of our basic and diluted earnings per share, (dollars in thousands, except per-share amounts):

	For the Years Ended December 31,
	2016			2015			2014
Income (numerator):
Net (loss) income — basic	$	(52,243	)	$	(174,104	)	$	56,172
Weighted average shares (denominator):
Weighted average shares — basic		41,488,206			40,464,283			39,407,733
Dilution effect of share-based compensation,    treasury method (1)		—			—			12,132
Weighted average shares — diluted		41,488,206			40,464,283			39,419,865
Net (loss) income per share:
Basic	$	(1.26	)	$	(4.30	)	$	1.43
Diluted	$	(1.26	)	$	(4.30	)	$	1.42

(1) Approximately 39,000 options to purchase our common stock were excluded from this calculation because they were antidilutive for the years ended December 31, 2016 and 2015.

Oil and Gas Operations

Revenue and Accounts Receivable.     We recognize revenue for our production when the quantities are delivered to or collected by the respective purchaser. Prices for such production are defined in sales contracts and are readily determinable based on certain publicly available indices.

Accounts receivable, joint interest owners, consist of uncollateralized joint interest owner obligations due within 30 days of the invoice date. Accounts receivable, oil, NGLs and gas sales, consist of uncollateralized accrued revenues due under normal trade terms, generally requiring payment within 30 to 60 days of production. No interest is charged on past-due balances. Payments made on all accounts receivable are applied to the earliest unpaid items. We review accounts receivable periodically and reduce the carrying amount by a valuation allowance that reflects our best estimate of the amount that may not be collectible. No such allowance was considered necessary at December 31, 2016 or 2015. Accounts receivable related to oil, NGLs and gas sales includes $0.2 million and $4.8 million from realized gains on commodity derivatives at December 31, 2016 and 2015, respectively.

Oil, NGLs and Gas Sales Payable.     Oil, NGLs and gas sales payable represents amounts collected from purchasers for oil, NGLs and gas sales which are either revenues due to other revenue interest owners or severance taxes due to the respective state or local tax authorities. Generally, we are required to remit amounts due under these liabilities within 60 days of the end of the month in which the related production occurred.

Production Costs.     Production costs, including compressor rental and repair, pumpers’ and supervisors’ salaries, saltwater disposal, insurance, repairs and maintenance, expensed workovers and other operating expenses are expensed as incurred and included in lease operating expenses on our consolidated statements of operations.

Exploration expenses.     Exploration expenses include lease expirations, delay rentals, geological and geophysical costs and dry hole costs. For the year ended December 31, 2015 exploration expense includes $2.2 million related to the early termination of daywork drilling contracts.

Dependence on Major Customers.     For the year ended December 31, 2016, sales to JP Energy Development, LP (“JP Energy”) and DCP Midstream, LP (“DCP”) accounted for approximately 54% and 46%, respectively, of our total sales. As of December 31, 2016, we had dedicated all of our oil production from northern Project Pangea and

F-13

Approach Resources Inc. and Subsidiaries

Notes to Consolidated Financial Statements — (Continued)

Pangea West through September 2022 to JP Energy. In addition, as of December 31, 2016, we had contracted to sell all of our NGLs and natural gas production from Project Pangea to DCP through August 2023. For the year ended December 31, 2015, sales to DCP and JP Energy accounted for approximately 36% and 63%, respectively of our total sales. For the year ended December 31, 2014, sales to DCP and JP Energy accounted for approximately 30% and 69%, respectively of our total sales. We believe that there are potential alternative purchasers and that it may be necessary to establish relationships with new purchasers. However, there can be no assurance that we can establish such relationships and that those relationships will result in increased purchasers. Although we are exposed to a concentration of credit risk, we believe that all of our purchasers are credit worthy.

Segment Reporting

The Company presently operates in one business segment, the exploration and production of oil, NGLs and natural gas.

Recent Accounting Pronouncements

In May 2014, the Financial Accounting Standards Board (“FASB”) issued an accounting standards update for “Revenue from Contracts with Customers,” which supersedes the revenue recognition requirements in “Topic 605, Revenue Recognition.” This accounting standard update provides new guidance concerning recognition and measurement of revenue and requires additional disclosures about the nature, timing and uncertainty of revenue and cash flows arising from contracts with customers. This new guidance permits adoption through the use of either a full retrospective approach or a modified retrospective approach for annual reporting periods beginning on or after December 15, 2016, with early adoption not permitted. In August 2015, FASB delayed the effective date one year, making the new standard effective for interim periods and annual periods beginning after December 15, 2017. We have not determined which transition method we will use and are continuing to evaluate our existing revenue recognition policies to determine whether any of our contracts will be affected by the new requirements. This evaluation will continue throughout 2017, and we are currently planning to adopt this new standard in the first quarter of 2018.

In September 2015, FASB issued an accounting standards update for “Business Combinations,” which requires that an acquirer recognize adjustments to provisional amounts that are identified during the measurement period in the reporting period in which the adjustment amounts are determined. We adopted this new guidance prospectively in the first quarter of 2016. This new guidance did not have a significant impact on the consolidated financial statements.

In February 2016, FASB issued an accounting standards update for “Leases,” which amends existing guidance to require lessees to recognize assets and liabilities on the balance sheet for the rights and obligations created by long-term leases and to disclose additional quantitative and qualitative information about leasing arrangements. This new guidance is effective for interim and annual periods beginning after December 15, 2018, and we will adopt it using a modified retrospective approach. The Company is evaluating the impact of this new guidance on its consolidated financial statements.

In March 2016, FASB issued an accounting standards update for “Compensation — Stock Compensation,” which amends existing guidance related to the accounting for forfeitures, employer tax withholding on share-based compensation and financial statement presentation of excess tax benefits or deficiencies.  This standard is effective for interim and annual reporting periods beginning after December 15, 2016, with early adoption permitted. We applied this standard using a modified retrospective approach. We have elected to (i) recognize forfeitures of share-based compensation as they occur, (ii) permit tax withholdings in excess of the minimum statutory requirements and (iii) recognize previously un-recognized excess tax benefits related to share-based compensation in the current year.  As a result, we have recognized an increase in accumulated earnings in the current year of $1.7 million related to the change in accounting principal as of January 1, 2016.  Adoption of this guidance did not impact our consolidated statements of operations or cash flows.

In January 2017, the FASB issued an accounting standards update for “Clarifying the Definition of a Business,” which provides guidance to assist entities with evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. This standard requires entities to use a screen test to determine when an integrated set of assets and activities is not a business or if the integrated set of assets and activities needs to

F-14

Approach Resources Inc. and Subsidiaries

Notes to Consolidated Financial Statements — (Continued)

be further evaluated against the framework. This standard is effective for interim and annual reporting periods beginning after December 15, 2016. The Company is evaluating the impact of this new guidance on its consolidated financial statements.

2. Exchange Transactions

On November 2, 2016, we entered into an exchange agreement with the largest holder of our 7% Senior Notes due 2021 (the “Senior Notes”) to exchange $130,552,000 principal amount of our Senior Notes for 39,165,600 newly issued shares of common stock, par value $0.01 per share (the “Initial Exchange”). 

On January 26, 2017, our stockholders approved the Initial Exchange and an increase in our authorized common stock from 90 million shares to 180 million shares.  We closed the Initial Exchange on January 27, 2017, and paid $1.1 million of accrued interest on the Senior Notes held by the exchanging noteholder. In connection with the Initial Exchange, a second supplemental indenture became effective, which removed certain covenants and events of default from the indenture governing our Senior Notes, and eliminated certain restrictive covenants discussed in Note 3. As of December 31, 2016, we have incurred approximately $2.1 million in costs related to the Initial Exchange, which are recorded in prepaid expenses and other current assets.

On January 30, 2017, we offered to exchange our remaining$99,768,000principal amount of outstanding Senior Notes for shares of our common stock at a ratio of 276 shares of common stock per $1,000 principal amount of our Senior Notes (the “Follow-On Exchange”). There are no minimum subscription requirements for the Follow-On Exchange, and we cannot predict participation levels.

Depending on the participation levels in the Follow-On Exchange, we may further reduce our long-term debt. Additionally, use of our federal NOLs may be limited as a result of the Follow-On Exchange.

3. Long-Term Debt

The following table provides a summary of our long-term debt at December 31, 2016, and December 31, 2015 (in thousands).

	December 31, 2016			December 31, 2015
Senior secured credit facility:
Outstanding borrowings	$	273,000		$	273,000
Debt issuance costs		(1,304	)		(2,252	)
Senior secured credit facility, net		271,696			270,748
Senior notes:
Principal		230,320			230,320
Debt issuance costs		(3,667	)		(4,481	)
Senior notes, net		226,653			225,839
Total long-term debt	$	498,349		$	496,587

Senior Secured Credit Facility

At December 31, 2016, the borrowing base and aggregate lender commitments under our amended and restated senior secured credit facility (the “Credit Facility”) were $325 million, with maximum commitments from the lenders of $1 billion. The Credit Facility has a maturity date of May 7, 2019. The borrowing base is redetermined semi-annually based on our oil, NGLs and gas reserves. We, or the lenders, can each request one additional borrowing base redetermination each calendar year.

Borrowings under the Credit Facility bear interest based on the agent bank’s prime rate plus an applicable margin ranging from 1.50% to 2.50%, or the sum of the LIBOR rate plus an applicable margin ranging from 2.50% to 3.50%. In addition, we pay an annual commitment fee of 0.50% of unused borrowings available under the Credit Facility. Margins vary based on the borrowings outstanding compared to the borrowing base of the lenders.

F-15

Approach Resources Inc. and Subsidiaries

Notes to Consolidated Financial Statements — (Continued)

We had $273 million of outstanding borrowings under the Credit Facility at December 31, 2016 and 2015. The weighted average interest rate applicable to borrowings under the Credit Facility in 2016 was 3.3%. We also had outstanding unused letters of credit under our Credit Facility totaling $0.6 million at December 31, 2016, compared to $0.3 million at December 31, 2015, which reduce amounts available for borrowing under the Credit Facility.

Obligations under the Credit Facility are secured by mortgages on substantially all of the oil and gas properties of the Company and its subsidiaries. The Company is required to grant liens in favor of the lenders covering the oil and gas properties of the Company and its subsidiaries representing at least 90% of the total value of all oil and gas properties of the Company and its subsidiaries.  

On May 3, 2016, we entered into a third amendment to the Credit Facility. The third amendment, among other things, (a) decreased the borrowing base to $325 million from $450 million, (b) revised the Company’s permitted ratio of EBITDAX (as defined in the Credit Facility) to cash Interest Expense (as defined in the Credit Facility) to 1.25 to 1.0 (or 1.0 to 1.0 following the issuance of second lien indebtedness), through December 31, 2017, 1.5 to 1.0 through December 31, 2018, and 2.0 to 1.0 thereafter; (c) increased the applicable margin rates on borrowings by 100 basis points, (d) permits the Company to issue up to $150 million of second lien indebtedness, subject to various conditions and limitations, (e) permits the Company to repurchase outstanding debt with proceeds of certain asset sales, equity issuances or second lien indebtedness, and (f) requires cash and cash equivalents in excess of $35 million held by the Company to be applied to reduce outstanding borrowings under the Credit Facility. In connection with the third amendment to the Credit Facility, $0.6 million of debt issuance costs were written off as a result of the reduction in the borrowing base, and we incurred $0.2 million of debt issuance costs.

Covenants

The Credit Facility contains two principal financial covenants:

• a consolidated interest coverage ratio covenant (as defined in the Credit Facility) that requires us to maintain a ratio of consolidated EBITDAX to cash Interest Expense (as defined in the Credit Facility) as of the last day of any fiscal quarter of not less than 1.25 to 1.0 (or 1.0 to 1.0 following the issuance of second lien indebtedness) through December 31, 2017, a ratio of not less than 1.5 to 1.0 through December 31, 2018, and a ratio of not less than 2.0 to 1.0 thereafter, and

• a consolidated modified current ratio covenant (as defined in the Credit Facility) that requires us to maintain a ratio of not less than 1.0 to 1.0 as of the last day of any fiscal quarter.

The Credit Facility also contains covenants restricting cash distributions and other restricted payments, transactions with affiliates, incurrence of other debt, consolidations and mergers, the level of operating leases, asset sales, investment in other entities and liens on properties.

In addition, the obligations of the Company may be accelerated upon the occurrence of an Event of Default (as defined in the Credit Facility). Events of Default include customary events for a financing agreement of this type, including, without limitation, payment defaults, the inaccuracy of representations and warranties, defaults in the performance of affirmative or negative covenants, defaults on other indebtedness of the Company or its subsidiaries, bankruptcy or related defaults, defaults related to judgments and the occurrence of a Change of Control (as defined in the Credit Facility), which includes instances where a third party becomes the beneficial owner of more than 50% of the Company’s outstanding equity interests entitled to vote.

Senior Notes

In June 2013, we completed our public offering of $250 million principal amount of 7% Senior Notes due 2021 (the “Senior Notes”). Annual interest on the Senior Notes is payable semi-annually on June 15 and December 15. On December 15, 2016, we made a semi-annual interest payment of $8.1 million. We received net proceeds from the issuance of the Senior Notes of approximately $243 million, after deducting fees and expenses. We used a portion of the net proceeds from the offering to repay all outstanding borrowings under the Credit

F-16

Approach Resources Inc. and Subsidiaries

Notes to Consolidated Financial Statements — (Continued)

Facility, fund our capital expenditures for the development of our Wolfcamp shale oil resource play and for general working capital needs.

During the year ended December 31, 2015, we repurchased Senior Notes in the open market with an aggregate face value of $19.7 million for a purchase price of $8.8 million, including accrued interest. This resulted in a gain on extinguishment of debt of $10.6 million.

On November 2, 2016, we entered into the Initial Exchange. In January 2017, we closed the Initial Exchange and launched the Follow-On Exchange. The Initial Exchange reduced our Senior Notes outstanding by $130.6 million and will result in future interest savings of approximately $40 million. The Follow-On Exchange, if closed, is expected to further reduce our debt and improve our operating cash flow through the reduction of interest expense.

We issued the Senior Notes under a senior indenture dated June 11, 2013, among the Company, our subsidiary guarantors and Wilmington Trust, National Association, as successor trustee. The senior indenture, as supplemented by a supplemental indenture dated June 11, 2013, is referred to as the “Indenture.”

On December 20, 2016, we entered into the second supplemental indenture (the “Second Supplemental Indenture”), which became effective in connection with the closing of the Initial Exchange. The Second Supplemental Indenture (i) eliminated certain definitions and references to definitions contained in the Indenture; (ii) eliminated and revised, as applicable, certain events of default contained in the Indenture; (iii) eliminated certain conditions to consolidation, merger, conveyance, transfer or lease contained in the Indenture; (iv) eliminated certain covenants contained in the Indenture, including substantially all of the restrictive covenants set forth therein; and (v) supplemented and amended the Senior Notes and the securities guarantees, as and to the same extent as the Indenture has been amended and supplemented in accordance with the preceding clauses (i), (ii), (iii) and (iv).

We may redeem some or all of the Senior Notes at specified redemption prices, plus accrued and unpaid interest to the redemption date. The Senior Notes are fully and unconditionally guaranteed on a senior unsecured basis by each of our subsidiaries, subject to certain customary release provisions. A subsidiary guarantor may be released from its obligations under the guarantee:

• in connection with any sale or other disposition of all or substantially all of the assets of that guarantor (including by way of merger or consolidation) to a person that is not (either before or after giving effect to such transaction) the Company or a subsidiary guarantor, if the sale or other disposition otherwise complies with the Indenture;

• in connection with any sale or other disposition of the capital stock of that guarantor to a person that is not (either before or after giving effect to such transaction) the Company or a subsidiary guarantor, if that guarantor no longer qualifies as a subsidiary of the Company as a result of such disposition and the sale or other disposition otherwise complies with the Indenture;

• if the Company designates any restricted subsidiary that is a guarantor to be an unrestricted subsidiary in accordance with the Indenture;

• upon defeasance or covenant defeasance of the notes or satisfaction and discharge of the indenture, in each case, in accordance with the Indenture;

• upon the liquidation or dissolution of that guarantor, provided that no default or event of default occurs under the indenture as a result thereof or shall have occurred and is continuing; or

• in the case of any restricted subsidiary that, after the issue date of the notes is required under the indenture to guarantee the notes because it becomes a guarantor of indebtedness issued or an obligor under the revolving credit facility with respect to the Company and/or its subsidiaries, upon the release or discharge in full from its (i) guarantee of such indebtedness or (ii) obligation under such revolving credit facility, in each case, which resulted in such restricted subsidiary’s obligation to guarantee the notes.

As a result of the Second Supplemental Indenture, the Indenture contains limited events of default.

F-17

Approach Resources Inc. and Subsidiaries

Notes to Consolidated Financial Statements — (Continued)

Subsidiary Guarantors

The Senior Notes are guaranteed on a senior unsecured basis by each of our consolidated subsidiaries. Approach Resources Inc. is a holding company with no independent assets or operations. The subsidiary guarantees are full and unconditional and joint and several, and any subsidiaries of the Company other than the subsidiary guarantors are minor. There are no significant restrictions on the Company’s ability, or the ability of any subsidiary guarantor, to obtain funds from its subsidiaries through dividends, loans, advances or otherwise.

At December 31, 2016, we were in compliance with all of our covenants, and there were no existing defaults or events of default, under our debt instruments.

4. Termination Costs

In September 2015, we reduced our workforce to decrease costs and better align our workforce with the needs of the business and oil and gas prices. In connection with the reduction, we incurred $1.4 million in expenses, which was recorded in termination costs on our consolidated statements of operations. As of December 31, 2016, $0.3 million in termination costs is recorded in current liabilities on our consolidated balance sheets. We also recorded a benefit of $0.3 million in share-based compensation expense related to the forfeiture of unvested shares of restricted stock in connection with our workforce reduction, which was recorded in general and administrative expense on our consolidated statements of operations.

5. Share-Based Compensation

In June 2007, our board of directors and stockholders approved the 2007 Stock Incentive Plan (the “2007 Plan”). Under the 2007 Plan, we may grant restricted stock, stock options, stock appreciation rights, restricted stock units, performance awards, unrestricted stock awards and other incentive awards. Under a Fifth Amendment to the 2007 Plan effective June 2, 2016, the maximum number of shares of common stock available for the grant of awards under the 2007 Plan after June 2, 2016, is 6,125,000. Awards of any stock options are to be priced at not less than the fair market value at the date of the grant. We use (i) the closing stock price on the date of grant for the fair value of restricted stock awards, including performance-based awards, (ii) the Monte Carlo simulation method for the fair value of market-based awards, (iii) the fair market value of our common stock on the valuation date for cash-settled performance awards and (iv) the Black-Scholes option price model to measure the fair value of stock options. The vesting period of any stock award is to be determined by the board or an authorized committee at the time of the grant.

Share-based compensation expense amounted to $6.3 million, $8 million and $8.2 million for the years ended December 31, 2016, 2015 and 2014, respectively. Such amounts represent the estimated fair value of stock awards for which the requisite service period elapsed during those periods. Included in share-based compensation expense in 2014 was a benefit of $1.1 million for forfeited stock awards related to the retirement of one of our executive officers. Share-based compensation expense for the years ended December 31, 2016, 2015 and 2014, included $214,000, $735,000 and $749,000, respectively, related to grants to non-employee directors.

Stock Options

There were no stock option grants during the years ended December 31, 2016, 2015 and 2014. As of December 31, 2016, 38,525 options were fully vested and outstanding with a weighted average exercise price of $12.00 and a weighted average remaining contractual term of 0.85 years. There were no options exercised during the years ended December 31, 2016, 2015 and 2014.

Nonvested Shares

Share grants totaling 1,318,229 shares, 1,278,329 shares and 992,919 shares with an approximate aggregate fair market value of $2.5 million, $6.2 million and $14.4 million, based on the closing price of our common stock on the date of grant, were granted to employees and non-employee directors during the years ended December 31, 2016, 2015 and 2014, respectively. Included in the share grants for 2016, 2015 and 2014, are 550,272 shares,

F-18

Approach Resources Inc. and Subsidiaries

Notes to Consolidated Financial Statements — (Continued)

724,249 shares and 245,157 shares, respectively, awarded to our executive officers. The aggregate fair market value of these shares on the grant date was $0.3 million, $4.5 million and $4.5 million, respectively, to be expensed over a service period of approximately three years, subject to certain performance restrictions. The share grants for executive officers noted above does not include the cash-settled performance awards, which are discussed in more detail below.

A summary of the status of nonvested shares for the years ended December 31, 2016, 2015 and 2014, is presented below:

	Shares			Weighted Average Grant-Date Fair Value
Nonvested at January 1, 2014		699,231		$	23.70
Granted		992,919			14.48
Vested		(400,429	)		20.18
Canceled		(169,311	)		25.57
Nonvested at December 31, 2014		1,122,410		$	16.52
Granted		1,278,329			4.87
Vested		(419,222	)		15.26
Canceled		(246,261	)		14.30
Nonvested at December 31, 2015		1,735,256		$	8.60
Granted		1,318,229			1.90
Vested		(992,461	)		7.03
Canceled		(107,960	)		17.33
Nonvested at December 31, 2016		1,953,064		$	4.39

As of December 31, 2016, unrecognized compensation expense related to the nonvested shares amounted to $4 million, which will be recognized over a remaining service period of two years.

Cash-settled performance awards

In 2016, in addition to the share grants discussed above, we awarded 1,100,543 cash-settled performance awards, subject to certain performance conditions, to our executive officers. The aggregate fair market value of the cash-settled shares on the grant date was approximately $1 million, to be expensed over a remaining service period of approximately three years, subject to performance conditions.

The cash-settled performance awards represent a non-equity unit with a conversion value equal to the fair market value of a share of the Company’s common stock at the vesting date. These awards are classified as liability awards due to the cash settlement feature. Compensation costs associated with the cash-settled performance awards are re-measured, based on the fair market value of our common stock, at each interim reporting period and an adjustment is recorded in general and administrative expenses on our consolidated statements of operations. For the year ended December 31, 2016, we recognized $1.3 million in expense related to the cash-settled performance awards, recorded as a current liability of $0.6 million and a non-current liability of $0.7 million on our consolidated balance sheet.

Subsequent Restricted Share Award

Subsequent to December 31, 2016, 1,443,256 restricted shares were awarded to our executive officers, of which 962,171 shares are subject to certain performance conditions and 481,085 shares are subject to three-year total shareholder return (“TSR”) conditions, assuming maximum TSR. The aggregate fair market value of the shares on the grant date was approximately $2.9 million, to be expensed over a remaining service period of approximately three years.

F-19

Approach Resources Inc. and Subsidiaries

Notes to Consolidated Financial Statements — (Continued)

Employee Benefit Plan

The Company has a defined contribution employee benefit plan covering substantially all of its employees. We make a matching contribution equal to 100% of each pre-tax dollar contributed by the participant on the first 3% of eligible compensation and 50% on the next 2% of eligible compensation. The Company made contributions to the plan of approximately $338,000, $404,000 and $310,000 during the years ended December 31, 2016, 2015 and 2014, respectively.

6. Income Taxes

Our provision for income taxes comprised the following (in thousands):

	Years Ended December 31,
	2016			2015			2014
Current:
Federal	$	—		$	(265	)	$	(25	)
State		—			—			—
Total current provision for income taxes	$	—		$	(265	)	$	(25	)
Deferred:
Federal	$	(24,957	)	$	(91,716	)	$	32,754
State		539			(1,424	)		963
Total deferred provision for income taxes	$	(24,418	)	$	(93,140	)	$	33,717

Total income tax expense differed from the amounts computed by applying the U.S. Federal statutory tax rates to pre-tax income (in thousands):

	Years Ended December 31,
	2016			2015			2014
Statutory tax at 35%	$	(26,831	)	$	(93,628	)	$	31,452
State taxes, net of federal impact		578			(1,463	)		989
Share-based compensation tax shortfall		1,826			1,939			1,670
Permanent differences		11			26			37
Other differences		(2	)		(1,035	)		(456	)
Valuation allowance		—			756			—
Total	$	(24,418	)	$	(93,405	)	$	33,692

In 2016, 2015 and 2014, the Company recorded a tax shortfall related to share-based compensation of $1.8 million, $1.9 million and $1.7 million, respectively. This shortfall is for grants in which the realized tax deduction was less than the expense booked for these grants due to a decline in share price from the time of grant.

In 2016, we early adopted accounting standards update for “Compensation — Stock Compensation.” As a result, we have recognized an increase in accumulated earnings and our NOLs in the current year of $1.7 million related to the change in accounting principal as of January 1, 2016.  

Deferred tax assets and liabilities are the result of temporary differences between the financial statement carrying values and tax basis of assets and liabilities. Our net deferred tax assets and liabilities are recorded as a long-term liability of $5.6 million and $31.8 million at December 31, 2016 and 2015, respectively.

F-20

Approach Resources Inc. and Subsidiaries

Notes to Consolidated Financial Statements — (Continued)

Significant components of net deferred tax assets and liabilities are (in thousands):

	Years Ended December 31,
	2016			2015
Deferred tax assets:
Net operating loss carryforwards	$	155,018		$	88,230
Unrealized loss on commodity derivatives		1,732			—
Other		892			1,672
Total deferred tax assets		157,642			89,902
Deferred tax liabilities:
Difference in depreciation, depletion and    capitalization methods — oil and gas properties		(162,501	)		(118,534	)
Unrealized gain on commodity derivatives		—			(2,391	)
Total deferred tax liabilities		(162,501	)		(120,925	)
Valuation allowance		(756	)		(756	)
Net deferred tax liability	$	(5,615	)	$	(31,779	)

Our NOLs have the following expiration dates (in thousands):

Expiration Dates	Amounts
2030	$	5,790
2031		19,686
2032		54,714
2033		78
2034		56,505
2035		116,482
2036		189,649
Total	$	442,904

A change in ownership of our common stock by more than 50% within a three-year period would result in a substantial portion of our NOLs being eliminated or becoming restricted, and we would need to reduce our deferred tax assets to reflect the restricted use of these NOLs when such an ownership change occurs. An ownership change would establish an annual limitation on the amount of our pre-change NOLs that we could use to offset our taxable income in any future taxable year to an amount generally equal to the value of our common stock immediately before the ownership change, multiplied by the federal long-term tax exempt rate for the month of the ownership change. We do not believe that the Initial Exchange resulted in a change of ownership of 50% or more of common stock over the applicable period; however, the Follow-On Exchange may result in such an ownership change. If such an ownership change occurs, use of our NOLs as of December 31, 2016 could be limited.

7. Derivative Instruments and Fair Value Measurements

At December 31, 2016, we had the following commodity derivatives positions outstanding:

Commodity and Period	Contract Type	Volume Transacted	Contract Price
Natural Gas
January 2017 — March 2017	Swap	100,000 MMBtu/month	$2.463/MMBtu
January 2017 — March 2017	Swap	300,000 MMBtu/month	$2.45/MMBtu
January 2017 — March 2017	Swap	200,000 MMBtu/month	$3.287/MMBtu
January 2017 — December 2017	Collar	100,000 MMBtu/month	$3.00/MMBtu - $3.65/MMBtu
April 2017 — December 2017	Collar	200,000 MMBtu/month	$2.30/MMBtu - $2.60/MMBtu
April 2017 — December 2017	Collar	200,000 MMBtu/month	$3.00/MMBtu - $3.44/MMBtu
April 2017 — December 2017	Collar	200,000 MMBtu/month	$3.00/MMBtu - $3.50/MMBtu

F-21

Approach Resources Inc. and Subsidiaries

Notes to Consolidated Financial Statements — (Continued)

After December 31, 2016, we entered into the following commodity derivative positions:

Commodity and Period	Contract Type	Volume Transacted	Contract Price
Natural Gas
January 2018 — December 2018	Swap	200,000 MMBtu/month	$3.085/MMBtu
January 2018 — December 2018	Swap	250,000 MMBtu/month	$3.084/MMBtu
NGLs (C2 - Ethane)
February 2017 — December 2017	Swap	1,050 Bbls/day	$11.34/Bbl
NGLs (C3 - Propane)
February 2017 — December 2017	Swap	750 Bbls/day	$27.916/Bbl
NGLs (IC4 - Isobutane)
February 2017 — December 2017	Swap	75 Bbls/day	$36.7325/Bbl
NGLs (NC4 - Butane)
February 2017 — December 2017	Swap	250 Bbls/day	$35.9205/Bbl

The following summarizes the fair value of our open commodity derivatives as of December 31, 2016 and 2015 (in thousands):

	Balance Sheet Location	Fair Value
		December 31, 2016			December 31, 2015
Derivatives not designated as hedging    instruments
Commodity derivatives	Unrealized (loss) gain on    commodity derivatives	$	(4,880	)	$	6,737

The following summarizes the change in the fair value of our commodity derivatives (in thousands):

	Income Statement Location
		Year Ended December 31,
		2016			2015			2014
Derivatives not designated as hedging    instruments
Commodity derivatives	Unrealized (loss) gain on    commodity derivatives	$	(11,616	)	$	(33,214	)	$	42,113
	Realized gain on    commodity derivatives		6,132			52,489			2,359
		$	(5,484	)	$	19,275		$	44,472

Unrealized gains and losses, at fair value, are included on our consolidated balance sheets as current or non-current assets or liabilities based on the anticipated timing of cash settlements under the related contracts. Changes in the fair value of our commodity derivative contracts are recorded in earnings as they occur and included in income (expense) on our consolidated statements of operations. We estimate the fair value of swap contracts based on the present value of the difference in exchange-quoted forward price curves and contractual settlement prices multiplied by notional quantities. We internally valued the option contracts using industry-standard option pricing models and observable market inputs. We use our internal valuations to determine the fair values of the contracts that are reflected on our consolidated balance sheets. Realized gains and losses are also included in income (expense) on our consolidated statements of operations.

We are exposed to credit losses in the event of nonperformance by the counterparties on our commodity derivatives positions and have considered the exposure in our internal valuations. However, we do not anticipate nonperformance by the counterparties over the term of the commodity derivatives positions.

F-22

Approach Resources Inc. and Subsidiaries

Notes to Consolidated Financial Statements — (Continued)

To estimate the fair value of our commodity derivatives positions, we use market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated or generally unobservable. We primarily apply the market approach for recurring fair value measurements and attempt to use the best available information. We determine the fair value based upon the hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and lowest priority to unobservable inputs (Level 3 measurement). The three levels of fair value hierarchy are as follows:

• Level 1 — Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. At December 31, 2016, we had no Level 1 measurements.

• Level 2 — Pricing inputs are other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reporting date. Level 2 includes those financial instruments that are valued using models or other valuation methodologies. These models are primarily industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Our derivatives, which consist primarily of commodity swaps and collars, are valued using commodity market data which is derived by combining raw inputs and quantitative models and processes to generate forward curves. Where observable inputs are available, directly or indirectly, for substantially the full term of the asset or liability, the instrument is categorized in Level 2. At December 31, 2016, all of our commodity derivatives were valued using Level 2 measurements.

• Level 3 — Pricing inputs include significant inputs that are generally less observable from objective sources. These inputs may be used with internally developed methodologies that result in management’s best estimate of fair value. The fair value of oil and gas properties used in estimating our recognized impairment loss in 2015 represents a nonrecurring Level 3 measurement. At December 31, 2016, we had no Level 3 measurements.

Nonrecurring Fair Value Measurements

We recorded no impairment of our proved properties for the year ended December 31, 2016. Due to the impact of the decline in forward commodity prices during the year ended December 31, 2015, there were indications that the carrying values of certain of our oil and gas properties may be impaired and undiscounted cash flows attributable to these assets indicated their carrying amounts were not expected to be recovered. For the year ended December 31, 2015, we recognized an impairment loss of $214.7 million related primarily to our vertical Canyon wells, due to the impact of the decline in forward commodity prices. At September 30, 2015, we had $22 million in value recorded for these properties, which was the estimated fair value. We estimated the fair value of the proved oil and gas properties and equipment using a discounted cash flow model, which is a Level 3 fair value measurement. Significant inputs used to determine the fair value include estimates of (i) future sales prices for oil and gas based on NYMEX strip prices, (ii) pricing adjustments for differentials, (iii) production costs, (iv) capital expenditures, (v) future oil and gas reserves to be recovered and the timing thereof, and (vi) discount rates.

Financial Instruments Not Recorded at Fair Value

The following table sets forth the fair values of financial instruments that are not recorded at fair value on our financial statements (in thousands).

	December 31, 2016
	Carrying Amount		Fair Value
Senior Notes, net	$	226,653	$	206,286

F-23

Approach Resources Inc. and Subsidiaries

Notes to Consolidated Financial Statements — (Continued)

The fair value of the Senior Notes is based on quoted market prices, but the Senior Notes are not actively traded in the public market. Accordingly, the fair value of the Senior Notes would be classified as Level 2 in the fair value hierarchy.

8. Commitments and Contingencies

At December 31, 2016, we had outstanding employment agreements with all four of our executive officers that contained automatic renewal provisions providing that such agreements may be automatically renewed for successive terms of one year unless the employment is terminated at the end of the term by written notice given to the employee not less than 60 days prior to the end of such term. Our maximum commitment under the employment agreements, which would apply if the employees covered by these agreements were each terminated without cause, resigned for good reason, or received a notice of non-renewal was approximately $5.7 million at December 31, 2016. This estimate assumes the maximum potential bonus for 2017 is earned by each executive officer during 2017. In 2017, we amended the employment agreements with two of our executive officers, which among other things, increased the maximum commitment under the employment agreements, which would apply if the employees covered by these agreements were each terminated without cause, by approximately $0.6 million.

In 2016, we recorded a contractual settlement of $1.4 million, which is recorded in other income on our consolidated statements of operations.

We lease our office space in Fort Worth, Texas, under a non-cancelable agreement that expires on March 31, 2020. In January 2017, we amended our lease to reduce the aggregate leased space by approximately 5,500 square feet and extended the term to September 30, 2021. This amendment reduced our contractual obligations by approximately $0.4 million during the next three years, while increasing our total contractual obligations by $0.9 million over the extended term of the lease.

We also have non-cancelable operating lease commitments related to office equipment that expire by 2021. The following is a schedule by years of future minimum rental payments required under our operating lease arrangements as of December 31, 2016 (in thousands):

2017	$	989
2018		979
2019		980
2020		248
2021		2
Total	$	3,198

Rent expense under our lease arrangements amounted to $1,025,000, $1,002,000 and $717,000 for the years ended December 31, 2016, 2015 and 2014, respectively.

Litigation

We are involved in various legal and regulatory proceedings arising in the normal course of business. While we cannot predict the outcome of these proceedings with certainty, we do not believe that an adverse result in any pending legal or regulatory proceeding, individually or in the aggregate, would be material to our consolidated financial condition or cash flows.

In 2016, we received $1.1 million from a service provider in a legal settlement, which reduced our current liabilities on our consolidated balance sheets and is recorded as a reduction in additions to oil and gas properties on our consolidated statements of cash flows.

F-24

Approach Resources Inc. and Subsidiaries

Notes to Consolidated Financial Statements — (Continued)

Environmental Issues

We are engaged in oil and gas exploration and production and may become subject to certain liabilities or damages as they relate to environmental clean up of well sites or other environmental restoration or ground water contamination, in connection with drilling or operating oil and gas wells. In connection with our acquisition of existing or previously drilled well bores, we may not be aware of what environmental safeguards were taken at the time such wells were drilled or during such time the wells were operated. Should it be determined that a liability exists with respect to any environmental clean up, restoration or contamination, we would be responsible for curing such a violation or paying damages. No claim has been made, nor are we aware of any liability that exists, as it relates to any environmental clean up, restoration, contamination or the violation of any rules or regulations relating thereto.

9. Oil and Gas Producing Activities

Set forth below is certain information regarding the costs incurred for oil and gas property acquisition, development and exploration activities (in thousands):

	For the Years Ended December 31,
	2016		2015		2014
Property acquisition costs:
Unproved properties	$	17	$	653	$	4,578
Proved properties		—		—		—
Exploration costs		3,923		4,439		3,831
Development costs(1)		15,884		146,237		382,995
Total costs incurred	$	19,824	$	151,329	$	391,404

(1) For the years ended December 31, 2016, 2015 and 2014, development costs included $36,000, $151,000 and $898,000, respectively, in non-cash asset retirement obligations.

Set forth below is certain information regarding the results of operations for oil and gas producing activities (in thousands):

	For the Years Ended December 31,
	2016			2015			2014
Revenues	$	90,302		$	131,336		$	258,529
Production costs		(27,467	)		(40,057	)		(48,635	)
Exploration expense		(3,923	)		(4,439	)		(3,831	)
Depletion		(79,044	)		(109,319	)		(106,802	)
Impairment of oil and gas properties		—			(220,197	)		—
Income tax benefit (expense)		7,144			86,120			(35,387	)
Results of operations	$	(12,988	)	$	(156,556	)	$	63,874

10. Disclosures About Oil and Gas Producing Activities (unaudited)

Proved Reserves

All of our estimated oil and natural gas reserves are attributable to properties within the United States, primarily in the Permian Basin in West Texas. The estimates of proved reserves and related valuations for the years ended December 31, 2016, 2015 and 2014, were prepared by DeGolyer and MacNaughton, independent petroleum engineers. Each year’s estimate of proved reserves and related valuations were also prepared in accordance with then-current rules and guidelines established by the Securities and Exchange Commission and the Financial Accounting Standards Board.

F-25

Approach Resources Inc. and Subsidiaries

Notes to Consolidated Financial Statements — (Continued)

The following table summarizes the prices used in the reserve estimates for 2016,2015 and 2014. Commodity prices used for the reserve estimates, adjusted for basis differentials, grade and quality, are as follows:

	2016		2015		2014
Oil (per Bbl)	$	42.69	$	50.16	$	94.56
Natural gas liquids (per Bbl)	$	14.12	$	15.13	$	31.50
Gas (per Mcf)	$	2.47	$	2.64	$	4.55

Oil, NGLs and natural gas reserve estimates are subject to numerous uncertainties inherent in the estimation of quantities of proved reserves and in the projection of future rates of production and the timing of development expenditures. The accuracy of such estimates is a function of the quality of available data and of engineering and geological interpretation and judgment. Results of subsequent drilling, testing and production may cause either upward or downward revision of previous estimates. Further, the volumes considered to be commercially recoverable fluctuate with changes in prices and operating costs. The Company emphasizes that reserve estimates are inherently imprecise and that estimates of new discoveries are more imprecise than those of currently producing oil and natural gas properties. Accordingly, these estimates are expected to change as additional information becomes available in the future.

The following table provides a summary of the changes of the total proved reserves for the years ended December 31, 2016, 2015 and 2014, as well as proved developed and proved undeveloped reserves at the beginning and end of each respective year.

Total Proved Reserves	Oil (MBbls)			NGLs (MBbls)			Natural Gas (MMcf)			Total (MBoe)
Balance — January 1, 2014		46,067			32,593			216,002			114,661
Extensions and discoveries		19,347			10,658			79,454			43,247
Production(1)		(2,024	)		(1,461	)		(10,773	)		(5,281	)
Revisions to previous estimates		(8,052	)		(883	)		15,337			(6,379	)
Balance — December 31, 2014		55,338			40,907			300,020			146,248
Extensions and discoveries		11,054			10,630			79,268			34,895
Production(1)		(1,882	)		(1,694	)		(13,262	)		(5,787	)
Revisions to previous estimates		(10,014	)		(357	)		9,962			(8,710	)
Balance — December 31, 2015		54,496			49,486			375,988			166,646
Extensions and discoveries		6,529			4,564			33,347			16,651
Production(1)		(1,275	)		(1,529	)		(11,734	)		(4,759	)
Revisions to previous estimates		(9,719	)		(4,887	)		(45,324	)		(22,161	)
Balance — December 31, 2016		50,031			47,634			352,277			156,377

(1) Production included 1,390 MMcf, 1,530 MMcf and 1,330 MMcf related to field fuel in 2014, 2015 and 2016, respectively.

F-26

Approach Resources Inc. and Subsidiaries

Notes to Consolidated Financial Statements — (Continued)

Total Proved Reserves	Oil (MBbls)		NGLs (MBbls)		Natural Gas (MMcf)		Total (MBoe)
Proved Developed Reserves:
January 1, 2014		13,646		14,919		99,742		45,189
December 31, 2014		17,978		19,082		138,961		60,220
December 31, 2015		15,667		20,414		154,652		61,856
December 31, 2016		13,466		20,375		150,208		58,875
Proved Undeveloped Reserves:
January 1, 2014		32,421		17,674		116,260		69,472
December 31, 2014		37,360		21,825		161,059		86,028
December 31, 2015		38,829		29,072		221,335		104,790
December 31, 2016		36,565		27,259		202,069		97,502

The following is a discussion of the material changes in our proved reserve quantities for the years ended December 31, 2016, 2015 and 2014:

Year Ended December 31, 2016

Extensions and discoveries for 2016 were 16.7 MMBoe, primarily attributable to our development project in the Wolfcamp shale oil resource play in the Permian Basin. During 2016, we reclassified 22.4 MMBoe of proved undeveloped reserves to unproved reserves. The reserves reclassified are attributable to horizontal well locations in Project Pangea that are no longer expected to be developed within five years from their initial booking, as required by SEC rules. Revisions included an increase of 2.1 MMBoe resulting from cost reductions, updated well performance and technical parameters, offset by a decrease of 1.9 MMBoe due to lower commodity prices. We produced 4.8 MMBoe during 2016. This production included 1,330 MMcf of gas that was produced and used as field fuel (primarily for compressors and artificial lift) before the gas was delivered to a sales point.

Year Ended December 31, 2015

Extensions and discoveries for 2015 were 34.9 MMBoe, primarily attributable to our development project in the Wolfcamp shale oil resource play in the Permian Basin. During 2015, we reclassified 11.9 MMBoe of proved reserves to unproved reserves. The reserves reclassified are attributable to horizontal and vertical well locations in Project Pangea that are no longer expected to be developed within five years from their initial booking, as required by SEC rules. Revisions included an increase of 13 MMBoe resulting from cost reductions, updated well performance and technical parameters, offset by a decrease of 9.8 MMBoe due to lower commodity prices. We produced 5.8 MMBoe during 2015. This production included 1,530 MMcf of gas that was produced and used as field fuel (primarily for compressors and artificial lift) before the gas was delivered to a sales point.

Year Ended December 31, 2014

Extensions and discoveries for 2014 were 43.2 MMBoe, primarily attributable to our development project in the Wolfcamp shale oil resource play in the Permian Basin. During 2014, we reclassified 9.3 MMBoe of proved undeveloped reserves to unproved reserves. The reserves reclassified included 5.8 MMBoe attributable to vertical Canyon locations in Project Pangea that we do not plan to drill within five years from their initial booking, and 3.5 MMBoe attributable to horizontal Wolfcamp locations that are no longer included in our proved development plan. Revisions included an increase of 6.3 MMBoe attributable to updated well performance and an increase of 0.7 MMBoe due to pricing, offset by a decrease of 4.1 MMBoe resulting from updated technical parameters and costs. We produced 5.3 MMBoe during 2014. This production included 1,390 MMcf of gas that was produced and used as field fuel (primarily for compressors and artificial lift) before the gas was delivered to a sales point.

F-27

Approach Resources Inc. and Subsidiaries

Notes to Consolidated Financial Statements — (Continued)

Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Reserves

The standardized measure of discounted future net cash flows is computed by applying the 12-month unweighted average of the first-day-of-the-month pricing for oil and natural gas (with consideration of price changes only to the extent provided by contractual arrangements) to the estimated future production of proved oil and natural gas reserves less estimated future expenditures (based on year-end costs) to be incurred in developing and producing the proved reserves, discounted using a rate of 10 percent per year to reflect the estimated timing of the future cash flows. Future income taxes are calculated by comparing undiscounted future cash flows to the tax basis of oil and natural gas properties plus available carryforwards and credits and applying the current tax rates to the difference.

Discounted future cash flow estimates like those shown below are not intended to represent estimates of the fair value of oil and natural gas properties. Estimates of fair value would also consider probable and possible reserves, anticipated future oil and natural gas prices, interest rates, changes in development and production costs and risks associated with future production. Because of these and other considerations, any estimate of fair value is necessarily subjective and imprecise.

The following table provides the standardized measure of discounted future net cash flows at December 31, 2016, 2015 and 2014 (in thousands):

	Years Ended December 31,
	2016			2015			2014
Future cash flows	$	3,319,551		$	4,097,568		$	7,430,368
Future production costs		(1,054,211	)		(1,237,888	)		(1,704,333	)
Future development costs		(829,926	)		(934,814	)		(1,247,446	)
Future income tax expense		(132,834	)		(307,374	)		(1,267,025	)
Future net cash flows		1,302,580			1,617,492			3,211,564
10% annual discount for estimated timing of cash    flows		(1,004,825	)		(1,157,097	)		(2,155,749	)
Standardized measure of discounted future net    cash flows	$	297,755		$	460,395		$	1,055,815

Future cash flows as shown above were reported without consideration for the effects of commodity derivative transactions outstanding at each period end.

F-28

Approach Resources Inc. and Subsidiaries

Notes to Consolidated Financial Statements — (Continued)

Changes in Standardized Measure of Discounted Future Net Cash Flows

The changes in the standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves are as follows (in thousands):

	Years Ended December 31,
	2016			2015			2014
Balance, beginning of period	$	460,395		$	1,055,815		$	676,277
Net change in sales and transfer prices and in    production (lifting) costs related to future    production		(191,841	)		(1,405,864	)		(59,920	)
Changes in estimated future development costs		17,405			231,900			(388,772	)
Sales and transfers of oil and gas produced during    the period		(62,835	)		(91,278	)		(209,893	)
Net change due to extensions, discoveries and    improved recovery		13,988			156,783			534,231
Net change due to revisions in quantity estimates		(25,236	)		(59,305	)		(78,801	)
Previously estimated development costs incurred    during the period		15,884			146,237			382,995
Accretion of discount		46,040			105,582			113,188
Other		(9,500	)		6,915			(11,897	)
Net change in income taxes		33,455			313,610			98,407
Standardized Measure of discounted future net    cash flows	$	297,755		$	460,395		$	1,055,815

11. Supplementary Data

Selected Quarterly Financial Data (unaudited), (dollars in thousands, except per-share amounts):

	2016 Quarters Ended
	December 31			September 30			June 30			March 31
Net revenues	$	26,505		$	23,749		$	22,433		$	17,615
Net operating expenses		(33,564	)		(32,201	)		(34,534	)		(34,869	)
Interest expense, net		(7,086	)		(7,067	)		(6,808	)		(6,298	)
Write-off of debt issuance costs		—			—			(563	)		—
Realized gain on commodity derivatives		442			781			1,409			3,500
Unrealized (loss) gain on commodity derivatives		(3,343	)		760			(8,076	)		(957	)
Other income (expense)		—			(10	)		1,417			104
Loss before income tax benefit		(17,046	)		(13,988	)		(24,722	)		(20,905	)
Income tax benefit		(3,571	)		(4,915	)		(8,687	)		(7,245	)
Net loss	$	(13,475	)	$	(9,073	)	$	(16,035	)	$	(13,660	)
Basic net loss applicable to common stockholders    per common share	$	(0.32	)	$	(0.22	)	$	(0.39	)	$	(0.33	)
Diluted net loss applicable to common stockholders    per common share	$	(0.32	)	$	(0.22	)	$	(0.39	)	$	(0.33	)

F-29

Approach Resources Inc. and Subsidiaries

Notes to Consolidated Financial Statements — (Continued)

	2015 Quarters Ended
	December 31			September 30			June 30			March 31
Net revenues	$	25,492		$	33,941		$	38,605		$	33,298
Net operating expenses		(38,671	)		(272,462	)		(46,970	)		(45,686	)
Interest expense, net		(6,436	)		(6,465	)		(6,243	)		(5,922	)
Gain on debt extinguishment		9,080			1,483			—			—
Realized gain on commodity derivatives		14,552			12,755			9,281			15,901
Unrealized (loss) gain on commodity derivatives		(10,285	)		296			(13,904	)		(9,321	)
Other income (expense)		225			(91	)		12			26
Loss before income tax benefit		(6,043	)		(230,543	)		(19,219	)		(11,704	)
Income tax benefit		(284	)		(81,756	)		(7,369	)		(3,996	)
Net loss	$	(5,759	)	$	(148,787	)	$	(11,850	)	$	(7,708	)
Basic net loss applicable to common    stockholders per common share	$	(0.14	)	$	(3.67	)	$	(0.29	)	$	(0.19	)
Diluted net loss applicable to common    stockholders per common share	$	(0.14	)	$	(3.67	)	$	(0.29	)	$	(0.19	)

	2014 Quarters Ended
	December 31			September 30			June 30			March 31
Net revenues	$	55,070		$	68,124		$	73,408		$	61,927
Net operating expenses		(50,136	)		(45,525	)		(50,812	)		(44,899	)
Interest expense, net		(5,715	)		(5,442	)		(5,357	)		(5,137	)
Equity in earnings (losses) of investee		5			—			(186	)		—
Realized gain (loss) on commodity derivatives		7,782			(764	)		(3,320	)		(1,339	)
Unrealized gain (loss) on commodity derivatives		36,907			18,810			(7,678	)		(5,926	)
Other income (expense)		176			—			(109	)		—
Income before income tax		44,089			35,203			5,946			4,626
Income tax provision		17,102			12,756			2,153			1,681
Net income	$	26,987		$	22,447		$	3,793		$	2,945
Basic net income applicable to common    stockholders per common share	$	0.68		$	0.57		$	0.10		$	0.08
Diluted net income applicable to common    stockholders per common share	$	0.68		$	0.57		$	0.10		$	0.08

F-30

Approach Resources Inc.

Index to Exhibits

Exhibit Number	Description of Exhibit
*3.1	Certificate of Amendment of Restated Certificate of Incorporation of Approach Resources Inc.
3.2	Restated Certificate of Incorporation of Approach Resources Inc. (filed as Exhibit 3.1 to the Company’s Quarterly Report on Form 10-Q filed December 13, 2007, and incorporated herein by reference).
3.3	Second Amended and Restated Bylaws of Approach Resources Inc. (filed as Exhibit 3.2 to the Company’s Current Report on Form 8-K filed November 8, 2013, and incorporated herein by reference).
4.1	Specimen Common Stock Certificate (filed as Exhibit 4.1 to the Company’s Registration Statement on Form S-1/A filed October 18, 2007 (File No. 333-144512), and incorporated herein by reference).
4.2	Second Supplemental Indenture, dated as of December 20, 2016, by and among Approach Resources Inc., the guarantors named therein and Wilmington Trust, National Association, as successor trustee under the Indenture (filed as Exhibit 4.1 to the Company’s Current Report on Form 8-K filed December 22, 2016, and incorporated herein by reference).
4.3	First Supplemental Indenture, dated as of June 11, 2013, among Approach Resources Inc., as issuer, the subsidiary guarantors named therein, as guarantors, and Wells Fargo Bank, National Association, as trustee (filed as Exhibit 4.2 to the Company’s Current Report on Form 8-K filed June 11, 2013, and incorporated herein by reference).
4.4	Senior Indenture, dated as of June 11, 2013, among Approach Resources Inc., as issuer, the subsidiary guarantors named therein, as guarantors, and Wells Fargo Bank, National Association, as trustee (filed as Exhibit 4.1 to the Company’s Current Report on Form 8-K filed June 11, 2013, and incorporated herein by reference).
4.5	Agreement dated as of April 28, 2016 by and among Approach Resources, Inc., Wells Fargo Bank, National Association, and Wilmington Trust, National Association (filed as Exhibit 4.4 to the Company’s Quarterly Report on Form 10-Q filed August 4, 2016, and incorporated herein by reference).
4.6	Registration Rights Agreement, dated as of January 27, 2017, by and among Approach Resources Inc., Wilks Brothers, LLC and SDW Investments, LLC (filed as Exhibit 4.2 to the Company’s Current Report on Form 8-K filed January 30, 2017, and incorporated herein by reference).
4.7	Registration Rights Agreement, dated as of November 14, 2007, by and among Approach Resources Inc. and investors identified therein (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K/A filed December 3, 2007, and incorporated herein by reference).
10.1	Form of Amended and Restated Indemnity Agreement between Approach Resources Inc. and each of its directors and officers (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed May 7, 2012 (File No. 333-144512), and incorporated herein by reference).
10.2†	Amended and Restated Employment Agreement by and between Approach Resources Inc. and J. Ross Craft dated January 1, 2011 (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed January 6, 2011, and incorporated herein by reference).
*10.3†	Amendment to Employment Agreement by and between Approach Resources Inc. and J. Curtis Henderson dated January 26, 2017.

72

Approach Resources Inc.

Index to Exhibits — (Continued)

Exhibit Number	Description of Exhibit
10.4†	Employment Agreement by and between Approach Resources Inc. and J. Curtis Henderson dated January 1, 2011 (filed as Exhibit 10.3 to the Company’s Current Report on Form 8-K filed January 6, 2011, and incorporated herein by reference).
*10.5†	Amendment to Employment Agreement by and between Approach Resources Inc. and Qingming Yang dated January 26, 2017.
10.6†	Employment Agreement by and between Approach Resources Inc. and Qingming Yang dated January 24, 2011 (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed January 28, 2011, and incorporated herein by reference).
10.7†	Employment Agreement by and between Approach Resources Inc., and Sergei Krylov dated January 3, 2014 (filed as Exhibit 10.1 to the Company’s Quarterly Report on Form 10-Q filed May 9, 2014, and incorporated herein by reference).
10.8	Form of Business Opportunities Agreement among Approach Resources Inc. and the other signatories thereto (filed as Exhibit 10.11 to the Company’s Registration Statement on Form S-1/A filed October 18, 2007 (File No. 333-144512), and incorporated herein by reference).
10.9†	Fifth Amendment to the Approach Resources Inc. 2007 Stock Incentive Plan effective as of June 2, 2016 (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed June 2, 2016, and incorporated herein by reference).
10.10†	Fourth Amendment to the Approach Resources Inc. 2007 Stock Incentive Plan (filed as Exhibit 10.2 to the Company’s Quarterly Report on Form 10-Q filed May 5, 2016, and incorporated herein by reference).
10.11†	Third Amendment to the Approach Resources Inc. 2007 Stock Incentive Plan (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed June 2, 2015, and incorporated herein by reference).
10.12†	Second Amendment to the Approach Resources Inc. 2007 Stock Incentive Plan, effective as of May 31, 2012 (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed June 1, 2012, and incorporated herein by reference).
10.13†	First Amendment dated December 31, 2008, to Approach Resources Inc. 2007 Stock Incentive Plan, effective as of June 28, 2007 (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed December 31, 2008, and incorporated herein by reference).
10.14†	Approach Resources Inc. 2007 Stock Incentive Plan, effective as of June 28, 2007 (filed as Exhibit 10.6 to the Company’s Registration Statement on Form S-1 filed July 12, 2007, and incorporated herein by reference).
10.15†	Form of Restricted Stock Award Agreement under Approach Resources Inc. 2007 Stock Incentive Plan (filed as Exhibit 10.10 to the Company’s Quarterly Report on Form 10-Q filed November 6, 2008, and incorporated herein by reference).
10.16†	Form of Performance-Based, Time-Vesting Restricted Stock Award Agreement under Approach Resources Inc. 2007 Stock Incentive Plan (filed as Exhibit 10.14 to the Company’s Annual Report on Form 10-K filed March 11, 2011, and incorporated herein by reference).
*10.17†	Revised Form of TSR-Based Restricted Stock Award Agreement under Approach Resources Inc. 2007 Stock Incentive Plan.
10.18†	Form of TSR-Based Restricted Stock Award Agreement under Approach Resources Inc. 2007 Stock Incentive Plan (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed February 20, 2012, and incorporated herein by reference).

73

Approach Resources Inc.

Index to Exhibits — (Continued)

Exhibit Number	Description of Exhibit
10.19†	Form of Cash Settled Performance Share Unit Award Agreement under Approach Resources Inc. 2007 Stock Incentive Plan (filed as Exhibit 10.3 to the Company’s Quarterly Report on Form 10-Q filed May 5, 2016, and incorporated herein by reference).
10.20	Exchange Agreement, dated as of November 2, 2016, by and among Approach Resources Inc., Wilks Brothers, LLC and SDW Investments, LLC (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed November 3, 2016, and incorporated herein by reference).
10.21	Stockholder Agreement, dated as of January 27, 2017, by and among Approach Resources Inc., Wilks Brothers, LLC and SDW Investments, LLC (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed January 30, 2017, and incorporated herein by reference).
10.22	Amendment dated August 4, 2014 to Gas Purchase Contract dated as of January 1, 2011, between Approach Resources I, LP and Approach Oil & Gas Inc., as Seller, and DCP Midstream, LP, as Buyer (pursuant to a request for confidential treatment, portions of this exhibit have been redacted and have been provided separately to the Securities and Exchange Commission) (filed as Exhibit 10.2 to the Company’s Quarterly Report on Form 10-Q filed November 6, 2014, and incorporated herein by reference).
10.23	Gas Purchase Contract dated as of January 1, 2011, between Approach Resources I, LP and Approach Oil & Gas Inc., as Seller, and DCP Midstream, LP, as Buyer (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed January 14, 2011, and incorporated herein by reference).
10.24	Specimen Oil and Gas Lease for University Lands (filed as Exhibit 10.19 to the Company’s Annual Report on Form 10-K filed March 12, 2012, and incorporated herein by reference).
10.25	Third Amendment dated as of May 3, 2016, to Amended and Restated Credit Agreement dated as of May 7, 2014, by and amount the Company, JPMorgan Chase Bank, N.A., as Administrative Agent, and each of the Lenders party thereto (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed May 4, 2016, and incorporated herein by reference).
10.26	Second Amendment dated as of December 30, 2014, to Amended and Restated Credit Agreement, dated as of May 7, 2014, by and among the Company, JPMorgan Chase Bank, N.A., as Administrative Agent, and each of the Lenders party thereto (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed January 6, 2015, and incorporated herein by reference).
10.27	First Amendment dated as of November 4, 2014, to Amended and Restated Credit Agreement, dated as of May 7, 2014, by and among the Company, JPMorgan Chase Bank, N.A., as Administrative Agent, and each of the Lenders party thereto (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed November 5, 2014, and incorporated herein by reference).
10.28	Amended and Restated Credit Agreement, dated as of May 7, 2014, by and among the Company, JPMorgan Chase Bank, N.A., as Administrative Agent, and the lenders from time-to-time party thereto (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed May 8, 2014, and incorporated herein by reference).
10.29	Amended and Restated Guaranty and Pledge Agreement, dated as of May 7, 2014, by and among the Company, the subsidiary guarantors and JPMorgan Chase Bank, N.A., as Administrative Agent (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed May 8, 2014, and incorporated herein by reference).

74

Approach Resources Inc.

Index to Exhibits — (Continued)

Exhibit Number	Description of Exhibit
10.30	Amendment No. 1 to Crude Oil Purchase Agreement dated as of October 7, 2013, between Approach Operating, LLC, Approach Oil & Gas Inc. and Approach Resources I, LP, and Wildcat Permian Services LLC and JP Energy Development, LP (pursuant to a request for confidential treatment, portions of this exhibit have been redacted and have been provided separately to the Securities and Exchange Commission) (filed as Exhibit 10.37 to the Company’s Annual Report on Form 10-K filed February 25, 2014, and incorporated herein by reference).
10.31	Crude Oil Purchase Agreement dated as of September 12, 2012, between Approach Operating, LLC and Approach Oil & Gas Inc., as Seller, and Wildcat Permian Services LLC, as Buyer (pursuant to a request for confidential treatment, portions of this exhibit have been redacted and have been provided separately to the Securities and Exchange Commission) (filed as Exhibit 10.4 of the Company’s Quarterly Report on Form 10-Q for the three months ended September 30, 2012 and incorporated herein by reference).
*12.1	Statement of Computation Ratio of Earnings to Fixed Charges.
14.1	Code of Conduct (filed as Exhibit 14.1 to the Company’s Annual Report on Form 10-K filed March 28, 2008, and incorporated herein by reference).
*21.1	Subsidiaries.
*23.1	Consent of Hein & Associates LLP.
*23.2	Consent of DeGolyer and MacNaughton.
*31.1	Certification by the President and Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
*31.2	Certification by the Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
*32.1	Certification by the President and Chief Executive Officer Pursuant to 18 U.S.C. Section 1350, as adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
*32.2	Certification by the Chief Financial Officer Pursuant to U.S.C. Section 1350, as adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
*99.1	Report of DeGolyer and MacNaughton.
*101.INS	XBRL Instance Document.
*101.SCH	XBRL Taxonomy Extension Schema Document.
*101.CAL	XBRL Taxonomy Extension Calculation Linkbase Document.
*101.LAB	XBRL Taxonomy Extension Label Linkbase Document.
*101.PRE	XBRL Taxonomy Extension Presentation Linkbase Document.
*101.DEF	XBRL Taxonomy Extension Definition Linkbase Document.

* Filed herewith.

† Denotes management contract or compensatory plan or arrangement.

75

EX-3.1

Exhibit 3.1

CERTIFICATE OF AMENDMENT

OF

RESTATED

CERTIFICATE OF INCORPORATION

OF

APPROACH RESOURCES INC.

Approach Resources Inc., a corporation organized and existing under the laws of the State of Delaware (the “Corporation”), hereby certifies as follows:

1. The name of the Corporation is Approach Resources Inc.

2. The Board of Directors of the Corporation, acting in accordance with the provisions of Section 141 and 242 of the Delaware General Corporation Law, adopted resolutions to amend Section 4.1 of the Restated Certificate of Incorporation of the Corporation so that the first paragraph thereof is hereby amended and replaced as follows:

The total number of shares of all classes of stock that the Corporation shall have the authority to issue is 190,000,000, of which 180,000,000 of such shares shall be Common Stock, all of one class, having a par value of $0.01 per share (“Common Stock”), and 10,000,000 of such shares shall be Preferred Stock, having a par value of $0.01 per share (“Preferred Stock”).

3. This Certificate of Amendment was submitted to the stockholders of the Corporation and was duly adopted by the required vote of stockholders of the Corporation in accordance with Section 242 of the Delaware General Corporation Law.

4. This Certificate of Amendment shall become effective immediately upon being duly filed with the Secretary of State of the State of Delaware.

IN WITNESS WHEREOF, the undersigned has duly executed this Certificate of Amendment as of January 27, 2017.

APPROACH RESOURCES INC.

By: /s/ J. Ross Craft

Name:	J. Ross Craft
Title:	Chairman, President and Chief Executive Officer

Certificate of Amendment

EX-10.3

Exhibit 10.3

AMENDMENT NO. 1

TO

EMPLOYMENT AGREEMENT

This Amendment No. 1 to Employment Agreement (this “Amendment”) is effective as of January 26, 2017, by and among Approach Resources Inc., a Delaware corporation (the “Company”), and J. Curtis Henderson, an individual residing in the state of Texas (“Employee”).

RECITALS

WHEREAS, Employee and the Company are parties to that Employment Agreement between Employee and Company, effective January 1, 2011 (the “Employment Agreement”);

WHEREAS, the parties wish to amend the Employment Agreement, as set forth herein;

NOW THEREFORE, in consideration of the premises and mutual covenants contained in this Amendment, together with other good and valuable consideration, the receipt and sufficiency of which is hereby acknowledged, and intending to be legally bound hereby, the parties agree to the following terms:

SECTION 1. Amendments to the Employment Agreement.  The Employment Agreement shall be amended as follows:.  

1.1Section 7(d)(i).  Section 7(d)(i) is hereby amended and restated in its entirety to read as follows:

“(i) on the earliest date between 20 and 60 days following Employee’s Separation from Service when the Release described in subparagraph 10(a) has become fully enforceable and irrevocable, a lump sum in cash equal to 200% of the greater of (A) the then-current Base Salary, and (B) the Base Salary at any time within two years immediately before the Separation from Service; and”

1.2Section 7(e)(i).  Section 7(e)(i) is hereby amended and restated in its entirety to read as follows:

“(i) on the earliest date between 20 and 60 days following Employee’s Separation from Service when the Release described in subparagraph 10(a) has become fully enforceable and irrevocable, a lump sum in cash equal to 200% of the greater of (A) the then-current Base Salary, and (B) the Base Salary at any time within two years immediately before the Separation from Service; and”

1.3Section 8(b)(i)-(ii).  Sections 8(b)(i)-(ii) are hereby amended and restated in its entirety to read as follows:

“(i) on the earliest date between 20 and 60 days following Employee’s Separation from Service when the Release described in subparagraph 10(a) has become fully enforceable and irrevocable, a lump sum in cash equal to 200% of the greater of (A) the then-current Base Salary, and (B) the Base Salary at any time within two years immediately before the CIC Effective Date; and

(ii) on or before the 60th day following Employee’s Separation from Service, a lump sum in cash equal to 200% of the average of any Bonuses received by Employee

from the Company in the two years before the CIC Effective Date; and”

SECTION 2. Miscellaneous

2.1.Scope of Amendment.The parties amend the Employment Agreement solely to the extent provided above, and in all other respects it shall continue in full force and effect.  

2.1.Counterparts.  This Amendment may be executed in counterparts, and all parties need not execute the same counterpart.  Facsimiles or other electronic transmission (e.g., pdf) will be effective as originals.

2.2.Headings.  The headings, captions, and arrangements used in this Amendment are, unless specified otherwise, for convenience only and will not be deemed to limit, amplify, or modify the terms of this Amendment, nor affect the meaning thereof.

2.3.Governing Law.  This Amendment shall be governed by and construed in accordance with the laws of the State of Texas.

[Signature page follows]

2

IN WITNESS WHEREOF, the parties hereto have caused this Amendment to be duly executed by their respective authorized officers on the date first written above.

EMPLOYEE:

__/s/      J. Curtis Henderson_____________

Name: J. Curtis Henderson

COMPANY:

APPROACH RESOURCES INC.

A Delaware Corporation

By:__/s/ J. Ross Craft___________________

Name:	J. Ross Craft
Title:	Chairman and Chief Executive Officer

3

EX-10.5

Exhibit 10.5

AMENDMENT NO. 1

TO

EMPLOYMENT AGREEMENT

This Amendment No. 1 to Employment Agreement (this “Amendment”) is effective as of January 26, 2017, by and among Approach Resources Inc., a Delaware corporation (the “Company”), and Qingming Yang, an individual residing in the state of Texas (“Employee”).

RECITALS

WHEREAS, Employee and the Company are parties to that Employment Agreement between Employee and Company, effective January 24, 2011 (the “Employment Agreement”);

WHEREAS, the parties wish to amend the Employment Agreement, as set forth herein;

NOW THEREFORE, in consideration of the premises and mutual covenants contained in this Amendment, together with other good and valuable consideration, the receipt and sufficiency of which is hereby acknowledged, and intending to be legally bound hereby, the parties agree to the following terms:

SECTION 1. Amendments to the Employment Agreement.  The Employment Agreement shall be amended as follows:.  

1.1Section 7(d)(i).  Section 7(d)(i) is hereby amended and restated in its entirety to read as follows:

“(i) on the earliest date between 20 and 60 days following Employee’s Separation from Service when the Release described in subparagraph 10(a) has become fully enforceable and irrevocable, a lump sum in cash equal to 200% of the greater of (A) the then-current Base Salary, and (B) the Base Salary at any time within two years immediately before the Separation from Service; and”

1.2Section 7(e)(i).  Section 7(e)(i) is hereby amended and restated in its entirety to read as follows:

“(i) on the earliest date between 20 and 60 days following Employee’s Separation from Service when the Release described in subparagraph 10(a) has become fully enforceable and irrevocable, a lump sum in cash equal to 200% of the greater of (A) the then-current Base Salary, and (B) the Base Salary at any time within two years immediately before the Separation from Service; and”

1.3Section 8(b)(i)-(ii).  Sections 8(b)(i)-(ii) are hereby amended and restated in its entirety to read as follows:

“(i) on the earliest date between 20 and 60 days following Employee’s Separation from Service when the Release described in subparagraph 10(a) has become fully enforceable and irrevocable, a lump sum in cash equal to 200% of the greater of (A) the then-current Base Salary, and (B) the Base Salary at any time within two years immediately before the CIC Effective Date; and

(ii) on or before the 60th day following Employee’s Separation from Service, a lump sum in cash equal to 200% of the average of any Bonuses received by Employee

from the Company in the two years before the CIC Effective Date; and”

SECTION 2. Miscellaneous

2.1.Scope of Amendment.The parties amend the Employment Agreement solely to the extent provided above, and in all other respects it shall continue in full force and effect.  

2.1.Counterparts.  This Amendment may be executed in counterparts, and all parties need not execute the same counterpart.  Facsimiles or other electronic transmission (e.g., pdf) will be effective as originals.

2.2.Headings.  The headings, captions, and arrangements used in this Amendment are, unless specified otherwise, for convenience only and will not be deemed to limit, amplify, or modify the terms of this Amendment, nor affect the meaning thereof.

2.3.Governing Law.  This Amendment shall be governed by and construed in accordance with the laws of the State of Texas.

[Signature page follows]

2

IN WITNESS WHEREOF, the parties hereto have caused this Amendment to be duly executed by their respective authorized officers on the date first written above.

EMPLOYEE:

__/s/ Qingming Yang________________

Name: Qingming Yang

COMPANY:

APPROACH RESOURCES INC.

A Delaware Corporation

By:__/s/ J. Ross Craft________________

Name:	J. Ross Craft
Title:	Chairman and Chief Executive Officer

3

EX-10.17

Exhibit 10.17

APPROACH RESOURCES INC.
2007 STOCK INCENTIVE PLAN

2017 RESTRICTED STOCK AWARD AGREEMENT

TSR VESTING REQUIREMENTS

THIS AGREEMENT, made and entered into as of March 7, 2017, by and between Approach Resources Inc., a Delaware corporation (“Approach”), and __________, an employee, outside director or other individual providing services to Approach or one of its Affiliates (“Participant”).

WHEREAS, the Compensation Committee of Approach’s Board of Directors or such other committee designated by Approach’s Board of Directors (the “Committee”), acting under Approach’s 2007 Stock Incentive Plan, as amended (the “Plan”), has the authority to award restricted shares (including the Target Restricted Shares and Maximum Restricted Shares each as defined herein, the “Restricted Shares”) of Approach’s common stock, $0.01 par value per share (the “Common Stock”), to employees, outside directors or other individuals providing services to Approach or an Affiliate;

WHEREAS, pursuant to the Plan, the Committee has determined to make such an award to Participant on the terms and conditions and subject to the restrictions set forth in the Plan and this Agreement, and Participant desires to accept such award; and

WHEREAS, a copy of the Plan has been made available to Participant and shall be deemed a part of this Agreement as if fully set forth herein and the terms capitalized but not defined herein shall have the meanings set forth in the Plan.

NOW, THERFORE, in consideration of the premises and mutual covenants and agreements contained herein, the receipt and sufficiency of which are hereby acknowledged, the parties hereby agree as follows:

1.TSR Restricted Stock Award.  On the terms and conditions and subject to the restrictions, including forfeiture, hereinafter set forth, Approach hereby awards to Participant, and Participant hereby accepts, a restricted stock award (the “Award”) with respect to a target number of __________ shares [100% OF TARGET] (the “Target Restricted Shares”) of Common Stock; provided, that, based on the relative achievement of the TSR Vesting Objective (as defined in this Agreement) and the other terms and conditions herein, the number of Restricted Shares that may ultimately become free of restrictions hereunder may range from 0% to 150% of the Target Restricted Shares (such number of Restricted Shares that equal 150% of the Target Restricted Shares, or __________ [150% OF TARGET] Restricted Shares, shall hereinafter be referred to as the “Maximum Restricted Shares”).  The Award is made on __________ (the “Grant Date”).  On the Grant Date, a number of Restricted Shares equal to the Maximum Restricted Shares shall be issued to Participant.  A certificate representing the Maximum Restricted Shares shall be issued in the name of Participant (or, at the option of Approach, in the name of a nominee of Approach) as of the Grant Date and delivered to Participant on the Grant Date or as soon thereafter as is practicable.  Participant shall cause the certificate representing the Maximum Restricted Shares, upon receipt thereof by Participant, to be deposited, together with stock powers and any other instrument of transfer reasonably requested by Approach duly endorsed in blank, with Approach, to be held by Approach in escrow for Participant’s benefit until such time as the Maximum Restricted Shares represented by such certificate are either forfeited by Participant to Approach or the restrictions thereon terminate as set forth in this Agreement.

2.Vesting and Forfeiture.  The Restricted Shares shall be subject to a performance period that shall commence on __________ and shall end two years after year of grant date (the “Performance Period”), subject to (i) the Committee’s certification of the level of achievement of the TSR Vesting Objective outlined in Section 2(a) below, and (ii) except as otherwise provided in Section 2(b) or 2(c), Participant’s continuous active service with Approach or an Affiliate through the end of the Performance Period (the “Continuous Service Requirement”).  During the Performance Period, the Maximum Restricted Shares shall be subject to being forfeited by Participant to Approach as provided in this Agreement, and Participant may not sell, transfer,

pledge, exchange, hypothecate or otherwise dispose of any of the Maximum Restricted Shares (the “Restrictions”).

(a)TSR Vesting Objective.  The “TSR Vesting Objective” means Approach’s relative ranking in respect of the Performance Period with regard to Total Shareholder Return (as defined in Appendix A attached hereto) as compared to Total Shareholder Return of the Peer Companies (as defined in Appendix A), and the level of achievement of the TSR Vesting Objective shall be determined in accordance with Appendix A.  After the end of the Performance Period (but no later than March 15, ____), the Committee will determine Approach’s Total Shareholder Return as compared to Total Shareholder Return of the Peer Companies and will certify the level of achievement with respect to the TSR Vesting Objective and what percentage of the Target Restricted Shares has been earned in accordance with the table set forth in Appendix A (such number of Restricted Shares that become earned shall hereinafter be called the “Earned Restricted Shares”), subject to Participant’s satisfaction of the Continuous Service Requirement; provided, that, if Approach’s absolute Total Shareholder Return for the Performance Period is negative, the number of Earned Restricted Shares shall not exceed the Target Restricted Shares.  Any fractional Earned Restricted Shares shall be rounded up to the nearest whole share of Common Stock. The Committee shall have the sole discretion for determining the level of achievement with respect to the TSR Vesting Objective and the number of Earned Restricted Shares, and any such determinations shall be conclusive.  If the Committee determines that less than the total number of Maximum Restricted Shares has become Earned Restricted Shares, (i) the Participant shall have no rights whatsoever in and to any of the Maximum Restricted Shares that have not become Earned Restricted Shares, (ii) all of the Maximum Restricted Shares that have not become Earned Restricted Shares shall automatically revert to Approach at no cost and (iii) neither the Participant nor any of his or her heirs, beneficiaries, executors, administrators or other personal representatives shall have any rights with respect to any Maximum Restricted Shares that have not become Earned Restricted Shares.  Following the removal of the Restrictions on any Earned Restricted Shares, Approach shall, as soon as administratively feasible, deliver to Participant from escrow a certificate representing such shares of Common Stock and Participant shall be free to sell, transfer, pledge, exchange, hypothecate or otherwise dispose of such shares of Common Stock, subject to applicable securities laws and the policies of Approach then in effect.

(b)Termination of Employment.

(i)Termination Generally.  Subject to Section 2(b)(ii) and Section 2(c), upon termination of Participant’s employment or service with Approach or an Affiliate prior to the end of the Performance Period, (A) the Participant shall have no rights whatsoever in and to any of the Maximum Restricted Shares, (B) all of the Maximum Restricted Shares shall automatically revert to Approach at no cost, and (C)  neither Participant nor any of his or her heirs, beneficiaries, executors, administrators or other personal representatives shall have any rights with respect thereto.

(ii)Termination for Death or Disability.  If Participant’s employment or service with Approach or an Affiliate is terminated prior to the end of the Performance Period as a result of the Participant’s death or Disability (as defined in the Plan), then the Restrictions on a number of Restricted Shares equal to the Target Restricted Shares shall automatically lapse at the time of such termination of employment or service and such number of Target Restricted Shares shall be deemed to be Earned Restricted Shares.  Following the removal of the Restrictions on the Earned Restricted Shares as of the time of termination, Approach shall, as soon as administratively feasible, deliver to Participant from escrow a certificate representing such shares of Common Stock and Participant shall be free to sell, transfer, pledge, exchange, hypothecate or otherwise dispose of such shares of Common Stock, subject to applicable securities laws and the policies of Approach then in effect.

(c)Change of Control.  Notwithstanding the Change of Control provisions in Article XIII of the Plan or any provision hereof to the contrary, if a Change of Control (as defined in the Plan) occurs prior to the end of the Performance Period (the date of such occurrence, the “Change of Control Date”) and Participant

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has remained in continuous service with Approach or an Affiliate through the Change of Control Date, then, upon the occurrence of such Change of Control, Participant shall be deemed to have earned a number of the Restricted Shares equal to the number of Earned Restricted Shares the Participant would have earned in accordance with Section 2(a), but assuming that (i) the Performance Period ended on the Change of Control Date, and (ii) the determination of whether, and to what extent, the TSR Vesting Objective is achieved shall be based on actual performance against the stated criteria through the Change of Control Date (and the Committee shall certify the level of such achievement no later than 60 days following the Change of Control Date).  Following the removal of the Restrictions on the Earned Restricted Shares as of the Change of Control Date, Approach shall, as soon as administratively feasible, deliver to Participant from escrow a certificate representing such shares of Common Stock and Participant shall be free to sell, transfer, pledge, exchange, hypothecate or otherwise dispose of such shares of Common Stock, subject to applicable securities laws and the policies of Approach then in effect.

3.Rights as Stockholder.  Subject to the provisions of this Agreement, upon the issuance of a certificate or certificates representing the Maximum Restricted Shares to Participant, Participant shall become the record and beneficial owner thereof for all purposes and shall have all rights as a stockholder, including without limitation voting rights and the right to receive dividends and distributions (provided that any such dividend or distribution shall be paid no later than the 15th day of the third month of the calendar year following the calendar year in which the dividend or distribution is declared by Approach), with respect to the Maximum Restricted Shares.  If and to the extent Approach shall effect a stock split, stock dividend or similar distribution with respect to the Common Stock, (a) the stock distributed pursuant thereto shall be held by Approach with respect to those Maximum Restricted Shares as to which the Restrictions have not yet been removed pursuant to Section 2; (b) such additional stock shall enjoy the privileges and be subject to the Restrictions applicable to the Maximum Restricted Shares; and (c) Participant shall be entitled to sell, transfer, pledge, exchange, hypothecate or otherwise dispose of such additional stock when and to the extent the Restrictions on the Maximum Restricted Shares to which the distribution relates have been removed pursuant to Section 2.

4.Optional Issuance in Book-Entry Form.  Notwithstanding the foregoing, at the option of Approach, any shares of Common Stock that under the terms of this Agreement are issuable in the form of a stock certificate may instead be issued in book-entry form.

5.Withholding Taxes.  

(a)Participant may elect, within 30 days of the Grant Date and on notice to Approach and the Internal Revenue Service in accordance with Section 83(b) of the Internal Revenue Code of 1986, as amended, and the regulations and other guidance thereunder, to realize income for federal income tax purposes equal to the fair market value of the Maximum Restricted Shares on the Grant Date.  In such event, Participant shall make arrangements satisfactory to Approach or the appropriate Affiliate to pay in the calendar year that includes the Grant Date any federal, state or local taxes required to be withheld with respect to such shares.

(b)If no election is made by Participant pursuant to Section 5(a) hereof, then upon the termination of the Restrictions applicable hereunder to all or any portion of the Restricted Shares, Participant (or in the event of Participant’s death, the administrator or executor of Participant’s estate) will pay to Approach or the appropriate Affiliate, or make arrangements satisfactory to Approach or such Affiliate regarding payment of, any federal, state or local taxes of any kind required by law to be withheld with respect to the Earned Restricted Shares with respect to which such Restrictions have terminated.  Approach may allow the Participant to pay the amount of such taxes required by law to be withheld with respect to the Earned Restricted Shares by (i) withholding shares of Common Stock from any issuance of Common Stock due as a result of the removal of the Restrictions on any Restricted Shares, or (ii) permitting the Participant to deliver to Approach previously acquired shares of Common Stock, in each case having an aggregate Fair Market Value on the date of calculation equal to the amount of such required withholding taxes.

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(c)Any provision of this Agreement to the contrary notwithstanding, if Participant does not satisfy his or her obligations under paragraphs (a) or (b) of this Section 5, Approach shall, to the extent permitted by law, have the right to deduct from any payments made under the Plan, regardless of the form of such payment, or from any other compensation payable to Participant, whether or not pursuant to this Agreement or the Plan and regardless of the form of payment, any federal, state or local taxes of any kind required by law to be withheld with respect to the Restricted Shares.

6.Reclassification of Shares.  In the event of any reorganization, recapitalization, stock split, stock dividend, merger, consolidation, combination of shares or other change affecting the Common Stock, the Committee shall make adjustments in accordance with the Plan.  Any such adjustments made by the Committee shall be conclusive.

7.Effect on Employment.  Nothing contained in this Agreement shall confer upon Participant the right to continue in the employment of Approach or any Affiliate, or affect any right which Approach or any Affiliate may have to terminate the employment of Participant.  This shall not be construed as any agreement or understanding, express or implied, that Approach or any Affiliate will retain Participant as an employee for any period of time or at any particular rate of compensation or other terms and conditions of employment unrelated to Restricted Shares.

8.Investment Representations.  

(a)The shares are being received for Participant’s own account with the intent of holding them and without the intent of participating, directly or indirectly, in a distribution of such shares and not with a view to distribute, or for resale in connection with any distribution of, such shares or any portion thereof.

(b)A legend may be placed on any certificate(s) or other document(s) delivered to Participant or substitute therefore indicating restrictions on transferability of the shares pursuant to this Agreement or referring to any stop transfer orders and other restrictions as the Committee may deem advisable under the rules, regulations and other requirements of the Securities and Exchange Commission, NASDAQ or any other stock exchange or association upon which the Common Stock of Approach is then listed or quoted, any applicable federal or state securities laws, and any applicable corporate law, and any transfer agent of Approach shall be instructed to require compliance therewith.

9.Assignment.  Approach may assign all or any portion of its rights and obligations under this Agreement.  The Award, the Restricted Shares and the rights and obligations of Participant under this Agreement may not be assigned, sold, transferred, pledged, exchanged, hypothecated or otherwise disposed of by Participant other than by will or the applicable laws of descent and distribution.

10.Binding Effect.  This Agreement shall be binding upon and inure to the benefit of (a) Approach and its successors and assigns, and (b) Participant and his or her heirs, devisees, executors, administrators and personal representatives.

11.Notices.  All notices between the parties hereto shall be in writing and given in the manner provided in Section 15.7 of the Plan.  Notices to Participant shall be given to Participant’s address as contained in Approach’s records.  Notices to Approach shall be addressed to the Corporate Secretary at the principal executive offices of Approach as set forth in Section 15.7 of the Plan.

12.Governing Law; Exclusive Forum; Consent to Jurisdiction.  This Agreement shall be governed by the laws of the State of Delaware except for its laws with respect to conflict of laws.  The exclusive forum for any lawsuit arising from or related to this Agreement shall be a state or federal court in Tarrant County, Texas.  This provision does not prevent Approach from removing to an appropriate federal court any action brought in state court.  NOTHING IN THIS AGREEMENT SHALL BE CONSTRUED AS

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PROHIBITING REMOVAL TO FEDERAL COURT BY APPROACH OF ANY ACTION BROUGHT AGAINST IT BY PARTICIPANT.

13.Execution of Receipts and Releases.  Any issuance or transfer of the Restricted Shares to Participant or Participant’s legal representative, heir, legatee or distributee, in accordance with the provisions of this Agreement, shall be in full satisfaction of all claims of such persons hereunder related to the Award.  Approach may require Participant or Participant’s legal representative, heir, legatee or distributee, as a condition precedent to such issuance, to execute such a release and receipt therefore in such form as Approach may determine.

14.Severability.  If any provision of this Agreement is held to be illegal or invalid for any reason, the illegality or invalidity shall not affect the remaining provisions hereof, but such provision shall be fully severable and this Agreement shall be construed and enforced as if the illegal or invalid provision had never been included herein.

15.Headings.  The titles and headings of Sections are included for convenience of reference only and are not to be considered in construction of the provisions hereof.

16.Amendment.  The Committee may amend the terms of this Award and this Agreement at any time, although no such amendment shall adversely affect, in any material way, the Participant’s (or a Participant’s Permitted Transferee’s) rights under an outstanding Award without the prior consent of the Participant (or the Participant’s Permitted Transferee) then holding the Award.

17.Entire Agreement.  This Agreement constitutes the entire agreement between the parties concerning its subject matter and supersedes all prior agreements, understandings, and statements, both written and oral, between the parties with respect to such subject matter.  In signing this Agreement, the Participant is not relying on any written or oral statement, promise, or representation from Approach or its Affiliates concerning this Agreement other than as set above in this Agreement.

18.Miscellaneous. Notwithstanding anything to the contrary in this Agreement, Approach will not be required to comply with any term, covenant or condition of this Agreement if and to the extent prohibited by applicable law. Participant shall reimburse Approach for incentive-based or equity-based compensation and profits realized from the sale of the Restricted Shares covered by this Agreement as required by applicable law, including, but not limited to, Section 304 of the Sarbanes-Oxley Act of 2002 and Section 954 of the Dodd-Frank Wall Street Reform and Consumer Protection Act of 2010, and agrees that Approach need not comply with any term, covenant or condition of this Agreement to the extent that doing so would require that Participant reimburse Approach for such amounts pursuant to Section 304 of the Sarbanes-Oxley Act of 2002 and/or Section 954 of the Dodd-Frank Wall Street Reform and Consumer Protection Act of 2010.

IN WITNESS WHEREOF, Approach and Participant have executed this Agreement as of the date first written above.

Approach Resources Inc.

By:

Name:

Title:

PARTICIPANT

By:

Name:

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STOCK POWER AND ASSIGNMENT

SEPARATE FROM CERTIFICATE

FOR VALUE RECEIVED and pursuant to that certain Approach Resources Inc. 2007 Stock Incentive Plan and the Restricted Stock Award Agreement dated __________ (the “Agreement”), the undersigned Participant hereby sells, assigns and transfers unto Approach Resources Inc., __________ shares of Common Stock, $0.01 par value per share, of Approach Resources Inc., a Delaware corporation (“Approach”), standing in the undersigned’s name on the books of Approach and does hereby irrevocably constitute and appoint the Corporate Secretary of Approach as the undersigned’s attorney-in-fact, with full power of substitution, to transfer said stock on the books of Approach.  THIS ASSIGNMENT MAY ONLY BE USED AS AUTHORIZED BY THE AGREEMENT AND ANY EXHIBITS THERETO.

Dated:  _________________________

PARTICIPANT

By:

Name:

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APPENDIX A

TO RESTRICTED STOCK AWARD AGREEMENT

Total Shareholder Return Vesting Objective

The TSR Vesting Objective for the Restricted Shares is outlined in this Appendix A below.  The “TSR Vesting Objective” means Approach’s relative ranking in respect of the Performance Period with regard to Total Shareholder Return as compared to Total Shareholder Return of the Peer Companies. The Committee shall have the sole discretion for determining the level of achievement with respect to the TSR Vesting Objective and the number of Earned Restricted Shares, and any such determinations shall be conclusive.

1. Defined Terms.  

(a)“Total Shareholder Return” means, as to Approach and each of the Peer Companies, the annualized rate of return shareholders receive through stock price changes and the assumed reinvestment of dividends paid over the Performance Period.  Dividends per share paid other than in the form of cash shall have a value equal to the amount of such dividends reported by the issuer to its shareholders for purposes of Federal income taxation.  For purposes of determining the Total Shareholder Return for Approach and each of the Peer Companies the change in the price of Approach’s Common Stock and of the common stock of each Peer Company, as the case may be, shall be based upon the average of the closing stock prices of Approach and each such Peer Company on each trading day in the 30-day period preceding each of the start (“Initial Value”) and the end (“Closing Value”) of the Performance Period.    

(b)“Peer Company” means a company that (i) has a class of common equity securities listed to trade on a national securities exchange which is registered with the Commission under Section 6 of the Exchange Act of 1934, as amended (the “Exchange Act”), and registered under Section 12 of the Exchange Act, during each day of the Performance Period, and (ii) is one of the following companies:

Bill Barrett Corporation	Matador Resources Company
Callon Petroleum Company	Northern Oil & Gas Inc.
Carrizo Oil & Gas, Inc.	PDC Energy Inc.
Comstock Resources Inc.	Petroquest Energy, Inc.
Diamondback Energy Inc.	Resolute Energy Corporation
Gulfport Energy Corporation	Rex Energy Corporation
Jones Energy Inc.	Sanchez Energy Corporation

If a Peer Company ceases to qualify as a Peer Company at any time during the Performance Period due to or following its bankruptcy or de-listing due to failure to meet minimum listing standards, such company shall remain a Peer Company with its Total Shareholder Return automatically deemed to occupy the lowest available rank (i.e., if a Peer Company has been de-listed due to failure to meet minimum listing standards, or has filed bankruptcy, then any subsequent Peer Company to be de-listed or to file bankruptcy will occupy the next to lowest rank) among the Peer Companies for the Performance Period. In addition, if and solely to the extent that at the end of the Performance Period one or more of the 14 companies listed above fails to qualify as a “Peer Company” for reasons other than bankruptcy or de-listing due to failure to meet minimum listing standards (such as a merger or going-private transaction), then such number of alternate companies (as the Committee may, in their discretion, select) as is necessary to have 14 Peer Companies may be treated as Peer Companies for the entire Performance Period, provided that each such alternate company satisfies the definition of Peer Company.  

If, after adding all eligible alternate companies (or if the Committee does not select alternate Peer Companies), the number of companies qualifying as Peer Companies for the Performance Period is less than 14, the percentage of the Target Restricted Shares earned shall be determined in a manner consistent with (a) the requirements to qualify the Restricted Shares as performance-based compensation exempt from the limitations imposed by Section 162(m) of the Internal Revenue Code of 1986, as amended, and (b) the following general guidelines for determining the number of Earned Restricted Shares:

(i)If the Company’s Total Shareholder Return ranks in the 79^th percentile or above as compared to the Total Shareholder Return of the qualifying Peer Companies, the number of Earned Restricted Shares shall equal the Maximum Restricted Shares;

(ii)If the Company’s Total Shareholder Return ranks in the 57^th percentile as compared to the Total Shareholder Return of the qualifying Peer Companies (or, the next percentile above 57% that applies if the actual determination of the Total Shareholder Return rankings for the Performance Period does not include the 57^th percentile), the number of Earned Restricted Shares shall equal the Target Restricted Shares;

(iii)If the Company’s Total Shareholder Return ranks in the 43^rd percentile as compared to the Total Shareholder Return of the qualifying Peer Companies (or, the next percentile above 43% that applies if the actual determination of the Total Shareholder Return rankings for the Performance Period does not include the 43^rd percentile), the number of Earned Restricted Shares shall equal 50% of the Target Restricted Shares (such percentage of the Target Restricted Shares, the “Threshold Restricted Shares”);

(iv)If the Company’s Total Shareholder Return ranks below the 43^rd percentile as compared to the Total Shareholder Return of the qualifying Peer Companies, no Restricted Shares will become Earned Restricted Shares; and

(v)If the Company’s Total Shareholder Return ranking falls in between the levels specified above for earning the Maximum Restricted Shares, the Target Restricted Shares and the Threshold Restricted Shares, the Target Restricted Shares that become Earned Restricted Shares will be determined by reference to the closest percentile ranking set forth below in Section 2 (e.g., if the revised Total Shareholder Return Percentile Ranking is 66%, then 117% of Target Restricted Shares would be earned (subject to the Maximum, Target and Threshold levels specified above).  

(c)“Performance Period” means the three year period commencing on __________ and ending two years after year of grant date.  

2.Calculation of Ranking; Earned Restricted Shares.  After the end of the Performance Period, the Committee will determine Approach’s Total Shareholder Return as compared to Total Shareholder Return of the Peer Companies and will certify the level of achievement with respect to the TSR Vesting Objective and the number of Earned Restricted Shares in accordance with the following table:

TSR Company Ranking	Percentile Ranking	Percentage of Target Restricted Shares Earned
Company 1	100%	150%
Company 2	93%	150%
Company 3	86%	150%
Company 4	79%	150%
Company 5	71%	133%
Company 6	64%	117%
Company 7	57%	100%
Company 8	50%	67%
Company 9	43%	50%
Company 10	36%	0%
Company 11	29%	0%
Company 12	21%	0%
Company 13	14%	0%
Company 14	7%	0%
Company 15	0%	0%

A-2

Notwithstanding the foregoing, (a) if Approach’s absolute Total Shareholder Return for the Performance Period is negative, the number of Earned Restricted Shares shall not exceed the Target Restricted Shares, and (b) no Restricted Shares will become Earned Restricted Shares unless Participant also satisfies the Continuous Service Requirement in accordance with the terms of the Agreement.  

A-3

EX-12.1

Exhibit 12.1

APPROACH RESOURCES INC.

STATEMENT OF COMPUTATION OF RATIOS OF EARNINGS TO FIXED CHARGES

	Years ended December 31,
(in thousands, except ratios)	2012		2013		2014		2015			2016
COMPUTATION OF EARNINGS (LOSS):
Earnings (loss) before income taxes	$	9,722	$	114,763	$	89,864	$	(267,509	)	$	(76,661	)
Fixed charges		4,766		14,153		21,670		25,089			27,301
	$	14,488	$	128,916	$	111,534	$	(242,420	)	$	(49,360	)
COMPUTATION OF FIXED CHARGES:
Interest expense(1)	$	4,737	$	14,125	$	21,656	$	25,066		$	27,262
Implicit interest in rent		29		28		14		23			39
	$	4,766	$	14,153	$	21,670	$	25,089		$	27,301
Ratio of earnings (loss) to fixed charges(2)	3.04x		9.11x		5.15x		—		(3)		—	(3)

(1) For purposes of computing this ratio, we have excluded interest income from interest expense amounts reported on the consolidated statement of operations.

(2) The ratio has been computed by dividing earnings (loss) by fixed charges. For purposes of computing the ratio, the numerator consists of the sum of (i) earnings (loss), which includes income before income taxes, and (ii) fixed charges. The denominator consists of fixed charges, which includes interest expense and a portion of rentals representative of an implicit interest factor for such rentals.

(3) Due to our net losses for the years ended December 31, 2015 and 2016, the coverage ratio for each of these periods was less than 1:1. To achieve a coverage ratio of 1:1, we would have needed additional earnings of approximately $242.4 million and $49.4 million for the years ended December 31, 2015 and 2016, respectively.

EX-21.1

Exhibit 21.1

Subsidiaries of Approach Resources Inc.

Name	Jurisdiction of Incorporation or Formation
Approach Oil & Gas Inc.	Delaware
Approach Operating, LLC	Delaware
Approach Delaware, LLC	Delaware
Approach Resources I, LP	Texas
Approach Services, LLC	Delaware
Approach Midstream Holdings, LLC	Delaware

EX-23.1

Exhibit 23.1

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We consent to the incorporation by reference in Registration Statement (No. 333-195880) on Form S-3 and Registration Statements (No. 333-148951, 333-183069, 333-208003 and 333-214906) on Form S-8 of Approach Resources Inc. of our reports dated March 10, 2017, relating to our audits of the consolidated financial statements and internal control over financial reporting, which appear in this Annual Report on Form 10-K of Approach Resources Inc. for the year ended December 31, 2016.

/s/ Hein & Associates LLP

Dallas, Texas

March 10, 2017

EX-23.2

Exhibit 23.2

DEGOLYER AND MACNAUGHTON

5001 SPRING VALLEY ROAD

SUITE 800 EAST

DALLAS, TEXAS 75244

March 10, 2017

Approach Resources Inc.

One Ridgmar Centre

6500 West Freeway, Suite 800

Fort Worth, Texas 76116

Ladies and Gentlemen:

We hereby consent to the use of the name DeGolyer and MacNaughton, to references to DeGolyer and MacNaughton as an independent petroleum engineering consulting firm, to the inclusion of references to our third-party letter report dated January 29, 2015, containing our opinion on the proved reserves attributable to certain properties that Approach Resources Inc. has represented that it owns as of December 31, 2014, our third-party letter report dated January 27, 2016, containing our opinion on the proved reserves attributable to certain properties that Approach Resources Inc. has represented that it owns as of December 31, 2015, and to our third-party letter report dated February 7, 2017, containing our opinion on the proved reserves attributable to certain properties that Approach Resources Inc. has represented that it owns as of December 31, 2016, under the headings “Part I — Item 2. Properties,” “Part II — Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations,” and “Notes to Consolidated Financial Statements — 10. Disclosures About Oil and Gas Producing Activities (unaudited)” in Approach Resources Inc.’s Annual Report on Form 10-K for the year ended December 31, 2016 (the Annual Report). We further consent to the inclusion of our third party letter report dated February 7, 2017, containing our opinion on the proved reserves attributable to certain properties that Approach Resources Inc. has represented that it owns as of December 31, 2016, as an exhibit in the Annual Report.

We hereby further consent to the incorporation by reference of our name and such aforementioned information with respect to the estimated oil and gas reserves of Approach Resources Inc. in Registration Statement (No. 333-195880) on Form S-3 and Registration Statements (Nos. 33-214906, 333-208003, 333-183069 and 333-148951) on Form S-8 of Approach Resources Inc.

Very truly yours,

/s/ DeGOLYER and MacNAUGHTON

DeGOLYER and MacNAUGHTON

Texas Registered Engineering Firm F-716

EX-31.1

Exhibit 31.1

Certification

I, J. Ross Craft, certify that:

1. I have reviewed this annual report on Form 10-K of Approach Resources Inc.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:	March 10, 2017	/s/ J. Ross Craft
		J. Ross Craft
		Chairman of the Board and Chief Executive Officer
		(Principal Executive Officer)

EX-31.2

Exhibit 31.2

Certification

I, Sergei Krylov, certify that:

1. I have reviewed this annual report on Form 10-K of Approach Resources Inc.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:	March 10, 2017	/s/ Sergei Krylov
		Sergei Krylov
		Executive Vice President and Chief Financial Officer
		(Principal Financial Officer)

EX-32.1

Exhibit 32.1

Certification of Chief Executive Officer of Approach Resources Inc.

(Pursuant to 18 U.S.C. Section 1350, as adopted pursuant to

Section 906 of the Sarbanes-Oxley Act of 2002)

In connection with the annual report on Form 10-K of Approach Resources Inc. (the “Company”) for the period ended December 31, 2016, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, J. Ross Craft, Chairman of the Board and Chief Executive Officer of the Company, hereby certify, pursuant to 18 U.S.C. 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to my knowledge:

(1) The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

		APPROACH RESOURCES INC.
Date:	March 10, 2017	/s/ J. Ross Craft
		J. Ross Craft
		Chairman of the Board and Chief Executive Officer
		(Principal Executive Officer)

EX-32.2

Exhibit 32.2

Certification of Chief Financial Officer of Approach Resources Inc.

(Pursuant to 18 U.S.C. Section 1350, as adopted pursuant to

Section 906 of the Sarbanes-Oxley Act of 2002)

In connection with the annual report on Form 10-K of Approach Resources Inc. (the “Company”) for the period ended December 31, 2016, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Sergei Krylov, Executive Vice President and Chief Financial Officer of the Company, hereby certify, pursuant to 18 U.S.C. 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to my knowledge:

(1) The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

		APPROACH RESOURCES INC.
Date:	March 10, 2017	/s/ Sergei Krylov
		Sergei Krylov
		Executive Vice President and Chief Financial Officer
		(Principal Financial Officer)

EX-99.1

Exhibit 99.1

DeGolyer and MacNaughton

5001 Spring Valley Road

Suite 800 East

Dallas, Texas 75244

February 7, 2017

Approach Resources Inc.

6500 West Freeway, Suite 800

Fort Worth, Texas 76116

Ladies and Gentlemen:

Pursuanttoyourrequest, wehavepreparedestimatesoftheextentandvalueofthenetprovedoil,condensate,naturalgasliquids(NGL),andgasreserves,asofDecember31,2016,ofcertainpropertiesthatApproachResourcesInc.(Approach)hasrepresentedthatitowns.ThesepropertiesarelocatedintheStateofTexas.Thisevaluation wascompletedon February7,2017.Approachhasrepresented thatthesepropertiesaccountfor100percentonanetequivalentbarrelbasisofApproach’snetprovedreservesasofDecember31,2016.Thenetprovedreservesestimates preparedbyushavebeenpreparedinaccordancewiththereservesdefinitionsofRules4–l0(a)(1)–(32)ofRegulationS–XoftheSecuritiesandExchangeCommission(SEC)oftheUnitedStates.ThisreportwaspreparedinaccordancewithguidelinesspecifiedinItem1202(a)(8)ofRegulationS–KandistobeusedforinclusionincertainSECfilingsbyApproach.

Reservesestimatesincludedhereinareexpressedasnetreserves.Grossreservesaredefinedasthetotalestimatedpetroleumtobeproducedfromthese propertiesafterDecember31,2016.Netreservesaredefinedasthatportionofthe grossreservesattributabletotheinterestsownedbyApproachafterdeductingallinterestsownedbyothers.

Values of proved reserves shown herein are expressed in terms of future gross revenue, future net revenue, and present worth. Future gross revenue is that revenue which will accrue to the evaluated interests from the production and sale of the estimated net reserves. Future net revenue is calculated by deducting estimated production taxes, ad valorem taxes, operating expenses, and capital and abandonment costs from the future gross revenue.  Operating expenses include field operating expenses, transportation expenses, compression charges, and an allocation of overhead that directly relates to production activities. Future income tax expenses were not taken into account in the preparation of these estimates. Present worth is defined as future net revenue discounted at a specified arbitrary discount rate compounded annually over the expected period of realization. Present worth should not be construed as fair market value because no consideration was given to additional factors that influence the prices at which properties are bought and sold.

Estimates of oil, condensate, NGL, and gas reserves and future net revenue should be regarded only as estimates that may change as further production history and additional information become available. Not only are such reserves and revenue estimates based on that information which is currently available, but such estimates are also subject to the uncertainties inherent in the application of judgmental factors in interpreting such information.

Data used in this evaluation were obtained from reviews with Approach personnel, from Approach files, from records on file with the appropriate regulatory agencies, and from public sources. Additionally, this information includes data supplied by IHS Global Inc.; Copyright 2016 IHS Global Inc. In the preparation of this report we have relied, without independent verification, upon such information furnished by Approach with respect to property interests, production from such properties, current costs of operation and development, current prices for production, agreements relating to current and future operations and sale of production, and various other information and data that were accepted as represented. A field examination of the properties was not considered necessary for the purposes of this report.

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Methodology and Procedures

Estimates of reserves were prepared by the use of appropriate geologic, petroleum engineering, and evaluation principles and techniques that are in accordance with practices generally recognized by the petroleum industry as presented in the publication of the Society of Petroleum Engineers entitled "Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information (Revision as of February 19, 2007)." The method or combination of methods used in the analysis of each reservoir was tempered by experience with similar reservoirs, stage of development, quality and completeness of basic data, and production history.

Based on the current stage of field development, production performance, the development plans provided by Approach, and the analyses of areas offsetting existing wells with test or production data, reserves were classified as proved.

For the fields evaluated in this report, structure and isopach maps were prepared by Approach to delineate each reservoir. Electrical logs, radioactivity logs, seismic data, and other available data were used to prepare these maps. Parameters of area, porosity, and water saturation were estimated and applied by Approach to the isopach maps to obtain estimates of original oil in place (OOIP) or original gas in place (OGIP). These maps were reviewed in detail and found acceptable to use for the purpose of this report.

For developed producing wells whose performance disclosed a reliable decline in producing-rate trends or other diagnostic characteristics, reserves were estimated using decline-curve analysis. Reserves for producing wells whose performance was not yet established and for undeveloped locations were estimated using type curves. The parameters needed to develop these type curves such as initial decline rate, b factor, and final decline rate were based on nearby wells producing from the same reservoir and of similar completion for which more data were available.

In certain cases, when the previously named methods could not be used, reserves were estimated by analogy with similar wells or reservoirs for which more complete data were available.

Gas quantities estimated herein are expressed as fuel gas and sales gas. Fuel gas is that portion of the produced gas to be used in field operations. Sales gas is defined as that portion of the total gas to be delivered into a gas pipeline for sale after field separation, processing, fuel use, and flare. Gas reserves are expressed at a temperature base of 60 degrees Fahrenheit and at a pressure base of 14.65 pounds per square inch absolute. Gas quantities included herein are expressed in thousands of cubic feet (Mcf). Oil and condensate reserves estimated herein are those to be recovered by conventional lease separation. NGL reserves are those attributed to the leasehold interests according to processing agreements. Oil, condensate, and NGL reserves included herein are expressed in barrels (bbl) representing 42 United States gallons per barrel. For reporting purposes, oil and condensate reserves have been estimated separately and are presented herein as a summed quantity.

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Definition of Reserves

Petroleum reserves estimated by us included in this report are classified as proved. Only proved reserves have been evaluated for this report. Reserves classifications used by us in this report are in accordance with the reserves definitions of Rules 4–l0(a) (1)–(32) of Regulation S–X of the SEC. Reserves are judged to be economically producible in future years from known reservoirs under existing economic and operating conditions and assuming continuation of current regulatory practices using conventional production methods and equipment. In the analyses of production-decline curves, reserves were estimated  only  to  the limit of economic rates of production under existing economic and operating conditions using prices and costs consistent with the effective date of this report, including consideration of changes in existing prices provided only by contractual arrangements but not including escalations based upon future conditions. The petroleum reserves are classified as follows:

Proved oil and gas reserves – Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data,  can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain,  regardless  of  whether  deterministic or  probabilistic  methods  are  used  for  the  estimation.  The  project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

(i) The area of the reservoir considered as proved includes:

(A) The area identified by drilling and limited by fluid contacts, if any, and (B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.

(ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.

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DeGolyer and MacNaughton

(iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of  the  reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.

(iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when:

(A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and (B) The project has been approved for development by all necessary parties and entities, including governmental entities.

(v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

Developed oil and gas reserves – Developed oil and gas reserves are reserves of any category that can be expected to be recovered:

(i) Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and

(ii) Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

Undeveloped oil and gas reserves – Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

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

(ii) Undrilledlocationscanbeclassifiedashavingundevelopedreservesonlyifadevelopmentplanhasbeenadoptedindicating thattheyarescheduledtobedrilledwithinfiveyears,unlessthespecificcircumstancesjustifyalongertime.

(iii) Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, as defined in [section 210.4–10 (a) Definitions], or by other evidence using reliable technology establishing reasonable certainty.

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Primary Economic Assumptions

The following economic assumptions were used for estimating existing and future prices and costs:

Oil and Condensate Prices

Approach has represented that the oil and condensate prices were based on a reference price, calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period, unless prices are defined by contractual arrangements.    Approach  supplied differentials by field to a West Texas Intermediate reference price of $42.69 per barrel and the prices were held constant thereafter. The volume-weighted average oil and condensate price attributable to estimated proved reserves over the lives of the properties was $39.84 per barrel.

NGL Prices

Approach has represented that the NGL prices were based on a 12-month average price, calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period, unless prices are defined by contractual arrangements. The volume-weighted average NGL price attributable to the estimated proved reserves over the lives of the properties was $14.12 per barrel.

Gas Prices

Approach has represented that the gas prices were based on a reference price, calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period, unless prices are defined by contractual arrangements. The gas prices were calculated for each property using differentials and British thermal units (Btu) values provided by Approach to the Henry Hub reference price of $2.47 per million Btu and held constant thereafter. The volume-weighted average gas price attributable to estimated proved reserves over the lives of the properties was $2.122 per thousand cubic feet.

ProductionandAdValoremTaxes

Production taxes were calculated using the tax rates for Texas, including, where appropriate, abatements for enhanced recovery programs. Ad valorem taxes were calculated using rates provided by Approach based on historical tax data.

OperatingExpenses,CapitalCosts,andAbandonmentCosts

Estimates of operating expenses, provided by Approach and based on current expenses, were used for the lives of the properties with no increases in the future based on inflation. In certain cases, future expenses, either higher or lower than current expenses, may have been used because of anticipated changes in operating conditions. Future capital expenditures were estimated using 2016 values provided by Approach and were not adjusted for inflation. Abandonment costs were provided by Approach.

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Our estimates of the net proved reserves attributable to Approach’s interests in the evaluated properties were based on the definitions of proved reserves of the SEC and are summarized as follows, expressed in thousands of barrels (Mbbl), millions of cubic feet (MMcf), and thousands of barrels of oil equivalent (Mboe):

	Estimated by DeGolyer and MacNaughton Net Proved Reserves as of December 31, 2016
	Oil and Condensate (Mbbl)		NGL (Mbbl)		Fuel Gas (MMcf)		Sales Gas (MMcf)		Oil Equivalent (Mboe)
Permian Basin
Proved Developed		13,466		20,375		18,406		131,290		58,790
Proved Undeveloped		36,565		27,259		25,755		176,314		97,502
Total Permian Basin		50,031		47,634		44,161		307,604		156,293
East Texas Basin
Proved Developed		0		0		17		495		85
Proved Undeveloped		0		0		0		0		0
Total East Texas Basin		0		0		17		495		85
Total Proved		50,031		47,634		44,178		308,099		156,377

Note:Gas is converted to oil equivalent using an energy equivalent factor of 6,000 cubic feet of gas per 1 barrel of oil equivalent.

The estimated  future revenue  attributable to  Approach’s interests in  the proved reserves, as of December 31, 2016, of the properties evaluated is summarized as follows, expressed in thousands of dollars (M$):

	Proved
	Developed Producing		Developed Nonproducing		Undeveloped		Total
Future Gross Revenue, M$		1,095,137		9,096		2,215,418		3,319,551
Production and Ad Valorem Taxes, M$		88,656		664		173,508		262,828
Operating Expenses, M$		350,562		1,651		439,170		791,383
Capital and Abandonment Costs, M$		16,495		2,720		810,711		829,926
Future Net Revenue, M$		639,324		4,061		792,030		1,435,415
Present Worth at 10 Percent, M$		294,974		774		12,141		307,889

Note:Future income tax expenses were not taken into account in the preparation of these estimates.

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DeGolyer and MacNaughton

While the oil and gas industry may be subject to regulatory changes from time to time that could affect an industry participant’s ability to recover its oil and gas reserves, we are not aware of any such governmental actions which would restrict the recovery of the December 31, 2016, estimated oil and gas reserves.

In our opinion, the information relating to estimated proved reserves, estimated future net revenue from proved reserves, and present worth of estimated future net revenue from proved reserves of oil, condensate, natural gas liquids, and gas contained in this report has been prepared in accordance with Paragraphs 932-235-50-4, 932-235-50-6, 932-235-50-7, 932-235-50-9, 932-235-50-30, and 932-235-50-31(a), (b), and (e) of the Accounting Standards Update 932-235-50, Extractive Industries – Oil and Gas (Topic 932): Oil and Gas Reserve Estimation and Disclosures (January 2010) of the Financial Accounting Standards Board and Rules 4–l0(a) (1)–(32) of Regulation S–X and Rules 302(b), 1201, 1202(a) (1), (2), (3), (4), (8), and 1203(a) of Regulation S-K of the Securities and Exchange Commission; provided, however, that (i) future income tax expenses have not been taken into account in estimating the future net revenue and present worth values set forth herein and (ii) estimates of the proved developed and proved undeveloped reserves are not presented at the beginning of the year.

To the extent the above-enumerated rules, regulations, and statements require determinations of an accounting or legal nature, we, as engineers, are necessarily unable to express an opinion as to whether the above-described information is in accordance therewith or sufficient therefor.

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DeGolyer and MacNaughton

DeGolyer and MacNaughton is an independent petroleum engineering consulting firm that has been providing petroleum consulting services throughout the world since 1936. DeGolyer and MacNaughton does not have any financial interest, including stock ownership, in Approach. Our fees were not contingent on the results of our evaluation. This letter report has been prepared at the request of Approach. DeGolyer and MacNaughton has used all assumptions, data, procedures, and methods that it considers necessary and appropriate to prepare this report.

Submitted,

/s/ DeGolyer and MacNaughton

DeGOLYER and MacNAUGHTON
Texas Registered Engineering Firm F-716

	/s/ Dennis W. Thompson
	Dennis W. Thompson, P.E.
[SEAL]	Senior Vice President
	DeGolyer and MacNaughton

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DeGolyer and MacNaughton

CERTIFICATE of QUALIFICATION

I, Dennis W. Thompson, Petroleum Engineer with DeGolyer and MacNaughton, 5001 Spring Valley Road, Suite 800 East, Dallas, Texas, 75244 U.S.A., hereby certify:

1. That I am a Senior Vice President with DeGolyer and MacNaughton, which company did prepare the letter report addressed to Approach dated February 7, 2017, and that I, as Senior Vice President, was responsible for the preparation of this letter report.

2. That I attended the Eastern New Mexico University, and that I graduated with a Bachelor of Science degree in Geology in the year 1973; that I earned a Master of Science degree in Petroleum Engineering from the University of Texas at Austin in 1975; that I am a Registered Professional Engineer in the State of Texas; that I am a member of the Society of Petroleum Engineers and the Society of Petroleum Evaluation Engineers; and that I have in excess of 37 years of experience in oil and gas reservoir studies and reserves evaluations.

	/s/ Dennis W. Thompson
	Dennis W. Thompson, P.E.
	Senior Vice President
[SEAL]	DeGolyer and MacNaughton

10

XML

Document and Entity Information - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Mar. 06, 2017	Jun. 30, 2016
Document And Entity Information [Abstract]
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2016
Document Fiscal Year Focus	2016
Document Fiscal Period Focus	FY
Trading Symbol	AREX
Entity Registrant Name	Approach Resources Inc
Entity Central Index Key	0001405073
Current Fiscal Year End Date	--12-31
Entity Well-known Seasoned Issuer	No
Entity Current Reporting Status	Yes
Entity Voluntary Filers	No
Entity Filer Category	Accelerated Filer
Entity Common Stock, Shares Outstanding		80,903,376
Entity Public Float			$ 80.3

XML

Consolidated Balance Sheets - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
CURRENT ASSETS:
Cash and cash equivalents	$ 21	$ 600
Accounts receivable:
Joint interest owners	92	142
Oil, NGLs and gas sales	9,547	11,747
Unrealized gain on commodity derivatives		6,737
Prepaid expenses and other current assets	2,834	1,212
Total current assets	12,494	20,438
PROPERTIES AND EQUIPMENT:
Oil and gas properties, at cost, using the successful efforts method of accounting	1,869,774	1,853,781
Furniture, fixtures and equipment	5,644	5,628
Total oil and gas properties and equipment	1,875,418	1,859,409
Less accumulated depletion, depreciation and amortization	(783,357)	(704,863)
Net oil and gas properties and equipment	1,092,061	1,154,546
Total assets	1,104,555	1,174,984
CURRENT LIABILITIES:
Accounts payable	9,482	10,799
Oil, NGLs and gas sales payable	4,190	4,245
Unrealized loss on commodity derivatives	4,880
Accrued liabilities	7,817	13,464
Total current liabilities	26,369	28,508
NON-CURRENT LIABILITIES:
Senior secured credit facility, net	271,696	270,748
Senior notes, net	226,653	225,839
Deferred income taxes	5,615	31,779
Asset retirement obligations	10,607	10,143
Other non-current liabilities	663
Total liabilities	541,603	567,017
COMMITMENTS AND CONTINGENCIES (Note 8)
STOCKHOLDERS’ EQUITY :
Preferred stock, $0.01 par value, 10,000,000 shares authorized none outstanding
Common stock, $0.01 par value, 90,000,000 shares authorized, 41,764,770 and 40,788,705 issued and outstanding, respectively	418	408
Additional paid-in capital	586,095	580,623
Accumulated (deficit) earnings	(23,561)	26,936
Total stockholders’ equity	562,952	607,967
Total liabilities and stockholders’ equity	$ 1,104,555	$ 1,174,984

XML

Consolidated Balance Sheets (Parenthetical) - $ / shares	Dec. 31, 2016	Dec. 31, 2015
Statement Of Financial Position [Abstract]
Preferred stock, par value	$ 0.01	$ 0.01
Preferred stock, shares authorized	10,000,000	10,000,000
Preferred stock, shares outstanding	0	0
Common stock, par value	$ 0.01	$ 0.01
Common stock, shares authorized	90,000,000	90,000,000
Common stock, issued	41,764,770	40,788,705
Common stock, outstanding	41,764,770	40,788,705

XML

Consolidated Statements of Operations - USD ($)		12 Months Ended
		Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
REVENUES:
Oil, NGLs and gas sales		$ 90,302,000	$ 131,336,000	$ 258,529,000
EXPENSES:
Lease operating		19,250,000	28,972,000	32,701,000
Production and ad valorem taxes		8,217,000	11,085,000	15,934,000
Exploration		3,923,000	4,439,000	3,831,000
General and administrative	[1]	24,734,000	28,341,000	32,104,000
Termination costs			1,436,000
Impairment of oil and gas properties		0	220,197,000	0
Depletion, depreciation and amortization		79,044,000	109,319,000	106,802,000
Total expenses		135,168,000	403,789,000	191,372,000
OPERATING (LOSS) INCOME		(44,866,000)	(272,453,000)	67,157,000
OTHER:
Interest expense, net		(27,259,000)	(25,066,000)	(21,651,000)
Gain on debt extinguishment			10,563,000
Write-off of debt issuance costs		(563,000)
Equity in losses of investee				(181,000)
Realized gain on commodity derivatives		6,132,000	52,489,000	2,359,000
Unrealized (loss) gain on commodity derivatives		(11,616,000)	(33,214,000)	42,113,000
Other income		1,511,000	172,000	67,000
(LOSS) INCOME BEFORE INCOME TAX (BENEFIT) PROVISION		(76,661,000)	(267,509,000)	89,864,000
INCOME TAX (BENEFIT) PROVISION:
Current			(265,000)	(25,000)
Deferred		(24,418,000)	(93,140,000)	33,717,000
NET (LOSS) INCOME		$ (52,243,000)	$ (174,104,000)	$ 56,172,000
(LOSS) EARNINGS PER SHARE:
Basic		$ (1.26)	$ (4.30)	$ 1.43
Diluted		$ (1.26)	$ (4.30)	$ 1.42
WEIGHTED AVERAGE SHARES OUTSTANDING:
Basic		41,488,206	40,464,283	39,407,733
Diluted		41,488,206	40,464,283	39,419,865

[1] Includes non-cash share-based compensation expense as follows:

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Consolidated Statements of Operations (Parenthetical) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Income Statement [Abstract]
Includes non-cash share-based compensation expense	$ 6,279	$ 7,954	$ 8,247

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Consolidated Statements of Changes in Stockholders' Equity - USD ($) $ in Thousands	Total	Common Stock [Member]	Additional Paid-in Capital [Member]	Accumulated (Deficit) Earnings [Member]
Beginning balance, value at Dec. 31, 2013	$ 710,495	$ 390	$ 565,237	$ 144,868
Beginning balance, shares at Dec. 31, 2013		39,047,699
Issuance of common shares to directors for compensation, value	749	$ 1	748
Issuance of common shares to directors for compensation, shares		40,898
Restricted stock issuance, net of cancellations, value		$ 8	(8)
Restricted stock issuance, net of cancellations, shares		782,708
Share-based compensation expense	7,498		7,498
Surrender of restricted shares for payment of income taxes, value	(587)		(587)
Surrender of restricted shares for payment of income taxes, shares		(57,106)
Net (loss) income	56,172			56,172
Ending balance, value at Dec. 31, 2014	774,327	$ 399	572,888	201,040
Ending balance, shares at Dec. 31, 2014		39,814,199
Issuance of common shares to directors for compensation, value	735	$ 1	734
Issuance of common shares to directors for compensation, shares		134,783
Restricted stock issuance, net of cancellations, value		$ 8	(8)
Restricted stock issuance, net of cancellations, shares		897,285
Share-based compensation expense	7,219		7,219
Surrender of restricted shares for payment of income taxes, value	(210)		(210)
Surrender of restricted shares for payment of income taxes, shares		(57,562)
Net (loss) income	(174,104)			(174,104)
Ending balance, value at Dec. 31, 2015	607,967	$ 408	580,623	26,936
Ending balance, shares at Dec. 31, 2015		40,788,705
Cumulative effect of change in accounting principal	1,746			1,746
Issuance of common shares to directors for compensation, value	214	$ 2	212
Issuance of common shares to directors for compensation, shares		196,287
Restricted stock issuance, net of cancellations, value		$ 10	(10)
Restricted stock issuance, net of cancellations, shares		1,013,982
Share-based compensation expense	6,065		6,065
Surrender of restricted shares for payment of income taxes, value	(797)	$ (2)	(795)
Surrender of restricted shares for payment of income taxes, shares		(234,204)
Net (loss) income	(52,243)			(52,243)
Ending balance, value at Dec. 31, 2016	$ 562,952	$ 418	$ 586,095	$ (23,561)
Ending balance, shares at Dec. 31, 2016		41,764,770

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Consolidated Statements of Cash Flows - USD ($)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
OPERATING ACTIVITIES:
Net (loss) income	$ (52,243,000)	$ (174,104,000)	$ 56,172,000
Adjustments to reconcile net (loss) income to net cash provided by operating activities:
Depletion, depreciation and amortization	79,044,000	109,319,000	106,802,000
Impairment of oil and gas properties	0	220,197,000	0
Amortization of debt issuance costs	1,396,000	1,561,000	1,546,000
Gain on debt extinguishment		(10,563,000)
Write-off of debt issuance costs	563,000
Unrealized loss (gain) on commodity derivatives	11,616,000	33,214,000	(42,113,000)
Exploration expense	3,753,000	1,836,000	3,831,000
Share-based compensation expense	6,279,000	7,954,000	8,247,000
Deferred income tax (benefit) expense	(24,418,000)	(93,140,000)	33,717,000
Equity in losses of investee			181,000
Other non-cash items	(92,000)	(172,000)	(179,000)
Changes in operating assets and liabilities:
Accounts receivable	2,250,000	7,878,000	3,262,000
Prepaid expenses and other current assets	534,000	(325,000)	(179,000)
Accounts payable	358,000	964,000	(2,262,000)
Oil, NGLs and gas sales payable	(55,000)	(4,291,000)	2,435,000
Accrued liabilities	(2,904,000)	2,388,000	144,000
Cash provided by operating activities	26,081,000	102,716,000	171,604,000
INVESTING ACTIVITIES:
Additions to oil and gas properties	(19,788,000)	(151,178,000)	(390,506,000)
Proceeds from sale of equity method investment, net of contributions			(181,000)
Change in restricted cash			7,350,000
Additions to furniture, fixtures and equipment, net	(16,000)	(67,000)	(3,024,000)
Change in working capital related to investing activities	(4,086,000)	(66,102,000)	9,189,000
Cash used in investing activities	(23,890,000)	(217,347,000)	(377,172,000)
FINANCING ACTIVITIES:
Borrowings under credit facility	50,100,000	272,000,000	353,921,000
Repayment of amounts outstanding under credit facility	(50,100,000)	(149,000,000)	(203,921,000)
Extinguishment of senior notes		(8,722,000)
Tax withholdings related to restricted stock	(797,000)	(210,000)	(587,000)
Debt issuance costs	(197,000)		(2,174,000)
Change in working capital related to financing activities	(1,776,000)	731,000
Cash (used in) provided by financing activities	(2,770,000)	114,799,000	147,239,000
CHANGE IN CASH AND CASH EQUIVALENTS	(579,000)	168,000	(58,329,000)
CASH AND CASH EQUIVALENTS , beginning of year	600,000	432,000	58,761,000
CASH AND CASH EQUIVALENTS , end of year	21,000	600,000	432,000
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:
Cash paid for income taxes			404,000
Cash paid for interest	25,972,000	23,634,000	20,232,000
SUPPLEMENTAL DISCLOSURE OF NON-CASH TRANSACTION:
Acquisition of oil and gas properties			510,000
Asset retirement obligations capitalized	$ 36,000	$ 151,000	$ 898,000

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Summary of Significant Accounting Policies

12 Months Ended

Dec. 31, 2016

Accounting Policies [Abstract]

Summary of Significant Accounting Policies

1. Summary of Significant Accounting Policies

Organization and Nature of Operations

Approach Resources Inc. (“Approach,” the “Company,” “we,” “us” or “our”) is an independent energy company focused on the exploration, development, production and acquisition of unconventional oil and gas properties. We focus on finding and developing oil and natural gas reserves in oil shale and tight gas sands. Our properties are primarily located in the Permian Basin in West Texas. We also own interests in the East Texas Basin.

Consolidation, Basis of Presentation and Significant Estimates

The accompanying consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America and include the accounts of the Company and its wholly owned subsidiaries. Intercompany accounts and transactions are eliminated. In preparing the accompanying financial statements, management has made certain estimates and assumptions that affect reported amounts in the financial statements and disclosures of contingencies. Actual results may differ from those estimates. Significant assumptions are required in the valuation of proved oil and natural gas reserves, which affect our estimate of depletion expense as well as our impairment analyses. Significant assumptions also are required in our estimation of accrued liabilities, commodity derivatives, income tax provision, share-based compensation and asset retirement obligations. It is at least reasonably possible these estimates could be revised in the near term, and these revisions could be material. Certain prior-year amounts have been reclassified to conform to current-year presentation. These classifications have no impact on the net loss reported.

Cash and Cash Equivalents

We consider all highly liquid debt instruments purchased with an original maturity of three months or less to be cash equivalents. At times, the amount of cash and cash equivalents on deposit in financial institutions exceeds federally insured limits. We monitor the soundness of the financial institutions and believe the Company’s risk is negligible.

Oil and Gas Properties

Capitalized Costs.     Our oil and gas properties comprised the following (in thousands):

	December 31,
	2016			2015
Mineral interests in properties:
Unproved leasehold costs	$	33,596		$	37,853
Proved leasehold costs		44,643			44,122
Wells and related equipment and facilities		1,774,314			1,753,649
Support equipment		8,002			9,545
Uncompleted wells, equipment and facilities		9,219			8,612
Total costs		1,869,774			1,853,781
Less accumulated depreciation, depletion and    amortization		(780,412	)		(702,139	)
Net capitalized costs	$	1,089,362		$	1,151,642

We follow the successful efforts method of accounting for our oil and gas producing activities. Costs to acquire mineral interests in oil and gas properties and to drill and equip development wells and related asset retirement costs are capitalized. Costs to drill exploratory wells are capitalized pending determination of whether the wells have proved reserves. If we determine that the wells do not have proved reserves, the costs are charged to exploration expense. There were no exploratory wells capitalized, pending determination of whether the wells have proved reserves, at December 31, 2016 or 2015. Geological and geophysical costs, including seismic studies are charged to exploration expense as incurred. We capitalize interest on expenditures for significant exploration and development projects that last more than six months while activities are in progress to bring the assets to their intended use and while these expenditures are excluded from our depletable base. Through December 31, 2016, we have capitalized no interest costs because our individual wells and infrastructure projects are generally developed in less than six months. Costs incurred to maintain wells and related equipment are charged to expense as incurred.

On the sale or retirement of a complete unit of a proved property, the cost and related accumulated depreciation, depletion and amortization are eliminated from the property accounts, and the resulting gain or loss is recognized. On the retirement or sale of a partial unit of proved property, the cost is charged to accumulated depreciation, depletion and amortization with no gain or loss recognized in income.

Capitalized amounts attributable to proved oil and gas properties are depleted by the unit-of-production method over proved reserves using the unit conversion ratio of six Mcf of gas to one barrel of oil equivalent (“Boe”), and one barrel of NGLs to one Boe. The ratios of six Mcf of natural gas to one Boe and one barrel of NGLs to one Boe do not assume price equivalency and, given price differentials, the price for a Boe for natural gas may differ significantly from the price for a barrel of oil. Depreciation, depletion and amortization expense for oil and gas producing property and related equipment was $78.7 million, $108.8 million and $106.2 million for the years ended December 31, 2016, 2015 and 2014, respectively.

Capitalized costs related to proved oil and gas properties, including wells and related equipment and facilities, are periodically evaluated for impairment based on an analysis of undiscounted future net cash flows in accordance with ASC 360, Accounting for the Impairment or Disposal of Long-Lived Assets, as events or changes in circumstances indicate that the carrying values of those assets may not be recoverable. If undiscounted cash flows are insufficient to recover the net capitalized costs related to proved properties, then we recognize an impairment charge equal to the difference between the net capitalized costs related to proved properties and their estimated fair values based on the present value of the related future net cash flows. Estimating future net cash flows involves the use of judgments, including estimation of the proved and unproved oil and natural gas reserve quantities, timing of development and production, expected future commodity prices, capital expenditures and production costs. We recorded no impairment of our proved properties for the years ended December 31, 2016 and 2014. During the year ended December 31, 2015, we recognized an impairment loss of $214.7 million related primarily to our vertical Canyon wells. See Note 7 for proved property impairment disclosures.

Unproved oil and gas properties that are individually significant are periodically assessed for impairment of value, and a loss is recognized at the time of impairment by providing an impairment allowance. We recorded no impairment of our unproved properties for the years ended December 31, 2016 and 2014. Certain leases that we consider non-core to our development of Project Pangea were impaired during the year ended December 31, 2015, as we did not plan to develop them. As a result, we recorded a non-cash impairment loss of unproved property of $5.5 million for the year ended December 31, 2015.

The total impairment loss of $220.2 million for the year ended December 31, 2015, is recorded in impairment of oil and gas properties on our consolidated statements of operations, and in accumulated depletion, depreciation and amortization on our consolidated balance sheets.

On the sale of an entire interest in an unproved property for cash or cash equivalents, gain or loss on the sale is recognized, taking into consideration the amount of any recorded impairment if the property had been assessed individually. If a partial interest in an unproved property is sold, the amount received is treated as a reduction of the cost of the interest retained.

Other Property

Furniture, fixtures and equipment are carried at cost. Depreciation of furniture, fixtures and equipment is provided using the straight-line method over estimated useful lives ranging from three to 15 years. Gain or loss on retirement or sale or other disposition of assets is included in income in the period of disposition. Depreciation expense for other property and equipment was $343,000, $563,000 and $588,000 for the years ended December 31, 2016, 2015 and 2014, respectively.

Financial Instruments

The carrying amounts of financial instruments including cash and cash equivalents, accounts receivable, accounts payable and accrued liabilities approximate fair value, as of December 31, 2016 and 2015. See Note 7 for fair value disclosures.

Income Taxes

We are subject to U.S. federal income taxes along with state income taxes in Texas. When tax returns are filed, it is highly certain that some positions taken would be sustained upon examination by the taxing authorities, while others are subject to uncertainty about the merits of the position taken or the amount of the position that would be ultimately sustained. The benefit of a tax position is recognized in the financial statements in the period during which, based on all available evidence, management believes it is more likely than not that the position will be sustained upon examination, including the resolution of appeals or litigation processes, if any. Tax positions taken are not offset or aggregated with other positions. Tax positions that meet the more-likely-than-not recognition threshold are measured as the largest amount of tax benefit that is more than 50% likely of being realized upon settlement with the applicable taxing authority. The portion of the benefits associated with tax positions taken that exceeds the amount measured as described above is reflected as a liability for unrecognized tax benefits in the accompanying balance sheet along with any associated interest and penalties that would be payable to the taxing authorities upon examination. Interest and penalties associated with unrecognized tax benefits are classified as additional income taxes on the consolidated statements of operations.

Based on our analysis, we did not have any uncertain tax positions as of December 31, 2016 or 2015. The Company’s income tax returns are subject to examination by the relevant taxing authorities as follows: U.S. Federal income tax returns for tax years 2013 and forward and Texas income and margin tax returns for tax years 2013 and forward. There are currently no income tax examinations underway for these jurisdictions.

Deferred tax assets and liabilities are recognized for the estimated future tax consequences attributable to the differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are measured using the tax rate in effect for the year in which those temporary differences are expected to be recovered or settled. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in income in the year of the enacted tax rate change.

We monitor our deferred tax assets by jurisdiction to assess their potential realization, and a valuation allowance is recognized on deferred tax assets when we believe that certain of these assets are more likely than not to be realized. In performing this review, we make estimates and assumptions regarding projected future taxable income, the expected timing of reversals of existing temporary differences and the implementation of tax planning strategies. To the extent that a valuation allowance is established or changed during any period, we would recognize expense or benefit within our consolidated tax expense. We do not currently have a valuation allowance on our federal net operating loss carryforwards (“NOLs”).

Derivative Activity

We record our open derivative instruments at fair value on our consolidated balance sheets as either unrealized gains or losses on commodity derivatives. We record changes in such fair value in earnings on our consolidated statements of operations under the caption entitled “unrealized (loss) gain on commodity derivatives.”

Although we have not designated our derivative instruments as cash-flow hedges, we use those instruments to reduce our exposure to fluctuations in commodity prices related to our natural gas and oil production. Unrealized gains and losses, at fair value, are included on our consolidated balance sheets as current or non-current assets or liabilities based on the anticipated timing of cash settlements under the related contracts. Changes in the fair value of our commodity derivative contracts are recorded in earnings as they occur and included in income (expense) on our consolidated statements of operations. Realized gains and losses are also included in income (expense) on our consolidated statements of operations.

Accrued Liabilities

The following is a summary of our accrued liabilities at December 31, 2016 and 2015 (in thousands):

	2016		2015
Capital expenditures accrual	$	1,067	$	3,476
Operating expenses and other		6,750		9,988
Total	$	7,817	$	13,464

Asset Retirement Obligations

Our asset retirement obligations relate to future plugging and abandonment expenses on oil and gas properties. Based on the expected timing of payments, the full asset retirement obligation is classified as non-current. There were no significant changes to the asset retirement obligations for the years ended December 31, 2016, 2015 and 2014.

Share-Based Compensation

We measure and record compensation expense for share-based payment awards to employees and outside directors based on estimated grant date fair values. We recognize compensation costs for awards granted over the requisite service period based on the grant date fair value in general and administrative expenses on our consolidated statements of operations.

In 2016, we awarded cash-settled performance awards, subject to certain performance conditions, to our executive officers. The cash-settled performance awards represent a non-equity unit with a conversion value equal to the fair market value of a share of the Company’s common stock at the vesting date. These awards are classified as liability awards due to the cash settlement feature. Compensation costs associated with the cash-settled performance awards are re-measured at each interim reporting period and an adjustment is recorded in general and administrative expenses on our consolidated statements of operations.

Earnings Per Common Share

We report basic earnings per common share, which excludes the effect of potentially dilutive securities, and diluted earnings per common share, which includes the effect of all potentially dilutive securities unless their impact is antidilutive. The following are reconciliations of the numerators and denominators of our basic and diluted earnings per share, (dollars in thousands, except per-share amounts):

	For the Years Ended December 31,
	2016			2015			2014
Income (numerator):
Net (loss) income — basic	$	(52,243	)	$	(174,104	)	$	56,172
Weighted average shares (denominator):
Weighted average shares — basic		41,488,206			40,464,283			39,407,733
Dilution effect of share-based compensation,    treasury method (1)		—			—			12,132
Weighted average shares — diluted		41,488,206			40,464,283			39,419,865
Net (loss) income per share:
Basic	$	(1.26	)	$	(4.30	)	$	1.43
Diluted	$	(1.26	)	$	(4.30	)	$	1.42

(1) Approximately 39,000 options to purchase our common stock were excluded from this calculation because they were antidilutive for the years ended December 31, 2016 and 2015.

Oil and Gas Operations

Revenue and Accounts Receivable.     We recognize revenue for our production when the quantities are delivered to or collected by the respective purchaser. Prices for such production are defined in sales contracts and are readily determinable based on certain publicly available indices.

Accounts receivable, joint interest owners, consist of uncollateralized joint interest owner obligations due within 30 days of the invoice date. Accounts receivable, oil, NGLs and gas sales, consist of uncollateralized accrued revenues due under normal trade terms, generally requiring payment within 30 to 60 days of production. No interest is charged on past-due balances. Payments made on all accounts receivable are applied to the earliest unpaid items. We review accounts receivable periodically and reduce the carrying amount by a valuation allowance that reflects our best estimate of the amount that may not be collectible. No such allowance was considered necessary at December 31, 2016 or 2015. Accounts receivable related to oil, NGLs and gas sales includes $0.2 million and $4.8 million from realized gains on commodity derivatives at December 31, 2016 and 2015, respectively.

Oil, NGLs and Gas Sales Payable.     Oil, NGLs and gas sales payable represents amounts collected from purchasers for oil, NGLs and gas sales which are either revenues due to other revenue interest owners or severance taxes due to the respective state or local tax authorities. Generally, we are required to remit amounts due under these liabilities within 60 days of the end of the month in which the related production occurred.

Production Costs.     Production costs, including compressor rental and repair, pumpers’ and supervisors’ salaries, saltwater disposal, insurance, repairs and maintenance, expensed workovers and other operating expenses are expensed as incurred and included in lease operating expenses on our consolidated statements of operations.

Exploration expenses.     Exploration expenses include lease expirations, delay rentals, geological and geophysical costs and dry hole costs. For the year ended December 31, 2015 exploration expense includes $2.2 million related to the early termination of daywork drilling contracts.

Dependence on Major Customers.     For the year ended December 31, 2016, sales to JP Energy Development, LP (“JP Energy”) and DCP Midstream, LP (“DCP”) accounted for approximately 54% and 46%, respectively, of our total sales. As of December 31, 2016, we had dedicated all of our oil production from northern Project Pangea and Pangea West through September 2022 to JP Energy. In addition, as of December 31, 2016, we had contracted to sell all of our NGLs and natural gas production from Project Pangea to DCP through August 2023. For the year ended December 31, 2015, sales to DCP and JP Energy accounted for approximately 36% and 63%, respectively of our total sales. For the year ended December 31, 2014, sales to DCP and JP Energy accounted for approximately 30% and 69%, respectively of our total sales. We believe that there are potential alternative purchasers and that it may be necessary to establish relationships with new purchasers. However, there can be no assurance that we can establish such relationships and that those relationships will result in increased purchasers. Although we are exposed to a concentration of credit risk, we believe that all of our purchasers are credit worthy.

Segment Reporting

The Company presently operates in one business segment, the exploration and production of oil, NGLs and natural gas.

Recent Accounting Pronouncements

In May 2014, the Financial Accounting Standards Board (“FASB”) issued an accounting standards update for “Revenue from Contracts with Customers,” which supersedes the revenue recognition requirements in “Topic 605, Revenue Recognition.” This accounting standard update provides new guidance concerning recognition and measurement of revenue and requires additional disclosures about the nature, timing and uncertainty of revenue and cash flows arising from contracts with customers. This new guidance permits adoption through the use of either a full retrospective approach or a modified retrospective approach for annual reporting periods beginning on or after December 15, 2016, with early adoption not permitted. In August 2015, FASB delayed the effective date one year, making the new standard effective for interim periods and annual periods beginning after December 15, 2017. We have not determined which transition method we will use and are continuing to evaluate our existing revenue recognition policies to determine whether any of our contracts will be affected by the new requirements. This evaluation will continue throughout 2017, and we are currently planning to adopt this new standard in the first quarter of 2018.

In September 2015, FASB issued an accounting standards update for “Business Combinations,” which requires that an acquirer recognize adjustments to provisional amounts that are identified during the measurement period in the reporting period in which the adjustment amounts are determined. We adopted this new guidance prospectively in the first quarter of 2016. This new guidance did not have a significant impact on the consolidated financial statements.

In February 2016, FASB issued an accounting standards update for “Leases,” which amends existing guidance to require lessees to recognize assets and liabilities on the balance sheet for the rights and obligations created by long-term leases and to disclose additional quantitative and qualitative information about leasing arrangements. This new guidance is effective for interim and annual periods beginning after December 15, 2018, and we will adopt it using a modified retrospective approach. The Company is evaluating the impact of this new guidance on its consolidated financial statements.

In March 2016, FASB issued an accounting standards update for “Compensation — Stock Compensation,” which amends existing guidance related to the accounting for forfeitures, employer tax withholding on share-based compensation and financial statement presentation of excess tax benefits or deficiencies.  This standard is effective for interim and annual reporting periods beginning after December 15, 2016, with early adoption permitted. We applied this standard using a modified retrospective approach. We have elected to (i) recognize forfeitures of share-based compensation as they occur, (ii) permit tax withholdings in excess of the minimum statutory requirements and (iii) recognize previously un-recognized excess tax benefits related to share-based compensation in the current year.  As a result, we have recognized an increase in accumulated earnings in the current year of $1.7 million related to the change in accounting principal as of January 1, 2016.  Adoption of this guidance did not impact our consolidated statements of operations or cash flows.

In January 2017, the FASB issued an accounting standards update for “Clarifying the Definition of a Business,” which provides guidance to assist entities with evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. This standard requires entities to use a screen test to determine when an integrated set of assets and activities is not a business or if the integrated set of assets and activities needs to be further evaluated against the framework. This standard is effective for interim and annual reporting periods beginning after December 15, 2016. The Company is evaluating the impact of this new guidance on its consolidated financial statements.

F-1

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Exchange Transactions

12 Months Ended

Dec. 31, 2016

Exchange Transactions [Abstract]

Exchange Transactions

2. Exchange Transactions

On November 2, 2016, we entered into an exchange agreement with the largest holder of our 7% Senior Notes due 2021 (the “Senior Notes”) to exchange $130,552,000 principal amount of our Senior Notes for 39,165,600 newly issued shares of common stock, par value $0.01 per share (the “Initial Exchange”). 

On January 26, 2017, our stockholders approved the Initial Exchange and an increase in our authorized common stock from 90 million shares to 180 million shares.  We closed the Initial Exchange on January 27, 2017, and paid $1.1 million of accrued interest on the Senior Notes held by the exchanging noteholder. In connection with the Initial Exchange, a second supplemental indenture became effective, which removed certain covenants and events of default from the indenture governing our Senior Notes, and eliminated certain restrictive covenants discussed in Note 3. As of December 31, 2016, we have incurred approximately $2.1 million in costs related to the Initial Exchange, which are recorded in prepaid expenses and other current assets.

On January 30, 2017, we offered to exchange our remaining$99,768,000principal amount of outstanding Senior Notes for shares of our common stock at a ratio of 276 shares of common stock per $1,000 principal amount of our Senior Notes (the “Follow-On Exchange”). There are no minimum subscription requirements for the Follow-On Exchange, and we cannot predict participation levels.

Depending on the participation levels in the Follow-On Exchange, we may further reduce our long-term debt. Additionally, use of our federal NOLs may be limited as a result of the Follow-On Exchange.

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Long-Term Debt

12 Months Ended

Dec. 31, 2016

Debt Disclosure [Abstract]

Long-Term Debt

3. Long-Term Debt

The following table provides a summary of our long-term debt at December 31, 2016, and December 31, 2015 (in thousands).

	December 31, 2016			December 31, 2015
Senior secured credit facility:
Outstanding borrowings	$	273,000		$	273,000
Debt issuance costs		(1,304	)		(2,252	)
Senior secured credit facility, net		271,696			270,748
Senior notes:
Principal		230,320			230,320
Debt issuance costs		(3,667	)		(4,481	)
Senior notes, net		226,653			225,839
Total long-term debt	$	498,349		$	496,587

Senior Secured Credit Facility

At December 31, 2016, the borrowing base and aggregate lender commitments under our amended and restated senior secured credit facility (the “Credit Facility”) were $325 million, with maximum commitments from the lenders of $1 billion. The Credit Facility has a maturity date of May 7, 2019. The borrowing base is redetermined semi-annually based on our oil, NGLs and gas reserves. We, or the lenders, can each request one additional borrowing base redetermination each calendar year.

Borrowings under the Credit Facility bear interest based on the agent bank’s prime rate plus an applicable margin ranging from 1.50% to 2.50%, or the sum of the LIBOR rate plus an applicable margin ranging from 2.50% to 3.50%. In addition, we pay an annual commitment fee of 0.50% of unused borrowings available under the Credit Facility. Margins vary based on the borrowings outstanding compared to the borrowing base of the lenders.

We had $273 million of outstanding borrowings under the Credit Facility at December 31, 2016 and 2015. The weighted average interest rate applicable to borrowings under the Credit Facility in 2016 was 3.3%. We also had outstanding unused letters of credit under our Credit Facility totaling $0.6 million at December 31, 2016, compared to $0.3 million at December 31, 2015, which reduce amounts available for borrowing under the Credit Facility.

Obligations under the Credit Facility are secured by mortgages on substantially all of the oil and gas properties of the Company and its subsidiaries. The Company is required to grant liens in favor of the lenders covering the oil and gas properties of the Company and its subsidiaries representing at least 90% of the total value of all oil and gas properties of the Company and its subsidiaries.

On May 3, 2016, we entered into a third amendment to the Credit Facility. The third amendment, among other things, (a) decreased the borrowing base to $325 million from $450 million, (b) revised the Company’s permitted ratio of EBITDAX (as defined in the Credit Facility) to cash Interest Expense (as defined in the Credit Facility) to 1.25 to 1.0 (or 1.0 to 1.0 following the issuance of second lien indebtedness), through December 31, 2017, 1.5 to 1.0 through December 31, 2018, and 2.0 to 1.0 thereafter; (c) increased the applicable margin rates on borrowings by 100 basis points, (d) permits the Company to issue up to $150 million of second lien indebtedness, subject to various conditions and limitations, (e) permits the Company to repurchase outstanding debt with proceeds of certain asset sales, equity issuances or second lien indebtedness, and (f) requires cash and cash equivalents in excess of $35 million held by the Company to be applied to reduce outstanding borrowings under the Credit Facility. In connection with the third amendment to the Credit Facility, $0.6 million of debt issuance costs were written off as a result of the reduction in the borrowing base, and we incurred $0.2 million of debt issuance costs.

Covenants

The Credit Facility contains two principal financial covenants:

• a consolidated interest coverage ratio covenant (as defined in the Credit Facility) that requires us to maintain a ratio of consolidated EBITDAX to cash Interest Expense (as defined in the Credit Facility) as of the last day of any fiscal quarter of not less than 1.25 to 1.0 (or 1.0 to 1.0 following the issuance of second lien indebtedness) through December 31, 2017, a ratio of not less than 1.5 to 1.0 through December 31, 2018, and a ratio of not less than 2.0 to 1.0 thereafter, and

• a consolidated modified current ratio covenant (as defined in the Credit Facility) that requires us to maintain a ratio of not less than 1.0 to 1.0 as of the last day of any fiscal quarter.

The Credit Facility also contains covenants restricting cash distributions and other restricted payments, transactions with affiliates, incurrence of other debt, consolidations and mergers, the level of operating leases, asset sales, investment in other entities and liens on properties.

In addition, the obligations of the Company may be accelerated upon the occurrence of an Event of Default (as defined in the Credit Facility). Events of Default include customary events for a financing agreement of this type, including, without limitation, payment defaults, the inaccuracy of representations and warranties, defaults in the performance of affirmative or negative covenants, defaults on other indebtedness of the Company or its subsidiaries, bankruptcy or related defaults, defaults related to judgments and the occurrence of a Change of Control (as defined in the Credit Facility), which includes instances where a third party becomes the beneficial owner of more than 50% of the Company’s outstanding equity interests entitled to vote.

Senior Notes

In June 2013, we completed our public offering of $250 million principal amount of 7% Senior Notes due 2021 (the “Senior Notes”). Annual interest on the Senior Notes is payable semi-annually on June 15 and December 15. On December 15, 2016, we made a semi-annual interest payment of $8.1 million. We received net proceeds from the issuance of the Senior Notes of approximately $243 million, after deducting fees and expenses. We used a portion of the net proceeds from the offering to repay all outstanding borrowings under the Credit Facility, fund our capital expenditures for the development of our Wolfcamp shale oil resource play and for general working capital needs.

During the year ended December 31, 2015, we repurchased Senior Notes in the open market with an aggregate face value of $19.7 million for a purchase price of $8.8 million, including accrued interest. This resulted in a gain on extinguishment of debt of $10.6 million.

On November 2, 2016, we entered into the Initial Exchange. In January 2017, we closed the Initial Exchange and launched the Follow-On Exchange. The Initial Exchange reduced our Senior Notes outstanding by $130.6 million and will result in future interest savings of approximately $40 million. The Follow-On Exchange, if closed, is expected to further reduce our debt and improve our operating cash flow through the reduction of interest expense.

We issued the Senior Notes under a senior indenture dated June 11, 2013, among the Company, our subsidiary guarantors and Wilmington Trust, National Association, as successor trustee. The senior indenture, as supplemented by a supplemental indenture dated June 11, 2013, is referred to as the “Indenture.”

On December 20, 2016, we entered into the second supplemental indenture (the “Second Supplemental Indenture”), which became effective in connection with the closing of the Initial Exchange. The Second Supplemental Indenture (i) eliminated certain definitions and references to definitions contained in the Indenture; (ii) eliminated and revised, as applicable, certain events of default contained in the Indenture; (iii) eliminated certain conditions to consolidation, merger, conveyance, transfer or lease contained in the Indenture; (iv) eliminated certain covenants contained in the Indenture, including substantially all of the restrictive covenants set forth therein; and (v) supplemented and amended the Senior Notes and the securities guarantees, as and to the same extent as the Indenture has been amended and supplemented in accordance with the preceding clauses (i), (ii), (iii) and (iv).

We may redeem some or all of the Senior Notes at specified redemption prices, plus accrued and unpaid interest to the redemption date. The Senior Notes are fully and unconditionally guaranteed on a senior unsecured basis by each of our subsidiaries, subject to certain customary release provisions. A subsidiary guarantor may be released from its obligations under the guarantee:

• in connection with any sale or other disposition of all or substantially all of the assets of that guarantor (including by way of merger or consolidation) to a person that is not (either before or after giving effect to such transaction) the Company or a subsidiary guarantor, if the sale or other disposition otherwise complies with the Indenture;

• in connection with any sale or other disposition of the capital stock of that guarantor to a person that is not (either before or after giving effect to such transaction) the Company or a subsidiary guarantor, if that guarantor no longer qualifies as a subsidiary of the Company as a result of such disposition and the sale or other disposition otherwise complies with the Indenture;

• if the Company designates any restricted subsidiary that is a guarantor to be an unrestricted subsidiary in accordance with the Indenture;

• upon defeasance or covenant defeasance of the notes or satisfaction and discharge of the indenture, in each case, in accordance with the Indenture;

• upon the liquidation or dissolution of that guarantor, provided that no default or event of default occurs under the indenture as a result thereof or shall have occurred and is continuing; or

• in the case of any restricted subsidiary that, after the issue date of the notes is required under the indenture to guarantee the notes because it becomes a guarantor of indebtedness issued or an obligor under the revolving credit facility with respect to the Company and/or its subsidiaries, upon the release or discharge in full from its (i) guarantee of such indebtedness or (ii) obligation under such revolving credit facility, in each case, which resulted in such restricted subsidiary’s obligation to guarantee the notes.

As a result of the Second Supplemental Indenture, the Indenture contains limited events of default.

Subsidiary Guarantors

The Senior Notes are guaranteed on a senior unsecured basis by each of our consolidated subsidiaries. Approach Resources Inc. is a holding company with no independent assets or operations. The subsidiary guarantees are full and unconditional and joint and several, and any subsidiaries of the Company other than the subsidiary guarantors are minor. There are no significant restrictions on the Company’s ability, or the ability of any subsidiary guarantor, to obtain funds from its subsidiaries through dividends, loans, advances or otherwise.

At December 31, 2016, we were in compliance with all of our covenants, and there were no existing defaults or events of default, under our debt instruments.

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Termination Costs

12 Months Ended

Dec. 31, 2016

Restructuring And Related Activities [Abstract]

Termination Costs

4. Termination Costs

In September 2015, we reduced our workforce to decrease costs and better align our workforce with the needs of the business and oil and gas prices. In connection with the reduction, we incurred $1.4 million in expenses, which was recorded in termination costs on our consolidated statements of operations. As of December 31, 2016, $0.3 million in termination costs is recorded in current liabilities on our consolidated balance sheets. We also recorded a benefit of $0.3 million in share-based compensation expense related to the forfeiture of unvested shares of restricted stock in connection with our workforce reduction, which was recorded in general and administrative expense on our consolidated statements of operations.

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Share-Based Compensation

12 Months Ended

Dec. 31, 2016

Disclosure Of Compensation Related Costs Sharebased Payments [Abstract]

Share-Based Compensation

5. Share-Based Compensation

In June 2007, our board of directors and stockholders approved the 2007 Stock Incentive Plan (the “2007 Plan”). Under the 2007 Plan, we may grant restricted stock, stock options, stock appreciation rights, restricted stock units, performance awards, unrestricted stock awards and other incentive awards. Under a Fifth Amendment to the 2007 Plan effective June 2, 2016, the maximum number of shares of common stock available for the grant of awards under the 2007 Plan after June 2, 2016, is 6,125,000. Awards of any stock options are to be priced at not less than the fair market value at the date of the grant. We use (i) the closing stock price on the date of grant for the fair value of restricted stock awards, including performance-based awards, (ii) the Monte Carlo simulation method for the fair value of market-based awards, (iii) the fair market value of our common stock on the valuation date for cash-settled performance awards and (iv) the Black-Scholes option price model to measure the fair value of stock options. The vesting period of any stock award is to be determined by the board or an authorized committee at the time of the grant.

Share-based compensation expense amounted to $6.3 million, $8 million and $8.2 million for the years ended December 31, 2016, 2015 and 2014, respectively. Such amounts represent the estimated fair value of stock awards for which the requisite service period elapsed during those periods. Included in share-based compensation expense in 2014 was a benefit of $1.1 million for forfeited stock awards related to the retirement of one of our executive officers. Share-based compensation expense for the years ended December 31, 2016, 2015 and 2014, included $214,000, $735,000 and $749,000, respectively, related to grants to non-employee directors.

Stock Options

There were no stock option grants during the years ended December 31, 2016, 2015 and 2014. As of December 31, 2016, 38,525 options were fully vested and outstanding with a weighted average exercise price of $12.00 and a weighted average remaining contractual term of 0.85 years. There were no options exercised during the years ended December 31, 2016, 2015 and 2014.

Nonvested Shares

Share grants totaling 1,318,229 shares, 1,278,329 shares and 992,919 shares with an approximate aggregate fair market value of $2.5 million, $6.2 million and $14.4 million, based on the closing price of our common stock on the date of grant, were granted to employees and non-employee directors during the years ended December 31, 2016, 2015 and 2014, respectively. Included in the share grants for 2016, 2015 and 2014, are 550,272 shares, 724,249 shares and 245,157 shares, respectively, awarded to our executive officers. The aggregate fair market value of these shares on the grant date was $0.3 million, $4.5 million and $4.5 million, respectively, to be expensed over a service period of approximately three years, subject to certain performance restrictions. The share grants for executive officers noted above does not include the cash-settled performance awards, which are discussed in more detail below.

A summary of the status of nonvested shares for the years ended December 31, 2016, 2015 and 2014, is presented below:

	Shares			Weighted Average Grant-Date Fair Value
Nonvested at January 1, 2014		699,231		$	23.70
Granted		992,919			14.48
Vested		(400,429	)		20.18
Canceled		(169,311	)		25.57
Nonvested at December 31, 2014		1,122,410		$	16.52
Granted		1,278,329			4.87
Vested		(419,222	)		15.26
Canceled		(246,261	)		14.30
Nonvested at December 31, 2015		1,735,256		$	8.60
Granted		1,318,229			1.90
Vested		(992,461	)		7.03
Canceled		(107,960	)		17.33
Nonvested at December 31, 2016		1,953,064		$	4.39

As of December 31, 2016, unrecognized compensation expense related to the nonvested shares amounted to $4 million, which will be recognized over a remaining service period of two years.

Cash-settled performance awards

In 2016, in addition to the share grants discussed above, we awarded 1,100,543 cash-settled performance awards, subject to certain performance conditions, to our executive officers. The aggregate fair market value of the cash-settled shares on the grant date was approximately $1 million, to be expensed over a remaining service period of approximately three years, subject to performance conditions.

The cash-settled performance awards represent a non-equity unit with a conversion value equal to the fair market value of a share of the Company’s common stock at the vesting date. These awards are classified as liability awards due to the cash settlement feature. Compensation costs associated with the cash-settled performance awards are re-measured, based on the fair market value of our common stock, at each interim reporting period and an adjustment is recorded in general and administrative expenses on our consolidated statements of operations. For the year ended December 31, 2016, we recognized $1.3 million in expense related to the cash-settled performance awards, recorded as a current liability of $0.6 million and a non-current liability of $0.7 million on our consolidated balance sheet.

Subsequent Restricted Share Award

Subsequent to December 31, 2016, 1,443,256 restricted shares were awarded to our executive officers, of which 962,171 shares are subject to certain performance conditions and 481,085 shares are subject to three-year total shareholder return (“TSR”) conditions, assuming maximum TSR. The aggregate fair market value of the shares on the grant date was approximately $2.9 million, to be expensed over a remaining service period of approximately three years.

Employee Benefit Plan

The Company has a defined contribution employee benefit plan covering substantially all of its employees. We make a matching contribution equal to 100% of each pre-tax dollar contributed by the participant on the first 3% of eligible compensation and 50% on the next 2% of eligible compensation. The Company made contributions to the plan of approximately $338,000, $404,000 and $310,000 during the years ended December 31, 2016, 2015 and 2014, respectively.

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Income Taxes

12 Months Ended

Dec. 31, 2016

Income Tax Disclosure [Abstract]

Income Taxes

6. Income Taxes

Our provision for income taxes comprised the following (in thousands):

	Years Ended December 31,
	2016			2015			2014
Current:
Federal	$	—		$	(265	)	$	(25	)
State		—			—			—
Total current provision for income taxes	$	—		$	(265	)	$	(25	)
Deferred:
Federal	$	(24,957	)	$	(91,716	)	$	32,754
State		539			(1,424	)		963
Total deferred provision for income taxes	$	(24,418	)	$	(93,140	)	$	33,717

Total income tax expense differed from the amounts computed by applying the U.S. Federal statutory tax rates to pre-tax income (in thousands):

	Years Ended December 31,
	2016			2015			2014
Statutory tax at 35%	$	(26,831	)	$	(93,628	)	$	31,452
State taxes, net of federal impact		578			(1,463	)		989
Share-based compensation tax shortfall		1,826			1,939			1,670
Permanent differences		11			26			37
Other differences		(2	)		(1,035	)		(456	)
Valuation allowance		—			756			—
Total	$	(24,418	)	$	(93,405	)	$	33,692

In 2016, 2015 and 2014, the Company recorded a tax shortfall related to share-based compensation of $1.8 million, $1.9 million and $1.7 million, respectively. This shortfall is for grants in which the realized tax deduction was less than the expense booked for these grants due to a decline in share price from the time of grant.

In 2016, we early adopted accounting standards update for “Compensation — Stock Compensation.” As a result, we have recognized an increase in accumulated earnings and our NOLs in the current year of $1.7 million related to the change in accounting principal as of January 1, 2016.  

Deferred tax assets and liabilities are the result of temporary differences between the financial statement carrying values and tax basis of assets and liabilities. Our net deferred tax assets and liabilities are recorded as a long-term liability of $5.6 million and $31.8 million at December 31, 2016 and 2015, respectively.

Significant components of net deferred tax assets and liabilities are (in thousands):

	Years Ended December 31,
	2016			2015
Deferred tax assets:
Net operating loss carryforwards	$	155,018		$	88,230
Unrealized loss on commodity derivatives		1,732			—
Other		892			1,672
Total deferred tax assets		157,642			89,902
Deferred tax liabilities:
Difference in depreciation, depletion and    capitalization methods — oil and gas properties		(162,501	)		(118,534	)
Unrealized gain on commodity derivatives		—			(2,391	)
Total deferred tax liabilities		(162,501	)		(120,925	)
Valuation allowance		(756	)		(756	)
Net deferred tax liability	$	(5,615	)	$	(31,779	)

Our NOLs have the following expiration dates (in thousands):

Expiration Dates	Amounts
2030	$	5,790
2031		19,686
2032		54,714
2033		78
2034		56,505
2035		116,482
2036		189,649
Total	$	442,904

A change in ownership of our common stock by more than 50% within a three-year period would result in a substantial portion of our NOLs being eliminated or becoming restricted, and we would need to reduce our deferred tax assets to reflect the restricted use of these NOLs when such an ownership change occurs. An ownership change would establish an annual limitation on the amount of our pre-change NOLs that we could use to offset our taxable income in any future taxable year to an amount generally equal to the value of our common stock immediately before the ownership change, multiplied by the federal long-term tax exempt rate for the month of the ownership change. We do not believe that the Initial Exchange resulted in a change of ownership of 50% or more of common stock over the applicable period; however, the Follow-On Exchange may result in such an ownership change. If such an ownership change occurs, use of our NOLs as of December 31, 2016 could be limited.

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Derivative Instruments and Fair Value Measurements

12 Months Ended

Dec. 31, 2016

Derivative Instruments And Hedging Activities Disclosure [Abstract]

Derivative Instruments and Fair Value Measurements

7. Derivative Instruments and Fair Value Measurements

At December 31, 2016, we had the following commodity derivatives positions outstanding:

Commodity and Period	Contract Type	Volume Transacted	Contract Price
Natural Gas
January 2017 — March 2017	Swap	100,000 MMBtu/month	$2.463/MMBtu
January 2017 — March 2017	Swap	300,000 MMBtu/month	$2.45/MMBtu
January 2017 — March 2017	Swap	200,000 MMBtu/month	$3.287/MMBtu
January 2017 — December 2017	Collar	100,000 MMBtu/month	$3.00/MMBtu - $3.65/MMBtu
April 2017 — December 2017	Collar	200,000 MMBtu/month	$2.30/MMBtu - $2.60/MMBtu
April 2017 — December 2017	Collar	200,000 MMBtu/month	$3.00/MMBtu - $3.44/MMBtu
April 2017 — December 2017	Collar	200,000 MMBtu/month	$3.00/MMBtu - $3.50/MMBtu

After December 31, 2016, we entered into the following commodity derivative positions:

Commodity and Period	Contract Type	Volume Transacted	Contract Price
Natural Gas
January 2018 — December 2018	Swap	200,000 MMBtu/month	$3.085/MMBtu
January 2018 — December 2018	Swap	250,000 MMBtu/month	$3.084/MMBtu
NGLs (C2 - Ethane)
February 2017 — December 2017	Swap	1,050 Bbls/day	$11.34/Bbl
NGLs (C3 - Propane)
February 2017 — December 2017	Swap	750 Bbls/day	$27.916/Bbl
NGLs (IC4 - Isobutane)
February 2017 — December 2017	Swap	75 Bbls/day	$36.7325/Bbl
NGLs (NC4 - Butane)
February 2017 — December 2017	Swap	250 Bbls/day	$35.9205/Bbl

The following summarizes the fair value of our open commodity derivatives as of December 31, 2016 and 2015 (in thousands):

	Balance Sheet Location	Fair Value
		December 31, 2016			December 31, 2015
Derivatives not designated as hedging    instruments
Commodity derivatives	Unrealized (loss) gain on    commodity derivatives	$	(4,880	)	$	6,737

The following summarizes the change in the fair value of our commodity derivatives (in thousands):

	Income Statement Location
		Year Ended December 31,
		2016			2015			2014
Derivatives not designated as hedging    instruments
Commodity derivatives	Unrealized (loss) gain on    commodity derivatives	$	(11,616	)	$	(33,214	)	$	42,113
	Realized gain on    commodity derivatives		6,132			52,489			2,359
		$	(5,484	)	$	19,275		$	44,472

Unrealized gains and losses, at fair value, are included on our consolidated balance sheets as current or non-current assets or liabilities based on the anticipated timing of cash settlements under the related contracts. Changes in the fair value of our commodity derivative contracts are recorded in earnings as they occur and included in income (expense) on our consolidated statements of operations. We estimate the fair value of swap contracts based on the present value of the difference in exchange-quoted forward price curves and contractual settlement prices multiplied by notional quantities. We internally valued the option contracts using industry-standard option pricing models and observable market inputs. We use our internal valuations to determine the fair values of the contracts that are reflected on our consolidated balance sheets. Realized gains and losses are also included in income (expense) on our consolidated statements of operations.

We are exposed to credit losses in the event of nonperformance by the counterparties on our commodity derivatives positions and have considered the exposure in our internal valuations. However, we do not anticipate nonperformance by the counterparties over the term of the commodity derivatives positions.

To estimate the fair value of our commodity derivatives positions, we use market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated or generally unobservable. We primarily apply the market approach for recurring fair value measurements and attempt to use the best available information. We determine the fair value based upon the hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and lowest priority to unobservable inputs (Level 3 measurement). The three levels of fair value hierarchy are as follows:

• Level 1 — Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. At December 31, 2016, we had no Level 1 measurements.

• Level 2 — Pricing inputs are other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reporting date. Level 2 includes those financial instruments that are valued using models or other valuation methodologies. These models are primarily industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Our derivatives, which consist primarily of commodity swaps and collars, are valued using commodity market data which is derived by combining raw inputs and quantitative models and processes to generate forward curves. Where observable inputs are available, directly or indirectly, for substantially the full term of the asset or liability, the instrument is categorized in Level 2. At December 31, 2016, all of our commodity derivatives were valued using Level 2 measurements.

• Level 3 — Pricing inputs include significant inputs that are generally less observable from objective sources. These inputs may be used with internally developed methodologies that result in management’s best estimate of fair value. The fair value of oil and gas properties used in estimating our recognized impairment loss in 2015 represents a nonrecurring Level 3 measurement. At December 31, 2016, we had no Level 3 measurements.

Nonrecurring Fair Value Measurements

We recorded no impairment of our proved properties for the year ended December 31, 2016. Due to the impact of the decline in forward commodity prices during the year ended December 31, 2015, there were indications that the carrying values of certain of our oil and gas properties may be impaired and undiscounted cash flows attributable to these assets indicated their carrying amounts were not expected to be recovered. For the year ended December 31, 2015, we recognized an impairment loss of $214.7 million related primarily to our vertical Canyon wells, due to the impact of the decline in forward commodity prices. At September 30, 2015, we had $22 million in value recorded for these properties, which was the estimated fair value. We estimated the fair value of the proved oil and gas properties and equipment using a discounted cash flow model, which is a Level 3 fair value measurement. Significant inputs used to determine the fair value include estimates of (i) future sales prices for oil and gas based on NYMEX strip prices, (ii) pricing adjustments for differentials, (iii) production costs, (iv) capital expenditures, (v) future oil and gas reserves to be recovered and the timing thereof, and (vi) discount rates.

Financial Instruments Not Recorded at Fair Value

The following table sets forth the fair values of financial instruments that are not recorded at fair value on our financial statements (in thousands).

	December 31, 2016
	Carrying Amount		Fair Value
Senior Notes, net	$	226,653	$	206,286

The fair value of the Senior Notes is based on quoted market prices, but the Senior Notes are not actively traded in the public market. Accordingly, the fair value of the Senior Notes would be classified as Level 2 in the fair value hierarchy.

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Commitments and Contingencies

12 Months Ended

Dec. 31, 2016

Commitments And Contingencies Disclosure [Abstract]

Commitments and Contingencies

8. Commitments and Contingencies

At December 31, 2016, we had outstanding employment agreements with all four of our executive officers that contained automatic renewal provisions providing that such agreements may be automatically renewed for successive terms of one year unless the employment is terminated at the end of the term by written notice given to the employee not less than 60 days prior to the end of such term. Our maximum commitment under the employment agreements, which would apply if the employees covered by these agreements were each terminated without cause, resigned for good reason, or received a notice of non-renewal was approximately $5.7 million at December 31, 2016. This estimate assumes the maximum potential bonus for 2017 is earned by each executive officer during 2017. In 2017, we amended the employment agreements with two of our executive officers, which among other things, increased the maximum commitment under the employment agreements, which would apply if the employees covered by these agreements were each terminated without cause, by approximately $0.6 million.

In 2016, we recorded a contractual settlement of $1.4 million, which is recorded in other income on our consolidated statements of operations.

We lease our office space in Fort Worth, Texas, under a non-cancelable agreement that expires on March 31, 2020. In January 2017, we amended our lease to reduce the aggregate leased space by approximately 5,500 square feet and extended the term to September 30, 2021. This amendment reduced our contractual obligations by approximately $0.4 million during the next three years, while increasing our total contractual obligations by $0.9 million over the extended term of the lease.

We also have non-cancelable operating lease commitments related to office equipment that expire by 2021. The following is a schedule by years of future minimum rental payments required under our operating lease arrangements as of December 31, 2016 (in thousands):

2017	$	989
2018		979
2019		980
2020		248
2021		2
Total	$	3,198

Rent expense under our lease arrangements amounted to $1,025,000, $1,002,000 and $717,000 for the years ended December 31, 2016, 2015 and 2014, respectively.

Litigation

We are involved in various legal and regulatory proceedings arising in the normal course of business. While we cannot predict the outcome of these proceedings with certainty, we do not believe that an adverse result in any pending legal or regulatory proceeding, individually or in the aggregate, would be material to our consolidated financial condition or cash flows.

In 2016, we received $1.1 million from a service provider in a legal settlement, which reduced our current liabilities on our consolidated balance sheets and is recorded as a reduction in additions to oil and gas properties on our consolidated statements of cash flows.

Environmental Issues

We are engaged in oil and gas exploration and production and may become subject to certain liabilities or damages as they relate to environmental clean up of well sites or other environmental restoration or ground water contamination, in connection with drilling or operating oil and gas wells. In connection with our acquisition of existing or previously drilled well bores, we may not be aware of what environmental safeguards were taken at the time such wells were drilled or during such time the wells were operated. Should it be determined that a liability exists with respect to any environmental clean up, restoration or contamination, we would be responsible for curing such a violation or paying damages. No claim has been made, nor are we aware of any liability that exists, as it relates to any environmental clean up, restoration, contamination or the violation of any rules or regulations relating thereto.

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Oil and Gas Producing Activities

12 Months Ended

Dec. 31, 2016

Extractive Industries [Abstract]

Oil and Gas Producing Activities

9. Oil and Gas Producing Activities

Set forth below is certain information regarding the costs incurred for oil and gas property acquisition, development and exploration activities (in thousands):

	For the Years Ended December 31,
	2016		2015		2014
Property acquisition costs:
Unproved properties	$	17	$	653	$	4,578
Proved properties		—		—		—
Exploration costs		3,923		4,439		3,831
Development costs(1)		15,884		146,237		382,995
Total costs incurred	$	19,824	$	151,329	$	391,404

(1) For the years ended December 31, 2016, 2015 and 2014, development costs included $36,000, $151,000 and $898,000, respectively, in non-cash asset retirement obligations.

Set forth below is certain information regarding the results of operations for oil and gas producing activities (in thousands):

	For the Years Ended December 31,
	2016			2015			2014
Revenues	$	90,302		$	131,336		$	258,529
Production costs		(27,467	)		(40,057	)		(48,635	)
Exploration expense		(3,923	)		(4,439	)		(3,831	)
Depletion		(79,044	)		(109,319	)		(106,802	)
Impairment of oil and gas properties		—			(220,197	)		—
Income tax benefit (expense)		7,144			86,120			(35,387	)
Results of operations	$	(12,988	)	$	(156,556	)	$	63,874

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Disclosures About Oil and Gas Producing Activities (unaudited)

12 Months Ended

Dec. 31, 2016

Extractive Industries [Abstract]

Disclosures About Oil and Gas Producing Activities (unaudited)

10. Disclosures About Oil and Gas Producing Activities (unaudited)

Proved Reserves

All of our estimated oil and natural gas reserves are attributable to properties within the United States, primarily in the Permian Basin in West Texas. The estimates of proved reserves and related valuations for the years ended December 31, 2016, 2015 and 2014, were prepared by DeGolyer and MacNaughton, independent petroleum engineers. Each year’s estimate of proved reserves and related valuations were also prepared in accordance with then-current rules and guidelines established by the Securities and Exchange Commission and the Financial Accounting Standards Board.

The following table summarizes the prices used in the reserve estimates for 2016, 2015 and 2014. Commodity prices used for the reserve estimates, adjusted for basis differentials, grade and quality, are as follows:

	2016		2015		2014
Oil (per Bbl)	$	42.69	$	50.16	$	94.56
Natural gas liquids (per Bbl)	$	14.12	$	15.13	$	31.50
Gas (per Mcf)	$	2.47	$	2.64	$	4.55

Oil, NGLs and natural gas reserve estimates are subject to numerous uncertainties inherent in the estimation of quantities of proved reserves and in the projection of future rates of production and the timing of development expenditures. The accuracy of such estimates is a function of the quality of available data and of engineering and geological interpretation and judgment. Results of subsequent drilling, testing and production may cause either upward or downward revision of previous estimates. Further, the volumes considered to be commercially recoverable fluctuate with changes in prices and operating costs. The Company emphasizes that reserve estimates are inherently imprecise and that estimates of new discoveries are more imprecise than those of currently producing oil and natural gas properties. Accordingly, these estimates are expected to change as additional information becomes available in the future.

The following table provides a summary of the changes of the total proved reserves for the years ended December 31, 2016, 2015 and 2014, as well as proved developed and proved undeveloped reserves at the beginning and end of each respective year.

Total Proved Reserves	Oil (MBbls)			NGLs (MBbls)			Natural Gas (MMcf)			Total (MBoe)
Balance — January 1, 2014		46,067			32,593			216,002			114,661
Extensions and discoveries		19,347			10,658			79,454			43,247
Production(1)		(2,024	)		(1,461	)		(10,773	)		(5,281	)
Revisions to previous estimates		(8,052	)		(883	)		15,337			(6,379	)
Balance — December 31, 2014		55,338			40,907			300,020			146,248
Extensions and discoveries		11,054			10,630			79,268			34,895
Production(1)		(1,882	)		(1,694	)		(13,262	)		(5,787	)
Revisions to previous estimates		(10,014	)		(357	)		9,962			(8,710	)
Balance — December 31, 2015		54,496			49,486			375,988			166,646
Extensions and discoveries		6,529			4,564			33,347			16,651
Production(1)		(1,275	)		(1,529	)		(11,734	)		(4,759	)
Revisions to previous estimates		(9,719	)		(4,887	)		(45,324	)		(22,161	)
Balance — December 31, 2016		50,031			47,634			352,277			156,377

(1) Production included 1,390 MMcf, 1,530 MMcf and 1,330 MMcf related to field fuel in 2014, 2015 and 2016, respectively.

Total Proved Reserves	Oil (MBbls)		NGLs (MBbls)		Natural Gas (MMcf)		Total (MBoe)
Proved Developed Reserves:
January 1, 2014		13,646		14,919		99,742		45,189
December 31, 2014		17,978		19,082		138,961		60,220
December 31, 2015		15,667		20,414		154,652		61,856
December 31, 2016		13,466		20,375		150,208		58,875
Proved Undeveloped Reserves:
January 1, 2014		32,421		17,674		116,260		69,472
December 31, 2014		37,360		21,825		161,059		86,028
December 31, 2015		38,829		29,072		221,335		104,790
December 31, 2016		36,565		27,259		202,069		97,502

The following is a discussion of the material changes in our proved reserve quantities for the years ended December 31, 2016, 2015 and 2014:

Year Ended December 31, 2016

Extensions and discoveries for 2016 were 16.7 MMBoe, primarily attributable to our development project in the Wolfcamp shale oil resource play in the Permian Basin. During 2016, we reclassified 22.4 MMBoe of proved undeveloped reserves to unproved reserves. The reserves reclassified are attributable to horizontal well locations in Project Pangea that are no longer expected to be developed within five years from their initial booking, as required by SEC rules. Revisions included an increase of 2.1 MMBoe resulting from cost reductions, updated well performance and technical parameters, offset by a decrease of 1.9 MMBoe due to lower commodity prices. We produced 4.8 MMBoe during 2016. This production included 1,330 MMcf of gas that was produced and used as field fuel (primarily for compressors and artificial lift) before the gas was delivered to a sales point.

Year Ended December 31, 2015

Extensions and discoveries for 2015 were 34.9 MMBoe, primarily attributable to our development project in the Wolfcamp shale oil resource play in the Permian Basin. During 2015, we reclassified 11.9 MMBoe of proved reserves to unproved reserves. The reserves reclassified are attributable to horizontal and vertical well locations in Project Pangea that are no longer expected to be developed within five years from their initial booking, as required by SEC rules. Revisions included an increase of 13 MMBoe resulting from cost reductions, updated well performance and technical parameters, offset by a decrease of 9.8 MMBoe due to lower commodity prices. We produced 5.8 MMBoe during 2015. This production included 1,530 MMcf of gas that was produced and used as field fuel (primarily for compressors and artificial lift) before the gas was delivered to a sales point.

Year Ended December 31, 2014

Extensions and discoveries for 2014 were 43.2 MMBoe, primarily attributable to our development project in the Wolfcamp shale oil resource play in the Permian Basin. During 2014, we reclassified 9.3 MMBoe of proved undeveloped reserves to unproved reserves. The reserves reclassified included 5.8 MMBoe attributable to vertical Canyon locations in Project Pangea that we do not plan to drill within five years from their initial booking, and 3.5 MMBoe attributable to horizontal Wolfcamp locations that are no longer included in our proved development plan. Revisions included an increase of 6.3 MMBoe attributable to updated well performance and an increase of 0.7 MMBoe due to pricing, offset by a decrease of 4.1 MMBoe resulting from updated technical parameters and costs. We produced 5.3 MMBoe during 2014. This production included 1,390 MMcf of gas that was produced and used as field fuel (primarily for compressors and artificial lift) before the gas was delivered to a sales point.

Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Reserves

The standardized measure of discounted future net cash flows is computed by applying the 12-month unweighted average of the first-day-of-the-month pricing for oil and natural gas (with consideration of price changes only to the extent provided by contractual arrangements) to the estimated future production of proved oil and natural gas reserves less estimated future expenditures (based on year-end costs) to be incurred in developing and producing the proved reserves, discounted using a rate of 10 percent per year to reflect the estimated timing of the future cash flows. Future income taxes are calculated by comparing undiscounted future cash flows to the tax basis of oil and natural gas properties plus available carryforwards and credits and applying the current tax rates to the difference.

Discounted future cash flow estimates like those shown below are not intended to represent estimates of the fair value of oil and natural gas properties. Estimates of fair value would also consider probable and possible reserves, anticipated future oil and natural gas prices, interest rates, changes in development and production costs and risks associated with future production. Because of these and other considerations, any estimate of fair value is necessarily subjective and imprecise.

The following table provides the standardized measure of discounted future net cash flows at December 31, 2016, 2015 and 2014 (in thousands):

	Years Ended December 31,
	2016			2015			2014
Future cash flows	$	3,319,551		$	4,097,568		$	7,430,368
Future production costs		(1,054,211	)		(1,237,888	)		(1,704,333	)
Future development costs		(829,926	)		(934,814	)		(1,247,446	)
Future income tax expense		(132,834	)		(307,374	)		(1,267,025	)
Future net cash flows		1,302,580			1,617,492			3,211,564
10% annual discount for estimated timing of cash    flows		(1,004,825	)		(1,157,097	)		(2,155,749	)
Standardized measure of discounted future net    cash flows	$	297,755		$	460,395		$	1,055,815

Future cash flows as shown above were reported without consideration for the effects of commodity derivative transactions outstanding at each period end.

Changes in Standardized Measure of Discounted Future Net Cash Flows

The changes in the standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves are as follows (in thousands):

	Years Ended December 31,
	2016			2015			2014
Balance, beginning of period	$	460,395		$	1,055,815		$	676,277
Net change in sales and transfer prices and in    production (lifting) costs related to future    production		(191,841	)		(1,405,864	)		(59,920	)
Changes in estimated future development costs		17,405			231,900			(388,772	)
Sales and transfers of oil and gas produced during    the period		(62,835	)		(91,278	)		(209,893	)
Net change due to extensions, discoveries and    improved recovery		13,988			156,783			534,231
Net change due to revisions in quantity estimates		(25,236	)		(59,305	)		(78,801	)
Previously estimated development costs incurred    during the period		15,884			146,237			382,995
Accretion of discount		46,040			105,582			113,188
Other		(9,500	)		6,915			(11,897	)
Net change in income taxes		33,455			313,610			98,407
Standardized Measure of discounted future net    cash flows	$	297,755		$	460,395		$	1,055,815

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Supplementary Data

12 Months Ended

Dec. 31, 2016

Quarterly Financial Information Disclosure [Abstract]

Supplementary Data

11. Supplementary Data

Selected Quarterly Financial Data (unaudited), (dollars in thousands, except per-share amounts):

	2016 Quarters Ended
	December 31			September 30			June 30			March 31
Net revenues	$	26,505		$	23,749		$	22,433		$	17,615
Net operating expenses		(33,564	)		(32,201	)		(34,534	)		(34,869	)
Interest expense, net		(7,086	)		(7,067	)		(6,808	)		(6,298	)
Write-off of debt issuance costs		—			—			(563	)		—
Realized gain on commodity derivatives		442			781			1,409			3,500
Unrealized (loss) gain on commodity derivatives		(3,343	)		760			(8,076	)		(957	)
Other income (expense)		—			(10	)		1,417			104
Loss before income tax benefit		(17,046	)		(13,988	)		(24,722	)		(20,905	)
Income tax benefit		(3,571	)		(4,915	)		(8,687	)		(7,245	)
Net loss	$	(13,475	)	$	(9,073	)	$	(16,035	)	$	(13,660	)
Basic net loss applicable to common stockholders    per common share	$	(0.32	)	$	(0.22	)	$	(0.39	)	$	(0.33	)
Diluted net loss applicable to common stockholders    per common share	$	(0.32	)	$	(0.22	)	$	(0.39	)	$	(0.33	)

	2015 Quarters Ended
	December 31			September 30			June 30			March 31
Net revenues	$	25,492		$	33,941		$	38,605		$	33,298
Net operating expenses		(38,671	)		(272,462	)		(46,970	)		(45,686	)
Interest expense, net		(6,436	)		(6,465	)		(6,243	)		(5,922	)
Gain on debt extinguishment		9,080			1,483			—			—
Realized gain on commodity derivatives		14,552			12,755			9,281			15,901
Unrealized (loss) gain on commodity derivatives		(10,285	)		296			(13,904	)		(9,321	)
Other income (expense)		225			(91	)		12			26
Loss before income tax benefit		(6,043	)		(230,543	)		(19,219	)		(11,704	)
Income tax benefit		(284	)		(81,756	)		(7,369	)		(3,996	)
Net loss	$	(5,759	)	$	(148,787	)	$	(11,850	)	$	(7,708	)
Basic net loss applicable to common    stockholders per common share	$	(0.14	)	$	(3.67	)	$	(0.29	)	$	(0.19	)
Diluted net loss applicable to common    stockholders per common share	$	(0.14	)	$	(3.67	)	$	(0.29	)	$	(0.19	)

	2014 Quarters Ended
	December 31			September 30			June 30			March 31
Net revenues	$	55,070		$	68,124		$	73,408		$	61,927
Net operating expenses		(50,136	)		(45,525	)		(50,812	)		(44,899	)
Interest expense, net		(5,715	)		(5,442	)		(5,357	)		(5,137	)
Equity in earnings (losses) of investee		5			—			(186	)		—
Realized gain (loss) on commodity derivatives		7,782			(764	)		(3,320	)		(1,339	)
Unrealized gain (loss) on commodity derivatives		36,907			18,810			(7,678	)		(5,926	)
Other income (expense)		176			—			(109	)		—
Income before income tax		44,089			35,203			5,946			4,626
Income tax provision		17,102			12,756			2,153			1,681
Net income	$	26,987		$	22,447		$	3,793		$	2,945
Basic net income applicable to common    stockholders per common share	$	0.68		$	0.57		$	0.10		$	0.08
Diluted net income applicable to common    stockholders per common share	$	0.68		$	0.57		$	0.10		$	0.08

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Summary of Significant Accounting Policies (Policies)

12 Months Ended

Dec. 31, 2016

Accounting Policies [Abstract]

Organization and Nature of Operations

Organization and Nature of Operations

Approach Resources Inc. (“Approach,” the “Company,” “we,” “us” or “our”) is an independent energy company focused on the exploration, development, production and acquisition of unconventional oil and gas properties. We focus on finding and developing oil and natural gas reserves in oil shale and tight gas sands. Our properties are primarily located in the Permian Basin in West Texas. We also own interests in the East Texas Basin.

Consolidation, Basis of Presentation and Significant Estimates

Consolidation, Basis of Presentation and Significant Estimates

The accompanying consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America and include the accounts of the Company and its wholly owned subsidiaries. Intercompany accounts and transactions are eliminated. In preparing the accompanying financial statements, management has made certain estimates and assumptions that affect reported amounts in the financial statements and disclosures of contingencies. Actual results may differ from those estimates. Significant assumptions are required in the valuation of proved oil and natural gas reserves, which affect our estimate of depletion expense as well as our impairment analyses. Significant assumptions also are required in our estimation of accrued liabilities, commodity derivatives, income tax provision, share-based compensation and asset retirement obligations. It is at least reasonably possible these estimates could be revised in the near term, and these revisions could be material. Certain prior-year amounts have been reclassified to conform to current-year presentation. These classifications have no impact on the net loss reported.

Cash and Cash Equivalents

Cash and Cash Equivalents

We consider all highly liquid debt instruments purchased with an original maturity of three months or less to be cash equivalents. At times, the amount of cash and cash equivalents on deposit in financial institutions exceeds federally insured limits. We monitor the soundness of the financial institutions and believe the Company’s risk is negligible.

Capitalized Costs

Capitalized Costs.     Our oil and gas properties comprised the following (in thousands):

	December 31,
	2016			2015
Mineral interests in properties:
Unproved leasehold costs	$	33,596		$	37,853
Proved leasehold costs		44,643			44,122
Wells and related equipment and facilities		1,774,314			1,753,649
Support equipment		8,002			9,545
Uncompleted wells, equipment and facilities		9,219			8,612
Total costs		1,869,774			1,853,781
Less accumulated depreciation, depletion and    amortization		(780,412	)		(702,139	)
Net capitalized costs	$	1,089,362		$	1,151,642

We follow the successful efforts method of accounting for our oil and gas producing activities. Costs to acquire mineral interests in oil and gas properties and to drill and equip development wells and related asset retirement costs are capitalized. Costs to drill exploratory wells are capitalized pending determination of whether the wells have proved reserves. If we determine that the wells do not have proved reserves, the costs are charged to exploration expense. There were no exploratory wells capitalized, pending determination of whether the wells have proved reserves, at December 31, 2016 or 2015. Geological and geophysical costs, including seismic studies are charged to exploration expense as incurred. We capitalize interest on expenditures for significant exploration and development projects that last more than six months while activities are in progress to bring the assets to their intended use and while these expenditures are excluded from our depletable base. Through December 31, 2016, we have capitalized no interest costs because our individual wells and infrastructure projects are generally developed in less than six months. Costs incurred to maintain wells and related equipment are charged to expense as incurred.

On the sale or retirement of a complete unit of a proved property, the cost and related accumulated depreciation, depletion and amortization are eliminated from the property accounts, and the resulting gain or loss is recognized. On the retirement or sale of a partial unit of proved property, the cost is charged to accumulated depreciation, depletion and amortization with no gain or loss recognized in income.

Capitalized amounts attributable to proved oil and gas properties are depleted by the unit-of-production method over proved reserves using the unit conversion ratio of six Mcf of gas to one barrel of oil equivalent (“Boe”), and one barrel of NGLs to one Boe. The ratios of six Mcf of natural gas to one Boe and one barrel of NGLs to one Boe do not assume price equivalency and, given price differentials, the price for a Boe for natural gas may differ significantly from the price for a barrel of oil. Depreciation, depletion and amortization expense for oil and gas producing property and related equipment was $78.7 million, $108.8 million and $106.2 million for the years ended December 31, 2016, 2015 and 2014, respectively.

Capitalized costs related to proved oil and gas properties, including wells and related equipment and facilities, are periodically evaluated for impairment based on an analysis of undiscounted future net cash flows in accordance with ASC 360, Accounting for the Impairment or Disposal of Long-Lived Assets, as events or changes in circumstances indicate that the carrying values of those assets may not be recoverable. If undiscounted cash flows are insufficient to recover the net capitalized costs related to proved properties, then we recognize an impairment charge equal to the difference between the net capitalized costs related to proved properties and their estimated fair values based on the present value of the related future net cash flows. Estimating future net cash flows involves the use of judgments, including estimation of the proved and unproved oil and natural gas reserve quantities, timing of development and production, expected future commodity prices, capital expenditures and production costs. We recorded no impairment of our proved properties for the years ended December 31, 2016 and 2014. During the year ended December 31, 2015, we recognized an impairment loss of $214.7 million related primarily to our vertical Canyon wells. See Note 7 for proved property impairment disclosures.

Unproved oil and gas properties that are individually significant are periodically assessed for impairment of value, and a loss is recognized at the time of impairment by providing an impairment allowance. We recorded no impairment of our unproved properties for the years ended December 31, 2016 and 2014. Certain leases that we consider non-core to our development of Project Pangea were impaired during the year ended December 31, 2015, as we did not plan to develop them. As a result, we recorded a non-cash impairment loss of unproved property of $5.5 million for the year ended December 31, 2015.

The total impairment loss of $220.2 million for the year ended December 31, 2015, is recorded in impairment of oil and gas properties on our consolidated statements of operations, and in accumulated depletion, depreciation and amortization on our consolidated balance sheets.

On the sale of an entire interest in an unproved property for cash or cash equivalents, gain or loss on the sale is recognized, taking into consideration the amount of any recorded impairment if the property had been assessed individually. If a partial interest in an unproved property is sold, the amount received is treated as a reduction of the cost of the interest retained.

F-1

Other Property

Other Property

Furniture, fixtures and equipment are carried at cost. Depreciation of furniture, fixtures and equipment is provided using the straight-line method over estimated useful lives ranging from three to 15 years. Gain or loss on retirement or sale or other disposition of assets is included in income in the period of disposition. Depreciation expense for other property and equipment was $343,000, $563,000 and $588,000 for the years ended December 31, 2016, 2015 and 2014, respectively.

Financial Instruments

Financial Instruments

The carrying amounts of financial instruments including cash and cash equivalents, accounts receivable, accounts payable and accrued liabilities approximate fair value, as of December 31, 2016 and 2015. See Note 7 for fair value disclosures.

Income Taxes

Income Taxes

We are subject to U.S. federal income taxes along with state income taxes in Texas. When tax returns are filed, it is highly certain that some positions taken would be sustained upon examination by the taxing authorities, while others are subject to uncertainty about the merits of the position taken or the amount of the position that would be ultimately sustained. The benefit of a tax position is recognized in the financial statements in the period during which, based on all available evidence, management believes it is more likely than not that the position will be sustained upon examination, including the resolution of appeals or litigation processes, if any. Tax positions taken are not offset or aggregated with other positions. Tax positions that meet the more-likely-than-not recognition threshold are measured as the largest amount of tax benefit that is more than 50% likely of being realized upon settlement with the applicable taxing authority. The portion of the benefits associated with tax positions taken that exceeds the amount measured as described above is reflected as a liability for unrecognized tax benefits in the accompanying balance sheet along with any associated interest and penalties that would be payable to the taxing authorities upon examination. Interest and penalties associated with unrecognized tax benefits are classified as additional income taxes on the consolidated statements of operations.

Based on our analysis, we did not have any uncertain tax positions as of December 31, 2016 or 2015. The Company’s income tax returns are subject to examination by the relevant taxing authorities as follows: U.S. Federal income tax returns for tax years 2013 and forward and Texas income and margin tax returns for tax years 2013 and forward. There are currently no income tax examinations underway for these jurisdictions.

Deferred tax assets and liabilities are recognized for the estimated future tax consequences attributable to the differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are measured using the tax rate in effect for the year in which those temporary differences are expected to be recovered or settled. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in income in the year of the enacted tax rate change.

We monitor our deferred tax assets by jurisdiction to assess their potential realization, and a valuation allowance is recognized on deferred tax assets when we believe that certain of these assets are more likely than not to be realized. In performing this review, we make estimates and assumptions regarding projected future taxable income, the expected timing of reversals of existing temporary differences and the implementation of tax planning strategies. To the extent that a valuation allowance is established or changed during any period, we would recognize expense or benefit within our consolidated tax expense. We do not currently have a valuation allowance on our federal net operating loss carryforwards (“NOLs”).

Derivative Activity

Derivative Activity

We record our open derivative instruments at fair value on our consolidated balance sheets as either unrealized gains or losses on commodity derivatives. We record changes in such fair value in earnings on our consolidated statements of operations under the caption entitled “unrealized (loss) gain on commodity derivatives.”

Although we have not designated our derivative instruments as cash-flow hedges, we use those instruments to reduce our exposure to fluctuations in commodity prices related to our natural gas and oil production. Unrealized gains and losses, at fair value, are included on our consolidated balance sheets as current or non-current assets or liabilities based on the anticipated timing of cash settlements under the related contracts. Changes in the fair value of our commodity derivative contracts are recorded in earnings as they occur and included in income (expense) on our consolidated statements of operations. Realized gains and losses are also included in income (expense) on our consolidated statements of operations.

Accrued Liabilities

Accrued Liabilities

The following is a summary of our accrued liabilities at December 31, 2016 and 2015 (in thousands):

	2016		2015
Capital expenditures accrual	$	1,067	$	3,476
Operating expenses and other		6,750		9,988
Total	$	7,817	$	13,464

Asset Retirement Obligations

Asset Retirement Obligations

Our asset retirement obligations relate to future plugging and abandonment expenses on oil and gas properties. Based on the expected timing of payments, the full asset retirement obligation is classified as non-current. There were no significant changes to the asset retirement obligations for the years ended December 31, 2016, 2015 and 2014.

Share-Based Compensation

Share-Based Compensation

We measure and record compensation expense for share-based payment awards to employees and outside directors based on estimated grant date fair values. We recognize compensation costs for awards granted over the requisite service period based on the grant date fair value in general and administrative expenses on our consolidated statements of operations.

In 2016, we awarded cash-settled performance awards, subject to certain performance conditions, to our executive officers. The cash-settled performance awards represent a non-equity unit with a conversion value equal to the fair market value of a share of the Company’s common stock at the vesting date. These awards are classified as liability awards due to the cash settlement feature. Compensation costs associated with the cash-settled performance awards are re-measured at each interim reporting period and an adjustment is recorded in general and administrative expenses on our consolidated statements of operations.

Earnings Per Common Share

Earnings Per Common Share

We report basic earnings per common share, which excludes the effect of potentially dilutive securities, and diluted earnings per common share, which includes the effect of all potentially dilutive securities unless their impact is antidilutive. The following are reconciliations of the numerators and denominators of our basic and diluted earnings per share, (dollars in thousands, except per-share amounts):

	For the Years Ended December 31,
	2016			2015			2014
Income (numerator):
Net (loss) income — basic	$	(52,243	)	$	(174,104	)	$	56,172
Weighted average shares (denominator):
Weighted average shares — basic		41,488,206			40,464,283			39,407,733
Dilution effect of share-based compensation,    treasury method (1)		—			—			12,132
Weighted average shares — diluted		41,488,206			40,464,283			39,419,865
Net (loss) income per share:
Basic	$	(1.26	)	$	(4.30	)	$	1.43
Diluted	$	(1.26	)	$	(4.30	)	$	1.42

(1) Approximately 39,000 options to purchase our common stock were excluded from this calculation because they were antidilutive for the years ended December 31, 2016 and 2015.

Revenue and Accounts Receivable from Purchasers and Joint Interest Owners

Revenue and Accounts Receivable.     We recognize revenue for our production when the quantities are delivered to or collected by the respective purchaser. Prices for such production are defined in sales contracts and are readily determinable based on certain publicly available indices.

Accounts receivable, joint interest owners, consist of uncollateralized joint interest owner obligations due within 30 days of the invoice date. Accounts receivable, oil, NGLs and gas sales, consist of uncollateralized accrued revenues due under normal trade terms, generally requiring payment within 30 to 60 days of production. No interest is charged on past-due balances. Payments made on all accounts receivable are applied to the earliest unpaid items. We review accounts receivable periodically and reduce the carrying amount by a valuation allowance that reflects our best estimate of the amount that may not be collectible. No such allowance was considered necessary at December 31, 2016 or 2015. Accounts receivable related to oil, NGLs and gas sales includes $0.2 million and $4.8 million from realized gains on commodity derivatives at December 31, 2016 and 2015, respectively.

Oil and Gas Sales Payable

Oil, NGLs and Gas Sales Payable.     Oil, NGLs and gas sales payable represents amounts collected from purchasers for oil, NGLs and gas sales which are either revenues due to other revenue interest owners or severance taxes due to the respective state or local tax authorities. Generally, we are required to remit amounts due under these liabilities within 60 days of the end of the month in which the related production occurred.

Production Costs

Production Costs.     Production costs, including compressor rental and repair, pumpers’ and supervisors’ salaries, saltwater disposal, insurance, repairs and maintenance, expensed workovers and other operating expenses are expensed as incurred and included in lease operating expenses on our consolidated statements of operations.

Exploration expenses

Exploration expenses.     Exploration expenses include lease expirations, delay rentals, geological and geophysical costs and dry hole costs. For the year ended December 31, 2015 exploration expense includes $2.2 million related to the early termination of daywork drilling contracts.

Dependence on Major Customer

Dependence on Major Customers.     For the year ended December 31, 2016, sales to JP Energy Development, LP (“JP Energy”) and DCP Midstream, LP (“DCP”) accounted for approximately 54% and 46%, respectively, of our total sales. As of December 31, 2016, we had dedicated all of our oil production from northern Project Pangea and Pangea West through September 2022 to JP Energy. In addition, as of December 31, 2016, we had contracted to sell all of our NGLs and natural gas production from Project Pangea to DCP through August 2023. For the year ended December 31, 2015, sales to DCP and JP Energy accounted for approximately 36% and 63%, respectively of our total sales. For the year ended December 31, 2014, sales to DCP and JP Energy accounted for approximately 30% and 69%, respectively of our total sales. We believe that there are potential alternative purchasers and that it may be necessary to establish relationships with new purchasers. However, there can be no assurance that we can establish such relationships and that those relationships will result in increased purchasers. Although we are exposed to a concentration of credit risk, we believe that all of our purchasers are credit worthy.

Segment Reporting

Segment Reporting

The Company presently operates in one business segment, the exploration and production of oil, NGLs and natural gas.

Recent Accounting Pronouncements

Recent Accounting Pronouncements

In May 2014, the Financial Accounting Standards Board (“FASB”) issued an accounting standards update for “Revenue from Contracts with Customers,” which supersedes the revenue recognition requirements in “Topic 605, Revenue Recognition.” This accounting standard update provides new guidance concerning recognition and measurement of revenue and requires additional disclosures about the nature, timing and uncertainty of revenue and cash flows arising from contracts with customers. This new guidance permits adoption through the use of either a full retrospective approach or a modified retrospective approach for annual reporting periods beginning on or after December 15, 2016, with early adoption not permitted. In August 2015, FASB delayed the effective date one year, making the new standard effective for interim periods and annual periods beginning after December 15, 2017. We have not determined which transition method we will use and are continuing to evaluate our existing revenue recognition policies to determine whether any of our contracts will be affected by the new requirements. This evaluation will continue throughout 2017, and we are currently planning to adopt this new standard in the first quarter of 2018.

In September 2015, FASB issued an accounting standards update for “Business Combinations,” which requires that an acquirer recognize adjustments to provisional amounts that are identified during the measurement period in the reporting period in which the adjustment amounts are determined. We adopted this new guidance prospectively in the first quarter of 2016. This new guidance did not have a significant impact on the consolidated financial statements.

In February 2016, FASB issued an accounting standards update for “Leases,” which amends existing guidance to require lessees to recognize assets and liabilities on the balance sheet for the rights and obligations created by long-term leases and to disclose additional quantitative and qualitative information about leasing arrangements. This new guidance is effective for interim and annual periods beginning after December 15, 2018, and we will adopt it using a modified retrospective approach. The Company is evaluating the impact of this new guidance on its consolidated financial statements.

In March 2016, FASB issued an accounting standards update for “Compensation — Stock Compensation,” which amends existing guidance related to the accounting for forfeitures, employer tax withholding on share-based compensation and financial statement presentation of excess tax benefits or deficiencies.  This standard is effective for interim and annual reporting periods beginning after December 15, 2016, with early adoption permitted. We applied this standard using a modified retrospective approach. We have elected to (i) recognize forfeitures of share-based compensation as they occur, (ii) permit tax withholdings in excess of the minimum statutory requirements and (iii) recognize previously un-recognized excess tax benefits related to share-based compensation in the current year.  As a result, we have recognized an increase in accumulated earnings in the current year of $1.7 million related to the change in accounting principal as of January 1, 2016.  Adoption of this guidance did not impact our consolidated statements of operations or cash flows.

In January 2017, the FASB issued an accounting standards update for “Clarifying the Definition of a Business,” which provides guidance to assist entities with evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. This standard requires entities to use a screen test to determine when an integrated set of assets and activities is not a business or if the integrated set of assets and activities needs to be further evaluated against the framework. This standard is effective for interim and annual reporting periods beginning after December 15, 2016. The Company is evaluating the impact of this new guidance on its consolidated financial statements.

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Summary of Significant Accounting Policies (Tables)

12 Months Ended

Dec. 31, 2016

Accounting Policies [Abstract]

Summary of Oil and Gas Properties

Our oil and gas properties comprised the following (in thousands):

	December 31,
	2016			2015
Mineral interests in properties:
Unproved leasehold costs	$	33,596		$	37,853
Proved leasehold costs		44,643			44,122
Wells and related equipment and facilities		1,774,314			1,753,649
Support equipment		8,002			9,545
Uncompleted wells, equipment and facilities		9,219			8,612
Total costs		1,869,774			1,853,781
Less accumulated depreciation, depletion and    amortization		(780,412	)		(702,139	)
Net capitalized costs	$	1,089,362		$	1,151,642

Summary of Accrued Liabilities

The following is a summary of our accrued liabilities at December 31, 2016 and 2015 (in thousands):

	2016		2015
Capital expenditures accrual	$	1,067	$	3,476
Operating expenses and other		6,750		9,988
Total	$	7,817	$	13,464

Reconciliations of Numerators and Denominators of Basic and Diluted Earnings Per Share

The following are reconciliations of the numerators and denominators of our basic and diluted earnings per share, (dollars in thousands, except per-share amounts):

	For the Years Ended December 31,
	2016			2015			2014
Income (numerator):
Net (loss) income — basic	$	(52,243	)	$	(174,104	)	$	56,172
Weighted average shares (denominator):
Weighted average shares — basic		41,488,206			40,464,283			39,407,733
Dilution effect of share-based compensation,    treasury method (1)		—			—			12,132
Weighted average shares — diluted		41,488,206			40,464,283			39,419,865
Net (loss) income per share:
Basic	$	(1.26	)	$	(4.30	)	$	1.43
Diluted	$	(1.26	)	$	(4.30	)	$	1.42

(1) Approximately 39,000 options to purchase our common stock were excluded from this calculation because they were antidilutive for the years ended December 31, 2016 and 2015.

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Long-Term Debt (Tables)

12 Months Ended

Dec. 31, 2016

Debt Disclosure [Abstract]

Schedule of Long Term Debt

The following table provides a summary of our long-term debt at December 31, 2016, and December 31, 2015 (in thousands).

	December 31, 2016			December 31, 2015
Senior secured credit facility:
Outstanding borrowings	$	273,000		$	273,000
Debt issuance costs		(1,304	)		(2,252	)
Senior secured credit facility, net		271,696			270,748
Senior notes:
Principal		230,320			230,320
Debt issuance costs		(3,667	)		(4,481	)
Senior notes, net		226,653			225,839
Total long-term debt	$	498,349		$	496,587

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Share-Based Compensation (Tables)

12 Months Ended

Dec. 31, 2016

Disclosure Of Compensation Related Costs Sharebased Payments [Abstract]

Summary of Status of Nonvested Shares

A summary of the status of nonvested shares for the years ended December 31, 2016, 2015 and 2014, is presented below:

	Shares			Weighted Average Grant-Date Fair Value
Nonvested at January 1, 2014		699,231		$	23.70
Granted		992,919			14.48
Vested		(400,429	)		20.18
Canceled		(169,311	)		25.57
Nonvested at December 31, 2014		1,122,410		$	16.52
Granted		1,278,329			4.87
Vested		(419,222	)		15.26
Canceled		(246,261	)		14.30
Nonvested at December 31, 2015		1,735,256		$	8.60
Granted		1,318,229			1.90
Vested		(992,461	)		7.03
Canceled		(107,960	)		17.33
Nonvested at December 31, 2016		1,953,064		$	4.39

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Income Taxes (Tables)

12 Months Ended

Dec. 31, 2016

Income Tax Disclosure [Abstract]

Schedule of Provision for Income Taxes

Our provision for income taxes comprised the following (in thousands):

	Years Ended December 31,
	2016			2015			2014
Current:
Federal	$	—		$	(265	)	$	(25	)
State		—			—			—
Total current provision for income taxes	$	—		$	(265	)	$	(25	)
Deferred:
Federal	$	(24,957	)	$	(91,716	)	$	32,754
State		539			(1,424	)		963
Total deferred provision for income taxes	$	(24,418	)	$	(93,140	)	$	33,717

Total Income Tax Expense Differed from Amounts Computed by Applying U.S. Federal Statutory Tax Rates to Pre-Tax Income

Total income tax expense differed from the amounts computed by applying the U.S. Federal statutory tax rates to pre-tax income (in thousands):

	Years Ended December 31,
	2016			2015			2014
Statutory tax at 35%	$	(26,831	)	$	(93,628	)	$	31,452
State taxes, net of federal impact		578			(1,463	)		989
Share-based compensation tax shortfall		1,826			1,939			1,670
Permanent differences		11			26			37
Other differences		(2	)		(1,035	)		(456	)
Valuation allowance		—			756			—
Total	$	(24,418	)	$	(93,405	)	$	33,692

Significant Components of Net Deferred Tax Assets and Liabilities

Significant components of net deferred tax assets and liabilities are (in thousands):

	Years Ended December 31,
	2016			2015
Deferred tax assets:
Net operating loss carryforwards	$	155,018		$	88,230
Unrealized loss on commodity derivatives		1,732			—
Other		892			1,672
Total deferred tax assets		157,642			89,902
Deferred tax liabilities:
Difference in depreciation, depletion and    capitalization methods — oil and gas properties		(162,501	)		(118,534	)
Unrealized gain on commodity derivatives		—			(2,391	)
Total deferred tax liabilities		(162,501	)		(120,925	)
Valuation allowance		(756	)		(756	)
Net deferred tax liability	$	(5,615	)	$	(31,779	)

Schedule of NOLs

Our NOLs have the following expiration dates (in thousands):

Expiration Dates	Amounts
2030	$	5,790
2031		19,686
2032		54,714
2033		78
2034		56,505
2035		116,482
2036		189,649
Total	$	442,904

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Derivative Instruments and Fair Value Measurements (Tables)

12 Months Ended

Dec. 31, 2016

Derivative Instruments And Hedging Activities Disclosure [Abstract]

Commodity Derivatives Volumes and Prices

At December 31, 2016, we had the following commodity derivatives positions outstanding:

Commodity and Period	Contract Type	Volume Transacted	Contract Price
Natural Gas
January 2017 — March 2017	Swap	100,000 MMBtu/month	$2.463/MMBtu
January 2017 — March 2017	Swap	300,000 MMBtu/month	$2.45/MMBtu
January 2017 — March 2017	Swap	200,000 MMBtu/month	$3.287/MMBtu
January 2017 — December 2017	Collar	100,000 MMBtu/month	$3.00/MMBtu - $3.65/MMBtu
April 2017 — December 2017	Collar	200,000 MMBtu/month	$2.30/MMBtu - $2.60/MMBtu
April 2017 — December 2017	Collar	200,000 MMBtu/month	$3.00/MMBtu - $3.44/MMBtu
April 2017 — December 2017	Collar	200,000 MMBtu/month	$3.00/MMBtu - $3.50/MMBtu

After December 31, 2016, we entered into the following commodity derivative positions:

Commodity and Period	Contract Type	Volume Transacted	Contract Price
Natural Gas
January 2018 — December 2018	Swap	200,000 MMBtu/month	$3.085/MMBtu
January 2018 — December 2018	Swap	250,000 MMBtu/month	$3.084/MMBtu
NGLs (C2 - Ethane)
February 2017 — December 2017	Swap	1,050 Bbls/day	$11.34/Bbl
NGLs (C3 - Propane)
February 2017 — December 2017	Swap	750 Bbls/day	$27.916/Bbl
NGLs (IC4 - Isobutane)
February 2017 — December 2017	Swap	75 Bbls/day	$36.7325/Bbl
NGLs (NC4 - Butane)
February 2017 — December 2017	Swap	250 Bbls/day	$35.9205/Bbl

Summary of Fair Value of Open Commodity Derivatives

The following summarizes the fair value of our open commodity derivatives as of December 31, 2016 and 2015 (in thousands):

	Balance Sheet Location	Fair Value
		December 31, 2016			December 31, 2015
Derivatives not designated as hedging    instruments
Commodity derivatives	Unrealized (loss) gain on    commodity derivatives	$	(4,880	)	$	6,737

Summary of Change in Fair Value of Commodity Derivatives

The following summarizes the change in the fair value of our commodity derivatives (in thousands):

	Income Statement Location
		Year Ended December 31,
		2016			2015			2014
Derivatives not designated as hedging    instruments
Commodity derivatives	Unrealized (loss) gain on    commodity derivatives	$	(11,616	)	$	(33,214	)	$	42,113
	Realized gain on    commodity derivatives		6,132			52,489			2,359
		$	(5,484	)	$	19,275		$	44,472

Summary of Financial Instruments Not Recorded at Fair Value

The following table sets forth the fair values of financial instruments that are not recorded at fair value on our financial statements (in thousands).

	December 31, 2016
	Carrying Amount		Fair Value
Senior Notes, net	$	226,653	$	206,286

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Commitments and Contingencies (Tables)

12 Months Ended

Dec. 31, 2016

Commitments And Contingencies Disclosure [Abstract]

Schedule of Years of Future Minimum Rental Payments Required Under Operating Lease Arrangements

The following is a schedule by years of future minimum rental payments required under our operating lease arrangements as of December 31, 2016 (in thousands):

2017	$	989
2018		979
2019		980
2020		248
2021		2
Total	$	3,198

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Oil and Gas Producing Activities (Tables)

12 Months Ended

Dec. 31, 2016

Extractive Industries [Abstract]

Schedule of Information Regarding Costs Incurred for Oil and Gas Property Acquisition, Development and Exploration Activities

Set forth below is certain information regarding the costs incurred for oil and gas property acquisition, development and exploration activities (in thousands):

	For the Years Ended December 31,
	2016		2015		2014
Property acquisition costs:
Unproved properties	$	17	$	653	$	4,578
Proved properties		—		—		—
Exploration costs		3,923		4,439		3,831
Development costs(1)		15,884		146,237		382,995
Total costs incurred	$	19,824	$	151,329	$	391,404

(1) For the years ended December 31, 2016, 2015 and 2014, development costs included $36,000, $151,000 and $898,000, respectively, in non-cash asset retirement obligations.

Schedule of Information Regarding Results of Operations for Oil and Gas Producing Activities

Set forth below is certain information regarding the results of operations for oil and gas producing activities (in thousands):

	For the Years Ended December 31,
	2016			2015			2014
Revenues	$	90,302		$	131,336		$	258,529
Production costs		(27,467	)		(40,057	)		(48,635	)
Exploration expense		(3,923	)		(4,439	)		(3,831	)
Depletion		(79,044	)		(109,319	)		(106,802	)
Impairment of oil and gas properties		—			(220,197	)		—
Income tax benefit (expense)		7,144			86,120			(35,387	)
Results of operations	$	(12,988	)	$	(156,556	)	$	63,874

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Disclosures About Oil and Gas Producing Activities (unaudited) (Tables)

12 Months Ended

Dec. 31, 2016

Extractive Industries [Abstract]

Commodity Prices Inclusive of Adjustments for Quality and Location Used in Determining Future Net Revenues Related to Standardized Measure Calculation

The following table summarizes the prices used in the reserve estimates for 2016, 2015 and 2014. Commodity prices used for the reserve estimates, adjusted for basis differentials, grade and quality, are as follows:

	2016		2015		2014
Oil (per Bbl)	$	42.69	$	50.16	$	94.56
Natural gas liquids (per Bbl)	$	14.12	$	15.13	$	31.50
Gas (per Mcf)	$	2.47	$	2.64	$	4.55

Summary of Changes in Quantities of Proved Oil, NGL and Natural Gas Reserves

The following table provides a summary of the changes of the total proved reserves for the years ended December 31, 2016, 2015 and 2014, as well as proved developed and proved undeveloped reserves at the beginning and end of each respective year.

Total Proved Reserves	Oil (MBbls)			NGLs (MBbls)			Natural Gas (MMcf)			Total (MBoe)
Balance — January 1, 2014		46,067			32,593			216,002			114,661
Extensions and discoveries		19,347			10,658			79,454			43,247
Production(1)		(2,024	)		(1,461	)		(10,773	)		(5,281	)
Revisions to previous estimates		(8,052	)		(883	)		15,337			(6,379	)
Balance — December 31, 2014		55,338			40,907			300,020			146,248
Extensions and discoveries		11,054			10,630			79,268			34,895
Production(1)		(1,882	)		(1,694	)		(13,262	)		(5,787	)
Revisions to previous estimates		(10,014	)		(357	)		9,962			(8,710	)
Balance — December 31, 2015		54,496			49,486			375,988			166,646
Extensions and discoveries		6,529			4,564			33,347			16,651
Production(1)		(1,275	)		(1,529	)		(11,734	)		(4,759	)
Revisions to previous estimates		(9,719	)		(4,887	)		(45,324	)		(22,161	)
Balance — December 31, 2016		50,031			47,634			352,277			156,377

(1) Production included 1,390 MMcf, 1,530 MMcf and 1,330 MMcf related to field fuel in 2014, 2015 and 2016, respectively.

Total Proved Reserves	Oil (MBbls)		NGLs (MBbls)		Natural Gas (MMcf)		Total (MBoe)
Proved Developed Reserves:
January 1, 2014		13,646		14,919		99,742		45,189
December 31, 2014		17,978		19,082		138,961		60,220
December 31, 2015		15,667		20,414		154,652		61,856
December 31, 2016		13,466		20,375		150,208		58,875
Proved Undeveloped Reserves:
January 1, 2014		32,421		17,674		116,260		69,472
December 31, 2014		37,360		21,825		161,059		86,028
December 31, 2015		38,829		29,072		221,335		104,790
December 31, 2016		36,565		27,259		202,069		97,502

Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Natural Gas Reserves

The following table provides the standardized measure of discounted future net cash flows at December 31, 2016, 2015 and 2014 (in thousands):

	Years Ended December 31,
	2016			2015			2014
Future cash flows	$	3,319,551		$	4,097,568		$	7,430,368
Future production costs		(1,054,211	)		(1,237,888	)		(1,704,333	)
Future development costs		(829,926	)		(934,814	)		(1,247,446	)
Future income tax expense		(132,834	)		(307,374	)		(1,267,025	)
Future net cash flows		1,302,580			1,617,492			3,211,564
10% annual discount for estimated timing of cash    flows		(1,004,825	)		(1,157,097	)		(2,155,749	)
Standardized measure of discounted future net    cash flows	$	297,755		$	460,395		$	1,055,815

Summary of Changes in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Natural Gas Reserves

The changes in the standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves are as follows (in thousands):

	Years Ended December 31,
	2016			2015			2014
Balance, beginning of period	$	460,395		$	1,055,815		$	676,277
Net change in sales and transfer prices and in    production (lifting) costs related to future    production		(191,841	)		(1,405,864	)		(59,920	)
Changes in estimated future development costs		17,405			231,900			(388,772	)
Sales and transfers of oil and gas produced during    the period		(62,835	)		(91,278	)		(209,893	)
Net change due to extensions, discoveries and    improved recovery		13,988			156,783			534,231
Net change due to revisions in quantity estimates		(25,236	)		(59,305	)		(78,801	)
Previously estimated development costs incurred    during the period		15,884			146,237			382,995
Accretion of discount		46,040			105,582			113,188
Other		(9,500	)		6,915			(11,897	)
Net change in income taxes		33,455			313,610			98,407
Standardized Measure of discounted future net    cash flows	$	297,755		$	460,395		$	1,055,815

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Supplementary Data (Tables)

12 Months Ended

Dec. 31, 2016

Quarterly Financial Information Disclosure [Abstract]

Selected Quarterly Financial Data

Selected Quarterly Financial Data (unaudited), (dollars in thousands, except per-share amounts):

	2016 Quarters Ended
	December 31			September 30			June 30			March 31
Net revenues	$	26,505		$	23,749		$	22,433		$	17,615
Net operating expenses		(33,564	)		(32,201	)		(34,534	)		(34,869	)
Interest expense, net		(7,086	)		(7,067	)		(6,808	)		(6,298	)
Write-off of debt issuance costs		—			—			(563	)		—
Realized gain on commodity derivatives		442			781			1,409			3,500
Unrealized (loss) gain on commodity derivatives		(3,343	)		760			(8,076	)		(957	)
Other income (expense)		—			(10	)		1,417			104
Loss before income tax benefit		(17,046	)		(13,988	)		(24,722	)		(20,905	)
Income tax benefit		(3,571	)		(4,915	)		(8,687	)		(7,245	)
Net loss	$	(13,475	)	$	(9,073	)	$	(16,035	)	$	(13,660	)
Basic net loss applicable to common stockholders    per common share	$	(0.32	)	$	(0.22	)	$	(0.39	)	$	(0.33	)
Diluted net loss applicable to common stockholders    per common share	$	(0.32	)	$	(0.22	)	$	(0.39	)	$	(0.33	)

	2015 Quarters Ended
	December 31			September 30			June 30			March 31
Net revenues	$	25,492		$	33,941		$	38,605		$	33,298
Net operating expenses		(38,671	)		(272,462	)		(46,970	)		(45,686	)
Interest expense, net		(6,436	)		(6,465	)		(6,243	)		(5,922	)
Gain on debt extinguishment		9,080			1,483			—			—
Realized gain on commodity derivatives		14,552			12,755			9,281			15,901
Unrealized (loss) gain on commodity derivatives		(10,285	)		296			(13,904	)		(9,321	)
Other income (expense)		225			(91	)		12			26
Loss before income tax benefit		(6,043	)		(230,543	)		(19,219	)		(11,704	)
Income tax benefit		(284	)		(81,756	)		(7,369	)		(3,996	)
Net loss	$	(5,759	)	$	(148,787	)	$	(11,850	)	$	(7,708	)
Basic net loss applicable to common    stockholders per common share	$	(0.14	)	$	(3.67	)	$	(0.29	)	$	(0.19	)
Diluted net loss applicable to common    stockholders per common share	$	(0.14	)	$	(3.67	)	$	(0.29	)	$	(0.19	)

	2014 Quarters Ended
	December 31			September 30			June 30			March 31
Net revenues	$	55,070		$	68,124		$	73,408		$	61,927
Net operating expenses		(50,136	)		(45,525	)		(50,812	)		(44,899	)
Interest expense, net		(5,715	)		(5,442	)		(5,357	)		(5,137	)
Equity in earnings (losses) of investee		5			—			(186	)		—
Realized gain (loss) on commodity derivatives		7,782			(764	)		(3,320	)		(1,339	)
Unrealized gain (loss) on commodity derivatives		36,907			18,810			(7,678	)		(5,926	)
Other income (expense)		176			—			(109	)		—
Income before income tax		44,089			35,203			5,946			4,626
Income tax provision		17,102			12,756			2,153			1,681
Net income	$	26,987		$	22,447		$	3,793		$	2,945
Basic net income applicable to common    stockholders per common share	$	0.68		$	0.57		$	0.10		$	0.08
Diluted net income applicable to common    stockholders per common share	$	0.68		$	0.57		$	0.10		$	0.08

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Summary of Significant Accounting Policies - Summary of Oil and Gas Properties (Detail) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Mineral interests in properties:
Unproved leasehold costs	$ 33,596	$ 37,853
Proved leasehold costs	44,643	44,122
Wells and related equipment and facilities	1,774,314	1,753,649
Support equipment	8,002	9,545
Uncompleted wells, equipment and facilities	9,219	8,612
Total costs	1,869,774	1,853,781
Less accumulated depreciation, depletion and amortization	(780,412)	(702,139)
Net capitalized costs	$ 1,089,362	$ 1,151,642

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Summary of Significant Accounting Policies - Additional Information (Detail)		12 Months Ended
	Jan. 02, 2016 USD ($)	Dec. 31, 2016 USD ($) Well Segment	Dec. 31, 2015 USD ($) Well	Dec. 31, 2014 USD ($)
Summary Of Significant Accounting Policies [Line Items]
Number of exploratory wells capitalized | Well		0	0
Capitalized interest cost		$ 0
Depreciation depletion and amortization for oil & gas		78,700,000	$ 108,800,000	$ 106,200,000
Impairment of oil and gas properties and equipment		0	220,197,000	0
Depreciation expense for other property and equipment		$ 343,000	563,000	588,000
Tax benefit		50.00%
Uncertain tax positions		$ 0	0
Number of days in which payment is to be made		30 days
Realized gains on commodity derivatives		$ 200,000	4,800,000
Exploration expenses		$ 3,923,000	$ 4,439,000	$ 3,831,000
Number of business segment | Segment		1
New Accounting Pronouncement, Early Adoption, Effect [Member]
Summary Of Significant Accounting Policies [Line Items]
Increase in accumulated earnings	$ 1,700,000
Customer Concentration Risk [Member] | DCP Midstream, LLC [Member]
Summary Of Significant Accounting Policies [Line Items]
Sales to customers		46.00%	36.00%	30.00%
Customer Concentration Risk [Member] | JP Energy Permian, LLC [Member]
Summary Of Significant Accounting Policies [Line Items]
Sales to customers		54.00%	63.00%	69.00%
Drilling Contracts [Member]
Summary Of Significant Accounting Policies [Line Items]
Exploration expenses		$ 2,200,000
Minimum [Member]
Summary Of Significant Accounting Policies [Line Items]
Estimated useful lives of furniture, fixtures and equipment		3 years
Minimum [Member] | Oil and Gas [Member]
Summary Of Significant Accounting Policies [Line Items]
Number of days in which payment is to be made		30 days
Maximum [Member]
Summary Of Significant Accounting Policies [Line Items]
Estimated useful lives of furniture, fixtures and equipment		15 years
Maximum [Member] | Oil and Gas [Member]
Summary Of Significant Accounting Policies [Line Items]
Number of days in which payment is to be made		60 days
Proved Property Impairment [Member]
Summary Of Significant Accounting Policies [Line Items]
Impairment of oil and gas properties and equipment		$ 0	$ 214,700,000
Unproved Property Impairment [Member]
Summary Of Significant Accounting Policies [Line Items]
Impairment of oil and gas properties and equipment		$ 0	$ 5,500,000	$ 0

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Summary of Significant Accounting Policies - Summary of Accrued Liabilities (Detail) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Regulatory Assets [Abstract]
Capital expenditures accrual	$ 1,067	$ 3,476
Operating expenses and other	6,750	9,988
Total	$ 7,817	$ 13,464

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Summary of Significant Accounting Policies - Reconciliations of Numerators and Denominators of Basic and Diluted Earnings Per Share (Detail) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended												12 Months Ended
	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Earnings Per Share [Abstract]
Net (loss) income — basic	$ (13,475)	$ (9,073)	$ (16,035)	$ (13,660)	$ (5,759)	$ (148,787)	$ (11,850)	$ (7,708)	$ 26,987	$ 22,447	$ 3,793	$ 2,945	$ (52,243)	$ (174,104)	$ 56,172
Weighted average shares — basic													41,488,206	40,464,283	39,407,733
Dilution effect of share-based compensation, treasury method															12,132
Weighted average shares — diluted													41,488,206	40,464,283	39,419,865
Basic	$ (0.32)	$ (0.22)	$ (0.39)	$ (0.33)	$ (0.14)	$ (3.67)	$ (0.29)	$ (0.19)	$ 0.68	$ 0.57	$ 0.10	$ 0.08	$ (1.26)	$ (4.30)	$ 1.43
Diluted	$ (0.32)	$ (0.22)	$ (0.39)	$ (0.33)	$ (0.14)	$ (3.67)	$ (0.29)	$ (0.19)	$ 0.68	$ 0.57	$ 0.10	$ 0.08	$ (1.26)	$ (4.30)	$ 1.42

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Summary of Significant Accounting Policies - Reconciliations of Numerators and Denominators of Basic and Diluted Earnings Per Share (Parenthetical) (Detail) - shares	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Employee Stock Option [Member]
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Antidilutive securities excluded from computation of earnings per common share	39,000	39,000

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Exchange Transactions - Additional Information (Detail)	Jan. 30, 2017 USD ($)	Jan. 27, 2017 USD ($)	Nov. 02, 2016 USD ($) $ / shares shares	Jan. 26, 2017 shares	Dec. 31, 2016 USD ($) $ / shares shares	Dec. 31, 2015 $ / shares shares
Exchange Transactions [Line Items]
Common stock, par value | $ / shares					$ 0.01	$ 0.01
Common stock, shares authorized | shares					90,000,000	90,000,000
7% Senior Notes Due 2021 [Member]
Exchange Transactions [Line Items]
Debt exchange to common stock, principal amount			$ 130,552,000
Debt conversion, interest rate of debt			7.00%
7% Senior Notes Due 2021 [Member] | Initial Exchange [Member]
Exchange Transactions [Line Items]
Common stock, par value | $ / shares			$ 0.01
Common stock, shares authorized | shares					90,000,000
7% Senior Notes Due 2021 [Member] | Initial Exchange [Member] | Subsequent Event [Member]
Exchange Transactions [Line Items]
Common stock, shares authorized | shares				180,000,000
Debt exchange date		Jan. 27, 2017
Payments of accrued interest		$ 1,100,000
7% Senior Notes Due 2021 [Member] | Initial Exchange [Member] | Prepaid Expenses and Other Current Assets [Member]
Exchange Transactions [Line Items]
Costs related to debt exchange					$ 2,100,000
7% Senior Notes Due 2021 [Member] | Follow-On Exchange [Member] | Subsequent Event [Member]
Exchange Transactions [Line Items]
Debt exchange to common stock, remaining principal amount	$ 99,768,000
Conversion ratio of senior notes to common stock shares	0.276
Debt exchange, principal amount denominator for conversion into common stock	$ 1,000
Minimum subscription requirements	$ 0
Common Stock [Member] | 7% Senior Notes Due 2021 [Member] | Initial Exchange [Member]
Exchange Transactions [Line Items]
Debt exchange to common stock, shares issued | shares			39,165,600

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Long-Term Debt - Schedule of Long Term Debt (Detail) - USD ($) $ in Thousands	Dec. 31, 2016	May 03, 2016	Dec. 31, 2015
Debt Instrument [Line Items]
Senior secured credit facility, net	$ 271,696		$ 270,748
Senior notes, net	226,653		225,839
Total long-term debt	498,349		496,587
Senior Notes [Member]
Debt Instrument [Line Items]
Principal	230,320		230,320
Debt issuance costs	(3,667)		(4,481)
Senior notes, net	226,653		225,839
Senior Secured Credit Facility [Member]
Debt Instrument [Line Items]
Outstanding borrowings	273,000		273,000
Debt issuance costs	(1,304)	$ (200)	(2,252)
Senior secured credit facility, net	$ 271,696		$ 270,748

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Long-Term Debt - Additional Information (Detail)				3 Months Ended			12 Months Ended
	Dec. 15, 2016 USD ($)	Nov. 02, 2016 USD ($)	May 03, 2016 USD ($)	Jun. 30, 2016 USD ($)	Dec. 31, 2015 USD ($)	Sep. 30, 2015 USD ($)	Dec. 31, 2016 USD ($)	Dec. 31, 2015 USD ($)	Mar. 31, 2016 USD ($)	Jun. 30, 2013 USD ($)
Line of Credit Facility [Line Items]
Debt issuance costs written off				$ 563,000			$ 563,000
Senior notes, net					$ 225,839,000		226,653,000	$ 225,839,000
Gain on extinguishment of debt					9,080,000	$ 1,483,000		10,563,000
Senior Notes [Member]
Line of Credit Facility [Line Items]
Debt issuance costs					4,481,000		3,667,000	4,481,000
Senior notes, net					225,839,000		$ 226,653,000	225,839,000
7% Senior Notes Originated June 11, 2013 [Member] | Senior Notes [Member]
Line of Credit Facility [Line Items]
Senior notes, net										$ 250,000,000
Stated interest rate							7.00%
Debt instrument payment of interest							Semi-annually on June 15 and December 15.
Semi-annual interest payment amount	$ 8,100,000
Proceeds from issuance of senior notes							$ 243,000,000
Repurchased senior notes face value					19,700,000			19,700,000
Repurchased price of senior notes								8,800,000
Gain on extinguishment of debt								10,600,000
Debt exchange to common stock, principal amount		$ 130,600,000
Future interest savings		$ 40,000,000
Senior Secured Credit Facility [Member]
Line of Credit Facility [Line Items]
Senior secured credit facility, borrowing base			$ 325,000,000				325,000,000		$ 450,000,000
Senior secured facility, maximum borrowing capacity							$ 1,000,000,000
Maturity period of senior secured credit facility							May 07, 2019
Annual commitment fee of unused borrowings							0.50%
Senior secured credit facility, interest rate description							Borrowings under the Credit Facility bear interest based on the agent bank’s prime rate plus an applicable margin ranging from 1.50% to 2.50%, or the sum of the LIBOR rate plus an applicable margin ranging from 2.50% to 3.50%. In addition, we pay an annual commitment fee of 0.50% of unused borrowings available.
Senior secured credit facility					273,000,000		$ 273,000,000	273,000,000
Interest rate applicable of senior secured credit facility							3.30%
Unused letters of credit outstanding					300,000		$ 600,000	300,000
Production from liens covering the oil and gas properties							90.00%
Interest coverage ratio, through December 31, 2018			1.5
Interest coverage ratio, thereafter			2.0
Increase in applicable margin rates on borrowings			1.00%
Second lien indebtedness			$ 150,000,000
Cash and cash equivalents, minimum threshold to reduce outstanding borrowings under credit facility			35,000,000
Debt issuance costs written off			600,000
Debt issuance costs			$ 200,000		$ 2,252,000		$ 1,304,000	$ 2,252,000
Outstanding equity interests ownership percentage							50.00%
Senior Secured Credit Facility [Member] | Covenants Agreements One [Member]
Line of Credit Facility [Line Items]
Covenant description							 a consolidated interest coverage ratio covenant (as defined in the Credit Facility) that requires us to maintain a ratio of consolidated EBITDAX to cash Interest Expense (as defined in the Credit Facility) as of the last day of any fiscal quarter of not less than 1.25 to 1.0 (or 1.0 to 1.0 following the issuance of second lien indebtedness) through December 31, 2017, a ratio of not less than 1.5 to 1.0 through December 31, 2018, and a ratio of not less than 2.0 to 1.0 thereafter, and  a consolidated modified current ratio covenant (as defined in the Credit Facility) that requires us to maintain a ratio of not less than 1.0 to 1.0 as of the last day of any fiscal quarter.
Senior Secured Credit Facility [Member] | Before Second Lien Indebtedness [Member]
Line of Credit Facility [Line Items]
Interest coverage ratio, through December 31, 2017			1.25
Senior Secured Credit Facility [Member] | Before Second Lien Indebtedness [Member] | Covenants Agreements One [Member]
Line of Credit Facility [Line Items]
Minimum current ratio							1.25
Senior Secured Credit Facility [Member] | After Second Lien Indebtedness [Member]
Line of Credit Facility [Line Items]
Interest coverage ratio, through December 31, 2017			1.0
Senior Secured Credit Facility [Member] | After Second Lien Indebtedness [Member] | Covenants Agreements One [Member]
Line of Credit Facility [Line Items]
Minimum current ratio							1.0
Senior Secured Credit Facility [Member] | Minimum [Member] | Prime Rate [Member]
Line of Credit Facility [Line Items]
Senior secured credit facility, marginal percentage							1.50%
Senior Secured Credit Facility [Member] | Minimum [Member] | London Interbank Offered Rate (LIBOR) [Member]
Line of Credit Facility [Line Items]
Senior secured credit facility, marginal percentage							2.50%
Senior Secured Credit Facility [Member] | Maximum [Member] | Prime Rate [Member]
Line of Credit Facility [Line Items]
Senior secured credit facility, marginal percentage							2.50%
Senior Secured Credit Facility [Member] | Maximum [Member] | London Interbank Offered Rate (LIBOR) [Member]
Line of Credit Facility [Line Items]
Senior secured credit facility, marginal percentage							3.50%

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Termination Costs - Additional Information (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Sep. 30, 2015
Restructuring Cost and Reserve [Line Items]
Severance expenses		$ 1,436
Current Liabilities [Member]
Restructuring Cost and Reserve [Line Items]
Termination costs recorded in current liabilities			$ 1,400
Employee Severance [Member]
Restructuring Cost and Reserve [Line Items]
Severance expenses	$ 300
Employee Severance [Member] | General and Administrative Expense [Member]
Restructuring Cost and Reserve [Line Items]
Benefit recorded in share-based compensation expense	$ 300

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Share-Based Compensation - Additional Information (Detail) - USD ($)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Amendment effective date	Jun. 02, 2016
Share-based compensation expense	$ 6,300,000	$ 8,000,000	$ 8,200,000
Shares subject to stock options, granted	0	0	0
Shares subject to stock options, shares exercisable	38,525
Weighted average exercise price, outstanding	$ 12.00
Weighted average remaining contractual term, outstanding	10 months 6 days
Number of stock options exercised	0	0	0
Subsequent restricted share award	1,443,256
Current fiscal year employer matching contribution description	We make a matching contribution equal to 100% of each pre-tax dollar contributed by the participant on the first 3% of eligible compensation and 50% on the next 2% of eligible compensation
Contributions to employee benefit plan	$ 338,000	$ 404,000	$ 310,000
Primary [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Employer matching contribution, percentage	100.00%
Secondary [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Employer matching contribution, percentage	50.00%
Non-Employee Director [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based compensation expense	$ 214,000	$ 735,000	749,000
Forfeiture Benefit Adjustments Member [Member] | Executive Officers [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Forfeited stock awards			$ 1,100,000
Nonvested Shares [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares grant	1,318,229	1,278,329	992,919
Average grant date fair value	$ 2,500,000	$ 6,200,000	$ 14,400,000
Unrecognized compensation expense related to nonvested shares	$ 4,000,000
Nonvested outstanding weighted average remaining service period	2 years
Nonvested Shares [Member] | Executive Officers [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Additional shares grant	550,272	724,249	245,157
Additional share grant fair value	$ 300,000	$ 4,500,000	$ 4,500,000
Cash Settled Performance Shares [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share awards, subject to certain performance conditions	1,100,543
Fair market value of shares subject to performance conditions	$ 1,000,000
Service period	3 years
Cash Settled Performance Shares [Member] | General and Administrative Expenses [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based compensation expense	$ 1,300,000
Cash Settled Performance Shares [Member] | Current Liability [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based compensation, liability	600,000
Cash Settled Performance Shares [Member] | Non-Current Liability [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based compensation, liability	700,000
Performance Shares [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Fair market value of shares subject to performance conditions	$ 2,900,000
Service period	3 years
Subsequent restricted share award	962,171
Total Shareholder Return Performance Stock Awards [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Subsequent restricted share award	481,085
2007 Plan [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
The maximum number of common stock	6,125,000

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Share-Based Compensation - Summary of Status of Nonvested Shares (Detail) - $ / shares	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Disclosure Of Compensation Related Costs Sharebased Payments [Abstract]
Nonvested Shares, Beginning Balance	1,735,256	1,122,410	699,231
Nonvested Shares, Granted	1,318,229	1,278,329	992,919
Nonvested Shares, Vested	(992,461)	(419,222)	(400,429)
Nonvested Shares, Canceled	(107,960)	(246,261)	(169,311)
Nonvested Shares, Ending Balance	1,953,064	1,735,256	1,122,410
Weighted Average Grant-Date Fair Value, Nonvested, Beginning Balance	$ 8.60	$ 16.52	$ 23.70
Weighted Average Grant-Date Fair Value, Nonvested, Granted	1.90	4.87	14.48
Weighted Average Grant-Date Fair Value, Nonvested, Vested	7.03	15.26	20.18
Weighted Average Grant-Date Fair Value, Nonvested, Canceled	17.33	14.30	25.57
Weighted Average Grant-Date Fair Value, Nonvested, Ending Balance	$ 4.39	$ 8.60	$ 16.52

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Income Taxes - Schedule of Provision for Income Taxes (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Current:
Federal		$ (265)	$ (25)
Total current provision for income taxes		(265)	(25)
Deferred:
Federal	$ (24,957)	(91,716)	32,754
State	539	(1,424)	963
Total deferred provision for income taxes	$ (24,418)	$ (93,140)	$ 33,717

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Income Taxes - Total Income Tax Expense Differed from Amounts Computed by Applying U.S. Federal Statutory Tax Rates to Pre-Tax Income (Detail) - USD ($) $ in Thousands	3 Months Ended												12 Months Ended
	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Income Tax Disclosure [Abstract]
Statutory tax at 35%													$ (26,831)	$ (93,628)	$ 31,452
State taxes, net of federal impact													578	(1,463)	989
Share-based compensation tax shortfall													1,826	1,939	1,670
Permanent differences													11	26	37
Other differences													(2)	(1,035)	(456)
Valuation allowance														756
Total	$ (3,571)	$ (4,915)	$ (8,687)	$ (7,245)	$ (284)	$ (81,756)	$ (7,369)	$ (3,996)	$ 17,102	$ 12,756	$ 2,153	$ 1,681	$ (24,418)	$ (93,405)	$ 33,692

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Income Taxes - Total Income Tax Expense Differed from Amounts Computed by Applying U.S. Federal Statutory Tax Rates to Pre-Tax Income (Parenthetical) (Detail)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Income Tax Disclosure [Abstract]
Statutory tax rate	35.00%	35.00%	35.00%

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Income Taxes - Additional Information (Detail) - USD ($) $ in Thousands		12 Months Ended
	Jan. 02, 2016	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Income Taxes [Line Items]
Share-based compensation tax shortfall		$ 1,826	$ 1,939	$ 1,670
Net deferred tax assets and liabilities recorded as long-term liability		$ 5,600	$ 31,800
NOLs, limitations on use		A change in ownership of our common stock by more than 50% within a three-year period would result in a substantial portion of our NOLs being eliminated or becoming restricted, and we would need to reduce our deferred tax assets to reflect the restricted use of these NOLs when such an ownership change occurs. An ownership change would establish an annual limitation on the amount of our pre-change NOLs that we could use to offset our taxable income in any future taxable year to an amount generally equal to the value of our common stock immediately before the ownership change, multiplied by the federal long-term tax exempt rate for the month of the ownership change.
New Accounting Pronouncement, Early Adoption, Effect [Member]
Income Taxes [Line Items]
Increase in accumulated earnings and NOLs	$ 1,700

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Income Taxes - Significant Components of Net Deferred Tax Assets and Liabilities (Detail) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Income Tax Disclosure [Abstract]
Net operating loss carryforwards	$ 155,018	$ 88,230
Unrealized loss on commodity derivatives	1,732
Other	892	1,672
Total deferred tax assets	157,642	89,902
Difference in depreciation, depletion and capitalization methods — oil and gas properties	(162,501)	(118,534)
Unrealized gain on commodity derivatives		(2,391)
Total deferred tax liabilities	(162,501)	(120,925)
Valuation allowance	(756)	(756)
Net deferred tax liability	$ (5,615)	$ (31,779)

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Income Taxes - Schedule of NOLs (Detail) $ in Thousands	12 Months Ended
	Dec. 31, 2016 USD ($)
Operating Loss Carryforwards [Line Items]
Amounts	$ 442,904
Expiration Dates 2030 [Member]
Operating Loss Carryforwards [Line Items]
Amounts	$ 5,790
Expiration Dates	2030
Expiration Dates 2031 [Member]
Operating Loss Carryforwards [Line Items]
Amounts	$ 19,686
Expiration Dates	2031
Expiration Date 2032 [Member]
Operating Loss Carryforwards [Line Items]
Amounts	$ 54,714
Expiration Dates	2032
Expiration Date 2033 [Member]
Operating Loss Carryforwards [Line Items]
Amounts	$ 78
Expiration Dates	2033
Expiration Date 2034 [Member]
Operating Loss Carryforwards [Line Items]
Amounts	$ 56,505
Expiration Dates	2034
Expiration Date 2035 [Member]
Operating Loss Carryforwards [Line Items]
Amounts	$ 116,482
Expiration Dates	2035
Expiration Date 2036 [Member]
Operating Loss Carryforwards [Line Items]
Amounts	$ 189,649
Expiration Dates	2036

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Derivative Instruments and Fair Value Measurements - Commodity Derivatives Volumes and Prices (Detail)		12 Months Ended
	Mar. 09, 2017 MMBTU $ / MMBTU $ / bbl bbl	Dec. 31, 2016 MMBTU $ / MMBTU
Natural Gas January 2017 - March 2017 Contract One [Member] | Swap [Member]
Derivatives Fair Value [Line Items]
Volume Transacted | MMBTU		100,000
Contract Price		2.463
Natural Gas January 2017 - March 2017 Contract Two [Member] | Swap [Member]
Derivatives Fair Value [Line Items]
Volume Transacted | MMBTU		300,000
Contract Price		2.45
Natural Gas January 2017 - March 2017 Contract Three [Member] | Swap [Member]
Derivatives Fair Value [Line Items]
Volume Transacted | MMBTU		200,000
Contract Price		3.287
Natural Gas January 2017 - December 2017 Contract [Member] | Collar [Member]
Derivatives Fair Value [Line Items]
Volume Transacted | MMBTU		100,000
Natural Gas January 2017 - December 2017 Contract [Member] | Collar [Member] | Minimum [Member]
Derivatives Fair Value [Line Items]
Contract Price		3.00
Natural Gas January 2017 - December 2017 Contract [Member] | Collar [Member] | Maximum [Member]
Derivatives Fair Value [Line Items]
Contract Price		3.65
Natural Gas April 2017 - December 2017 Contract One [Member] | Collar [Member]
Derivatives Fair Value [Line Items]
Volume Transacted | MMBTU		200,000
Natural Gas April 2017 - December 2017 Contract One [Member] | Collar [Member] | Minimum [Member]
Derivatives Fair Value [Line Items]
Contract Price		2.30
Natural Gas April 2017 - December 2017 Contract One [Member] | Collar [Member] | Maximum [Member]
Derivatives Fair Value [Line Items]
Contract Price		2.60
Natural Gas April 2017 - December 2017 Contract Two [Member] | Collar [Member]
Derivatives Fair Value [Line Items]
Volume Transacted | MMBTU		200,000
Natural Gas April 2017 - December 2017 Contract Two [Member] | Collar [Member] | Minimum [Member]
Derivatives Fair Value [Line Items]
Contract Price		3.00
Natural Gas April 2017 - December 2017 Contract Two [Member] | Collar [Member] | Maximum [Member]
Derivatives Fair Value [Line Items]
Contract Price		3.44
Natural Gas April 2017 - December 2017 Contract Three [Member] | Collar [Member]
Derivatives Fair Value [Line Items]
Volume Transacted | MMBTU		200,000
Natural Gas April 2017 - December 2017 Contract Three [Member] | Collar [Member] | Minimum [Member]
Derivatives Fair Value [Line Items]
Contract Price		3.00
Natural Gas April 2017 - December 2017 Contract Three [Member] | Collar [Member] | Maximum [Member]
Derivatives Fair Value [Line Items]
Contract Price		3.50
Natural Gas January 2018 - December 2018 Contract One [Member] | Swap [Member] | Subsequent Event [Member]
Derivatives Fair Value [Line Items]
Volume Transacted | MMBTU	200,000
Contract Price	3.085
Natural Gas January 2018 - December 2018 Contract Two [Member] | Swap [Member] | Subsequent Event [Member]
Derivatives Fair Value [Line Items]
Volume Transacted | MMBTU	250,000
Contract Price	3.084
NGLs (C2 - Ethane) February 2017 - December 2017 Contract [Member] | Swap [Member] | Subsequent Event [Member]
Derivatives Fair Value [Line Items]
Volume Transacted | bbl	1,050
Contract Price | $ / bbl	11.34
NGLs (C3 - Propane) February 2017 - December 2017 Contract [Member] | Swap [Member] | Subsequent Event [Member]
Derivatives Fair Value [Line Items]
Volume Transacted | bbl	750
Contract Price | $ / bbl	27.916
NGLs (IC4 - Isobutane) February 2017 - December 2017 Contract [Member] | Swap [Member] | Subsequent Event [Member]
Derivatives Fair Value [Line Items]
Volume Transacted | bbl	75
Contract Price | $ / bbl	36.7325
NGLs (NC4 - Butane) February 2017 - December 2017 Contract [Member] | Swap [Member] | Subsequent Event [Member]
Derivatives Fair Value [Line Items]
Volume Transacted | bbl	250
Contract Price | $ / bbl	35.9205

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Derivative Instruments and Fair Value Measurements - Summary of Fair Value of Open Commodity Derivatives (Detail) - Commodity Derivatives [Member] - Unrealized (Loss) Gain on Commodity Derivatives [Member] - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Derivatives Fair Value [Line Items]
Derivatives not designated as hedging instruments, fair value of Liability derivative	$ (4,880)
Derivatives not designated as hedging instruments, fair value of assets derivative		$ 6,737

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Derivative Instruments and Fair Value Measurements - Summary of Change in Fair Value of Commodity Derivatives (Detail) - USD ($) $ in Thousands	3 Months Ended												12 Months Ended
	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Derivatives Fair Value [Line Items]
Total gain (loss) on commodity derivatives	$ 442	$ 781	$ 1,409	$ 3,500	$ 14,552	$ 12,755	$ 9,281	$ 15,901	$ 7,782	$ (764)	$ (3,320)	$ (1,339)	$ 6,132	$ 52,489	$ 2,359
Derivatives Not Designated as Hedging Instruments [Member]
Derivatives Fair Value [Line Items]
Total gain (loss) on commodity derivatives													(5,484)	19,275	44,472
Derivatives Not Designated as Hedging Instruments [Member] | Unrealized (Loss) Gain on Commodity Derivatives [Member]
Derivatives Fair Value [Line Items]
Total gain (loss) on commodity derivatives													(11,616)	(33,214)	42,113
Derivatives Not Designated as Hedging Instruments [Member] | Realized Gain on Commodity Derivatives [Member]
Derivatives Fair Value [Line Items]
Total gain (loss) on commodity derivatives													$ 6,132	$ 52,489	$ 2,359

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Derivative Instruments and Fair Value Measurements - Additional Information (Detail) - USD ($)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Sep. 30, 2015
Derivative Instruments And Hedging Activities Disclosures [Line Items]
Impairment of oil and gas properties and equipment	$ 0	$ 220,197,000	$ 0
Proved oil and gas property fair value				$ 22,000,000
Proved Property Impairment [Member]
Derivative Instruments And Hedging Activities Disclosures [Line Items]
Impairment of oil and gas properties and equipment	$ 0	$ 214,700,000

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Derivative Instruments and Fair Value Measurements - Summary of Financial Instruments Not Recorded at Fair Value (Detail) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Derivative Instruments And Hedging Activities Disclosure [Abstract]
Senior notes, net	$ 226,653	$ 225,839
Senior Notes, Fair Value	$ 206,286

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Commitments and Contingencies - Additional Information (Detail)	1 Months Ended	12 Months Ended
	Jan. 31, 2017 USD ($) ft²	Dec. 31, 2017 USD ($) ExecutiveOfficer	Dec. 31, 2016 USD ($) ExecutiveOfficer	Dec. 31, 2015 USD ($)	Dec. 31, 2014 USD ($)
Other Commitments [Line Items]
Number of executive officers contained automatic renewal provisions | ExecutiveOfficer			4
Contractual settlement			$ 1,400,000
Non-Cancelable operating lease expiration date			2021
Non-Cancelable lease agreement for office space, expiration date			Mar. 31, 2020
Rent expense under lease arrangements			$ 1,025,000	$ 1,002,000	$ 717,000
Legal settlement received from a service provider			1,100,000
Subsequent Event [Member]
Other Commitments [Line Items]
Non-Cancelable lease agreement for office space, expiration date	Sep. 30, 2021
Reduction in aggregate leased space | ft²	5,500
Reduction in contractual obligations during next three years	$ 400,000
Increase in total contractual obligations	$ 900,000
Scenario, Forecast [Member]
Other Commitments [Line Items]
Number of executive officers contained automatic renewal provisions | ExecutiveOfficer		2
Employment Agreements [Member]
Other Commitments [Line Items]
Commitment under contracts			$ 5,700,000
Employment Agreements [Member] | Scenario, Forecast [Member]
Other Commitments [Line Items]
Commitment under contracts		$ 600,000

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Commitments and Contingencies - Schedule of Years of Future Minimum Rental Payments Required Under Operating Lease Arrangements (Detail) $ in Thousands	Dec. 31, 2016 USD ($)
Commitments And Contingencies Disclosure [Abstract]
2017	$ 989
2018	979
2019	980
2020	248
2021	2
Total	$ 3,198

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Oil and Gas Producing Activities - Schedule of Information Regarding Costs Incurred for Oil and Gas Property Acquisition, Development and Exploration Activities (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Extractive Industries [Abstract]
Unproved properties	$ 17	$ 653	$ 4,578
Exploration costs	3,923	4,439	3,831
Development costs	15,884	146,237	382,995
Total costs incurred	$ 19,824	$ 151,329	$ 391,404

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Oil and Gas Producing Activities - Schedule of Information Regarding Costs Incurred for Oil and Gas Property Acquisition, Development and Exploration Activities (Parenthetical) (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Development costs	$ 15,884	$ 146,237	$ 382,995
Non-cash Asset Retirement Obligations [Member]
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Development costs	$ 36,000	$ 151,000	$ 898,000

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Oil and Gas Producing Activities - Schedule of Information Regarding Results of Operations for Oil and Gas Producing Activities (Detail) - USD ($)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Extractive Industries [Abstract]
Revenues	$ 90,302,000	$ 131,336,000	$ 258,529,000
Production costs	(27,467,000)	(40,057,000)	(48,635,000)
Exploration expense	(3,923,000)	(4,439,000)	(3,831,000)
Depletion	(79,044,000)	(109,319,000)	(106,802,000)
Impairment of oil and gas properties	0	(220,197,000)	0
Income tax benefit (expense)	7,144,000	86,120,000	(35,387,000)
Results of operations	$ (12,988,000)	$ (156,556,000)	$ 63,874,000

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Disclosures About Oil and Gas Producing Activities - Commodity Prices Inclusive of Adjustments for Quality and Location Used in Determining Future Net Revenues Related to Standardized Measure Calculation (Detail) - Reserve Estimate [Member]	12 Months Ended
	Dec. 31, 2016 $ / bbl $ / Mcf	Dec. 31, 2015 $ / bbl $ / Mcf	Dec. 31, 2014 $ / bbl $ / Mcf
Oil (MBbls) [Member]
Average Sales Price and Production Costs Per Unit of Production [Line Items]
Commodity Prices	42.69	50.16	94.56
NGLs (MBbls) [Member]
Average Sales Price and Production Costs Per Unit of Production [Line Items]
Commodity Prices	14.12	15.13	31.50
Natural Gas (MMcf) [Member]
Average Sales Price and Production Costs Per Unit of Production [Line Items]
Commodity Prices | $ / Mcf	2.47	2.64	4.55

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Disclosures About Oil and Gas Producing Activities - Summary of Changes in Quantities of Proved Oil, NGL and Natural Gas Reserves (Detail)	12 Months Ended
	Dec. 31, 2016 MBoe MBbls MMcf	Dec. 31, 2015 MBoe MBbls MMcf	Dec. 31, 2014 MBoe MBbls MMcf
Reserve Quantities [Line Items]
Production | MMcf	(1,330)	(1,530)	(1,390)
Proved Developed and Proved Undeveloped Reserves, Beginning Balance | MBoe	166,646	146,248	114,661
Extensions and discoveries | MBoe	16,651	34,895	43,247
Production | MBoe	(4,759)	(5,787)	(5,281)
Revisions to previous estimates | MBoe	(22,161)	(8,710)	(6,379)
Proved Developed and Proved Undeveloped Reserves, Ending Balance | MBoe	156,377	166,646	146,248
Oil (MBbls) [Member]
Reserve Quantities [Line Items]
Proved Developed and Proved Undeveloped Reserves, Beginning Balance	54,496	55,338	46,067
Extensions and discoveries	6,529	11,054	19,347
Production	(1,275)	(1,882)	(2,024)
Revisions to previous estimates	(9,719)	(10,014)	(8,052)
Proved Developed and Proved Undeveloped Reserves, Ending Balance	50,031	54,496	55,338
NGLs (MBbls) [Member]
Reserve Quantities [Line Items]
Proved Developed and Proved Undeveloped Reserves, Beginning Balance	49,486	40,907	32,593
Extensions and discoveries	4,564	10,630	10,658
Production	(1,529)	(1,694)	(1,461)
Revisions to previous estimates	(4,887)	(357)	(883)
Proved Developed and Proved Undeveloped Reserves, Ending Balance	47,634	49,486	40,907
Natural Gas (MMcf) [Member]
Reserve Quantities [Line Items]
Proved Developed and Proved Undeveloped Reserves, Beginning Balance | MMcf	375,988	300,020	216,002
Extensions and discoveries | MMcf	33,347	79,268	79,454
Production | MMcf	(11,734)	(13,262)	(10,773)
Revisions to previous estimates | MMcf	(45,324)	9,962	15,337
Proved Developed and Proved Undeveloped Reserves, Ending Balance | MMcf	352,277	375,988	300,020

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Disclosures About Oil and Gas Producing Activities - Summary of Changes in Quantities of Proved Oil, NGL and Natural Gas Reserves (Parenthetical) (Detail)	12 Months Ended
	Dec. 31, 2016 MBoe MBbls MMcf	Dec. 31, 2015 MBoe MBbls MMcf	Dec. 31, 2014 MBoe MBbls MMcf	Dec. 31, 2013 MBoe MBbls MMcf
Reserve Quantities [Line Items]
Field fuel | MMcf	1,330	1,530	1,390
Proved Developed Reserves | MBoe	58,875	61,856	60,220	45,189
Proved Undeveloped Reserves | MBoe	97,502	104,790	86,028	69,472
Oil (MBbls) [Member]
Reserve Quantities [Line Items]
Field fuel	1,275	1,882	2,024
Proved Developed Oil Reserves	13,466	15,667	17,978	13,646
Proved Undeveloped Oil Reserves	36,565	38,829	37,360	32,421
NGLs (MBbls) [Member]
Reserve Quantities [Line Items]
Field fuel	1,529	1,694	1,461
Proved Developed Oil Reserves	20,375	20,414	19,082	14,919
Proved Undeveloped Oil Reserves	27,259	29,072	21,825	17,674
Natural Gas (MMcf) [Member]
Reserve Quantities [Line Items]
Field fuel | MMcf	11,734	13,262	10,773
Proved Developed Oil Reserves | MMcf	150,208	154,652	138,961	99,742
Proved Undeveloped Oil Reserves | MMcf	202,069	221,335	161,059	116,260

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Disclosures About Oil and Gas Producing Activities - Additional Information (Detail)	12 Months Ended
	Dec. 31, 2016 MBoe MMcf	Dec. 31, 2015 MBoe MMcf	Dec. 31, 2014 MBoe MMcf
Reserve Quantities [Line Items]
Extensions and discoveries	16,651	34,895	43,247
Economic revisions	22,400	11,900	9,300
Production	4,800	5,800	5,300
Field fuel | MMcf	1,330	1,530	1,390
Significant changes in reserves	Extensions and discoveries for 2016 were 16.7 MMBoe, primarily attributable to our development project in the Wolfcamp shale oil resource play in the Permian Basin. During 2016, we reclassified 22.4 MMBoe of proved undeveloped reserves to unproved reserves. The reserves reclassified are attributable to horizontal well locations in Project Pangea that are no longer expected to be developed within five years from their initial booking, as required by SEC rules. Revisions included an increase of 2.1 MMBoe resulting from cost reductions, updated well performance and technical parameters, offset by a decrease of 1.9 MMBoe due to lower commodity prices.	Extensions and discoveries for 2015 were 34.9 MMBoe, primarily attributable to our development project in the Wolfcamp shale oil resource play in the Permian Basin. During 2015, we reclassified 11.9 MMBoe of proved reserves to unproved reserves. The reserves reclassified are attributable to horizontal and vertical well locations in Project Pangea that are no longer expected to be developed within five years from their initial booking, as required by SEC rules. Revisions included an increase of 13 MMBoe resulting from cost reductions, updated well performance and technical parameters, offset by a decrease of 9.8 MMBoe due to lower commodity prices.	Extensions and discoveries for 2014 were 43.2 MMBoe, primarily attributable to our development project in the Wolfcamp shale oil resource play in the Permian Basin. During 2014, we reclassified 9.3 MMBoe of proved undeveloped reserves to unproved reserves. The reserves reclassified included 5.8 MMBoe attributable to vertical Canyon locations in Project Pangea that we do not plan to drill within five years from their initial booking, and 3.5 MMBoe attributable to horizontal Wolfcamp locations that are no longer included in our proved development plan. Revisions included an increase of 6.3 MMBoe attributable to updated well performance and an increase of 0.7 MMBoe due to pricing, offset by a decrease of 4.1 MMBoe resulting from updated technical parameters and costs.
Period for reclassification of proved reserves to unproved reserves	5 years	5 years
Increased revisions due to cost reduction, updated well Performance and technical parameters	2,100	13,000
Decreased revisions due to lower commodity prices	1,900	9,800
Increased revisions	(22,161)	(8,710)	(6,379)
Increased revision due to pricing			700
Southeast Project Pangea [Member]
Reserve Quantities [Line Items]
Economic revisions			5,800
Decreased revisions			4,100
Wolfcamp Shale Oil Resources [Member]
Reserve Quantities [Line Items]
Economic revisions			3,500
Increased revisions			6,300

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Disclosures About Oil and Gas Producing Activities - Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Natural Gas Reserves (Detail) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Extractive Industries [Abstract]
Future cash flows	$ 3,319,551	$ 4,097,568	$ 7,430,368
Future production costs	(1,054,211)	(1,237,888)	(1,704,333)
Future development costs	(829,926)	(934,814)	(1,247,446)
Future income tax expense	(132,834)	(307,374)	(1,267,025)
Future net cash flows	1,302,580	1,617,492	3,211,564
10% annual discount for estimated timing of cash flows	(1,004,825)	(1,157,097)	(2,155,749)
Standardized measure of discounted future net cash flows	$ 297,755	$ 460,395	$ 1,055,815	$ 676,277

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Disclosures About Oil and Gas Producing Activities - Summary of Changes in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Natural Gas Reserves (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Extractive Industries [Abstract]
Standardized measure of discounted future net cash flows, Beginning balance	$ 460,395	$ 1,055,815	$ 676,277
Net change in sales and transfer prices and in production (lifting) costs related to future production	(191,841)	(1,405,864)	(59,920)
Changes in estimated future development costs	17,405	231,900	(388,772)
Sales and transfers of oil and gas produced during the period	(62,835)	(91,278)	(209,893)
Net change due to extensions, discoveries and improved recovery	13,988	156,783	534,231
Net change due to revisions in quantity estimates	(25,236)	(59,305)	(78,801)
Previously estimated development costs incurred during the period	15,884	146,237	382,995
Accretion of discount	46,040	105,582	113,188
Other	(9,500)	6,915	(11,897)
Net change in income taxes	33,455	313,610	98,407
Standardized Measure of discounted future net cash flows	$ 297,755	$ 460,395	$ 1,055,815

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Supplementary Data - Selected Quarterly Financial Data (Detail) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended												12 Months Ended
	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Quarterly Financial Information Disclosure [Abstract]
Net revenues	$ 26,505	$ 23,749	$ 22,433	$ 17,615	$ 25,492	$ 33,941	$ 38,605	$ 33,298	$ 55,070	$ 68,124	$ 73,408	$ 61,927	$ 90,302	$ 131,336	$ 258,529
Net operating expenses	(33,564)	(32,201)	(34,534)	(34,869)	(38,671)	(272,462)	(46,970)	(45,686)	(50,136)	(45,525)	(50,812)	(44,899)	(135,168)	(403,789)	(191,372)
Interest expense, net	(7,086)	(7,067)	(6,808)	(6,298)	(6,436)	(6,465)	(6,243)	(5,922)	(5,715)	(5,442)	(5,357)	(5,137)	(27,259)	(25,066)	(21,651)
Gain on debt extinguishment					9,080	1,483								10,563
Write-off of debt issuance costs			(563)										(563)
Equity in earnings (losses) of investee									5		(186)				(181)
Realized gain on commodity derivatives	442	781	1,409	3,500	14,552	12,755	9,281	15,901	7,782	(764)	(3,320)	(1,339)	6,132	52,489	2,359
Unrealized (loss) gain on commodity derivatives	(3,343)	760	(8,076)	(957)	(10,285)	296	(13,904)	(9,321)	36,907	18,810	(7,678)	(5,926)	(11,616)	(33,214)	42,113
Other income (expense)		(10)	1,417	104	225	(91)	12	26	176		(109)		1,511	172	67
(LOSS) INCOME BEFORE INCOME TAX (BENEFIT) PROVISION	(17,046)	(13,988)	(24,722)	(20,905)	(6,043)	(230,543)	(19,219)	(11,704)	44,089	35,203	5,946	4,626	(76,661)	(267,509)	89,864
Income tax provision (benefit)	(3,571)	(4,915)	(8,687)	(7,245)	(284)	(81,756)	(7,369)	(3,996)	17,102	12,756	2,153	1,681	(24,418)	(93,405)	33,692
NET (LOSS) INCOME	$ (13,475)	$ (9,073)	$ (16,035)	$ (13,660)	$ (5,759)	$ (148,787)	$ (11,850)	$ (7,708)	$ 26,987	$ 22,447	$ 3,793	$ 2,945	$ (52,243)	$ (174,104)	$ 56,172
Basic net income (loss) applicable to common stockholders per common share	$ (0.32)	$ (0.22)	$ (0.39)	$ (0.33)	$ (0.14)	$ (3.67)	$ (0.29)	$ (0.19)	$ 0.68	$ 0.57	$ 0.10	$ 0.08	$ (1.26)	$ (4.30)	$ 1.43
Diluted net income (loss) applicable to common stockholders per common share	$ (0.32)	$ (0.22)	$ (0.39)	$ (0.33)	$ (0.14)	$ (3.67)	$ (0.29)	$ (0.19)	$ 0.68	$ 0.57	$ 0.10	$ 0.08	$ (1.26)	$ (4.30)	$ 1.42