Approach Resources 10Q 2015 Q3 Quarterly report

Approach Resources (AREXQ) 10-Q2015 Q3 Quarterly report

Content analysis

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended September 30, 2015

¨	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 No.)

One Ridgmar Centre 6500 West Freeway, Suite 800 Fort Worth, Texas		76116
(Address of principal executive offices)		(Zip Code)

(817) 989-9000

(Registrant’s telephone number, including area code)

N/A

(Former name, former address and former fiscal year, if changed since last report)

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. x Yes ¨ No

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

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

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

The number of shares of the registrant’s common stock, $0.01 par value, outstanding as of October 30, 2015, was 40,470,643.

PART I—FINANCIAL INFORMATION

Item 1.

Financial Statements.

Approach Resources Inc. and Subsidiaries

Unaudited Consolidated Balance Sheets

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


	September 30, 2015			December 31, 2014
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	319		$	432
Accounts receivable:
Joint interest owners		68			132
Oil, NGL and gas sales		14,848			19,635
Unrealized gain on commodity derivatives		16,201			39,951
Prepaid expenses and other current assets		1,116			929


Total current assets		32,552			61,079

PROPERTIES AND EQUIPMENT:
Oil and gas properties, at cost, using the successful efforts method of accounting		1,852,377			1,708,278
Furniture, fixtures and equipment		5,635			5,561


Total oil and gas properties and equipment		1,858,012			1,713,839
Less accumulated depletion, depreciation and amortization		(682,557	)		(382,180	)


Net oil and gas properties and equipment		1,175,455			1,331,659

Unrealized gain on commodity derivatives		821			—


Total assets	$	1,208,828		$	1,392,738


LIABILITIES AND STOCKHOLDERS’ EQUITY
CURRENT LIABILITIES:
Accounts payable	$	13,550		$	33,336
Oil, NGL and gas sales payable		4,611			8,536
Deferred income taxes – current		5,670			14,242
Accrued liabilities		21,364			50,738


Total current liabilities		45,195			106,852

NON-CURRENT LIABILITIES:
Senior secured credit facility, net		275,579			147,072
Senior notes, net		240,014			244,239
Deferred income taxes		26,128			110,677
Asset retirement obligations		10,035			9,571


Total liabilities		596,951			618,411

COMMITMENTS AND CONTINGENCIES

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, 40,442,397 and 39,814,199 issued and outstanding, respectively		400			399
Additional paid-in capital		578,782			572,888
Retained earnings		32,695			201,040


Total stockholders’ equity		611,877			774,327

Total liabilities and stockholders’ equity	$	1,208,828		$	1,392,738

See accompanying notes to these unaudited consolidated financial statements

Approach Resources Inc. and Subsidiaries

Unaudited Consolidated Statements of Operations

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


	Three Months Ended September 30,						Nine Months Ended September 30,
	2015			2014			2015			2014
REVENUES:
Oil, NGL and gas sales	$	33,941		$	68,124		$	105,844		$	203,459

EXPENSES:
Lease operating		7,681			7,665			21,744			23,462
Production and ad valorem taxes		2,700			3,335			8,502			12,429
Exploration		1,956			891			4,211			3,595
General and administrative (1)		7,270			7,675			22,882			23,612
Termination costs		1,436			—			1,436			—
Impairment of oil and gas properties		220,197			—			220,197			—
Depletion, depreciation and amortization		31,222			25,959			86,146			78,138

Total expenses		272,462			45,525			365,118			141,236


OPERATING (LOSS) INCOME		(238,521	)		22,599			(259,274	)		62,223

OTHER:
Interest expense, net		(6,465	)		(5,442	)		(18,630	)		(15,936	)
Gain on debt extinguishment		1,483			—			1,483			—
Equity in losses of investee		—			—			—			(186	)
Realized gain (loss) on commodity derivatives		12,755			(764	)		37,937			(5,423	)
Unrealized gain (loss) on commodity derivatives		296			18,810			(22,929	)		5,206
Other expense		(91	)		—			(53	)		(109	)


(LOSS) INCOME BEFORE INCOME TAX (BENEFIT) PROVISION		(230,543	)		35,203			(261,466	)		45,775
INCOME TAX (BENEFIT) PROVISION		(81,756	)		12,756			(93,121	)		16,590


NET (LOSS) INCOME	$	(148,787	)	$	22,447		$	(168,345	)	$	29,185


(LOSS) EARNINGS PER SHARE:
Basic	$	(3.67	)	$	0.57		$	(4.16	)	$	0.74

Diluted	$	(3.67	)	$	0.57		$	(4.16	)	$	0.74


WEIGHTED AVERAGE SHARES OUTSTANDING:
Basic		40,541,420			39,363,441			40,419,187			39,325,552
Diluted		40,541,420			39,379,779			40,419,187			39,340,961

(1) Includes non-cash share-based compensation expense as follows:

		1,708			1,965			6,000			5,726

See accompanying notes to these unaudited consolidated financial statements

Approach Resources Inc. and Subsidiaries

Unaudited Consolidated Statements of Cash Flows

(In thousands)


	Nine Months Ended September 30,
	2015			2014

OPERATING ACTIVITIES:
Net (loss) income	$	(168,345	)	$	29,185
Adjustments to reconcile net (loss) income to cash provided by operating activities:
Depletion, depreciation and amortization		86,146			78,138
Impairment of oil and gas properties		220,197			—
Amortization of debt issuance costs		1,178			1,151
Gain on debt extinguishment		(1,483	)		—
Unrealized loss (gain) on commodity derivatives		22,929			(5,206	)
Exploration expense		1,626			3,595
Share-based compensation expense		6,000			5,726
Deferred income tax (benefit) expense		(93,121	)		16,590
Equity in losses of investee		—			186
Other non-cash items		53			—
Changes in operating assets and liabilities:
Accounts receivable		4,851			2,090
Prepaid expenses and other current assets		(240	)		(169	)
Accounts payable		(216	)		(520	)
Oil, NGL and gas sales payable		(3,925	)		3,607
Accrued liabilities		6,865			1,092

Cash provided by operating activities		82,515			135,465


INVESTING ACTIVITIES:
Additions to oil and gas properties		(151,226	)		(297,122	)
Contribution to equity method investment		—			(186	)
Change in restricted cash		—			7,350
Additions to furniture, fixtures and equipment, net		(74	)		(2,672	)
Change in working capital related to investing activities		(55,915	)		12,765

Cash used in investing activities		(207,215	)		(279,865	)


FINANCING ACTIVITIES:
Borrowings under credit facility		241,500			231,421
Repayment of amounts outstanding under credit facility		(113,500	)		(141,921	)
Extinguishment of senior notes		(3,413	)		—
Debt issuance costs		—			(2,227	)

Cash provided by financing activities		124,587			87,273


CHANGE IN CASH AND CASH EQUIVALENTS		(113	)		(57,127	)
CASH AND CASH EQUIVALENTS, beginning of period	$	432		$	58,761


CASH AND CASH EQUIVALENTS, end of period	$	319		$	1,634


SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:
Cash paid for interest	$	13,216		$	10,529


SUPPLEMENTAL DISCLOSURE OF NON-CASH TRANSACTION:
Asset retirement obligations capitalized	$	151		$	428

See accompanying notes to these unaudited consolidated financial statements

Approach Resources Inc. and Subsidiaries

Notes to Consolidated Financial Statements (Unaudited)

September 30, 2015

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 engaged in the exploration, development, production and acquisition of oil and gas properties. We focus on finding and developing oil and natural gas reserves in oil shale and tight gas sands. Substantially all of our properties are located in the Permian Basin in West Texas.

Consolidation, Basis of Presentation and Significant Estimates

The interim consolidated financial statements of the Company are unaudited and contain all adjustments (consisting primarily of normal recurring accruals) necessary for a fair statement of the results for the interim periods presented. Results for interim periods are not necessarily indicative of results to be expected for a full year, due in part to the volatility in prices for oil, natural gas liquids (“NGLs”) and gas, future commodity prices for commodity derivative contracts, global economic and financial market conditions, interest rates, access to sources of liquidity, estimates of reserves, drilling risks, geological risks, transportation restrictions, the timing of acquisitions, product supply and demand, market competition and interruptions of production. You should read these consolidated interim financial statements in conjunction with the audited consolidated financial statements and notes thereto included in our Annual Report on Form 10-K for the year ended December 31, 2014, filed with the Securities and Exchange Commission on February 26, 2015.

The accompanying interim 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 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) income reported.

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 application not permitted. In July 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.

Approach Resources Inc. and Subsidiaries

Notes to Consolidated Financial Statements (Unaudited)

September 30, 2015

In April 2015, FASB issued an accounting standards update for “Interest – Imputation of Interest,” which simplifies the presentation of debt issuance costs. This accounting standard update requires that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. This new update is effective for financial statements issued for fiscal years beginning after December 15, 2015 (and interim periods within those fiscal years), with early adoption permitted and retrospective application required. We adopted this accounting standard update during the second quarter. The adoption of this new accounting standard update resulted in a reclassification of debt issuance costs from Other assets to Senior secured credit facility, net and Senior notes, net. See Note 4 “Long-Term Debt” for disclosure of debt issuance costs. Adoption of this accounting standard update did not impact our statements of operations or cash flows.

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. This new update is effective for financial statements issued for fiscal years beginning after December 15, 2015 (and interim periods within those fiscal years). This new guidance will be adopted prospectively in the first quarter of 2016. The Company is evaluating the impact of this new guidance and does not expect it to have a significant impact on the consolidated financial statements.

2.	Impairment of Oil and Gas Properties

Capitalized costs related to proved oil and gas properties, including wells and related equipment and facilities, are periodically evaluated for potential impairment when events or circumstances indicate that the carrying values of those assets may not be recoverable in accordance with ASC 360,Accounting for the Impairment or Disposal of Long-Lived Assets. If undiscounted cash flows are insufficient to recover the net capitalized costs related to proved properties, then we recognize an impairment loss 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, NGL and natural gas reserve quantities, timing of development and production, expected future commodity prices, capital expenditures and production costs. The fair value of the proved oil and gas properties and equipment was estimated 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 rate.

For the three and nine months ended September 30, 2015, we recognized an impairment loss of $214.7 million related primarily to our vertical Canyon wells, due to the impact of the sharp decline in forward commodity prices during the three months ended September 30, 2015. At September 30, 2015, we had $22 million in value recorded for these properties, which is the estimated fair value. Our estimates of future cash flows attributable to our oil and gas properties could decline further with commodity prices which may result in additional impairment losses.

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. Certain leases outside of our core development project were impaired during the three and nine months ended September 30, 2015, as we do not plan to develop them in the current commodity price environment. As a result, we recorded a non-cash impairment loss of unproved property of $5.5 million for the three and nine months ended September 30, 2015.

Approach Resources Inc. and Subsidiaries

Notes to Consolidated Financial Statements (Unaudited)

September 30, 2015

The total impairment loss of $220.2 million for the three and nine months ended September 30, 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.

3.	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 table provides a reconciliation of the numerators and denominators of our basic and diluted earnings per share (dollars in thousands, except per-share amounts).


	Three Months Ended September 30,					Nine Months Ended September 30,
	2015			2014		2015			2014

Income (numerator):
Net (loss) income – basic	$	(148,787	)	$	22,447	$	(168,345	)	$	29,185


Weighted average shares (denominator):
Weighted average shares – basic		40,541,420			39,363,441		40,419,187			39,325,552
Dilution effect of share-based compensation, treasury method		—	(1)		16,338		—	(1)		15,409

Weighted average shares – diluted		40,541,420			39,379,779		40,419,187			39,340,961


Net (loss) income per share:
Basic	$	(3.67	)	$	0.57	$	(4.16	)	$	0.74

Diluted	$	(3.67	)	$	0.57	$	(4.16	)	$	0.74

(1)	Approximately 39,000 options to purchase our common stock were excluded from this calculation because they were antidilutive for the three and nine months ended September 30, 2015.

4.	Long-Term Debt

The following table provides a summary of our long-term debt at September 30, 2015, and December 31, 2014 (in thousands).


	September 30,			December 31,
	2015			2014

Senior secured credit facility:
Outstanding borrowings	$	278,000		$	150,000
Debt issuance costs		(2,421	)		(2,928	)

Senior secured credit facility, net		275,579			147,072
Senior notes:
Principal		245,000			250,000
Debt issuance costs		(4,986	)		(5,761	)

Senior notes, net		240,014			244,239

Total long-term debt	$	515,593		$	391,311

Approach Resources Inc. and Subsidiaries

Notes to Consolidated Financial Statements (Unaudited)

September 30, 2015

Senior Secured Credit Facility

At September 30, 2015, the borrowing base and aggregate lender commitments under our amended and restated senior secured credit facility (the “Credit Facility”) were $450 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, NGL and gas reserves. We, or the lenders, can each request one additional borrowing base redetermination each calendar year.

In September 2015, the lenders under the Credit Facility completed their semi-annual borrowing base redetermination, which reaffirmed the aggregate lender commitments of $450 million and decreased the borrowing base to $450 million from $525 million.

Borrowings bear interest based on the agent bank’s prime rate plus an applicable margin ranging from 0.50% to 1.50%, or the sum of the LIBOR rate plus an applicable margin ranging from 1.50% to 2.50%. In addition, we pay an annual commitment fee ranging from 0.375% to 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 outstanding borrowings of $278 million under the Credit Facility at September 30, 2015, compared to $150 million of outstanding borrowings at December 31, 2014. The weighted average interest rate applicable to borrowings under the Credit Facility for the nine months ended September 30, 2015, was 2.1%. We had outstanding unused letters of credit under the Credit Facility totaling $0.3 million at September 30, 2015, and December 31, 2014, 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 maintain liens covering the oil and gas properties of the Company and its subsidiaries, representing at least 80% of the total value of all oil and gas properties of the Company and its subsidiaries.

Covenants

The Credit Facility contains two principal financial covenants:

•

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, and

•

a consolidated interest coverage ratio covenant (as defined in the Credit Facility) that requires us to maintain a ratio of consolidated EBITDAX to interest for the preceding four fiscal quarters of not less than 2.5 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

Approach Resources Inc. and Subsidiaries

Notes to Consolidated Financial Statements (Unaudited)

September 30, 2015

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.

In August 2015, we repurchased a portion of our Senior Notes in the open market with an aggregate face value of $5 million for a purchase price of $3.5 million, including accrued interest. This resulted in a gain on extinguishment of debt of $1.5 million.

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

On and after June 15, 2016, we may redeem some or all of the Senior Notes at specified redemption prices, plus accrued and unpaid interest to the redemption date. Before June 15, 2016, we may redeem up to 35% of the Senior Notes at a redemption price of 107% of the principal amount, plus accrued and unpaid interest to the redemption date, with the proceeds of certain equity offerings. In addition, before June 15, 2016, we may redeem some or all of the Notes for cash at a redemption price equal to 100% of their principal amount plus an applicable make-whole premium and accrued and unpaid interest to the redemption date. If we sell certain of our assets or experience specific kinds of changes of control, we may be required to offer to purchase the Senior Notes from holders. 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

Approach Resources Inc. and Subsidiaries

Notes to Consolidated Financial Statements (Unaudited)

September 30, 2015

obligor under a 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 credit facility, in each case, which resulted in such restricted subsidiary’s obligation to guarantee the notes.

The Indenture restricts our ability, among other things, to (i) sell certain assets, (ii) pay distributions on, redeem or repurchase, equity interests, (iii) incur additional debt, (iv) make certain investments, (v) enter into transactions with affiliates, (vi) incur liens and (vii) merge or consolidate with another company. These restrictions are subject to a number of important exceptions and qualifications. If at any time the Senior Notes are rated investment grade by both Moody’s Investors Service and Standard & Poor’s Ratings Services and no default (as defined in the Indenture) has occurred and is continuing, many of these restrictions will terminate. The Indenture contains customary 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 September 30, 2015, we were in compliance with all of our covenants, and there were no existing defaults or events of default, under our debt instruments.

5.	Termination Costs

In September 2015, we reduced our workforce to decrease costs and better align our workforce with the needs of the business and current oil and gas prices. In connection with the reduction, we incurred $1.4 million in expenses, which is recorded in termination costs on our consolidated statements of operations. As of September 30, 2015, $1.4 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 97,083 outstanding unvested shares of restricted stock in connection with our workforce reduction, which is recorded in general and administrative expense on our consolidated statements of operations.

6.	Commitments and Contingencies

Our contractual obligations include long-term debt, operating lease obligations, asset retirement obligations, termination agreements and employment agreements with our executive officers. At September 30, 2015, outstanding borrowings under the Credit Facility were $278 million, compared to $150 million at December 31, 2014. In August 2015, we exercised our early termination option related to our last remaining daywork drilling rig contract. We incurred $1.7 million in expense related to the early termination of this contract, which is recorded in exploration expense on our consolidated statements of operations. Since December 31, 2014, there have been no other material changes to our contractual obligations.

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.

Approach Resources Inc. and Subsidiaries

Notes to Consolidated Financial Statements (Unaudited)

September 30, 2015

7.	Income Taxes

The effective income tax rate for the three and nine months ended September 30, 2015, was 35.5% and 35.6%, respectively. Total income tax expense for the three and nine months ended September 30, 2015, differed from amounts computed by applying the U.S. federal statutory tax rates to pre-tax income, due primarily to state taxes and the impact of permanent differences between book and taxable income.

The effective income tax rate for the three and nine months ended September 30, 2014, was 36.2%. Total income tax expense for the three and nine months ended September 30, 2014, differed from amounts computed by applying the U.S. federal statutory tax rates to pre-tax income, due primarily to state taxes and the impact of permanent differences between book and taxable income.

8.	Derivative Instruments and Fair Value Measurements

The following table provides our outstanding commodity derivative positions at September 30, 2015.


Commodity and Period	Contract Type	Volume Transacted	Contract Price
Crude Oil
October 2015 – December 2015	Collar	1,600 Bbls/d	$84.00/Bbl - $91.00/Bbl
October 2015 – December 2015	Collar	1,000 Bbls/d	$90.00/Bbl - $102.50/Bbl
October 2015 – December 2015	Three-Way Collar	500 Bbls/d	$75.00/Bbl - $84.00/Bbl - $94.00/Bbl
October 2015 – December 2015	Three-Way Collar	500 Bbls/d	$75.00/Bbl - $84.00/Bbl - $95.00/Bbl
October 2015 – December 2016	Swap	500 Bbls/d	$62.50/Bbl
October 2015 – December 2016	Swap	250 Bbls/d	$62.55/Bbl

Natural Gas
October 2015 – December 2015	Swap	200,000 MMBtu/month	$4.10/MMBtu
October 2015 – December 2015	Collar	130,000 MMBtu/month	$4.00/MMBtu - $4.25/MMBtu
March 2016 – December 2016	Swap	100,000 MMBtu/month	$2.91/MMBtu
March 2016 – December 2016	Swap	100,000 MMBtu/month	$2.95/MMBtu

The following table summarizes the fair value of our open commodity derivatives as of September 30, 2015, and December 31, 2014 (in thousands).


	Asset Derivatives
	Balance Sheet Location	Fair Value
		September 30,		December 31,
		2015		2014
Derivatives not designated as hedging instruments
Commodity derivatives	Unrealized gain on commodity derivatives	$	17,022	$	39,951

Approach Resources Inc. and Subsidiaries

Notes to Consolidated Financial Statements (Unaudited)

September 30, 2015

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


	Income Statement Location	Three Months Ended September 30,					Nine Months Ended September 30,
		2015		2014			2015			2014
Derivatives not designated as hedging instruments
Commodity derivatives	Realized gain (loss) on commodity derivatives	$	12,755	$	(764	)	$	37,937		$	(5,423	)
	Unrealized gain (loss) on commodity derivatives		296		18,810			(22,929	)		5,206

		$	13,051	$	18,046		$	(15,008	)	$	(217	)

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 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. Accounts receivable related to oil, NGL and gas sales includes $3.8 million and $4.8 million from realized gains on commodity derivatives at September 30, 2015, and December 31, 2014, respectively.

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 September 30, 2015, 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

Approach Resources Inc. and Subsidiaries

Notes to Consolidated Financial Statements (Unaudited)

September 30, 2015

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 September 30, 2015, 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 represents a nonrecurring Level 3 measurement. See Note 2 “Impairment of Oil and Gas Properties” for significant inputs and methodology related to the Level 3 measurement.

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).


	September 30, 2015
	Carrying Amount		Fair Value
Senior Notes, net	$	240,014	$	141,612

The fair value of the Senior Notes uses pricing that is readily available in the public market. Accordingly, the fair value of the Senior Notes would be classified as Level 2 in the fair value hierarchy.

9.	Share-Based Compensation

In February 2015, we awarded an aggregate of 724,249 restricted shares to our executive officers, of which 482,833 shares are subject to certain performance conditions and 241,416 shares are subject to three-year total shareholder return (“TSR”) conditions, assuming maximum TSR is achieved. The aggregate fair market value of the award, assuming target TSR is achieved, is $4.5 million, which will be expensed over a service period of approximately three years, subject to performance and three-year TSR conditions.

Item 2.

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. This section should be read in conjunction with management’s discussion and analysis contained in our Annual Report on Form 10-K for the year ended December 31, 2014, filed with the Securities and Exchange Commission (“SEC”) on February 26, 2015. 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. Certain 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 in this report. A glossary containing the meaning of the oil and gas industry terms used in this management’s discussion and analysis follows the “Results of Operations” table in this Item 2.

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, 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 or referred to 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, NGL and gas prices;

•

overall United States and global economic and financial market conditions;

•

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

•

the willingness and ability of the Organization of Petroleum Exporting Countries (“OPEC”) to set and maintain 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;

•

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;

•

our financial position;

•

our cash flows and liquidity;

•

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

•

marketing of oil, NGLs and gas;

•

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;

•

interpretation of 3-D seismic data;

•

replacing our oil, NGL and gas reserves;

•

our ability to retain and attract key personnel;

•

our business strategy, including our ability to recover oil, NGLs and 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, NGL and gas reserves and present value thereof;

•

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

•

other factors discussed in our Annual Report on Form 10-K for the year ended December 31, 2014, filed with the SEC on February 26, 2015, and in this Quarterly Report for the three and nine months ended September 30, 2015.

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 130,000 net acres, as of September 30, 2015. We believe our concentrated acreage position provides us an opportunity to achieve cost, operating and recovery efficiencies in the development of our drilling inventory. We are focused on developing the significant resource potential from the Wolfcamp shale oil formation. 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, 2014, our estimated proved reserves were 146.2 million barrels of oil equivalent (“MMBoe”), made up of 38% oil, 28% NGLs, 34% gas and 41% proved developed reserves. Substantially all of our proved reserves are located in the Permian Basin in Crockett and Schleicher counties, Texas. At September 30, 2015, we owned working interests in 757 producing oil and gas wells.

Third Quarter 2015 Activity

During the three months ended September 30, 2015, we produced 1,525 MBoe, or 16.6 MBoe/d. We drilled four horizontal wells and completed five horizontal wells. At September 30, 2015, four wells were waiting on completion. In August 2015, we exercised our early termination option related to our last remaining drilling rig contract.

2015 Capital Expenditures

For the three months ended September 30, 2015, our capital expenditures totaled $19.8 million, consisting of $17.9 million for drilling and completion activities and $1.9 million for infrastructure projects and equipment. During the third quarter of 2015, in response to continued decline in oil, NGL and gas prices, we suspended our drilling and completion activities. For the nine months ended September 30, 2015, our capital expenditures totaled $151.3 million. We will continue to monitor commodity prices and operating expenses to determine any further adjustments to our capital budget.

Our 2015 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.

Results of Operations

The following table sets forth summary information regarding oil, NGL and gas revenues, production, average product prices and average production costs and expenses for the three and nine months ended September 30, 2015 and 2014. We determine a barrel of oil equivalent 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 of natural gas or NGLs may differ significantly from the price for a barrel of oil.


	Three Months Ended September 30,					Nine Months Ended September 30,
	2015		2014			2015		2014

Revenues (in thousands):
Oil	$	20,213	$	47,194		$	67,142	$	140,509
NGLs		5,311		11,628			16,067		33,486
Gas		8,417		9,302			22,635		29,464

Total oil, NGL and gas sales		33,941		68,124			105,844		203,459

Realized gain (loss) on commodity derivatives		12,755		(764	)		37,937		(5,423	)

Total oil, NGL and gas sales including derivative impact	$	46,696	$	67,360		$	143,781	$	198,036


Production:
Oil (MBbls)		490		507			1,483		1,482
NGLs (MBbls)		488		392			1,266		1,057
Gas (MMcf)		3,285		2,445			8,721		6,727

Total (MBoe)		1,525		1,306			4,202		3,659
Total (MBoe/d)		16.6		14.2			15.4		13.4

Average prices:
Oil (per Bbl)	$	41.27	$	93.14		$	45.28	$	94.84
NGLs (per Bbl)		10.89		29.70			12.69		31.69
Gas (per Mcf)		2.56		3.80			2.60		4.38

Total (per Boe)	$	22.26	$	52.17		$	25.19	$	55.60

Realized gain (loss) on commodity derivatives (per Boe)		8.36		(0.58	)		9.03		(1.49	)

Total including derivative impact (per Boe)	$	30.62	$	51.59		$	34.22	$	54.11

Costs and expenses (per Boe):
Lease operating	$	5.04	$	5.87		$	5.17	$	6.41
Production and ad valorem taxes		1.77		2.55			2.02		3.40
Exploration		1.28		0.68			1.00		0.98
General and administrative		4.77		5.88			5.45		6.45
Depletion, depreciation and amortization		20.47		19.88			20.50		21.35

Glossary

Bbl. One stock tank barrel, of 42 U.S. gallons liquid volume, used herein to reference oil, condensate or NGLs.

Boe. Barrel of oil equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of oil equivalent, and one Bbl of NGLs to one Bbl of oil equivalent.

MBbl. Thousand barrels of oil, condensate or NGLs.

MBoe. Thousand barrels of oil equivalent.

Mcf. Thousand cubic feet of natural gas.

MMBoe. Million barrels of oil equivalent.

MMBtu. Million British thermal units.

MMcf. Million cubic feet of natural gas.

NGLs. Natural gas liquids.

NYMEX. New York Mercantile Exchange

/d. “Per day” when used with volumetric units or dollars.

Three Months Ended September 30, 2015, Compared to Three Months Ended September 30, 2014

Oil, NGL and gas sales. Oil, NGL and gas sales decreased $34.2 million, or 50%, for the three months ended September 30, 2015, to $33.9 million, from $68.1 million for the three months ended September 30, 2014. The decrease in oil, NGL and gas sales was due to a decrease in average realized commodity prices ($38.7 million) offset by an increase in production volumes ($4.5 million). Production volumes increased as a result of our development in Project Pangea.

Net (loss) income. Net loss for the three months ended September 30, 2015, was $148.8 million, or $3.67 per diluted share, compared to net income of $22.4 million, or $0.57 per diluted share, for the three months ended September 30, 2014. Net loss for the three months ended September 30, 2015, included an impairment loss of $220.2 million, a tax benefit of $81.8 million primarily related to the impairment loss, a realized gain on commodity derivatives of $12.8 million, an unrealized gain on commodity derivatives of $0.3 million, a gain on debt extinguishment of $1.5 million and termination costs of $1.4 million. Net loss for the three months ended September 30, 2015, was primarily due to lower revenues of $34.2 million and an impairment loss of $220.2 million due to depressed commodity prices, partially offset by the related tax benefit of $81.8 million.

Oil, NGL and gas production. Production for the three months ended September 30, 2015, totaled 1,525 MBoe (16.6 MBoe/d), compared to production of 1,306 MBoe (14.2 MBoe/d) in the prior-year period, a 17% increase. Production for the three months ended September 30, 2015, was 32% oil, 32% NGLs and 36% gas, compared to 39% oil, 30% NGLs and 31% gas in the 2014 period. Production volumes increased during the three months ended September 30, 2015, as a result of our continued development in Project Pangea. We expect production to decline next quarter due to reduced drilling and completion activity.

Impairment of oil and gas properties. We recognized a non-cash impairment loss of $220.2 million for the three months ended September 30, 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 thereof; and (vi) discount rate.

We may incur additional impairments to our oil and natural gas properties in the future if oil and gas prices continue to decline. The possibility and amount of any future impairment is difficult to predict, and will depend, in part, upon future oil and gas prices, estimates of proved reserves and future capital expenditures and production costs.

Commodity derivative activities. Our commodity derivative activity resulted in a realized gain of $12.8 million and a realized loss of $0.8 million for the three months ended September 30, 2015 and 2014, respectively. Our average realized price, including the effect of commodity derivatives, was $30.62 per Boe for the three months ended September 30, 2015, compared to $51.59 per Boe for the three months ended September 30, 2014. Realized gains and losses on commodity derivatives are derived from the relative movement of commodity prices in relation to the fixed pricing in our derivatives contracts for the respective periods. The unrealized gain on commodity derivatives was $0.3 million for the three months ended September 30, 2015, compared to $18.8 million for the three months ended September 30, 2014. As commodity prices increase or decrease, the fair value of the open portion of those positions decreases or increases, respectively.

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 net (loss) income on our consolidated statements of operations under the caption entitled “unrealized gain (loss) on commodity derivatives.”

Lease operating. Our lease operating expenses (“LOE”) were $7.7 million for the three months ended September 30, 2015 and 2014. LOE per Boe decreased $0.83, or 14%, for the three months ended September 30, 2015, to $5.04 per Boe, from $5.87 per Boe for the three months ended September 30, 2014. The decrease in LOE per Boe for the three months ended September 30, 2015, was primarily due to operation of our water recycling center, increased efficiency in our overall operations and other cost-saving initiatives. The following table summarizes LOE per Boe.


	Three Months Ended
	September 30,
	2015				2014				Change
	$MM		Boe		$MM		Boe		$MM			Boe			% Change (Boe)
Water hauling and other	$	2.6	$	1.71	$	2.9	$	2.20	$	(0.3	)	$	(0.49	)		(22.3	)%
Compressor rental and repair		2.5		1.61		2.4		1.83		0.1			(0.22	)		(12.0	)
Well repairs, workovers and maintenance		1.4		0.91		1.3		0.96		0.1			(0.05	)		(5.2	)
Pumpers and supervision		1.2		0.81		1.1		0.88		0.1			(0.07	)		(8.0	)

Total	$	7.7	$	5.04	$	7.7	$	5.87	$	—		$	(0.83	)		(14.1	)%

Production and ad valorem taxes. Our production and ad valorem taxes decreased $0.6 million, or 19%, for the three months ended September 30, 2015, to $2.7 million from $3.3 million for the three months ended September 30, 2014. The decrease in production and ad valorem taxes was primarily a function of the decrease in oil, NGL and gas sales between the two periods. Production and ad valorem taxes were $1.77 per Boe and $2.55 per Boe and approximately 8% and 4.9% of oil, NGL and gas sales for the three months ended September 30, 2015 and 2014, respectively. Production and ad valorem taxes for the three months ended September 30, 2014, included a $1 million refund from the state of Texas for production taxes on natural gas properties relating to tax reimbursements.

Exploration. We recorded $2 million, or $1.28 per Boe, and $0.9 million, or $0.68 per Boe, of exploration expense for the three months ended September 30, 2015 and 2014, respectively. The increase in exploration expense was primarily due to the early termination of our last remaining drilling contract for $1.7 million.

General and administrative. Our general and administrative expenses (“G&A”) decreased $0.4 million, or 5%, to $7.3 million, or $4.77 per Boe, for the three months ended September 30, 2015, from $7.7 million, or $5.88 per Boe, for the three months ended September 30, 2014. The decrease in G&A per Boe was primarily due to cost-saving initiatives. Share-based compensation for the three months ended September 30, 2015 included a benefit of $0.3 million related to forfeiture of 97,083 unvested shares of restricted stock in connection with our workforce reduction. We expect G&A to continue to decline from prior-year levels due to our cost-saving initiatives and the reduction in our workforce. The following table summarizes G&A in millions and G&A per Boe.


	Three Months Ended
	September 30,
	2015				2014				Change
	$MM		Boe		$MM		Boe		$MM			Boe			% Change (Boe)
Salaries and benefits	$	3.5	$	2.27	$	3.5	$	2.69	$	—		$	(0.42	)		(15.6	)%
Share-based compensation		1.7		1.12		2.0		1.50		(0.3	)		(0.38	)		(25.3	)
Professional fees		0.8		0.54		0.5		0.38		0.3			0.16			42.1
Other		1.3		0.84		1.7		1.31		(0.4	)		(0.47	)		(35.9	)

Total	$	7.3	$	4.77	$	7.7	$	5.88	$	(0.4	)	$	(1.11	)		(18.9	)%

Termination costs. We recorded $1.4 million in termination costs for the three months ended September 30, 2015, in connection with a reduction of our workforce.

Depletion, depreciation and amortization. Our depletion, depreciation and amortization expense (“DD&A”) increased $5.2 million, or 20%, to $31.2 million for the three months ended September 30, 2015, from $26 million for the three months ended September 30, 2014. Our DD&A per Boe increased by $0.59 per Boe, or 3%, to $20.47 per Boe for the three months ended September 30, 2015, compared to $19.88 per Boe for the three months ended September 30, 2014. The increase in DD&A expense over the prior period was primarily due to higher production.

Interest expense, net. Our interest expense, net, increased $1.1 million, or 19%, to $6.5 million for the three months ended September 30, 2015, from $5.4 million for the three months ended September 30, 2014. This increase was primarily due to higher interest expense from increased borrowings under our amended and restated senior secured credit facility (the “Credit Facility”). We expect our interest expense to remain higher than the prior-year period as a result of a higher outstanding balance under the Credit Facility.

Gain on extinguishment of debt.During the three months ended September 30, 2015, we repurchased a portion of our Senior Notes in the open market with an aggregate face value of $5 million for a purchase price of $3.5 million, including accrued interest. This resulted in a gain on extinguishment of debt of $1.5 million.

As market conditions warrant and subject to our contractual restrictions in the Credit Facility or otherwise, liquidity position and other factors, we may from time to time seek to repurchase additional Senior Notes. The amounts involved in any such transactions, individually or in the aggregate, may be material.

Income taxes. Our income taxes decreased $94.6 million to an income tax benefit of $81.8 million for the three months ended September 30, 2015, from an income tax expense of $12.8 million for the three months ended September 30, 2014. The decrease in income taxes was primarily due to the impairment loss of $220.2 million for the three months ended September 30, 2015. Our effective income tax rate for the three months ended September 30, 2015, was 35.5%, compared to 36.2% for the three months ended September 30, 2014.

Nine Months Ended September 30, 2015, Compared to Nine Months Ended September 30, 2014

Oil, NGL and gas sales. Oil, NGL and gas sales decreased $97.7 million, or 48%, for the nine months ended September 30, 2015, to $105.8 million, from $203.5 million for the nine months ended September 30, 2014. The decrease in oil, NGL and gas sales was due to a decrease in average realized commodity prices ($113.2 million) offset by an increase in production volumes ($15.5 million). Production volumes increased as a result of our development in Project Pangea.

Net (loss) income. Net loss for the nine months ended September 30, 2015, was $168.3 million, or $4.16 per diluted share, compared to net income of $29.2 million, or $0.74 per diluted share, for the nine months ended September 30, 2014. Net loss for the nine months ended September 30, 2015, included an impairment loss of $220.2 million, a tax benefit of $93.1 million primarily related to the impairment loss, an unrealized loss on commodity derivatives of $22.9 million and a realized gain on commodity derivatives of $37.9 million. Net loss for the nine months ended September 30, 2015, was primarily due to lower revenues of $97.7 million and an impairment loss of $220.2 million due to depressed commodity prices, partially offset by the related tax benefit of $93.1 million.

Oil, NGL and gas production. Production for the nine months ended September 30, 2015, totaled 4,202 MBoe (15.4 MBoe/d), compared to production of 3,659 MBoe (13.4 MBoe/d) in the prior-year period, a 15% increase. Production for the nine months ended September 30, 2015, was 35% oil, 30% NGLs and 35% gas, compared to 40% oil, 29% NGLs and 31% gas in the 2014 period. Production volumes increased during the nine months ended September 30, 2015, as a result of our development in Project Pangea.

Impairment of oil and gas properties. We recognized a non-cash impairment loss of $220.2 million for the nine months ended September 30, 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 thereof; and (vi) discount rate.

Commodity derivatives activities. Our commodity derivatives activity resulted in a realized gain of $37.9 million and a realized loss of $5.4 million for the nine months ended September 30, 2015 and 2014, respectively. Our average realized price, including the effect of commodity derivatives, was $34.22 per Boe for the nine months ended September 30, 2015, compared to $54.11 per Boe for the nine months ended September 30, 2014. Realized gains and losses on commodity derivatives are derived from the relative movement of commodity prices in relation to the fixed pricing in our derivatives contracts for the respective periods. The unrealized loss on commodity derivatives was $22.9 million for the nine months ended September 30, 2015, compared to an unrealized gain of $5.2 million for the nine months ended September 30, 2014. As commodity prices increase or decrease, the fair value of the open portion of those positions decreases or increases, respectively.

Lease operating. Our LOE decreased $1.8 million, or 7%, for the nine months ended September 30, 2015, to $21.7 million, or $5.17 per Boe, from $23.5 million, or $6.41 per Boe, for the nine months ended September 30, 2014. The decrease in LOE per Boe for the nine months ended September 30, 2015, was primarily due to a decrease in well repairs, workovers and maintenance. The following table summarizes LOE per Boe.


	Nine Months Ended
	September 30,
	2015				2014				Change
	$MM		Boe		$MM		Boe		$MM			Boe			% Change (Boe)
Water hauling and other	$	7.4	$	1.76	$	6.7	$	1.81	$	0.7		$	(0.05	)		(2.8	)%
Compressor rental and repair		7.7		1.84		6.8		1.86		0.9			(0.02	)		(1.1	)
Pumpers and supervision		3.7		0.88		3.3		0.90		0.4			(0.02	)		(2.2	)
Well repairs, workovers and maintenance		2.9		0.69		6.7		1.84		(3.8	)		(1.15	)		(62.5	)

Total	$	21.7	$	5.17	$	23.5	$	6.41	$	(1.8	)	$	(1.24	)		(19.3	)%

Production and ad valorem taxes. Our production and ad valorem taxes decreased $3.9 million, or 32%, for the nine months ended September 30, 2015, to $8.5 million from $12.4 million for the nine months ended September 30, 2014. The decrease in production and ad valorem taxes was primarily a function of the decrease in oil, NGL and gas sales between the two periods. Production and ad valorem taxes were $2.02 per Boe and $3.40 per Boe and approximately 8% and 6.1% of oil, NGL and gas sales for the nine months ended September 30, 2015 and 2014, respectively. Production and ad valorem taxes per Boe for the nine months ended September 30, 2014 included a $1 million refund from the state of Texas for production taxes on natural gas properties relating to tax reimbursements.

Exploration. We recorded $4.2 million, or $1.00 per Boe, and $3.6 million, or $0.98 per Boe, of exploration expense for the nine months ended September 30, 2015 and 2014, respectively. The increase in exploration expense was primarily due to the early termination of drilling contracts for $2.2 million, partially offset by lower lease expirations in the current period.

General and administrative. Our G&A decreased $0.7 million, or 3%, to $22.9 million, or $5.45 per Boe, for the nine months ended September 30, 2015, from $23.6 million, or $6.45 per Boe, for the nine months ended September 30, 2014. The decrease in G&A per Boe was primarily due to cost saving initiatives. Share-based compensation for the nine months ended September 30, 2015 included a benefit of $0.3 million related to forfeiture of 97,083 unvested shares of restricted stock in connection with our workforce reduction. Additionally, share-based compensation expense for the nine months ended September 30, 2014, includes a $1.1 million benefit of forfeited stock awards related to the retirement of one of our executive officers. We expect G&A to continue to decline from prior-year levels due to our cost-saving initiatives and the reduction in our workforce. The following table summarizes G&A in millions and G&A per Boe.


	Nine Months Ended
	September 30,
	2015				2014				Change
	$MM		Boe		$MM		Boe		$MM			Boe			% Change (Boe)
Salaries and benefits	$	10.5	$	2.49	$	11.1	$	3.03	$	(0.6	)	$	(0.54	)		(17.8	)%
Share-based compensation		6.0		1.43		5.7		1.56		0.3			(0.13	)		(8.3	)
Professional fees		2.4		0.57		2.1		0.58		0.3			(0.01	)		(1.7	)
Other		4.0		0.96		4.7		1.28		(0.7	)		(0.32	)		(25.0	)

Total	$	22.9	$	5.45	$	23.6	$	6.45	$	(0.7	)	$	(1.00	)		(15.5	)%

Termination costs.We recorded $1.4 million in termination costs for the nine months ended September 30, 2015, in connection with a reduction of our workforce.

Depletion, depreciation and amortization. Our DD&A increased $8 million, or 10%, to $86.1 million for the nine months ended September 30, 2015, from $78.1 million for the nine months ended September 30, 2014. Our DD&A per Boe decreased by $0.85 per Boe, or 4%, to $20.50 per Boe for the nine months ended September 30, 2015, compared to $21.35 per Boe for the nine months ended September 30, 2014. The increase in DD&A expense over the prior-year period was primarily due to higher production. 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.

Interest expense, net. Our interest expense, net, increased $2.7 million, or 17%, to $18.6 million for the nine months ended September 30, 2015, from $15.9 million for the nine months ended September 30, 2014. This increase was due to higher interest expense from increased borrowings under the Credit Facility. We expect our interest expense to remain higher than the prior-year period as a result of a higher outstanding balance under the Credit Facility.

Gain on extinguishment of debt.During the nine months ended September 30, 2015, we repurchased a portion of our Senior Notes in the open market with an aggregate face value of $5 million for a purchase price of $3.5 million, including accrued interest. This resulted in a gain on extinguishment of debt of $1.5 million.

Income taxes. Our income taxes decreased $109.7 million to an income tax benefit of $93.1 million for the nine months ended September 30, 2015, from an income tax expense of $16.6 million for the nine months ended September 30, 2014. The decrease in income taxes was primarily due to the net loss before income taxes in the 2015 period. Our effective income tax rate for the nine months ended September 30, 2015, was 35.6%, compared to 36.3% for the nine months ended September 30, 2014.

Liquidity and Capital Resources

We generally will rely on cash generated from operations, borrowings under the Credit Facility and, to the extent that credit and capital market conditions will allow, future public or private equity and debt offerings to satisfy our liquidity needs. Our ability to fund planned capital expenditures and to make acquisitions depends upon our future operating performance, availability of borrowings under the 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 the 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. Prices for oil, NGLs and gas are affected by national and international economic and political environments, national and global supply and demand for hydrocarbons, seasonal influences of weather and other factors beyond our control. Cash flows from operations are primarily used to fund exploration and development of our oil and gas properties.

We believe we have adequate liquidity from cash generated from operations and unused borrowing capacity under the Credit Facility for current working capital needs. 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 the Credit Facility.

Liquidity

We define liquidity as funds available under the Credit Facility and cash and cash equivalents. At September 30, 2015, we had $278 million in outstanding borrowings under the Credit Facility and liquidity of $172 million, compared to $150 million in outstanding borrowings under the Credit Facility and liquidity of $300 million at December 31, 2014. The table below summarizes our liquidity position at September 30, 2015, and December 31, 2014 (dollars in thousands).


	Liquidity at September 30,			Liquidity at December 31,
	2015			2014
Borrowing base	$	450,000		$	450,000
Cash and cash equivalents		319			432
Credit Facility – outstanding borrowings		(278,000	)		(150,000	)
Undrawn letters of credit		(325	)		(325	)

Liquidity	$	171,994		$	300,107

Working Capital

Our working capital is affected primarily by our capital spending program. We had a working capital deficit of $12.6 million and $45.8 million at September 30, 2015, and December 31, 2014, respectively. The primary reason for the change in working capital was a decrease in accounts payable and accrued liabilities due to a decrease in our capital expenditures. We expect our working capital position to continue to improve for the remainder of the year. To the extent we operate, or end fiscal year 2015, with a working capital deficit, we expect such deficit to be more than offset by liquidity available under the Credit Facility.

Cash Flows

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


	Nine Months Ended September 30,
	2015			2014
Cash provided by operating activities	$	82,515		$	135,465
Cash used in investing activities		(207,215	)		(279,865	)
Cash provided by financing activities		124,587			87,273

Net decrease in cash and cash equivalents	$	(113	)	$	(57,127	)

Operating Activities

Cash provided by operating activities decreased by 39%, or $53 million, to $82.5 million during the nine months ended September 30, 2015, compared to the prior-year period. The decrease in our cash provided by operating activities was primarily due to a decrease in oil, NGL and gas sales from lower commodity prices and the timing of payments and receipts of working capital components.

Investing Activities

Cash used in investing activities decreased by $72.7 million for the nine months ended September 30, 2015, to $207.2 million, compared to the prior-year period. Our capital expenditures for the nine months ended September 30, 2015, were primarily attributable to drilling and development ($139.6 million), infrastructure projects and equipment ($11 million) and lease extensions ($0.7 million). Cash used in investing activities also included changes in working capital associated with investing activities ($55.9 million). In the nine months ended September 30, 2014, $7.4 million in restricted cash was released from escrow related to the sale of our interest in the Wildcat pipeline, offset by $0.2 million in post-closing working capital adjustments related to the sale. During the nine months ended September 30, 2015, we drilled a total of 21 horizontal wells and completed 28 horizontal wells in Project Pangea. At September 30, 2015, four wells were waiting on completion.

Financing Activities

During the nine months ended September 30, 2015, cash provided by financing activities increased by $37.3 million, compared to the prior-year period. We had $278 million of outstanding borrowings under our Credit Facility at September 30, 2015, compared to $89.5 million of outstanding borrowings as of September 30, 2014. During the nine months ended September 30, 2015, net cash provided by financing activities included borrowings under our Credit Facility of $241.5 million that were partially offset by repayments of outstanding borrowings under our Credit Facility of $113.5 million. In comparison, for the nine months ended September 30, 2014, we had net cash provided by financing activities that included borrowings under the Credit Facility of $231.4 million, which were partially offset by repayments of outstanding borrowings under our Credit Facility of $141.9 million. The net cash provided by financing activities for the nine months ended September 30, 2015 includes the repurchase of a portion of our Senior Notes with an aggregate face value of $5 million for a purchase price of $3.5 million, including accrued interest. This resulted in a gain on extinguishment of debt of $1.5 million.

Senior Secured Credit Facility

At September 30, 2015, the borrowing base and aggregate lender commitments under our Credit Facility were $450 million, with maximum commitments from the lenders of $1 billion and a maturity date of May 7, 2019. We had outstanding borrowings of $278 million and $150 million under the Credit Facility at September 30, 2015, and December 31, 2014, respectively. The weighted average interest rate applicable to borrowings under the Credit Facility for the nine months ended September 30, 2015, was 2.1%. Additional information regarding our credit arrangements is included in Note 4. “Long-Term Debt.”

At September 30, 2015, we were in compliance with all of our covenants, and there were no existing defaults or events of default under our debt instruments. To date, we have experienced no disruptions in our ability to access the 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, commodity prices, assumptions and discount rates as such lender customarily uses in evaluating oil and gas properties, assigns to our properties.

Contractual Obligations

Our contractual obligations include long-term debt, operating lease obligations, asset retirement obligations and employment agreements with our executive officers. At September 30, 2015, outstanding borrowings under the Credit Facility were $278 million, compared to $150 million at December 31, 2014. In August 2015, we exercised our early termination option related to our last remaining daywork drilling rig contract. We incurred $1.7 million in expense related to the early termination of this contract, which is recorded in exploration expense on our consolidated statements of operations. Since December 31, 2014, there have been no other material changes to our contractual obligations.

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 September 30, 2015, 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 have, or are reasonably likely to have, a current or future material effect on our financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources.

General Trends and Outlook

Our financial results depend upon many factors, particularly the price of oil, NGLs and gas. Commodity prices are affected by changes in market demand, which is impacted by domestic and foreign supply of oil, NGL 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, NGL and gas consumption. As a result, we cannot accurately predict future oil, NGL and gas prices, and therefore, we cannot determine what effect increases or decreases will have on our capital program, production volumes and future revenues. A substantial or extended decline in oil, NGL and gas prices could have a material adverse effect on our business, financial condition, results of operations, quantities of oil and gas reserves that may be economically produced and liquidity that may be accessed through our borrowing base under the Credit Facility and through capital markets.

In addition to production volumes and commodity prices, finding and developing sufficient amounts of oil and gas reserves at economical costs are 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 reserves have a rapid initial decline. We attempt to overcome this natural decline by drilling to develop and identify additional reserves, by participating in farm-ins or other joint drilling ventures, and by acquisitions. However, during

times of severe price declines, we may from time to time 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 and increase future expected costs necessary to develop existing reserves.

We also face the challenge of financing exploration, development and future acquisitions. We believe we have adequate liquidity from cash generated from operations and unused borrowing capacity under the Credit Facility for current working capital needs and maintenance of our current development project. 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 the Credit Facility.

We believe the outlook for our business is favorable despite the continued uncertainty of oil, NGL and gas prices. Our resource base, strong balance sheet, risk management, including commodity derivative strategy, and disciplined investment of capital provide us with an opportunity to exploit and develop our positions and maximize efficiency in our key operating area. We continue to focus on maintaining a strong balance sheet and cash flow, while growing production modestly in light of evolving market conditions.

Item 3.

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 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.

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 the three months ended September 30, 2015, the NYMEX WTI spot price averaged $47 per barrel, compared with approximately $97 per barrel in the three months ended September 30, 2014. In the nine months ended September 30, 2015, the NYMEX WTI spot price averaged $51 per barrel and ranged from a low of $38 per barrel to a high of $61 per barrel. In the nine months ended September 30, 2014, the NYMEX WTI spot price averaged $100 per barrel and ranged from a low of $91 per barrel to a high of $107 per barrel.

In the three months ended September 30, 2015, the Henry Hub natural gas spot price averaged $2.74 per MMBtu, compared with approximately $3.95 per MMBtu in the three months ended September 30, 2014. In the nine months ended September 30, 2015, the Henry Hub natural gas spot price averaged $2.76 per MMBtu and ranged from a low of $2.49 per MMBtu to a high of $3.23 per MMBtu. In the nine months ended September 30, 2014, the Henry Hub natural gas spot price averaged $4.41 per MMBtu and ranged from a low of $3.75 per MMBtu to a high of $6.15 per MMBtu.

We expect that a further decline in, or sustained low, oil and gas prices will not only decrease our revenues, but will also reduce the amount of oil and gas that we can produce economically and therefore lower our oil and gas reserves. The continued significant decline in oil and gas prices increases the uncertainty as to the impact of commodity prices on our estimated proved reserves. A prolonged period of depressed commodity prices may have a significant impact on the volume of our proved reserves.

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 following table provides our outstanding commodity derivative positions at September 30, 2015.


Commodity and Period	Contract Type	Volume Transacted	Contract Price
Crude Oil
October 2015 – December 2015	Collar	1,600 Bbls/d	$84.00/Bbl - $91.00/Bbl
October 2015 – December 2015	Collar	1,000 Bbls/d	$90.00/Bbl - $102.50/Bbl
October 2015 – December 2015	Three-Way Collar	500 Bbls/d	$75.00/Bbl - $84.00/Bbl - $94.00/Bbl
October 2015 – December 2015	Three-Way Collar	500 Bbls/d	$75.00/Bbl - $84.00/Bbl - $95.00/Bbl
October 2015 – December 2016	Swap	500 Bbls/d	$62.50/Bbl
October 2015 – December 2016	Swap	250 Bbls/d	$62.55/Bbl

Natural Gas
October 2015 – December 2015	Swap	200,000 MMBtu/month	$4.10/MMBtu
October 2015 – December 2015	Collar	130,000 MMBtu/month	$4.00/MMBtu - $4.25/MMBtu
March 2016 – December 2016	Swap	100,000 MMBtu/month	$2.91/MMBtu
March 2016 – December 2016	Swap	100,000 MMBtu/month	$2.95/MMBtu

At September 30, 2015, the fair value of our open derivative contracts was an asset of $17 million, compared to an asset of $40 million at December 31, 2014.

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 the Credit Facility, and the collateral for the outstanding borrowings under our Credit Facility is used as collateral for our commodity derivatives.

For the nine months ended September 30, 2015, we recorded an unrealized loss on commodity derivatives of $22.9 million from the change in fair value of our commodity derivatives positions, compared to an unrealized gain of $5.2 million for the nine months ended September 30, 2014. A hypothetical 10% increase in commodity prices would have resulted in a $4.6 million decrease in the fair value of our commodity derivative positions recorded on our balance sheet at September 30, 2015, and a corresponding increase in the unrealized loss on commodity derivatives recorded on our consolidated statement of operations for the nine months ended September 30, 2015.

Item 4.

Controls and Procedures.

Evaluation of Disclosure Controls and Procedures

We maintain disclosure controls and procedures that are designed to ensure that information required to be disclosed in the reports we file under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. Such controls include those designed to ensure that information required to be disclosed by us in the reports that we file or submit under the Exchange Act is accumulated and communicated to management, including our Chairman, Chief Executive Officer and President (“CEO”), and Chief Financial Officer (“CFO”), as appropriate, to allow timely decisions regarding required disclosure.

Our management, with the participation of our CEO and CFO, has evaluated the effectiveness of our disclosure controls and procedures (as defined in Rule 13a-15(e) promulgated under the Exchange Act) as of September 30, 2015. Based on this evaluation, the CEO and CFO have concluded that, as of September 30, 2015, 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 CEO and CFO, as appropriate to allow timely decisions regarding required disclosure.

Internal Control over Financial Reporting

There were no changes made in our internal control over financial reporting (as defined in Rule 13a-15(f) promulgated under the Exchange Act) during the three months ended September 30, 2015, that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Limitations Inherent in All Controls

Our management, including our CEO and CFO, recognizes that the disclosure controls and procedures and internal controls (discussed above) cannot prevent all errors or all attempts at fraud. Any controls system, no matter how well-crafted and operated, can only provide reasonable, and not absolute, assurance of achieving the desired control objectives. Because of the inherent limitations in any control system, no evaluation or implementation of a control system can provide complete assurance that all control issues and all possible instances of fraud have been or will be detected.

PART II—OTHER INFORMATION

Item 1. Legal Proceedings.

There have been no material developments in the legal proceedings described in Part I, Item 3. “Legal Proceedings” of our Annual Report on Form 10-K for the year ended December 31, 2014, filed with the SEC on February 26, 2015.

Item 1A.

Risk Factors.

In addition to the other information set forth in this report, you should carefully consider the risks discussed in the following report that we have filed with the SEC, which risks could materially affect our business, financial condition and results of operations: Annual Report on Form 10-K for the year ended December 31, 2014, under the headings Item 1. “Business – Markets and Customers; Competition; and Regulation,” Item 1A. “Risk Factors,” Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations – General Trends and Outlook” and Item 7A. “Quantitative and Qualitative Disclosures about Market Risk” filed with the SEC on February 26, 2015.

Except as set forth below, there have been no material changes to the risk factors discussed in our Annual Report on Form 10-K for the year ended December 31, 2014, filed with the SEC on February 26, 2015, which is accessible on the SEC’s website atwww.sec.gov and our website atwww.approachresources.com.

The estimated volumes, standardized measure and present value of future net revenues (“PV-10”) from our proved reserves as of December 31, 2014, calculated using SEC pricing will be higher than these measures calculated using current market prices.

Our estimated proved reserves as of December 31, 2014, and related PV-10 and standardized measure were calculated under SEC rules using 12-month trailing average benchmark prices of $94.56 per Bbl of oil, $31.50 per Bbl of NGLs and $4.55 per Mcf of gas. On October 5, 2015, the prompt month NYMEX-WTI futures price for oil was $46.26 per Bbl and the prompt month NYMEX-Henry Hub futures price for gas was $2.68 per MMBtu. Our realized price for NGLs was $12.69 per Bbl for the nine months ended September 30, 2015. Using more recent prices in estimating our proved reserves, without giving effect to any development activities during 2015, could result in a reduction in proved reserve volumes due to economic limits. Furthermore, lower commodity prices could substantially reduce the PV-10 and standardized measure of our proved reserves as of a more recent date.

Although we have hedged a portion of our estimated 2015 production, our hedging program may be inadequate to protect us against continuing and prolonged declines in the price of oil and natural gas.

At October 1, 2015, we had commodity price derivative agreements on approximately 4,350 Bbls/d of oil and on approximately 330,000 MMBtu/month of natural gas hedged with collars and three-way collars through the end of 2015 at average prices of $74.78 per Bbl and $4.06 per MMBtu, respectively. These hedges will not protect us from continuing and prolonged decline in the price of oil and natural gas after 2015. We have not entered into any significant hedging transactions for our anticipated 2016 oil or gas production. To the extent that the prices for oil and gas remain at current levels or decline further, 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.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds.

The following table provides information relating to our purchase of shares of our common stock during the three months ended September 30, 2015. The repurchases reflect shares withheld upon vesting of restricted stock under our 2007 Stock Incentive Plan to satisfy statutory minimum tax withholding obligations.

ISSUER PURCHASES OF EQUITY SECURITIES


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 of Shares that May Yet Be Purchased Under the Plans or Programs

July 1, 2015 – July 31, 2015		687	$	3.89		—		—
August 1, 2015 – August 31, 2015		987		2.62		—		—
September 1, 2015 – September 30, 2015		228		2.44		—		—

Total		1,902	$	3.06		—		—

Item 6.

Exhibits.

See “Index to Exhibits” following the signature page of this report for a description of the exhibits included as part of this report.

SIGNATURES

Pursuant to the requirements 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.

Date: November 5, 2015	By:	/s/ J. Ross Craft
		J. Ross Craft
		Chairman of the Board, Chief Executive Officer and President (Principal Executive Officer)

Date: November 5, 2015	By:	/s/ Sergei Krylov
		Sergei Krylov
		Executive Vice President and Chief Financial Officer (Principal Financial Officer)

Index to Exhibits


Exhibit Number		*Description of Exhibit*

3.1		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).

3.2		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		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).

4.3		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).

*31.1		Certification by the Chairman, Chief Executive Officer and President 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 Chairman, Chief Executive Officer and President 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.

*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.

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