Edgar Filing: Jones Energy, Inc.

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 June 30, 2013

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

Commission file number 001-36006

Jones Energy, Inc.

(Exact name of registrant as specified in its charter)

Delaware	1311	80-0907968
(State or other Jurisdiction of	(Primary Standard Industrial	(IRS Employer
Incorporation or Organization)	Classification Code Number)	Identification Number)

807 Las Cimas Parkway, Suite 350
Austin, Texas 78746
(512) 328-2953
(Address, including zip code, and telephone number, including area code, of Registrant’s principal executive offices)

Robert J. Brooks

807 Las Cimas Parkway, Suite 350
Austin, Texas 78746
(512) 328-2953

(Address, including zip code, and telephone number, including area code, of Agent for service)

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

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

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. (Check one):

Large accelerated filer o	Accelerated filer o	Non-accelerated filer x	Smaller reporting company o

		(Do not check if a smaller reporting company)

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

On August 29, 2013, the Registrant had 12,500,000 shares of Class A common stock outstanding and 36,836,333 shares of Class B common stock outstanding.

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JONES ENERGY, INC.

TABLE OF CONTENTS

PART 1—FINANCIAL INFORMATION		1

Item 1. Unaudited Consolidated Financial Statements		2

	Balance Sheets
	Statements of Operations
	Statements of Changes in Members’ Equity
	Statements of Cash Flows
	Notes to Consolidated Financial Statements
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		18

Item 3. Quantitative and Qualitative Disclosures About Market Risk		26

Item 4. Controls and Procedures		28

PART II—OTHER INFORMATION		29

Item 1. Legal Proceedings		29

Item 1A. Risk Factors		29

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds		52

Item 3. Defaults Upon Senior Securities		52

Item 4. Mine Safety Disclosures		52

Item 5. Other Information		52

Item 6. Exhibits		53

SIGNATURES		54

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PART 1—FINANCIAL INFORMATION

Explanatory Note

The historical financial information contained in this report relates to periods that ended prior to the completion of the initial public offering (the “Offering”) of 12,500,000 shares of Class A common stock of Jones Energy, Inc. (the “Company”) at a price of $15.00 per share. The Company’s Class A common stock began trading on the New York Stock Exchange (“NYSE”) under the symbol “JONE” on July 24, 2013, and the Offering closed on July 29, 2013. Consequently, the unaudited consolidated financial statements and related discussion of financial condition and results of operations contained in this report pertain to Jones Energy Holdings, LLC (“JEH LLC”), the predecessor entity to the Company. In connection with the completion of the Offering, the Company became a holding company whose sole material asset consists of units of ownership in JEH LLC. As the sole managing member of JEH LLC, the Company is responsible for all operational, management and administrative decisions relating to JEH LLC’s business and will consolidate the financial results of JEH LLC and its subsidiaries.

JEH LLC acts as a holding company of operating subsidiaries that own and operate assets that are used in the exploration, development, production and acquisition of oil and natural gas properties. Prior to the Offering, the equity capital of JEH LLC consisted of several classes of limited liability company units with differing entitlements to distributions. In connection with the Offering, the Jones family, Metalmark Capital, Wells Fargo Central Pacific Holdings, Inc., and certain members of management, or, collectively, the Existing Owners, converted their existing membership interests in JEH LLC into a single class of units (the “JEH LLC Units”), and the Second Amended and Restated Limited Liability Company Agreement of JEH LLC was amended and restated to, among other things, modify JEH LLC’s equity capital to consist solely of the JEH LLC Units and admit the Company as the sole managing member of JEH LLC.

Unless the context otherwise requires, references in this report to “we,” “our,” “us,” or like terms, when used in a historical context, prior to the completion of the Offering, refer to JEH LLC and its subsidiaries. References in this report to “we,” “our,” “us,” or like terms, when used in the present tense or prospectively, subsequent to the Offering, refer to Jones Energy, Inc. and its subsidiaries.

While management believes that the financial statements contained herein are prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) and in compliance with the rules and regulations of the U.S. Securities and Exchange Commission (the “SEC”), the financial statements of JEH LLC may not be indicative of the financial results that will be reported for periods subsequent to the Offering of the Company. The information contained in this report should be read in conjunction with the information contained in Jones Energy, Inc.’s final prospectus dated July 23, 2013 and filed with the SEC pursuant to Rule 424(b) under the Securities Act of 1933, as amended (the “Securities Act”), on July 25, 2013 (the “Prospectus”).

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Item 1. Unaudited Consolidated Financial Statements

Jones Energy Holdings, LLC and Subsidiaries

(A Delaware limited liability company)

Consolidated Balance Sheets (Unaudited)

	June 30,		December 31,
(in thousands of dollars)	2013		2012

Assets
Current assets
Cash	$	29,366	$	23,726
Accounts receivable, net
Oil and gas sales	41,124		29,684
Joint interest owners	29,263		21,876
Other	1,848		4,590
Other current assets	5,156		1,088
Commodity derivative assets	18,053		17,648
Total current assets	124,810		98,612

Oil and gas properties, net, at cost under the successful efforts method	1,046,131		1,007,344
Other property, plant and equipment, net	2,764		3,398
Commodity derivative assets	34,540		25,199
Other assets	16,182		16,133
Total assets	$	1,224,427	$	1,150,686

Liabilities and Members’ Equity
Current liabilities
Trade accounts payable	$	60,248	$	38,036
Oil and gas sales payable	56,569		45,860
Accrued liabilities	5,122		3,873
Deferred tax liabilities	68		61
Asset retirement obligations	174		174
Commodity derivative liabilities	2,383		4,035
Total current liabilities	124,564		92,039

Long-term debt	605,000		610,000
Deferred revenue	15,000		—
Commodity derivative liabilities	88		7,657
Asset retirement obligations	10,023		9,332
Deferred tax liabilities	2,086		1,876
Total liabilities	756,761		720,904

Commitments and contingencies (Note 8)

Members’ equity
Class A preferred units; 14,250,000 authorized and issued	222,376		205,970
Class B preferred units; 1,500,000 authorized and issued	23,408		21,681
Class C preferred units; 8,500,000 authorized and issued	132,644		122,860
Common units; 4,500,000 authorized and issued	70,224		65,043
Management units; 3,194,444 authorized and issued	19,014		14,228
Total members’ equity	467,666		429,782
Total liabilities and members’ equity	$	1,224,427	$	1,150,686

The accompanying notes are an integral part of these consolidated financial statements.

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Jones Energy Holdings, LLC and Subsidiaries

(A Delaware limited liability company)

Consolidated Statements of Operations (Unaudited)

	Three Months Ended June 30,						Six Months Ended June 30,
(in thousands of dollars)	2013			2012			2013			2012

Operating revenues
Oil and gas sales	$	64,300		$	31,105		$	119,559		$	73,622
Other revenues	226			249			447			528
Total operating revenues	64,526			31,354			120,006			74,150

Operating costs and expenses
Lease operating	6,201			5,803			11,546			11,331
Production taxes	3,182			1,166			5,634			2,759
Exploration	479			107			605			181
Depletion, depreciation and amortization	26,922			18,249			52,023			37,022
Impairment of oil and gas properties	—			43			—			61
Accretion of discount	166			134			263			281
General and administrative	7,325			4,000			11,637			7,675
Total operating expenses	44,275			29,502			81,708			59,310
Operating income	20,251			1,852			38,298			14,840

Other income (expense)
Interest expense	(7,854		)	(5,552		)	(15,833		)	(12,152		)
Net gain on commodity derivatives	36,555			30,822			25,172			38,559
Gain (loss) on sales of assets	(45		)	(72		)	25			1,356
Other income (expense), net	28,656			25,198			9,364			27,763
Income before income tax	48,907			27,050			47,662			42,603

Income tax provision
Current	12			—			34			—
Deferred	240			112			217			223
Total income tax provision	252			112			251			223
Net income	$	48,655		$	26,938		$	47,411		$	42,380

The accompanying notes are an integral part of these consolidated financial statements.

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Jones Energy Holdings, LLC and Subsidiaries

(A Delaware limited liability company)

Statements of Changes In Members’ Equity (Unaudited)

	Preferred Units																			Total
	Class A				Class B				Class C				Common Units				Management Units			Members’
(amounts in thousands)	Units	Value			Units	Value			Units	Value			Units	Value			Units	Value		Equity

Balance at December 31, 2012	14,250	$	205,970		1,500	$	21,681		8,500	$	122,860		4,500	$	65,043		3,194	$	14,228	$	429,782

Stock-compensation expense	—	211			—	22			—	126			—	67			—	47		473
Distributions to members	—	(4,956		)	—	(522		)	—	(2,957		)	—	(1,565		)	—	—		(10,000		)
Net income	—	21,151			—	2,227			—	12,615			—	6,679			—	4,739		47,411

Balance at June 30, 2013	14,250	$	222,376		1,500	$	23,408		8,500	$	132,644		4,500	$	70,224		3,194	$	19,014	$	467,666

The accompanying notes are an integral part of these consolidated financial statements.

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Jones Energy Holdings, LLC and Subsidiaries

(A Delaware limited liability company)

Consolidated Statements of Cash Flows (Unaudited)

	Six Months Ended June 30,
(in thousands of dollars)	2013			2012

Cash flows from operating activities
Net income	$	47,411		$	42,380
Adjustments to reconcile net income to net cash provided by operating activities
Depletion, depreciation, and amortization	52,023			37,022
Impairment of oil and gas properties	—			61
Accretion of discount	263			281
Amortization of debt issuance costs	1,327			1,765
Stock compensation expense	473			283
Other compensation expense (Note 7)	2,465			—
Gain on commodity derivatives	(25,172		)	(38,559		)
Gain on sales of assets	(25		)	(1,356		)
Deferred income tax provision	217			223
Other - net	310			141
Changes in assets and liabilities
Accounts receivable	(17,456		)	26,167
Other assets	(7,885		)	(57		)
Accounts payable and accrued liabilities	7,859			(27,339		)
Deferred revenue	15,000			—
Net cash provided by operations	76,810			41,012
Cash flows from investing activities
Additions to oil and gas properties	(63,545		)	(62,034		)
Proceeds from sales of assets	423			9,151
Acquisition of other property, plant and equipment	(290		)	(323		)
Current period settlements of matured derivative contracts	7,267			11,907
Net cash used in investing	(56,145		)	(41,299		)
Cash flows from financing activities
Proceeds from issuance of long-term debt	—			44,243
Repayment under long-term debt	(5,000		)	(34,243		)
Payment of debt issuance costs	(25		)	—
Distributions to members (Note 7)	(10,000		)	—
Net cash (used in) provided by financing	(15,025		)	10,000
Net increase in cash	5,640			9,713
Cash
Beginning of period	23,726			6,136
End of period	$	29,366		$	15,849
Supplemental disclosure of cash flow information
Cash paid for interest	$	13,818		$	10,419
Noncash oil and gas property additions	26,312			(3,546		)
Current additions to ARO	263			166
Deferred offering costs	3,479			—
Noncash distributions to members (Note 7)	10,000			—

The accompanying notes are an integral part of these consolidated financial statements.

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Jones Energy Holdings, LLC and Subsidiaries

(A Delaware limited liability company)

Notes to Consolidated Financial Statements (Unaudited)

1. Organization and Description of Business

Jones Energy Holdings, LLC (“JEH LLC”) was organized December 16, 2009 as a Delaware limited liability company and began operations effective December 31, 2009. On December 31, 2009, a series of transactions was undertaken by JEH LLC as follows:

· The owners of Nosley Properties, LLC (“Nosley”) and Jones Energy, Ltd. (“JEL”) contributed all their ownership interests in Nosley and JEL for Common Units plus $15.0 million for Preferred Class B Units

· Metalmark Capital contributed $135.0 million for Preferred Class A Units

· Wells Fargo Energy Capital contributed $7.5 million for Preferred Class A Units

In addition to these capital contributions, JEH LLC borrowed $175.0 million from Wells Fargo N.A., used partially to repay the debt of Nosley and JEL. JEH LLC used the cash contributions and the balance of the Wells Fargo debt funding to acquire 100% of the equity interest of Crusader Energy Group, Inc., out of bankruptcy. The previous owners of Nosley and JEL hold two board of director seats and Metalmark holds two board of director seats; however, Metalmark holds the majority equity interest, which gives it effective control of JEH LLC.

On December 20, 2012 the owners of Class A Preferred, Class B Preferred and Common Units contributed $56.7 million, $25.2 million and $3.1 million, respectively, for Preferred Class C Units. JEH LLC used the capital contributions, along with $170 million borrowed from Wells Fargo N.A., to fund the acquisition of certain oil and gas properties in the Texas Panhandle (see Note 3, “Acquisition of Properties”).

In March 2013, Jones Energy, Inc. was formed as a Delaware corporation for the purpose of becoming a publicly traded entity and the holding company of JEH LLC. The historical financial information contained in this report relates to periods that ended prior to the completion of the initial public offering (“the Offering”) of Jones Energy, Inc. Consequently, the unaudited consolidated financial statements and notes thereto pertain to JEH LLC. In connection with the completion of the Offering on July 29, 2013, Jones Energy, Inc. became a holding company whose sole material asset consists of units of ownership in JEH LLC. As the sole managing member of JEH LLC, Jones Energy, Inc. is responsible for all operational, management and administrative decisions relating to JEH LLC’s business and for periods subsequent to July 29, 2013, will consolidate the financial results of JEH LLC and its subsidiaries.

JEH LLC is engaged in the acquisition, exploration, and production of oil and natural gas properties in the mid-continent U.S. through undivided ownership interests or through its wholly owned subsidiaries. JEH LLC operates in one industry segment and all of its operations are conducted in one geographic area of the United States. JEH LLC is headquartered in Austin, Texas.

2. Significant Accounting Policies

Basis of Presentation

The accompanying consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (GAAP). The

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Jones Energy Holdings, LLC and Subsidiaries

(A Delaware limited liability company)

Notes to Consolidated Financial Statements (Unaudited)

accompanying consolidated financial statements include JEH LLC and all of its subsidiaries. All significant intercompany transactions and balances have been eliminated in consolidation.

These interim financial statements have not been audited. However, in the opinion of management, all adjustments consisting of only normal and recurring adjustments necessary for a fair statement of the financial statements have been included. As these are interim financial statements, they do not include all disclosures required for financial statements prepared in conformity with GAAP. Interim period results are not necessarily indicative of results of operations or cash flows for a full year.

These consolidated financial statements have been prepared pursuant to the rules and regulations of the Securities and Exchange Commission (“SEC”) regarding interim financial reporting. Accordingly, they do not include all disclosures required by GAAP and should be read in conjunction with our most recent audited consolidated financial statements included in Jones Energy, Inc.’s final prospectus dated July 23, 2013 and filed with the SEC on July 25, 2013 pursuant to Rule 424(b) under the Securities Act of 1933, as amended.

Use of Estimates

In preparing the accompanying financial statements, management has made certain estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent liabilities, and the reported amounts of revenue and expenses during the reporting period. Actual results could differ from these estimates. Changes in estimates are recorded prospectively.

Significant assumptions are required in the valuation of proved oil and natural gas reserves, which affect JEH LLC’s estimates of depletion expense, impairment, and the allocation of value in our business combinations. Significant assumptions are also required in JEH LLC’s estimates of the unrealized gain or loss on commodity derivative assets and liabilities and asset retirement obligations (ARO).

Oil and Gas Properties

JEH LLC accounts for its oil and natural gas exploration and production activities under the successful efforts method of accounting. Oil and gas properties consisted of the following at June 30, 2013 and December 31, 2012:

	June 30,			December 31,
(in thousands of dollars)	2013			2012

Mineral interests in properties
Unproved	$	122,957		$	137,254
Proved	779,058			754,657
Wells and equipment and related facilities	452,905			372,628
	1,354,920			1,264,539
Less: Accumulated depletion and impairment	(308,789		)	(257,195		)
Net oil and gas properties	$	1,046,131		$	1,007,344

As of June 30, 2013 and December 31, 2012, there were no costs capitalized in connection with exploratory wells in progress.

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Jones Energy Holdings, LLC and Subsidiaries

(A Delaware limited liability company)

Notes to Consolidated Financial Statements (Unaudited)

JEH LLC capitalizes interest on expenditures for significant exploration and development projects that last more than six months while activities are in progress to bring the assets to their intended use. JEH LLC did not capitalize any interest during the period ended June 30, 2013 as no projects lasted more than six months. Depletion of oil and gas properties amounted to $26.7 million and $51.6 million for the three and six months ended June 30, 2013, respectively, and $18.1 million and $36.6 million for the three and six months ended June 30, 2012, respectively.

Other Property, Plant and Equipment

Other property, plant and equipment consisted of the following at June 30, 2013 and December 31, 2012:

	June 30,			December 31,
(in thousands of dollars)	2013			2012

Leasehold improvements	$	983		$	983
Furniture, fixtures, computers and software	2,305			2,204
Vehicles	740			719
Aircraft	412			1,295
Land	62			62
Production Equipment	72			72
	4,574			5,335
Less: Accumulated depreciation and amortization	(1,810		)	(1,937		)
Net other property, plant and equipment	$	2,764		$	3,398

Other property, plant and equipment is depreciated on a straight-line basis over the estimated useful lives of the property, plant, and equipment, which range from three years to ten years. Depreciation and amortization of other property, plant and equipment amounted to $0.2 million and $0.4 million during the three and six months ended June 30, 2013, respectively, and $0.2 million and $0.4 million during the three and six months ended June 30, 2012, respectively.

Commodity Derivatives

JEH LLC records its commodity derivative instruments on the consolidated balance sheet as either an asset or liability measured at its fair value. Changes in the derivative’s fair value are recognized currently in earnings, unless specific hedge accounting criteria are met. During the three month period ended June 30, 2013, JEH LLC elected not to designate any of its commodity price risk management activities as cash flow or fair value hedges. The changes in the fair values of outstanding financial instruments are recognized as gains or losses in the period of change.

Although JEH LLC does not designate its commodity derivative instruments as cash-flow hedges, management uses those instruments to reduce JEH LLC’s exposure to fluctuations in commodity prices related to its natural gas and oil production. Unrealized gains and losses, at fair value, are included on the consolidated balance sheet as current or noncurrent assets or liabilities based on the anticipated timing of cash settlements under the related contracts. Changes in the fair value of commodity derivative contracts are recorded in earnings as they occur and are included in other income (expense) on the consolidated statement of operations whether they are realized or unrealized. See Note 4, “Fair Value Measurement” for disclosure about the fair values of commodity derivative instruments.

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Jones Energy Holdings, LLC and Subsidiaries

(A Delaware limited liability company)

Notes to Consolidated Financial Statements (Unaudited)

Asset Retirement Obligations

A summary of JEH LLC’s ARO for the six months ended June 30, 2013 is as follows:

(in thousands of dollars)
Balance at December 31, 2012	$	9,506
Liabilities incurred	263
Accretion of discount	263
Liabilities settled due to sale of related properties	(4		)
Liabilities settled due to plugging and abandonment	(32		)
Change in estimate	201
Balance at June 30, 2013	10,197
Less: Current portion of ARO	(174		)
Total long-term ARO at June 30, 2013	$	10,023

Income Taxes

No provision for federal income taxes is recorded because the taxable income or loss is includable in the income tax returns of the individual partners and members.

Based on management’s analysis, JEH LLC did not have any uncertain tax positions as of June 30, 2013 and December 31, 2012.

Members’ Equity

The operations of JEH LLC are governed by the provisions of a limited liability company agreement executed by and among its members. JEH LLC is authorized to issue four classes of units, consisting of 14,250,000 units designated as Class A Preferred Units, 1,500,000 units designated as Class B Preferred Units, 4,500,000 units designated as Common Units, and 2,250,000 units designated as Management Units. In accordance with an amendment to the LLC agreement, an additional 8,500,000 units were issued and designated as Class C Preferred Units on December 20, 2012. The units are not represented by certificates. All Preferred and Common Units are issued at a price equal to $10.00 per unit. JEH LLC has issued 14,250,000 Class A Preferred Units, 1,500,000 Class B Preferred Units, 4,500,000 Common Units, and 8,500,000 Class C Preferred Units. JEH LLC issued 2,250,000 Management Units in April 2011 and on December 20, 2012, JEH LLC issued an additional 944,444 Management Units. In the second quarter of 2013, JEH LLC issued an additional 576,000 Management Units, which also have a five year vesting period, at a fair value of $8.71 per unit. The grant date fair value was determined using the Offering price (see Note 10) adjusted for the conversion ratio of the units for Jones Energy, Inc. shares (see Note 10). Members holding Preferred Units and Common Units vote together as a single class. A member is entitled to one vote for each Preferred Unit and Common Unit held by such member in connection with the election of directors and on all matters to be voted upon by the members of JEH LLC. Management Units have no voting power.

Members holding Class C Preferred Units have rights to all distributions, including those resulting from a liquidation, until their capital is returned. Members holding Class A and B Preferred Units then receive all distributions until their capital is returned. Members holding Common Units then receive all distributions until their capital is returned. Any additional distributions are distributed among all unit holders, including Management Units, ratably based upon number of units held.

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Jones Energy Holdings, LLC and Subsidiaries

(A Delaware limited liability company)

Notes to Consolidated Financial Statements (Unaudited)

As an LLC, the liability of the members is limited to their contributed capital. Allocation of net income is based on a hypothetical distribution at book value.

Recent Accounting Developments

The following recently issued accounting pronouncements have or will be adopted by JEH LLC:

Offsetting Assets and Liabilities

In December 2011, the Financial Accounting Standards Board (“FASB”), issued authoritative guidance requiring entities to disclose both gross and net information about instruments and transactions eligible for offset arrangement. The additional disclosures enable users of the financial statements to evaluate the effect or potential effect of netting arrangements on an entity’s financial position. These disclosure requirements are effective for interim and annual periods beginning after January 1, 2013. JEH LLC has provided all required disclosures for the periods presented in the second quarter of 2013 as they pertain to its commodity derivative instruments (see Note 4, “Fair Value Measurement”). These disclosure requirements did not affect JEH LLC’s operating results, financial position, or cash flows.

3. Acquisition of Properties

No material property acquisitions occurred during the six months ended June 30, 2013 and 2012.

On December 20, 2012, JEH LLC acquired certain oil and natural gas properties located in Texas for a purchase price of $251.9 million (referred to herein as the “Chalker acquisition” or “Chalker”). The acquired assets represented a strategic fit with JEH LLC’s existing Texas Panhandle properties and included both producing properties and undeveloped acreage. The purchase was financed with additional capital and long-term debt. During the quarter ended June 30, 2013, JEH LLC made a final determination with the sellers as to the purchase price resulting in a final purchase price of $253.5 million. The final purchase price was allocated as follows:

Oil and gas properties
Unproved	$	71,264
Proved	182,493
Asset retirement obligations	(293		)
Total purchase price	$	253,464

This acquisition qualified as a business combination under ASC 805. The valuation to determine the fair value was principally based on the discounted cash flows of both the producing and undeveloped properties, including projected drilling and equipment costs, recoverable reserves, production streams, future prices and operating costs, and risk-adjusted discount rates reflective of the current market.

The unaudited pro forma results presented below have been prepared to give the effect of the acquisition on our results of operations for the three and six months ended June 30, 2012. The unaudited pro forma results do not purport to represent what our actual results of operations would have been if the acquisition had been completed on January 1, 2012 or to project our results of operations for any future date or period.

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Jones Energy Holdings, LLC and Subsidiaries

(A Delaware limited liability company)

Notes to Consolidated Financial Statements (Unaudited)

	Three Months Ended June 30, 2012
(in thousands of dollars)	Actual		Pro Forma

Total operating revenue	$	31,354	$	41,057
Total operating expenses	29,502		30,317
Operating income	1,852		10,740
Net income	26,938		35,826

	Six Months Ended June 30, 2012
(in thousands of dollars)	Actual		Pro Forma

Total operating revenue	$	74,150	$	92,439
Total operating expenses	59,310		60,888
Operating income	14,840		31,551
Net income	42,380		59,091

4. Fair Value Measurement

Fair Value of Financial Instruments

JEH LLC determines fair value amounts using available market information and appropriate valuation methodologies. Fair value is the price that would be received to sell an asset or would be paid to transfer a liability in an orderly transaction between market participants at the measurement date. Considerable judgment is required in interpreting market data to develop the estimates of fair value. The use of different market assumptions and/or estimation methods may have a material effect on the estimated fair value amounts.

JEH LLC enters into a variety of derivative financial instruments, which may include over-the-counter instruments, such as natural gas, crude oil, and natural gas liquid contracts. JEH LLC utilizes valuation techniques that maximize the use of observable inputs, where available. If listed market prices or quotes are not published, fair value is determined based upon a market quote, adjusted by other market-based or independently sourced market data, such as trading volume, historical commodity volatility, and counterparty-specific considerations. These adjustments may include amounts to reflect counterparty credit quality, the time value of money, and the liquidity of the market.

Counterparty credit valuation adjustments are necessary when the market price of an instrument is not indicative of the fair value as a result of the credit quality of the counterparty. Generally, market quotes assume that all counterparties have low default rates and equal credit quality. Therefore, an adjustment may be necessary to reflect the quality of a specific counterparty to determine the fair value of the instrument. JEH LLC currently has all derivative positions placed and held by members of its lending group, which have strong credit quality.

Liquidity valuation adjustments are necessary when JEH LLC is not able to observe a recent market price for financial instruments that trade in less active markets. Exchange traded contracts are valued at market value without making any additional valuation adjustments; therefore, no liquidity reserve is applied.

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Jones Energy Holdings, LLC and Subsidiaries

(A Delaware limited liability company)

Notes to Consolidated Financial Statements (Unaudited)

Valuation Hierarchy

Fair value measurements are grouped into a three-level valuation hierarchy. The valuation hierarchy is based upon the transparency of inputs to the valuation of an asset or liability as of the measurement date. A financial instrument’s categorization within the hierarchy is based upon the input that requires the highest degree of judgment in the determination of the instrument’s fair value. The three levels are defined as follows:

Level 1 Pricing inputs are based on published prices in active markets for identical assets or liabilities as of the reporting date. JEH LLC does not classify any of its financial instruments in Level 1.

Level 2 Pricing inputs include quoted prices for similar assets and liabilities in active markets, and inputs that are observable for the asset or liability, either directly or indirectly, as of the reporting date. Contracts that are not traded on a recognized exchange or are tied to pricing transactions for which forward curve pricing is readily available are classified as Level 2 instruments. These include natural gas, crude oil and some natural gas liquids price swaps and natural gas basis swaps.

Level 3 Pricing inputs include significant inputs that are generally unobservable from objective sources. JEH LLC classifies natural gas liquid swaps and basis swaps for which future pricing is not readily available as Level 3. JEH LLC obtains estimates from independent third parties for its open positions and subjects those to the credit adjustment criteria described above.

The financial instruments carried at fair value as of June 30, 2013 and December 31, 2012, by consolidated balance sheet caption and by valuation hierarchy, as described above are as follows:

	June 30, 2013
	Fair Value Measurements
(in thousands of dollars)	(Level 1)		(Level 2)			(Level 3)		Total
Commodity Price Hedges
Current assets	$	—	$	17,094		$	959	$	18,053
Long-term assets	—		32,006			2,534		34,540
Current liabilities	—		2,383			—		2,383
Long-term liabilities	—		(64		)	152		88

	December 31, 2012
	Fair Value Measurements
(in thousands of dollars)	(Level 1)		(Level 2)		(Level 3)		Total
Commodity Price Hedges
Current assets	$	—	$	17,648	$	—	$	17,648
Long-term assets	—		24,756		443		25,199
Current liabilities	—		2,992		1,043		4,035
Long-term liabilities	—		6,739		918		7,657

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Jones Energy Holdings, LLC and Subsidiaries

(A Delaware limited liability company)

Notes to Consolidated Financial Statements (Unaudited)

The following table represents quantitative information about Level 3 inputs used in the fair value measurement of JEH LLC’s commodity derivative contracts as of June 30, 2013.

	Quantitative Information About Level 3 Fair Value Measurements
(in thousands of dollars)	Fair Value	Valuation Technique	Unobservable Input	Range

Natural gas liquid swaps		Use a discounted cash flow approach using inputs including forward price statements from counterparties	Natural gas liquid futures	$8.19 - $82.37 per barrel
Basis swaps		Use a discounted cash flow approach using inputs including forward price statements from counterparties	Forward basis prices	$(0.12) - $0.02 per mmbtu

Significant increases (decreases) in natural gas liquid futures in isolation would result in a significantly higher (lower) fair value measurement. The following table presents the changes in the Level 3 financial instruments for the six months ended June 30, 2013. Changes in fair value of Level 3 instruments represent changes in unrealized gains and losses for the periods that are reported in other income (expense). New contracts entered into during the year are generally entered into at no cost with changes in fair value from the date of agreement representing the entire fair value of the instrument. Transfers between levels are evaluated at the end of the reporting period.

(in thousands of dollars)

Balance at December 31, 2012, net	$	(1,519	)
Purchases	—
Settlements	—
Transfers to Level 2	1,083
Transfers to Level 3	(254		)
Changes in fair value	4,031
Balance at June 30, 2013, net	$	3,341

Transfers from Level 3 to Level 2 represent all of JEH LLC’s natural gas liquids swaps for which observable forward curve pricing information has become readily available. Transfers to Level 3 represent basis swaps that were previously considered Level 2 but due to the unavailability of forward prices at the valuation date were classified as Level 3 as of June 30, 2013. There were no purchases or settlements in the period that resulted in changes to Level 3.

Offsetting Assets and Liabilities

As of June 30, 2013, the counterparties to our commodity derivative contracts consisted of six financial institutions. All of our counterparties or their affiliates are also lenders under our credit facility. Therefore, we are not generally required to post additional collateral under our derivative agreements.

Our derivative agreements contain set-off provisions that state that in the event of default or early termination, any obligation owed by the defaulting party may be offset against any obligation owed to the defaulting party.

We adopted the guidance requiring disclosure of both gross and net information about financial instruments eligible for netting in the balance sheet under our derivative agreements. The following table presents information about our commodity derivative contracts which are netted on our balance sheet as of June 30, 2013 and December 31, 2012:

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Jones Energy Holdings, LLC and Subsidiaries

(A Delaware limited liability company)

Notes to Consolidated Financial Statements (Unaudited)

(in thousands)	Gross Amounts of Recognized Assets / Liabilities		Gross Amounts Offset in the Balance Sheet		Net Amounts of Assets/Liabilities Presented in the Balance Sheet		Gross Amounts Not Offset in the Balance Sheet		Net Amount
June 30, 2013
Commodity derivative contracts
Assets	54,874		(5,311	)	49,563		3,030		52,593
Liabilities	(7,436	)	5,311		(2,125	)	(346	)	(2,471	)
December 31, 2012
Commodity derivative contracts
Assets	49,200		(7,831	)	41,369		1,478		42,847
Liabilities	(17,928	)	7,831		(10,097	)	(1,595	)	(11,692	)

Nonfinancial Assets and Liabilities

Assets and liabilities acquired in business combinations are recorded at their fair value on the date of acquisition. Significant Level 3 assumptions associated with the calculation of future cash flows used in the analysis of fair value of the oil and gas property acquired include JEH LLC’s estimate of future commodity prices, production costs, development expenditures, production, risk-adjusted discount rates, and other relevant data. Additionally, fair value is used to determine the inception value of JEH LLC’s AROs. The inputs used to determine such fair value are primarily based upon costs incurred historically for similar work, as well as estimates from independent third parties for costs that would be incurred to restore leased property to the contractually stipulated condition. Additions to JEH LLC’s ARO represent a nonrecurring Level 3 measurement.

JEH LLC reviews its proved oil and gas properties for impairment purposes by comparing the expected undiscounted future cash flows at a producing field level to the unamortized capitalized cost of the asset. During the three and six month periods ended June 30, 2012, such reviews indicated that unamortized capitalized costs of certain properties were higher than their expected undiscounted future cash flows due primarily to downward reserve revisions, drilling of marginal or uneconomic wells, or development dry holes in certain producing fields. As a result, JEH LLC recorded charges of $0.04 and $0.06 million during the three and six months ended June 30, 2012. No impairment was recorded during the three and six months ended June 30, 2013. Impairment of oil and gas properties charges are recorded on the statement of operations. Significant assumptions associated with the calculation of future cash flows used in the impairment analysis include JEH LLC’s estimate of future commodity prices, production costs, development expenditures, production, risk-adjusted discount rates, and other relevant data. As such, the fair value of oil and gas properties used in estimating impairment represents a nonrecurring Level 3 measurement.

The fair value measurement of Monarch shares is based on inputs that are not observable in the market and therefore represent Level 3 inputs. The fair value was measured using a market approach valuation technique. Significant inputs to the valuation include estimates of future revenue, and operating costs, and related valuation multiples. These inputs require significant judgments and estimates by management at the time of the valuation and are subject to change.

5. Derivative Instruments and Hedging Activities

JEH LLC had various commodity derivatives in place to offset uncertain price fluctuations that could affect its future operations as of June 30, 2013 and December 31, 2012, as follows:

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Jones Energy Holdings, LLC and Subsidiaries

(A Delaware limited liability company)

Notes to Consolidated Financial Statements (Unaudited)

Hedging Positions

	June 30, 2013
								Weighted			Final
		Low			High			Average			Expiration

Oil swaps	Exercise price	$	81.00		$	104.45		$	89.38
	Barrels per month	24,000			143,116			89,275			December 2017
Natural gas swaps	Exercise price	$	3.52		$	6.90		$	4.96
	mmbtu per month	430,000			1,110,000			742,652			December 2017
Basis swaps	Contract differential	$	(0.45	)	$	(0.03	)	$	(0.32	)
	mmbtu per month	320,000			820,000			423,333			March 2016
Natural gas liquids swaps	Exercise price	$	6.72		$	97.13		$	29.57
	Barrels per month	2,000			144,973			46,314			December 2017

	December 31, 2012
								Weighted			Final
		Low			High			Average			Expiration

Oil swaps	Exercise price	$	81.00		$	104.45		$	89.60
	Barrels per month	24,000			143,116			89,323			December 2017
Natural gas swaps	Exercise price	$	3.52		$	6.90		$	4.96
	mmbtu per month	430,000			1,110,000			767,053			December 2017
Basis swaps	Contract differential	$	(0.65	)	$	(0.03	)	$	(0.31	)
	mmbtu per month	320,000			850,000			484,615			March 2016
Natural gas liquids swaps	Exercise price	$	6.72		$	97.13		$	33.81
	Barrels per month	2,000			144,973			55,616			December 2017

JEH LLC recognized net gains on derivative instruments of $36.6 million and $25.2 million for the three and six months ended June 30, 2013, respectively, and $30.8 million and $38.6 million for the three and six months ended June 30, 2012, respectively.

6. Long-Term Debt

JEH LLC entered into two credit agreements dated December 31, 2009, with Wells Fargo Bank N.A. The Senior Secured Revolving Credit Facility (the “Revolver”) had a first lien, maximum available credit amount of $360.0 million and a borrowing base of $150.0 million. The Second Lien Term Loan (the “Term Loan”) had a face amount of $40.0 million. JEH LLC’s oil and gas properties are pledged as collateral against these credit agreements. The original maturity date of the Revolver was December 31, 2013, and the original maturity date of the Term Loan was June 30, 2014.

On November 18, 2011, the borrowing base of the Revolver was increased to $400.0 million, and the funded amount of the Term Loan was increased to $120.0 million.

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Jones Energy Holdings, LLC and Subsidiaries

(A Delaware limited liability company)

Notes to Consolidated Financial Statements (Unaudited)

On November 5, 2012, the credit agreements were amended extending the maturity date of the Revolver to November 5, 2017 and the maturity date of the Term loan to May 5, 2018. The borrowing base was decreased to $360.0 million.

On December 20, 2012, the credit agreements were further amended to finance an acquisition of certain oil and gas properties. The borrowing base on the Revolver was increased to $490.0 million and the funded amount of the Term Loan was increased to $160.0 million.

On June 12, 2013, the credit agreements were further amended. The borrowing base on the Revolver was increased to $500.0 million.

For the three and six months ended June 30, 2013, the average interest rates under the Revolver were 3.05% and 3.16%, respectively, on an outstanding balance of $445 million. For the same periods in 2012, the average interest rates were 3.15% and 3.15%, respectively, on an outstanding balance of $305 million. Total interest and commitment fees under the two facilities were $7.2 million and $14.5 million for the three and six months ended June 30, 2013, respectively, and $4.7 million and $10.4 million for the three and six months ended June 30, 2012, respectively.

The Revolver requires a quarterly payment of commitment fees equal to 0.5% on the daily unused amount of the commitment.

Terms of the Term Loan require JEH LLC to pay interest on the loan every three months with the principal and interest due on the loan maturity date of May 5, 2018. Prepayment of the principal balance is allowed in whole or in part at any time with a premium payment due in certain conditions. Any amounts prepaid may not be re-borrowed.

The Revolver and Term Loans are categorized as Level 3 in the valuation hierarchy as the debt is not publicly traded and no observable market exists to determine the fair value; however, the carrying value of the Revolver and Term Loans approximate fair value, as they are subject to short-term floating interest rates that approximate the rates available to JEH LLC for those periods.

The Revolver and Term Loans include covenants that require, among other things, restrictions on asset sales, distributions to members, and additional indebtedness, and the maintenance of certain financial ratios, including leverage, proven reserves to debt, and current ratio. At June 30, 2013 and December 31, 2012, JEH LLC was in compliance with its financial debt covenants.

7. Monarch Investment

On May 7, 2013, JEH LLC entered into a marketing agreement with a company related through common ownership, Monarch Natural Gas, LLC, for the sale to Monarch of natural gas produced from certain properties. In connection with that agreement, Monarch issued to JEH LLC equity interests in its parent, Monarch Natural Gas Holdings, LLC, having an estimated fair value of $15.0 million. Contemporaneous with the execution of the marketing agreement and the issuance of the equity interests, JEH LLC distributed 67% of the Monarch equity interests to JEH LLC’s owners pro rata based on equity contributions and approximately 16% of the interests to management. The remaining approximately 17% of the equity interests were reserved for distribution to management through an incentive plan. JEH LLC recognized $2.5 million of compensation expense in the second quarter of 2013 in connection with the management distributions and incentive plan. In addition, JEH LLC recorded deferred revenue of $15.0 million which will be amortized over the 10-year life of the marketing contract.

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Jones Energy Holdings, LLC and Subsidiaries

(A Delaware limited liability company)

Notes to Consolidated Financial Statements (Unaudited)

8. Commitments and Contingencies

JEH LLC is subject to legal proceedings and claims that arise in the ordinary course of its business. JEH LLC believes that the final disposition of such matters will not have a material adverse effect on its financial position, results of operations, or liquidity.

9. Income Taxes

The provision for income taxes relates solely to the Texas Margin Tax and consists of the following for the three and six months ended June 30, 2013 and 2012:

	Three Months Ended June 30,				Six Months Ended June 30,
(in thousands of dollars)	2013		2012		2013		2012

Current	$	12	$	—	$	34	$	—
Deferred	240		112		217		223
	$	252	$	112	$	251	$	223

10. Subsequent Events

Initial Public Offering of Jones Energy, Inc.

A corporate reorganization and recapitalization occurred in connection with the initial public offering on July 29, 2013. The existing owners of JEH LLC converted their existing membership interests in JEH LLC into JEH LLC Units and amended the existing LLC agreement to, among other things, modify its equity capital to consist solely of JEH LLC Units. Jones Energy, Inc. became the sole managing member of JEH LLC. Two classes of common stock, Class A common stock and Class B common stock, were authorized in connection with the offering. Only Class A common stock was offered to investors pursuant to the offering. In a transaction separate from the offering, Jones Energy, Inc. issued to the Existing Owners of JEH LLC, a number of shares of Class B common stock equal to the number of JEH LLC Units issued to the Existing Owners.

On July 23, 2013 Jones Energy, Inc. priced 12,500,000 of Class A common stock shares at $15.00 per share and on July 24, 2013 shares of Jones Energy, Inc.’s common stock began trading on the New York Stock Exchange under the symbol “JONE”. After deducting expenses and underwriting discounts and commissions of approximately $10.5 million, Jones Energy, Inc. received net proceeds of $177.0 million (or $173.0 million net of estimated offering expenses paid directly by us) and used a portion of these proceeds to repay $167.0 million of outstanding borrowings under the senior secured revolving credit facility.

Issuance of Management Units

JEH LLC issued 993,944 Management Units in July 2013 with a five-year vesting requirement and a grant-date fair value of $8.71. The grant-date fair value was determined using the Offering price adjusted for the conversion ratio of the units for Jones Energy, Inc. shares.

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Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with the “Management’s Discussion and Analysis of Financial Condition and Results of Operations” section and audited consolidated financial statements and related notes thereto included in our final prospectus dated July 23, 2013 and filed on July 25, 2013 with the Securities and Exchange Commission pursuant to Rule 424(b) under the Securities Act and with the unaudited consolidated financial statements and related notes thereto presented in this Quarterly Report on Form 10-Q.

Overview

We are an independent oil and gas company engaged in the development, production and acquisition of oil and natural gas properties in the Anadarko and Arkoma basins of Texas and Oklahoma. Our CEO, Jonny Jones, founded our predecessor company in 1988 in continuation of his family’s long history in the oil and gas business, which dates back to the 1920’s. We have grown rapidly by leveraging our focus on low cost drilling and completions and our horizontal drilling expertise to develop our inventory and execute several strategic acquisitions. We have accumulated extensive knowledge and experience in developing the Anadarko and Arkoma basins, having concentrated our operations in the Anadarko basin for 25 years and applied our knowledge to the Arkoma basin since 2011. We have drilled over 580 total wells, including over 400 horizontal wells, since our formation and delivered compelling economic returns over various commodity price cycles. Our operations are focused on horizontal drilling and completions within two distinct basins in the Texas Panhandle and Oklahoma:

· the Anadarko Basin—targeting the liquids-rich Cleveland, Granite Wash, Tonkawa and Marmaton formations; and

· the Arkoma Basin—targeting the liquids-rich fairway of the Woodford shale formation.

We optimize returns through a disciplined emphasis on controlling costs and promoting operational efficiencies, and we believe we are recognized as one of the lowest-cost drilling and completion operators in the Cleveland and Woodford shale formations.

The Anadarko and Arkoma basins are among the most prolific and largest onshore producing oil and natural gas basins in the United States, enjoying multiple producing horizons and extensive well control demonstrated over seven decades of development. The formations we target are generally characterized by oil and liquids-rich natural gas content, extensive production histories, long-lived reserves, high drilling success rates and attractive initial production rates. We focus on formations in our operating areas that we believe offer significant development and acquisition opportunities and to which we can apply our technical experience and operational excellence to increase proved reserves and production to deliver compelling economic rates of return. Our goal is to build value through a disciplined balance between developing our current inventory of 2,435 gross identified drilling locations and actively pursuing joint venture agreements, farm-out agreements, joint operating agreements and similar partnering agreements, which we refer to as joint development agreements, organic leasing proximate to existing acreage and strategic acquisitions.

Our profitability and ability to grow depend principally on the prices we obtain for our hydrocarbons, the volumes we produce and our ability to drill and complete wells at lower costs than other operators in our areas. Oil, natural gas and NGL prices historically have been volatile, may fluctuate widely in the future and are dependent on factors beyond our control, such as economic, political and regulatory developments, as well as competition from other sources of energy. Development of unconventional oil and gas in the U.S. continues to change the landscape of the onshore resource as well as pricing for the commodities. In light of price volatility, we continually evaluate and adjust our drilling program to allocate capital to wells that we believe will provide the most attractive returns. Additionally, we hedge a substantial portion of our expected future oil and gas production to reduce our exposure to fluctuations in commodity price. See “Quantitative and qualitative disclosures about market risk— Commodity price risk and hedges” below for discussion of our hedging and hedge positions.

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On July 29, 2013, we closed our initial public offering of 12,500,000 shares of our Class A common stock at a price to the public of $15.00 per share. We received net proceeds of approximately $177.0 million (net of underwriting discounts and commissions).

Second Quarter 2013 Highlights:

· Increased total production to 16,725 barrels of oil equivalent per day (“Boe/d”), up 5% from the first quarter of 2013 and 37% from the second quarter of 2012

· Increased oil production to 4,540 barrels per day (“Bbl/d”), up 31% from the first quarter of 2013 and 147% from the second quarter of 2012

· Increased adjusted EBITDAX to $52.7 million, up 12% from the first quarter of 2013 and 71% from the second quarter of 2012

· Increased drilling pace from five rigs as of April 1, 2013 to six rigs as of June 30, 2013, all of which were drilling in the Cleveland; expect to add four additional rigs by year end (two Cleveland and two Woodford)

· Achieved our fastest ever spud to total depth (“TD”) time and average rate of penetration for a Cleveland well of 14.6 days and 873 ft./day, respectively

· Achieved a 40% production uplift by optimizing stimulation design and increasing stage count from 10 to 14 on recent Woodford completions with at least three months of production

· Signed a new Joint Development Agreement (“JDA”) with Vanguard Natural Resources, covering a 360 section AMI in the Arkoma Woodford

· Entered into an agreement with BP to drill up to 17 wells in the Arkoma Woodford

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Results of Operations

The following table summarizes our revenues, expenses and production data for the periods indicated.

(in thousands of dollars except for production, sales	Three Months Ended June 30,									Six Months Ended June 30,
price and average cost data)	2013			2012			Change			2013			2012			Change

Revenues:
Oil	$	36,674		$	15,050		$	21,624		$	64,249		$	34,109		$	30,140
Natural gas	14,900			5,003			9,897			27,687			12,404			15,283
NGLs	12,726			11,052			1,674			27,623			27,109			514
Total oil and gas	64,300			31,105			33,195			119,559			73,622			45,937
Other	226			249			(23		)	447			528			(81		)
Total operating revenues	64,526			31,354			33,172			120,006			74,150			45,856

Costs and expenses:
Lease operating	6,201			5,803			398			11,546			11,331			215
Production taxes	3,182			1,166			2,016			5,634			2,759			2,875
Exploration	479			107			372			605			181			424
Depletion, depreciation and amortization	26,922			18,249			8,673			52,023			37,022			15,001
Impairment of oil and gas properties	—			43			(43		)	—			61			(61		)
Accretion of discount	166			134			32			263			281			(18		)
General and administrative	7,325			4,000			3,325			11,637			7,675			3,962
Total costs and expenses	44,275			29,502			14,773			81,708			59,310			22,398
Operating income	20,251			1,852			18,400			38,298			14,840			23,458

Other income (expenses):
Interest expense	(7,854		)	(5,552		)	(2,302		)	(15,833		)	(12,152		)	(3,681		)
Net gain on commodity derivatives	36,555			30,822			5,733			25,172			38,559			(13,387		)
Gain (loss) on sales of assets	(45		)	(72		)	27			25			1,356			(1,331		)
Total other income (expense)	28,656			25,198			3,458			9,364			27,763			(18,399		)
Income before income tax	48,907			27,050			21,858			47,662			42,603			5,059
Income tax provision	252			112			140			251			223			28
Net income	$	48,655		$	26,938		$	21,718		$	47,411		$	42,380		$	5,031

Net production volumes:
Oil (MBbls)	413			167			246			725			361			364
Natural gas (MMcf)	4,138			3,268			870			8,404			6,812			1,592
NGLs (MBbls)	419			399			20			825			845			(20		)
Total (MBoe)	1,522			1,111			411			2,951			2,341			609
Average net (Boe/d)	16,725			12,209			4,516			16,304			12,934			3,370

Average sales price:
Oil (per Bbl)	$	88.80		$	90.12		$	(1.32	)	$	88.62		$	94.48		$	(5.87	)
Natural gas (per Mcf)	$	3.60		$	1.53		$	2.07		$	3.29		$	1.82		$	1.47
NGLs (per Bbl)	$	30.37		$	27.70		$	2.67		$	33.48		$	32.08		$	1.40
Combined (per Boe) realized	$	42.25		$	28.00		$	14.25		$	40.51		$	31.45		$	9.07

Average costs (per BOE):
Lease operating	$	4.07		$	5.22		$	(1.15	)	$	3.91		$	4.84		$	(0.93	)
Production taxes	$	2.09		$	1.05		$	1.04		$	1.91		$	1.18		$	0.73
Depletion, depreciation and amortization	$	17.69		$	16.43		$	1.26		$	17.63		$	15.81		$	1.81
General and administrative	$	4.81		$	3.60		$	1.21		$	3.94		$	3.28		$	0.66

Non-GAAP financial measure

Adjusted EBITDAX is a supplemental non-GAAP financial measure that is used by management and external users of our consolidated financial statements, such as industry analysts, investors, lenders and rating agencies.

We define Adjusted EBITDAX as earnings before interest expense, income taxes, depreciation, depletion and amortization, exploration expense, unrealized gains and losses from derivatives, and other items. Adjusted EBITDAX is not a measure of net income as determined by GAAP. Management believes Adjusted EBITDAX is useful because it allows them to more effectively evaluate our operating performance and compare the results of our operations from period to period and against our peers without regard to our financing methods or capital structure. We exclude the items listed above from net income in arriving at Adjusted EBITDAX because these amounts can vary substantially from company to company within our industry depending upon accounting methods and book

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values of assets, capital structures and the method by which the assets were acquired. Adjusted EBITDAX has limitations as an analytical tool and should not be considered as an alternative to, or more meaningful than, net income as determined in accordance with GAAP or as an indicator of our liquidity. Certain items excluded from Adjusted EBITDAX are significant components in understanding and assessing a company’s financial performance, such as a company’s cost of capital and tax structure, as well as the historical costs of depreciable assets. Our presentation of Adjusted EBITDAX should not be construed as an inference that our results will be unaffected by unusual or non-recurring items. Our computations of Adjusted EBITDAX may not be comparable to other similarly titled measures of other companies.

The following table sets forth a reconciliation of net income (loss) as determined in accordance with GAAP to Adjusted EBITDAX for the periods indicated:

	Three Months Ended June 30,						Six Months Ended June 30,
(in thousands of dollars)	2013			2012			2013			2012

Reconciliation of Adjusted EBITDAX to net income
Net income	$	48,655		$	26,938		$	47,411		$	42,380
Interest expense (excluding amortization of deferred financing costs)	7,190			4,669			14,506			10,387
Deferred taxes	240			112			217			223
Amortization of deferred financing costs	664			883			1,327			1,765
Depreciation and depletion	26,922			18,249			52,023			37,022
Impairment of oil and natural gas properties	—			43			—			61
Accretion expense	166			134			263			281
Other non-cash charges	145			201			310			141
Stock compensation expense	352			142			473			283
Other compensation expense	2,465			—			2,465			—
Net gain on derivative contracts	(36,555		)	(30,822		)	(25,172		)	(38,559		)
Current period settlements of matured derivative contracts	2,457			10,179			6,205			15,420
Loss (gain) on sales of assets	45			72			(25		)	(1,356		)
Adjusted EBITDAX	$	52,746		$	30,800		$	100,003		$	68,048

Results of Operations - Three months ended June 30, 2013 as compared to three months ended June 30, 2012

Operating revenues

Oil and gas sales. Our oil and gas sales increased by $33.2 million (106.8%) to $64.3 million for the three months ended June 30, 2013, as compared to $31.1 million for the three months ended June 30, 2012. The increase was primarily due to higher oil and natural gas production volumes combined with higher oil and natural gas prices. Crude oil production increased 147.3%, from 167 MMbls for the three months ended June 30, 2012 to 413 MMbls for the three months ended June 30, 2013, primarily resulting from the wells acquired from Chalker (the “Chalker properties”) and subsequent drilling thereon. The Chalker properties have an initial oil rate that is higher than our average historical Cleveland well and therefore generate higher revenue per well earlier in their life than average. Natural gas production increased 26.6% from 3,268 MMcf for the three months ended June 30, 2012 to 4,138 MMcf for the three months ended June 30, 2013, primarily due to new wells added through drilling and the Chalker acquisition. The realized average natural gas price, excluding the effects of commodity derivative instruments, increased from $1.53 per Mcf to $3.60 per Mcf, or 135.3%, in the three months ended June 30, 2013 as compared to the three months ended June 30, 2012.

Costs and expenses

Lease operating. Per unit lease operating expense decreased $1.15 per Boe (22%) to $4.07 per Boe in the second quarter of 2013 from $5.22 per Boe in the second quarter of 2012, due to the acquisition of the Chalker wells, which increased the overall productivity of our properties, particularly related to barrels of oil produced. The Chalker properties have an initial oil rate that is higher than our average historical Cleveland well and therefore generate higher revenue per well earlier in their life than average (and correspondingly lower lease operating expenses as a percentage thereof). Our lease operating expense increased by $0.4 million (6.9%) to $6.2 million for the three months ended June 30, 2013, as compared to $5.8 million for the three months ended June 30, 2012. Recurring operating

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expenses increased $0.4 million (9.1%) to $4.8 million for the three months ended June 30, 2013, as compared to $4.4 million for the three months ended June 30, 2012. Workover expense was consistent at $1.4 million for the three months ended June 30, 2013 and 2012. The increase in recurring lease operating expense was primarily due to an increase in the number of operated wells resulting from continued drilling activity and the Chalker acquisition.

Production taxes. Our production taxes increased by $2.0 million (166.7%) to $3.2 million for the three months ended June 30, 2013, as compared to $1.2 million for the three months ended June 30, 2012. Overall production taxes increased in conjunction with the increase in revenue; however, the average effective rate increased from 3.7% for the three months ended June 30, 2012 to 4.9% for the three months ended June 30, 2013. Production taxes were at a higher rate during the three months ended June 30, 2013 due to the acquisition and drilling of the Chalker properties in Texas, which imposes a higher initial tax rate than Oklahoma, where many of our other properties are located.

Depreciation, depletion and amortization. Depreciation, depletion and amortization increased by $8.7 million (47.8%) to $26.9 million for the three months ended June 30, 2013 as compared to $18.2 million for the three months ended June 30, 2012. This was primarily a result of continued drilling activity and the addition of the Chalker properties at the end of 2012, which increased our total proved reserve base in the Cleveland formation. On a per unit basis, depletion expense increased to $17.69 per Boe for the quarter ended June 30, 2013, compared to $16.43 per Boe for the quarter ended June 30, 2012.

General and administrative. Our general and administrative expenses increased $3.3 million (82.5%) to $7.3 million for the three months ended June 30, 2013, as compared to $4.0 million for the three months ended June 30, 2012. The increase was attributable to a one-time management distribution related to the Monarch incentive plan and an increase in salaries and benefits due to an increase in headcount. On a per unit basis, general and administrative expense increased from $3.60 per Boe for the three months ended June 30, 2012 to $4.81 per Boe for the three months ended June 30, 2013. Excluding the management distribution, general and administrative expense decreased from $3.60 per Boe for the three months ended June 30, 2012 to $3.19 per Boe for the three months ended June 30, 2013 as the increase in activity resulting from the acquisition of the Chalker properties significantly increased production (37.0% on a Boe basis) but did not cause a proportional increase in general and administrative expenses.

Interest and other. Our interest and other financing expenses increased by $2.3 million (41.1%) to $7.9 million for the three months ended June 30, 2013, as compared to $5.6 million for the three months ended June 30, 2012, primarily due to an increase of $188.3 million in average outstanding debt. The increase in average outstanding debt was used to finance the Chalker acquisition at the end of 2012 and to support continued drilling activity.

Gain (loss) on commodity derivatives. Our net gain on commodity derivatives increased by $5.8 million (18.8%) to a gain of $36.6 million for the three months ended June 30, 2013, as compared to a gain of $30.8 million for the three months ended June 30, 2012. The higher gain was driven by a decrease in future prices for both crude oil and natural gas, but was somewhat offset by a higher average current market price for natural gas during the three months ended June 30, 2013 as compared to the three months ended June 30, 2012 ($4.09 per MMBtu versus $2.22 per MMBtu, respectively). The 12-month forward prices at March 31, 2013 for natural gas averaged $4.17 per MMBtu, while the 12-month forward prices at June 30, 2013 were $3.74. The 12-month forward prices at March 31, 2013 for crude oil averaged $96.21 per Bbl, while the 12-month forward prices at June 30, 2013 averaged $93.33 per Bbl. The gain for the three months ended June 30, 2012 was lower as compared to the three months ended June 30, 2013 due to increasing 12-month forward prices for natural gas, which was offset by decreasing 12-month forward prices for crude oil. The 12-month forward prices at March 31, 2012 for natural gas averaged $2.70 per MMBtu, while the 12-month forward prices at June 30, 2012 were $3.20 per MMbtu. The 12-month forward prices at March 31, 2012 for crude oil averaged $104.43 per Bbl, while the 12-month forward prices at June 30, 2012 averaged $86.78 per Bbl.

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Results of Operations - Six months ended June 30, 2013 as compared to six months ended June 30, 2012

Operating revenues

Oil and gas sales. Our oil and gas sales increased by $46.0 million (62.5%) to $119.6 million for the six months ended June 30, 2013, as compared to $73.6 million for the six months ended June 30, 2012. The increase was primarily due to higher oil and natural gas production volumes combined with higher natural gas prices. Crude oil production increased 100.8%, from 361 MMbls for the six months ended June 30, 2012 to 725 MMbls for the six months ended June 30, 2013, primarily resulting from our acquisition of the Chalker properties, which have an initial oil rate that is higher than our average historical Cleveland well and therefore generate higher revenue per well earlier in their life than average. Natural gas production increased 23.4% from 6,812 MMcf for the six months ended June 30, 2012 to 8,404 MMcf for the six months ended June 30, 2013, primarily due to new wells added through drilling and the Chalker acquisition. The realized average natural gas price, excluding the effects of commodity derivative instruments, increased from $1.82 per Mcf to $3.29 per Mcf, or 80.8%, in the six months ended June 30, 2012 as compared to the six months ended June 30, 2013.

Costs and expenses

Lease operating. Per unit lease operating expense decreased $0.93 per Boe to $3.91 per Boe in the six months ended June 30, 2013 from $4.84 per Boe in the six months ended June 30, 2012, due to the acquisition of the Chalker wells, which increased overall productivity, particularly related to barrels of oil produced. The Chalker properties have an initial oil rate that is higher than our average historical Cleveland well and therefore generate higher revenue per well earlier in their life than average (and correspondingly lower lease operating expenses as a percentage thereof). Our lease operating expense increased by $0.2 million (1.8%) to $11.5 million for the six months ended June 30, 2013, as compared to $11.3 million for the six months ended June 30, 2012. Recurring operating expenses increased $0.9 million (10.5%) to $9.5 million for the six months ended June 30, 2013, as compared to $8.6 million for the six months ended June 30, 2012, primarily due to an increase in the number of operated wells resulting from continued drilling activity and the Chalker acquisition. The increase in lease operating expense was offset by a $0.7 million decrease in workover expense. Workover expense was higher in the six months ended June 30, 2012 as compared to the six months ended June 30, 2013 due to work performed to get wells back on line after being shut in as a result of completion operations on adjacent wells.

Production taxes. Our production taxes increased by $2.8 million (100.0%) to $5.6 million for the six months ended June 30, 2013 as compared to $2.8 million for the six months ended June 30, 2012. Overall, production taxes increased in conjunction with the increase in revenue; however, the average effective rate increased from 3.7% for the six months ended June 30, 2012 to 4.7% for the six months ended June 30, 2013. Production taxes were at a higher rate during the six months ended June 30, 2013 with the acquisition and drilling of the Chalker properties in Texas, which imposes a higher initial tax rate than Oklahoma, where many of our other properties are located.

Depreciation, depletion and amortization. Depreciation, depletion and amortization increased by $15.0 million (40.5%) to $52.0 million for the six months ended June 30, 2013 as compared to $37.0 million for the six months ended June 30, 2012. This was primarily a result of continued drilling activity and the addition of the Chalker properties at the end of 2012, which increased total proved reserves in the Cleveland formation. On a per unit basis, depletion expense increased to $17.63 per Boe for the six months ended June 30, 2013, compared to $15.81 per Boe for the six months ended June 30, 2012.

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General and administrative. Our general and administrative expenses increased by $3.9 million (50.6%) to $11.6 million for the six months ended June 30, 2013, as compared to $7.7 million for the six months ended June 30, 2012. The increase was attributable to an increase in salaries and benefits due to an increase in headcount and a one-time management distribution related to the Monarch incentive plan. On a per unit basis, general and administrative expense increased from $3.28 per Boe for the six months ended June 30, 2012 to $3.94 per Boe for the six months ended June 30, 2013. Excluding the management distribution, general and administrative expense decreased from $3.28 per Boe for the six months ended June 30, 2012 to $3.11 per Boe for the six months ended June 30, 2013 as the increase in activity resulting from the acquisition of the Chalker properties significantly increased production (26.1% on a Boe basis) but did not cause a proportional increase in general and administrative expenses.

Interest and other. Our interest and other financing expenses increased by $3.6 million (29.5%) to $15.8 million for the six months ended June 30, 2013, as compared to $12.2 million for the six months ended June 30, 2012, primarily due to an increase of $189.0 million in average outstanding debt. The increase in average outstanding debt was used to finance the Chalker acquisition during the fourth quarter of 2012 and to support continued drilling activity.

Gain (loss) on commodity derivatives. Our net gain on commodity derivatives decreased by $13.4 million to a gain of $25.2 million for the six months ended June 30, 2013, as compared to a gain of $38.6 million for the six months ended June 30, 2012. The decrease in the gain was attributable to increases in future crude oil and natural gas prices. The 12-month forward prices at June 30, 2013 crude oil averaged $93.33 per Bbl as compared to $93.22 per Bbl at December 31, 2012, while the 12-month forward prices at June 30, 2012 averaged $86.78 per Bbl as compared to $98.77 per Bbl at December 31, 2011. The 12-month forward prices at June 30, 2013 for natural gas averaged $3.74 per MMBtu as compared to $3.54 per MMBtu at December 31, 2012, while the 12-month forward prices at June 30, 2012 averaged $3.20 per MMBtu as compared to $3.25 per MMBtu at December 31, 2011.

Gain on sales of assets. Our gain on sales of assets decreased from $1.4 million for the six months ended June 30, 2012 to $0.02 million for the six months ended June 30, 2013, due to the sale of properties in the North Barnett Shale during the first quarter of 2012 with no significant sales of properties in the first six months of 2013.

Liquidity and Capital Resources

Our primary sources of liquidity have historically been capital contributions from our members, borrowings under bank credit facilities and cash flows from operations. Our primary use of capital has been, and will continue to be during 2013 and for the foreseeable future, for the exploration, development and acquisition of oil and gas properties.

As we pursue reserves and production growth, we continually consider which capital resources, including cash flow, equity and debt financings, are available to meet our future financial obligations, planned capital expenditure activities and liquidity requirements. We continually monitor market conditions and consider taking on additional debt, equity or other sources of financing. We strive to maintain financial flexibility in order to maintain substantial borrowing capacity under our senior secured revolving credit facility, facilitate drilling on our undeveloped acreage positions and permit us to selectively expand our acreage positions.

We believe that our cash on hand, cash flow from operating activities and availability under our credit facilities will be sufficient to fund our planned capital expenditures and operating expenses and comply with our debt covenants during the next 12 months. In the event our cash flows are materially less than anticipated and other sources of capital we historically have utilized are not available on acceptable terms, we may curtail our capital spending.

The following table summarizes our cash flows for the six months ended June 30, 2013 and 2012:

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	Six Months Ended June 30,
(in thousands of dollars)	2013			2012

Net cash provided by operating activities	$	76,810		$	41,012
Net cash used in investing activities	(56,145		)	(41,299		)
Net cash (used in) provided by financing activities	(15,025		)	10,000
Net increase in cash	$	5,640		$	9,713

Cash flow provided by operating activities

Net cash provided by operating activities was $76.8 million during the six months ended June 30, 2013 as compared to cash provided by operating activities of $41.0 million during the six months ended June 30, 2012. The increase in operating cash flows was primarily due to a $46.0 million increase in revenues during the six months ended June 30, 2013 as compared to the six months ended June 30, 2012. The increase in revenue was primarily driven by a 100.8% increase in oil production volumes as a result of the Chalker acquisition in the fourth quarter of 2012, combined with an increase in both natural gas prices and volumes.

Cash flow used in investing activities

Net cash used in investing activities was $56.1 million during the six months ended June 30, 2013 as compared to cash used in investing activities of $41.3 million during the six months ended June 30, 2012. Capital expenditures increased $31.4 million during the six months ended June 30, 2013 as compared to the six months ended June 30, 2012 due to an increase in drilling activity, particularly related to the Chalker properties. Additionally, we received cash proceeds of $9.2 million from the sale of North Barnett properties in the first quarter of 2012 with no meaningful sales of properties occurring during the six months ended June 30, 2013.

Cash flow used in or provided by financing activities

Net cash used in financing activities was $15.0 million during the six months ended June 30, 2013 as compared to cash provided by financing activities of $10.0 million during the six months ended June 30, 2012. The decrease in cash flows provided by financing activities was primarily due to a $5.0 million repayment of debt in the first quarter of 2013 compared to net borrowings of $10.0 million during the six months ended June 30, 2012, in addition to, a $10.0 million non-cash distribution to members related to the Monarch investment.

Contractual Obligations

There have been no material changes in our contractual obligations as reported in the Prospectus.

Off-Balance Sheet Arrangements

We do not have any off-balance sheet arrangements.

Critical Accounting Policies and Estimates

There have been no changes to our critical accounting policies and estimates from those set forth in the Prospectus.

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Item 3. Quantitative and Qualitative Disclosures About Market Risk

The following market risk disclosures should be read in conjunction with the quantitative and qualitative disclosures about market risk contained in the Prospectus, as well as with the unaudited consolidated financial statements and notes included in this Quarterly Report.

We are exposed to certain market risks that are inherent in our financial statements that arise in the normal course of business. We may enter into derivative instruments to manage or reduce market risk, but do not enter into derivative agreements for speculative purposes.

We do not designate these or future derivative instruments as hedges for accounting purposes. Accordingly, the changes in the fair value of these instruments are recognized currently in earnings.

Commodity price risk and hedges

Our principal market risk exposure is to oil, natural gas and NGL prices, which are inherently volatile. As such, future earnings are subject to change due to fluctuations in such prices. Realized prices are primarily driven by the prevailing prices for oil and regional spot prices for natural gas and NGLs. We have used, and expect to continue to use, oil, natural gas and NGL derivative contracts to reduce our risk of price fluctuations of these commodities. Pursuant to our risk management policy, we engage in these activities as a hedging mechanism against price volatility associated with projected production levels. The fair value of our oil, natural gas and NGL derivative contracts at June 30, 2013 was a net asset of $50.1 million.

As of June 30, 2013, we have hedged approximately 48% of our total forecasted production from proved reserves through 2017. The production hedged thereby is consistent with the anticipated monthly production levels in the December 31, 2012 reserve report. Actual production will vary from the amounts estimated in this reserve report, perhaps materially.

Counterparty and customer credit risk

Joint interest receivables arise from billings to entities that own partial interests in the wells we operate. These entities participate in our wells primarily based on their ownership in leases on which we drill. We are also subject to credit risk due to concentration of our oil and natural gas receivables with several significant customers. The inability or failure of these significant customers to meet their obligations or their insolvency or liquidation may adversely affect our financial results. In addition, our oil and natural gas derivative arrangements expose us to credit risk in the event of nonperformance by counterparties.

While we do not typically require our partners, customers and counterparties to post collateral and we do not have a formal process in place to evaluate and assess the credit standing of our partners or customers for oil and gas receivables and the counterparties on our derivative instruments, we do evaluate the credit standing of such parties as we deem appropriate under the circumstances. This evaluation may include reviewing a party’s credit rating, latest financial information and, in the case of a customer with which we have receivables, their historical payment record, and undertaking the due diligence necessary to determine creditworthiness. The counterparties on our derivative instruments currently in place are lenders under the revolving credit facility with investment grade ratings. We are not permitted under the terms of the revolving credit facility to enter into derivative instruments with counterparties outside of the banks who are lenders under the revolving credit facility. As a result, any future derivative instruments will be with these or other lenders under the revolving credit facility who will also likely carry investment grade ratings.

Interest rate risk

We are subject to market risk exposure related to changes in interest rates on our indebtedness. The terms of the senior secured revolving credit facility and the second lien term loan provide for interest on borrowings at a floating rate equal to prime, LIBOR or federal funds rate plus margins ranging from 0.75% to 2.75% on the revolver and 6.0-7.0% on the term loan depending on the base rate used and the amount of the loan outstanding in relation to the

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borrowing base. During the three months ended June 30, 2013, borrowings under the senior secured revolving credit facility and second lien term loan bore interest at a weighted average rate of 3.05% and 9.25%, respectively. During the six months ended June 30, 2013, borrowings under the senior secured revolving credit facility and second lien term loan bore interest at a weighted average rate of 3.16% and 9.28%, respectively.

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Item 4. Controls and Procedures

Changes in Internal Control over Financial Reporting

Prior to the completion of our initial public offering, we were a private company with limited accounting personnel to adequately execute our accounting processes and limited other supervisory resources with which to address our internal control over financial reporting. As previously discussed in our Prospectus, we have not maintained an effective control environment in that the design and execution of our controls has not consistently resulted in effective review of our financial statements and supervision by appropriate individuals. The lack of adequate staffing levels resulted in insufficient time spent on review and approval of certain information used to prepare our financial statements. We concluded that these control deficiencies, although varying in severity, constitute a material weakness in our control environment.

Management has taken steps to address the causes of our audit adjustments and to improve our internal control over financial reporting, including the implementation of new accounting processes and control procedures and the identification of gaps in our skills base and expertise of the staff required to meet the financial reporting requirements of a public company. Since July 2010, we have hired three accounting managers along with a number of degreed staff accountants. This team has enabled us to expedite our month-end close process, thereby facilitating the timely preparation of financial reports. Likewise, we strengthened our internal control environment through the addition of skilled accounting personnel. We continue to hire incremental qualified staff as needed in conjunction with a comprehensive review of our internal controls and formalization of our review and approval processes. We designed new processes and implemented controls to remediate the material weakness identified as of December 31, 2012. However, insufficient time has elapsed to test the operational effectiveness of these new controls, and as such, we are unable to conclude the material weakness has been remediated.

Evaluation of Disclosure Controls and Procedures

As required by Rule 13a-15(b) of the Exchange Act, we have evaluated, under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this report. Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by us in reports that we file under the Exchange Act is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure and is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC. In light of the previously identified material weakness described above and the insufficient time to test the operational effectiveness of our new processes and controls, our principal executive officer and principal financial officer have concluded that our disclosure controls and procedures were not effective at the reasonable assurance level as of June 30, 2013.

Management’s Assessment of Internal Control over Financial Reporting

The SEC, as required by Section 404 of the Sarbanes-Oxley Act, adopted rules requiring every public company that files reports with the SEC to include a management report on such company’s internal control over financial reporting in its annual report. Pursuant to the recently enacted Jumpstart Our Business Startups Act of 2012 (the “JOBS Act”), our independent registered public accounting firm will not be required to attest to the effectiveness of our internal control over financial reporting pursuant to Section 404 of the Sarbanes-Oxley Act of 2002 for up to five years or through such earlier date that we are no longer an “emerging growth company” as defined in the JOBS Act. Our first Annual Report on Form 10-K will not include a report of management’s assessment regarding internal control over financial reporting or an attestation report of our independent registered public accounting firm due to a transition period established by SEC rules applicable to newly public companies. Our management will be required to provide an assessment of the effectiveness of our internal control over financial reporting as of December 31, 2014.

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PART II—OTHER INFORMATION

Item 1. Legal Proceedings

For a discussion of legal proceedings, see Note 8 to the Consolidated Financial Statements appearing in Part I, Item 1 of this Quarterly Report on Form 10-Q, which is incorporated in this item by reference.

Item 1A. Risk Factors

Investing in our Class A common stock involves a high degree of risk. You should carefully consider the risks described below together with the other information set forth in this Quarterly Report on Form 10-Q, including our consolidated financial statements and the related notes, before investing in our Class A common stock. Our business, financial condition or results of operations could be materially adversely affected by any of these risks. The trading price of our Class A common stock could decline due to any of these risks, and you may lose all or part of your investment.

Risks related to our business

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

Our future financial condition and results of operations will depend on the success of our exploration, exploitation, development and production activities. Our oil, natural gas and NGLs exploitation, development and production activities are subject to numerous risks beyond our control, including the risk that drilling will not result in commercially viable oil and natural gas production. Our decisions to purchase, explore, develop or otherwise exploit locations or properties will depend in part on the evaluation of information obtained through geophysical and geological analyses, production data and engineering studies, the results of which are often inconclusive or subject to varying interpretations. In addition, our cost of drilling, completing and operating wells is often uncertain before drilling commences. Further, many factors may curtail, delay or cancel our scheduled drilling projects, including the following:

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

· pressure or irregularities in geological formations;

· shortages of or delays in obtaining equipment and qualified personnel;

· equipment failures or accidents;

· fires and blowouts;

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

· declines in oil, natural gas and NGL prices;

· limited availability of financing at acceptable rates;

· title problems; and

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

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

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

· landing our wellbore in the desired drilling zone;

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

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

· running tools and other equipment consistently through the horizontal wellbore.

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

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

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

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

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

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

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

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

Our exploration, exploitation, development and acquisition activities require substantial capital expenditures. Our budgeted capital expenditures for 2013 are currently expected to be approximately $204.0 million. Historically, we have funded development and operating activities primarily through a combination of equity capital raised from a private equity partner, through borrowings under our bank credit facilities and through internal operating cash flows. We intend to finance our capital expenditures predominantly with cash flows from operations. If necessary, we may also access capital through proceeds from potential asset dispositions, borrowings under our credit facilities and the issuance of debt and equity securities. Our cash flow from operations and access to capital are subject to a number of variables, including:

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

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

· the prices at which we sell our production;

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

· take-away capacity;

· our ability to acquire, locate and produce new reserves;

· the ability and willingness of banks to lend to us; and

· our ability to access the equity and debt capital markets.

If our cash flow from operations is not sufficient to fund our capital expenditure budget, we may have limited ability to obtain the additional capital necessary to conduct our operations at expected levels. Our senior secured revolving credit facility and our second lien term loan facility may restrict our ability to obtain new debt financing. We may not be able to obtain debt or equity financing on terms favorable to us, or at all. The failure to obtain additional financing could result in a curtailment of our operations relating to exploration and development of our prospects, which in turn could lead to a decline in our oil, natural gas and NGLs production or reserves, and in some areas a loss of properties.

External financing may be required in the future to fund our growth. We may not be able to obtain additional financing, and financing under our senior secured revolving credit facility and our second lien term loan facility may not be available in the future. Without additional capital resources, we may be unable to pursue and consummate acquisition opportunities as they become available, and we may be forced to limit or defer our planned oil, natural gas and NGLs development program, which will adversely affect the recoverability and ultimate value of our oil,

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natural gas and NGLs properties, in turn negatively affecting our business, financial condition and results of operations.

The development of our proved undeveloped reserves in our areas of operation may take longer and may require higher levels of capital expenditures than we currently anticipate. Therefore, our undeveloped reserves may not be ultimately developed or produced.

Approximately 54% of our total estimated proved reserves were classified as proved undeveloped as of December 31, 2012. Development of these reserves may take longer and require higher levels of capital expenditures than we currently anticipate. In addition, declines in commodity prices could cause us to reevaluate our development plans and delay or cancel development. Delays in the development of our reserves or increases in costs to drill and develop such reserves will reduce the future net revenues estimated for such reserves and may result in some projects becoming uneconomic. In addition, delays in the development of reserves could cause us to have to reclassify our proved reserves as unproved reserves.

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

The price we receive for our oil, natural gas and NGLs heavily influences our revenue, profitability, access to capital and future rate of growth. Oil and natural gas are commodities and, therefore, their prices are subject to wide fluctuations in response to relatively minor changes in supply and demand. The markets for oil, natural gas and NGLs historically have been volatile and will likely continue to be volatile in the future. The prices we receive for our production and the levels of our production depend on numerous factors beyond our control. These factors include the following:

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

· the actions of the Organization of Petroleum Exporting Countries;

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

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

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

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

· localized supply and demand fundamentals and transportation availability;

· weather conditions and natural disasters;

· domestic, local and foreign governmental regulations and taxes;

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

· futures contracts;

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

· technological advances affecting energy consumption;

· the price and availability of alternative fuels; and

· the impact of energy conservation efforts.

NGLs are made up of ethane, propane, isobutane, butane and natural gasoline, all of which have different uses and different pricing characteristics. NGLs comprised 36% of our 2012 production at an average price of $29.07 per bbl, a 34% drop in average price from the prior year. Further, realized monthly NGL prices have recently approached five-year lows, principally due to significant supply, and it is unclear how long we will continue to experience these low prices. A further or extended decline in NGL prices could materially and adversely affect our future business, financial condition and results of operations.

Substantially all of our production is sold to purchasers under contracts with market-based prices. Lower oil,

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natural gas and NGL prices will reduce our cash flows and the present value of our reserves. If oil, natural gas and NGL prices deteriorate, we anticipate that the borrowing base under our senior secured revolving credit facility, which is revised periodically, may be reduced, which would negatively impact our borrowing ability. Additionally, prices could reduce our cash flows to a level that would require us to borrow to fund our 2013 capital budget. Lower oil, natural gas and NGL prices may also reduce the amount of oil, natural gas and NGLs that we can produce economically. Substantial decreases in oil, natural gas and NGL prices could render uneconomic a significant portion of our identified drilling locations. This may result in significant downward adjustments to our estimated proved reserves. As a result, a substantial or extended decline in oil, natural gas or NGL prices may materially and adversely affect our future business, financial condition, results of operations, liquidity or ability to finance planned capital expenditures.

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

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

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

Our management team has identified and scheduled certain drilling locations as an estimation of our future multi-year drilling activities on our existing acreage. These drilling locations represent a significant part of our growth strategy. Our drilling locations are in various stages of evaluation, ranging from a location that is ready to drill to a location that will require substantial additional interpretation. There is no way to predict in advance of drilling and testing whether any particular location will yield oil, natural gas or NGLs in sufficient quantities to recover drilling or completion costs or to be economically viable. Similarly, the use of technologies and the study of producing fields in the same area of producing wells will not enable us to know conclusively prior to drilling whether oil or natural gas will be present or, if present, whether oil or natural gas will be present in sufficient quantities to be economically viable. Even if sufficient quantities of oil or natural gas exist, we may damage the potentially productive hydrocarbon bearing formation or experience mechanical difficulties while drilling or completing the well, resulting in a reduction in production from or abandonment of the well. If we drill additional wells that we identify as dry holes in our current and future drilling locations, our drilling success rate may decline and materially harm our business. In addition, our ability to drill and develop these drilling locations depends on a number of uncertainties, including oil, natural gas and NGL prices, the availability and cost of capital, drilling and production costs, the availability of drilling services and equipment, drilling results, lease expirations, gathering systems, marketing and pipeline transportation constraints, regulatory approvals and other factors. In addition, a number of our identified drilling locations are associated with joint development agreements and if we do not meet our obligation to drill the minimum number of wells specified in an agreement, we will lose the right to continue to develop certain acreage covered by that agreement. Because of the uncertainty inherent in these factors, we do not know if the numerous drilling locations we have identified will ever be drilled or if we will be able to produce oil, natural gas or NGLs from these or any other drilling locations. In addition, unless production is established within the spacing units covering the undeveloped acres on which some of the potential locations are obtained, the leases for such acreage will expire. As such, our actual drilling activities may materially differ from those presently identified, and if our 2013 drilling results fall below our expectations, we may not generate sufficient cash flow from operations to fund our capital expenditure budget.

If commodity prices decrease, we may be required to take write-downs of the carrying values of our properties.

Accounting rules require that we periodically review the carrying value of our properties for possible impairment. Based on prevailing commodity prices and specific market factors and circumstances at the time of prospective

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impairment reviews, and the continuing evaluation of development plans, production data, economics and other factors, we may be required to write down the carrying value of our properties. A write-down constitutes a non-cash charge to earnings. We may incur impairment charges in the future, which could have a material adverse effect on our results of operations for the periods in which such charges are taken.

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

Numerous uncertainties are inherent in estimating quantities of oil, natural gas and NGL reserves. Our estimates of our proved reserve quantities are based upon our reserve report as of December 31, 2012. Reserve estimation is a subjective process of evaluating underground accumulations of oil, natural gas and NGLs that cannot be measured in an exact manner. Reserves that are “proved reserves” are those estimated quantities of oil, natural gas and NGLs that geological and engineering data demonstrate with reasonable certainty are recoverable in future years from known reservoirs under existing economic and operating conditions and that relate to projects for which the extraction of hydrocarbons must have commenced or the operator must be reasonably certain will commence within a reasonable time.

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

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

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

If we do not meet our obligation to drill the minimum number of wells specified in a joint development agreement, we will lose the right to continue to develop the undeveloped acreage covered by the agreement, which would result in the loss of any proved undeveloped reserves attributable to such undeveloped acreage. For example, pursuant to the terms of our existing joint development agreement with Southridge Energy, LLC, or Southridge, we are obligated to drill 20 additional wells prior to October 31, 2013 in order to continue to earn an interest in future wells and acreage. We have not completed any wells under this agreement in 2013 and currently do not have any rigs running on this acreage. If we are unable to obtain an extension beyond October 31, 2013 or negotiate an alternative arrangement with Southridge, we would not expect to meet our obligation to drill the minimum number of wells within the deadline currently specified in the Southridge Agreement. We have been in discussions with Southridge for this purpose and proposed an extension and modified arrangement by which we would develop the subject properties within 12 to 18 months. We may be unable to reach a mutually acceptable extension or amendment before October 31, 2013, or at all. If we do not obtain an extension or amendment and the 20 well commitment is not timely satisfied, we would, as of October 31, 2013, lose the right to continue to develop approximately 11,517 gross (3,310 net) acres in the Woodford shale formation, including approximately 15.5 MMBoe of proved undeveloped reserves attributable to such acreage (representing approximately 18% of our proved reserves and approximately 7% of our standardized measure as of December 31, 2012) that were included in our estimated proved reserves as of December 31, 2012. We estimate that we would incur an impairment charge of approximately $15 million in connection with such a reduction in our proved reserves.

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

You should not assume that the standardized measure of discounted future net cash flows from our proved reserves is the current market value of our estimated oil, natural gas and NGL reserves. In accordance with SEC requirements in effect at December 31, 2010, 2011 and 2012, we based the discounted future net cash flows from our proved reserves on the 12-month unweighted arithmetic average of the first-day-of-the-month commodities prices for the preceding 12 months without giving effect to derivative transactions. Actual future net cash flows from our oil and natural gas properties will be affected by factors such as:

· actual prices we receive for oil, natural gas and NGLs;

· actual cost of development and production expenditures;

· the amount and timing of actual production; and

· changes in governmental regulations or taxation.

The timing of both our production and our incurrence of expenses in connection with the development and production of oil and natural gas properties will affect the timing and amount of actual future net revenues from proved reserves, and thus their actual present value. In addition, the 10% discount factor we use when calculating standardized measure may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with our company or the oil and natural gas industry in general. Prior to the consummation of our initial public offering, as a limited liability company, we were not historically subject to entity-level taxation. Accordingly, our standardized measure for historical periods does not provide for federal or state corporate income taxes, except for the Texas margin tax, because taxable income has been passed through to our equity holders. However, upon consummation of our initial public offering, we became a corporation subject to entity-level taxation. As a result, we are treated as a taxable entity for federal income tax purposes, and our future income taxes will be dependent upon our future taxable income.

If oil prices decline by $10.00 per Bbl, then our standardized measure as of December 31, 2012 would decrease approximately $119 million. If natural gas prices decline by $1.00 per Mcf, then our standardized measure as of December 31, 2012 would decrease by approximately $100 million.

Over 97% of our producing properties are located in the Anadarko and Arkoma basins in the Texas Panhandle and Oklahoma, making us vulnerable to risks associated with operating in one geographic area.

Over 97% of our estimated proved reserves as of December 31, 2012 were located in the Anadarko and Arkoma basins in the Texas Panhandle and Oklahoma, approximately 48% of which are being produced from the Cleveland formation from properties located in four contiguous counties of Texas and Oklahoma. As a result of this concentration, we may be disproportionately exposed to the impact of regional supply and demand factors, delays or interruptions of production from wells in this area caused by governmental regulation, processing or transportation capacity constraints, availability of equipment, facilities, personnel or services market limitations or interruption of the processing or transportation of oil, natural gas or NGLs. In addition, the effect of fluctuations on supply and demand may become more pronounced within specific geographic oil and natural gas producing areas such as our properties producing from the Cleveland formation, which may cause these conditions to occur with greater frequency or magnify the effects of these conditions. Due to the concentrated nature of our portfolio of properties, a number of our properties could experience any of the same conditions at the same time, resulting in a relatively greater impact on our results of operations than they might have on other companies that have a more diversified portfolio of properties. Such delays or interruptions could have a material adverse effect on our financial condition and results of operations.

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

Historically, we have been dependent on a few customers for a significant portion of our revenue. For the year ended December 31, 2012 purchases by four of our customers accounted for approximately 24%, 18%, 18% and 15%, respectively, of our total oil, natural gas and NGL sales. This concentration of customers may increase our overall exposure to credit risk, and customers will likely be similarly affected by changes in economic and industry conditions. To the extent that any of our major purchasers reduces their purchases of oil, natural gas or NGLs or defaults on their obligations to us, our financial condition and results of operations could be adversely affected.

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

In the future we may make acquisitions of businesses that complement or expand our current business. We may not be able to identify attractive acquisition opportunities. Even if we do identify attractive acquisition opportunities, we may not be able to complete the acquisition or do so on commercially acceptable terms.

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

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

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

· an inability to successfully integrate the assets we acquire;

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

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

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

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

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

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

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

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

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

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

It is our practice, in acquiring oil and natural gas leases or undivided interests in oil and natural gas leases or other developed rights, not to incur the expense of retaining lawyers to examine the title to the mineral interest to be acquired. Rather, we rely upon the judgment of oil and natural gas lease brokers or landmen who perform the fieldwork in examining records in the appropriate governmental or county clerk’s office to determine mineral ownership before we acquire an oil and gas lease or other developed rights in a specific mineral interest.

Prior to the drilling of an oil or gas well, it is the normal practice in our industry for the operator of the well to obtain a drilling title opinion from a qualified title attorney to ensure there are no obvious title defects on the property on which the well is to be located. The title attorney would typically research documents that are of record, including liens, taxes and all applicable contracts that burden the property. Frequently, as a result of such

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examinations, certain curative work must be undertaken to correct defects in the marketability of the title, and such curative work entails expense. Our failure to completely cure any title defects may invalidate our title to the subject property and adversely impact our ability in the future to increase production and reserves. Additionally, because a less strenuous title review is conducted on lands where a well has not yet been scheduled, undeveloped acreage has greater risk of title defects than developed acreage. Any title defects or defects in assignment of leasehold rights in properties in which we hold an interest may adversely impact our ability in the future to increase production and reserves, which could have a material adverse effect on our business, financial condition and results of operations.

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

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

To achieve more predictable cash flow and to reduce our exposure to adverse fluctuations in the prices of oil, natural gas and NGLs, we have entered into commodity derivative contracts for a significant portion of our oil, natural gas and NGLs production that could result in both realized and unrealized hedging losses. The extent of our commodity price exposure is related largely to the effectiveness and scope of our commodity derivative contracts. For example, some of the commodity derivative contracts we utilize are based on quoted market prices, which may differ significantly from the actual prices we realize in our operations for oil, natural gas and NGLs. In addition, our senior secured revolving credit facility and our second lien term loan facility limit the aggregate notional volume of commodities that can be covered under commodity derivative contracts we can enter into and, as a result, we will continue to have direct commodity price exposure on the unhedged portion of our production volumes. For the years ending December 31, 2013, 2014, 2015, 2016 and 2017, approximately 17%, 39%, 60%, 76% and 75%, respectively, of our estimated total oil, natural gas and NGL production, based on our reserve report as of December 31, 2012, will not be covered by commodity derivative contracts.

Our policy has been to hedge a significant portion of our estimated oil, natural gas and NGLs production. However, our price hedging strategy and future hedging transactions will be determined at our discretion. We are not under an obligation to hedge a specific portion of our production. The prices at which we hedge our production in the future will be dependent upon commodity prices at the time we enter into these transactions, which may be substantially higher or lower than current oil, natural gas and NGLs prices. Accordingly, our price hedging strategy may not protect us from significant declines in oil, natural gas and NGL prices received for our future production. Conversely, our hedging strategy may limit our ability to realize cash flows from commodity price increases. It is also possible that a larger percentage of our future production will not be hedged as compared with past years, which would result in our oil and natural gas revenues becoming more sensitive to commodity price changes.

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

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

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Our hedging transactions expose us to counterparty credit risk.

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

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

The adoption of the Dodd-Frank Wall Street Reform and Consumer Protection Act, or the Dodd-Frank Act, could have an adverse effect on our ability to use derivatives to reduce the effect of commodity price risk, interest rate and other risks associated with our business.

We use commodity derivatives to manage our commodity price risk. The U.S. Congress adopted comprehensive financial reform legislation that, among other things, establishes comprehensive federal oversight and regulation of over-the-counter derivatives and many of the entities that participate in that market. Although the Dodd-Frank Act was enacted on July 21, 2010, the Commodity Futures Trading Commission, or the CFTC, and the SEC, along with certain other regulators, must promulgate final rules and regulations to implement many of its provisions relating to over-the-counter derivatives. While some of these rules have been finalized, some have not and, as a result, the final form and timing of the implementation of the new regulatory regime affecting commodity derivatives remains uncertain.

In particular, on October 18, 2011, the CFTC adopted final rules under the Dodd-Frank Act establishing position limits for certain energy commodity futures and options contracts and economically equivalent swaps, futures and options. The position limit levels set the maximum amount of covered contracts that a trader may own or control separately or in combination, net long or short. The final rules also contained limited exemptions from position limits which would be phased in over time for certain bona fide hedging transactions and positions. The position limits rules were vacated by a Federal court on September 28, 2012, and the CFTC has appealed that decision.

If these or similar position limits go into effect in the future, the timing of implementation of the final rules, their applicability to, and impact on, us and the ultimate success of any legal challenge to their validity remain uncertain, and they could have a material adverse impact on us by affecting the prices of or market for commodities relevant to our operations and/or by reducing the availability to us of commodity derivatives.

The Dodd-Frank Act also imposes a number of other new requirements on certain over-the-counter derivatives and subjects certain swap dealers and major swap participants to significant new regulatory requirements, which in certain cases may cause them to conduct their activities through new entities that may not be as creditworthy as our current counterparties, all of which may have a material adverse effect on us. The impact of this regulatory regime on the availability, pricing and terms and conditions of commodity derivatives remains uncertain, but the final requirements could have a materially adverse effect on our ability to hedge our exposure to commodity prices.

If we reduce our use of derivatives as a result of the Dodd-Frank Act, the regulations promulgated under it and the changes to the nature of the derivatives markets, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures. In addition, the Dodd-Frank Act was intended, in part, to reduce the volatility of commodity prices, which some legislators attributed to speculative trading in derivatives and commodity contracts related to oil, natural gas and NGLs. Our revenue could, therefore, be adversely affected if commodity prices were to decrease.

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

The Obama administration’s budget proposals for fiscal year 2014 contain numerous proposed tax changes, and from time to time, legislation has been introduced that would enact many of these proposed changes. The proposed budget and legislation would repeal many tax incentives and deductions that are currently used by U.S. oil and gas companies and impose new fees. Among others, the provisions include: elimination of the ability to fully deduct intangible drilling costs in the year incurred; repeal of the percentage depletion deduction for oil and gas properties; repeal of the domestic manufacturing tax deduction for oil and gas companies; increase in the geological and

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geophysical amortization period for independent producers; and implementation of a fee on non-producing federal oil and gas leases. The passage of legislation containing some or all of these provisions or any other similar change in U.S. federal income tax law could eliminate or postpone certain tax deductions that are currently available to us with respect to oil and natural gas exploration and development, and any such change could have a material adverse effect on our business, financial condition and results of operations.

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

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

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

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

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

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

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

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

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

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

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

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

· adverse weather conditions and natural disasters;

· abnormally pressured formations;

· facility or equipment malfunctions;

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

· fires, explosions and ruptures of pipelines;

· personal injuries and death; and

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

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

· injury or loss of life;

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

· pollution and other environmental damage and associated clean-up responsibilities;

· regulatory investigations, penalties or other sanctions;

· suspension of our operations; and

· repair and remediation costs.

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

Our oil and natural gas exploration and production operations are subject to complex and stringent laws and

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

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

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

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

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

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

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

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

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

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

· the National Environmental Policy Act, or NEPA, which requires federal agencies to evaluate major agency actions having the potential to significantly impact the environment and which may require the preparation of Environmental Assessments and more detailed Environmental Impact Statements that may be made available for public review and comment;

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

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

We may incur significant delays, costs and liabilities as a result of federal, state and local environmental, health and safety requirements applicable to exploration, development and production activities. These laws and

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

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

Hydraulic fracturing is an important and common practice that is used to stimulate production of natural gas and/or oil from dense subsurface rock formations. The process involves the injection of water, sand and chemicals under pressure into the formation to fracture the surrounding rock and stimulate production. We routinely utilize hydraulic fracturing techniques in many of our oil and natural gas drilling and completion programs. The process is typically regulated by state oil and natural gas commissions. However, the EPA recently asserted federal regulatory authority over certain hydraulic fracturing activities involving diesel under the federal Safe Drinking Water Act, or SDWA, and released draft guidance in May 2012 on regulatory requirements for companies that plan to conduct hydraulic fracturing using diesel. In addition, on November 23, 2011, the EPA announced that it was granting in part a petition to initial rulemaking under the Toxic Substances Control Act, relating to chemical substances and mixtures used in oil and gas exploration and production. Congress has also considered legislation to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the fracturing process.

Some states have adopted, and other states are considering adopting, regulations that could impose more stringent permitting, disclosure and well construction requirements on hydraulic fracturing operations under certain circumstances. For example, Texas adopted a law in June 2011 requiring disclosure to the Railroad Commission of Texas, or TRRC, and the public of certain information regarding the components used in the hydraulic fracturing process. On December 13, 2011, the TRRC finalized regulations requiring public disclosure of chemicals in fluids used in the hydraulic fracturing process for drilling permits issued after February 1, 2012. In addition, on October 20, 2011, Louisiana adopted new regulations for hydraulic fracturing operations in the state. These new regulations require hydraulic fracturing operators to publicly disclose the volume of hydraulic fracturing fluid, the type, trade name, supplier and volume of additives, and a list of chemical compounds contained in the additive, along with its maximum concentration, subject to certain trade secret protections. However, even trade secret chemicals will have to be identified by their chemical family. A mandatory disclosure of information regarding the constituents of hydraulic fracturing fluids could make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings based upon allegations that specific chemicals used in the fracturing process could adversely affect the environment. In addition, the Oklahoma Corporation Commission has adopted rules prohibiting water pollution resulting from hydraulic fracturing operations and requiring disclosure of chemicals used in hydraulic fracturing.

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

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

There are also certain governmental reviews either underway or being proposed that focus on environmental aspects of hydraulic fracturing practices. The White House Council on Environmental Quality is coordinating an administration-wide review of hydraulic fracturing practices, and a committee of the United States House of Representatives has conducted an investigation of hydraulic fracturing practices. Furthermore, a number of federal agencies are analyzing, or have been requested to review, a variety of environmental issues associated with hydraulic fracturing. The EPA is conducting a study of the potential environmental effects of hydraulic fracturing on drinking water and groundwater. The EPA released its first progress report on this study in December 2012 and expects to release a final draft report for public comment and peer review in 2014. Moreover, the EPA announced on October 20, 2011 that it is launching a study of wastewater resulting from hydraulic fracturing activities and currently plans to propose pretreatment standards by 2014. In addition, the U.S. Department of Energy’s Natural Gas Subcommittee of the Secretary of Energy Advisory Board conducted a review of hydraulic fracturing issues and practices and made recommendations to better protect the environment from drilling using hydraulic fracturing completion methods. These ongoing or proposed studies, depending on their degree of pursuit and any meaningful results obtained, could spur initiatives to further regulate hydraulic fracturing under the Safe Drinking Water Act, the Toxic Substances Control Act, or other statutory and/or regulatory mechanisms. President Obama created the Interagency Working Group on Unconventional Natural Gas and Oil by Executive Order on April 13, 2012, which is charged with coordinating and aligning federal agency research and scientific studies on unconventional oil and natural gas resources.

Also, the U.S. Department of the Interior’s Bureau of Land Management, or BLM, is considering proposing rules regarding well stimulation, chemical disclosures and other requirements for hydraulic fracturing on federal and Indian lands. BLM released a proposed rule requiring the disclosure of chemicals used during hydraulic fracturing and addressing drilling plans, water management and wastewater disposal, on federal and Indian lands in May 2012. However, BLM pulled back its proposal in January 2013 after reviewing comments and published an updated proposed rule on May 24, 2013 with comments due August 23, 2013.

Further, on April 17, 2012, the EPA released final rules that will subject all oil and gas operations (production, processing, transmission, storage and distribution) to regulation under the New Source Performance Standards, or NSPS, and National Emission Standards for Hazardous Air Pollutants, or NESHAPS, programs. These rules became effective on October 15, 2012. The EPA rules also include NSPS standards for completions of hydraulically-fractured gas wells. These standards include the reduced emission completion techniques developed in the EPA’s Natural Gas STAR program along with pit flaring of gas not sent to the gathering line. The standards will be applicable to newly drilled and fractured wells as well as existing wells that are refractured. Further, the regulations under NESHAPS include maximum achievable control technology, or MACT, standards for those glycol dehydrators and storage vessels at major sources of hazardous air pollutants not currently subject to MACT standards. In October 2012, several challenges to the EPA’s rules were filed by various parties, including environmental groups and industry associations. In a January 16, 2013 unopposed motion to hold this litigation in abeyance, the EPA indicated that it may reconsider some aspects of the rules. Depending on the outcome of such proceedings, the rules may be modified or rescinded or the EPA may issue new rules. We are currently evaluating the effect these rules will have on our business. Additionally, on December 11, 2012, seven states submitted a notice of intent to sue the EPA to compel the agency to make a determination as to whether standards of performance limiting methane emissions from oil and gas sources are appropriate, and, if so, to promulgate performance standards for methane emissions from the oil and gas sector, which was not addressed in the EPA rules that became effective on October 15, 2012. The notice of intent also requested the EPA issue emission guidelines for the control of methane emissions from existing oil and gas sources. Increased regulation and attention given to the hydraulic-fracturing process could lead to greater opposition, including litigation, to oil and gas production activities using hydraulic-fracturing techniques. Additional legislation or regulation could also lead to operational delays or increased operating costs in the production of oil and natural gas, including from the developing shale formations, or could make it more difficult to perform hydraulic fracturing. The adoption of any federal, state or local laws or the implementation of regulations regarding hydraulic fracturing could potentially cause a decrease in the completion of

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new oil and gas wells, increased compliance costs and time, which could adversely affect our financial position, results of operations and cash flows.

Climate change legislation or regulations restricting emissions of greenhouse gases could result in increased operating costs and reduced demand for the oil, natural gas and NGLs we produce.

In December 2009, the EPA officially published its findings that emissions of carbon dioxide, methane and other greenhouse gases, or GHGs, present an endangerment to public health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the earth’s atmosphere and other climatic changes. Based on its findings, the EPA has begun adopting and implementing regulations to restrict emissions of GHGs under existing provisions of the federal Clean Air Act, including one rule that requires a reduction in emissions of GHGs from motor vehicles and another that regulates emissions of GHGs from certain large stationary sources. Since January 2, 2011, the EPA has required new or modified stationary sources that emit GHGs at levels above regulatory and statutory thresholds to apply for a Prevention of Significant Deterioration, or PSD, permit under the Clean Air Act. The EPA set the current regulatory thresholds in its “Tailoring Rule,” which was intended to avoid the need for large numbers of relatively small GHG-emitting sources to obtain a permit under the Clean Air Act. The EPA has also indicated that it may revise its Tailoring Rule carbon dioxide equivalent thresholds downward in a future rulemaking, which would likely subject additional stationary sources to GHG permitting requirements.

The EPA has also proposed GHG New Source Performance Standards under the Clean Air Act for certain electric utility generating units and may propose GHG NSPS for additional source categories in the future. In addition, on October 30, 2009, the EPA published a final rule requiring the reporting of GHG emissions from specified large GHG emission sources in the United States beginning in 2011 for emissions occurring in 2010. On November 9, 2010, the EPA issued final rules to expand its existing GHG reporting rule to include onshore oil and natural gas production, processing, transmission, storage and distribution facilities with reporting of GHG emissions from such facilities required on an annual basis. The first reports were due in 2012 for emissions occurring in 2011.

In addition, the U.S. Congress has from time to time considered adopting legislation to reduce emissions of GHGs and almost one-half of the states have already taken legal measures to reduce emissions of GHGs primarily through the planned development of GHG emission inventories and/or regional GHG cap and trade programs. The adoption of legislation or regulatory programs to reduce emissions of GHGs could require us to incur increased operating costs, such as costs to purchase and operate emissions control systems, to acquire emissions allowances or comply with new regulatory or reporting requirements. Any such legislation or regulatory programs could also increase the cost of consuming, and thereby reduce demand for, the oil, natural gas and NGLs we produce. Consequently, legislation and regulatory programs to reduce emissions of GHGs could have an adverse effect on our business, financial condition and results of operations.

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

We may face unanticipated water and other waste disposal costs.

We may be subject to regulation that restricts our ability to discharge water produced as part of our gas production operations. Productive zones frequently contain water that must be removed in order for the gas to produce, and our ability to remove and dispose of sufficient quantities of water from the various zones will determine whether we can produce gas in commercial quantities. The produced water currently is transported from the lease and injected into disposal wells. The availability of disposal wells with sufficient capacity to receive all of the water produced from our wells may affect our ability to produce our wells. Also, the EPA expects to issue new standards regarding the disposal of wastewater from hydraulic fracturing into publicly owned treatment facilities this year. Therefore, the cost to transport and dispose of that water, including the cost of complying with regulations concerning water disposal, may reduce our profitability.

Where water produced from our projects fails to meet the quality requirements of applicable regulatory agencies, our wells produce water in excess of the applicable volumetric permit limits, the disposal wells fail to meet the requirements of all applicable regulatory agencies, or we are unable to secure access to disposal wells with sufficient

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capacity to accept all of the produced water, we may have to shut in wells, reduce drilling activities, or upgrade facilities for water handling or treatment. The costs to dispose of this produced water may increase if any of the following occur:

· we cannot obtain future permits from applicable regulatory agencies;

· water of lesser quality or requiring additional treatment is produced;

· our wells produce excess water;

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

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

Our senior secured revolving credit facility and our second lien term loan facility contain covenants that restrict our ability to make investments, incur additional indebtedness and engage in certain other transactions, which could adversely affect our ability to meet our future goals.

Our senior secured revolving credit facility and our second lien term loan facility include certain covenants that, among other things, restrict:

· our investments, loans and advances and the payment of dividends and other restricted payments;

· our incurrence of additional indebtedness;

· the granting of liens, other than liens created pursuant to the senior secured revolving credit facility and the second lien term loan facility and certain other permitted liens;

· mergers, consolidations and sales of all or substantially all of our properties;

· the hedging, forward sale or swap of our production of oil, natural gas, NGLs or other commodities; and

· the sale of assets (other than production sold in the ordinary course of business).

Our senior secured revolving credit facility and our second lien term loan facility require us to maintain specified financial ratios, such as leverage ratios. These restrictive covenants may restrict our ability to expand or pursue our business strategies. Our ability to comply with these and other provisions of our senior secured revolving credit facility and our second lien term loan facility may be impacted by changes in economic or business conditions, results of operations or events beyond our control. The breach of any of these covenants could result in a default under our senior secured revolving credit facility or our second lien term loan facility, in which case, the lenders holding a specified majority or supermajority under that credit facility could elect to declare all amounts borrowed under that credit facility, together with accrued interest, to be immediately due and payable. If we were unable to repay such borrowings or interest, our lenders could proceed against their collateral, which consists of, among other things, substantially all of our oil and gas properties. If the indebtedness under our senior secured revolving credit facility or our second lien term loan facility were to be accelerated, our assets may not be sufficient to repay in full such indebtedness.

In addition, our borrowing base under the senior secured revolving credit facility, which is derived by our lenders from our estimated proved reserves, is subject to periodic redeterminations by the lenders on a semi-annual basis on February 1 and August 1 of each year. We and the administrative agent (acting at the direction of lenders holding at least 66 2⁄3% of the outstanding loans and letter of credit obligations) may each request one unscheduled borrowing base redetermination between each scheduled redetermination. In addition, the lenders may elect to redetermine the borrowing base upon the occurrence of certain defaults under our material operating agreements or upon the cancellation or termination of certain of our farm-out agreements. Reductions in our proved reserves, including our proved undeveloped reserves, may result in a reduction by our lenders in our borrowing base and in the amounts we are able to borrow under the facility. The borrowing base will also be reduced in certain circumstances as a result of our issuance of unsecured notes, our termination of certain hedging positions and our consummation of certain asset sales. In the future we could be forced to repay a portion of our then outstanding borrowings under the senior secured revolving credit facility in the event that, due to future redeterminations or reductions of our borrowing base, the outstanding borrowings exceed the redetermined or reduced borrowing base. If we are forced to make any such repayment, we may not have sufficient funds to make such repayment. If we do not have sufficient funds and are otherwise unable to negotiate renewals of our borrowings or arrange new financing, we may have to sell significant assets. Any such sale could have a material adverse effect on our business, financial condition and results

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of operations.

Our level of indebtedness may increase, which could reduce our financial flexibility.

As of July 29, 2013, we had $222 million available for borrowing based on the current borrowing base of $500 million, under our senior secured revolving credit facility. In the future, we may incur significant indebtedness in order to make future acquisitions or to develop our properties.

Our level of indebtedness could affect our operations in several ways, including the following:

· a significant portion of our cash flows could be used to service our indebtedness;

· a high level of debt would increase our vulnerability to general adverse economic and industry conditions;

· the covenants contained in the agreements governing our outstanding indebtedness will limit our ability to borrow additional funds, dispose of assets, pay dividends and make certain investments;

· a high level of debt may place us at a competitive disadvantage compared to our competitors that are less leveraged and, therefore, such competitors may be able to take advantage of opportunities that our indebtedness would prevent us from pursuing;

· our debt covenants may also affect our flexibility in planning for, and reacting to, changes in the economy and in our industry;

· a high level of debt may make it more likely that a reduction in our borrowing base following a periodic redetermination could require us to repay a portion of our then outstanding bank borrowings; and

· a high level of debt may impair our ability to obtain additional financing in the future for working capital, capital expenditures, acquisitions, general corporate or other purposes.

A high level of indebtedness increases the risk that we may default on our debt obligations. Our ability to meet our debt obligations and to reduce our level of indebtedness depends on our future performance. General economic conditions, oil, natural gas and NGL prices and financial, business and other factors affect our operations and our future performance. Many of these factors are beyond our control. We may not be able to generate sufficient cash flows to pay the interest on our debt and future working capital, borrowings or equity financing may not be available to pay or refinance such debt. Factors that may affect our ability to raise cash through an offering of our capital stock or a refinancing of our debt include financial market conditions, the value of our assets and our performance at the time we need capital.

Increases in interest rates could adversely affect our business.

Our business and operating results can be harmed by factors such as the availability, terms of and cost of capital, increases in interest rates or a reduction in credit rating. These changes could cause our cost of doing business to increase, limit our ability to pursue acquisition opportunities, reduce our cash flow available for drilling and place us at a competitive disadvantage. For example, as of June 30, 2013, we had approximately $55 million of total available borrowing capacity under our revolving credit facility and our second lien term loan facility, subject to compliance with financial covenants. The impact of a 1.0% increase in interest rates on an assumed borrowing of the full $660 million available under our credit facilities would result in increased annual interest expense of approximately $5.0 million and a corresponding decrease in our net income. Recent and continuing disruptions and volatility in the global financial markets may lead to a contraction in credit availability impacting our ability to finance our operations. A significant reduction in our cash flows from operations or the availability of credit could materially and adversely affect our ability to achieve our planned growth and operating results.

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

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

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satisfy their obligations under these arrangements, our business may be adversely affected.

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

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

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

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

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

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

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

The Jones family and Metalmark Capital, our primary private equity investor, control a significant percentage of our voting power and have the ability to take actions that may conflict with your interests.

As of July 29, 2013, Metalmark Capital beneficially owned approximately 63.0% of our Class B common stock and Jones family entities collectively beneficially owned approximately 33.5% of our Class B common stock. Holders of Class A common stock and Class B common stock will vote together as a single class on all matters presented to our stockholders for their vote or approval, except as otherwise required by applicable law or our amended and restated certificate of incorporation. Consequently, the Jones family and Metalmark Capital have significant influence over all matters that require approval by our stockholders, including the election and removal of directors, changes to our organizational documents and approval of significant corporate transactions. This concentration of ownership will limit your ability to influence corporate matters, and as a result, actions may be taken that you may not view as beneficial.

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

Our success will depend to a large extent upon the efforts and abilities of our executive officers and key operations personnel. The loss of the services of one or more of these key employees could have a material adverse effect on us. We do not maintain insurance against the loss of any of these individuals. Our business will also be dependent upon our ability to attract and retain qualified personnel. Acquiring and keeping these personnel could prove more difficult or cost substantially more than estimated. This could cause us to incur greater costs, or prevent us from pursuing our development and exploitation strategy as quickly as we would otherwise wish to do.

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

We have had limited accounting personnel to execute our accounting processes and limited other supervisory resources with which to address our internal control over financial reporting. As such, we have not maintained an effective control environment to ensure that the design and execution of our controls has consistently resulted in effective review of our financial statements and supervision by appropriate individuals. As a result of these factors, certain material misstatements in our annual financial statements were discovered and brought to the attention of our management by our independent registered public accounting firm for correction. These material misstatements included certain errors in our annual financial statements for the years ended 2010, 2011 and 2012, including out-of-period adjustments and errors in the calculation of our depreciation, depletion and amortization expense and our asset retirement obligations. We and our independent registered public accounting firm concluded that these control deficiencies constituted a material weakness in our control environment. A material weakness is a control deficiency, or a combination of control deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of our annual or interim financial statements will not be prevented or detected on a timely basis. The control deficiencies described above, at varying degrees of severity, contributed to the material weakness in the control environment as further described below.

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In 2010 and 2011, we did not maintain effective controls to ensure that correct inputs and formulas in spreadsheets were used in our calculation of depreciation, depletion and amortization, or DD&A, expense. In 2012, the lack of effective controls over last-minute journal entries and use of final adjusted production data resulted in the misstatement of DD&A. For each of these periods, effective controls were not adequately designed or consistently operating to ensure that key computations were properly reviewed before the amounts were recorded in our accounting records. The above identified control deficiencies resulted in audit adjustments to our consolidated financial statements during 2010, 2011, and 2012.

In December 2012, we were notified by the Oklahoma Tax Commission that sales tax had not been remitted on tangible property conveyed as part of the sale of a number of oil and gas properties. Due to the lack of state tax expertise on our staff, we were unaware of the requirement to remit such a tax and had failed to file, albeit unintentionally. Consequently, tax expense for periods prior to 2012 was understated. Management is reviewing the internal control weakness related to this omission to determine the proper organizational structure in response.

Effective internal controls are necessary for us to provide reliable financial reports, prevent fraud and to operate successfully as a publicly traded company. To comply with the requirements of being a publicly traded company, we may need to implement additional financial and management controls, reporting systems and procedures and hire additional accounting, finance and legal staff. Our efforts to develop and maintain our internal controls may not be successful, and we may be unable to maintain effective controls over our financial processes and reporting in the future or to comply with our obligations under Section 404 of the Sarbanes-Oxley Act of 2002, which we refer to as Section 404. For example, Section 404 will require us, among other things, to annually review and report on, and our independent registered public accounting firm to attest to, the effectiveness of our internal controls over financial reporting. We must comply with Section 404 (except for the requirement for an auditor’s attestation report) beginning with our fiscal year ending December 31, 2014. Any failure to develop, implement or maintain effective internal controls or to improve our internal controls could harm our operating results or cause us to fail to meet our reporting obligations. Given the difficulties inherent in the design and operation of internal controls over financial reporting, we can provide no assurance as to our conclusions about the effectiveness of our internal controls, and we may incur significant costs in our efforts to comply with Section 404. If one or more material weaknesses persist or if we fail to establish and maintain effective internal control over financial reporting, our ability to accurately report our financial results could be adversely affected. Ineffective internal controls could also subject us to regulatory scrutiny and a loss of confidence in our reported financial information, which could have an adverse effect on our business and would likely have a negative effect on the trading price of our Class A common stock.

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

In April 2012, President Obama signed into law the Jumpstart Our Business Startups Act, or the JOBS Act. For as long as we remain an “emerging growth company” as defined in the JOBS Act, we may take advantage of certain exemptions from various reporting requirements that are applicable to other public companies that are not emerging growth companies, including not being required to provide an auditor’s attestation report on management’s assessment of the effectiveness of our system of internal control over financial reporting pursuant to Section 404 of the Sarbanes-Oxley Act and reduced disclosure obligations regarding executive compensation in our periodic reports. We will remain an emerging growth company for up to five years, although we will lose that status sooner if we have more than $1.0 billion of revenues in a fiscal year, have more than $700 million in market value of our Class A common stock held by non-affiliates, or issue more than $1.0 billion of non-convertible debt over a three-year period.

In addition, the JOBS Act provides that an emerging growth company can delay adopting new or revised accounting standards until such time as those standards apply to private companies. We have irrevocably elected to “opt out” of this exemption and, therefore, will be subject to the same new or revised accounting standards as other public companies that are not emerging growth companies.

To the extent that we rely on any of the exemptions available to emerging growth companies, you will receive less information about our executive compensation and internal control over financial reporting than issuers that are not emerging growth companies. If some investors find our Class A common stock to be less attractive as a result, there may be a less active trading market for our Class A common stock and our trading price may be more volatile.

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

We are heavily dependent on our information systems and computer based programs, including our well

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

Risks Inherent in an Investment in Us

Because we are are a relatively small company, the requirements of being a public company, including compliance with the reporting requirements of the Exchange Act and the requirements of the Sarbanes-Oxley Act of 2002, may strain our resources, increase our costs and distract management, and we may be unable to comply with these requirements in a timely or cost-effective manner.

As a public company with listed equity securities, we will need to comply with new laws, regulations and requirements, certain corporate governance provisions of the Sarbanes-Oxley Act of 2002, related regulations of the SEC, including compliance with the reporting requirements of the Securities Exchange Act of 1934, as amended, or the Exchange Act, and the requirements of the NYSE with which we are not required to comply as a private company. Complying with these statutes, regulations and requirements will occupy a significant amount of time of our board of directors and management and will significantly increase our costs and expenses. We will need to:

· institute a more comprehensive compliance function;

· design, establish, evaluate and maintain a system of internal controls over financial reporting in compliance with the requirements of Section 404 of the Sarbanes-Oxley Act of 2002 and the related rules and regulations of the SEC and the Public Company Accounting Oversight Board;

· comply with listing standards promulgated by the NYSE;

· prepare and distribute periodic public reports in compliance with our obligations under the federal securities laws;

· establish new internal policies, such as those relating to disclosure controls and procedures and insider trading;

· involve and retain to a greater degree outside counsel and accountants in the above activities; and

· establish an investor relations function.

In addition, we expect that being a public company subject to these rules and regulations may make it more difficult and more expensive for us to obtain director and officer liability insurance and we may be required to accept reduced policy limits and coverage or incur substantially higher costs to obtain the same or similar coverage. As a result, it may be more difficult for us to attract and retain qualified individuals to serve on our board of directors or as executive officers. We are currently evaluating these rules, and we cannot predict or estimate the amount of additional costs we may incur or the timing of such costs.

We do not intend to pay, and our credit facilities currently prohibit us from paying, cash dividends on our Class A common stock and, consequently, your only opportunity to achieve a return on your investment is if the price of our Class A common stock appreciates.

We do not plan to declare dividends on shares of our Class A common stock in the foreseeable future. Additionally, we are currently prohibited from making any cash dividends pursuant to the terms of our senior secured revolving credit facility and our second lien term loan facility. Consequently, your only opportunity to achieve a return on your investment in us will be if you sell your Class A common stock at a price greater than you paid for it. There is no guarantee that the price of our Class A common stock that will prevail in the market will ever exceed the purchase price.

Future sales of our Class A common stock in the public market could reduce our stock price, and any additional capital raised by us through the sale of equity or convertible securities may dilute your ownership in us.

Subject to certain limitations and exceptions, holders of JEH LLC Units may exchange their JEH LLC Units (together with a corresponding number of shares of Class B common stock) for shares of Class A common stock (on

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a one-for-one basis, subject to customary conversion rate adjustments for stock splits, stock dividends and reclassification and other similar transactions) and then sell those shares of Class A common stock. Additionally, we may issue additional shares of Class A common stock or convertible securities in subsequent public offerings. As of July 29, 2013, we had 12,500,000 outstanding shares of Class A common stock and 36,836,333 outstanding shares of Class B common stock. As of July 29, 2013, Metalmark Capital beneficially owned 23,204,216 shares of Class B common stock and certain Jones family entities beneficially owned 12,323,547 shares of Class B common stock, all of which are restricted from immediate resale under the federal securities laws and are subject to the lock-up agreements between such parties and the underwriters, but may be sold into the market in the future. Additionally, the Jones family entities and Metalmark Capital are parties to a stockholders’ agreement with us which requires us to effect the registration of their shares in certain circumstances no earlier than the expiration of the lock-up period contained in the underwriting agreement entered into in connection with our initial public offering. Employees are subject to certain restrictions on the sale of their shares for 180 days after the date of our initial public offering; however, after such period, and subject to compliance with the Securities Act or exemptions therefrom, these employees may sell such shares into the public market.

On August 8, 2013, we filed a registration statement with the SEC on Form S-8 providing for the registration of 3,850,000 shares of our Class A common stock issued or reserved for issuance under our equity incentive plan. Subject to the satisfaction of vesting conditions and the expiration of lock-up agreements, shares registered under the registration statement on Form S-8 are available for resale immediately in the public market without restriction.

We cannot predict the size of future issuances of our Class A common stock or securities convertible into Class A common stock or the effect, if any, that future issuances and sales of shares of our Class A common stock will have on the market price of our Class A common stock. Sales of substantial amounts of our Class A common stock (including shares issued in connection with an acquisition), or the perception that such sales could occur, may adversely affect prevailing market prices of our Class A common stock.

The underwriters of the initial public offering may waive or release parties to the lock-up agreements entered into in connection with the public offering, which could adversely affect the price of our Class A common stock.

Certain of our stockholders, directors, members of our senior management team and certain affiliates of Metalmark Capital and Wells Fargo entered into lock-up agreements with respect to their Class A common stock, pursuant to which they are subject to certain resale restrictions for a period of 180 days following the effective date of the prospectus. Certain representatives of the underwriters to the initial public offering, at any time and without notice, may release all or any portion of the Class A common stock subject to the foregoing lock-up agreements. If the restrictions under the lock-up agreements are waived, then the related Class A common stock will be available for sale into the public markets, which could cause the market price of our Class A common stock to decline and impair our ability to raise capital.

A significant reduction by Metalmark Capital of its ownership interest in us could adversely affect us.

Metalmark Capital is our largest stockholder and two members of our board of directors are affiliated with Metalmark Capital. We believe that Metalmark Capital’s substantial ownership interest in us provides them with an economic incentive to assist us to be successful. Following the 180th day after the closing of the initial public offering, however, Metalmark Capital will not be subject to any obligation to maintain their ownership interest in us and may elect at any time thereafter to sell all or a substantial portion of or otherwise reduce its ownership interest in us. If Metalmark Capital sells all or a substantial portion of its ownership interest in us, Metalmark Capital would have less incentive to assist in our success, and its affiliates that are members of our board of directors may resign. Such actions could adversely affect our ability to successfully implement our business strategies, which could adversely affect our cash flows or results of operations.

We are subject to anti-takeover provisions that could delay or prevent an acquisition of our company, even if the acquisition would be beneficial to our stockholders.

Provisions in our amended and restated certificate of incorporation and amended and restated bylaws may delay or prevent an acquisition of us. These provisions may also frustrate or prevent any attempts by our stockholders to replace or remove our current management by making it more difficult for stockholders to replace members of our board of directors, who are responsible for appointing the members of our management team. Furthermore, because

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we are incorporated in Delaware, we are governed by the provisions of Section 203 of the Delaware General Corporation Law, or the DGCL, which prohibits, with some exceptions, stockholders owning in excess of 15% of our outstanding voting stock from merging or combining with us. Additionally, our amended and restated bylaws establish advance notice requirements for nominations for election to our board of directors and for proposing matters that can be acted upon at stockholder meetings. Although we believe these provisions together provide an opportunity to receive higher bids by requiring potential acquirers to negotiate with our board of directors, they would apply even if an offer to acquire us may be considered beneficial by some stockholders.

In addition, certain change of control events have the effect of accelerating the payment due under our Tax Receivable Agreement, which could be substantial and accordingly serve as a disincentive to a potential acquirer of our company.

The NYSE does not require publicly listed companies like us to immediately comply with certain of its corporate governance requirements.

We will rely on the phase-in rules of the SEC and the NYSE with respect to the independence of our nomination, compensation and audit committees. These rules permit us to have an audit committee that has one member that is independent by the date that our Class A common stock first trades on the NYSE, a majority of members that are independent within 90 days of the effectiveness of the registration statement of which the Prospectus formed a part and all members that are independent within one year of the effective date. Similarly, the rules permit us to have nominating and compensation committees that have one member that is independent by the date that our Class A common stock first trades on the NYSE, a majority of members that are independent within 90 days of the listing date and all members that are independent within one year of the listing date. Additionally, we have 12 months from the date of listing to satisfy the requirement that a majority of the board of directors be independent. Accordingly, you may not have the same protections afforded to stockholders of companies that are subject to all of the corporate governance requirements of the NYSE.

We are a holding company. Our sole material asset is our equity interest in JEH LLC, and we are accordingly dependent upon distributions from JEH LLC to pay taxes, make payments under the Tax Receivable Agreement and cover our corporate and other overhead expenses.

We are a holding company and will have no material assets other than our equity interest in JEH LLC. We have no independent means of generating revenue. To the extent JEH LLC has available cash, we intend to cause JEH LLC to make distributions to its unitholders, including us, in an amount sufficient to cover all applicable taxes at assumed tax rates and payments under the Tax Receivable Agreement we will enter into with JEH LLC and the Existing Owners, and to reimburse us for our corporate and other overhead expenses. We are limited, however, in our ability to cause JEH LLC and its subsidiaries to make these and other distributions to us due to the restrictions under our credit facilities. To the extent that we need funds and JEH LLC or its subsidiaries are restricted from making such distributions under applicable law or regulation or under the terms of their financing arrangements, or are otherwise unable to provide such funds, it could materially adversely affect our liquidity and financial condition.

The Jones family and Metalmark Capital hold a majority of the combined voting power of our Class A and Class B common stock.

As of July 30, 2013, the Jones family and Metalmark Capital hold approximately 72.0% of the combined voting power of our Class A and Class B common stock. Although the Jones family and Metalmark Capital are entitled to act separately in their own respective interests with respect to their stock in us, the Jones family and Metalmark Capital have the ability to elect all of the members of our board of directors, and thereby to control our management and affairs. In addition, they are able to determine the outcome of all matters requiring stockholder approval, including mergers and other material transactions, and are able to cause or prevent a change in the composition of our board of directors or a change in control of our company that could deprive our stockholders of an opportunity to receive a premium for their Class A common stock as part of a sale of our company. So long as the Jones family and Metalmark Capital continue to own a significant amount of the outstanding shares of our common stock, even if such amount is less than 50%, they will continue to be able to strongly influence all matters requiring stockholder approval, regardless of whether or not other stockholders believe that the transaction is in their own best interests.

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

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

The payment obligations under the Tax Receivable Agreement are our obligations and not obligations of JEH LLC. For purposes of the Tax Receivable Agreement, cash savings in tax generally are calculated by comparing our actual tax liability to the amount we would have been required to pay had we not been able to utilize any of the tax benefits subject to the Tax Receivable Agreement. The term of the Tax Receivable Agreement commenced upon the completion of our initial public offering and will continue until all such tax benefits have been utilized or expired, unless we exercise our right to terminate the Tax Receivable Agreement by making the termination payment specified in the agreement.

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

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

In certain cases, payments under the Tax Receivable Agreement may be accelerated and/or significantly exceed the actual benefits, if any, we realize in respect of the tax attributes subject to the Tax Receivable Agreement.

If we elect to terminate the Tax Receivable Agreement early or it is terminated early due to certain mergers or other changes of control we would be required to make an immediate payment equal to the present value of the anticipated future tax benefits subject to the Tax Receivable Agreement, which calculation of anticipated future tax benefits will be based upon certain assumptions and deemed events set forth in the Tax Receivable Agreement, including the assumption that we have sufficient taxable income to fully utilize such benefits and that any JEH LLC Units that the Existing Owners or their permitted transferees own on the termination date are deemed to be exchanged on the termination date. Any early termination payment may be made significantly in advance of the actual realization, if any, of such future benefits.

In these situations, our obligations under the Tax Receivable Agreement could have a substantial negative impact on our liquidity and could have the effect of delaying, deferring or preventing certain mergers, asset sales, other forms of business combinations or other changes of control due to the additional transaction cost a potential acquirer may attribute to satisfying such obligations. There can be no assurance that we will be able to finance our obligations under the Tax Receivable Agreement.

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

The Existing Owners may have interests that conflict with holders of shares of our Class A common stock.

As of July 30, 2013, the Existing Owners beneficially owned approximately 74.7% of the JEH LLC Units. Because they hold a portion of their ownership interest in our business through JEH LLC, rather than through us, the Existing Owners may have conflicting interests with holders of shares of Class A common stock. For example, the Existing Owners may have different tax positions from us which could influence their decisions regarding whether and when to cause us to dispose of assets and whether and when to cause us to incur new or refinance existing indebtedness, especially in light of the Tax Receivable Agreement.

Furthermore, conflicts of interest could arise in the future between us, on the one hand, and the Existing Owners, on the other hand, concerning among other things, potential competitive business activities or business opportunities. These conflicts of interest may not be resolved in our favor.

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

Use of Proceeds

On July 29, 2013, we completed our initial public offering of our Class A common stock pursuant to our registration statement on Form S-1 (File 333-188896), as amended and declared effective by the SEC on July 23, 2013. J.P. Morgan Securities LLC, Barclays Capital Inc. and Wells Fargo Securities, LLC acted as joint book-running managers and representatives of the underwriters in the offering. The sale of the shares in our initial public offering closed on July 29, 2013 and we sold 12,500,000 shares of Class A common stock to the public.

The proceeds of our initial public offering, based on the public offering price of $15.00 per share, were $187.5 million. After subtracting underwriting discounts and commissions of $10.5 million, we received net proceeds of approximately $177.0 million from the sale of 12,500,000 shares of Class A common stock (or $173.0 million net of estimated offering expenses paid directly by us). The net proceeds of approximately $173.0 million were contributed to JEH LLC in exchange for JEH LLC Units. JEH LLC used those net proceeds to repay $167.0 million of outstanding borrowings under its senior secured revolving credit facility. The remaining $6.0 million was used for general corporate purposes. No fees or expenses have been paid, directly or indirectly, to any officer, director, or 10% stockholder or other affiliate.

Item 3. Defaults Upon Senior Securities

None.

Item 4. Mine Safety Disclosures

Not applicable.

Item 5. Other Information

Not applicable.

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Item 6. Exhibits

Exhibit No.		Description
3.1		Amended and Restated Certificate of Incorporation (incorporated by reference herein to Exhibit 3.1 of the Form 8-K, filed by the registrant on July 30, 2013).

3.2		Amended and Restated Bylaws (incorporated by reference herein to Exhibit 3.2 of the Form 8-K, filed by the registrant on July 30, 2013).

10.1		Jones Energy Holdings, LLC Monarch Equity Plan (incorporated by reference herein to Exhibit 10.8 of the Form S-1 (File No. 333-188896), filed by the registrant on May 28, 2013).

31.1*		Rule 13a-14(a)/15d-14(a) Certification of Jonny Jones (Principal Executive Officer).

31.2*		Rule 13a-14(a)/15d-14(a) Certification of Robert J. Brooks (Principal Financial Officer).

32.1**		Section 1350 Certification of Jonny Jones (Principal Executive Officer).

32.2**		Section 1350 Certification of Robert J. Brooks (Principal Financial Officer).

101.INS**		XBRL Instance Document.

101.SCH**		XBRL Taxonomy Extension Schema Document.

101.CAL**		XBRL Taxonomy Extension Calculation Linkbase Document.

101.DEF**		XBRL Taxonomy Extension Definition Linkbase Document.

101.LAB**		XBRL Taxonomy Extension Label Linkbase Document.

101.PRE**		XBRL Taxonomy Extension Presentation Linkbase Document.

* - filed herewith

** - furnished herewith

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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.

	Jones Energy, Inc.

	(registrant)


Date: September 3, 2013	By:	/s/ Jonny Jones
		Name:	Jonny Jones
		Title:	Chief Executive Officer

Signature Page to Form 10-Q