Jones Energy, Inc. - FORM 10-Q

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EX-31.2 - EX-31.2 - Jones Energy, Inc.	a14-14173_1ex31d2.htm
EX-32.2 - EX-32.2 - Jones Energy, Inc.	a14-14173_1ex32d2.htm

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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, 2014

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 x No o

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 1, 2014, the Registrant had 12,526,580 shares of Class A common stock outstanding and 36,813,731 shares of Class B common stock outstanding.

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JONES ENERGY, INC.

TABLE OF CONTENTS

PART 1—FINANCIAL INFORMATION	ii

Item 1. Financial Statements	ii

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	21

Item 3. Quantitative and Qualitative Disclosures About Market Risk	30

Item 4. Controls and Procedures	31

PART II—OTHER INFORMATION	32

Item 1. Legal Proceedings	32

Item 1A. Risk Factors	32

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	33

Item 3. Defaults Upon Senior Securities	33

Item 4. Mine Safety Disclosures	33

Item 5. Other Information	33

Item 6. Exhibits	34

SIGNATURES	35

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PART 1—FINANCIAL INFORMATION

Item 1. Financial Statements

Jones Energy, Inc.

Index

	Page(s)

Unaudited Consolidated Financial Statements

Balance Sheets	1

Statements of Operations	2

Statement of Changes in Stockholders’ Equity	3

Statements of Cash Flows	4

Notes to the Consolidated Financial Statements	5–20

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Jones Energy, Inc.

Consolidated Balance Sheets (Unaudited)

	June 30,			December 31,
(in thousands of dollars)	2014			2013

Assets
Current assets
Cash	$	31,791		$	23,820
Restricted cash	97			45
Accounts receivable, net
Oil and gas sales	78,238			51,233
Joint interest owners	30,080			42,481
Other	1,824			16,782
Commodity derivative assets	5,408			8,837
Other current assets	3,098			2,392
Deferred tax assets	12			12
Total current assets	150,548			145,602
Oil and gas properties, net, at cost
under the successful efforts method	1,449,765			1,297,228
Other property, plant and equipment, net	3,591			3,444
Commodity derivative assets	10,584			25,398
Other assets	20,307			15,006
Deferred tax assets	1,766			1,301
Total assets	$	1,636,561		$	1,487,979
Liabilities and Stockholders’ Equity
Current liabilities
Trade accounts payable	$	87,978		$	89,430
Oil and gas sales payable	81,703			66,179
Accrued liabilities	31,038			10,805
Commodity derivative liabilities	20,761			10,664
Asset retirement obligations	2,870			2,590
Total current liabilities	224,350			179,668
Long-term debt	250,000			658,000
Senior notes	500,000			—
Deferred revenue	14,004			14,531
Commodity derivative liabilities	9,904			190
Asset retirement obligations	9,245			8,373
Deferred tax liabilities	3,696			3,093
Total liabilities	1,011,199			863,855
Commitments and contingencies (Note 9)
Stockholders’ equity
Class A common stock, $0.001 par value; 12,548,878 shares issued and 12,526,580 shares outstanding at June 30, 2014 and 12,526,580 shares issued and outstanding at December 31, 2013	13			13
Class B common stock, $0.001 par value; 36,814,035 and 36,836,333 shares issued and outstanding at June 30, 2014 and December 31, 2013	37			37
Treasury stock, at cost: 22,298 Class A shares at June 30, 2014 and 0 shares at December 31, 2013	(352		)	—
Additional paid-in-capital	174,555			173,169
Retained earnings (deficit)	(2,160		)	(2,186		)
Stockholders’ equity	172,093			171,033
Non-controlling interest	453,269			453,091
Total stockholders’ equity	625,362			624,124
Total liabilities and stockholders’ equity	$	1,636,561		$	1,487,979

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

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Jones Energy, Inc.

Consolidated Statements of Operations (Unaudited)

	Three Months Ended June 30,						Six Months Ended June 30,
(in thousands of dollars except per share data)	2014			2013			2014			2013

Operating revenues
Oil and gas sales	$	105,795		$	64,300		$	203,663		$	119,559
Other revenues	595			226			971			447
Total operating revenues	106,390			64,526			204,634			120,006
Operating costs and expenses
Lease operating	12,378			6,201			22,391			11,546
Production taxes	5,174			3,182			9,936			5,634
Exploration	191			479			3,012			605
Depletion, depreciation and amortization	43,211			26,922			82,556			52,023
Accretion of discount	197			166			367			263
General and administrative (including non-cash compensation expense)	6,537			7,325			11,798			11,637
Total operating expenses	67,688			44,275			130,060			81,708
Operating income	38,702			20,251			74,574			38,298
Other income (expense)
Interest expense	(14,767		)	(8,092		)	(22,810		)	(16,279		)
Net gain (loss) on commodity derivatives	(33,698		)	36,555			(50,948		)	25,172
Gain (loss) on sales of assets	1			(45		)	67			25
Other income (expense), net	(48,464		)	28,418			(73,691		)	8,918
Income (loss) before income tax	(9,762		)	48,669			883			47,216

Income tax provision (benefit)	(578		)	252			679			251
Net income (loss)	(9,184		)	48,417			204			46,965
Net income (loss) attributable to non-controlling interests	(7,537		)	—			178			—
Net income (loss) attributable to controlling interests	$	(1,647	)	$	48,417		$	26		$	46,965

Earnings per share:
Basic	$	(0.13	)				$	0.00
Diluted	$	(0.13	)				$	0.00
Weighted average shares outstanding:
Basic	12,500						12,500
Diluted	12,530						12,521

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

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Jones Energy, Inc.

Consolidated Statement of Changes In Stockholders’ Equity (Unaudited)

	Common Stock							Treasury Stock				Additional							Total
	Class A			Class B				Class A				Paid-in-		Retained			Non-controlling		Stockholders’
(amounts in thousands)	Shares	Value		Shares		Value		Shares	Value			Capital		Earnings			Interest		Equity

Balance at December 31, 2013	12,500	$	13	36,836		$	37	—	$	—		$	173,169	$	(2,186	)	$	453,091	$	624,124
Stock-compensation expense	—	—		—		—		—	—			1,386		—			—		1,386
Treasury stock	—	—		(22	)	—		22	(352		)	—		—			—		(352		)
Net income	—	—		—		—		—	—			—		26			178		204
Balance at June 30, 2014	12,500	$	13	36,814		$	37	22	$	(352	)	$	174,555	$	(2,160	)	$	453,269	$	625,362

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

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Jones Energy, Inc.

Consolidated Statements of Cash Flows (Unaudited)

	Six Months Ended June 30,
(in thousands of dollars)	2014			2013

Cash flows from operating activities
Net income	$	204		$	46,965
Adjustments to reconcile net income to net cash provided by operating activities
Exploration expense	2,983			—
Depletion, depreciation, and amortization	82,556			52,023
Accretion of discount	367			263
Amortization of debt issuance costs	5,282			1,327
Accrued interest expense	7,612			689
Stock compensation expense	1,386			473
Other non-cash compensation expense	253			2,465
Amortization of deferred revenue	(526		)	—
Net loss (gain) on commodity derivatives	50,948			(25,172		)
Gain on sales of assets	(67		)	(25		)
Deferred income taxes	138			217
Other - net	40			310
Changes in assets and liabilities
Accounts receivable	(13,365		)	(17,456		)
Other assets	(85		)	(2,885		)
Accounts payable and accrued liabilities	17,581			7,616
Net cash provided by operations	155,307			66,810

Cash flows from investing activities
Additions to oil and gas properties	(229,582		)	(63,545		)
Net adjustments to purchase price of properties acquired	13,681			—
Proceeds from sales of assets	67			423
Acquisition of other property, plant and equipment	(639		)	(290		)
Current period settlements of matured derivative contracts	(11,255		)	7,267
Change in restricted cash	(52		)	—
Net cash used in investing	(227,780		)	(56,145		)

Cash flows from financing activities
Proceeds from issuance of long-term debt	60,000			—
Repayment under long-term debt	(468,000		)	(5,000		)
Proceeds from senior notes	500,000
Purchases of treasury stock	(352		)	—
Payment of debt issuance costs	(11,204		)	(25		)
Net cash provided by (used in) financing	80,444			(5,025		)
Net increase in cash	7,971			5,640

Cash
Beginning of period	23,820			23,726
End of period	$	31,791		$	29,366

Supplemental disclosure of cash flow information
Cash paid for interest	$	9,348		$	13,818
Cash paid for income taxes	155			—
Change in accrued additions to oil and gas properties	7,218			26,312
Current additions to ARO	844			263
Deferred offering costs	—			3,479
Noncash distribution to members	—			10,000

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

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Jones Energy, Inc.

Notes to the Consolidated Financial Statements (Unaudited)

1. Organization and Description of Business

Organization

Jones Energy, Inc. (the “Company”) was formed in March 2013 as a Delaware corporation to become a publicly traded entity and the holding company of Jones Energy Holdings, LLC (“JEH”). As the sole managing member of JEH, Jones Energy, Inc. is responsible for all operational, management and administrative decisions relating to JEH’s business and consolidates the financial results of JEH and its subsidiaries.

JEH was formed as a Delaware limited liability company on December 16, 2009 through investments made by the Jones family and through private equity funds managed by Metalmark Capital and Wells Fargo Energy Capital. JEH 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.

Pursuant to the terms of a corporate reorganization that was completed in connection with the closing of Jones Energy, Inc.’s initial public offering (“IPO”) on July 29, 2013, the pre-IPO owners of JEH converted their existing membership interests in JEH into JEH units and amended the existing LLC agreement to, among other things, modify its equity capital to consist solely of JEH units and to admit Jones Energy, Inc. as the sole managing member of JEH. Jones Energy, Inc.’s certificate of incorporation authorizes two classes of common stock, Class A common stock and Class B common stock. Only Class A common stock was offered to investors pursuant to the IPO. The Class B common stock is held by the pre-IPO owners of JEH and can be exchanged (together with a corresponding number of JEH units) for shares of Class A common stock on a one-for-one basis, subject to customary conversion rate adjustments for stock splits, stock dividends and reclassifications and other similar transactions. The Class B common stock has no economic rights but entitles its holder to one vote on all matters to be voted on by the Company’s stockholders generally. As a result of the IPO, the pre-IPO owners retained 74.7% of the total economic interest in JEH, but with no voting rights or management power over JEH, resulting in the Company reporting this ownership interest as a non-controlling interest.

Description of Business

The Company is engaged in the acquisition, exploration, and production of oil and natural gas properties in the mid-continent United States. The Company’s assets are located within two distinct basins in the Texas Panhandle and Oklahoma, the Anadarko Basin and the Arkoma Basin, and are owned by JEH and its operating subsidiaries. The Company operates in one industry segment and all of its operations are conducted in one geographic area of the United States. The Company is headquartered in Austin, Texas.

Revision of Previously Issued Financial Statements

In conjunction with our year-end audit and the preparation of our annual Form 10-K, we identified an error in our previously issued financial statements which would have been material to our fourth quarter of 2013 if recorded as an out of period adjustment in such period. We recorded the adjustments on a quarterly basis in prior periods and therefore, have revised our Consolidated Statement of Operations for the three and six months ended June 30, 2013 to record $0.2 million and $0.4 million, respectively, of additional interest expense on obligations that are unrelated to our credit agreements discussed in Note 6.

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Jones Energy, Inc.

Notes to the Consolidated Financial Statements (Unaudited)

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”). All significant intercompany transactions and balances have been eliminated in consolidation. The financial statements reported for June 30, 2014, and the three and six month periods then ended include the Company and all of its subsidiaries.

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 Annual Report on Form 10-K for the year ended December 31, 2013.

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 the Company’s estimates of depletion expense, impairment, and the allocation of value in our business combinations. Significant assumptions are also required in the Company’s estimates of the net gain or loss on commodity derivative assets, fair value associated with business combinations, and asset retirement obligations (“ARO”).

Oil and Gas Properties

The Company 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, 2014 and December 31, 2013:

	June 30,			December 31,
(in thousands of dollars)	2014			2013

Mineral interests in properties
Unproved	$	95,799		$	99,134
Proved	975,173			958,816
Wells and equipment and related facilities	831,328			609,748
	1,902,300			1,667,698
Less: Accumulated depletion and impairment	(452,535		)	(370,470		)
Net oil and gas properties	$	1,449,765		$	1,297,228

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Jones Energy, Inc.

Notes to the Consolidated Financial Statements (Unaudited)

Costs to acquire mineral interests in oil and natural gas properties are capitalized. Costs to drill and equip development wells and the related asset retirement costs are capitalized. The costs to drill and equip exploratory wells are capitalized pending determination of whether the Company has discovered proved commercial reserves. If proved commercial reserves are not discovered, such drilling costs are charged to expense. In some circumstances, it may be uncertain whether proved commercial reserves have been found when drilling has been completed. Such exploratory well drilling costs may continue to be capitalized if the anticipated reserve quantity is sufficient to justify its completion as a producing well and sufficient progress in assessing the reserves and the economic and operating viability of the project is being made. During the six months ended June 30, 2014 we had no material capitalized costs associated with exploratory wells.

The Company 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. The Company did not capitalize any interest during the six months ended June 30, 2014 as no projects lasted more than six months. Depletion of oil and gas properties amounted to $43.0 million and $82.0 million for the three and six months ended June 30, 2014, respectively, and $26.7 million and $51.6 million for the three and six months ended June 30, 2013, respectively.

Other Property, Plant and Equipment

Other property, plant and equipment consisted of the following at June 30, 2014 and December 31, 2013:

	June 30,			December 31,
(in thousands of dollars)	2014			2013

Leasehold improvements	$	1,116		$	1,060
Furniture, fixtures, computers and software	3,003			2,491
Vehicles	903			835
Aircraft	910			910
Other	134			134
	6,066			5,430
Less: Accumulated depreciation and amortization	(2,475		)	(1,986		)
Net other property, plant and equipment	$	3,591		$	3,444

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 $0.5 million during the three and six months ended June 30, 2014, respectively, and $0.2 million and $0.4 million during the three and six months ended June 30, 2013, respectively.

Commodity Derivatives

The Company 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 six month periods ended June 30, 2014 and 2013, the Company 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 the Company does not designate its commodity derivative instruments as cash-flow hedges, management uses those instruments to reduce the Company’s exposure to fluctuations in commodity prices related to its natural gas and oil production. Net 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

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Jones Energy, Inc.

Notes to the Consolidated Financial Statements (Unaudited)

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. See Note 4, “Fair Value Measurement,” for disclosure about the fair values of commodity derivative instruments.

Asset Retirement Obligations

The Company’s asset retirement obligations consist of future plugging and abandonment expenses on oil and natural gas properties.

A summary of the Company’s ARO for the six months ended June 30, 2014 is as follows:

(in thousands of dollars)
Balance at December 31, 2013	$	10,963

Liabilities incurred	844
Accretion of discount	367
Liabilities settled due to sale of related properties	(38		)
Liabilities settled due to plugging and abandonment	(55		)
Change in estimate	34

Balance at June 30, 2014	12,115

Less: Current portion of ARO	(2,870		)

Total long-term ARO at June 30, 2014	$	9,245

Income Taxes

Following its IPO on July 29, 2013, the Company began recording a federal and state income tax liability associated with its status as a corporation. No provision for federal income taxes was recorded prior to the IPO because the taxable income or loss was includable in the income tax returns of the individual partners and members. The Company is also subject to state income taxes. The State of Texas includes in its tax system a franchise tax applicable to the Company and an accrual for franchise taxes is included in the financial statements when appropriate.

Income taxes are accounted for under the asset and liability method, which requires recognition of deferred tax assets and liabilities for the expected future tax consequences of events that have been included in the financial statements. Under this method, deferred tax assets and liabilities are determined based on the differences between the financial statements and tax basis of assets and liabilities using enacted tax rates in effect for the year in which differences are expected to be recovered or settled pursuant to the provisions of ASC 740—Income Taxes. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in income in the period that includes the enactment date.

The Company records a valuation allowance if it is deemed more likely than not that all or a portion of its deferred income tax assets will not be realized. In addition, income tax rules and regulations are subject to interpretation and the application of those rules and regulations require judgment by the Company and may be challenged by the taxation authorities. The Company follows ASC 740-10-25, which requires the use of a two-step approach for recognizing and measuring tax benefits taken or expected to be taken in a tax return and disclosures regarding uncertainties in income tax positions. Only tax positions that meet the more likely than not recognition threshold are recognized. The Company’s policy is to include any interest and penalties recorded on uncertain tax positions as a component of income tax expense. The Company’s unrecognized tax benefits or related interest and penalties are immaterial.

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Jones Energy, Inc.

Notes to the Consolidated Financial Statements (Unaudited)

Tax Receivable Agreement

In conjunction with the IPO, the Company entered into a Tax Receivable Agreement (“TRA”) with JEH and the pre-IPO owners. Upon any exchange of JEH units and Class B common stock of the Company held by JEH’s pre-IPO owners for Class A common stock of the Company, the TRA provides for the payment by the Company, directly to such exchanging owners, of 85% of the amount of cash savings in income or franchise taxes that the Company realizes as a result of (i) the tax basis increases resulting from the exchange of JEH Units for shares of Class A common stock (or resulting from a sale of JEH Units for cash) and (ii) imputed interest deemed to be paid by the Company as a result of, and additional tax basis arising from, any payments the Company makes under the TRA. The Company will retain the benefit of the remaining 15% of the cash savings. Liabilities under the TRA will be recognized upon the exchange of shares. As of June 30, 2014, there had been no exchanges that resulted in a material liability.

Stock Compensation

JEH had a management incentive plan that provided membership-interest awards in JEH to members of senior management (“management units”). The management unit grants awarded prior to the initial filing of the registration statement in March 2013 had a dual vesting schedule. Sixty percent of the units awarded vested in five equal annual installments, with the remaining 40% vesting upon a company restructuring event, including the IPO. All grants awarded after the initial registration statement but prior to the IPO have a vesting structure of either three or five equal annual installments and were valued at the IPO price, adjusted for equivalent shares. Both the vested and unvested management units were converted into JEH Units and shares of Class B common stock at the IPO date.

Under the Jones Energy, Inc. 2013 Omnibus Incentive Plan, established in conjunction with the Company’s IPO, the Company reserved 3,850,000 shares of Class A common stock for director and employee stock-based compensation awards.

In September 2013, the Company granted each of the four outside members of the Board of Directors 6,645 shares of restricted Class A common stock under the Jones Energy, Inc. 2013 Omnibus Incentive Plan. The fair value of the restricted stock awards was based on the value of the Company’s Class A common stock on the date of grant and is expensed on a straight-line basis over the one-year vesting period.

In May 2014, the Company granted performance unit and restricted stock unit awards to certain officers and employees under the Jones Energy, Inc. 2013 Omnibus Incentive Plan. The fair value of the performance units was based on the grant date fair value (using a Monte Carlo simulation model) and is expensed on a straight-line basis over the applicable three-year performance period. The number of shares of common stock issuable upon vesting of the performance unit awards ranges from zero to 200% based on the Company’s total shareholder return relative to an industry peer group over the applicable three-year performance period. The fair value of the restricted stock unit awards was based on the value of the Company’s Class A common stock on the date of grant and is expensed on a straight-line basis over the applicable three-year vesting period.

Refer to Note 7, “Stock-based Compensation,” for additional information regarding the management units, performance units, and restricted stock unit awards.

Recent Accounting Developments

There are no recent accounting developments applicable to the Company as of June 30, 2014.

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Jones Energy, Inc.

Notes to the Consolidated Financial Statements (Unaudited)

3. Acquisition of Properties

No property acquisitions that would qualify as a business combination occurred during the six months ended June 30, 2014.

On December 18, 2013, JEH closed on the purchase of certain oil and natural gas properties located in Texas and western Oklahoma from Sabine Mid-Continent, LLC, for an initial purchase price of $193.5 million (referred to herein as the “Sabine acquisition” or “Sabine”), subject to customary closing adjustments. The acquired assets include both producing properties and undeveloped acreage. The purchase was financed with borrowings under the senior secured credit facility.

During the quarter ended June 30, 2014, the Company made a final determination with the sellers as to the purchase price resulting in a final purchase price of $177.8 million. The amount of the total purchase price allocated to undeveloped oil and gas properties was reduced by these adjustments. The adjustments were retroactively applied to our December 31, 2013 Consolidated Balance Sheet as a reduction to oil and gas properties and an increase in receivables. The adjusted purchase price is allocated as follows:

(in thousands of dollars)

Oil and gas properties
Unproved	$	31,587
Proved	147,024
Asset retirement obligations	(824		)
Total purchase price	$	177,787

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 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 determination of fair value is dependent on factors as of the acquisition date and the final adjustments to the purchase price.

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, 2013. 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, 2013 or to project our results of operations for any future date or period.

	Three Months Ended June 30, 2013				Six Months Ended June 30, 2013
(in thousands of dollars)	Actual		Pro Forma		Actual		Pro Forma

Total operating revenue	$	64,526	$	77,704	$	120,006	$	147,372
Total operating expenses	44,275		52,413		81,708		90,889
Operating income	20,251		25,291		38,298		56,483
Net income	48,417		53,457		46,965		65,150

4. Fair Value Measurement

Fair Value of Financial Instruments

The Company 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.

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Jones Energy, Inc.

Notes to the Consolidated Financial Statements (Unaudited)

The Company 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. The Company 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 because 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. The Company currently has all of its derivative positions placed and held by members of its lending group, which have strong credit quality.

Liquidity valuation adjustments are necessary when the Company 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.

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. The Company does not classify any of its financial instruments as 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. The Company classifies natural gas liquid swaps and basis swaps for which future pricing is not readily available as Level 3. The Company obtains estimates from independent third parties for its open positions and subjects those to the credit adjustment criteria described above.

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Jones Energy, Inc.

Notes to the Consolidated Financial Statements (Unaudited)

The financial instruments carried at fair value as of June 30, 2014 and December 31, 2013, by consolidated balance sheet caption and by valuation hierarchy, as described above are as follows:

	June 30, 2014
(in thousands of dollars)	Fair Value Measurements
Commodity Price Hedges	(Level 1)		(Level 2)		(Level 3)		Total

Current assets	$	—	$	5,408	$	—	$	5,408
Long-term assets	—		10,584		—		10,584
Current liabilities	—		19,336		1,425		20,761
Long-term liabilities	—		9,002		902		9,904

	December 31, 2013
(in thousands of dollars)	Fair Value Measurements
Commodity Price Hedges	(Level 1)		(Level 2)		(Level 3)			Total

Current assets	$	—	$	8,837	$	—		$	8,837
Long-term assets	—		25,967		(569		)	25,398
Current liabilities	—		10,188		476			10,664
Long-term liabilities	—		—		190			190

The following table represents quantitative information about Level 3 inputs used in the fair value measurement of the Company’s commodity derivative contracts as of June 30, 2014.

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

Natural gas liquid swaps	$	(2,327	)	Use a discounted cash flow approach using inputs including forward price statements from counterparties	Natural gas liquid futures prices	$9.56 - $80.96 per barrel

Significant increases/decreases in natural gas liquid futures in isolation would result in a significantly lower/higher fair value measurement. The following table presents the changes in the Level 3 financial instruments for the six months ended June 30, 2014. Changes in fair value of Level 3 instruments represent changes in 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, 2013, net	$	(1,235	)
Purchases	(953		)
Settlements	—
Transfers to Level 2	(147		)
Transfers to Level 3	—
Changes in fair value	8
Balance at June 30, 2014, net	$	(2,327	)

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Jones Energy, Inc.

Notes to the Consolidated Financial Statements (Unaudited)

Transfers from Level 3 to Level 2 represent all of the Company’s natural gas liquids and basis swaps for which observable forward curve pricing information has become readily available. Transfers to Level 3 represent hedges 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, 2014.

Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis

The following table provides the fair value of financial instruments that are not recorded at fair value in the consolidated financial statements:

	June 30, 2014				December 31, 2013
(in thousands of dollars)	Carrying Amount		Fair Value		Carrying Amount		Fair Value

Debt:
Revolver	$	250,000	$	250,000	$	498,000	$	498,000
Term Loan	—		—		160,000		160,000
Senior Notes due 2022	500,000		530,000		—		—

The Revolver is 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 approximates fair value, as it is subject to short-term floating interest rates that approximate the rates available to the Company for those periods.

The fair value of the 2022 Notes is based on pricing that is readily available in the public market. Accordingly, the 2022 Notes would be classified as Level 2 in the valuation hierarchy as the pricing is based on quoted market prices for similar debt securities in active markets.

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 the Company’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 the Company’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 the Company’s ARO represent a nonrecurring Level 3 measurement.

The Company 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. Significant assumptions associated with the calculation of future cash flows used in the impairment analysis include the Company’s estimate of future commodity prices, production costs, development expenditures, production, risk-adjusted discount rates, and other relevant data. Accordingly, the fair value of oil and gas properties used in estimating impairment represents a nonrecurring Level 3 measurement. The Company assessed its unproved properties for impairment as of June 30, 2014 and no impairments were noted. In the event of an impairment, charges are recorded on the Consolidated Statement of Operations. No impairment charges on the Company’s proved properties were recorded during the six months ended June 30, 2014.

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Jones Energy, Inc.

Notes to the Consolidated Financial Statements (Unaudited)

5. Derivative Instruments and Hedging Activities

The Company had various commodity derivatives in place to offset uncertain price fluctuations that could affect its future operations as of June 30, 2014 and December 31, 2013, as follows:

Hedging Positions

	June 30, 2014
								Weighted			Final
		Low			High			Average			Expiration

Oil swaps	Exercise price	$	81.70		$	101.86		$	88.49
	Barrels per month	29,000			151,175			87,311			December 2017

Natural gas swaps	Exercise price	$	3.88		$	6.90		$	4.83
	mmbtu per month	510,000			1,420,000			815,790			December 2017

Basis swaps	Contract differential	$	(0.43	)	$	(0.11	)	$	(0.31	)
	mmbtu per month	320,000			890,000			501,905			March 2016

Natural gas liquids swaps	Exercise price	$	6.72		$	95.24		$	39.91
	Barrels per month	2,000			168,800			60,619			December 2017

	December 31, 2013
								Weighted			Final
		Low			High			Average			Expiration

Oil swaps	Exercise price	$	81.70		$	102.84		$	89.03
	Barrels per month	29,000			161,613			96,149			December 2017

Natural gas swaps	Exercise price	$	3.88		$	6.90		$	4.26
	mmbtu per month	510,000			1,290,000			830,275			December 2017

Basis swaps	Contract differential	$	(0.43	)	$	(0.11	)	$	(0.34	)
	mmbtu per month	320,000			690,000			467,037			March 2016

Natural gas liquids swaps	Exercise price	$	6.72		$	95.24		$	32.98
	Barrels per month	2,000			118,000			46,646			December 2017

The Company recognized net losses on derivative instruments of $33.7 million and $50.9 million for the three and six months ended June 30, 2014, respectively, and net gains on derivative instruments of $36.6 million and $25.2 million for the three and six months ended June 30, 2013.

Offsetting Assets and Liabilities

As of June 30, 2014, the counterparties to our commodity derivative contracts consisted of seven financial institutions as we entered into some contracts with a new counterparty during the quarter ended June 30, 2014. 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.

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Jones Energy, Inc.

Notes to the Consolidated Financial Statements (Unaudited)

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 that are netted on our Consolidated Balance Sheet as of June 30, 2014 and December 31, 2013:

(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, 2014
Commodity derivative contracts
Assets	$	21,045		$	(6,774	)	$	14,271		$	1,721		$	15,992
Liabilities	(31,675		)	6,774			(24,901		)	(5,764		)	(30,665		)
December 31, 2013
Commodity derivative contracts
Assets	$	38,071		$	(6,035	)	$	32,036		$	2,199		$	34,235
Liabilities	(14,347		)	6,035			(8,312		)	(2,542		)	(10,854		)

6. Long-Term Debt

Senior Notes

On April 1, 2014, JEH and its wholly-owned subsidiary, Jones Energy Finance Corp., (the “Issuers”) sold $500 million in aggregate principal amount of the Issuers’ 6.75% Senior Notes due 2022 (the “2022 Notes”). The Company used the proceeds from the issuance of the 2022 Notes to repay all outstanding borrowings under the Term Loan ($160.0 million) and a portion of the borrowing under its Revolver ($308.0 million). The Company subsequently terminated its Term Loan in accordance with its terms. The 2022 Notes bear interest at a rate of 6.75% per year, payable semi-annually on April 1 and October 1 of each year beginning with October 1, 2014. As of June 30, 2014, the Company had $8.4 million in interest accrued related to the 2022 Notes.

The 2022 Notes are guaranteed on a senior unsecured basis by Jones Energy, Inc. and by all of its existing significant subsidiaries. The 2022 Notes will be senior in right of payment to any future subordinated indebtedness of the Issuers.

The Company may redeem the 2022 Notes at any time on or after April 1, 2017 at a declining redemption price set forth in the loan documents, plus accrued and unpaid interest.

The indenture governing the 2022 Notes contains covenants that limit the ability of the Company to incur additional indebtedness or issue certain preferred stock, pay dividends on capital stock, transfer or sell assets, make investments, create certain liens, enter into agreements that restrict dividends or other payments from the Company’s restricted subsidiaries to the Company, consolidate, merge or transfer all of the Company’s assets, engage in transactions with affiliates or create unrestricted subsidiaries. However, many of these covenants will be suspended if the notes are rated investment grade by Standard & Poor’s or Moody’s.

Other Long-Term Debt

In December 2009, the Company entered into two credit agreements with Wells Fargo Bank N.A, the Senior Secured Revolving Credit Facility (the “Revolver”) and the Second Lien Term Loan (the “Term Loan”). On April 1, 2014, the Term Loan was terminated in connection with the issuance of the 2022 Notes. The Revolver’s maturity date is November 5, 2017. The most recent redetermination on April 14, 2014, decreased the borrowing base on the Revolver from $575.0 million to $550.0 million, which occurred in conjunction with the issuance of the 2022 Notes. The Company’s oil and gas properties are pledged as collateral against the credit agreement.

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Jones Energy, Inc.

Notes to the Consolidated Financial Statements (Unaudited)

Terms of the Revolver require the Company to pay interest on the loan on the earlier of the London InterBank Offered Rate (LIBOR) tranche maturity date or three months, with the entire principal and interest due on the loan maturity date. Borrowings may be drawn on the principal amount up to the maximum available credit amount. Interest on the Revolver is calculated at a base rate (LIBOR or prime), plus a margin of 0.50% to 2.50% based on the actual amount borrowed compared to the borrowing base amount and the base rate selected. For the three and six months ended June 30, 2014, the average interest rates under the Revolver were 2.24% and 2.67%, respectively, on average outstanding balances of $235.1 million and $372.0 million, respectively. For the same periods in 2013, the average interest rates were 3.05% and 3.16%, respectively, on average outstanding balances of $445.0 million and $445.4 million, respectively.

Total interest and commitment fees under the Revolver and Term Loan were $1.3 million and $8.5 million for the three and six months ended June 30, 2014 and $7.2 million and $14.5 million for the three and six months ended June 30, 2013. $3.8 million in unamortized deferred financing costs were written off to interest expense during the three months ended June 30, 2014 in connection with the repayment of the Term Loan.

7. Stock-based Compensation

Management Units

Prior to the IPO, JEH granted membership-interest awards in JEH to members of senior management (“management units”) under a previously existing management incentive plan. These awards had various vesting schedules, and a portion of the management units vested in a lump sum at the IPO date. Both the vested and unvested management units were converted into JEH units and shares of Class B common stock at the IPO date. As of June 30, 2014, there were 380,450 unvested JEH units and shares of Class B common stock. The units/shares will become convertible into a like number of shares of Class A common stock upon vesting. The following table summarizes information related to the units/shares held by management as of June 30, 2014:

	JEH Units		Weighted Average Grant Date Fair Value per Share

Unvested at January 1, 2014	457,150		$	12.46
Granted	4,772		15.00
Forfeited	(4,772	)	(15.00		)
Vested	(76,700	)	(15.00		)
Unvested at June 30, 2014	380,450		$	11.95

Stock compensation expense associated with the management units amounted to $0.4 million and $0.8 million for the three and six months ended June 30, 2014, respectively, and $0.4 million and $0.5 million for the three and six months ended June 30, 2013, respectively, and is included in general and administrative expenses on the Company’s Consolidated Statement of Operations.

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Jones Energy, Inc.

Notes to the Consolidated Financial Statements (Unaudited)

Restricted Stock Awards

On September 4, 2013, the Company granted restricted stock awards to non-employee members of the Board of Directors. Each of the four directors was awarded 6,645 restricted shares of Class A common stock, contingent on the director serving as a director of the Company for a one-year service period from the date of grant. The fair value of the awards was based on the value of the Company’s Class A common stock on the date of grant. The total value of the awards to the directors is as follows:

	Restricted Stock Awards	Weighted Average Grant Date Fair Value per Share

Unvested at January 1, 2014	26,580	$	15.05
Granted	—	—
Forfeited	—	—
Vested	—	—
Unvested at June 30, 2014	26,580	$	15.05

Stock compensation expense associated with the Board of Directors awards for the three and six months ended June 30, 2014 was $0.1 million and $0.2 million, respectively, and is included in general and administrative expenses on the Company’s Consolidated Statement of Operations.

Restricted Stock Unit Awards

On May 20, 2014 and on June 13, 2014, the Company granted 283,929 and 20,000 restricted stock unit awards, respectively, to certain officers and employees of the Company. The fair value of the restricted stock unit awards was based on the value of the Company’s Class A common stock on the date of grant and is expensed on a straight-line basis over the applicable three-year vesting period. The total value of the awards to the officers and employees is as follows:

	Restricted Stock Awards	Weighted Average Grant Date Fair Value per Share

Unvested at January 1, 2014	—	$	—
Granted	303,929	17.17
Forfeited	—	—
Vested	—	—
Unvested at June 30, 2014	303,929	$	17.17

Stock compensation expense associated with the employee restricted stock unit awards for the three and six months ended June 30, 2014 was $0.2 million and $0.2 million, respectively, and is included in general and administrative expenses on the Company’s Consolidated Statement of Operations.

Performance Unit Awards

On May 20, 2014, the Company granted 201,318 performance unit awards to certain officers of the Company. Upon the completion of the applicable three-year performance period, each officer will vest in a number of performance units. The number of performance units in which each officer vests at such time will range from 0% to 200% based on the Company’s total shareholder return relative to an industry peer group over the applicable three-year performance period. Each vested performance unit is exchangeable for one share of the Company’s Class A common stock. The grant date fair value of the performance units was determined using a Monte Carlo simulation model, which results in an expected percentage of performance units earned. The fair value of the performance units is recognized on a straight-line basis over the applicable three-year performance period.

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Jones Energy, Inc.

Notes to the Consolidated Financial Statements (Unaudited)

Stock compensation expense associated with the performance unit awards for the three and six months ended June 30, 2014 was $0.2 million and $0.2 million, respectively, and is included in general and administrative expenses on the Company’s Consolidated Statement of Operations.

The Monte Carlo simulation process is a generally accepted statistical technique used, in this instance, to simulate future stock prices for the Company and the components of the peer group. The simulation uses a risk-neutral framework along with the risk-free rate of return, the volatility of each entity, and the correlations of each entity with the other entities in the peer group. A stock price path has been simulated for the Company and each peer company and is used to determine the payout percentages and the stock price of the Company’s common stock as of the vesting date. The ending stock price is multiplied by the payout percentage to determine the projected payout, which is then discounted with the risk-free rate of return to the grant date to determine the grant date fair value for that simulation. When enough simulations are generated, the resulting distribution gives a reasonable estimate of the range of future expected stock prices.

The following assumptions were used for the Monte Carlo simulation model to determine the grant date fair value and associated compensation expense during the three months ended June 30, 2014:

Stock Price(1)	$	17.07
Beginning Average Stock Price(2)	$	14.78
Expected Volatility(3)	46.95		%
Risk-Free Rate of Return(4)	0.61		%

(1) Based on the closing price of Jones Energy, Inc. Class A common stock on May 20, 2014.

(2) Based on the 10 trading days as of the beginning of the performance period.

(3) Based on the average historical volatilities over the most recent 2.62-year period for the Company and each peer company using daily stock prices through May 20, 2014. The measurement period reflects the 2.62 years remaining in the performance period as of the grant date.

(4) Based on the yield curve of U.S. Treasury rates as of May 20, 2014.

Based on these assumptions, the Monte Carlo simulation model resulted in a simulated fair value of $21.65 based on an expected percentage of performance units earned of 126.80%.

8. Earnings per Share

Basic earnings per share (“EPS”) is computed by dividing net income (loss) attributable to controlling interests by the weighted-average number of shares of Class A common stock outstanding during the period. Class B common stock is not included in the calculation of earnings per share because they are not participating securities and have no economic interest in the Company. Diluted earnings per share takes into account the dilutive effect of potential common stock that could be issued by the Company in conjunction with stock awards that have been granted to directors and employees. In accordance with ASC 260, Earnings Per Share, awards of nonvested shares shall be considered outstanding as of the respective grant dates for purposes of computing diluted EPS even though their exercise is contingent upon vesting. For the three and six months ended June 30, 2014, 32,642 shares of performance units were excluded from the calculation as they would have had an antidilutive effect. The following is a calculation of the basic and diluted weighted-average number of shares of Class A common stock outstanding and EPS for the three and six months ended June 30, 2014.

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Jones Energy, Inc.

Notes to the Consolidated Financial Statements (Unaudited)

(in thousands, except per share data)	Three Months Ended June 30, 2014			Six Months Ended June 30, 2014
Income (numerator):
Net income attributable to controlling interests	$	(1,647	)	$	26

Weighted-average shares (denominator):
Weighted-average number of shares of Class A common stock - basic	12,500			12,500
Weighted-average number of shares of Class A common stock - diluted	12,530			12,521

Earnings per share:
Basic	$	(0.13	)	$	0.00
Diluted	$	(0.13	)	$	0.00

9. Commitments and Contingencies

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

10. Income Taxes

Following its IPO, the Company began recording federal and state income tax liabilities associated with its status as a corporation. Prior to the IPO, the Company only recorded a provision for Texas franchise tax as the Company’s taxable income or loss was includable in the federal income tax returns of the individual partners and members. The Company will recognize a tax liability on its share of pre-tax book income, exclusive of the non-controlling interest. JEH is not subject to income tax at the federal level and only recognizes Texas franchise tax expense.

The Company’s effective tax rate for the three and six months ended June 30, 2014 was 5.9% and 76.9%, respectively. The effective rate differs from the statutory rate of 35% primarily due to net income allocated to the non-controlling interest, percentage depletion, state income taxes, and other permanent differences. On a year to date basis, the difference in effective rate between reported periods reflects differences in the composition of estimated income, the Company’s tax expense in Texas, and is amplified, on a percentage basis, by the proximity of our year to date pre-tax book income to zero.

The Company’s income tax provision was a benefit of $0.6 million and an expense of $0.7 million for the three and six months ended June 30, 2014, respectively, and an expense of $0.3 million and $0.3 million for the three and six months ended June 30, 2013, respectively. See the table below for the allocation of the income tax provision between the controlling and non-controlling interests. As of June 30, 2014, the Company did not have any uncertain tax positions requiring adjustments to its tax liability.

	Three months ended June 30,					Six months ended June 30,
(in thousands of dollars)	2014			2013		2014		2013

Income tax provision (benefit)
Jones Energy, Inc.	$	(827	)	$	—	$	198	$	—
Non-controlling interest	249			252		481		251
Total tax provision (benefit)	$	(578	)	$	252	$	679	$	251

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Jones Energy, Inc.

Notes to the Consolidated Financial Statements (Unaudited)

The Company had deferred tax assets for its federal and state loss carryforwards at June 30, 2014 recorded in noncurrent deferred taxes. Deferred tax assets are reduced by a valuation allowance, when, in the opinion of management, it is more likely than not that some portion or all of the deferred tax assets will not be realized. As of June 30, 2014, management determined that a valuation allowance was not required for the tax loss carryforwards as they are expected to be fully utilized before expiration.

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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 Annual Report on Form 10-K for the year ended December 31, 2013, filed on March 14, 2014 with the Securities and Exchange Commission, as well as the unaudited consolidated financial statements and related notes thereto presented in this Quarterly Report on Form 10-Q and in our quarterly report on Form 10-Q for the quarter ended March 31, 2014, filed on May 9, 2014 with the Securities and Exchange Commission. Unless indicated otherwise in this Quarterly Report or the context requires otherwise, all references to “Jones Energy,” the “Company,” “our company,” “we,” “our” and “us” refer to Jones Energy, Inc. and its subsidiaries, including Jones Energy Holdings, LLC (“JEH LLC”). Jones Energy, Inc. is a holding company whose sole material asset is an equity interest in JEH LLC.

Overview

We are an independent oil and gas company engaged in the exploration, development, production and acquisition of oil and natural gas properties in the Anadarko and Arkoma basins of Texas and Oklahoma. Our Chairman and CEO, Jonny Jones, founded our predecessor company in 1988 in continuation of his family’s long history in the oil and gas business, which dates back to the 1920’s. We have grown rapidly by leveraging our focus on low cost drilling and completion methods and our horizontal drilling expertise to develop our inventory and execute several strategic acquisitions. We have accumulated extensive knowledge and experience in developing the Anadarko and Arkoma basins, having concentrated our operations in the Anadarko basin for over 25 years and applied our knowledge to the Arkoma basin since 2011. 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 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 attractive economic rates of return. Our goal is to build value through a disciplined balance between developing our current inventory of identified drilling locations and other opportunities within our existing asset base, 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 and strategic acquisitions. In all of our joint development agreements, we control the drilling and completion of a well, which is the phase during which we can leverage our operational expertise and cost discipline. Following completion, we in some cases may turn over operatorship to a partner during the production phase of a well. We believe the ceding to us of drilling and completion operatorship in our areas of operation by several large oil and gas companies, including ExxonMobil and BP, reflects their acknowledgement of our low cost, safe and efficient operations.

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. Henry Hub natural gas spot price decreased from an

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average of $8.86 MMBtu in 2008 to an average of $3.65 MMBtu in 2013 as the local domestic supply of natural gas increased substantially and the commodity became decoupled from the price of oil. Over the same time period, as the global economic environment improved, West Texas Intermediate spot prices for oil ranged from less than $40 per barrel to greater than $140 per barrel. 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.

Second Quarter 2014 Highlights:

· Successful frack trial outcome in the Cleveland with average oil uplift of more than 30% through the first six months

· Increased average net production to a record 23.6 MBoe/d, up 41% compared to the same period in 2013

· Increased average net oil production to 7.2 MBbl/d, up 59% compared to the same period in 2013.

· Increased Cleveland average net production to 16.8 MBoe/d, up 74% compared to the same period in 2013

· Increased EBITDAX to $77.1 million, up 45% compared to the same period in 2013

· Acquired approximately 10,000 net acres of leasehold primarily in the Texas Panhandle

· Initiated the Tonkawa drilling program with first two wells drilled in line with budget

· Completion of offering of $500,000,000 in aggregate principal amount of 6.75% Senior Notes due 2022

Updated Capital Expenditures Outlook

In our Annual Report on Form 10-K for the year ended December 31, 2013, we provided an overview of our 2014 capital expenditures budget, which was approximately $350 million, of which $310 million was expected to be used to drill and complete wells. In our press release announcing financial and operational results for the second quarter of 2014, we provided an update to the market regarding our capital expenditures for the full year 2014. The updated outlook reflects total projected capital expenditures of $460 million.

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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 price	Three Months Ended June 30,									Six Months Ended June 30,
and average cost data)	2014			2013			Change			2014			2013			Change

Revenues:
Oil	$	64,527		$	36,674		$	27,853		$	118,452		$	64,249		$	54,203
Natural gas	23,292			14,900			8,392			44,677			27,687			16,990
NGLs	17,976			12,726			5,250			40,534			27,623			12,911
Total oil and gas	105,795			64,300			41,495			203,663			119,559			84,104
Other	595			226			369			971			447			524
Total operating revenues	106,390			64,526			41,864			204,634			120,006			84,628
Costs and expenses:
Lease operating	12,378			6,201			6,177			22,391			11,546			10,845
Production taxes	5,174			3,182			1,992			9,936			5,634			4,302
Exploration	191			479			(288		)	3,012			605			2,407
Depletion, depreciation and amortization	43,211			26,922			16,289			82,556			52,023			30,533
Accretion of discount	197			166			31			367			263			104
General and administrative	6,537			7,325			(788		)	11,798			11,637			161
Total costs and expenses	67,688			44,275			23,413			130,060			81,708			48,352
Operating income	38,702			20,251			18,451			74,574			38,298			36,276
Other income (expenses):
Interest expense	(14,767		)	(8,092		)	(6,675		)	(22,810		)	(16,279		)	(6,531		)
Net gain (loss) on commodity derivatives	(33,698		)	36,555			(70,253		)	(50,948		)	25,172			(76,120		)
Gain on sales of assets	1			(45		)	46			67			25			42
Total other income (expense)	(48,464		)	28,418			(76,882		)	(73,691		)	8,918			(82,609		)
Income before income tax	(9,762		)	48,669			(58,431		)	883			47,216			(46,333		)
Income tax provision	(578		)	252			(830		)	679			251			428
Net income (loss)	(9,184		)	48,417			(57,601		)	204			46,965			(46,761		)
Net income (loss) attributable to non-controlling interests	(7,537		)	—			(7,537		)	178			—			178
Net income (loss) attributable to controlling interests	$	(1,647	)	$	48,417		$	(50,064	)	$	26		$	46,965		$	(46,939	)

Net production volumes:
Oil (MBbls)	655			413			242			1,230			725			505
Natural gas (MMcf)	5,550			4,138			1,412			10,559			8,404			2,155
NGLs (MBbls)	566			419			147			1,089			825			264
Total (MBoe)	2,146			1,522			624			4,079			2,951			1,128
Average net (Boe/d)	23,582			16,725			6,857			22,536			16,304			6,232
Average sales price, unhedged:
Oil (per Bbl), unhedged	$	98.51		$	88.80		$	9.71		$	96.30		$	88.62		$	7.68
Natural gas (per Mcf), unhedged	4.20			3.60			0.60			4.23			3.29			0.94
NGLs (per Bbl), unhedged	31.76			30.37			1.39			37.22			33.48			3.74
Combined (per Boe) realized, unhedged	49.30			42.25			7.05			49.93			40.51			9.42
Average sales price, hedged:
Oil (per Bbl), hedged	$	89.97		$	86.75		$	3.22		$	88.85		$	86.54		$	2.31
Natural gas (per Mcf), hedged	4.31			4.11			0.20			4.19			4.06			0.13
NGLs (per Bbl), hedged	29.99			30.58			(0.59		)	34.20			33.59			0.61
Combined (per Boe) realized, hedged	46.51			43.12			3.39			46.77			42.21			4.56
Average costs (per Boe):
Lease operating	$	5.77		$	4.07		$	1.70		$	5.49		$	3.91		$	1.58
Production taxes	2.41			2.09			0.32			2.44			1.91			0.53
Depletion, depreciation and amortization	20.14			17.69			2.45			20.24			17.63			2.61
General and administrative	3.05			4.81			(1.76		)	2.89			3.94			(1.05		)

Non-GAAP financial measure

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.

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We define EBITDAX as earnings before interest expense, income taxes, depreciation, depletion and amortization, exploration expense, gains and losses from derivatives less the current period settlements of matured derivative contracts and the other items described below; however, we may modify our definition of EBITDAX in the future. EBITDAX is not a measure of net income as determined by United States generally accepted accounting principles, or GAAP. Management believes 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 EBITDAX because these amounts can vary substantially from company to company within our industry depending upon accounting methods and book values of assets, capital structures and the method by which the assets were acquired. 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 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 EBITDAX should not be construed as an inference that our results will be unaffected by unusual or non-recurring items. Our computations of 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 EBITDAX for the periods indicated:

	Three Months Ended June 30,						Six Months Ended June 30,
(in thousands of dollars)	2014			2013			2014			2013

Reconciliation of EBITDAX to net income
Net income (loss)	$	(9,184	)	$	48,417		$	204		$	46,965
Interest expense (excluding amortization of deferred financing costs)	10,184			7,428			17,528			14,952
Exploration expense	191			479			3,012			605
Income taxes	(578		)	240			679			217
Amortization of deferred financing costs	4,583			664			5,282			1,327
Depreciation and depletion	43,211			26,922			82,556			52,023
Accretion expense	197			166			367			263
Other non-cash charges (benefits)	(26		)	145			40			310
Stock compensation expense	929			352			1,386			473
Other non-cash compensation expense	127			2,465			253			2,465
Net loss (gain) on commodity derivatives	33,698			(36,555		)	50,948			(25,172		)
Current period settlements of matured derivative contracts	(5,985		)	2,457			(12,895		)	6,205
Amortization of deferred revenue	(282		)	—			(526		)	—
Loss (gain) on sales of assets	(1		)	45			(67		)	(25		)
EBITDAX	$	77,064		$	53,225		$	148,767		$	100,608

Adjusted net income and adjusted earnings per share are supplemental non-GAAP financial measures that are used by management and external users of the Company’s consolidated financial statements.

We define adjusted net income as net income excluding the impact of certain non-cash items including gains or losses on commodity derivative instruments not yet settled, impairment of oil and gas properties, non-cash compensation expense, and, specifically, in the second quarter of 2014, the write off of the net unamortized portion of capitalized loan costs that were associated with our Term Loan, which was paid off with the proceeds from the issuance of our 2022 Notes, which we consider to be a non-recurring event. We define adjusted earnings per share as adjusted net income divided by the weighted average shares outstanding. We believe adjusted net income and adjusted earnings per share is useful to investors because it provides readers with a more meaningful measure of our profitability before recording certain items for which the timing or amount cannot be reasonably determined. However, this measure is provided in addition to, not as an alternative for, and should be read in conjunction with, the information contained in our financial statements prepared in accordance with GAAP. Our computations of adjusted net income and adjusted earnings per share may not be comparable to other similarly titled measures of other companies. The following tables provide a reconciliation of net income (loss) as determined in accordance with GAAP to adjusted net income for the three and six months ended June 30, 2014 and 2013, respectively.

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	Three Months Ended June 30,						Six Months Ended June 30,
(in thousands of dollars except per share data)	2014			2013			2014			2013

Net income (loss)	$	(9,184	)	$	48,417		$	204		$	46,965
Net loss (gain) on commodity derivatives	33,698			(36,555		)	50,948			(25,172		)
Current period settlements of matured derivative contracts	(5,985		)	2,457			(12,895		)	6,205
Non-cash stock compensation expense	929			352			1,386			473
Other non-cash compensation expense	127			2,465			253			2,465
Net unamortized capitalized loan costs associated with Term Loan	3,761			—			3,761			—
Tax impact(1)	(2,888		)	—			(3,908		)	—
Adjusted net income	20,458			$	17,136		39,749			$	30,936

Adjusted net income attributable to non-controlling interests	16,727						32,545
Adjusted net income attributable to controlling interests	$	3,731					$	7,204

	Three Months Ended June 30,			Six Months Ended June 30,
	2014			2014

Earnings per share (basic and diluted)	$	(0.13	)	$	—
Net loss on commodity derivatives	0.68			1.03
Current period settlements of matured derivative contracts	(0.12		)	(0.26		)
Non-cash stock compensation expense	0.02			0.03
Other non-cash compensation expense	—			0.01
Net unamortized capitalized loan costs associated with Term Loan	0.08			0.08
Tax impact	(0.23		)	(0.31		)
Adjusted earnings per share (basic and diluted)	$	0.30		$	0.58

Effective tax rate on net income attributable to controlling interests	36.4		%	36.4		%

(1) In arriving at adjusted net income, the tax impact of the adjustments to net income is determined by applying the appropriate tax rate to each adjustment and then allocating the tax impact between the controlling and non-controlling interests.

Results of Operations - Three months ended June 30, 2014 as compared to three months ended June 30, 2013

Oil and gas sales. Oil and gas sales increased $41.5 million, or 64.5%, to $105.8 million for the three months ended June 30, 2014, as compared to $64.3 million for the three months ended June 30, 2013. The increase is attributable to increases in production and prices for all three products. Average daily production increased 41.0% to 23,582 Boe per day for the three months ended June 30, 2014 from 16,725 Boe per day for the three months ended June 30, 2013 with the main driver being an increase in crude oil production, which specifically accounted for 57.5% of the total increase in oil and gas sales. We produced 655,000 barrels of crude oil during the three months ended June 30, 2014 as compared to 413,000 barrels of crude oil during the three months ended June 30, 2013, an increase of 58.6%. The overall increase in production is a result of increased drilling (ten rigs as of June 30, 2014 versus six rigs as of June 30, 2013) and the acquisition of 92 producing Sabine wells. The increase in oil production is attributable to an increased focus on drilling oil-based wells. In addition, both natural gas and NGLs experienced production increases of more than 30%. Average prices for all three products increased in the three months ended June 30, 2014 as compared to the three months ended June 30, 2013. The average realized price of crude oil, natural gas and natural gas liquids, excluding the effects of derivatives, increased from $88.80 to $98.51, $3.60 to $4.20, and $30.37 to $31.76, respectively, for the three months ended June 30, 2014 as compared to the three months ended June 30, 2013.

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Costs and expenses

Lease operating. Lease operating expenses increased $6.2 million, or 100.0%, to $12.4 million for the three months ended June 30, 2014, as compared to $6.2 million for the three months ended June 30, 2013. The increase in lease operating expenses is partially attributable to the 41.0% increase in production volumes discussed above. Of the total, non-recurring expenses increased from $1.4 million for the three months ended June 30, 2013 to $2.2 million for the three months ended June 30, 2014 as a result of remediation work performed on wells taken off line in connection with nearby fracks. On a per unit basis, lease operating expenses increased $1.70, or 41.8%, from $4.07 in second quarter of 2013 to $5.77 in the second quarter of 2014. $0.35 of the per unit variance can be specifically attributed to an increase in ad valorem taxes which is attributable to the increase in the number of producing wells from new drilling, primarily in Texas, and the properties acquired from Sabine. Operating expenses incurred on non-operated properties accounted for an additional $0.29 of the per unit increase. The remainder of the increase is attributable to increases in certain types of expenses such as compressors, chemicals and salt water disposal costs that are characteristic of the types of wells we have been drilling.

Production taxes. Production taxes increased by $2.0 million, or 62.5%, to $5.2 million for the three months ended June 30, 2014, as compared to $3.2 million for the three months ended June 30, 2013. Overall, production taxes increased in conjunction with the 64.5% increase in oil and gas sales. The average production tax rate was 4.9% in both quarters with our drilling focused in areas characterized by the same production tax regulations.

Depreciation, depletion and amortization. Depreciation, depletion and amortization increased by $16.2 million, or 60.0%, to $43.2 million for the three months ended June 30, 2014, as compared to $27.0 million for the three months ended June 30, 2013. Depreciation, depletion and amortization increased from $17.69 per Boe in the second quarter of 2013 to $20.14 per Boe in the second quarter of 2014, or an increase of 13.8%. The increase was primarily the result of continued drilling activity and the addition of the Sabine properties at the end of 2013, which increased our total depreciable basis.

General and administrative. General and administrative expenses decreased by $0.8 million, or 11.0%, to $6.5 million for the three months ended June 30, 2014, as compared to $7.3 million for the three months ended June 30, 2013. In the second quarter of 2013, we recognized a $2.5 million one-time management distribution related to the Monarch incentive plan. Excluding this one-time, non-cash event, general and administrative expenses increased by $1.6 million, or 32.7%, for the three months ended June 30, 2014 as compared to the three months ended June 30, 2013. Of the $1.6 million, $0.6 million was attributable to increases in other stock compensation expense resulting from the new long term incentive plan implemented in the second quarter of 2014. The remaining increases are attributable to overall growth of the company with the most significant increases related to higher salaries and benefits resulting from an increase in headcount. Excluding the aforementioned non-cash expenses, general and administrative expense decreased, on a per unit basis, from $2.96 per Boe for the three months ended June 30, 2013 to $2.53 for the three months ended June 30, 2014. The increase in activity resulting from our increased drilling program, combined with the acquisition of the Sabine properties, increased production without a proportionate increase in general and administrative expenses.

Interest expense. Interest expense increased by $6.7 million, or 82.7%, to $14.8 million for the three months ended June 30, 2014 as compared to $8.1 million for the three months ended June 30, 2013. The increase is primarily attributable to increased borrowings and the addition of the 2022 Notes which were issued on April 1, 2014.

Net loss on commodity derivatives. Our commodity derivatives decreased from a net gain of $36.6 million during the three months ended June 30, 2013 to a net loss of $33.7 million during the three months ended June 30, 2014. The variance was driven by higher average crude oil and natural gas prices ($102.99 and $4.67 respectively) for the second quarter of 2014, as compared to the average crude oil and natural gas prices ($94.22 and $4.09, respectively) for the second quarter of 2013, combined with higher average futures prices as of June 30, 2014 as compared to June 30, 2013 for both commodities.

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Results of Operations - Six months ended June 30, 2014 as compared to six months ended June 30, 2013

Oil and gas sales. Oil and gas sales increased $84.1 million, or 70.3%, to $203.7 million for the six months ended June 30, 2014, as compared to $119.6 million for the six months ended June 30, 2013. The increase is attributable to increases in production and prices for all three products. Average daily production increased 38.2% to 22,536 Boe per day for the six months ended June 30, 2014 from 16,304 Boe per day for the six months ended June 30, 2013 with the main driver being an increase in crude oil production, which specifically accounted for 61.6% of the total increase in oil and gas sales. We produced 1.2 million barrels of crude oil during the six months ended June 30, 2014 as compared to 725,000 barrels of crude oil during the six months ended June 30, 2013, an increase of 69.7%. The overall increase in production is a result of increased drilling (ten rigs as of June 30, 2014 versus six rigs as of June 30, 2013) and the acquisition of 92 producing Sabine wells. The increase in oil production is attributable to an increased focus on drilling oil-based wells. In addition, both natural gas and NGLs experienced production increases of more than 25%. Average prices for all three products increased in the six months ended June 30, 2014 as compared to the six months ended June 30, 2013. The average realized price of crude oil, natural gas and natural gas liquids, excluding the effects of derivatives, increased from $88.62 to $96.30, $3.29 to $4.23, and $33.48 to $37.22, respectively, for the three months ended June 30, 2014 as compared to the three months ended June 30, 2013.

Costs and expenses

Lease operating. Lease operating expenses increased $10.9 million, or 94.8% to $22.4 million for the six months ended June 30, 2014, as compared to $11.5 million for the six months ended June 30, 2013. The increase in lease operating is partially attributable to the 38.2% increase in production volumes discussed above. On a per unit basis, lease operating expenses increased $1.58, or 40.4%, from $3.91 in the first half of 2013 to $5.49 in the second half of 2014. Of the total lease operating expenses, non-recurring expenses increased from $2.0 million for the six months ended June 30, 2013 to $4.0 million for the six months ended June 30, 2014 as a result of remediation work performed on wells taken off line in connection with nearby fracks, which accounts for approximately $0.28 of the per unit increase. An additional $0.37 of the per unit variance can be specifically attributed to an increase in ad valorem taxes which is due to the increase in the number of producing wells from new drilling, primarily in Texas, and the properties acquired from Sabine. Operating expenses incurred on non-operated properties accounted for an additional $0.26 of the per unit increase. The remainder of the increase is explained through increases in certain types of expenses such as compressors, chemicals and salt water disposal costs that are characteristic of the types of wells we have been drilling.

Production taxes. Production taxes increased by $4.3 million, or 76.8%, to $9.9 million for the six months ended June 30, 2014, as compared to $5.6 million for the six months ended June 30, 2013. Overall, production taxes increased in conjunction with the 70.3% increase in oil and gas sales. The average production tax rate for the six months ended June 30, 2014 was 4.9% as compared to 4.7% for the six months ended June 30, 2013. During the first half of 2013 we started to shift our focus on drilling Cleveland properties in Texas, as opposed to drilling wells in Oklahoma. Texas imposes a higher initial tax rate than Oklahoma, and as a result we saw an increase in our average production tax rate for the period.

Depreciation, depletion and amortization. Depreciation, depletion and amortization increased by $30.6 million, or 58.8%, to $82.6 million for the six months ended June 30, 2014, as compared to $52.0 million for the six months ended June 30, 2013. Depreciation, depletion and amortization increased from $17.63 per Boe in the first half of 2013 to $20.24 per Boe in the first half of 2014, or an increase of 14.8%. The increase was primarily the result of continued drilling activity and the addition of the Sabine properties at the end of 2013, which increased our total depreciable basis.

General and administrative. General and administrative expenses increased by $0.2 million, or 1.7%, to $11.8 million for the six months ended June 30, 2014, as compared to $11.6 million for the six months ended June 30, 2013. Non-cash compensation expense decreased by $1.3 million as there was a $2.5 million one-time management distribution related to the Monarch incentive plan during the second quarter of 2013, which was offset by increases in other non-cash stock compensation expense for the six months ended June 30, 2014 related to the new long term incentive plans. The decrease in non-cash items was offset by increases in other general administrative expenses that is attributable to the overall growth of the company and increase in headcount. These include increases to payroll and benefits, travel, office expenses, and corporate insurance. Excluding the aforementioned non-cash expenses,

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general and administrative expense decreased, on a per unit basis, from $2.95 per Boe for the six months ended June 30, 2013 to $2.48 for the six months ended June 30, 2014. The increase in activity resulting from our increased drilling program, combined with the acquisition of the Sabine properties, increased production without a proportionate increase in general and administrative expenses.

Interest expense. Interest expense increased by $6.5 million, or 39.9%, to $22.8 million for the six months ended June 30, 2014 as compared to $16.3 million for the six months ended June 30, 2013. The increase is primarily attributable to increased borrowings and the addition of the 2022 Notes which were issued on April 1, 2014.

Net loss on commodity derivatives. Our commodity derivatives decreased from a net gain of $25.2 million during the six months ended June 30, 2013 to a net loss of $50.9 million during the six months ended June 30, 2014. The variance was driven by higher average crude oil and natural gas prices ($98.68 and $4.80 respectively) for the first half of 2014, as compared to the average crude oil and natural gas prices ($94.30 and $3.71, respectively) for the first half of 2013, combined with higher average futures prices as of June 30, 2014 as compared to June 30, 2013 for both commodities.

Liquidity and Capital Resources

Historically, our primary sources of liquidity have been private and public sales of our equity and debt, borrowings under bank credit facilities and cash flows from operations. Our primary use of capital has been 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 equity and debt financings, are available to meet our future financial obligations, planned capital expenditure activities and liquidity requirements. Our future ability to grow proved reserves and production will be highly dependent on the capital resources available to us. We strive to maintain financial flexibility in order to maintain substantial borrowing capacity under our Revolver, facilitate drilling on our undeveloped acreage positions and permit us to selectively expand our acreage positions. Depending on the timing and concentration of the development of our non-proved locations, we may be required to generate or raise significant amounts of capital to develop all of our potential drilling locations should we endeavor to do so. 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. Our balance sheet at June 30, 2014 reflects a working capital deficit as we use the available balance of the borrowing base under our Revolver to manage cash flow.

On April 1, 2014, we issued $500 million aggregate principal amount of our 6.75% senior unsecured notes due 2022 at an offering price equal to 100% of par. We received net proceeds of approximately $489 million, of which $160 million was used to repay all of the outstanding borrowings under our Term Loan, with the remaining proceeds used to pay down borrowings under our Revolver. We subsequently terminated the Term Loan in accordance with its terms. For additional information regarding the terms of the 2022 Notes, see Note 6 to the Consolidated Financial Statements appearing in Part I, Item 1 of this Quarterly Report on Form 10-Q. Following, the repayment on the Revolver, we have approximately $300 million of available borrowing capacity, which significantly enhances our liquidity and working capital.

Our capital budget is primarily focused on the development of existing core areas in the Cleveland and Woodford plays through exploitation and development. The amount of capital we expend may fluctuate materially based on market conditions, the economic returns being realized and the success of our drilling results.

The amount, timing and allocation of capital expenditures are largely discretionary and within management’s control. If oil and gas prices decline to levels below our acceptable levels, or costs increase to levels above our acceptable levels, we may choose to defer a portion of our budgeted capital expenditures until later periods in order to achieve the desired balance between sources and uses of liquidity and prioritize capital projects that we believe have the highest expected returns and potential to generate near-term cash flow. We may also increase our capital expenditures significantly to take advantage of opportunities we consider to be attractive. We consistently monitor and adjust our projected capital expenditures in response to success or lack of success in drilling activities, changes in prices, availability of financing, drilling and acquisition costs, industry conditions, the timing of regulatory approvals, the availability of rigs, contractual obligations, internally generated cash flow and other factors both within and outside our control.

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The following table summarizes our cash flows for the six months ended June 30, 2014 and 2013:

	Six Months Ended June 30,
(in thousands of dollars)	2014			2013

Net cash provided by operating activities	$	155,307		$	66,810
Net cash used in investing activities	(227,780		)	(56,145		)
Net cash provided by (used in) financing activities	80,444			(5,025		)
Net increase in cash	$	7,971		$	5,640

Cash flow provided by operating activities

Net cash provided by operating activities was $155.3 million during the six months ended June 30, 2014 as compared to net cash provided by operating activities of $66.8 million during the six months ended June 30, 2013. The increase in operating cash flows was primarily due to the $84.1 million increase in oil and gas revenues during the six months ended June 30, 2014 as compared to the six months ended June 30, 2013, driven by a 38.2% increase in production between the two periods and increases in prices for all products. The increase in revenues was offset by increases in operating expenses and production taxes which were also driven by the increase in production.

Cash flow used in investing activities

Net cash used in investing activities was $227.8 million during the six months ended June 30, 2014 as compared to net cash used in investing activities of $56.1 million during the six months ended June 30, 2013. The increase was primarily driven by an increase in capital expenditures resulting from our increased drilling program from six rigs at June 30, 2013 to ten rigs at June 30, 2014.

Cash flow used in or provided by financing activities

Net cash provided by financing activities was $80.4 million during the six months ended June 30, 2014 as compared to net cash used in financing activities of $5.0 million during the three months ended June 30, 2013. We recorded net proceeds of $489 million from the issuance of the Senior Notes, net of costs, in the second quarter of 2014, which was offset by net repayments of $408 million on the Revolver and Term Loan.

Contractual Obligations

There have been no material changes in our contractual obligations as reported in our Annual Report on Form 10-K for the year ended December 31, 2013.

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 our Annual Report.

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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 our Annual Report on Form 10-K for the year ended December 31, 2013, 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, 2014 was a net liability of $14.7 million.

As of June 30, 2014, we have hedged approximately 35% of our total forecasted production from proved reserves through 2018.

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 our Revolver with investment grade ratings. We are not permitted under the terms of the Revolver to enter into derivative instruments with counterparties outside of the banks who are lenders under the Revolver. As a result, any future derivative instruments will be with these or other lenders under the Revolver 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 Revolver provide for interest on borrowings at a floating rate equal to prime, LIBOR or federal funds rate plus margins ranging from 0.50% to 2.50% on the Revolver depending on the base rate used and the amount of the loan outstanding in relation to the borrowing base.

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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. In previous years, 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. We have strengthened the accounting group, both in number and in caliber of personnel. 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 have designed but not fully implemented new processes and controls to remediate the material weakness identified. There have been no changes in internal control over financial reporting during the quarter ended June 30, 2014 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

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, 2014.

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 Annual Report on Form 10-K for the year ended December 31, 2013 did 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 9 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

Our business faces many risks. Any of the risks discussed elsewhere in this Form 10-Q and our other SEC filings, including our Annual Report on Form 10-K for the year ended December 31, 2013, could have a material impact on our business, financial position or results of operations. Additional risks and uncertainties not presently known to us or that we currently believe to be immaterial may also impair our business operations.

With the exception of the following risk factor, there have been no material changes in our risk factors from those described in our Annual Report. For a discussion of our potential risks and uncertainties, see the information in Item 1A. “Risk Factors” in our Annual Report.

The presence of endangered or threatened species may force us to modify or terminate our operations in certain areas. Additionally, the designation of previously unidentified endangered or threatened species could cause us to incur additional costs or limit future development activity in the affected areas.

We conduct operations in areas where certain species that are listed as threatened or endangered under the Endangered Species Act, or ESA, may be present. For example, our operations in Oklahoma overlap with the range of the American Burying Beetle, which is listed as endangered. The presence of endangered or threatened species may force us to modify or terminate our operations in certain areas. Additionally, the designation of previously unidentified endangered or threatened species could cause us to incur additional costs or limit future development activity in the affected areas. For example, after lengthy consideration, the U.S. Fish and Wildlife Service determined to list the Lesser Prairie Chicken as a threatened species under the Endangered Species Act on March 27, 2014. In a special rule released simultaneously with the decision to list the Lesser Prairie Chicken as threatened, the Fish and Wildlife Service will exempt from “take” certain oil and gas and other activities conducted by a participant that result in an “incidental take” of the Lesser Prairie Chicken as long as the participant is enrolled in, and operating in compliance with, a range wide conservation plan developed by the Western Association of Fish & Wildlife Agencies endorsed by the Fish and Wildlife Service. The rules become effective on May 12, 2014. The rules are subject to separate ongoing legal challenges filed by states, industry groups, and environmental organizations that alternatively seek to overturn the listing of the Lesser Prairie Chicken altogether or to compel a more restrictive listing as endangered, rather than threatened. Environmental groups have also challenged the special rule exempting “incidental takes” for participants enrolled in the range wide conservation plan. To mitigate the risk of liability from “incidental takes” of the Lesser Prairie Chicken, we have enrolled our affected leasehold interest in a Candidate Conservation Agreement with Assurances plan through the Fish and Wildlife Service. Environmental groups have indicated their intent to challenge this Candidate Conservation Agreement with Assurances in federal court. We are continuing to evaluate the impact of these rules and legal challenges on our operations. As with any other species in areas that we operate, the listing of the Lesser Prairie Chicken under the Endangered Species Act could force us to incur additional costs and delay or otherwise limit or terminate our operations.

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

The following table reflects the Company’s repurchase of its Class A common stock for the three months ended June 30, 2014:

	Total Number of Shares Purchased		Average Price Paid Per Share		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs (1)	Aggregate Dollar Value of Shares Purchased		Approximate Dollar Value That May Yet Be Purchased Under Plans or Programs (1)
April 1, 2014 - April 30, 2014	16,233	(2)	$	15.31	16,233	$	248,527	$	751,473
May 1, 2014 - May 31, 2014	6,065	(2)	$	17.06	6,065	$	103,469	$	648,004
June 1, 2014 – June 30, 2014	—		—		—	—		—
Total purchases during the quarter ended June 30, 2014	22,298		—		22,298	$	351,996	$	648,004

(1) On April 28, 2014, the Board of Directors authorized the Company to repurchase up to $1,000,000 of its Class A common stock from certain employees of the Company (the “Electing Employees”) to permit the payment of certain tax withholding obligations.

(2) On April 30, 2014 and May 27, 2014, the Company issued an aggregate of 16,233 and 6,065 shares of Class A common stock, respectively, to Electing Employees in exchange for an equivalent number of membership interests in Jones Energy Holdings, LLC (the “JEH LLC Units”) and shares of Class B common stock held by such Electing Employees. This exchange (the “Exchange”) was made pursuant to and in accordance with the Exchange Agreement, dated July 29, 2013, included as Exhibit 10.3 to the Issuer’s Current Report on Form 8-K filed July 30, 2013. Immediately following the Exchange, the shares of Class A common stock were purchased by the Company from the Electing Employees for cash at a purchase price equal to $15.31 and $17.06, respectively (the closing price per share of Class A common stock on the New York Stock Exchange on April 28, 2014 and May 23, 2014, respectively). These shares were previously reported as being beneficially owned by Jonny Jones solely as a result of his status as a member of JRJ Management Company, LLC, as the manager of Jones Energy Management, LLC and as the trustee of the managing member of JET 3 GP, LLC, which are the general partners of the entities that held these shares prior to the Exchange. However, the purchase of the Class A common stock by the Company from the Electing Employees and any future purchases of Class A common stock pursuant to the repurchase plan is for the sole benefit of the Company and the Electing Employees and no proceeds will go to Jonny Jones or any other director or executive officer of the Company other than the Electing Employees. The Exchange was exempt from registration pursuant to Section 4(2) of the Securities Act of 1933, as amended.

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
10.1		Indenture, dated April 1, 2014, among Jones Energy Holdings, LLC, Jones Energy Finance Corp., the Guarantors named therein and Wells Fargo Bank, National Association, as trustee (incorporated by reference herein to Exhibit 4.1 to the Form 8-K filed by the registrant on April 1, 2014).
10.2		Registration Rights Agreement, dated April 1, 2014, among Jones Energy Holdings, LLC, Jones Energy Finance Corp., the Guarantors named therein and Citigroup Global Markets Inc., as the sole representative of the Initial Purchasers named therein (incorporated by reference herein to Exhibit 4.2 to the Form 8-K filed by the registrant on April 1, 2014).
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: August 8, 2014	By:	/s/ Jonny Jones
		Name:	Jonny Jones
		Title:	Chief Executive Officer

Signature Page to Form 10-Q (Q2 2014)

Jones Energy, Inc. - FORM 10-Q - August 8, 2014

Attached files

Jones Energy, Inc. Reports