8-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 8-K

CURRENT REPORT

Pursuant to Section 13 or 15(d)

of the Securities Exchange Act of 1934

Date of Report (date of earliest event reported):  February 5, 2015 (February 5, 2015)

Jones Energy, Inc.

(Exact name of registrant as specified in its charter)

Delaware	001-36006	80-0907968
(State or Other Jurisdiction of Incorporation or Organization)	(Commission File Number)	(I.R.S. Employer Identification No.)

807 Las Cimas Parkway, Suite 350 Austin, Texas	78746
(Address of Principal Executive Offices)	(Zip Code)

Registrant’s telephone number, including area code:  (512) 328-2953

Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions:

o Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)

o Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)

o Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))

o Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))

Item 8.01.             Other Events.

Jones Energy Holdings, LLC (“JEH”) and Jones Energy Finance Corp. (“JEFC” and, together with JEH, the “Issuers”), both subsidiaries of Jones Energy, Inc. (the “Company”), will be filing a registration statement on Form S-4, which incorporates by reference the contents of this Current Report on Form 8-K. The Company and JEH’s material subsidiaries (the “Subsidiary Guarantors” and, together with the Company, the “Guarantors”) will be co-registrants with the Issuers, and the registration statement will register a guarantee of debt securities by the Guarantors. At such time, the Guarantors will become subject to the requirements of Rule 3-10 of Regulation S-X regarding financial statements of guarantors and issuers of guaranteed securities registered or being registered.

This Current Report on Form 8-K was prepared to amend the Company’s audited financial statements as of December 31, 2013 and 2012 and for each of the years in the three year period ending December 31, 2013 to include Note 13, providing the condensed consolidating financial information as required by Rule 3-10 of Regulation S-X.

The Company has not otherwise updated the financial information for activities or events occurring after the date this information was originally presented in the Company’s Form 10-K for the year ended December 31, 2013.

Item 9.01. Financial Statements and Exhibits.

(d) Exhibits

EXHIBIT NUMBER	DESCRIPTION
23.1	Consent of Pricewaterhouse Coopers LLP.
99.1	Financial statements of Jones Energy, Inc. and subsidiaries as of December 31, 2013 and 2012, and for each of the years in the three-year period ended December 31, 2013.
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.

2

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 hereunto duly authorized.

			JONES ENERGY, INC.
Date: February 5, 2015	By:	/s/ Robert J. Brooks
		Robert J. Brooks
		Executive Vice President and Chief Financial Officer

3

INDEX TO EXHIBITS

EXHIBIT NUMBER	DESCRIPTION
23.1	Consent of Pricewaterhouse Coopers LLP.
99.1	Financial statements of Jones Energy, Inc. and subsidiaries as of December 31, 2013 and 2012, and for each of the years in the three-year period ended December 31, 2013.
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.

4

EX-23.1

Exhibit 23.1

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We hereby consent to the incorporation by reference in the Registration Statements on Form S-3 (No. 333-197809) and on Form S-8 (No. 333-190471) of Jones Energy, Inc. of our report dated March 14, 2014, except with respect to our opinion on the consolidated financial statements insofar as it relates to the condensed consolidated financial information discussed in Note 13, as to which the date is February 5, 2015, relating to the consolidated financial statements, which appears in this Current Report on Form 8-K of Jones Energy, Inc. dated February 5, 2015.

/s/ PricewaterhouseCoopers LLP

Houston, Texas

February 5, 2015

EX-99.1

Exhibit 99.1

Report of Independent Registered Public Accounting Firm

To the Board of Directors and Stockholders of Jones Energy, Inc.:

In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of operations, changes in stockholders’ / members’ equity, and cash flows present fairly, in all material respects, the financial position of Jones Energy, Inc. and its subsidiaries at December 31, 2013 and 2012, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2013 in conformity with accounting principles generally accepted in the United States of America.  These financial statements are the responsibility of the Company’s management.  Our responsibility is to express an opinion on these financial statements based on our audits.  We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States).  Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement.  An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation.  We believe that our audits provide a reasonable basis for our opinion.

/s/ PricewaterhouseCoopers LLP

Houston, Texas

March 14, 2014, except with respect to our opinion on the consolidated financial statements insofar as it relates to the condensed consolidated financial information discussed in Note 13, as to which the date is February 5, 2015

F-1

Jones Energy, Inc

Consolidated Balance Sheets

December 31, 2013 and 2012

(in thousands of dollars)	December 31, 2013			December 31, 2012
Assets
Current assets
Cash	$	23,820		$	23,726
Restricted Cash	45			—
Accounts receivable, net
Oil and gas sales	51,233			29,684
Joint interest owners	42,481			21,876
Other	1,459			4,590
Commodity derivative assets	8,837			17,648
Other current assets	2,392			1,088
Deferred tax assets	12			—
Total current assets	130,279			98,612
Oil and gas properties, net, at cost under the successful efforts method	1,312,551			1,007,344
Other property, plant and equipment, net	3,444			3,398
Commodity derivative assets	25,398			25,199
Other assets	15,006			16,133
Deferred tax assets	1,301			—
Total assets	$	1,487,979		$	1,150,686
Liabilities and Stockholders’ / Members’ Equity
Current liabilities
Trade accounts payable	$	89,430		$	38,036
Oil and gas sales payable	66,179			45,860
Accrued liabilities	10,805			5,255
Commodity derivative liabilities	10,664			4,035
Deferred tax liabilities	—			61
Asset retirement obligations	2,590			174
Total current liabilities	179,668			93,421
Long-term debt	658,000			610,000
Deferred revenue	14,531			—
Commodity derivative liabilities	190			7,657
Asset retirement obligations	8,373			9,332
Deferred tax liabilities	3,093			1,876
Total liabilities	863,855			722,286
Commitments and contingencies (Note 10)
Stockholders’ / members’ equity
Members’ equity	—			428,400
Class A common stock, $0.001 par value; 12,526,580 shares issued and outstanding	13			—
Class B common stock, $0.001 par value; 36,836,333 shares issued and outstanding	37			—
Additional paid-in-capital	173,169			—
Retained earnings (deficit)	(2,186		)	—
Stockholders’ / members’ equity	171,033			428,400
Non-controlling interest	453,091			—
Total stockholders’ / members’ equity	624,124			428,400
Total liabilities and stockholders’ / members’ equity	$	1,487,979		$	1,150,686

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

F-2

Jones Energy, Inc.

Consolidated Statements of Operations

Years Ended December 31, 2013, 2012 and 2011

	Year Ended December 31,
(in thousands except per share data)	2013			2012			2011
Operating revenues
Oil and gas sales	$	258,063		$	148,967		$	167,261
Other revenues	1,106			847			1,022
Total operating revenues	259,169			149,814			168,283
Operating costs and expenses
Lease operating	27,781			23,097			21,548
Production taxes	12,865			5,583			5,333
Exploration	1,710			356			780
Depletion, depreciation and amortization	114,136			80,709			68,906
Impairment of oil and gas properties	14,415			18,821			31,970
Accretion of discount	608			533			413
General and administrative (including non-cash compensation expense)	31,902			15,875			16,679
Total operating expenses	203,417			144,974			145,629
Operating income	55,752			4,840			22,654
Other income (expense)
Interest expense	(30,774		)	(25,292		)	(21,994		)
Net gain (loss) on commodity derivatives	(2,566		)	16,684			34,490
Gain on bargain purchase	—			—			26,208
Gain (loss) on sales of assets	(78		)	1,162			(859		)
Other income (expense), net	(33,418		)	(7,446		)	37,845
Income (loss) before income tax	22,334			(2,606		)	60,499
Income tax provision
Current	85			—			—
Deferred	(156		)	473			173
Total income tax provision	(71		)	473			173
Net income (loss)	22,405			(3,079		)	60,326
Net income attributable to non-controlling interests	24,591			—			—
Net income (loss) attributable to controlling interests	$	(2,186	)	$	(3,079	)	$	60,326
Earnings per share:
Basic and diluted	$	(0.17	)
Weighted average shares outstanding:
Basic and diluted	12,500

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

F-3

Jones Energy, Inc.

Statement of Changes in Stockholders’ / Members’ Equity

Years Ended December 31, 2013, 2012 and 2011

	Common Stock									Additional								Total
	Class A			Class B			Members’			Paid-in-		Retained			Non-controlling			Stockholders’ /
(amounts in thousands)	Shares	Value		Shares	Value		Equity			Capital		Deficit			Interest			Members’ Equity
Balance at December 31, 2010	—	$	—	—	$	—	$	284,449		$	—	$	—		$	—		$	284,449
Stock-compensation expense	—	—		—	—		1,134			—		—			—			1,134
Net income	—	—		—	—		60,326			—		—			—			60,326
Balance at December 31, 2011	—	—		—	—		345,909			—		—			—			345,909
Issuance of Class C preferred units	—	—		—	—		85,000			—		—			—			85,000
Stock-compensation expense	—	—		—	—		570			—		—			—			570
Net income (loss)	—	—		—	—		(3,079		)									(3,079		)
Balance at December 31, 2012	—	—		—	—		428,400			—		—			—			428,400
Issuance of common stock	12,500	13		36,836	37		—			—		—			—			50
Proceeds from the sale of common stock	—	—		—	—		—			172,431		—			—			172,431
Reclassification of members’ contributions	—	—		—	—		(464,037		)	—		—			464,037			—
Stock-compensation expense	—	—		—	—		10,100			738		—			—			10,838
Distribution to members	—	—		—	—		(10,000		)	—		—			—			(10,000		)
Net income	—	—		—	—		35,537			—		(2,186		)	(10,946		)	22,405
Balance at December 31, 2013	12,500	$	13	36,836	$	37	$	—		$	173,169	$	(2,186	)	$	453,091		$	624,124

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

F-4

Jones Energy, Inc.

Consolidated Statements of Cash Flows

Years Ended December 31, 2013, 2012 and 2011

	Year Ended December 31,
(in thousands of dollars)	2013			2012			2011
Cash flows from operating activities
Net income (loss)	$	22,405		$	(3,079	)	$	60,326
Adjustments to reconcile net income (loss) to net cash provided by operating activities
Exploration expense	—			—			478
Depletion, depreciation, and amortization	114,136			80,709			68,906
Impairment of oil and gas properties	14,415			18,821			31,970
Accretion of discount	608			533			413
Amortization of debt issuance costs	2,677			3,544			2,940
Stock compensation expense	10,838			570			1,134
Other non-cash compensation expense (Note 9)	2,719			—			—
Amortization of deferred revenue	(469		)	—			—
Gain on commodity derivatives	2,566			(16,684		)	(34,490		)
Gain on bargain purchase price	—			—			(26,208		)
(Gain) loss on sales of assets	78			(1,162		)	859
Deferred income tax provision	(156		)	473			173
Other—net	79			129			(59		)
Changes in assets and liabilities
Accounts receivable	(41,481		)	11,568			(32,593		)
Other assets	163			1,873			(3,360		)
Accounts payable and accrued liabilities	35,318			(12,745		)	49,728
Net cash provided by operations	163,896			84,550			120,217
Cash flows from investing activities
Additions to oil and gas properties	(197,618		)	(125,493		)	(157,046		)
Acquisition of properties	(193,496		)	(249,007		)	(168,480		)
Proceeds from sales of assets	1,607			9,158			6,747
Acquisition of other property, plant and equipment	(1,634		)	(969		)	(1,735		)
Current period settlements of matured derivative contracts	7,586			28,675			1,551
Change in restricted cash	(45		)	—			—
Net cash used in investing	(383,600		)	(337,636		)	(318,963		)
Cash flows from financing activities
Proceeds from issuance of long-term debt	220,000			233,243			316,500
Repayment under long-term debt	(172,000		)	(38,243		)	(126,500		)
Payment of debt issuance costs	(683		)	(9,324		)	(3,678		)
Issuance of preferred units	—			85,000			—
Proceeds from sale of common stock, net of expenses of $15.1 million	172,481			—			—
Net cash provided by financing	219,798			270,676			186,322
Net increase (decrease) in cash	94			17,590			(12,424		)
Cash
Beginning of period	23,726			6,136			18,560
End of period	$	23,820		$	23,726		$	6,136
Supplemental disclosure of cash flow information
Cash paid for interest	$	25,414		$	20,759		$	18,151
Change in accrued additions to oil and gas properties	41,945			3,355			26,774
Noncash acquisition of oil and gas properties	—			2,918			—
Current additions to ARO	1,516			662			4,077
Noncash distributions to members (Note 9)	10,000			—			—

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

F-5

Jones Energy, Inc.

Notes to Consolidated Financial Statements

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. Prior to the IPO, JEH owned the controlling interest in the Company; hence all of the net income (loss) earned prior to the IPO date is reflected in the net income (loss) attributable to non-controlling interests on the Consolidated Statement of Operations for the year ended December 31, 2013.

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 is headquartered in Austin, Texas.

Revision of Previously Issued Financial Statements

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. Therefore we have revised our Consolidated Statement of Operations for the years ended December 31, 2012 and 2011 to record $0.6 million and $0.8 million, respectively of additional interest expense on obligations that are unrelated to our credit agreements discussed in Note 6. As a result, net income decreased for the years ended December 31, 2012 and 2011 by $0.6 million and $0.8 million,

F-6

Jones Energy, Inc.

Notes to Consolidated Financial Statements (Continued)

1. Organization and Description of Business (Continued)

respectively. The balance sheet impacts of the revision are increases in accrued liabilities and decreases in members’ equity of $0.6 million and $1.4 million at December 31, 2011 and 2012, respectively. These revisions had no impact on our net cash provided by operations in our Consolidated Statement of Cash Flows. We have determined that these errors are not material to our consolidated financial statements for the years ended December 31, 2012 and 2011.

2. Significant Accounting Policies

Basis of Presentation

The accompanying 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 December 31, 2013, 2012 and 2011, and the years then ended include the Company and all of its subsidiaries.

Segment Information

The Company operates in one industry segment, which is the exploration, development and production of oil and natural gas, and all of its operations are conducted in one geographic area of the United States.

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 and liabilities, fair value associated with business combinations, and asset retirement obligations (“ARO”).

Financial Instruments

Cash, accounts receivable and accounts payable are recorded at cost. The fair value of accounts receivable and accounts payable are not materially different from their carrying amounts because of the short-term nature of these instruments. The carrying values of outstanding balances under the Company’s credit agreements represent fair value because the agreements have variable interest rates, which are reflective of the Company’s credit risk. Derivative instruments are recorded at fair value, as discussed below.

Cash

Cash and cash equivalents include highly liquid investments with a maturity of three months or less. At times, the amount of cash on deposit in financial institutions exceeds federally insured limits.

F-7

Jones Energy, Inc.

Notes to Consolidated Financial Statements (Continued)

2. Significant Accounting Policies (Continued)

Management monitors the soundness of the financial institutions and believes the Company’s risk is negligible.

Accounts Receivable

Accounts receivable—Oil and gas sales consist of uncollateralized accrued revenues due under normal trade terms, generally requiring payment within 30 to 60 days of production. Accounts receivable—Joint interest owners consist of uncollateralized joint interest owner obligations due within 30 days of the invoice date. Accounts receivable—Other consist primarily of severance tax refunds due from state agencies. No interest is charged on past-due balances. The Company routinely assesses the recoverability of all material trade, joint interest and other receivables to determine their collectability, and reduces the carrying amounts by a valuation allowance that reflects management’s best estimate of the amounts that may not be collected. As of December 31, 2013 and 2012, the Company did not have significant allowances for doubtful accounts.

Concentration of Risk

Substantially all of the Company’s accounts receivable are related to the oil and gas industry. This concentration of entities may affect the Company’s overall credit risk in that these entities may be affected similarly by changes in economic and other conditions. As of December 31, 2013, 79% of Accounts receivable—Oil and gas sales are due from 8 purchasers and 77% of Accounts receivable—Joint interest owners are due from 5 working interest owners. As of December 31, 2012, 92% of Accounts receivable—Oil and gas sales were due from 8 purchasers, and 72% of 2012 Accounts receivable—Joint interest owners were due from 5 working interest owners. If any or all of these significant counterparties were to fail to pay amounts due to the Company, the Company’s financial position and results of operations could be materially and adversely affected.

Dependence on Major Customers

The Company maintains a portfolio of crude oil and natural gas marketing contracts with large, established refiners and oil and gas purchasers. During the year ended December 31, 2013, the largest purchasers were PVR Midstream, Unimark LLC, Mercuria, Valero, and Plains Marketing, which accounted for approximately 15%, 13%, 13%, 13% and 6% of consolidated oil and gas sales, respectively. During the year ended December 31, 2012, the largest purchasers were Unimark LLC, Mercuria, PVR Midstream, and Plains Marketing, which accounted for approximately 24%, 18%, 18% and 15% of consolidated oil and gas sales, respectively. During the year ended December 31, 2011, the largest purchasers were Plains Marketing, PVR Midstream, Unimark LLC, and Valero Marketing, which accounted for approximately 27%, 22%, 13% and 9% of consolidated oil and gas sales, respectively.

Management believes that there are alternative purchasers and that it may be necessary to establish relationships with such new purchasers. However, there can be no assurance that the Company can establish such relationships and that those relationships will result in an increased number of purchasers. Although the Company is exposed to a concentration of credit risk, management believes that all of the Company’s purchasers are credit worthy.

F-8

Jones Energy, Inc.

Notes to Consolidated Financial Statements (Continued)

2. Significant Accounting Policies (Continued)

Dependence on Suppliers

The Company’s industry is cyclical, and from time to time, there is a shortage of drilling rigs, equipment, services, supplies and qualified personnel. During these periods, the costs and delivery times of rigs, equipment, services and supplies are substantially greater. If the unavailability or high cost of drilling rigs, equipment, services, supplies or qualified personnel were particularly severe in its areas of operation, the Company could be materially and adversely affected. Management believes that there are potential alternative providers of drilling and completion services and that it may become necessary to establish relationships with new contractors. However, there can be no assurance that the Company can establish such relationships and that those relationships will result in increased availability of drilling rigs or other services, or that they could be obtained on the same terms.

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 December 31, 2013 and 2012:

(in thousands of dollars)	2013			2012
Mineral interests in properties
Unproved	$	114,457		$	137,254
Proved	958,816			737,558
Wells and equipment and related facilities	609,748			389,727
	1,683,021			1,264,539
Less: Accumulated depletion and impairment	(370,470		)	(257,195		)
Net oil and gas properties	$	1,312,551		$	1,007,344

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. In 2013, we had no material capitalized costs associated with exploratory wells. As of December 31, 2012, there were no costs capitalized in connection with exploratory wells in progress.

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 in 2013 as no projects lasted more than six months. During the year ended December 31, 2012, the Company capitalized $0.1 million in interest. Costs incurred to maintain wells and related equipment are charged to expense as incurred.

F-9

Jones Energy, Inc.

Notes to Consolidated Financial Statements (Continued)

2. Significant Accounting Policies (Continued)

On the sale or retirement of a proved field, the cost and related accumulated depletion, depreciation and amortization are eliminated from the field accounts, and the resultant gain or loss is recognized.

Capitalized amounts attributable to proved oil and gas properties are depleted by the unit-of-production method over proved reserves, using the unit conversion ratio of six thousand cubic feet of gas to one barrel of oil equivalent. Depletion of the costs of wells and related equipment and facilities, including capitalized asset retirement costs, net of salvage values, is computed using proved developed reserves. The reserve base used to calculate depreciation, depletion, and amortization for leasehold acquisition costs and the cost to acquire proved properties is the sum of proved developed reserves and proved undeveloped reserves. Depletion of oil and gas properties amounted to $113.3 million, $79.9 million and $68.2 million for the years ended December 31, 2013, 2012 and 2011, respectively.

The Company reviews its proved oil and natural gas properties, including related wells and equipment, for impairment by comparing expected undiscounted future cash flows at a producing field level to the net capitalized cost of the asset. If the future undiscounted cash flows, based on the Company’s estimate of future commodity prices, operating costs, and production, are lower than the net capitalized cost, the capitalized cost is reduced to fair value. Fair value is calculated by discounting the future cash flows at an appropriate risk-adjusted discount rate. Due to the significant assumptions associated with the inputs and calculations described, the fair value of oil and gas properties used in estimating impairment represents a nonrecurring Level 3 measurement. The Company incurred impairment charges of $18.8 million and $19.8 million related to its proved oil and natural gas properties and equipment in 2012 and 2011, respectively. No impairments of proved properties were recorded in 2013.

The Company evaluates its unproved properties for impairment on a property-by-property basis. The Company’s unproved property consists of acquisition costs related to its undeveloped acreage. The Company reviews the unproved property for indicators of impairment based on the Company’s current exploration plans with consideration given to results of any drilling and seismic activity during the period and known information regarding exploration activity by other companies on adjacent blocks. In the fourth quarter of 2013, the Company recorded an impairment charge of $14.4 million related to its unproved Southridge properties. As the Company did not drill the required number of wells by October 31, 2013 necessary to keep its joint development agreement with Southridge in effect, the Company lost its right to the undeveloped acreage. The Company incurred no impairment charges related to its unproved properties in 2012. In 2011, the Company incurred a $12.2 million impairment charge related to its unproven properties in fields which were not expected to produce natural gas with a sufficiently high liquid content reducing the economic return of those fields. These charges represent nonrecurring Level 3 measurements. Impairment of oil and gas properties charges are recorded on the Consolidated Statement of Operations.

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

F-10

Jones Energy, Inc.

Notes to Consolidated Financial Statements (Continued)

2. Significant Accounting Policies (Continued)

Other Property, Plant and Equipment

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

(in thousands of dollars)	2013			2012
Leasehold improvements	$	1,060		$	983
Furniture, fixtures, computers and software	2,491			2,204
Vehicles	835			719
Aircraft	910			1,295
Other	134			134
	5,430			5,335
Less: Accumulated depreciation and amortization	(1,986		)	(1,937		)
Net other property, plant and equipment	$	3,444		$	3,398

Other property, plant and equipment is depreciated on a straight-line basis over the estimated useful lives of the property, plant and equipment, which range from three years to ten years. Depreciation and amortization of other property, plant and equipment amounted to $0.8 million, $0.8 million and $0.7 million during the years ended December 31, 2013, 2012 and 2011, respectively.

Oil and Gas Sales Payable

Oil and gas sales payable represents amounts collected from purchasers for oil and gas sales, which are due to other revenue interest owners. Generally, the Company is required to remit amounts due under these liabilities within 60 days of receipt.

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 years ended December 31, 2013, 2012 and 2011, 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 Jones 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 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. The Company estimates an ARO for each well in the period in which

F-11

Jones Energy, Inc.

Notes to Consolidated Financial Statements (Continued)

2. Significant Accounting Policies (Continued)

it is incurred based on estimated present value of plugging and abandonment costs, increased by an inflation factor to the estimated date that the well would be plugged. The resulting liability is recorded by increasing the carrying amount of the related long- lived asset. The liability is then accreted to its then-present value each period and the capitalized cost is depleted over the useful life of the related asset. If the liability is settled for an amount other than the recorded amount, a gain or loss is recognized. The ARO is classified as current or noncurrent based on the expect timing of payments. A summary of the Company’s ARO for the years ended December 31, 2013 and 2012 is as follows:

(in thousands of dollars)	2013			2012
ARO liability at beginning of year	$	9,506		$	9,563
Liabilities incurred(1)	1,515			662
Accretion of discount	608			596
Liabilities settled due to sale of related properties	(271		)	(927		)
Liabilities settled due to plugging and abandonment	(702		)	(388		)
Change in estimate	307			—
ARO liability at end of year	10,963			9,506
Less: Current portion of ARO at end of year	(2,590		)	(174		)
Total long-term ARO at end of year	$	8,373		$	9,332

(1)Includes $824 related to wells acquired (see Note 3, “Acquisition of Properties”).

Revenue Recognition

Revenues from the sale of crude oil, natural gas, and natural gas liquids are recognized when the product is delivered at a fixed or determinable price, title has transferred, collectability is reasonably assured and evidenced by a contract. The Company follows the “sales method” of accounting for its oil and natural gas revenue, so it recognizes revenue on all crude oil, natural gas, and natural gas liquids sold to purchasers. A receivable or liability is recognized only to the extent that the Company has an imbalance on a specific property greater than the expected remaining proved reserves.

Production Costs

Production costs, including compressor rental, pumpers’ salaries, saltwater disposal, ad valorem taxes, insurance, repairs and maintenance, expensed workovers and other operating expenses are expensed as incurred and included in lease operating expense on the Consolidated Statement of Operations.

Exploration Expenses

Exploration expenses include dry hole costs, lease extensions, delay rentals and geological and geophysical costs.

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

F-12

Jones Energy, Inc.

Notes to Consolidated Financial Statements (Continued)

2. Significant Accounting Policies (Continued)

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.

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 December 31, 2013, there have been no exchanges and no liability is recorded on the Consolidated Balance Sheet.

Comprehensive Income

The Company has no elements of comprehensive income other than net income.

Statement of Cash Flows

The Company presents its cash flows using the indirect method.

F-13

Jones Energy, Inc.

Notes to Consolidated Financial Statements (Continued)

2. Significant Accounting Policies (Continued)

Related Party Transactions

In the years ended December 31, 2013, 2012 and 2011, the Company paid an annual administration fee to Metalmark of $0.7 million. This amount was charged to expense. As a result of the IPO, this fee is no longer payable to Metalmark.

On May 7, 2013, the Company entered into a natural gas sale and purchase agreement with Monarch Natural Gas, LLC, or Monarch, under which Monarch has the first right to gather the natural gas the Company produces from the Chalker properties, process the NGLs from this natural gas production and market the processed natural gas and extracted NGLs. Under the Monarch agreement, the Company is paid a specified percentage of the value of the NGLs extracted and sold by Monarch, based on a set liquids recovery percentage, and the amount received from the sale of the residue gas, after deducting a fixed volume for fuel, lost and unaccounted for gas. For the year ended December 31, 2013, the Company produced approximately 0.8 MMBoe of natural gas and NGLs from the Chalker properties that became subject to the Monarch agreement. The initial term of the agreement runs for 10 years from the effective date of September 1, 2013. At the time the Company entered into the agreement, Metalmark Capital owned approximately 81% of the outstanding equity interests of Monarch. In addition, Metalmark Capital beneficially owns in excess of five percent of the Company’s outstanding equity interests and two of our directors, Howard I. Hoffen and Gregory D. Myers, are managing directors of Metalmark Capital. In connection with the Company’s entering into the Monarch agreement, Monarch issued to JEH equity interests in Monarch having a deemed value of $15 million. JEH assigned $2.4 million of the Monarch equity interests to Jonny Jones, the Company’s chief executive officer and chairman of the board, and reserved $2.6 million of the Monarch equity interests to a benefit plan established for certain of the Company’s officers, including Mike McConnell, Robert Brooks and Eric Niccum. The remaining $10 million of Monarch equity was distributed to certain of the pre-IPO owners, which include Metalmark Capital, Wells Fargo, the Jones family entities, and certain of the Company’s officers and directors, including Jonny Jones, Mike McConnell, Robert Brooks and Eric Niccum.

Stock Compensation

JEH implemented a management incentive plan effective January 1, 2010, 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 have a single vesting structure of 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. At December 31, 2013, there were 457,150 unvested JEH Units and shares of Class B common stock that will become convertible into a like number of shares of Class A common stock upon vesting.

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. As of December 31, 2013 no such awards had been issued or granted to any of the Company’s employees.

F-14

Jones Energy, Inc.

Notes to Consolidated Financial Statements (Continued)

2. Significant Accounting Policies (Continued)

On September 4, 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 grants 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.

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

Business Combinations

For acquisitions of working interests that are accounted for as business combinations, the results of operations are included in the Consolidated Statement of Operations from the date of acquisition. Purchase prices are allocated to assets acquired based on their estimated fair values at the time of acquisition. 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. The fair value measurement is based on the assumptions of market participants and not those of the reporting entity. Therefore, entity-specific intentions do not impact the measurement of fair value. The fair value of oil and natural gas properties is determined using a risk-adjusted after-tax discounted cash flow analysis based upon significant inputs including: 1) oil and gas prices, 2) projections of estimated quantities of oil and natural gas reserves, including those classified as proved, probable and possible, 3) projections of future rates of production, 4) timing and amount of future development and operating costs, 5) projected reserve recovery factors, and 6) weighted average cost of capital.

Recent Accounting Developments

The following recently issued accounting pronouncement has been adopted by the Company:

Offsetting Assets and Liabilities

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

3. Acquisition of Properties

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 adjusted 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

F-15

Jones Energy, Inc.

Notes to Consolidated Financial Statements (Continued)

3. Acquisition of Properties (Continued)

acreage. The purchase was financed with borrowings under the senior secured credit facility. The purchase price was allocated as follows:

(in thousands of dollars)
Oil and gas properties
Unproved	$	39,596
Proved	154,724
Asset retirement obligations	(824		)
Total purchase price	$	193,496

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, which when they occur, may result in an adjustment to the value of the acquired properties reflected in the consolidated financial statements. Any such adjustment may be material.

In connection with the closing, approximately $24 million of the purchase price was placed in an escrow account. This amount represented the allocated value of the Sabine properties that had unresolved title defects claimed by JEH. In the event one or more title defects are not cured by Sabine, the affected property will be reconveyed to Sabine and the Company will receive an amount of cash from the escrow account equal to the allocated value of the reconveyed property. A corresponding adjustment to the allocation of the Sabine purchase price will be made at such time.

The unaudited pro forma results presented below have been prepared to include the effect of the Sabine acquisition on our results of operations for the year ended December 31, 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.

	Post		Year Ended December 31, 2013
(in thousands of dollars)	Acquisition(1)		Pro Forma
	(unaudited)		(unaudited)
Total operating revenue	$	1,365	$	308,773
Total operating expenses	291		229,648
Operating income	1,074		79,125
Net income	1,074		45,778

(1)Represents revenues and expenses for the post acquisition period of December 18, 2013 to December 31, 2013 included in the Consolidated Statement of Operations.

On December 20, 2012, JEH acquired certain oil and natural gas properties located in Texas for a purchase price of $251.9 million (referred to herein as the “Chalker acquisition” or “Chalker”). The acquired assets included both producing properties and undeveloped acreage. The purchase was

F-16

Jones Energy, Inc.

Notes to Consolidated Financial Statements (Continued)

3. Acquisition of Properties (Continued)

financed with additional equity capital and borrowings under the senior secured credit facility. In the second quarter of 2013, the Company made a final determination with the sellers as to the purchase price adjustments resulting in a final purchase price of $253.5 million. The final purchase price was allocated as follows:

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

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

The unaudited pro forma results presented below have been prepared to include the effect of the Chalker acquisition on our results of operations for the year ended December 31, 2012. The unaudited pro forma results do not purport to represent what our actual results of operations would have been if the acquisition had been completed on January 1, 2012 or to project our results of operations for any future date or period.

	Year Ended December 31, 2012
(in thousands of dollars)	Pro Forma
	(unaudited)
Total operating revenue	$	194,685
Total operating expenses	161,053
Operating income	33,632
Net income	25,713

On April 14, 2011, Jones Energy acquired certain oil and natural gas properties located in Oklahoma for a purchase price of $154.1 million. The acquisition included both producing and undeveloped properties. The purchase was financed with additional borrowings under the senior secured credit facility. The purchase price was allocated as follows:

(in thousands of dollars)
Oil and gas properties	$	154,225
Asset retirement obligations	(167		)
Total purchase price	$	154,058

This acquisition qualified as a business combination under ASC 805. The Company recorded a total fair value of $180.3 million ($154.1 million for producing properties and $26.2 million for undeveloped property). The total resulted in a bargain purchase gain of $26.2 million, which was recorded in the Consolidated Statement of Operations. The valuation to determine the fair value was

F-17

Jones Energy, Inc.

Notes to Consolidated Financial Statements (Continued)

3. Acquisition of Properties (Continued)

principally based on the discounted cash flows of the both the producing and undeveloped properties, including projected drilling and equipment costs, recoverable reserves, production streams, future prices and operating costs, and risk-adjusted discount rates reflective of the current market. The recognized gain was the difference between the net fair value and the consideration paid the seller.

Management believes the bargain purchase gain resulted from the fact that the seller, who retained a 50% ownership interest in the undeveloped properties, benefitted from the Company’s available liquidity that would enable accelerated development of the prospect.

The following income statement line items present the pro forma results as if these properties had been acquired on January 1, 2010:

	Year Ended December 31, 2011
(in thousands of dollars)	Pro Forma
	(unaudited)
Total operating revenue	$	176,884
Total operating expenses	150,197
Operating income	26,687
Net income	62,408

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.

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 as a result of the credit quality of the counterparty. Generally, market quotes assume that all counterparties have low default rates and equal credit quality. Therefore, an adjustment may be necessary to reflect the quality of a specific counterparty to determine the fair value of the instrument. The Company currently has all derivative positions placed and held by members of its lending group, which have strong credit quality.

F-18

Jones Energy, Inc.

Notes to Consolidated Financial Statements (Continued)

4. Fair Value Measurement (Continued)

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 in Level 1.
Level 2	Pricing inputs include quoted prices for similar assets and liabilities in active markets, and inputs that are observable for the asset or liability, either directly or indirectly, as of the reporting date. Contracts that are not traded on a recognized exchange or are tied to pricing transactions for which forward curve pricing is readily available are classified as Level 2 instruments. These include natural gas, crude oil and some natural gas liquids price swaps and natural gas basis swaps.
Level 3	Pricing inputs include significant inputs that are generally unobservable from objective sources. 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.

F-19

Jones Energy, Inc

Notes to Consolidated Financial Statements (Continued)

4. Fair Value Measurement (Continued)

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

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

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

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 December 31, 2013.

	Quantitative Information About Level 3 Fair Value Measurements
Commodity Price Hedges	Fair Value			Valuation Technique	Unobservable Input	Range
Natural gas liquid swaps	$	(1,235	)	Use a discounted cash flow approach using inputs including forward price statements from counterparties	Natural gas liquid futures	$9.24 - $83.06 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 years ended December 31, 2013 and 2012. 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

F-20

Jones Energy, Inc

Notes to Consolidated Financial Statements (Continued)

4. Fair Value Measurement (Continued)

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 January 1, 2012, net	$	(2,083	)
Purchases	(2,352		)
Settlements	—
Transfers to Level 2	2,370
Transfers to Level 3	834
Changes in fair value	(288		)
Balance at December 31, 2012, net	(1,519		)
Purchases	(1,095		)
Settlements	(210		)
Transfers to Level 2	(753		)
Changes in fair value	2,342
Balance at December 31, 2013, net	$	(1,235	)

Transfers from Level 3 to Level 2 represent all of the Company’s natural gas basis swaps for which observable forward curve pricing information has become readily available. In 2012, transfers to Level 3 represented natural gas liquid swaps or basis swaps that were classified as Level 2 in 2011 but due to the unavailability of forward prices in 2012, were classified as Level 3 in 2012. The purchases represent natural gas liquid swaps that the Company entered into in 2013 that do not have observable forward curve pricing information.

Offsetting Assets and Liabilities

As of December 31, 2013, the counterparties to our commodity derivative contracts consisted of six financial institutions. All of our counterparties or their affiliates are also lenders under our credit facility. Therefore, we are not generally required to post additional collateral under our derivative agreements.

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

F-21

Jones Energy, Inc

Notes to Consolidated Financial Statements (Continued)

4. Fair Value Measurement (Continued)

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 December 31, 2013 and December 31, 2012:

(in thousands of dollars)	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
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		)
December 31, 2012
Commodity derivative contracts
Assets	$	49,200		$	(7,831	)	$	41,369		$	1,478		$	42,847
Liabilities	(17,928		)	7,831			(10,097		)	(1,595		)	(11,692		)

Nonfinancial Assets and Liabilities

Assets and liabilities acquired in business combinations are recorded at their fair value on the date of acquisition. Significant Level 3 assumptions associated with the calculation of future cash flows used in the analysis of fair value of the oil and gas property acquired include 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. No significant impairment charges on the Company’s proved properties were recorded during the year ended December 31, 2013. During 2012 and 2011, unamortized capitalized costs of certain properties were higher than their expected undiscounted future cash flows due primarily to downward reserve revisions, drilling of marginal or uneconomic wells, or development dry holes in certain producing fields. As a result, the Company recorded charges of $18.8 million and $19.8 million during the years ended December 31, 2012 and 2011, respectively.

Additionally, the Company reviews its unproved properties for indicators of impairment based on the Company’s current exploration plans. In the fourth quarter of 2013, the Company recorded an impairment charge of $14.4 million related to the Southridge properties. As the Company did not drill the required number of wells by October 31, 2013 necessary to keep its joint development agreement with Southridge in effect, the Company lost its right to the undeveloped acreage and associated reserves. The Company incurred no impairment charges related to its unproved properties in 2012. In

F-22

Jones Energy, Inc

Notes to Consolidated Financial Statements (Continued)

4. Fair Value Measurement (Continued)

2011, the Company incurred a $12.2 million impairment charge related to its unproven properties in fields which were not expected to produce natural gas with a sufficiently high liquid content. With low natural gas prices during that period, the lack of natural gas liquids reduced the economic return of those fields and as a result, the Company had no intentions to continue development of those fields.

Impairment charges are recorded on the Consolidated Statement of Operations. 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. As such, the fair value of oil and gas properties used in estimating impairment represents a nonrecurring Level 3 measurement.

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 December 31, 2013 and 2012, as follows:

Hedging Positions

	December 31, 2013
		Low			High			Weighted Average			Final 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

	December 31, 2012
		Low			High			Weighted Average			Final Expiration
Oil swaps	Exercise price	$	81.00		$	104.45		$	89.60
	Barrels per month	24,000			143,116			89,323			December 2017
Natural gas swaps	Exercise price	$	3.52		$	6.90		$	4.96
	mmbtu per month	430,000			1,110,000			767,053			December 2017
Basis swaps	Contract differential	$	(0.65	)	$	(0.03	)	$	(0.31	)
	mmbtu per month	320,000			850,000			484,615			March 2016
Natural gas liquids swaps	Exercise price	$	6.72		$	97.13		$	33.81
	Barrels per month	2,000			144,973			55,616			December 2017

F-23

Jones Energy, Inc

Notes to Consolidated Financial Statements (Continued)

5. Derivative Instruments and Hedging Activities (Continued)

The Company recognized a net loss on derivative instruments of $2.6 million for the year ended December 31, 2013 and net gains of $16.7 million and $34.5 million for the years ended December 31, 2012 and 2011, respectively.

6. Long-Term Debt

The Company entered into two credit agreements dated December 31, 2009, with Wells Fargo Bank N.A, the Senior Secured Revolving Credit Facility (the “Revolver”) and the Second Lien Term Loan (the “Term Loan”) which were subsequently amended on November 18, 2011, November 5, 2012, December 20, 2012, June 12, 2013, December 18, 2013 and January 29, 2014. In connection with the November 2012 amendment, the maturity date of the Revolver was extended to November 5, 2017 and the maturity date of the Term loan was extended to May 5, 2018. In connection with the June 2013 amendment, the borrowing base on the Revolver was increased to $500.0 million and subsequently increased to $575.0 million on December 18, 2013 in conjunction with the Sabine acquisition. The Company’s oil and gas properties are pledged as collateral against these credit agreements.

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 year ended December 31, 2013, the average interest rate under the Revolver was 3.01% on an average outstanding balance of $384.9 million. For the year ended December 31, 2012, the average interest rate under the Revolver was 3.30% on an average outstanding balance of $306.8 million.

Terms of the Term Loan require the Company to pay interest on the loan every three months with the principal and interest due on the loan maturity date of May 5, 2018. Interest on the Term Loan is calculated at a base rate (LIBOR, prime, or federal funds), plus a margin of 6% to 7% based on the base rate selected. As of December 31, 2013, the average interest rate was 9.19% on an average outstanding balance of $160.0 million. As of December 31, 2012, the average interest rate was 9.16% on an average outstanding balance of $121.3 million.

Total interest and commitment fees under the two facilities were $27.0 million, $21.2 million and $18.2 million for the years ended December 31, 2013, 2012 and 2011, respectively.

In connection with the IPO, the Company used the net proceeds to repay outstanding borrowings under the Revolver of $167.0 million.

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

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

F-24

Jones Energy, Inc

Notes to Consolidated Financial Statements (Continued)

7. Stock-based Compensation

JEH granted membership-interest awards in JEH to members of senior management (“management units”) under a management incentive plan prior to the IPO. 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 December 31, 2013, there were 457,150 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:

	JEH Units		Weighted Average Grant Date Fair Value per Share
Unvested at January 1, 2013	710,767		$	3.62
Granted	911,654		$	15.00
Forfeited	(167,239	)	$	3.62
Vested	(998,032	)	$	9.96
Unvested at December 31, 2013	457,150		$	12.46

Stock compensation expense associated with the management units for the years ended December 31, 2013, 2012 and 2011 was $10.7 million, $0.6 million and $1.1 million, respectively, and is included in general and administrative expenses on the Company’s Consolidated Statement of Operations.

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, 2013	—	—
Granted	27	$	15.05
Forfeited	—	—
Vested	—	—
Unvested at December 31, 2013	27	$	15.05

Stock compensation expense associated with the Board of Directors awards for the year ended December 31, 2013 was $0.1 million and is included in general and administrative expenses on the Company’s Consolidated Statement of Operations.

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

F-25

Jones Energy, Inc

Notes to Consolidated Financial Statements (Continued)

8. Earnings per Share (Continued)

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. On September 4, 2013 (the “grant date”), the Company granted to its directors restricted shares of Class A common stock, which vest on the first anniversary of the grant date. In accordance with ASC 260, Earnings Per Share, awards of nonvested shares shall be considered outstanding as of the grant date for purposes of computing diluted EPS even though their exercise is contingent upon vesting. For the year ended December 31, 2013, the directors’ restricted shares of Class A common stock were excluded from the diluted calculation, as their inclusion would have been anti-dilutive as the Company was in a net loss position. 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 year ended December 31, 2013. Net income (loss) and the weighted average number of shares of Class A common stock outstanding is based on the actual days in which the shares were outstanding for the period from July 29, 2013, the closing date of the IPO, to December 31, 2013.

(in thousands, except per share data)	December 31, 2013
Income (numerator):
Net income (loss) attributable to controlling interests	$	(2,186	)
Weighted-average shares (denominator):
Weighted-average number of shares of Class A common stock—basic and diluted	12,500
Earnings (loss) per share:
Basic and diluted	$	(0.17	)
Anti-dilutive restricted shares of Class A common stock	27

9. Monarch Investment

On May 7, 2013, the Company entered into a marketing agreement with Monarch Natural Gas, LLC (“Monarch”), a company related through common ownership, for the sale to Monarch of natural gas produced from certain properties. In connection with that agreement, Monarch issued to the Company equity interests in its parent, Monarch Natural Gas Holdings, LLC, having an estimated fair value of $15.0 million. Contemporaneous with the execution of the marketing agreement and the issuance of the equity interests, the Company distributed 67% or $10 million of the Monarch equity interests to the Company’s owners pro rata based on equity contributions and approximately 16% of the interests to a member of management. The remaining approximately 17% of the equity interests were reserved for distribution to management through an incentive plan. The Company recognized $0.3 million of compensation expense during the year ended December 31, 2013 in connection with the incentive plan. In addition, the Company recorded deferred revenue of $15.0 million which is being amortized on an estimated units-of-production basis commencing in September 2013, the first month of production sales to Monarch. The Company amortized $0.5 million of the deferred revenue balance during the year ended December 31, 2013 and is recorded in other revenues on the Company’s Consolidated Statement of Operations.

F-26

Jones Energy, Inc

Notes to Consolidated Financial Statements (Continued)

10. Commitments and Contingencies

Lease obligations

The Company leases approximately 31,000 square feet of office space in Austin, TX under an operating lease arrangement. Future minimum payments for noncancellable operating leases extending beyond one year at December 31, 2013 are as follows:

(in thousands of dollars)
Years Ending December 31,
2014	$	586
2015	482
2016	458
2017	147
Thereafter	—
	$	1,673

Rent expense under operating leases was $0.8 million, $0.8 million and $0.7 million for the years ended December 31, 2013, 2012 and 2011, respectively.

Litigation

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 current matters will not have a material adverse effect on its financial position, results of operations, or liquidity.

11. Benefit Plans

The Company established a 401(k) tax-deferred savings plan (the “Plan”) for the benefit of employees. The Plan is a defined contribution plan and the Company may match a portion of employee contributions. For the years ended December 31, 2013 and 2012, $0.3 million and $0.2 million were contributed, respectively, to the Plan.

In 2013, the Company established a 409A tax-deferred savings plan for the benefit of key employees. This plan is a defined contribution plan, and the Company may match a portion of employee contributions. For the year ended December 31, 2013, the Company made a negligible contribution to this plan.

12. Income Taxes

Following its IPO, the Company began recording a federal and state income tax liability 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 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

F-27

Jones Energy, Inc

Notes to Consolidated Financial Statements (Continued)

12. Income Taxes (Continued)

franchise tax expense. The following table summarizes the tax provision for the years ended December 31, 2013, 2012 and 2011:

	Year Ended December 31,
(in thousands of dollars)	2013			2012		2011
Current tax expense
Federal	$	85		$	—	$	—
State	—			—		—
Total current expense	85			—		—
Deferred tax expense (benefit)
Federal	(1,260		)	—		—
State	1,104			473		173
Total deferred expense (benefit)	(156		)	473		173
Total tax expense (benefit)	(71		)	473		173
Tax benefit attributable to controlling interests	(1,223		)	—		—
Tax expense attributable to non-controlling interests	1,152			473		173
Total tax expense (benefit)	$	(71	)	$	473	$	173

For the years ended December 31, 2012 and 2011, the reported taxes relate solely to the Texas franchise tax liability of JEH.

A reconciliation of the Company’s provision for income taxes as reported and the amount computed by multiplying income before taxes, less non-controlling interest, by the U.S. federal statutory rate of 35%:

(in thousands of dollars)	December 31, 2013
Provision calculated at federal statutory income tax rate:
Net income before taxes	$	22,334
Statutory rate	35		%
Income tax expense computed at statutory rate	7,817
Less: Non-controlling interests	(9,009		)
Income tax benefit attributable to controlling interests	(1,192		)
State and local income taxes, net of federal benefit	(49		)
Other	18
Tax benefit attributable to controlling interests	(1,223		)
Tax expense attributable to non-controlling interests	1,152
Total income tax benefit	$	(71	)

For the years ended December 31, 2012 and 2011, the calculation is not applicable as the Company was not subject to federal income taxes prior to the IPO.

F-28

Jones Energy, Inc

Notes to Consolidated Financial Statements (Continued)

12. Income Taxes (Continued)

The Company is subject to federal, state and local income and franchise taxes. As such, deferred income taxes result from temporary differences between the carrying amounts of assets and liabilities of the Company for financial reporting purposes and the amounts used for income tax purposes. Deferred tax assets and liabilities are measured using enacted tax rates in effect in the years in which those temporary differences are expected to reverse.

Significant components of the Company’s deferred tax assets and deferred tax liabilities consisted of the following:

	As of December 31,
(in thousands of dollars)	2013			2012
Deferred tax assets
Investment in consolidated subsidiary JEH	$	526		$	—
Net operating loss	649			—
Alternative minimum tax credits	86			—
State deferred tax asset	52			—
Total deferred tax assets	1,313			—
Deferred tax liabilities
State deferred tax liability	3,093			1,936
Total deferred tax liabilities	3,093			1,936
Net deferred tax assets (liabilities)	(1,780		)	(1,936		)
Valuation allowance	—			—
Net deferred tax assets (liabilities)	$	(1,780	)	$	(1,936	)

The Company has a federal net operating loss carry-forward totaling $1.8 million and state net operating loss carry-forward of $0.4 million, both expiring in 2033. No valuation allowance has been recorded as management believes that there is sufficient future taxable income to fully utilize its deferred tax assets. This future taxable income will arise from reversing temporary differences due to the excess of the book carrying value of oil and gas properties over their corresponding tax basis. The Company may elect to capitalize intangible drilling costs, rather than expensing these costs, in order to prevent an operating loss carry-forward from expiring unused.

Separate federal and state income tax returns are filed for Jones Energy, Inc. and Jones Energy Holdings, LLC. JEH’s Texas franchise tax returns are subject to audit for 2009, 2010, 2011, and 2012. The tax years 2010 through 2013 remain open to examination by the major taxing jurisdictions to which the Company is subject. The Company is not currently under audit in any other major taxing jurisdiction.

Accounting for uncertainty in income taxes prescribes a recognition threshold and measurement methodology for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. As of December 31, 2013 and December 31, 2012 there was no material liability or expense for the periods then ended recorded for payments of interest and penalties associated with uncertain tax positions or material unrecognized tax positions and the Company’s unrecognized tax benefits were not material.

F-29

Jones Energy, Inc

Notes to Consolidated Financial Statements (Continued)

13. Subsidiary Guarantors

On April 1, 2014, JEH and its wholly-owned subsidiary, Jones Energy Finance Corp. (the “Issuers”), sold $500.0 million in aggregate principal amount of the Issuers’ 6.75% Senior Notes due 2022 (the “2022 Notes”).

The 2022 Notes are guaranteed on a senior unsecured basis by the Company and by all of JEH’s current subsidiaries (except Jones Energy Finance Corp. and two immaterial subsidiaries) and certain future subsidiaries, including any future subsidiaries that guarantee any indebtedness under the Company’s Revolver. Each subsidiary guarantor is 100% owned by JEH, and all guarantees are full, unconditional, and joint and several with all other subsidiary guarantees and the parent guarantee. Any subsidiaries of JEH other than the subsidiary guarantors and Jones Energy Finance Corp. are minor.

The Company is a holding company and has no independent assets or operations of its own.  The Company is the sole managing member of JEH and is responsible for all operational, management and administrative decisions related to JEH’s business. In accordance with JEH’s limited liability company agreement, the Company may not be removed as the sole managing member of JEH.

The Company currently holds approximately 25.3% of the economic interest in JEH, with the remaining 74.7% economic interest held by a group of investors that owned interests in JEH prior to the Company’s IPO (the “Existing Owners”). The Existing Owners have no voting rights with respect to their economic interest in JEH.

The Company has two classes of common stock, Class A common stock, which was sold to investors in the IPO, and Class B common stock.  Pursuant to the Company’s certificate of incorporation, each share of Class A common stock is entitled to one vote per share, and the shares of Class A common stock are entitled to 100% of the economic interests in the Company. Each share of Class B common stock has no economic rights in the Company, but entitles its holder to one vote on all matters to be voted on by the Company’s stockholders generally.

In connection with a reorganization that occurred immediately prior to the IPO, each Existing Owner was issued a number of shares of Class B common stock that is equal to the number of JEH Units that such Existing Owner holds. Holders of the Company’s Class A common stock and Class B common stock generally vote together as a single class on all matters presented to the Company’s stockholders for their vote or approval. Accordingly, the Existing Owners collectively have a number of votes in the Company equal to the aggregate number of JEH Units that they hold.

The Existing Owners have the right, pursuant to the terms of an Exchange Agreement by and among the Company, JEH and each of the Existing Owners, to exchange their JEH Units (together with a corresponding number of shares of Class B common stock) 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.  As a result, the Company expects that over time the Company will have an increasing economic interest in JEH as Class B common stock and JEH Units are exchanged for Class A common stock.  Moreover, any transfers of JEH Units outside of the Exchange Agreement (other than permitted transfers to affiliates) must be approved by the Company.  The Company intends to retain full voting and management control over JEH.

F-30

Jones Energy, Inc

Notes to Consolidated Financial Statements (Continued)

Jones Energy, Inc.

Condensed Consolidating Statements of Operations

Year Ended December 31, 2013

	Year Ended December 31, 2013
(in thousands of dollars)	JEI(Parent)			Issuers			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations		Consolidated
Operating revenues
Oil and gas sales	$	—		$	—		$	258,063		$	—		$	—	$	258,063
Other revenues	—			469			637			—			—		1,106
Total operating revenues	—			469			258,700			—			—		259,169
Operating costs and expenses
Lease operating	—			—			27,781			—			—		27,781
Production taxes	—			—			12,865			—			—		12,865
Exploration	—			—			1,710			—			—		1,710
Depletion, depreciation and amortization	—			—			114,046			90			—		114,136
Impairment of oil and gas properties	—			—			14,415			—			—		14,415
Accretion of discount	—			—			608			—			—		608
General and administrative (including non-cash compensation expense)	—			4,154			27,490			258			—		31,902
Total operating expenses	—			4,154			198,915			348			—		203,417
Operating income	—			(3,685		)	59,785			(348		)	—		55,752
Other income (expense)
Interest expense	—			(29,653		)	(1,121		)	—			—		(30,774		)
Net gain (loss) on commodity derivatives	—			(2,566		)	—			—			—		(2,566		)
Gain (loss) on sales of assets	—			—			41			(119		)	—		(78		)
Other income (expense), net	—			(32,219		)	(1,080		)	(119		)	—		(33,418		)
Income (loss) before income tax	—			(35,904		)	58,705			(467		)	—		22,334
Equity interest in Income	(3,400		)	—			—			—			3,400		—
Income tax provision (benefit)
Current	85			—			—			—			—		85
Deferred	(1,299		)	1,143			—			—			—		(156		)
Total income tax provision (benefit)	(1,214		)	1,143			—			—			—		(71		)
Net income (loss)	$	(2,186	)	$	(37,047	)	$	58,705		$	(467	)	$	3,400	$	22,405
Net income (loss) attributable to non-controlling interests	—			—			—			—			$	24,591	$	24,591
Net income (loss) attributable to controlling interests	$	(2,186	)	—			—			—			—		$	(2,186	)

F-31

Jones Energy, Inc

Notes to Consolidated Financial Statements (Continued)

Jones Energy, Inc.

Condensed Consolidating Statements of Operations

Year Ended December 31, 2012

	Year Ended December 31, 2012
(in thousands of dollars)	JEI(Parent)		Issuers			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations		Consolidated
Operating revenues
Oil and gas sales	$	—	$	—		$	148,967		$	—		$	—	$	148,967
Other revenues	—		—			847			—			—		847
Total operating revenues	—		—			149,814			—			—		149,814
Operating costs and expenses
Lease operating	—		—			23,097			—			—		23,097
Production taxes	—		—			5,583			—			—		5,583
Exploration	—		—			356			—			—		356
Depletion, depreciation and amortization	—		—			80,554			155			—		80,709
Impairment of oil and gas properties	—		—			18,821			—			—		18,821
Accretion of discount	—		—			533			—			—		533
General and administrative (including non-cash compensation expense)	—		2,589			12,562			724			—		15,875
Total operating expenses	—		2,589			141,506			879			—		144,974
Operating income	—		(2,589		)	8,308			(879		)	—		4,840
Other income (expense)
Interest expense	—		(24,679		)	(613		)	—			—		(25,292		)
Net gain (loss) on commodity derivatives	—		16,684			—			—			—		16,684
Gain (loss) on sales of assets	—		—			1,162			—			—		1,162
Other income (expense), net	—		(7,995		)	549			—			—		(7,446		)
Income (loss) before income tax	—		(10,584		)	8,857			(879		)	—		(2,606		)
Income tax provision (benefit)
Current	—		—			—			—			—		—
Deferred	—		473			—			—			—		473
Total income tax provision (benefit)	—		473			—			—			—		473
Net income (loss)	$	—	$	(11,057	)	$	8,857		$	(879	)	$	—	$	(3,079	)

F-32

Jones Energy, Inc

Notes to Consolidated Financial Statements (Continued)

Jones Energy, Inc

Condensed Consolidating Balance Sheet

December 31, 2013

	December 31, 2013
(in thousands of dollars)	JEI(Parent)			Issuers		Guarantor Subsidiaries		Non-Guarantor Subsidiaries			Eliminations			Consolidated
Assets
Current assets
Cash	$	100		$	6,000	$	17,650	$	70		$	—		$	23,820
Restricted Cash	—			—		45		—			—			45
Accounts receivable, net
Oil and gas sales	—			—		51,233		—			—			51,233
Joint interest owners	—			—		42,481		—			—			42,481
Other	—			—		1,459		—			—			1,459
Commodity derivative assets	—			8,837		—		—			—			8,837
Other current assets	—			387		2,005		—			—			2,392
Deferred tax assets	—			12		—		—			—			12
Intercompany receivable	638			1,051,389		—					(1,052,027		)	—
Total current assets	738			1,066,625		114,873		70			(1,052,027		)	130,279
Oil and gas properties, net, at cost under the successful efforts method	—			—		1,312,551		—			—			1,312,551
Other property, plant and equipment, net	—			—		2,557		887			—			3,444
Commodity derivative assets	—			25,398		—		—			—			25,398
Other assets	—			14,072		934		—			—			15,006
Investment in Subsidiaries	169,081			—		—		—			(169,081		)	—
Deferred tax assets	1,301			—		—		—			—			1,301
Total assets	$	171,120		$	1,106,095	$	1,430,915	$	957		$	(1,221,108	)	$	1,487,979
Liabilities and Stockholders’ / Members’ Equity
Current liabilities
Trade accounts payable	$	—		$	230	$	89,200	$	—		$	—		$	89,430
Oil and gas sales payable	—			—		66,179		—			—			66,179
Accrued liabilities	87			1,642		9,076		—			—			10,805
Commodity derivative liabilities	—			10,664		—		—			—			10,664
Deferred tax liabilities	—			—		—		—			—			—
Asset retirement obligations	—			—		2,590		—			—			2,590
Intercompany payable				—		1,051,935		2,279			(1,054,214		)	—
Total current liabilities	87			12,536		1,218,980		2,279			(1,054,214		)	179,668
Long-term debt	—			658,000		—		—			—			658,000
Deferred revenue	—			14,531		—		—			—			14,531
Commodity derivative liabilities	—			190		—		—			—			190
Asset retirement obligations	—			—		8,373		—			—			8,373
Deferred tax liabilities	—			3,093		—		—			—			3,093
Total liabilities	87			688,350		1,227,353		2,279			(1,054,214		)	863,855
Commitments and contingencies (Note 10)
Stockholders’ / members’ equity
Members’ equity	—			417,745		203,562		(1,322		)	(619,985		)	—
Class A common stock, $0.001 par value; 12,526,580 shares issued and outstanding	13			—		—		—			—			13
Class B common stock, $0.001 par value; 36,836,333 shares issued and outstanding	37			—		—		—			—			37
Additional paid-in-capital	173,169			—		—		—			—			173,169
Retained earnings (deficit)	(2,186		)	—		—		—			—			(2,186		)
Stockholders’ / members’ equity	171,033			417,745		203,562		(1,322		)	(619,985		)	171,033
Non-controlling interest	—			—		—		—			453,091			453,091
Total stockholders’ / members’ equity	171,033			417,745		203,562		(1,322		)	(166,894		)	624,124
Total liabilities and stockholders’ / members’ equity	$	171,120		$	1,106,095	$	1,430,915	$	957		$	(1,221,108	)	$	1,487,979

F-33

Jones Energy, Inc

Notes to Consolidated Financial Statements (Continued)

Jones Energy, Inc

Condensed Consolidating Balance Sheet

December 31, 2012

	December 31, 2012
(in thousands of dollars)	JEI(Parent)		Issuers		Guarantor Subsidiaries		Non-Guarantor Subsidiaries			Eliminations			Consolidated
Assets
Current assets
Cash	$	—	$	5,056	$	18,600	$	70		$	—		$	23,726
Restricted Cash	—		—		—		—			—			—
Accounts receivable, net
Oil and gas sales	—		—		29,684		—			—			29,684
Joint interest owners	—		—		21,876		—			—			21,876
Other	—		1,719		2,871		—			—			4,590
Commodity derivative assets	—		17,648		—		—			—			17,648
Other current assets	—		—		1,088		—			—			1,088
Deferred tax assets	—		—		—		—			—			—
Intercompany receivable	—		845,184		—		—			(845,184		)	—
Total current assets	—		869,607		74,119		70			(845,184		)	98,612
Oil and gas properties, net, at cost
under the successful efforts method	—		—		1,007,344		—			—			1,007,344
Other property, plant and equipment, net	—		—		2,568		830			—			3,398
Commodity derivative assets	—		25,199		—		—			—			25,199
Other assets	—		13,446		2,687		—			—			16,133
Deferred tax assets	—		—		—		—			—			—
Total assets	$	—	$	908,252	$	1,086,718	$	900		$	(845,184	)	$	1,150,686
Liabilities and Stockholders’ / Members’ Equity
Current liabilities
Trade accounts payable	$	—	$	116	$	37,920	$	—		$	—		$	38,036
Oil and gas sales payable	—		—		45,860		—			—			45,860
Accrued liabilities	—		110		5,145		—			—			5,255
Commodity derivative liabilities	—		4,035		—		—			—			4,035
Deferred tax liabilities	—		61		—		—			—			61
Asset retirement obligations	—		—		174		—			—			174
Intercompany payable	—		—		843,430		1,754			(845,184		)	—
Total current liabilities	—		4,322		932,529		1,754			(845,184		)	93,421
Long-term debt	—		610,000		—		—			—			610,000
Deferred revenue	—		—		—		—			—			—
Commodity derivative liabilities	—		7,657		—		—			—			7,657
Asset retirement obligations	—		—		9,332		—			—			9,332
Deferred tax liabilities	—		1,876		—		—			—			1,876
Total liabilities	—		623,855		941,861		1,754			(845,184		)	722,286
Commitments and contingencies (Note 10)
Stockholders’ / members’ equity
Members’ equity	—		284,397		144,857		(854		)	—			428,400
Stockholders’ / members’ equity	—		284,397		144,857		(854		)	—			428,400
Total stockholders’ / members’ equity	—		284,397		144,857		(854		)	—			428,400
Total liabilities and stockholders’ / members’ equity	$	—	$	908,252	$	1,086,718	$	900		$	(845,184	)	$	1,150,686

F-34

Jones Energy, Inc

Notes to Consolidated Financial Statements (Continued)

Jones Energy, Inc.

Consolidated Statements of Cash Flows

Years Ended December 31, 2013

	Year Ended December 31, 2013
(in thousands of dollars)	JEI(Parent)			Issuers			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated
Cash flows from operating activities
Net income (loss)	$	(2,186	)	$	(37,047	)	$	58,705		$	(467	)	$	3,400		$	22,405
Adjustments to reconcile net income (loss) to net cash provided by operating activities	2,286			(189,393		)	331,265			733			(3,400		)	141,491
Net cash (used in) / provided by operations	100			(226,440		)	389,970			266			—			163,896
Cash flows from investing activities
Investment in subsidiary	(172,481		)										172,481			—
Additions to oil and gas properties	—			—			(197,618		)							(197,618		)
Acquisition of properties	—			—			(193,496		)							(193,496		)
Proceeds from sales of assets	—			—			963			644						1,607
Acquisition of other property, plant and equipment	—			—			(724		)	(910		)				(1,634		)
Current period settlements of matured derivative contracts	—			7,586			—			—						7,586
Change in restricted cash	—			—			(45		)	—						(45		)
Net cash (used in) / provided by investing	(172,481		)	7,586			(390,920		)	(266		)	172,481			(383,600		)
Cash flows from financing activities
Proceeds from investment by JEI				172,481									(172,481		)	—
Proceeds from issuance of long-term debt	—			220,000			—			—						220,000
Repayment under long-term debt	—			(172,000		)	—			—						(172,000		)
Payment of debt issuance costs	—			(683		)	—			—						(683		)
Proceeds from sale of common stock, net of expenses of $15.1 million	172,481			—			—			—						172,481
Net cash (used in) provided by financing	172,481			219,798			—			—			(172,481		)	219,798
Net increase (decrease) in cash	100			944			(950		)	—			—			94
Cash
Beginning of period	—			5,056			18,600			70			—			23,726
End of period	$	100		$	6,000		$	17,650		$	70		—			$	23,820

F-35

Jones Energy, Inc

Notes to Consolidated Financial Statements (Continued)

Jones Energy, Inc.

Consolidated Statements of Cash Flows

Years Ended December 31, 2012

	Year Ended December 31, 2012
(in thousands of dollars)	JEI(Parent)		Issuers			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Consolidated
Cash flows from operating activities
Net income (loss)	$	—	$	(11,057	)	$	8,857		$	(879	)	$	(3,079	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities			(283,848		)	370,623			854			87,629
Net cash (used in) / provided by operations	—		(294,905		)	379,480			(25		)	84,550
Cash flows from investing activities
Additions to oil and gas properties	—		—			(125,493		)	—			(125,493		)
Acquisition of properties	—		—			(249,007		)	—			(249,007		)
Proceeds from sales of assets	—		—			9,158			—			9,158
Acquisition of other property, plant and equipment	—		—			(969		)	—			(969		)
Current period settlements of matured derivative contracts	—		28,675			—			—			28,675
Change in restricted cash	—		—			—			—			—
Net cash (used in) / provided by investing	—		28,675			(366,311		)	—			(337,636		)
Cash flows from financing activities
Proceeds from issuance of long-term debt	—		233,243			—			—			233,243
Repayment under long-term debt	—		(38,243		)	—			—			(38,243		)
Payment of debt issuance costs	—		(9,324		)	—			—			(9,324		)
Issuance of preferred units	—		85,000			—			—			85,000
Net cash provided by financing	—		270,676			—			—			270,676
Net increase (decrease) in cash	—		4,446			13,169			(25		)	17,590
Cash
Beginning of period	—		610			5,431			95			6,136
End of period	$	—	$	5,056		$	18,600		$	70		$	23,726

F-36

Jones Energy, Inc.

Supplemental Information on Oil and Gas Producing Activities (Unaudited)

Costs Incurred

Costs incurred for oil and gas property acquisitions, exploration and development for the last three years are as follows:

(in thousands of dollars)	2013		2012		2011
Property acquisitions:
Unproved	$	51,266	$	69,725	$	—
Proved	142,230		182,200		168,480
Exploration	1,710		356		780
Development	240,412		125,493		156,628
Asset retirement costs	1,822		662		418
Total costs incurred	$	437,440	$	378,436	$	326,306

Capitalized Costs

Capitalized costs for our oil and gas properties consisted of the following at the end of each of the following years:

(in thousands)	2013			2012
Unproved properties	$	114,457		$	137,254
Proved properties	1,568,564			1,127,285
	1,683,021			1,264,539
Accumulated depletion and impairment	(370,470		)	(257,195		)
Net capitalized costs	$	1,312,551		$	1,007,344

Reserves

Users of this information should be aware that the process of estimating quantities of proved and proved developed oil and gas reserves (including natural gas liquids) is very complex, requiring significant subjective decisions in the evaluation of all available geological, engineering and economic data for each reservoir. The data for a given reservoir also may change substantially over time as a result of numerous factors, including additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. Consequently, material revisions to existing reserve estimates may occur from time to time.

The following tables set forth the Company’s total proved reserves and the changes in the Company’s total proved reserves. These reserve estimates are based in part on reports prepared by Cawley, Gillespie & Associates, Inc. (“Cawley Gillespie”), independent petroleum engineers, utilizing data compiled by us. In preparing its reports, Cawley Gillespie evaluated properties representing all of the Company’s proved reserves at December 31, 2013, 2012 and 2011. The Company’s proved reserves are located onshore in the United States. There are many uncertainties inherent in estimating proved reserve quantities, and projecting future production rates and the timing of future development expenditures. In addition, reserve estimates of new discoveries are more imprecise than those of properties with production history. Accordingly, these estimates are subject to change as additional information becomes available. Proved reserves are the estimated quantities of natural gas, natural gas liquids and oil that geoscience and engineering data demonstrate with reasonable certainty to be economically producible in future years from known oil and natural gas reservoirs under existing

F-37

economic conditions, operating methods and government regulations at the end of the respective years. Proved developed reserves are those reserves expected to be recovered through existing wells with existing equipment and operating methods.

	Crude Oil (MBbls)		NGL (MBbls)		Natural Gas (MMcf)		Total (MBoe)(1)
Estimated Proved Reserves
December 31, 2010	5,991		9,953		108,634		34,050
Extensions and discoveries	2,419		7,881		50,310		18,685
Production	(811	)	(1,215	)	(11,438	)	(3,932	)
Purchases of minerals in place	378		18,182		117,489		38,142
Sales of minerals in place	(114	)	(201	)	(2,688	)	(763	)
Revisions of previous estimates	(423	)	6		(17,728	)	(3,372	)
December 31, 2011	7,440		34,606		244,579		82,810
Extensions and discoveries	286		1,766		11,727		4,007
Production	(742	)	(1,770	)	(13,980	)	(4,842	)
Purchases of minerals in place	6,056		5,799		36,842		17,995
Sales of minerals in place	(8	)	(53	)	(309	)	(113	)
Revisions of previous estimates	(492	)	(5,602	)	(50,779	)	(14,557	)
December 31, 2012	12,540		34,746		228,080		85,300
Extensions and discoveries	3,786		5,710		39,799		16,129
Production	(1,557	)	(1,724	)	(17,575	)	(6,210	)
Purchases of minerals in place	3,275		4,418		35,023		13,530
Sales of minerals in place	—		—		583		97
Revisions of previous estimates	(1,356	)	(10,235	)	(49,262	)	(19,801	)
December 31, 2013	16,688		32,915		236,648		89,045

Revision of previous estimates

For the year ended December 31, 2013, the Company had net negative revisions of 19,801 MBoe, of which 15,518 MBoe was related to the expiration of the Company’s JDA with Southridge. The remaining net negative revisions of 4,283 MBoe were due to a combination of production performance in the Cleveland and Woodford, prices and other changes.

For the year ended December 31, 2012, the Company had net negative revisions of 14,557 MBoe primarily due to the removal of certain proved undeveloped reserves in the Atoka formation, production performance in the Woodford formation and decreased gas prices in the Cleveland.

For the year ended December 31, 2011, the Company had net negative revisions of 3,372 MBoe primarily due to the removal of certain proved undeveloped reserves in the Granite Wash, Cleveland, and Atoka formations due to decreased gas prices. This was partially offset by the addition of certain

F-38

proved undeveloped reserves in the more liquid-rich area of the Cleveland formation due to increased oil prices.

	Crude Oil (MBbls)	NGL (MBbls)	Natural Gas (MMcf)	Total (MBoe)(1)
Estimated Proved Reserves
December 31, 2011
Proved developed	2,535	14,020	110,433	34,961
Proved undeveloped	4,905	20,586	134,146	47,849
Total proved reserves	7,440	34,606	244,579	82,810
December 31, 2012
Proved developed	4,262	16,320	110,956	39,075
Proved undeveloped	8,278	18,426	117,124	46,225
Total proved reserves	12,540	34,746	228,080	85,300
December 31, 2013
Proved developed	7,129	19,101	139,623	49,501
Proved undeveloped	9,559	13,814	97,025	39,544
Total proved reserves	16,688	32,915	236,648	89,045

(1)Barrels of oil equivalent determined using the ratio of six Mcf of natural gas to one Bbl of crude oil or natural gas liquids.

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

The following information was developed utilizing procedures prescribed by FASB Accounting Standards Codification Topic 932, Extractive Industries—Oil and Gas (Topic 932). The “standardized measure of discounted future net cash flows” should not be viewed as representative of the current value of our proved oil and gas reserves. It and the other information contained in the following tables may be useful for certain comparative purposes, but should not be solely relied upon in evaluating the Company or its performance.

In reviewing the information that follows, the following factors should be taken into account:

·future costs and sales prices will probably differ from those required to be used in these calculations;

·actual production rates for future periods may vary significantly from the rates assumed in the calculations;

·future tax rates, deductions and credits are calculated under current laws, which may change in future years;

·a 10% discount rate may not be reasonable relative to risk inherent in realizing future net oil and natural gas revenues.

Under the standardized measure, future cash inflows were estimated by using the average of the historical unweighted first-day-of-the-month prices of oil and natural gas for the prior twelve month periods ended December 31, 2013, 2012 and 2011. Future cash inflows do not reflect the impact of open hedge positions. Future cash inflows were reduced by estimated future development and production costs based on year-end costs in order to arrive at net cash flows. Use of a 10% discount rate, first-day-of- the-month prices and year-end costs are required by ASC 932.

F-39

In general, management does not rely on the following information in making investment and operating decisions. Such decisions are based upon a wide range of factors, including estimates of probable as well as proved reserves and varying price and cost assumptions considered more representative of a range of possible outcomes.

The standardized measure of discounted future net cash flows from the Company’s estimated proved oil and natural gas reserves follows:

(in thousands)	2013			2012			2011
Future cash inflows	$	3,213,718		$	2,746,767		$	3,279,260
Less related future:
Production costs	(734,974		)	(612,054		)	(648,035		)
Development costs	(549,343		)	(529,692		)	(556,302		)
Income tax expenses	(129,497		)	—			—
Future net cash flows	1,799,904			1,605,021			2,074,923
10% annual discount for estimated timing of cash flows	(859,395		)	(823,001		)	(1,159,116		)
Standardized measure of discounted future net cash flows	$	940,509		$	782,020		$	915,807

A summary of the changes in the standardized measure of discounted future net cash flows applicable to proved natural gas and crude oil reserves follows:

(in thousands)	2013			2012			2011
Balance, beginning of period	$	782,020		$	915,807		$	354,507
Net change in sales and transfer prices, net of production expenses	77,280			(336,855		)	133,740
Changes in estimated future development costs	(9,706		)	67,495			3,391
Sales and transfers of oil and gas produced during the period	(224,739		)	(119,931		)	(139,600		)
Net change due to extensions and discoveries	239,844			37,723			298,299
Net change due to purchases of minerals in place	149,619			197,740			230,687
Net change due to sales of minerals in place	(337		)	(1,578		)	(10,969		)
Net change due to revisions in quantity estimates	(168,438		)	(144,901		)	(48,425		)
Previously estimated development costs incurred during the period	110,783			99,513			83,287
Net change in income taxes	(76,965		)	—			—
Accretion of discount	59,621			91,581			35,451
Other	1,527			(24,574		)	(24,561		)
Balance, end of period	$	940,509		$	782,020		$	915,807

F-40

Supplemental Quarterly Financial Information (Unaudited)

Following is a summary of the Company’s results of operations by quarter for the years ended December 31, 2013 and 2012.

	2013
(in thousands except per share data)	First Quarter			Second Quarter		Third Quarter			Fourth Quarter			Full Year
Revenues	$	55,480		$	64,526	$	68,851		$	70,312		$	259,169
Operating income	18,047			20,251		12,095			5,359			55,752
Net income (loss)	(1,452		)	48,417		(15,483		)	(9,077		)	22,405
Net income (loss) attributable to non-controlling interests						(14,623		)	(7,751		)	24,591
Net loss attributable to controlling interests						(860		)	(1,326		)	(2,186		)
Basic and diluted earnings per share						$	(0.07	)	$	(0.11	)	$	(0.17	)

	2012
	First Quarter		Second Quarter		Third Quarter			Fourth Quarter			Full Year
Revenues	$	42,797	$	31,354	$	31,935		$	43,728		$	149,814
Operating income (loss)	12,989		1,852		(324		)	(9,677		)	4,840
Net income (loss)	15,323		26,803		(24,527		)	(20,678		)	(3,079		)

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. Therefore, we have revised our Supplemental Quarterly Financial Information for the quarters ended March 31, 2012, June 30, 2012, September 30, 2012, December 31, 2012, March 31, 2013, June 30, 2013 and September 30, 2013 to reflect additional interest expense on obligations that are unrelated to our credit agreements discussed in Note 6. These revisions had the effect of:

·decreasing net income (loss) by $0.1 million, $0.1 million, $0.2 million, $0.2 million, $0.2 million, $0.2 million, and $0.3 million for the quarters ended March 31, 2012, June 30, 2012, September 30, 2012, December 31, 2012, March 31, 2013, June 30, 2013 and September 30, 2013, respectively;

·decreasing net income (loss) attributable to non-controlling interests by $0.2 million, for each of the quarters ended March 31, 2013, June 30, 2013 and September 30, 2013; and

·decreasing net loss attributable to controlling interests by $39 thousand for the quarter ended September 30, 2013.

We have determined that these errors are not material to any of our previously issued interim or annual consolidated financial statements, therefore, no restatements have been made to the 2013 quarterly financial statements included in our previously filed Form 10-Qs for this matter. Additionally, revisions to the three month period ended March 31, 2013, the three and six month periods ended June 30, 2013 and the three and nine month periods ended September 30, 2013 will be made when they are next filed in the Company’s quarterly financial statements on Form 10-Q for the quarters ending March 31, 2014, June 30, 2014 and September 30, 2014, respectively.

F-41

XML

Fair Value Measurement (Details) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Fair Value Measurements
Current assets	$ 8,837	$ 17,648
Long-term assets	25,398	25,199
Current liabilities	10,664	4,035
Long-term liabilities	190	7,657
Level 2 | Commodity Price Hedges
Fair Value Measurements
Current assets	8,837	17,648
Long-term assets	25,967	24,756
Current liabilities	10,188	2,992
Long-term liabilities		6,739
Level 3 | Commodity Price Hedges
Fair Value Measurements
Long-term assets	(569)	443
Current liabilities	476	1,043
Long-term liabilities	190	918
Total | Commodity Price Hedges
Fair Value Measurements
Current assets	8,837	17,648
Long-term assets	25,398	25,199
Current liabilities	10,664	4,035
Long-term liabilities	$ 190	$ 7,657

XML

Subsidiary Guarantors (Details 5) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Cash flows from operating activities
Net income (loss)	$ 22,405,000	$ (3,079,000)	$ 60,326,000
Adjustments to reconcile net income (loss) to net cash provided by operating activities	141,491,000	87,629,000
Net cash provided by operations	163,896,000	84,550,000	120,217,000
Cash flows from investing activities
Additions to oil and gas properties	(197,618,000)	(125,493,000)	(157,046,000)
Acquisition of properties	(193,496,000)	(249,007,000)	(168,480,000)
Proceeds from sales of assets	1,607,000	9,158,000	6,747,000
Acquisition of other property, plant and equipment	(1,634,000)	(969,000)	(1,735,000)
Current period settlements of matured derivative contracts	7,586,000	28,675,000	1,551,000
Change in restricted cash	(45,000)
Net cash (used in) / provided by investing	(383,600,000)	(337,636,000)	(318,963,000)
Cash flows from financing activities
Proceeds from issuance of long-term debt	220,000,000	233,243,000	316,500,000
Repayment under long-term debt	(172,000,000)	(38,243,000)	(126,500,000)
Payment of debt issuance costs	(683,000)	(9,324,000)	(3,678,000)
Issuance of preferred units		85,000,000
Proceeds from sale of common stock, net of expenses of $15.1 million	172,481,000
Net cash provided by financing	219,798,000	270,676,000	186,322,000
Net increase (decrease) in cash	94,000	17,590,000	(12,424,000)
Cash
Beginning of period	23,726,000	6,136,000	18,560,000
End of period	23,820,000	23,726,000	6,136,000
Payment of stock issuance expenses	15,100,000
Eliminations
Cash flows from operating activities
Net income (loss)	3,400,000
Adjustments to reconcile net income (loss) to net cash provided by operating activities	(3,400,000)
Cash flows from investing activities
Investment in subsidiary	172,481,000
Net cash (used in) / provided by investing	172,481,000
Cash flows from financing activities
Proceeds from investment by JEI	(172,481,000)
Net cash provided by financing	(172,481,000)
JEI (Parent)
Cash flows from operating activities
Net income (loss)	(2,186,000)
Adjustments to reconcile net income (loss) to net cash provided by operating activities	2,286,000
Net cash provided by operations	100,000
Cash flows from investing activities
Investment in subsidiary	(172,481,000)
Net cash (used in) / provided by investing	(172,481,000)
Cash flows from financing activities
Proceeds from sale of common stock, net of expenses of $15.1 million	172,481,000
Net cash provided by financing	172,481,000
Net increase (decrease) in cash	100,000
Cash
End of period	100,000
Payment of stock issuance expenses	15,100,000
Issuers
Cash flows from operating activities
Net income (loss)	(37,047,000)	(11,057,000)
Adjustments to reconcile net income (loss) to net cash provided by operating activities	(189,393,000)	(283,848,000)
Net cash provided by operations	(226,440,000)	(294,905,000)
Cash flows from investing activities
Current period settlements of matured derivative contracts	7,586,000	28,675,000
Net cash (used in) / provided by investing	7,586,000	28,675,000
Cash flows from financing activities
Proceeds from investment by JEI	172,481,000
Proceeds from issuance of long-term debt	220,000,000	233,243,000
Repayment under long-term debt	(172,000,000)	(38,243,000)
Payment of debt issuance costs	(683,000)	(9,324,000)
Issuance of preferred units		85,000,000
Net cash provided by financing	219,798,000	270,676,000
Net increase (decrease) in cash	944,000	4,446,000
Cash
Beginning of period	5,056,000	610,000
End of period	6,000,000	5,056,000
Guarantor Subsidiaries
Cash flows from operating activities
Net income (loss)	58,705,000	8,857,000
Adjustments to reconcile net income (loss) to net cash provided by operating activities	331,265,000	370,623,000
Net cash provided by operations	389,970,000	379,480,000
Cash flows from investing activities
Additions to oil and gas properties	(197,618,000)	(125,493,000)
Acquisition of properties	(193,496,000)	(249,007,000)
Proceeds from sales of assets	963,000	9,158,000
Acquisition of other property, plant and equipment	(724,000)	(969,000)
Change in restricted cash	(45,000)
Net cash (used in) / provided by investing	(390,920,000)	(366,311,000)
Cash flows from financing activities
Net increase (decrease) in cash	(950,000)	13,169,000
Cash
Beginning of period	18,600,000	5,431,000
End of period	17,650,000	18,600,000
Non-Guarantor Subsidiaries
Cash flows from operating activities
Net income (loss)	(467,000)	(879,000)
Adjustments to reconcile net income (loss) to net cash provided by operating activities	733,000	854,000
Net cash provided by operations	266,000	(25,000)
Cash flows from investing activities
Acquisition of properties	644,000
Acquisition of other property, plant and equipment	(910,000)
Net cash (used in) / provided by investing	(266,000)
Cash flows from financing activities
Net increase (decrease) in cash		(25,000)
Cash
Beginning of period	70,000	95,000
End of period	$ 70,000	$ 70,000

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Benefit Plans (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Benefit Plans
Amount contributed to the Plan	$ 0.3	$ 0.2

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Monarch Investment (Details) (USD $)	12 Months Ended	0 Months Ended
	Dec. 31, 2013	May 07, 2013
Monarch Investment
Compensation expense recognized under management distributions and incentive plan	$ 2,719,000
Deferred revenue recorded	14,531,000
Equity interests issued to the Company in connection with the marketing agreement
Monarch Investment
Compensation expense recognized under management distributions and incentive plan	300,000
Deferred revenue recorded	15,000,000
Equity interests issued to the Company in connection with the marketing agreement | Equity interests | Monarch Natural Gas Holdings, LLC
Monarch Investment
Equity interests distributed to the entity's owners (as a percent)		67.00%
Equity interests distributed to the entity's owners		10,000,000
Equity interests distributed to a member of management (as a percent)		16.00%
Equity interests reserved for distribution to management through incentive plan (as a percent)		17.00%
Monarch
Monarch Investment
Amortization of deferred revenue	500,000
Monarch | Equity interests issued to the Company in connection with the marketing agreement | Equity interests | Monarch Natural Gas Holdings, LLC
Monarch Investment
Estimated fair value of equity interests issued to the entity		$ 15,000,000

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Significant Accounting Policies (Details) (USD $)	12 Months Ended
	Dec. 31, 2013 item	Dec. 31, 2012 item
Segment Information
Number of industry segments	1
Number of geographic areas in which the entity operates	1
Accounts Receivable
Payment period of oil and gas sales, Minimum	30 days
Payment period of oil and gas sales, Maximum	60 days
Period within which joint interest owner obligations becomes due	30 days
Interest charged on past-due balances	0
Accounts receivable - Oil and gas sales | Credit risk
Concentration of Risk
Concentration risk (as a percent)	79.00%	92.00%
Number of customers	8	8
Accounts receivable - Joint interest owners | Credit risk
Concentration of Risk
Concentration risk (as a percent)	77.00%	72.00%
Number of customers	5	5

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Derivative Instruments and Hedging Activities (Tables)

12 Months Ended

Dec. 31, 2013

Derivative Instruments and Hedging Activities

Schedule of various commodity derivatives in place to offset uncertain price fluctuations that could affect the entity's future operations

	December 31, 2013
		Low			High			Weighted Average			Final 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

	December 31, 2012
		Low			High			Weighted Average			Final Expiration
Oil swaps	Exercise price	$	81.00		$	104.45		$	89.60
	Barrels per month		24,000			143,116			89,323		December 2017
Natural gas swaps	Exercise price	$	3.52		$	6.90		$	4.96
	mmbtu per month		430,000			1,110,000			767,053		December 2017
Basis swaps	Contract differential	$	(0.65	)	$	(0.03	)	$	(0.31	)
	mmbtu per month		320,000			850,000			484,615		March 2016
Natural gas liquids swaps	Exercise price	$	6.72		$	97.13		$	33.81
	Barrels per month		2,000			144,973			55,616		December 2017

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Subsidiary Guarantors (Details) (Senior notes, 2022 Notes, Subsequent events, USD $) In Millions, unless otherwise specified	Apr. 01, 2014
Senior notes | 2022 Notes | Subsequent events
Subsidiary Guarantors
Issuance of debt	$ 550.0
Stated interest rate (as a percent)	6.75%

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Derivative Instruments and Hedging Activities (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Basis swaps | Low
Derivative instruments and hedging activities
Nonmonetary notional amount	320,000	320,000
Contract differential (in dollars per mmbtu)	(0.43)	(0.65)
Basis swaps | High
Derivative instruments and hedging activities
Nonmonetary notional amount	690,000	850,000
Contract differential (in dollars per mmbtu)	(0.11)	(0.03)
Basis swaps | Weighted Average
Derivative instruments and hedging activities
Nonmonetary notional amount	467,037	484,615
Contract differential (in dollars per mmbtu)	(0.34)	(0.31)
Oil | Swaps | Low
Derivative instruments and hedging activities
Exercise price (in dollars per barrels)	81.70	81.00
Nonmonetary notional amount	29,000	24,000
Oil | Swaps | High
Derivative instruments and hedging activities
Exercise price (in dollars per barrels)	102.84	104.45
Nonmonetary notional amount	161,613	143,116
Oil | Swaps | Weighted Average
Derivative instruments and hedging activities
Exercise price (in dollars per barrels)	89.03	89.60
Nonmonetary notional amount	96,149	89,323
Natural gas | Swaps | Low
Derivative instruments and hedging activities
Exercise price (in dollars per mmbtu)	3.88	3.52
Nonmonetary notional amount	510,000	430,000
Natural gas | Swaps | High
Derivative instruments and hedging activities
Exercise price (in dollars per mmbtu)	6.90	6.90
Nonmonetary notional amount	1,290,000	1,110,000
Natural gas | Swaps | Weighted Average
Derivative instruments and hedging activities
Exercise price (in dollars per mmbtu)	4.26	4.96
Nonmonetary notional amount	830,275	767,053
Natural gas liquids | Swaps | Low
Derivative instruments and hedging activities
Exercise price (in dollars per barrels)	6.72	6.72
Nonmonetary notional amount	2,000	2,000
Natural gas liquids | Swaps | High
Derivative instruments and hedging activities
Exercise price (in dollars per barrels)	95.24	97.13
Nonmonetary notional amount	118,000	144,973
Natural gas liquids | Swaps | Weighted Average
Derivative instruments and hedging activities
Exercise price (in dollars per barrels)	32.98	33.81
Nonmonetary notional amount	46,646	55,616
Commodity derivatives
Derivative instruments and hedging activities
Net gains (Loss) recognized on derivative instruments	$ (2.6)	$ 16.7	$ 34.5

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Significant Accounting Policies (Details 5)	0 Months Ended	12 Months Ended
	Sep. 04, 2013 item	Dec. 31, 2013
Management incentive plan | JEH | Management units | Common Class B
Stock Compensation
Unvested units and shares		457,150
Management incentive plan | JEH | Management units | Dual vesting
Stock Compensation
Percentage of units vesting in equal annual installments		60.00%
Vesting term		5 years
Percentage of units vesting upon restructuring event		40.00%
Management incentive plan | JEH | Management units | Single vesting
Stock Compensation
Vesting term		5 years
2013 Omnibus Incentive Plan | Class A common stock
Stock Compensation
Shares reserved (in shares)		3,850,000
Awards granted (in shares)		0
2013 Omnibus Incentive Plan | Restricted stock
Stock Compensation
Vesting term		1 year
Number of outside members of the Board of Directors to whom awards were granted	4
Awards granted, per outside member of the Board of Directors (in shares)	6,645

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Subsidiary Guarantors (Details 3) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Operating revenues
Oil and gas sales	$ 258,063	$ 148,967	$ 167,261
Other revenues	1,106	847	1,022
Total operating revenues	259,169	149,814	168,283
Operating costs and expenses
Lease operating	27,781	23,097	21,548
Production taxes	12,865	5,583	5,333
Exploration	1,710	356	780
Depletion, depreciation and amortization	114,136	80,709	68,906
Impairment of oil and gas properties	14,415	18,821	31,970
Accretion of discount	608	533	413
General and administrative (including non-cash compensation expense)	31,902	15,875	16,679
Total operating expenses	203,417	144,974	145,629
Operating income	55,752	4,840	22,654
Other income (expense)
Interest expense	(30,774)	(25,292)	(21,994)
Net gain (loss) on commodity derivatives	(2,566)	16,684	34,490
Gain on bargain purchase			26,208
Gain (loss) on sales of assets	(78)	1,162	(859)
Other income (expense), net	(33,418)	(7,446)	37,845
Income (loss) before income tax	22,334	(2,606)	60,499
Income tax provision
Current	85
Deferred	(156)	473	173
Total income tax provision	(71)	473	173
Net income (loss)	22,405	(3,079)	60,326
Net income attributable to non-controlling interests	24,591
Net income (loss) attributable to controlling interests	(2,186)	(3,079)	60,326
Eliminations
Other income (expense)
Equity interest in Income	3,400
Income tax provision
Net income (loss)	3,400
Net income attributable to non-controlling interests	24,591
JEI (Parent)
Other income (expense)
Equity interest in Income	(3,400)
Income tax provision
Current	85
Deferred	(1,299)
Total income tax provision	(1,214)
Net income (loss)	(2,186)
Net income (loss) attributable to controlling interests	(2,186)
Issuers
Operating revenues
Other revenues	469
Total operating revenues	469
Operating costs and expenses
General and administrative (including non-cash compensation expense)	4,154	2,589
Total operating expenses	4,154	2,589
Operating income	(3,685)	(2,589)
Other income (expense)
Interest expense	(29,653)	(24,679)
Net gain (loss) on commodity derivatives	(2,566)	16,684
Other income (expense), net	(32,219)	(7,995)
Income (loss) before income tax	(35,904)	(10,584)
Income tax provision
Deferred	1,143	473
Total income tax provision	1,143	473
Net income (loss)	(37,047)	(11,057)
Net income (loss) attributable to controlling interests		(11,057)
Guarantor Subsidiaries
Operating revenues
Oil and gas sales	258,063	148,967
Other revenues	637	847
Total operating revenues	258,700	149,814
Operating costs and expenses
Lease operating	27,781	23,097
Production taxes	12,865	5,583
Exploration	1,710	356
Depletion, depreciation and amortization	114,046	80,554
Impairment of oil and gas properties	14,415	18,821
Accretion of discount	608	533
General and administrative (including non-cash compensation expense)	27,490	12,562
Total operating expenses	198,915	141,506
Operating income	59,785	8,308
Other income (expense)
Interest expense	(1,121)	(613)
Gain (loss) on sales of assets	41	1,162
Other income (expense), net	(1,080)	549
Income (loss) before income tax	58,705	8,857
Income tax provision
Net income (loss)	58,705	8,857
Net income (loss) attributable to controlling interests		8,857
Non-Guarantor Subsidiaries
Operating costs and expenses
Depletion, depreciation and amortization	90	155
General and administrative (including non-cash compensation expense)	258	724
Total operating expenses	348	879
Operating income	(348)	(879)
Other income (expense)
Gain (loss) on sales of assets	(119)
Other income (expense), net	(119)
Income (loss) before income tax	(467)	(879)
Income tax provision
Net income (loss)	(467)	(879)
Net income (loss) attributable to controlling interests		$ (879)

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Commitments and Contingencies (Details) (USD $)	12 Months Ended
	Dec. 31, 2013 sqft	Dec. 31, 2012	Dec. 31, 2011
Commitments and Contingencies
Leased area of office space in Austin, TX (in square feet)	31,000
Future minimum payments for noncancellable operating leases
2014	$ 586,000
2015	482,000
2016	458,000
2017	147,000
Total	1,673,000
Rent expense under operating leases	$ 800,000	$ 800,000	$ 700,000

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Significant Accounting Policies

12 Months Ended

Dec. 31, 2013

Significant Accounting Policies

Significant Accounting Policies

2. Significant Accounting Policies

Basis of Presentation

        The accompanying 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 December 31, 2013, 2012 and 2011, and the years then ended include the Company and all of its subsidiaries.

Segment Information

        The Company operates in one industry segment, which is the exploration, development and production of oil and natural gas, and all of its operations are conducted in one geographic area of the United States.

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 and liabilities, fair value associated with business combinations, and asset retirement obligations ("ARO").

Financial Instruments

        Cash, accounts receivable and accounts payable are recorded at cost. The fair value of accounts receivable and accounts payable are not materially different from their carrying amounts because of the short-term nature of these instruments. The carrying values of outstanding balances under the Company's credit agreements represent fair value because the agreements have variable interest rates, which are reflective of the Company's credit risk. Derivative instruments are recorded at fair value, as discussed below.

Cash

        Cash and cash equivalents include highly liquid investments with a maturity of three months or less. At times, the amount of cash on deposit in financial institutions exceeds federally insured limits. Management monitors the soundness of the financial institutions and believes the Company's risk is negligible.

Accounts Receivable

        Accounts receivable—Oil and gas sales consist of uncollateralized accrued revenues due under normal trade terms, generally requiring payment within 30 to 60 days of production. Accounts receivable—Joint interest owners consist of uncollateralized joint interest owner obligations due within 30 days of the invoice date. Accounts receivable—Other consist primarily of severance tax refunds due from state agencies. No interest is charged on past-due balances. The Company routinely assesses the recoverability of all material trade, joint interest and other receivables to determine their collectability, and reduces the carrying amounts by a valuation allowance that reflects management's best estimate of the amounts that may not be collected. As of December 31, 2013 and 2012, the Company did not have significant allowances for doubtful accounts.

Concentration of Risk

        Substantially all of the Company's accounts receivable are related to the oil and gas industry. This concentration of entities may affect the Company's overall credit risk in that these entities may be affected similarly by changes in economic and other conditions. As of December 31, 2013, 79% of Accounts receivable—Oil and gas sales are due from 8 purchasers and 77% of Accounts receivable—Joint interest owners are due from 5 working interest owners. As of December 31, 2012, 92% of Accounts receivable—Oil and gas sales were due from 8 purchasers, and 72% of 2012 Accounts receivable—Joint interest owners were due from 5 working interest owners. If any or all of these significant counterparties were to fail to pay amounts due to the Company, the Company's financial position and results of operations could be materially and adversely affected.

Dependence on Major Customers

        The Company maintains a portfolio of crude oil and natural gas marketing contracts with large, established refiners and oil and gas purchasers. During the year ended December 31, 2013, the largest purchasers were PVR Midstream, Unimark LLC, Mercuria, Valero, and Plains Marketing, which accounted for approximately 15%, 13%, 13%, 13% and 6% of consolidated oil and gas sales, respectively. During the year ended December 31, 2012, the largest purchasers were Unimark LLC, Mercuria, PVR Midstream, and Plains Marketing, which accounted for approximately 24%, 18%, 18% and 15% of consolidated oil and gas sales, respectively. During the year ended December 31, 2011, the largest purchasers were Plains Marketing, PVR Midstream, Unimark LLC, and Valero Marketing, which accounted for approximately 27%, 22%, 13% and 9% of consolidated oil and gas sales, respectively.

        Management believes that there are alternative purchasers and that it may be necessary to establish relationships with such new purchasers. However, there can be no assurance that the Company can establish such relationships and that those relationships will result in an increased number of purchasers. Although the Company is exposed to a concentration of credit risk, management believes that all of the Company's purchasers are credit worthy.

Dependence on Suppliers

        The Company's industry is cyclical, and from time to time, there is a shortage of drilling rigs, equipment, services, supplies and qualified personnel. During these periods, the costs and delivery times of rigs, equipment, services and supplies are substantially greater. If the unavailability or high cost of drilling rigs, equipment, services, supplies or qualified personnel were particularly severe in its areas of operation, the Company could be materially and adversely affected. Management believes that there are potential alternative providers of drilling and completion services and that it may become necessary to establish relationships with new contractors. However, there can be no assurance that the Company can establish such relationships and that those relationships will result in increased availability of drilling rigs or other services, or that they could be obtained on the same terms.

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 December 31, 2013 and 2012:

(in thousands of dollars)	2013			2012
Mineral interests in properties
Unproved	$	114,457		$	137,254
Proved		958,816			737,558
Wells and equipment and related facilities		609,748			389,727
		1,683,021			1,264,539
Less: Accumulated depletion and impairment		(370,470	)		(257,195	)
Net oil and gas properties	$	1,312,551		$	1,007,344

        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. In 2013, we had no material capitalized costs associated with exploratory wells. As of December 31, 2012, there were no costs capitalized in connection with exploratory wells in progress.

        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 in 2013 as no projects lasted more than six months. During the year ended December 31, 2012, the Company capitalized $0.1 million in interest. Costs incurred to maintain wells and related equipment are charged to expense as incurred.

        On the sale or retirement of a proved field, the cost and related accumulated depletion, depreciation and amortization are eliminated from the field accounts, and the resultant gain or loss is recognized.

        Capitalized amounts attributable to proved oil and gas properties are depleted by the unit-of-production method over proved reserves, using the unit conversion ratio of six thousand cubic feet of gas to one barrel of oil equivalent. Depletion of the costs of wells and related equipment and facilities, including capitalized asset retirement costs, net of salvage values, is computed using proved developed reserves. The reserve base used to calculate depreciation, depletion, and amortization for leasehold acquisition costs and the cost to acquire proved properties is the sum of proved developed reserves and proved undeveloped reserves. Depletion of oil and gas properties amounted to $113.3 million, $79.9 million and $68.2 million for the years ended December 31, 2013, 2012 and 2011, respectively.

        The Company reviews its proved oil and natural gas properties, including related wells and equipment, for impairment by comparing expected undiscounted future cash flows at a producing field level to the net capitalized cost of the asset. If the future undiscounted cash flows, based on the Company's estimate of future commodity prices, operating costs, and production, are lower than the net capitalized cost, the capitalized cost is reduced to fair value. Fair value is calculated by discounting the future cash flows at an appropriate risk-adjusted discount rate. Due to the significant assumptions associated with the inputs and calculations described, the fair value of oil and gas properties used in estimating impairment represents a nonrecurring Level 3 measurement. The Company incurred impairment charges of $18.8 million and $19.8 million related to its proved oil and natural gas properties and equipment in 2012 and 2011, respectively. No impairments of proved properties were recorded in 2013.

        The Company evaluates its unproved properties for impairment on a property-by-property basis. The Company's unproved property consists of acquisition costs related to its undeveloped acreage. The Company reviews the unproved property for indicators of impairment based on the Company's current exploration plans with consideration given to results of any drilling and seismic activity during the period and known information regarding exploration activity by other companies on adjacent blocks. In the fourth quarter of 2013, the Company recorded an impairment charge of $14.4 million related to its unproved Southridge properties. As the Company did not drill the required number of wells by October 31, 2013 necessary to keep its joint development agreement with Southridge in effect, the Company lost its right to the undeveloped acreage. The Company incurred no impairment charges related to its unproved properties in 2012. In 2011, the Company incurred a $12.2 million impairment charge related to its unproven properties in fields which were not expected to produce natural gas with a sufficiently high liquid content reducing the economic return of those fields. These charges represent nonrecurring Level 3 measurements. Impairment of oil and gas properties charges are recorded on the Consolidated Statement of Operations.

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

Other Property, Plant and Equipment

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

(in thousands of dollars)	2013			2012
Leasehold improvements	$	1,060		$	983
Furniture, fixtures, computers and software		2,491			2,204
Vehicles		835			719
Aircraft		910			1,295
Other		134			134
		5,430			5,335
Less: Accumulated depreciation and amortization		(1,986	)		(1,937	)
Net other property, plant and equipment	$	3,444		$	3,398

        Other property, plant and equipment is depreciated on a straight-line basis over the estimated useful lives of the property, plant and equipment, which range from three years to ten years. Depreciation and amortization of other property, plant and equipment amounted to $0.8 million, $0.8 million and $0.7 million during the years ended December 31, 2013, 2012 and 2011, respectively.

Oil and Gas Sales Payable

        Oil and gas sales payable represents amounts collected from purchasers for oil and gas sales, which are due to other revenue interest owners. Generally, the Company is required to remit amounts due under these liabilities within 60 days of receipt.

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 years ended December 31, 2013, 2012 and 2011, 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 Jones 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 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. The Company estimates an ARO for each well in the period in which it is incurred based on estimated present value of plugging and abandonment costs, increased by an inflation factor to the estimated date that the well would be plugged. The resulting liability is recorded by increasing the carrying amount of the related long-lived asset. The liability is then accreted to its then-present value each period and the capitalized cost is depleted over the useful life of the related asset. If the liability is settled for an amount other than the recorded amount, a gain or loss is recognized. The ARO is classified as current or noncurrent based on the expect timing of payments. A summary of the Company's ARO for the years ended December 31, 2013 and 2012 is as follows:

(in thousands of dollars)	2013			2012
ARO liability at beginning of year	$	9,506		$	9,563
Liabilities incurred(1)		1,515			662
Accretion of discount		608			596
Liabilities settled due to sale of related properties		(271	)		(927	)
Liabilities settled due to plugging and abandonment		(702	)		(388	)
Change in estimate		307			—
ARO liability at end of year		10,963			9,506
Less: Current portion of ARO at end of year		(2,590	)		(174	)
Total long-term ARO at end of year	$	8,373		$	9,332

(1)

Includes $824 related to wells acquired (see Note 3, "Acquisition of Properties").

Revenue Recognition

        Revenues from the sale of crude oil, natural gas, and natural gas liquids are recognized when the product is delivered at a fixed or determinable price, title has transferred, collectability is reasonably assured and evidenced by a contract. The Company follows the "sales method" of accounting for its oil and natural gas revenue, so it recognizes revenue on all crude oil, natural gas, and natural gas liquids sold to purchasers. A receivable or liability is recognized only to the extent that the Company has an imbalance on a specific property greater than the expected remaining proved reserves.

Production Costs

        Production costs, including compressor rental, pumpers' salaries, saltwater disposal, ad valorem taxes, insurance, repairs and maintenance, expensed workovers and other operating expenses are expensed as incurred and included in lease operating expense on the Consolidated Statement of Operations.

Exploration Expenses

        Exploration expenses include dry hole costs, lease extensions, delay rentals and geological and geophysical costs.

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.

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 December 31, 2013, there have been no exchanges and no liability is recorded on the Consolidated Balance Sheet.

Comprehensive Income

        The Company has no elements of comprehensive income other than net income.

Statement of Cash Flows

        The Company presents its cash flows using the indirect method.

Related Party Transactions

        In the years ended December 31, 2013, 2012 and 2011, the Company paid an annual administration fee to Metalmark of $0.7 million. This amount was charged to expense. As a result of the IPO, this fee is no longer payable to Metalmark.

        On May 7, 2013, the Company entered into a natural gas sale and purchase agreement with Monarch Natural Gas, LLC, or Monarch, under which Monarch has the first right to gather the natural gas the Company produces from the Chalker properties, process the NGLs from this natural gas production and market the processed natural gas and extracted NGLs. Under the Monarch agreement, the Company is paid a specified percentage of the value of the NGLs extracted and sold by Monarch, based on a set liquids recovery percentage, and the amount received from the sale of the residue gas, after deducting a fixed volume for fuel, lost and unaccounted for gas. For the year ended December 31, 2013, the Company produced approximately 0.8 MMBoe of natural gas and NGLs from the Chalker properties that became subject to the Monarch agreement. The initial term of the agreement runs for 10 years from the effective date of September 1, 2013. At the time the Company entered into the agreement, Metalmark Capital owned approximately 81% of the outstanding equity interests of Monarch. In addition, Metalmark Capital beneficially owns in excess of five percent of the Company's outstanding equity interests and two of our directors, Howard I. Hoffen and Gregory D. Myers, are managing directors of Metalmark Capital. In connection with the Company's entering into the Monarch agreement, Monarch issued to JEH equity interests in Monarch having a deemed value of $15 million. JEH assigned $2.4 million of the Monarch equity interests to Jonny Jones, the Company's chief executive officer and chairman of the board, and reserved $2.6 million of the Monarch equity interests to a benefit plan established for certain of the Company's officers, including Mike McConnell, Robert Brooks and Eric Niccum. The remaining $10 million of Monarch equity was distributed to certain of the pre-IPO owners, which include Metalmark Capital, Wells Fargo, the Jones family entities, and certain of the Company's officers and directors, including Jonny Jones, Mike McConnell, Robert Brooks and Eric Niccum.

Stock Compensation

        JEH implemented a management incentive plan effective January 1, 2010, 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 have a single vesting structure of 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. At December 31, 2013, there were 457,150 unvested JEH Units and shares of Class B common stock that will become convertible into a like number of shares of Class A common stock upon vesting.

        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. As of December 31, 2013 no such awards had been issued or granted to any of the Company's employees.

        On September 4, 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 grants 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.

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

Business Combinations

        For acquisitions of working interests that are accounted for as business combinations, the results of operations are included in the Consolidated Statement of Operations from the date of acquisition. Purchase prices are allocated to assets acquired based on their estimated fair values at the time of acquisition. 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. The fair value measurement is based on the assumptions of market participants and not those of the reporting entity. Therefore, entity-specific intentions do not impact the measurement of fair value. The fair value of oil and natural gas properties is determined using a risk-adjusted after-tax discounted cash flow analysis based upon significant inputs including: 1) oil and gas prices, 2) projections of estimated quantities of oil and natural gas reserves, including those classified as proved, probable and possible, 3) projections of future rates of production, 4) timing and amount of future development and operating costs, 5) projected reserve recovery factors, and 6) weighted average cost of capital.

Recent Accounting Developments

        The following recently issued accounting pronouncement has been adopted by the Company:

Offsetting Assets and Liabilities

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

XML

Long-Term Debt (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013 item	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2009 item	Dec. 19, 2013	Jun. 12, 2013
Credit agreements
Number of credit agreements	2			2
Total interest and commitment fees	$ 27.0	$ 21.2	$ 18.2
Revolver
Credit agreements
Borrowing base					575.0	500.0
Frequency of interest payments	3 months
Average interest rates (as a percent)	3.01%	3.30%
Average outstanding balance	384.9	306.8
Repayment of borrowings	167.0
Revolver | Base rate
Credit agreements
Reference rate	base rate (LIBOR or prime)
Revolver | Base rate | Minimum
Credit agreements
Margin interest rate (as a percent)	0.50%
Revolver | Base rate | Maximum
Credit agreements
Margin interest rate (as a percent)	2.50%
Term Loan
Credit agreements
Frequency of interest payments	3 months
Average outstanding balance	$ 160.0	$ 121.3
Average interest rate (as a percent)	9.19%	9.16%
Term Loan | Base rate
Credit agreements
Reference rate	base rate (LIBOR, prime, or federal funds)
Term Loan | Base rate | Minimum
Credit agreements
Margin interest rate (as a percent)	6.00%
Term Loan | Base rate | Maximum
Credit agreements
Margin interest rate (as a percent)	7.00%

XML

Income Taxes (Tables)

12 Months Ended

Dec. 31, 2013

Income Taxes

Schedule of income tax provision

	Year Ended December 31,
(in thousands of dollars)	2013			2012		2011
Current tax expense
Federal	$	85		$	—	$	—
State		—			—		—
Total current expense		85			—		—
Deferred tax expense (benefit)
Federal		(1,260	)		—		—
State		1,104			473		173
Total deferred expense (benefit)		(156	)		473		173
Total tax expense (benefit)		(71	)		473		173
Tax benefit attributable to controlling interests		(1,223	)		—		—
Tax expense attributable to non-controlling interests		1,152			473		173
Total tax expense (benefit)	$	(71	)	$	473	$	173

Schedule of reconciliation of the Company's provision for income taxes as reported and the amount computed by multiplying income before taxes, less non-controlling interest, by the U.S. federal statutory rate

(in thousands of dollars)	December 31, 2013
Provision calculated at federal statutory income tax rate:
Net income before taxes	$	22,334
Statutory rate		35	%
Income tax expense computed at statutory rate		7,817
Less: Non-controlling interests		(9,009	)
Income tax benefit attributable to controlling interests		(1,192	)
State and local income taxes, net of federal benefit		(49	)
Other		18
Tax benefit attributable to controlling interests		(1,223	)
Tax expense attributable to non-controlling interests		1,152
Total income tax benefit	$	(71	)

Schedule of significant components of the Company's deferred tax assets and deferred tax liability

	As of December 31,
(in thousands of dollars)	2013			2012
Deferred tax assets
Investment in consolidated subsidiary JEH	$	526		$	—
Net operating loss		649			—
Alternative minimum tax credits		86			—
State deferred tax asset		52			—
Total deferred tax assets		1,313			—
Deferred tax liabilities
State deferred tax liability		3,093			1,936
Total deferred tax liabilities		3,093			1,936
Net deferred tax assets (liabilities)		(1,780	)		(1,936	)
Valuation allowance		—			—
Net deferred tax assets (liabilities)	$	(1,780	)	$	(1,936	)

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Commitments and Contingencies (Tables)

12 Months Ended

Dec. 31, 2013

Commitments and Contingencies

Schedule of future minimum payments for noncancellable operating leases extending beyond one year

(in thousands of dollars)
Years Ending December 31,
2014	$	586
2015		482
2016		458
2017		147
Thereafter		—
	$	1,673

XML

Stock-based Compensation (Details) (USD $) In Millions, except Share data, unless otherwise specified	12 Months Ended	0 Months Ended	12 Months Ended
	Dec. 31, 2013	Sep. 04, 2013 item	Dec. 31, 2012	Dec. 31, 2011
Non-employee members of Board Of Directors | Restricted stock
Units/ Awards
Granted (in shares)	27
Unvested at the end of the period (in shares)	27
Weighted Average Grant Date Fair Value per Share
Granted (in dollars per share)	$ 15.05
Unvested at the end of the period (in dollars per share)	$ 15.05
Non-employee members of Board Of Directors | Class A common stock | Restricted stock
Weighted Average Grant Date Fair Value per Share
Number of non-employee members of the Board of Directors to whom awards were granted		4
Awards granted to each non-employee director (in shares)		6,645
Service period from date of grant	1 year
Non-employee members of Board Of Directors | General and administrative expenses | Restricted stock
Weighted Average Grant Date Fair Value per Share
Stock compensation expense	$ 0.1
Management incentive plan | Management units | JEH | Common Class B
Units/ Awards
Unvested at the end of the period (in shares)	457,150
Management incentive plan | Management units | JEH | General and administrative expenses
Weighted Average Grant Date Fair Value per Share
Stock compensation expense	$ 10.7		$ 0.6	$ 1.1
Management incentive plan | Management units | JEH | Management
Units/ Awards
Unvested at the beginning of the period (in shares)	710,767
Granted (in shares)	911,654
Forfeited (in shares)	(167,239)
Vested (in shares)	(998,032)
Unvested at the end of the period (in shares)	457,150
Weighted Average Grant Date Fair Value per Share
Unvested at the beginning of the period (in dollars per share)	$ 3.62
Granted (in dollars per share)	$ 15.00
Forfeited (in dollars per share)	$ 3.62
Vested (in dollars per share)	$ 9.96
Unvested at the end of the period (in dollars per share)	$ 12.46

XML

Subsidiary Guarantors (Tables)

12 Months Ended

Dec. 31, 2013

Subsidiary Guarantors

Condensed Consolidating Statements of Operations

Jones Energy, Inc.

Condensed Consolidating Statements of Operations

Year Ended December 31, 2013

	Year Ended December 31, 2013
(in thousands of dollars)	JEI(Parent)			Issuers			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations		Consolidated
Operating revenues
Oil and gas sales	$	—		$	—		$	258,063		$	—		$	—	$	258,063
Other revenues	—			469			637			—			—		1,106
Total operating revenues	—			469			258,700			—			—		259,169
Operating costs and expenses
Lease operating	—			—			27,781			—			—		27,781
Production taxes	—			—			12,865			—			—		12,865
Exploration	—			—			1,710			—			—		1,710
Depletion, depreciation and amortization	—			—			114,046			90			—		114,136
Impairment of oil and gas properties	—			—			14,415			—			—		14,415
Accretion of discount	—			—			608			—			—		608
General and administrative (including non-cash compensation expense)	—			4,154			27,490			258			—		31,902
Total operating expenses	—			4,154			198,915			348			—		203,417
Operating income	—			(3,685		)	59,785			(348		)	—		55,752
Other income (expense)
Interest expense	—			(29,653		)	(1,121		)	—			—		(30,774		)
Net gain (loss) on commodity derivatives	—			(2,566		)	—			—			—		(2,566		)
Gain (loss) on sales of assets	—			—			41			(119		)	—		(78		)
Other income (expense), net	—			(32,219		)	(1,080		)	(119		)	—		(33,418		)
Income (loss) before income tax	—			(35,904		)	58,705			(467		)	—		22,334
Equity interest in Income	(3,400		)	—			—			—			3,400		—
Income tax provision (benefit)
Current	85			—			—			—			—		85
Deferred	(1,299		)	1,143			—			—			—		(156		)
Total income tax provision (benefit)	(1,214		)	1,143			—			—			—		(71		)
Net income (loss)	$	(2,186	)	$	(37,047	)	$	58,705		$	(467	)	$	3,400	$	22,405
Net income (loss) attributable to non-controlling interests	—			—			—			—			$	24,591	$	24,591
Net income (loss) attributable to controlling interests	$	(2,186	)	—			—			—			—		$	(2,186	)

Jones Energy, Inc.

Condensed Consolidating Statements of Operations

Year Ended December 31, 2012

	Year Ended December 31, 2012
(in thousands of dollars)	JEI(Parent)		Issuers			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations		Consolidated
Operating revenues
Oil and gas sales	$	—	$	—		$	148,967		$	—		$	—	$	148,967
Other revenues	—		—			847			—			—		847
Total operating revenues	—		—			149,814			—			—		149,814
Operating costs and expenses
Lease operating	—		—			23,097			—			—		23,097
Production taxes	—		—			5,583			—			—		5,583
Exploration	—		—			356			—			—		356
Depletion, depreciation and amortization	—		—			80,554			155			—		80,709
Impairment of oil and gas properties	—		—			18,821			—			—		18,821
Accretion of discount	—		—			533			—			—		533
General and administrative (including non-cash compensation expense)	—		2,589			12,562			724			—		15,875
Total operating expenses	—		2,589			141,506			879			—		144,974
Operating income	—		(2,589		)	8,308			(879		)	—		4,840
Other income (expense)
Interest expense	—		(24,679		)	(613		)	—			—		(25,292		)
Net gain (loss) on commodity derivatives	—		16,684			—			—			—		16,684
Gain (loss) on sales of assets	—		—			1,162			—			—		1,162
Other income (expense), net	—		(7,995		)	549			—			—		(7,446		)
Income (loss) before income tax	—		(10,584		)	8,857			(879		)	—		(2,606		)
Income tax provision (benefit)
Current	—		—			—			—			—		—
Deferred	—		473			—			—			—		473
Total income tax provision (benefit)	—		473			—			—			—		473
Net income (loss)	$	—	$	(11,057	)	$	8,857		$	(879	)	$	—	$	(3,079	)

Condensed Consolidating Balance Sheet

Jones Energy, Inc

Condensed Consolidating Balance Sheet

December 31, 2013

	December 31, 2013
(in thousands of dollars)	JEI(Parent)			Issuers		Guarantor Subsidiaries		Non-Guarantor Subsidiaries			Eliminations			Consolidated
Assets
Current assets
Cash	$	100		$	6,000	$	17,650	$	70		$	—		$	23,820
Restricted Cash	—			—		45		—			—			45
Accounts receivable, net
Oil and gas sales	—			—		51,233		—			—			51,233
Joint interest owners	—			—		42,481		—			—			42,481
Other	—			—		1,459		—			—			1,459
Commodity derivative assets	—			8,837		—		—			—			8,837
Other current assets	—			387		2,005		—			—			2,392
Deferred tax assets	—			12		—		—			—			12
Intercompany receivable	638			1,051,389		—					(1,052,027		)	—
Total current assets	738			1,066,625		114,873		70			(1,052,027		)	130,279
Oil and gas properties, net, at cost under the successful efforts method	—			—		1,312,551		—			—			1,312,551
Other property, plant and equipment, net	—			—		2,557		887			—			3,444
Commodity derivative assets	—			25,398		—		—			—			25,398
Other assets	—			14,072		934		—			—			15,006
Investment in Subsidiaries	169,081			—		—		—			(169,081		)	—
Deferred tax assets	1,301			—		—		—			—			1,301
Total assets	$	171,120		$	1,106,095	$	1,430,915	$	957		$	(1,221,108	)	$	1,487,979
Liabilities and Stockholders’ / Members’ Equity
Current liabilities
Trade accounts payable	$	—		$	230	$	89,200	$	—		$	—		$	89,430
Oil and gas sales payable	—			—		66,179		—			—			66,179
Accrued liabilities	87			1,642		9,076		—			—			10,805
Commodity derivative liabilities	—			10,664		—		—			—			10,664
Deferred tax liabilities	—			—		—		—			—			—
Asset retirement obligations	—			—		2,590		—			—			2,590
Intercompany payable				—		1,051,935		2,279			(1,054,214		)	—
Total current liabilities	87			12,536		1,218,980		2,279			(1,054,214		)	179,668
Long-term debt	—			658,000		—		—			—			658,000
Deferred revenue	—			14,531		—		—			—			14,531
Commodity derivative liabilities	—			190		—		—			—			190
Asset retirement obligations	—			—		8,373		—			—			8,373
Deferred tax liabilities	—			3,093		—		—			—			3,093
Total liabilities	87			688,350		1,227,353		2,279			(1,054,214		)	863,855
Commitments and contingencies (Note 10)
Stockholders’ / members’ equity
Members’ equity	—			417,745		203,562		(1,322		)	(619,985		)	—
Class A common stock, $0.001 par value; 12,526,580 shares issued and outstanding	13			—		—		—			—			13
Class B common stock, $0.001 par value; 36,836,333 shares issued and outstanding	37			—		—		—			—			37
Additional paid-in-capital	173,169			—		—		—			—			173,169
Retained earnings (deficit)	(2,186		)	—		—		—			—			(2,186		)
Stockholders’ / members’ equity	171,033			417,745		203,562		(1,322		)	(619,985		)	171,033
Non-controlling interest	—			—		—		—			453,091			453,091
Total stockholders’ / members’ equity	171,033			417,745		203,562		(1,322		)	(166,894		)	624,124
Total liabilities and stockholders’ / members’ equity	$	171,120		$	1,106,095	$	1,430,915	$	957		$	(1,221,108	)	$	1,487,979

Jones Energy, Inc

Condensed Consolidating Balance Sheet

December 31, 2012

	December 31, 2012
(in thousands of dollars)	JEI(Parent)		Issuers		Guarantor Subsidiaries		Non-Guarantor Subsidiaries			Eliminations			Consolidated
Assets
Current assets
Cash	$	—	$	5,056	$	18,600	$	70		$	—		$	23,726
Restricted Cash	—		—		—		—			—			—
Accounts receivable, net
Oil and gas sales	—		—		29,684		—			—			29,684
Joint interest owners	—		—		21,876		—			—			21,876
Other	—		1,719		2,871		—			—			4,590
Commodity derivative assets	—		17,648		—		—			—			17,648
Other current assets	—		—		1,088		—			—			1,088
Deferred tax assets	—		—		—		—			—			—
Intercompany receivable	—		845,184		—		—			(845,184		)	—
Total current assets	—		869,607		74,119		70			(845,184		)	98,612
Oil and gas properties, net, at cost
under the successful efforts method	—		—		1,007,344		—			—			1,007,344
Other property, plant and equipment, net	—		—		2,568		830			—			3,398
Commodity derivative assets	—		25,199		—		—			—			25,199
Other assets	—		13,446		2,687		—			—			16,133
Deferred tax assets	—		—		—		—			—			—
Total assets	$	—	$	908,252	$	1,086,718	$	900		$	(845,184	)	$	1,150,686
Liabilities and Stockholders’ / Members’ Equity
Current liabilities
Trade accounts payable	$	—	$	116	$	37,920	$	—		$	—		$	38,036
Oil and gas sales payable	—		—		45,860		—			—			45,860
Accrued liabilities	—		110		5,145		—			—			5,255
Commodity derivative liabilities	—		4,035		—		—			—			4,035
Deferred tax liabilities	—		61		—		—			—			61
Asset retirement obligations	—		—		174		—			—			174
Intercompany payable	—		—		843,430		1,754			(845,184		)	—
Total current liabilities	—		4,322		932,529		1,754			(845,184		)	93,421
Long-term debt	—		610,000		—		—			—			610,000
Deferred revenue	—		—		—		—			—			—
Commodity derivative liabilities	—		7,657		—		—			—			7,657
Asset retirement obligations	—		—		9,332		—			—			9,332
Deferred tax liabilities	—		1,876		—		—			—			1,876
Total liabilities	—		623,855		941,861		1,754			(845,184		)	722,286
Commitments and contingencies (Note 10)
Stockholders’ / members’ equity
Members’ equity	—		284,397		144,857		(854		)	—			428,400
Stockholders’ / members’ equity	—		284,397		144,857		(854		)	—			428,400
Total stockholders’ / members’ equity	—		284,397		144,857		(854		)	—			428,400
Total liabilities and stockholders’ / members’ equity	$	—	$	908,252	$	1,086,718	$	900		$	(845,184	)	$	1,150,686

Condensed Statements of Cash Flows

Jones Energy, Inc.

Consolidated Statements of Cash Flows

Years Ended December 31, 2013

	Year Ended December 31, 2013
(in thousands of dollars)	JEI(Parent)			Issuers			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated
Cash flows from operating activities
Net income (loss)	$	(2,186	)	$	(37,047	)	$	58,705		$	(467	)	$	3,400		$	22,405
Adjustments to reconcile net income (loss) to net cash provided by operating activities	2,286			(189,393		)	331,265			733			(3,400		)	141,491
Net cash (used in) / provided by operations	100			(226,440		)	389,970			266			—			163,896
Cash flows from investing activities
Investment in subsidiary	(172,481		)										172,481			—
Additions to oil and gas properties	—			—			(197,618		)							(197,618		)
Acquisition of properties	—			—			(193,496		)							(193,496		)
Proceeds from sales of assets	—			—			963			644						1,607
Acquisition of other property, plant and equipment	—			—			(724		)	(910		)				(1,634		)
Current period settlements of matured derivative contracts	—			7,586			—			—						7,586
Change in restricted cash	—			—			(45		)	—						(45		)
Net cash (used in) / provided by investing	(172,481		)	7,586			(390,920		)	(266		)	172,481			(383,600		)
Cash flows from financing activities
Proceeds from investment by JEI				172,481									(172,481		)	—
Proceeds from issuance of long-term debt	—			220,000			—			—						220,000
Repayment under long-term debt	—			(172,000		)	—			—						(172,000		)
Payment of debt issuance costs	—			(683		)	—			—						(683		)
Proceeds from sale of common stock, net of expenses of $15.1 million	172,481			—			—			—						172,481
Net cash (used in) provided by financing	172,481			219,798			—			—			(172,481		)	219,798
Net increase (decrease) in cash	100			944			(950		)	—			—			94
Cash
Beginning of period	—			5,056			18,600			70			—			23,726
End of period	$	100		$	6,000		$	17,650		$	70		—			$	23,820

Jones Energy, Inc.

Consolidated Statements of Cash Flows

Years Ended December 31, 2012

	Year Ended December 31, 2012
(in thousands of dollars)	JEI(Parent)		Issuers			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Consolidated
Cash flows from operating activities
Net income (loss)	$	—	$	(11,057	)	$	8,857		$	(879	)	$	(3,079	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities			(283,848		)	370,623			854			87,629
Net cash (used in) / provided by operations	—		(294,905		)	379,480			(25		)	84,550
Cash flows from investing activities
Additions to oil and gas properties	—		—			(125,493		)	—			(125,493		)
Acquisition of properties	—		—			(249,007		)	—			(249,007		)
Proceeds from sales of assets	—		—			9,158			—			9,158
Acquisition of other property, plant and equipment	—		—			(969		)	—			(969		)
Current period settlements of matured derivative contracts	—		28,675			—			—			28,675
Change in restricted cash	—		—			—			—			—
Net cash (used in) / provided by investing	—		28,675			(366,311		)	—			(337,636		)
Cash flows from financing activities
Proceeds from issuance of long-term debt	—		233,243			—			—			233,243
Repayment under long-term debt	—		(38,243		)	—			—			(38,243		)
Payment of debt issuance costs	—		(9,324		)	—			—			(9,324		)
Issuance of preferred units	—		85,000			—			—			85,000
Net cash provided by financing	—		270,676			—			—			270,676
Net increase (decrease) in cash	—		4,446			13,169			(25		)	17,590
Cash
Beginning of period	—		610			5,431			95			6,136
End of period	$	—	$	5,056		$	18,600		$	70		$	23,726

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Organization and Description of Business (Details)	12 Months Ended	0 Months Ended
	Dec. 31, 2013 item	Jul. 29, 2013 item
Organization and description of business
Number of classes of common stock	2
Number of distinct basins where entity's assets are located	2
Pre-IPO owners of JEH
Organization and description of business
Exchange ratio		1
Number of votes for each holder of common stock		1
JEH
Organization and description of business
Economic interest (as a percent)		74.70%

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Organization and Description of Business

12 Months Ended

Dec. 31, 2013

Organization and Description of Business

Organization and Description of Business

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. Prior to the IPO, JEH owned the controlling interest in the Company; hence all of the net income (loss) earned prior to the IPO date is reflected in the net income (loss) attributable to non-controlling interests on the Consolidated Statement of Operations for the year ended December 31, 2013.

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 is headquartered in Austin, Texas.

Revision of Previously Issued Financial Statements

        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. Therefore we have revised our Consolidated Statement of Operations for the years ended December 31, 2012 and 2011 to record $0.6 million and $0.8 million, respectively of additional interest expense on obligations that are unrelated to our credit agreements discussed in Note 6. As a result, net income decreased for the years ended December 31, 2012 and 2011 by $0.6 million and $0.8 million, respectively. The balance sheet impacts of the revision are increases in accrued liabilities and decreases in members' equity of $0.6 million and $1.4 million at December 31, 2011 and 2012, respectively. These revisions had no impact on our net cash provided by operations in our Consolidated Statement of Cash Flows. We have determined that these errors are not material to our consolidated financial statements for the years ended December 31, 2012 and 2011.

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Organization and Description of Business (Details 2) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Interest expense	$ 30,774	$ 25,292	$ 21,994
Net income (loss)	22,405	(3,079)	60,326
Accrued liabilities	10,805	5,255
Members' equity		428,400
Adjustment
Interest expense		600	800
Net income (loss)		(600)	(800)
Accrued liabilities		600	800
Members' equity		$ (1,400)	$ (600)

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Fair Value Measurement (Details 2) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Natural gas liquid | Swap | Minimum
Quantitative Information About Level 3 Fair Value Measurements
Swap price (in dollars per barrel/mmbtu)	6.72	6.72
Natural gas liquid | Swap | Maximum
Quantitative Information About Level 3 Fair Value Measurements
Swap price (in dollars per barrel/mmbtu)	95.24	97.13
Commodity derivatives
Quantitative Information About Level 3 Fair Value Measurements
Fair Value	$ 14,347	$ 17,928
Discounted cash flow approach | Level 3 | Commodity derivatives | Natural gas liquid | Swap
Quantitative Information About Level 3 Fair Value Measurements
Fair Value	$ (1,235)
Discounted cash flow approach | Level 3 | Commodity derivatives | Natural gas liquid | Swap | Minimum
Quantitative Information About Level 3 Fair Value Measurements
Swap price (in dollars per barrel/mmbtu)	9.24
Discounted cash flow approach | Level 3 | Commodity derivatives | Natural gas liquid | Swap | Maximum
Quantitative Information About Level 3 Fair Value Measurements
Swap price (in dollars per barrel/mmbtu)	83.06

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Subsidiary Guarantors (Details 4) (USD $) In Thousands, except Share data, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Current assets
Cash	$ 23,820	$ 23,726
Restricted Cash	45
Accounts receivable, net
Oil and gas sales	51,233	29,684
Joint interest owners	42,481	21,876
Other	1,459	4,590
Commodity derivative assets	8,837	17,648
Other current assets	2,392	1,088
Deferred tax assets	12
Total current assets	130,279	98,612
Oil and gas properties, net, at cost under the successful efforts method	1,312,551	1,007,344
Other property, plant and equipment, net	3,444	3,398
Commodity derivative assets	25,398	25,199
Other assets	15,006	16,133
Deferred tax assets	1,301
Total assets	1,487,979	1,150,686
Current liabilities
Trade accounts payable	89,430	38,036
Oil and gas sales payable	66,179	45,860
Accrued liabilities	10,805	5,255
Commodity derivative liabilities	10,664	4,035
Deferred tax liabilities		61
Asset retirement obligations	2,590	174
Total current liabilities	179,668	93,421
Long-term debt	658,000	610,000
Deferred revenue	14,531
Commodity derivative liabilities	190	7,657
Asset retirement obligations	8,373	9,332
Deferred tax liabilities	3,093	1,876
Total liabilities	863,855	722,286
Commitments and contingencies (Note 10)
Stockholders' / members' equity
Members' equity		428,400
Additional paid-in-capital	173,169
Retained earnings (deficit)	(2,186)
Stockholders' / members' equity	171,033	428,400
Non-controlling interest	453,091
Total stockholders' / members' equity	624,124	428,400	345,909	284,449
Total liabilities and stockholders' / members' equity	1,487,979	1,150,686
Class A common stock
Stockholders' / members' equity
Common stock	13
Common Stock, par value (in dollars per share)	$ 0.001
Common Stock, shares issued	12,526,580
Common Stock, shares outstanding	12,526,580
Class B common stock
Stockholders' / members' equity
Common stock	37
Common Stock, par value (in dollars per share)	$ 0.001
Common Stock, shares issued	36,836,333
Common Stock, shares outstanding	36,836,333
Eliminations
Accounts receivable, net
Intercompany receivable	(1,052,027)	(845,184)
Total current assets	(1,052,027)	(845,184)
Investment in Subsidiaries	(169,081)
Total assets	(1,221,108)	(845,184)
Current liabilities
Intercompany payable	(1,054,214)	(845,184)
Total current liabilities	(1,054,214)	(845,184)
Total liabilities	(1,054,214)	(845,184)
Commitments and contingencies (Note 10)
Stockholders' / members' equity
Members' equity	(619,985)
Stockholders' / members' equity	(619,985)
Non-controlling interest	453,091
Total stockholders' / members' equity	(166,894)
Total liabilities and stockholders' / members' equity	(1,221,108)	(845,184)
JEI (Parent)
Current assets
Cash	100
Accounts receivable, net
Intercompany receivable	638
Total current assets	738
Investment in Subsidiaries	169,081
Deferred tax assets	1,301
Total assets	171,120
Current liabilities
Accrued liabilities	87
Total current liabilities	87
Total liabilities	87
Commitments and contingencies (Note 10)
Stockholders' / members' equity
Additional paid-in-capital	173,169
Retained earnings (deficit)	(2,186)
Stockholders' / members' equity	171,033
Total stockholders' / members' equity	171,033
Total liabilities and stockholders' / members' equity	171,120
JEI (Parent) | Class A common stock
Stockholders' / members' equity
Common stock	13
Common Stock, par value (in dollars per share)	$ 0.001
Common Stock, shares issued	12,526,580
Common Stock, shares outstanding	12,526,580
JEI (Parent) | Class B common stock
Stockholders' / members' equity
Common stock	37
Common Stock, par value (in dollars per share)	$ 0.001
Common Stock, shares issued	36,836,333
Common Stock, shares outstanding	36,836,333
Issuers
Current assets
Cash	6,000	5,056
Accounts receivable, net
Other		1,719
Commodity derivative assets	8,837	17,648
Other current assets	387
Deferred tax assets	12
Intercompany receivable	1,051,389	845,184
Total current assets	1,066,625	869,607
Commodity derivative assets	25,398	25,199
Other assets	14,072	13,446
Total assets	1,106,095	908,252
Current liabilities
Trade accounts payable	230	116
Accrued liabilities	1,642	110
Commodity derivative liabilities	10,664	4,035
Deferred tax liabilities		61
Total current liabilities	12,536	4,322
Long-term debt	658,000	610,000
Deferred revenue	14,531
Commodity derivative liabilities	190	7,657
Deferred tax liabilities	3,093	1,876
Total liabilities	688,350	623,855
Commitments and contingencies (Note 10)
Stockholders' / members' equity
Members' equity	417,745	284,397
Stockholders' / members' equity	417,745	284,397
Total stockholders' / members' equity	417,745	284,397
Total liabilities and stockholders' / members' equity	1,106,095	908,252
Guarantor Subsidiaries
Current assets
Cash	17,650	18,600
Restricted Cash	45
Accounts receivable, net
Oil and gas sales	51,233	29,684
Joint interest owners	42,481	21,876
Other	1,459	2,871
Other current assets	2,005
Deferred tax assets		1,088
Total current assets	114,873	74,119
Oil and gas properties, net, at cost under the successful efforts method	1,312,551	1,007,344
Other property, plant and equipment, net	2,557	2,568
Other assets	934	2,687
Total assets	1,430,915	1,086,718
Current liabilities
Trade accounts payable	89,200	37,920
Oil and gas sales payable	66,179	45,860
Accrued liabilities	9,076	5,145
Asset retirement obligations	2,590	174
Intercompany payable	1,051,935	843,430
Total current liabilities	1,218,980	932,529
Asset retirement obligations	8,373	9,332
Total liabilities	1,227,353	941,861
Commitments and contingencies (Note 10)
Stockholders' / members' equity
Members' equity	203,562	144,857
Stockholders' / members' equity	203,562	144,857
Total stockholders' / members' equity	203,562	144,857
Total liabilities and stockholders' / members' equity	1,430,915	1,086,718
Non-Guarantor Subsidiaries
Current assets
Cash	70	70
Accounts receivable, net
Total current assets	70	70
Other property, plant and equipment, net	887	830
Total assets	957	900
Current liabilities
Intercompany payable	2,279	1,754
Total current liabilities	2,279	1,754
Total liabilities	2,279	1,754
Commitments and contingencies (Note 10)
Stockholders' / members' equity
Members' equity	(1,322)	(854)
Stockholders' / members' equity	(1,322)	(854)
Total stockholders' / members' equity	(1,322)	(854)
Total liabilities and stockholders' / members' equity	$ 957	$ 900

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Consolidated Balance Sheets (USD $) In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Current assets
Cash	$ 23,820	$ 23,726
Restricted Cash	45
Accounts receivable, net
Oil and gas sales	51,233	29,684
Joint interest owners	42,481	21,876
Other	1,459	4,590
Commodity derivative assets	8,837	17,648
Other current assets	2,392	1,088
Deferred tax assets	12
Total current assets	130,279	98,612
Oil and gas properties, net, at cost under the successful efforts method	1,312,551	1,007,344
Other property, plant and equipment, net	3,444	3,398
Commodity derivative assets	25,398	25,199
Other assets	15,006	16,133
Deferred tax assets	1,301
Total assets	1,487,979	1,150,686
Current liabilities
Trade accounts payable	89,430	38,036
Oil and gas sales payable	66,179	45,860
Accrued liabilities	10,805	5,255
Commodity derivative liabilities	10,664	4,035
Deferred tax liabilities		61
Asset retirement obligations	2,590	174
Total current liabilities	179,668	93,421
Long-term debt	658,000	610,000
Deferred revenue	14,531
Commodity derivative liabilities	190	7,657
Asset retirement obligations	8,373	9,332
Deferred tax liabilities	3,093	1,876
Total liabilities	863,855	722,286
Commitments and contingencies (Note 10)
Stockholders' / members' equity
Members' equity		428,400
Additional paid-in-capital	173,169
Retained earnings (deficit)	(2,186)
Stockholders' / members' equity	171,033	428,400
Non-controlling interest	453,091
Total stockholders' / members' equity	624,124	428,400	345,909	284,449
Total liabilities and stockholders' / members' equity	1,487,979	1,150,686
Class A common stock
Stockholders' / members' equity
Common stock	13
Class B common stock
Stockholders' / members' equity
Common stock	$ 37

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Earnings per Share (Details) (USD $) In Thousands, except Per Share data, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Income (numerator):
Net income (loss) applicable to controlling interests	$ (2,186)	$ (3,079)	$ 60,326
Weighted-average shares (denominator):
Weighted-average number of shares of Class A common stock - basic and diluted	12,500
Earnings (loss) per share:
Basic and diluted (in dollars per share)	$ (0.17)
Anti-dilutive restricted shares of Class A common stock	27

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Consolidated Statements of Cash Flows (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Cash flows from operating activities
Net income (loss)	$ 22,405	$ (3,079)	$ 60,326
Adjustments to reconcile net income (loss) to net cash provided by operating activities
Exploration expense			478
Depletion, depreciation, and amortization	114,136	80,709	68,906
Impairment of oil and gas properties	14,415	18,821	31,970
Accretion of discount	608	533	413
Amortization of debt issuance costs	2,677	3,544	2,940
Stock compensation expense	10,838	570	1,134
Other non-cash compensation expense (Note 9)	2,719
Amortization of deferred revenue	(469)
Gain on commodity derivatives	2,566	(16,684)	(34,490)
Gain on bargain purchase price			(26,208)
(Gain) loss on sales of assets	78	(1,162)	859
Deferred income tax provision	(156)	473	173
Other - net	79	129	(59)
Changes in assets and liabilities
Accounts receivable	(41,481)	11,568	(32,593)
Other assets	163	1,873	(3,360)
Accounts payable and accrued liabilities	35,318	(12,745)	49,728
Net cash provided by operations	163,896	84,550	120,217
Cash flows from investing activities
Additions to oil and gas properties	(197,618)	(125,493)	(157,046)
Acquisition of properties	(193,496)	(249,007)	(168,480)
Proceeds from sales of assets	1,607	9,158	6,747
Acquisition of other property, plant and equipment	(1,634)	(969)	(1,735)
Current period settlements of matured derivative contracts	7,586	28,675	1,551
Change in restricted cash	(45)
Net cash (used in) / provided by investing	(383,600)	(337,636)	(318,963)
Cash flows from financing activities
Proceeds from issuance of long-term debt	220,000	233,243	316,500
Repayment under long-term debt	(172,000)	(38,243)	(126,500)
Payment of debt issuance costs	(683)	(9,324)	(3,678)
Issuance of preferred units		85,000
Proceeds from sale of common stock, net of expenses of $15.1 million	172,481
Net cash provided by financing	219,798	270,676	186,322
Net increase (decrease) in cash	94	17,590	(12,424)
Cash
Beginning of period	23,726	6,136	18,560
End of period	23,820	23,726	6,136
Supplemental disclosure of cash flow information
Cash paid for interest	25,414	20,759	18,151
Change in accrued additions to oil and gas properties	41,945	3,355	26,774
Noncash acquisition of oil and gas properties		2,918
Current additions to ARO	1,516	662	4,077
Noncash distributions to members (Note 9)	$ 10,000

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Significant Accounting Policies (Details 3) (USD $)	12 Months Ended
	Dec. 31, 2013 item	Dec. 31, 2012	Dec. 31, 2011
Other Property, Plant and Equipment
Gross other property, plant and equipment	$ 5,430,000	$ 5,335,000
Less: Accumulated depreciation and amortization	(1,986,000)	(1,937,000)
Net other property, plant and equipment	3,444,000	3,398,000
Depreciation and amortization of other property, plant and equipment	800,000	800,000	700,000
Oil and Gas Sales Payable
Period of remittance for oil and gas sales payable	60 days
Asset Retirement Obligations
ARO liability at beginning of year	9,506,000	9,563,000
Liabilities incurred	1,516,000	662,000	4,077,000
Accretion of discount	608,000	596,000
Liabilities settled due to sale of related properties	(271,000)	(927,000)
Liabilities settled due to plugging and abandonment	(702,000)	(388,000)
Change in estimate	307,000
ARO liability at end of year	10,963,000	9,506,000	9,563,000
Less: Current portion of ARO at end of year	(2,590,000)	(174,000)
Total long-term ARO at end of year	8,373,000	9,332,000
Liabilities incurred related to wells acquired	824,000
Tax Receivable Agreement
Cash savings to be paid under tax receivable agreement with JEH and the pre-IPO owners (as a percent)	85.00%
Benefits of cash savings retained under tax receivable agreement (as a percent)	15.00%
Liabilities recorded	0
Number of exchanges	0
Minimum
Other Property, Plant and Equipment
Estimated useful lives	3 years
Maximum
Other Property, Plant and Equipment
Estimated useful lives	10 years
Leasehold improvements
Other Property, Plant and Equipment
Gross other property, plant and equipment	1,060,000	983,000
Furniture, fixtures, computers and software
Other Property, Plant and Equipment
Gross other property, plant and equipment	2,491,000	2,204,000
Vehicles
Other Property, Plant and Equipment
Gross other property, plant and equipment	835,000	719,000
Aircraft
Other Property, Plant and Equipment
Gross other property, plant and equipment	910,000	1,295,000
Other
Other Property, Plant and Equipment
Gross other property, plant and equipment	$ 134,000	$ 134,000

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Significant Accounting Policies (Tables)

12 Months Ended

Dec. 31, 2013

Significant Accounting Policies

Schedule of oil and gas properties

(in thousands of dollars)	2013			2012
Mineral interests in properties
Unproved	$	114,457		$	137,254
Proved		958,816			737,558
Wells and equipment and related facilities		609,748			389,727
		1,683,021			1,264,539
Less: Accumulated depletion and impairment		(370,470	)		(257,195	)
Net oil and gas properties	$	1,312,551		$	1,007,344

Schedule of other property, plant and equipment

(in thousands of dollars)	2013			2012
Leasehold improvements	$	1,060		$	983
Furniture, fixtures, computers and software		2,491			2,204
Vehicles		835			719
Aircraft		910			1,295
Other		134			134
		5,430			5,335
Less: Accumulated depreciation and amortization		(1,986	)		(1,937	)
Net other property, plant and equipment	$	3,444		$	3,398

Summary of the Company's ARO

(in thousands of dollars)	2013			2012
ARO liability at beginning of year	$	9,506		$	9,563
Liabilities incurred(1)		1,515			662
Accretion of discount		608			596
Liabilities settled due to sale of related properties		(271	)		(927	)
Liabilities settled due to plugging and abandonment		(702	)		(388	)
Change in estimate		307			—
ARO liability at end of year		10,963			9,506
Less: Current portion of ARO at end of year		(2,590	)		(174	)
Total long-term ARO at end of year	$	8,373		$	9,332

(1)

Includes $824 related to wells acquired (see Note 3, "Acquisition of Properties").

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Significant Accounting Policies (Details 4) (USD $) In Millions, unless otherwise specified	12 Months Ended			0 Months Ended
	Dec. 31, 2013 MMBoe	Dec. 31, 2012	Dec. 31, 2011	Sep. 01, 2013	May 07, 2013
Related Party Transactions
Production of natural gas and NGLs from the Chalker properties (in MMBoe)	0.8
Metalmark
Related Party Transactions
Annual administration fee	0.7	$ 0.7	$ 0.7
Number of directors who are managing directors of the related party	2
Metalmark | Minimum
Related Party Transactions
Outstanding equity interests held by the related party (as a percent)	5.00%
Monarch
Related Party Transactions
Initial term of the agreement				10 years
Monarch | Metalmark
Related Party Transactions
Outstanding equity interests held (as a percent)					81.00%
JEH
Related Party Transactions
Value of equity interests assigned to Jonny Jones					2.4
Value of equity interests reserved to a benefit plan established for certain of the entity's officers					2.6
Value of remaining equity interests distributed to certain of the pre-IPO owners					10
JEH | Monarch
Related Party Transactions
Deemed value of equity interests issued					$ 15

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Fair Value Measurement (Tables)

12 Months Ended

Dec. 31, 2013

Fair Value Measurement

Schedule of financial instruments carried at fair value

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

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

Schedule of quantitative information about Level 3 inputs used in the fair value measurement

	Quantitative Information About Level 3 Fair Value Measurements
Commodity Price Hedges	Fair Value			Valuation Technique	Unobservable Input	Range
Natural gas liquid swaps	$	(1,235	)	Use a discounted cash flow approach using inputs including forward price statements from counterparties	Natural gas liquid futures	$9.24 - $83.06 per barrel

Schedule of changes in fair value of Level 3 financial instruments

(in thousands of dollars)
Balance at January 1, 2012, net	$	(2,083	)
Purchases		(2,352	)
Settlements		—
Transfers to Level 2		2,370
Transfers to Level 3		834
Changes in fair value		(288	)
Balance at December 31, 2012, net		(1,519	)
Purchases		(1,095	)
Settlements		(210	)
Transfers to Level 2		(753	)
Changes in fair value		2,342
Balance at December 31, 2013, net	$	(1,235	)

Schedule of commodity derivative contracts which are netted on Consolidated Balance Sheet

(in thousands of dollars)	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
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	)
December 31, 2012
Commodity derivative contracts
Assets	$	49,200		$	(7,831	)	$	41,369		$	1,478		$	42,847
Liabilities		(17,928	)		7,831			(10,097	)		(1,595	)		(11,692	)

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Consolidated Statements of Cash Flows (Parenthetical) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013
Consolidated Statements of Cash Flows
Payment of stock issuance expenses	$ 15.1

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Consolidated Balance Sheets (Parenthetical) (USD $)	Dec. 31, 2013
Class A common stock
Common Stock, par value (in dollars per share)	$ 0.001
Common Stock, shares issued	12,526,580
Common Stock, shares outstanding	12,526,580
Class B common stock
Common Stock, par value (in dollars per share)	$ 0.001
Common Stock, shares issued	36,836,333
Common Stock, shares outstanding	36,836,333

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Commitments and Contingencies

12 Months Ended

Dec. 31, 2013

Commitments and Contingencies

Commitments and Contingencies

10. Commitments and Contingencies

Lease obligations

        The Company leases approximately 31,000 square feet of office space in Austin, TX under an operating lease arrangement. Future minimum payments for noncancellable operating leases extending beyond one year at December 31, 2013 are as follows:

(in thousands of dollars)
Years Ending December 31,
2014	$	586
2015		482
2016		458
2017		147
Thereafter		—
	$	1,673

        Rent expense under operating leases was $0.8 million, $0.8 million and $0.7 million for the years ended December 31, 2013, 2012 and 2011, respectively.

Litigation

        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 current matters will not have a material adverse effect on its financial position, results of operations, or liquidity.

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Document and Entity Information	12 Months Ended
	Dec. 31, 2013
Entity Registrant Name	Jones Energy, Inc.
Entity Central Index Key	0001573166
Document Type	8-K
Document Period End Date	Dec. 31, 2013
Amendment Flag	false
Current Fiscal Year End Date	--12-31

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Benefit Plans

12 Months Ended

Dec. 31, 2013

Benefit Plans

Benefit Plans

11. Benefit Plans

        The Company established a 401(k) tax-deferred savings plan (the "Plan") for the benefit of employees. The Plan is a defined contribution plan and the Company may match a portion of employee contributions. For the years ended December 31, 2013 and 2012, $0.3 million and $0.2 million were contributed, respectively, to the Plan.

        In 2013, the Company established a 409A tax-deferred savings plan for the benefit of key employees. This plan is a defined contribution plan, and the Company may match a portion of employee contributions. For the year ended December 31, 2013, the Company made a negligible contribution to this plan.

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Consolidated Statements of Operations (USD $) In Thousands, except Per Share data, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Operating revenues
Oil and gas sales	$ 258,063	$ 148,967	$ 167,261
Other revenues	1,106	847	1,022
Total operating revenues	259,169	149,814	168,283
Operating costs and expenses
Lease operating	27,781	23,097	21,548
Production taxes	12,865	5,583	5,333
Exploration	1,710	356	780
Depletion, depreciation and amortization	114,136	80,709	68,906
Impairment of oil and gas properties	14,415	18,821	31,970
Accretion of discount	608	533	413
General and administrative (including non-cash compensation expense)	31,902	15,875	16,679
Total operating expenses	203,417	144,974	145,629
Operating income	55,752	4,840	22,654
Other income (expense)
Interest expense	(30,774)	(25,292)	(21,994)
Net gain (loss) on commodity derivatives	(2,566)	16,684	34,490
Gain on bargain purchase			26,208
Gain (loss) on sales of assets	(78)	1,162	(859)
Other income (expense), net	(33,418)	(7,446)	37,845
Income (loss) before income tax	22,334	(2,606)	60,499
Income tax provision
Current	85
Deferred	(156)	473	173
Total income tax provision	(71)	473	173
Net income (loss)	22,405	(3,079)	60,326
Net income attributable to non-controlling interests	24,591
Net income (loss) attributable to controlling interests	$ (2,186)	$ (3,079)	$ 60,326
Earnings per share:
Basic and diluted (in dollars per share)	$ (0.17)
Weighted average shares outstanding:
Basic and diluted (in shares)	12,500

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Derivative Instruments and Hedging Activities

12 Months Ended

Dec. 31, 2013

Derivative Instruments and Hedging Activities

Derivative Instruments and Hedging Activities

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 December 31, 2013 and 2012, as follows:

Hedging Positions

	December 31, 2013
		Low			High			Weighted Average			Final 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

	December 31, 2012
		Low			High			Weighted Average			Final Expiration
Oil swaps	Exercise price	$	81.00		$	104.45		$	89.60
	Barrels per month		24,000			143,116			89,323		December 2017
Natural gas swaps	Exercise price	$	3.52		$	6.90		$	4.96
	mmbtu per month		430,000			1,110,000			767,053		December 2017
Basis swaps	Contract differential	$	(0.65	)	$	(0.03	)	$	(0.31	)
	mmbtu per month		320,000			850,000			484,615		March 2016
Natural gas liquids swaps	Exercise price	$	6.72		$	97.13		$	33.81
	Barrels per month		2,000			144,973			55,616		December 2017

        The Company recognized a net loss on derivative instruments of $2.6 million for the year ended December 31, 2013 and net gains of $16.7 million and $34.5 million for the years ended December 31, 2012 and 2011, respectively.

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Fair Value Measurement

12 Months Ended

Dec. 31, 2013

Fair Value Measurement

Fair Value Measurement

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.

        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 as a result of the credit quality of the counterparty. Generally, market quotes assume that all counterparties have low default rates and equal credit quality. Therefore, an adjustment may be necessary to reflect the quality of a specific counterparty to determine the fair value of the instrument. The Company currently has all derivative positions placed and held by members of its lending group, which have strong credit quality.

        Liquidity valuation adjustments are necessary when 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 in Level 1.
Level 2	Pricing inputs include quoted prices for similar assets and liabilities in active markets, and inputs that are observable for the asset or liability, either directly or indirectly, as of the reporting date. Contracts that are not traded on a recognized exchange or are tied to pricing transactions for which forward curve pricing is readily available are classified as Level 2 instruments. These include natural gas, crude oil and some natural gas liquids price swaps and natural gas basis swaps.
Level 3	Pricing inputs include significant inputs that are generally unobservable from objective sources. 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.

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

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

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

        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 December 31, 2013.

	Quantitative Information About Level 3 Fair Value Measurements
Commodity Price Hedges	Fair Value			Valuation Technique	Unobservable Input	Range
Natural gas liquid swaps	$	(1,235	)	Use a discounted cash flow approach using inputs including forward price statements from counterparties	Natural gas liquid futures	$9.24 - $83.06 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 years ended December 31, 2013 and 2012. 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 January 1, 2012, net	$	(2,083	)
Purchases		(2,352	)
Settlements		—
Transfers to Level 2		2,370
Transfers to Level 3		834
Changes in fair value		(288	)
Balance at December 31, 2012, net		(1,519	)
Purchases		(1,095	)
Settlements		(210	)
Transfers to Level 2		(753	)
Changes in fair value		2,342
Balance at December 31, 2013, net	$	(1,235	)

        Transfers from Level 3 to Level 2 represent all of the Company's natural gas basis swaps for which observable forward curve pricing information has become readily available. In 2012, transfers to Level 3 represented natural gas liquid swaps or basis swaps that were classified as Level 2 in 2011 but due to the unavailability of forward prices in 2012, were classified as Level 3 in 2012. The purchases represent natural gas liquid swaps that the Company entered into in 2013 that do not have observable forward curve pricing information.

Offsetting Assets and Liabilities

        As of December 31, 2013, the counterparties to our commodity derivative contracts consisted of six financial institutions. All of our counterparties or their affiliates are also lenders under our credit facility. Therefore, we are not generally required to post additional collateral under our derivative agreements.

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

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

(in thousands of dollars)	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
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	)
December 31, 2012
Commodity derivative contracts
Assets	$	49,200		$	(7,831	)	$	41,369		$	1,478		$	42,847
Liabilities		(17,928	)		7,831			(10,097	)		(1,595	)		(11,692	)

Nonfinancial Assets and Liabilities

        Assets and liabilities acquired in business combinations are recorded at their fair value on the date of acquisition. Significant Level 3 assumptions associated with the calculation of future cash flows used in the analysis of fair value of the oil and gas property acquired include 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. No significant impairment charges on the Company's proved properties were recorded during the year ended December 31, 2013. During 2012 and 2011, unamortized capitalized costs of certain properties were higher than their expected undiscounted future cash flows due primarily to downward reserve revisions, drilling of marginal or uneconomic wells, or development dry holes in certain producing fields. As a result, the Company recorded charges of $18.8 million and $19.8 million during the years ended December 31, 2012 and 2011, respectively.

        Additionally, the Company reviews its unproved properties for indicators of impairment based on the Company's current exploration plans. In the fourth quarter of 2013, the Company recorded an impairment charge of $14.4 million related to the Southridge properties. As the Company did not drill the required number of wells by October 31, 2013 necessary to keep its joint development agreement with Southridge in effect, the Company lost its right to the undeveloped acreage and associated reserves. The Company incurred no impairment charges related to its unproved properties in 2012. In 2011, the Company incurred a $12.2 million impairment charge related to its unproven properties in fields which were not expected to produce natural gas with a sufficiently high liquid content. With low natural gas prices during that period, the lack of natural gas liquids reduced the economic return of those fields and as a result, the Company had no intentions to continue development of those fields.

        Impairment charges are recorded on the Consolidated Statement of Operations. 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. As such, the fair value of oil and gas properties used in estimating impairment represents a nonrecurring Level 3 measurement.

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Acquisition of Properties (Tables)

12 Months Ended

Dec. 31, 2013

Sabine acquisition

Acquisition of Properties

Schedule of purchase price allocation

(in thousands of dollars)
Oil and gas properties
Unproved	$	39,596
Proved		154,724
Asset retirement obligations		(824	)
Total purchase price	$	193,496

Schedule of unaudited pro forma results of operations

			Year Ended December 31, 2013
	Post Acquisition(1)
(in thousands of dollars)			Pro Forma
	(unaudited)		(unaudited)
Total operating revenue	$	1,365	$	308,773
Total operating expenses		291		229,648
Operating income		1,074		79,125
Net income		1,074		45,778

(1)

Represents revenues and expenses for the post acquisition period of December 18, 2013 to December 31, 2013 included in the Consolidated Statement of Operations.

Chalker acquisition

Acquisition of Properties

Schedule of purchase price allocation

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

Schedule of unaudited pro forma results of operations

	Year Ended December 31, 2012
(in thousands of dollars)	Pro Forma
	(unaudited)
Total operating revenue	$	194,685
Total operating expenses		161,053
Operating income		33,632
Net income		25,713

Oil and natural gas properties located in Oklahoma

Acquisition of Properties

Schedule of purchase price allocation

(in thousands of dollars)
Oil and gas properties	$	154,225
Asset retirement obligations		(167	)
Total purchase price	$	154,058

Schedule of unaudited pro forma results of operations

	Year Ended December 31, 2011
(in thousands of dollars)	Pro Forma
	(unaudited)
Total operating revenue	$	176,884
Total operating expenses		150,197
Operating income		26,687
Net income		62,408

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Income Taxes

12 Months Ended

Dec. 31, 2013

Income Taxes

Income Taxes

12. Income Taxes

        Following its IPO, the Company began recording a federal and state income tax liability 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 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 following table summarizes the tax provision for the years ended December 31, 2013, 2012 and 2011:

	Year Ended December 31,
(in thousands of dollars)	2013			2012		2011
Current tax expense
Federal	$	85		$	—	$	—
State		—			—		—
Total current expense		85			—		—
Deferred tax expense (benefit)
Federal		(1,260	)		—		—
State		1,104			473		173
Total deferred expense (benefit)		(156	)		473		173
Total tax expense (benefit)		(71	)		473		173
Tax benefit attributable to controlling interests		(1,223	)		—		—
Tax expense attributable to non-controlling interests		1,152			473		173
Total tax expense (benefit)	$	(71	)	$	473	$	173

        For the years ended December 31, 2012 and 2011, the reported taxes relate solely to the Texas franchise tax liability of JEH.

        A reconciliation of the Company's provision for income taxes as reported and the amount computed by multiplying income before taxes, less non-controlling interest, by the U.S. federal statutory rate of 35%:

(in thousands of dollars)	December 31, 2013
Provision calculated at federal statutory income tax rate:
Net income before taxes	$	22,334
Statutory rate		35	%
Income tax expense computed at statutory rate		7,817
Less: Non-controlling interests		(9,009	)
Income tax benefit attributable to controlling interests		(1,192	)
State and local income taxes, net of federal benefit		(49	)
Other		18
Tax benefit attributable to controlling interests		(1,223	)
Tax expense attributable to non-controlling interests		1,152
Total income tax benefit	$	(71	)

        For the years ended December 31, 2012 and 2011, the calculation is not applicable as the Company was not subject to federal income taxes prior to the IPO.

        The Company is subject to federal, state and local income and franchise taxes. As such, deferred income taxes result from temporary differences between the carrying amounts of assets and liabilities of the Company for financial reporting purposes and the amounts used for income tax purposes. Deferred tax assets and liabilities are measured using enacted tax rates in effect in the years in which those temporary differences are expected to reverse.

        Significant components of the Company's deferred tax assets and deferred tax liabilities consisted of the following:

	As of December 31,
(in thousands of dollars)	2013			2012
Deferred tax assets
Investment in consolidated subsidiary JEH	$	526		$	—
Net operating loss		649			—
Alternative minimum tax credits		86			—
State deferred tax asset		52			—
Total deferred tax assets		1,313			—
Deferred tax liabilities
State deferred tax liability		3,093			1,936
Total deferred tax liabilities		3,093			1,936
Net deferred tax assets (liabilities)		(1,780	)		(1,936	)
Valuation allowance		—			—
Net deferred tax assets (liabilities)	$	(1,780	)	$	(1,936	)

        The Company has a federal net operating loss carry-forward totaling $1.8 million and state net operating loss carry-forward of $0.4 million, both expiring in 2033. No valuation allowance has been recorded as management believes that there is sufficient future taxable income to fully utilize its deferred tax assets. This future taxable income will arise from reversing temporary differences due to the excess of the book carrying value of oil and gas properties over their corresponding tax basis. The Company may elect to capitalize intangible drilling costs, rather than expensing these costs, in order to prevent an operating loss carry-forward from expiring unused.

        Separate federal and state income tax returns are filed for Jones Energy, Inc. and Jones Energy Holdings, LLC. JEH's Texas franchise tax returns are subject to audit for 2009, 2010, 2011, and 2012. The tax years 2010 through 2013 remain open to examination by the major taxing jurisdictions to which the Company is subject. The Company is not currently under audit in any other major taxing jurisdiction.

        Accounting for uncertainty in income taxes prescribes a recognition threshold and measurement methodology for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. As of December 31, 2013 and December 31, 2012 there was no material liability or expense for the periods then ended recorded for payments of interest and penalties associated with uncertain tax positions or material unrecognized tax positions and the Company's unrecognized tax benefits were not material.

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Earnings per Share

12 Months Ended

Dec. 31, 2013

Earnings per Share

Earnings per Share

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. On September 4, 2013 (the "grant date"), the Company granted to its directors restricted shares of Class A common stock, which vest on the first anniversary of the grant date. In accordance with ASC 260, Earnings Per Share, awards of nonvested shares shall be considered outstanding as of the grant date for purposes of computing diluted EPS even though their exercise is contingent upon vesting. For the year ended December 31, 2013, the directors' restricted shares of Class A common stock were excluded from the diluted calculation, as their inclusion would have been anti-dilutive as the Company was in a net loss position. 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 year ended December 31, 2013. Net income (loss) and the weighted average number of shares of Class A common stock outstanding is based on the actual days in which the shares were outstanding for the period from July 29, 2013, the closing date of the IPO, to December 31, 2013.

(in thousands, except per share data)	December 31, 2013
Income (numerator):
Net income (loss) attributable to controlling interests	$	(2,186	)
Weighted-average shares (denominator):
Weighted-average number of shares of Class A common stock—basic and diluted		12,500
Earnings (loss) per share:
Basic and diluted	$	(0.17	)
Anti-dilutive restricted shares of Class A common stock		27

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Long-Term Debt

12 Months Ended

Dec. 31, 2013

Long-Term Debt

Long-Term Debt

6. Long-Term Debt

        The Company entered into two credit agreements dated December 31, 2009, with Wells Fargo Bank N.A, the Senior Secured Revolving Credit Facility (the "Revolver") and the Second Lien Term Loan (the "Term Loan") which were subsequently amended on November 18, 2011, November 5, 2012, December 20, 2012, June 12, 2013, December 18, 2013 and January 29, 2014. In connection with the November 2012 amendment, the maturity date of the Revolver was extended to November 5, 2017 and the maturity date of the Term loan was extended to May 5, 2018. In connection with the June 2013 amendment, the borrowing base on the Revolver was increased to $500.0 million and subsequently increased to $575.0 million on December 18, 2013 in conjunction with the Sabine acquisition. The Company's oil and gas properties are pledged as collateral against these credit agreements.

        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 year ended December 31, 2013, the average interest rate under the Revolver was 3.01% on an average outstanding balance of $384.9 million. For the year ended December 31, 2012, the average interest rate under the Revolver was 3.30% on an average outstanding balance of $306.8 million.

        Terms of the Term Loan require the Company to pay interest on the loan every three months with the principal and interest due on the loan maturity date of May 5, 2018. Interest on the Term Loan is calculated at a base rate (LIBOR, prime, or federal funds), plus a margin of 6% to 7% based on the base rate selected. As of December 31, 2013, the average interest rate was 9.19% on an average outstanding balance of $160.0 million. As of December 31, 2012, the average interest rate was 9.16% on an average outstanding balance of $121.3 million.

        Total interest and commitment fees under the two facilities were $27.0 million, $21.2 million and $18.2 million for the years ended December 31, 2013, 2012 and 2011, respectively.

        In connection with the IPO, the Company used the net proceeds to repay outstanding borrowings under the Revolver of $167.0 million.

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

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

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Stock-based Compensation

12 Months Ended

Dec. 31, 2013

Stock-based Compensation

Stock-based Compensation

7. Stock-based Compensation

        JEH granted membership-interest awards in JEH to members of senior management ("management units") under a management incentive plan prior to the IPO. 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 December 31, 2013, there were 457,150 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:

	JEH Units			Weighted Average Grant Date Fair Value per Share
Unvested at January 1, 2013		710,767		$	3.62
Granted		911,654		$	15.00
Forfeited		(167,239	)	$	3.62
Vested		(998,032	)	$	9.96
Unvested at December 31, 2013		457,150		$	12.46

        Stock compensation expense associated with the management units for the years ended December 31, 2013, 2012 and 2011 was $10.7 million, $0.6 million and $1.1 million, respectively, and is included in general and administrative expenses on the Company's Consolidated Statement of Operations.

        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, 2013		—		—
Granted		27	$	15.05
Forfeited		—		—
Vested		—		—
Unvested at December 31, 2013		27	$	15.05

        Stock compensation expense associated with the Board of Directors awards for the year ended December 31, 2013 was $0.1 million and is included in general and administrative expenses on the Company's Consolidated Statement of Operations.

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Monarch Investment

12 Months Ended

Dec. 31, 2013

Monarch Investment

Monarch Investment

9. Monarch Investment

        On May 7, 2013, the Company entered into a marketing agreement with Monarch Natural Gas, LLC ("Monarch"), a company related through common ownership, for the sale to Monarch of natural gas produced from certain properties. In connection with that agreement, Monarch issued to the Company equity interests in its parent, Monarch Natural Gas Holdings, LLC, having an estimated fair value of $15.0 million. Contemporaneous with the execution of the marketing agreement and the issuance of the equity interests, the Company distributed 67% or $10 million of the Monarch equity interests to the Company's owners pro rata based on equity contributions and approximately 16% of the interests to a member of management. The remaining approximately 17% of the equity interests were reserved for distribution to management through an incentive plan. The Company recognized $0.3 million of compensation expense during the year ended December 31, 2013 in connection with the incentive plan. In addition, the Company recorded deferred revenue of $15.0 million which is being amortized on an estimated units-of-production basis commencing in September 2013, the first month of production sales to Monarch. The Company amortized $0.5 million of the deferred revenue balance during the year ended December 31, 2013 and is recorded in other revenues on the Company's Consolidated Statement of Operations.

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Significant Accounting Policies (Details 2) (USD $)	12 Months Ended
	Dec. 31, 2013 item Boe	Dec. 31, 2012	Dec. 31, 2011
Mineral interests in properties
Unproved	$ 114,457,000	$ 137,254,000
Proved	958,816,000	737,558,000
Wells and equipment and related facilities	609,748,000	389,727,000
Gross oil and gas properties	1,683,021,000	1,264,539,000
Less: Accumulated depletion and impairment	(370,470,000)	(257,195,000)
Net oil and gas properties	1,312,551,000	1,007,344,000
Costs capitalized in connection with exploratory wells in progress	0	0
Minimum project period for capitalization of interest on expenditures	6 months
Number of projects for which interest on expenditure is capitalized	0
Amount of capitalized interest on expenditures		100,000
Number of cubic feet of gas considered as numerator in calculation of unit conversion ratio	6,000
Depletion of oil and gas properties	113,300,000	79,900,000	68,200,000
Impairment charges of proved oil and natural gas properties and equipment	0	18,800,000	19,800,000
Impairment charges related to unproved properties	$ 14,400,000	$ 0	$ 12,200,000
Oil and gas sales | PVR Midstream
Dependence on Major Customers
Concentration risk (as a percent)	15.00%	18.00%	22.00%
Oil and gas sales | Unimark LLC
Dependence on Major Customers
Concentration risk (as a percent)	13.00%	24.00%	13.00%
Oil and gas sales | Mercuria
Dependence on Major Customers
Concentration risk (as a percent)	13.00%	18.00%
Oil and gas sales | Valero Marketing
Dependence on Major Customers
Concentration risk (as a percent)	13.00%		9.00%
Oil and gas sales | Plains Marketing
Dependence on Major Customers
Concentration risk (as a percent)	6.00%	15.00%	27.00%

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Subsidiary Guarantors (Details 2)	5 Months Ended
	Dec. 31, 2013 item
Subsidiary Guarantors
Classes of stock, number	2
Class A common stock
Subsidiary Guarantors
Economic interests	100.00%
Votes per share entitled to stockholders	1
Class B common stock
Subsidiary Guarantors
Economic interests	0.00%
Votes per share entitled to stockholders	1
Issuers
Subsidiary Guarantors
Economic interest	25.30%
Existing Owners | Class A common stock
Subsidiary Guarantors
Ratio in which JEH Units and Class B common stock is exchanged for Class A common stock	1
Issuers | Guarantor Subsidiaries
Subsidiary Guarantors
Ownership percentage in subsidiary guarantors	100.00%
Existing Owners | Issuers
Subsidiary Guarantors
Economic interest (as a percent)	74.70%

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Significant Accounting Policies (Policies)

12 Months Ended

Dec. 31, 2013

Significant Accounting Policies

Basis of Presentation

Basis of Presentation

        The accompanying 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 December 31, 2013, 2012 and 2011, and the years then ended include the Company and all of its subsidiaries.

Segment Information

Segment Information

        The Company operates in one industry segment, which is the exploration, development and production of oil and natural gas, and all of its operations are conducted in one geographic area of the United States.

Use of Estimates

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 and liabilities, fair value associated with business combinations, and asset retirement obligations ("ARO").

Financial Instruments

Financial Instruments

        Cash, accounts receivable and accounts payable are recorded at cost. The fair value of accounts receivable and accounts payable are not materially different from their carrying amounts because of the short-term nature of these instruments. The carrying values of outstanding balances under the Company's credit agreements represent fair value because the agreements have variable interest rates, which are reflective of the Company's credit risk. Derivative instruments are recorded at fair value, as discussed below.

Cash

Cash

        Cash and cash equivalents include highly liquid investments with a maturity of three months or less. At times, the amount of cash on deposit in financial institutions exceeds federally insured limits. Management monitors the soundness of the financial institutions and believes the Company's risk is negligible.

Accounts Receivable

Accounts Receivable

        Accounts receivable—Oil and gas sales consist of uncollateralized accrued revenues due under normal trade terms, generally requiring payment within 30 to 60 days of production. Accounts receivable—Joint interest owners consist of uncollateralized joint interest owner obligations due within 30 days of the invoice date. Accounts receivable—Other consist primarily of severance tax refunds due from state agencies. No interest is charged on past-due balances. The Company routinely assesses the recoverability of all material trade, joint interest and other receivables to determine their collectability, and reduces the carrying amounts by a valuation allowance that reflects management's best estimate of the amounts that may not be collected. As of December 31, 2013 and 2012, the Company did not have significant allowances for doubtful accounts.

Concentration of Risk

Concentration of Risk

        Substantially all of the Company's accounts receivable are related to the oil and gas industry. This concentration of entities may affect the Company's overall credit risk in that these entities may be affected similarly by changes in economic and other conditions. As of December 31, 2013, 79% of Accounts receivable—Oil and gas sales are due from 8 purchasers and 77% of Accounts receivable—Joint interest owners are due from 5 working interest owners. As of December 31, 2012, 92% of Accounts receivable—Oil and gas sales were due from 8 purchasers, and 72% of 2012 Accounts receivable—Joint interest owners were due from 5 working interest owners. If any or all of these significant counterparties were to fail to pay amounts due to the Company, the Company's financial position and results of operations could be materially and adversely affected.

Dependence on Major Customers

Dependence on Major Customers

        The Company maintains a portfolio of crude oil and natural gas marketing contracts with large, established refiners and oil and gas purchasers. During the year ended December 31, 2013, the largest purchasers were PVR Midstream, Unimark LLC, Mercuria, Valero, and Plains Marketing, which accounted for approximately 15%, 13%, 13%, 13% and 6% of consolidated oil and gas sales, respectively. During the year ended December 31, 2012, the largest purchasers were Unimark LLC, Mercuria, PVR Midstream, and Plains Marketing, which accounted for approximately 24%, 18%, 18% and 15% of consolidated oil and gas sales, respectively. During the year ended December 31, 2011, the largest purchasers were Plains Marketing, PVR Midstream, Unimark LLC, and Valero Marketing, which accounted for approximately 27%, 22%, 13% and 9% of consolidated oil and gas sales, respectively.

        Management believes that there are alternative purchasers and that it may be necessary to establish relationships with such new purchasers. However, there can be no assurance that the Company can establish such relationships and that those relationships will result in an increased number of purchasers. Although the Company is exposed to a concentration of credit risk, management believes that all of the Company's purchasers are credit worthy.

Dependence on Suppliers

Dependence on Suppliers

        The Company's industry is cyclical, and from time to time, there is a shortage of drilling rigs, equipment, services, supplies and qualified personnel. During these periods, the costs and delivery times of rigs, equipment, services and supplies are substantially greater. If the unavailability or high cost of drilling rigs, equipment, services, supplies or qualified personnel were particularly severe in its areas of operation, the Company could be materially and adversely affected. Management believes that there are potential alternative providers of drilling and completion services and that it may become necessary to establish relationships with new contractors. However, there can be no assurance that the Company can establish such relationships and that those relationships will result in increased availability of drilling rigs or other services, or that they could be obtained on the same terms.

Oil and Gas Properties

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 December 31, 2013 and 2012:

(in thousands of dollars)	2013			2012
Mineral interests in properties
Unproved	$	114,457		$	137,254
Proved		958,816			737,558
Wells and equipment and related facilities		609,748			389,727
		1,683,021			1,264,539
Less: Accumulated depletion and impairment		(370,470	)		(257,195	)
Net oil and gas properties	$	1,312,551		$	1,007,344

        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. In 2013, we had no material capitalized costs associated with exploratory wells. As of December 31, 2012, there were no costs capitalized in connection with exploratory wells in progress.

        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 in 2013 as no projects lasted more than six months. During the year ended December 31, 2012, the Company capitalized $0.1 million in interest. Costs incurred to maintain wells and related equipment are charged to expense as incurred.

        On the sale or retirement of a proved field, the cost and related accumulated depletion, depreciation and amortization are eliminated from the field accounts, and the resultant gain or loss is recognized.

        Capitalized amounts attributable to proved oil and gas properties are depleted by the unit-of-production method over proved reserves, using the unit conversion ratio of six thousand cubic feet of gas to one barrel of oil equivalent. Depletion of the costs of wells and related equipment and facilities, including capitalized asset retirement costs, net of salvage values, is computed using proved developed reserves. The reserve base used to calculate depreciation, depletion, and amortization for leasehold acquisition costs and the cost to acquire proved properties is the sum of proved developed reserves and proved undeveloped reserves. Depletion of oil and gas properties amounted to $113.3 million, $79.9 million and $68.2 million for the years ended December 31, 2013, 2012 and 2011, respectively.

        The Company reviews its proved oil and natural gas properties, including related wells and equipment, for impairment by comparing expected undiscounted future cash flows at a producing field level to the net capitalized cost of the asset. If the future undiscounted cash flows, based on the Company's estimate of future commodity prices, operating costs, and production, are lower than the net capitalized cost, the capitalized cost is reduced to fair value. Fair value is calculated by discounting the future cash flows at an appropriate risk-adjusted discount rate. Due to the significant assumptions associated with the inputs and calculations described, the fair value of oil and gas properties used in estimating impairment represents a nonrecurring Level 3 measurement. The Company incurred impairment charges of $18.8 million and $19.8 million related to its proved oil and natural gas properties and equipment in 2012 and 2011, respectively. No impairments of proved properties were recorded in 2013.

        The Company evaluates its unproved properties for impairment on a property-by-property basis. The Company's unproved property consists of acquisition costs related to its undeveloped acreage. The Company reviews the unproved property for indicators of impairment based on the Company's current exploration plans with consideration given to results of any drilling and seismic activity during the period and known information regarding exploration activity by other companies on adjacent blocks. In the fourth quarter of 2013, the Company recorded an impairment charge of $14.4 million related to its unproved Southridge properties. As the Company did not drill the required number of wells by October 31, 2013 necessary to keep its joint development agreement with Southridge in effect, the Company lost its right to the undeveloped acreage. The Company incurred no impairment charges related to its unproved properties in 2012. In 2011, the Company incurred a $12.2 million impairment charge related to its unproven properties in fields which were not expected to produce natural gas with a sufficiently high liquid content reducing the economic return of those fields. These charges represent nonrecurring Level 3 measurements. Impairment of oil and gas properties charges are recorded on the Consolidated Statement of Operations.

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

Other Property, Plant and Equipment

Other Property, Plant and Equipment

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

(in thousands of dollars)	2013			2012
Leasehold improvements	$	1,060		$	983
Furniture, fixtures, computers and software		2,491			2,204
Vehicles		835			719
Aircraft		910			1,295
Other		134			134
		5,430			5,335
Less: Accumulated depreciation and amortization		(1,986	)		(1,937	)
Net other property, plant and equipment	$	3,444		$	3,398

        Other property, plant and equipment is depreciated on a straight-line basis over the estimated useful lives of the property, plant and equipment, which range from three years to ten years. Depreciation and amortization of other property, plant and equipment amounted to $0.8 million, $0.8 million and $0.7 million during the years ended December 31, 2013, 2012 and 2011, respectively.

Oil and Gas Sales Payable

Oil and Gas Sales Payable

        Oil and gas sales payable represents amounts collected from purchasers for oil and gas sales, which are due to other revenue interest owners. Generally, the Company is required to remit amounts due under these liabilities within 60 days of receipt.

Commodity Derivatives

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 years ended December 31, 2013, 2012 and 2011, 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 Jones 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 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

Asset Retirement Obligations

        The Company's asset retirement obligations consist of future plugging and abandonment expenses on oil and natural gas properties. The Company estimates an ARO for each well in the period in which it is incurred based on estimated present value of plugging and abandonment costs, increased by an inflation factor to the estimated date that the well would be plugged. The resulting liability is recorded by increasing the carrying amount of the related long-lived asset. The liability is then accreted to its then-present value each period and the capitalized cost is depleted over the useful life of the related asset. If the liability is settled for an amount other than the recorded amount, a gain or loss is recognized. The ARO is classified as current or noncurrent based on the expect timing of payments. A summary of the Company's ARO for the years ended December 31, 2013 and 2012 is as follows:

(in thousands of dollars)	2013			2012
ARO liability at beginning of year	$	9,506		$	9,563
Liabilities incurred(1)		1,515			662
Accretion of discount		608			596
Liabilities settled due to sale of related properties		(271	)		(927	)
Liabilities settled due to plugging and abandonment		(702	)		(388	)
Change in estimate		307			—
ARO liability at end of year		10,963			9,506
Less: Current portion of ARO at end of year		(2,590	)		(174	)
Total long-term ARO at end of year	$	8,373		$	9,332

(1)

Includes $824 related to wells acquired (see Note 3, "Acquisition of Properties").

Revenue Recognition

Revenue Recognition

        Revenues from the sale of crude oil, natural gas, and natural gas liquids are recognized when the product is delivered at a fixed or determinable price, title has transferred, collectability is reasonably assured and evidenced by a contract. The Company follows the "sales method" of accounting for its oil and natural gas revenue, so it recognizes revenue on all crude oil, natural gas, and natural gas liquids sold to purchasers. A receivable or liability is recognized only to the extent that the Company has an imbalance on a specific property greater than the expected remaining proved reserves.

Production Costs

Production Costs

        Production costs, including compressor rental, pumpers' salaries, saltwater disposal, ad valorem taxes, insurance, repairs and maintenance, expensed workovers and other operating expenses are expensed as incurred and included in lease operating expense on the Consolidated Statement of Operations.

Exploration Expenses

Exploration Expenses

        Exploration expenses include dry hole costs, lease extensions, delay rentals and geological and geophysical costs.

Income Taxes

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.

Tax Receivable Agreement

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 December 31, 2013, there have been no exchanges and no liability is recorded on the Consolidated Balance Sheet.

Comprehensive Income

Comprehensive Income

        The Company has no elements of comprehensive income other than net income.

Statement of Cash Flows

Statement of Cash Flows

        The Company presents its cash flows using the indirect method.

Related Party Transactions

Related Party Transactions

        In the years ended December 31, 2013, 2012 and 2011, the Company paid an annual administration fee to Metalmark of $0.7 million. This amount was charged to expense. As a result of the IPO, this fee is no longer payable to Metalmark.

        On May 7, 2013, the Company entered into a natural gas sale and purchase agreement with Monarch Natural Gas, LLC, or Monarch, under which Monarch has the first right to gather the natural gas the Company produces from the Chalker properties, process the NGLs from this natural gas production and market the processed natural gas and extracted NGLs. Under the Monarch agreement, the Company is paid a specified percentage of the value of the NGLs extracted and sold by Monarch, based on a set liquids recovery percentage, and the amount received from the sale of the residue gas, after deducting a fixed volume for fuel, lost and unaccounted for gas. For the year ended December 31, 2013, the Company produced approximately 0.8 MMBoe of natural gas and NGLs from the Chalker properties that became subject to the Monarch agreement. The initial term of the agreement runs for 10 years from the effective date of September 1, 2013. At the time the Company entered into the agreement, Metalmark Capital owned approximately 81% of the outstanding equity interests of Monarch. In addition, Metalmark Capital beneficially owns in excess of five percent of the Company's outstanding equity interests and two of our directors, Howard I. Hoffen and Gregory D. Myers, are managing directors of Metalmark Capital. In connection with the Company's entering into the Monarch agreement, Monarch issued to JEH equity interests in Monarch having a deemed value of $15 million. JEH assigned $2.4 million of the Monarch equity interests to Jonny Jones, the Company's chief executive officer and chairman of the board, and reserved $2.6 million of the Monarch equity interests to a benefit plan established for certain of the Company's officers, including Mike McConnell, Robert Brooks and Eric Niccum. The remaining $10 million of Monarch equity was distributed to certain of the pre-IPO owners, which include Metalmark Capital, Wells Fargo, the Jones family entities, and certain of the Company's officers and directors, including Jonny Jones, Mike McConnell, Robert Brooks and Eric Niccum.

Stock Compensation

Stock Compensation

        JEH implemented a management incentive plan effective January 1, 2010, 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 have a single vesting structure of 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. At December 31, 2013, there were 457,150 unvested JEH Units and shares of Class B common stock that will become convertible into a like number of shares of Class A common stock upon vesting.

        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. As of December 31, 2013 no such awards had been issued or granted to any of the Company's employees.

        On September 4, 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 grants 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.

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

Business Combinations

Business Combinations

        For acquisitions of working interests that are accounted for as business combinations, the results of operations are included in the Consolidated Statement of Operations from the date of acquisition. Purchase prices are allocated to assets acquired based on their estimated fair values at the time of acquisition. 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. The fair value measurement is based on the assumptions of market participants and not those of the reporting entity. Therefore, entity-specific intentions do not impact the measurement of fair value. The fair value of oil and natural gas properties is determined using a risk-adjusted after-tax discounted cash flow analysis based upon significant inputs including: 1) oil and gas prices, 2) projections of estimated quantities of oil and natural gas reserves, including those classified as proved, probable and possible, 3) projections of future rates of production, 4) timing and amount of future development and operating costs, 5) projected reserve recovery factors, and 6) weighted average cost of capital.

Recent Accounting Developments

Recent Accounting Developments

        The following recently issued accounting pronouncement has been adopted by the Company:

Offsetting Assets and Liabilities

Offsetting Assets and Liabilities

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

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Stock-based Compensation (Tables)

12 Months Ended

Dec. 31, 2013

Non-employee members of Board Of Directors | Restricted stock

Stock-based Compensation

Summary of information related to the Units/shares or awards

	Restricted Stock Awards		Weighted Average Grant Date Fair Value per Share
Unvested at January 1, 2013		—		—
Granted		27	$	15.05
Forfeited		—		—
Vested		—		—
Unvested at December 31, 2013		27	$	15.05

Management incentive plan | Management units | Management

Stock-based Compensation

Summary of information related to the Units/shares or awards

	JEH Units			Weighted Average Grant Date Fair Value per Share
Unvested at January 1, 2013		710,767		$	3.62
Granted		911,654		$	15.00
Forfeited		(167,239	)	$	3.62
Vested		(998,032	)	$	9.96
Unvested at December 31, 2013		457,150		$	12.46

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Income Taxes (Details) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Current tax expense
Federal	$ 85,000
Total current expense	85,000
Deferred tax expense (benefit)
Federal	(1,260,000)
State	1,104,000	473,000	173,000
Total deferred expense (benefit)	(156,000)	473,000	173,000
Total income tax provision	(71,000)	473,000	173,000
Tax benefit attributable to controlling interests	(1,223,000)
Tax expense attributable to non-controlling interests	1,152,000	473,000	173,000
Provision calculated at federal statutory income tax rate:
Net income before taxes	22,334,000	(2,606,000)	60,499,000
Statutory rate (as a percent)	35.00%
Income tax expense computed at statutory rate	7,817,000
Less: Noncontrolling interests	(9,009,000)
Income tax benefit attributable to Jones Energy, Inc.	(1,192,000)
State and local income taxes, net of federal benefit	(49,000)
Other	18,000
Tax benefit attributable to Jones Energy, Inc.	(1,223,000)
Tax expense attributable to non-controlling interest	1,152,000	473,000	173,000
Total income tax provision	(71,000)	473,000	173,000
Deferred tax assets
Investment in consolidated subsidiary JEH	526,000
Net operating loss	649,000
Alternative minimum tax credits	86,000
State deferred tax asset	52,000
Total deferred tax assets	1,313,000
Deferred tax liabilities
State deferred tax liability	3,093,000	1,936,000
Total deferred tax liabilities	3,093,000	1,936,000
Net deferred tax assets (liabilities)	(1,780,000)	(1,936,000)
Net deferred tax assets (liabilities)	(1,780,000)	(1,936,000)
Federal
Operating loss carry-forward
Net operating loss carry-forward	1,800,000
State
Operating loss carry-forward
Net operating loss carry-forward	$ 400,000

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Fair Value Measurement (Details 3) (USD $)	12 Months Ended
	Dec. 31, 2013 item	Dec. 31, 2012	Dec. 31, 2011
Changes in fair value of Level 3 instruments
Balance at the beginning of the period	$ (1,519,000)	$ (2,083,000)
Purchases	(1,095,000)	(2,352,000)
Settlements	(210,000)
Transfer to Level 2	(753,000)	2,370,000
Transfers to Level 3		834,000
Changes in fair value	2,342,000	(288,000)
Balance at the end of the period	(1,235,000)	(1,519,000)	(2,083,000)
Offsetting Assets and Liabilities
Number of counterparties to commodity derivative contracts	6
Nonfinancial Assets and Liabilities
Impairment of proved properties	0	18,800,000	19,800,000
Impairment of unproved properties	14,400,000	0	12,200,000
Commodity derivatives
Assets
Gross Amounts of Recognized Assets / Liabilities	38,071,000	49,200,000
Gross Amounts Offset in the Balance Sheet	(6,035,000)	(7,831,000)
Net Amounts of Assets Presented in the Balance Sheet	32,036,000	41,369,000
Gross Amounts Not Offset in the Balance Sheet	2,199,000	1,478,000
Net Amount	34,235,000	42,847,000
Liabilities
Gross Amounts of Recognized Assets	(14,347,000)	(17,928,000)
Gross Amounts Offset in the Balance Sheet	6,035,000	7,831,000
Net Amounts of Assets Presented in the Balance Sheet	(8,312,000)	(10,097,000)
Gross Amounts Not Offset in the Balance Sheet	(2,542,000)	(1,595,000)
Net Amount	$ (10,854,000)	$ (11,692,000)

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Consolidated Statement of Changes In Stockholders' / Members' Equity (USD $) In Thousands, unless otherwise specified	Total	Common Stock Class A common stock	Common Stock Class B common stock	Members' Equity	Additional Paid-in-Capital	Retained Deficit	Non-controlling interest
Balance at Dec. 31, 2010	$ 284,449			$ 284,449
Increase (Decrease) Stockholders' / members' equity
Stock-compensation expense	1,134			1,134
Net income (loss)	60,326			60,326
Balance at Dec. 31, 2011	345,909			345,909
Increase (Decrease) Stockholders' / members' equity
Issuance of Class C Preferred Units	85,000			85,000
Stock-compensation expense	570			570
Net income (loss)	(3,079)			(3,079)
Balance at Dec. 31, 2012	428,400			428,400
Increase (Decrease) Stockholders' / members' equity
Issuance of common stock	50	13	37
Issuance of common stock (in shares)		12,500	36,836
Proceeds from the sale of common stock	172,431				172,431
Reclassification of members' contributions				(464,037)			464,037
Stock-compensation expense	10,838			10,100	738
Distribution to members	(10,000)			(10,000)
Net income (loss)	22,405			35,537		(2,186)	(10,946)
Balance at Dec. 31, 2013	$ 624,124	$ 13	$ 37		$ 173,169	$ (2,186)	$ 453,091
Balance (in shares/units) at Dec. 31, 2013		12,500	36,836

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Acquisition of Properties

12 Months Ended

Dec. 31, 2013

Acquisition of Properties

Acquisition of Properties

3. Acquisition of Properties

        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 adjusted 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. The purchase price was allocated as follows:

(in thousands of dollars)
Oil and gas properties
Unproved	$	39,596
Proved		154,724
Asset retirement obligations		(824	)
Total purchase price	$	193,496

        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, which when they occur, may result in an adjustment to the value of the acquired properties reflected in the consolidated financial statements. Any such adjustment may be material.

        In connection with the closing, approximately $24 million of the purchase price was placed in an escrow account. This amount represented the allocated value of the Sabine properties that had unresolved title defects claimed by JEH. In the event one or more title defects are not cured by Sabine, the affected property will be reconveyed to Sabine and the Company will receive an amount of cash from the escrow account equal to the allocated value of the reconveyed property. A corresponding adjustment to the allocation of the Sabine purchase price will be made at such time.

        The unaudited pro forma results presented below have been prepared to include the effect of the Sabine acquisition on our results of operations for the year ended December 31, 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.

			Year Ended December 31, 2013
	Post Acquisition(1)
(in thousands of dollars)			Pro Forma
	(unaudited)		(unaudited)
Total operating revenue	$	1,365	$	308,773
Total operating expenses		291		229,648
Operating income		1,074		79,125
Net income		1,074		45,778

(1)

Represents revenues and expenses for the post acquisition period of December 18, 2013 to December 31, 2013 included in the Consolidated Statement of Operations.

        On December 20, 2012, JEH acquired certain oil and natural gas properties located in Texas for a purchase price of $251.9 million (referred to herein as the "Chalker acquisition" or "Chalker"). The acquired assets included both producing properties and undeveloped acreage. The purchase was financed with additional equity capital and borrowings under the senior secured credit facility. In the second quarter of 2013, the Company made a final determination with the sellers as to the purchase price adjustments resulting in a final purchase price of $253.5 million. The final purchase price was allocated as follows:

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

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

        The unaudited pro forma results presented below have been prepared to include the effect of the Chalker acquisition on our results of operations for the year ended December 31, 2012. The unaudited pro forma results do not purport to represent what our actual results of operations would have been if the acquisition had been completed on January 1, 2012 or to project our results of operations for any future date or period.

	Year Ended December 31, 2012
(in thousands of dollars)	Pro Forma
	(unaudited)
Total operating revenue	$	194,685
Total operating expenses		161,053
Operating income		33,632
Net income		25,713

        On April 14, 2011, Jones Energy acquired certain oil and natural gas properties located in Oklahoma for a purchase price of $154.1 million. The acquisition included both producing and undeveloped properties. The purchase was financed with additional borrowings under the senior secured credit facility. The purchase price was allocated as follows:

(in thousands of dollars)
Oil and gas properties	$	154,225
Asset retirement obligations		(167	)
Total purchase price	$	154,058

        This acquisition qualified as a business combination under ASC 805. The Company recorded a total fair value of $180.3 million ($154.1 million for producing properties and $26.2 million for undeveloped property). The total resulted in a bargain purchase gain of $26.2 million, which was recorded in the Consolidated Statement of Operations. The valuation to determine the fair value was principally based on the discounted cash flows of the both the producing and undeveloped properties, including projected drilling and equipment costs, recoverable reserves, production streams, future prices and operating costs, and risk-adjusted discount rates reflective of the current market. The recognized gain was the difference between the net fair value and the consideration paid the seller.

        Management believes the bargain purchase gain resulted from the fact that the seller, who retained a 50% ownership interest in the undeveloped properties, benefitted from the Company's available liquidity that would enable accelerated development of the prospect.

        The following income statement line items present the pro forma results as if these properties had been acquired on January 1, 2010:

	Year Ended December 31, 2011
(in thousands of dollars)	Pro Forma
	(unaudited)
Total operating revenue	$	176,884
Total operating expenses		150,197
Operating income		26,687
Net income		62,408

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Earnings per Share (Tables)

12 Months Ended

Dec. 31, 2013

Earnings per Share

Schedule of calculation of the basic and diluted weighted-average shares and EPS

(in thousands, except per share data)	December 31, 2013
Income (numerator):
Net income (loss) attributable to controlling interests	$	(2,186	)
Weighted-average shares (denominator):
Weighted-average number of shares of Class A common stock—basic and diluted		12,500
Earnings (loss) per share:
Basic and diluted	$	(0.17	)
Anti-dilutive restricted shares of Class A common stock		27

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Acquisition of Properties (Details) (USD $)	12 Months Ended			0 Months Ended				12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Dec. 18, 2013	Dec. 31, 2013	Dec. 20, 2012	Apr. 14, 2011	Dec. 31, 2010
Oil and gas properties
Bargain purchase gain			$ 26,208,000
Post Acquisition
Total operating revenues	259,169,000	149,814,000	168,283,000
Total operating expenses	203,417,000	144,974,000	145,629,000
Operating income	55,752,000	4,840,000	22,654,000
Net income	(2,186,000)	(3,079,000)	60,326,000
Sabine acquisition
Acquisition of Properties
Initial purchase price				193,500,000
Oil and gas properties
Unproved				39,596,000
Proved				154,724,000
Asset retirement obligations				(824,000)
Total purchase price				193,496,000
Purchase price placed in escrow account				24,000,000
Post Acquisition
Total operating revenues					1,365,000
Total operating expenses					291,000
Operating income					1,074,000
Net income					1,074,000
Pro Forma
Total operating revenue	308,773,000
Total operating expenses	229,648,000
Operating income	79,125,000
Net income	45,778,000
Chalker acquisition
Acquisition of Properties
Initial purchase price						251,900,000
Oil and gas properties
Unproved						71,264,000
Proved						182,493,000
Asset retirement obligations						(293,000)
Total purchase price						253,464,000
Post Acquisition
Net income		(2,501,000)	61,130,000
Pro Forma
Total operating revenue		194,685,000
Total operating expenses		161,053,000
Operating income		33,632,000
Net income		25,713,000
Oil and natural gas properties located in Oklahoma
Acquisition of Properties
Initial purchase price							154,100,000
Oil and gas properties
Unproved							26,200,000
Proved							154,100,000
Oil and gas properties							154,225,000
Asset retirement obligations							(167,000)
Total purchase price							154,058,000
Total fair value							180,300,000
Bargain purchase gain							26,200,000
Ownership interest in the undeveloped properties (as a percent)							50.00%
Post Acquisition
Net income			61,130,000					24,780,000
Pro Forma
Total operating revenue			176,884,000
Total operating expenses			150,197,000
Operating income			26,687,000
Net income			$ 62,408,000

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Subsidiary Guarantors

12 Months Ended

Dec. 31, 2013

Subsidiary Guarantors

Subsidiary Guarantors

13. Subsidiary Guarantors

On April 1, 2014, JEH and its wholly-owned subsidiary, Jones Energy Finance Corp. (the “Issuers”), sold $500.0 million in aggregate principal amount of the Issuers’ 6.75% Senior Notes due 2022 (the “2022 Notes”).

The 2022 Notes are guaranteed on a senior unsecured basis by the Company and by all of JEH’s current subsidiaries (except Jones Energy Finance Corp. and two immaterial subsidiaries) and certain future subsidiaries, including any future subsidiaries that guarantee any indebtedness under the Company’s Revolver. Each subsidiary guarantor is 100% owned by JEH, and all guarantees are full, unconditional, and joint and several with all other subsidiary guarantees and the parent guarantee. Any subsidiaries of JEH other than the subsidiary guarantors and Jones Energy Finance Corp. are minor.

The Company is a holding company and has no independent assets or operations of its own.  The Company is the sole managing member of JEH and is responsible for all operational, management and administrative decisions related to JEH’s business. In accordance with JEH’s limited liability company agreement, the Company may not be removed as the sole managing member of JEH.

The Company currently holds approximately 25.3% of the economic interest in JEH, with the remaining 74.7% economic interest held by a group of investors that owned interests in JEH prior to the Company’s IPO (the “Existing Owners”). The Existing Owners have no voting rights with respect to their economic interest in JEH.

The Company has two classes of common stock, Class A common stock, which was sold to investors in the IPO, and Class B common stock.  Pursuant to the Company’s certificate of incorporation, each share of Class A common stock is entitled to one vote per share, and the shares of Class A common stock are entitled to 100% of the economic interests in the Company. Each share of Class B common stock has no economic rights in the Company, but entitles its holder to one vote on all matters to be voted on by the Company’s stockholders generally.

In connection with a reorganization that occurred immediately prior to the IPO, each Existing Owner was issued a number of shares of Class B common stock that is equal to the number of JEH Units that such Existing Owner holds. Holders of the Company’s Class A common stock and Class B common stock generally vote together as a single class on all matters presented to the Company’s stockholders for their vote or approval. Accordingly, the Existing Owners collectively have a number of votes in the Company equal to the aggregate number of JEH Units that they hold.

The Existing Owners have the right, pursuant to the terms of an Exchange Agreement by and among the Company, JEH and each of the Existing Owners, to exchange their JEH Units (together with a corresponding number of shares of Class B common stock) 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.  As a result, the Company expects that over time the Company will have an increasing economic interest in JEH as Class B common stock and JEH Units are exchanged for Class A common stock.  Moreover, any transfers of JEH Units outside of the Exchange Agreement (other than permitted transfers to affiliates) must be approved by the Company.  The Company intends to retain full voting and management control over JEH.

Jones Energy, Inc.

Condensed Consolidating Statements of Operations

Year Ended December 31, 2013

	Year Ended December 31, 2013
(in thousands of dollars)	JEI(Parent)			Issuers			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations		Consolidated
Operating revenues
Oil and gas sales	$	—		$	—		$	258,063		$	—		$	—	$	258,063
Other revenues	—			469			637			—			—		1,106
Total operating revenues	—			469			258,700			—			—		259,169
Operating costs and expenses
Lease operating	—			—			27,781			—			—		27,781
Production taxes	—			—			12,865			—			—		12,865
Exploration	—			—			1,710			—			—		1,710
Depletion, depreciation and amortization	—			—			114,046			90			—		114,136
Impairment of oil and gas properties	—			—			14,415			—			—		14,415
Accretion of discount	—			—			608			—			—		608
General and administrative (including non-cash compensation expense)	—			4,154			27,490			258			—		31,902
Total operating expenses	—			4,154			198,915			348			—		203,417
Operating income	—			(3,685		)	59,785			(348		)	—		55,752
Other income (expense)
Interest expense	—			(29,653		)	(1,121		)	—			—		(30,774		)
Net gain (loss) on commodity derivatives	—			(2,566		)	—			—			—		(2,566		)
Gain (loss) on sales of assets	—			—			41			(119		)	—		(78		)
Other income (expense), net	—			(32,219		)	(1,080		)	(119		)	—		(33,418		)
Income (loss) before income tax	—			(35,904		)	58,705			(467		)	—		22,334
Equity interest in Income	(3,400		)	—			—			—			3,400		—
Income tax provision (benefit)
Current	85			—			—			—			—		85
Deferred	(1,299		)	1,143			—			—			—		(156		)
Total income tax provision (benefit)	(1,214		)	1,143			—			—			—		(71		)
Net income (loss)	$	(2,186	)	$	(37,047	)	$	58,705		$	(467	)	$	3,400	$	22,405
Net income (loss) attributable to non-controlling interests	—			—			—			—			$	24,591	$	24,591
Net income (loss) attributable to controlling interests	$	(2,186	)	—			—			—			—		$	(2,186	)

Jones Energy, Inc.

Condensed Consolidating Statements of Operations

Year Ended December 31, 2012

	Year Ended December 31, 2012
(in thousands of dollars)	JEI(Parent)		Issuers			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations		Consolidated
Operating revenues
Oil and gas sales	$	—	$	—		$	148,967		$	—		$	—	$	148,967
Other revenues	—		—			847			—			—		847
Total operating revenues	—		—			149,814			—			—		149,814
Operating costs and expenses
Lease operating	—		—			23,097			—			—		23,097
Production taxes	—		—			5,583			—			—		5,583
Exploration	—		—			356			—			—		356
Depletion, depreciation and amortization	—		—			80,554			155			—		80,709
Impairment of oil and gas properties	—		—			18,821			—			—		18,821
Accretion of discount	—		—			533			—			—		533
General and administrative (including non-cash compensation expense)	—		2,589			12,562			724			—		15,875
Total operating expenses	—		2,589			141,506			879			—		144,974
Operating income	—		(2,589		)	8,308			(879		)	—		4,840
Other income (expense)
Interest expense	—		(24,679		)	(613		)	—			—		(25,292		)
Net gain (loss) on commodity derivatives	—		16,684			—			—			—		16,684
Gain (loss) on sales of assets	—		—			1,162			—			—		1,162
Other income (expense), net	—		(7,995		)	549			—			—		(7,446		)
Income (loss) before income tax	—		(10,584		)	8,857			(879		)	—		(2,606		)
Income tax provision (benefit)
Current	—		—			—			—			—		—
Deferred	—		473			—			—			—		473
Total income tax provision (benefit)	—		473			—			—			—		473
Net income (loss)	$	—	$	(11,057	)	$	8,857		$	(879	)	$	—	$	(3,079	)

Jones Energy, Inc

Condensed Consolidating Balance Sheet

December 31, 2013

	December 31, 2013
(in thousands of dollars)	JEI(Parent)			Issuers		Guarantor Subsidiaries		Non-Guarantor Subsidiaries			Eliminations			Consolidated
Assets
Current assets
Cash	$	100		$	6,000	$	17,650	$	70		$	—		$	23,820
Restricted Cash	—			—		45		—			—			45
Accounts receivable, net
Oil and gas sales	—			—		51,233		—			—			51,233
Joint interest owners	—			—		42,481		—			—			42,481
Other	—			—		1,459		—			—			1,459
Commodity derivative assets	—			8,837		—		—			—			8,837
Other current assets	—			387		2,005		—			—			2,392
Deferred tax assets	—			12		—		—			—			12
Intercompany receivable	638			1,051,389		—					(1,052,027		)	—
Total current assets	738			1,066,625		114,873		70			(1,052,027		)	130,279
Oil and gas properties, net, at cost under the successful efforts method	—			—		1,312,551		—			—			1,312,551
Other property, plant and equipment, net	—			—		2,557		887			—			3,444
Commodity derivative assets	—			25,398		—		—			—			25,398
Other assets	—			14,072		934		—			—			15,006
Investment in Subsidiaries	169,081			—		—		—			(169,081		)	—
Deferred tax assets	1,301			—		—		—			—			1,301
Total assets	$	171,120		$	1,106,095	$	1,430,915	$	957		$	(1,221,108	)	$	1,487,979
Liabilities and Stockholders’ / Members’ Equity
Current liabilities
Trade accounts payable	$	—		$	230	$	89,200	$	—		$	—		$	89,430
Oil and gas sales payable	—			—		66,179		—			—			66,179
Accrued liabilities	87			1,642		9,076		—			—			10,805
Commodity derivative liabilities	—			10,664		—		—			—			10,664
Deferred tax liabilities	—			—		—		—			—			—
Asset retirement obligations	—			—		2,590		—			—			2,590
Intercompany payable				—		1,051,935		2,279			(1,054,214		)	—
Total current liabilities	87			12,536		1,218,980		2,279			(1,054,214		)	179,668
Long-term debt	—			658,000		—		—			—			658,000
Deferred revenue	—			14,531		—		—			—			14,531
Commodity derivative liabilities	—			190		—		—			—			190
Asset retirement obligations	—			—		8,373		—			—			8,373
Deferred tax liabilities	—			3,093		—		—			—			3,093
Total liabilities	87			688,350		1,227,353		2,279			(1,054,214		)	863,855
Commitments and contingencies (Note 10)
Stockholders’ / members’ equity
Members’ equity	—			417,745		203,562		(1,322		)	(619,985		)	—
Class A common stock, $0.001 par value; 12,526,580 shares issued and outstanding	13			—		—		—			—			13
Class B common stock, $0.001 par value; 36,836,333 shares issued and outstanding	37			—		—		—			—			37
Additional paid-in-capital	173,169			—		—		—			—			173,169
Retained earnings (deficit)	(2,186		)	—		—		—			—			(2,186		)
Stockholders’ / members’ equity	171,033			417,745		203,562		(1,322		)	(619,985		)	171,033
Non-controlling interest	—			—		—		—			453,091			453,091
Total stockholders’ / members’ equity	171,033			417,745		203,562		(1,322		)	(166,894		)	624,124
Total liabilities and stockholders’ / members’ equity	$	171,120		$	1,106,095	$	1,430,915	$	957		$	(1,221,108	)	$	1,487,979

Jones Energy, Inc

Condensed Consolidating Balance Sheet

December 31, 2012

	December 31, 2012
(in thousands of dollars)	JEI(Parent)		Issuers		Guarantor Subsidiaries		Non-Guarantor Subsidiaries			Eliminations			Consolidated
Assets
Current assets
Cash	$	—	$	5,056	$	18,600	$	70		$	—		$	23,726
Restricted Cash	—		—		—		—			—			—
Accounts receivable, net
Oil and gas sales	—		—		29,684		—			—			29,684
Joint interest owners	—		—		21,876		—			—			21,876
Other	—		1,719		2,871		—			—			4,590
Commodity derivative assets	—		17,648		—		—			—			17,648
Other current assets	—		—		1,088		—			—			1,088
Deferred tax assets	—		—		—		—			—			—
Intercompany receivable	—		845,184		—		—			(845,184		)	—
Total current assets	—		869,607		74,119		70			(845,184		)	98,612
Oil and gas properties, net, at cost
under the successful efforts method	—		—		1,007,344		—			—			1,007,344
Other property, plant and equipment, net	—		—		2,568		830			—			3,398
Commodity derivative assets	—		25,199		—		—			—			25,199
Other assets	—		13,446		2,687		—			—			16,133
Deferred tax assets	—		—		—		—			—			—
Total assets	$	—	$	908,252	$	1,086,718	$	900		$	(845,184	)	$	1,150,686
Liabilities and Stockholders’ / Members’ Equity
Current liabilities
Trade accounts payable	$	—	$	116	$	37,920	$	—		$	—		$	38,036
Oil and gas sales payable	—		—		45,860		—			—			45,860
Accrued liabilities	—		110		5,145		—			—			5,255
Commodity derivative liabilities	—		4,035		—		—			—			4,035
Deferred tax liabilities	—		61		—		—			—			61
Asset retirement obligations	—		—		174		—			—			174
Intercompany payable	—		—		843,430		1,754			(845,184		)	—
Total current liabilities	—		4,322		932,529		1,754			(845,184		)	93,421
Long-term debt	—		610,000		—		—			—			610,000
Deferred revenue	—		—		—		—			—			—
Commodity derivative liabilities	—		7,657		—		—			—			7,657
Asset retirement obligations	—		—		9,332		—			—			9,332
Deferred tax liabilities	—		1,876		—		—			—			1,876
Total liabilities	—		623,855		941,861		1,754			(845,184		)	722,286
Commitments and contingencies (Note 10)
Stockholders’ / members’ equity
Members’ equity	—		284,397		144,857		(854		)	—			428,400
Stockholders’ / members’ equity	—		284,397		144,857		(854		)	—			428,400
Total stockholders’ / members’ equity	—		284,397		144,857		(854		)	—			428,400
Total liabilities and stockholders’ / members’ equity	$	—	$	908,252	$	1,086,718	$	900		$	(845,184	)	$	1,150,686

Jones Energy, Inc.

Consolidated Statements of Cash Flows

Years Ended December 31, 2013

	Year Ended December 31, 2013
(in thousands of dollars)	JEI(Parent)			Issuers			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated
Cash flows from operating activities
Net income (loss)	$	(2,186	)	$	(37,047	)	$	58,705		$	(467	)	$	3,400		$	22,405
Adjustments to reconcile net income (loss) to net cash provided by operating activities	2,286			(189,393		)	331,265			733			(3,400		)	141,491
Net cash (used in) / provided by operations	100			(226,440		)	389,970			266			—			163,896
Cash flows from investing activities
Investment in subsidiary	(172,481		)										172,481			—
Additions to oil and gas properties	—			—			(197,618		)							(197,618		)
Acquisition of properties	—			—			(193,496		)							(193,496		)
Proceeds from sales of assets	—			—			963			644						1,607
Acquisition of other property, plant and equipment	—			—			(724		)	(910		)				(1,634		)
Current period settlements of matured derivative contracts	—			7,586			—			—						7,586
Change in restricted cash	—			—			(45		)	—						(45		)
Net cash (used in) / provided by investing	(172,481		)	7,586			(390,920		)	(266		)	172,481			(383,600		)
Cash flows from financing activities
Proceeds from investment by JEI				172,481									(172,481		)	—
Proceeds from issuance of long-term debt	—			220,000			—			—						220,000
Repayment under long-term debt	—			(172,000		)	—			—						(172,000		)
Payment of debt issuance costs	—			(683		)	—			—						(683		)
Proceeds from sale of common stock, net of expenses of $15.1 million	172,481			—			—			—						172,481
Net cash (used in) provided by financing	172,481			219,798			—			—			(172,481		)	219,798
Net increase (decrease) in cash	100			944			(950		)	—			—			94
Cash
Beginning of period	—			5,056			18,600			70			—			23,726
End of period	$	100		$	6,000		$	17,650		$	70		—			$	23,820

Jones Energy, Inc.

Consolidated Statements of Cash Flows

Years Ended December 31, 2012

	Year Ended December 31, 2012
(in thousands of dollars)	JEI(Parent)		Issuers			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Consolidated
Cash flows from operating activities
Net income (loss)	$	—	$	(11,057	)	$	8,857		$	(879	)	$	(3,079	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities			(283,848		)	370,623			854			87,629
Net cash (used in) / provided by operations	—		(294,905		)	379,480			(25		)	84,550
Cash flows from investing activities
Additions to oil and gas properties	—		—			(125,493		)	—			(125,493		)
Acquisition of properties	—		—			(249,007		)	—			(249,007		)
Proceeds from sales of assets	—		—			9,158			—			9,158
Acquisition of other property, plant and equipment	—		—			(969		)	—			(969		)
Current period settlements of matured derivative contracts	—		28,675			—			—			28,675
Change in restricted cash	—		—			—			—			—
Net cash (used in) / provided by investing	—		28,675			(366,311		)	—			(337,636		)
Cash flows from financing activities
Proceeds from issuance of long-term debt	—		233,243			—			—			233,243
Repayment under long-term debt	—		(38,243		)	—			—			(38,243		)
Payment of debt issuance costs	—		(9,324		)	—			—			(9,324		)
Issuance of preferred units	—		85,000			—			—			85,000
Net cash provided by financing	—		270,676			—			—			270,676
Net increase (decrease) in cash	—		4,446			13,169			(25		)	17,590
Cash
Beginning of period	—		610			5,431			95			6,136
End of period	$	—	$	5,056		$	18,600		$	70		$	23,726