Jones Energy (JONEQ) 8-K 2016 FY Report of Independent Registered Public Accounting Firm

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’ equity, and of cash flows present fairly, in all material respects, the financial position of Jones Energy, Inc. and its subsidiaries as of December 31, 2016 and 2015 and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2016 in conformity with 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 financial 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 10, 2017, except for the effects of the special stock dividend described in Note 16 and changes in the subsidiary guarantor information described in Note 17, as to which the date is June 8, 2017

Jones Energy, Inc.

Consolidated Balance Sheets

December 31, 2016 and 2015

	December 31,			December 31,
(in thousands of dollars)	2016			2015
Assets
Current assets
Cash	$	34,642		$	21,893
Accounts receivable, net
Oil and gas sales	26,568			19,292
Joint interest owners	5,267			11,314
Other	6,061			15,170
Commodity derivative assets	24,100			124,207
Other current assets	2,684			2,298
Total current assets	99,322			194,174
Oil and gas properties, net, at cost under the successful efforts method	1,743,588			1,635,766
Other property, plant and equipment, net	2,996			3,873
Commodity derivative assets	34,744			93,302
Other assets	6,050			8,039
Total assets	$	1,886,700		$	1,935,154
Liabilities and Stockholders’ Equity
Current liabilities
Trade accounts payable	$	36,527		$	7,467
Oil and gas sales payable	28,339			32,408
Accrued liabilities	25,707			27,011
Commodity derivative liabilities	14,650			11
Other current liabilities	2,584			679
Total current liabilities	107,807			67,576
Long-term debt	724,009			837,654
Deferred revenue	7,049			11,417
Commodity derivative liabilities	1,209			—
Asset retirement obligations	19,458			20,301
Liability under tax receivable agreement	43,045			38,052
Other liabilities	792			330
Deferred tax liabilities	2,905			22,972
Total liabilities	906,274			998,302
Commitments and contingencies (Note 15)
Mezzanine equity
Series A preferred stock, $0.001 par value; 1,840,000 shares issued and outstanding at December 31, 2016 and no shares issued and outstanding at December 31, 2015	88,975			—
Stockholders’ equity
Class A common stock, $0.001 par value; 57,048,076 shares issued and 57,025,474 shares outstanding at December 31, 2016 and 30,573,509 shares issued and 30,550,907 shares outstanding at December 31, 2015	57			31
Class B common stock, $0.001 par value; 29,832,098 shares issued and outstanding at December 31, 2016 and 31,273,130 shares issued and outstanding at December 31, 2015	30			31
Treasury stock, at cost: 22,602 shares at December 31, 2016 and December 31, 2015	(358		)	(358		)
Additional paid-in-capital	447,137			363,723
Retained (deficit) / earnings	(8,652		)	36,569
Stockholders’ equity	438,214			399,996
Non-controlling interest	453,237			536,856
Total stockholders’ equity	891,451			936,852
Total liabilities and stockholders’ equity	$	1,886,700		$	1,935,154

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

Jones Energy, Inc.

Consolidated Statements of Operations

Years Ended December 31, 2016, 2015 and 2014

	Year Ended December 31,
(in thousands of dollars except per share data)	2016			2015			2014
Operating revenues
Oil and gas sales	$	124,877		$	194,555		$	378,401
Other revenues	2,970			2,844			2,196
Total operating revenues	127,847			197,399			380,597
Operating costs and expenses
Lease operating	32,640			41,027			37,760
Production and ad valorem taxes	7,768			12,130			22,556
Exploration	6,673			6,551			3,453
Depletion, depreciation and amortization	153,930			205,498			181,669
Accretion of ARO liability	1,263			1,087			770
General and administrative	29,640			33,388			25,763
Other operating	199			4,188			—
Total operating expenses	232,113			303,869			271,971
Operating income (loss)	(104,266		)	(106,470		)	108,626
Other income (expense)
Interest expense	(53,127		)	(64,458		)	(41,875		)
Gain on debt extinguishment	99,530			—			—
Net gain (loss) on commodity derivatives	(51,264		)	158,753			189,641
Other income (expense)	536			317			(4,554		)
Other income (expense), net	(4,325		)	94,612			143,212
Income (loss) before income tax	(108,591		)	(11,858		)	251,838
Income tax provision (benefit)
Current	3,981			113			53
Deferred	(27,767		)	(2,894		)	26,165
Total income tax provision (benefit)	(23,786		)	(2,781		)	26,218
Net income (loss)	(84,805		)	(9,077		)	225,620
Net income (loss) attributable to non-controlling interests	(42,253		)	(6,696		)	184,484
Net income (loss) attributable to controlling interests	$	(42,552	)	$	(2,381	)	$	41,136
Dividends and accretion on preferred stock	(2,669		)	—			—
Net income (loss) attributable to common shareholders	(45,221		)	(2,381		)	41,136
Earnings (loss) per share (1) :
Basic - Net income (loss) attributable to common shareholders	$	(1.04	)	$	(0.08	)	$	3.02
Diluted - Net income (loss) attributable to common shareholders	$	(1.04	)	$	(0.08	)	$	3.02
Weighted average Class A shares outstanding (1) :
Basic	43,506			29,161			13,622
Diluted	43,506			29,161			13,630

(1)All share and earnings per share information presented has been recast to retrospectively adjust for the effects of the 0.087423 per share Special Stock Dividend, as defined in Note 16, “Subsequent Events - Special Stock Dividend Declared”, distributed on March 31, 2017.

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

Jones Energy, Inc.

Statement of Changes in Stockholders’ Equity

Years Ended December 31, 2016, 2015 and 2014

	Common Stock									Treasury Stock				Additional		Retained						Total
	Class A				Class B					Class A				Paid-in-		(Deficit)/			Non-controlling			Stockholders’
(amounts in thousands)	Shares		Value		Shares		Value			Shares	Value			Capital		Earnings			Interest			Equity
Balance at December 31, 2013	12,500		13		36,836		37			—	—			173,169		(2,186		)	453,091			624,124
Treasury stock	(23	)	—		—		—			23	(358		)	—		—			—			(358		)
Exchange of Class B shares for Class A shares	117		—		(117	)	—			—	—			1,554		—			(1,630		)	(76		)
Stock-compensation expense	—		—		—		—			—	—			4,040		—			—			4,040
Vested restricted shares	28		—		—		—			—	—			—		—			—			—
Net income (loss)	—		—		—		—			—	—			—		41,136			184,484			225,620
Balance at December 31, 2014	12,622		13		36,719		37			23	(358		)	178,763		38,950			635,945			853,350
Sale of common stock	12,263		12		—		—			—	—			123,189		—			—			123,201
Exchange of Class B shares for Class A shares	5,446		6		(5,446	)	(6		)	—	—			54,209		—			(92,393		)	(38,184		)
Stock-compensation expense	67		—		—		—			—	—			7,562		—			—			7,562
Vested restricted shares	153		—		—		—			—	—			—		—			—			—
Net income (loss)	—		—		—		—			—	—			—		(2,381		)	(6,696		)	(9,077		)
Balance at December 31, 2015	30,551		$	31	31,273		$	31		23	$	(358	)	$	363,723	$	36,569		$	536,856		$	936,852
Stock-compensation expense	—		—		—		—			—	—			7,425		—			—			7,425
Vested restricted shares	385		—		—		—			—	—			—		—			—			—
Cash tax distribution	—		—		—		—			—	—			—		—			(17,319		)	(17,319		)
Sale of common stock	24,648		25		—		—			—	—			65,421		—			—			65,446
Exchange of Class B shares for Class A shares	1,441		1		(1,441	)	(1		)	—	—			10,568		—			(24,047		)	(13,479		)
Dividends and accretion on preferred stock	—		—		—		—			—	—			—		(2,669		)	—			(2,669		)
Net income (loss)	—		—		—		—			—	—			—		(42,552		)	(42,253		)	(84,805		)
Balance at December 31, 2016	57,025		$	57	29,832		$	30		23	$	(358	)	$	447,137	$	(8,652	)	$	453,237		$	891,451

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

Jones Energy, Inc.

Consolidated Statements of Cash Flows

Years Ended December 31, 2016, 2015 and 2014

	Year ended December 31,
(in thousands of dollars)	2016			2015			2014
Cash flows from operating activities
Net income (loss)	$	(84,805	)	$	(9,077	)	$	225,620
Adjustments to reconcile net income (loss) to net cash provided by operating activities
Depletion, depreciation, and amortization	153,930			205,498			181,669
Exploration (dry hole and lease abandonment)	6,261			5,250			2,952
Accretion of ARO liability	1,263			1,087			770
Amortization of debt issuance costs	4,060			6,043			6,878
Stock compensation expense	7,425			7,562			4,040
Deferred and other non-cash compensation expense	804			455			758
Amortization of deferred revenue	(2,384		)	(1,960		)	(1,154		)
(Gain) loss on commodity derivatives	51,264			(158,753		)	(189,641		)
(Gain) loss on sales of assets	(14		)	3			(297		)
(Gain) on debt extinguishment	(99,530		)	—			—
Deferred income tax provision	(27,767		)	(2,892		)	26,165
Other - net	418			(961		)	376
Changes in operating assets and liabilities
Accounts receivable	2,276			64,510			(2,453		)
Other assets	(675		)	(432		)	(669		)
Accrued interest expense	(4,727		)	7,050			7,823
Accounts payable and accrued liabilities	17,901			(54,534		)	2,482
Net cash provided by operations	25,700			68,849			265,319
Cash flows from investing activities
Additions to oil and gas properties	(264,462		)	(311,305		)	(474,619		)
Net adjustments to purchase price of properties acquired	—			—			15,709
Proceeds from sales of assets	1,645			41			448
Acquisition of other property, plant and equipment	(310		)	(1,101		)	(1,683		)
Current period settlements of matured derivative contracts	132,265			144,145			(3,654		)
Net cash (used in) investing	(130,862		)	(168,220		)	(463,799		)
Cash flows from financing activities
Proceeds from issuance of long-term debt	130,000			85,000			170,000
Repayment under long-term debt	(62,000		)	(335,000		)	(468,000		)
Proceeds from senior notes	—			236,475			500,000
Purchase of senior notes	(84,589		)	—			—
Payment of debt issuance costs	—			(1,556		)	(13,416		)
Payment of dividends on preferred stock	(1,615		)	—			—
Net distributions paid to JEH unitholders	(17,319		)	—			—
Proceeds from sale of common stock	65,446			122,779			—
Proceeds from sale of preferred stock	87,988			—			—
Purchases of treasury stock	—			—			(358		)
Net cash provided by financing	117,911			107,698			188,226
Net increase (decrease) in cash	12,749			8,327			(10,254		)
Cash
Beginning of period	21,893			13,566			23,820
End of period	$	34,642		$	21,893		$	13,566
Supplemental disclosure of cash flow information
Cash paid for interest	$	53,816		$	52,796		$	29,560
Cash paid for income taxes	—			(155		)	155
Change in accrued additions to oil and gas properties	9,325			(111,210		)	49,025
Asset retirement obligations incurred, including changes in estimate	(1,276		)	6,371			2,041

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

Jones Energy, Inc.

Notes to the 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, the Company 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 (collectively, the “Class B shareholders”). 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.

The Company’s certificate of incorporation authorizes two classes of common stock, Class A common stock and Class B common stock. The Class B common stock is held by the owners of JEH prior to the Company’s initial public offering (“IPO”) and can be exchanged (together with a corresponding number of common units representing membership interests in JEH (“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 holders to one vote on all matters to be voted on by the Company’s stockholders generally. As of December 31, 2016, the Company held 57,025,474 JEH Units and all of the preferred units representing membership interests in JEH, and the remaining 29,832,098 JEH Units are held by the Class B shareholders. The Class B shareholders have no voting rights with respect to their economic interest in JEH, resulting in the Company reporting this ownership interest as a non-controlling interest.

The Company’s certificate of incorporation also authorizes the Board of Directors of the Company to establish one or more series of preferred stock. Unless required by law or by any stock exchange on which our common stock is listed, the authorized shares of preferred stock will be available for issuance without further action. Rights and privileges associated with shares of preferred stock are subject to authorization by the Board of Directors of the Company and may differ from those of any and all other series at any time outstanding.

On August 25, 2016, the Company issued 1.84 million shares of its 8.0% Series A Perpetual Convertible preferred stock, par value $0.001 per share (the “Series A preferred stock”), pursuant to a registered public offering at $50 per share, for gross proceeds of approximately $92 million, before underwriting discounts and commissions of $3.68 million. See Note 12, “Stockholders’ and Mezzanine equity”.

Description of Business

The Company is engaged in the exploration, development, production and acquisition of oil and natural gas properties in the mid-continent United States, spanning areas of Texas and Oklahoma. The Company’s assets are located within the Anadarko and Arkoma basins, and are owned by JEH and its operating subsidiaries. The Company is headquartered in Austin, Texas.

2. Significant Accounting Policies

Basis of Presentation

The accompanying consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) and in accordance with the rules and regulations of the Securities and Exchange Commission. All significant intercompany transactions and balances have been eliminated in consolidation. The Company’s financial position as of December 31, 2016 and 2015 and the financial statements reported for each of the three years in the period ended December 31, 2016 include the Company and all of its subsidiaries

Certain prior period amounts have been reclassified to conform to the current presentation.

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 and unproved 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”).

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 it does business with, and believes the Company’s risk is not significant.

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 consists at December 31, 2016 and at December 31, 2015 of derivative positions not settled as of the balance sheet date. 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, 2016 and 2015, 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, including declines in commodity prices. As of December 31, 2016, 77% of Accounts receivable—Oil and gas sales were due from four purchasers and 48% of Accounts receivable-Joint interest owners were due from five working interest owners. As of December 31, 2015, 68% of Accounts receivable—Oil and gas sales are due from four purchasers and 80% of Accounts receivable—Joint interest owners are due from five working interest owners. As of December 31, 2014, 70% of Accounts receivable—Oil and gas sales were due from five purchasers and 67% of Accounts receivable—Joint interest owners were due from five 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, 2016, the largest purchasers of our production were Plains Marketing LP (“Plains Marketing”) and ETC Field Services LLC, which accounted for approximately 37% and 24% of consolidated oil and gas sales, respectively. During the year ended December 31, 2015, the largest purchasers of our production were Valero Energy Corp. (“Valero”), ETC Field Services LLC, Plains Marketing LP, and NGL Energy Partners LP, which accounted for approximately 18%, 17%, 16%, and 15% of consolidated oil and gas sales, respectively. During the year ended December 31, 2014, the largest purchasers of our production were Valero Energy Corp. (“Valero”), NGL Energy Partners LP, PVR Midstream LLC (“PVR Midstream”), Plains Marketing LP (“Plains Marketing”), and Monarch Natural Gas LLC which accounted for approximately 22%, 12%, 12%, 10% and 10% 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 can be an imbalance between the supply of and demand for drilling rigs, equipment, services, supplies and qualified personnel. During periods of oversupply, there can be financial pressure on suppliers. If the financial pressure leads to work interruptions or stoppages, the Company could be materially and adversely affected. Management believes that there are adequate alternative providers of drilling and completion services although 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.

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.

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.

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 the life of 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.

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.

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 and development activity by other companies on adjacent blocks.

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 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.

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, 2016, 2015 and 2014, the Company elected not to designate any of its commodity price risk management activities as cash flow or fair value hedges. The changes in the fair values of outstanding financial instruments are recognized as gains or losses in the period of change.

Although the Company does not designate its commodity derivative instruments as cash-flow hedges, management uses those instruments to reduce the Company’s exposure to fluctuations in commodity prices related to its natural gas and oil production. Net gains and losses, at fair value, are included on the Consolidated Balance Sheet as current or noncurrent assets or liabilities based on the anticipated timing of 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 7, “Fair Value Measurement,” for disclosure about the fair values of commodity derivative instruments.

Asset Retirement Obligations

The Company’s asset retirement obligations (“ARO”) 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.

Revenue Recognition

Revenues from the sale of crude oil, natural gas, and natural gas liquids are valued at the estimated sales price and 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. Any such imbalances were not significant as of December 31, 2016, 2015, and 2014.

Income Taxes

The Company records a federal and state income tax liability associated with its status as a corporation. The Company recognizes a tax liability on its share of pre-tax book income, exclusive of the non-controlling interest.

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 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.

Comprehensive Income

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

Recent Accounting Pronouncements

Adopted in the current year:

In August 2014, the Financial Accounting Standards Board (the “FASB”) issued Accounting Standards Update (“ASU”) 2014-15, “Presentation of Financial Statements—Going Concern (Subtopic 205-40): Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern.” This ASU requires management to evaluate whether there are conditions or events that raise substantial doubt about an entity’s ability to continue as a “going concern” and to provide disclosures when certain criteria are met. Substantial doubt exists when relevant conditions and events, considered in the aggregate, indicate that it is probable that the entity will be unable to meet its obligations as they become due within one year after the date that the financial statements are issued (or available to be issued). The amendments are effective for interim and annual reporting periods beginning after December 15, 2016. Early adoption is permitted and the Company chose to early adopt ASU 2014-15 beginning October 1, 2016. Adoption did not have a material impact on the financial position, cash flows or results of operations.

In January 2015, the FASB issued ASU 2015-01, “Income Statement—Extraordinary and Unusual Items.” This ASU removes the concept of extraordinary items from GAAP. Under existing guidance, an entity is required to separately disclose extraordinary items, net of tax, in the income statement after income from continuing operations if an event or transaction is of an unusual nature and occurs infrequently. This separate, net of tax presentation will no longer be allowed. The amendments are effective for interim and annual reporting periods beginning after December 15, 2015. Therefore, the Company adopted ASU 2015-01 beginning January 1, 2016. Adoption did not have a material impact on the financial position, cash flows or results of operations.

In April 2015, the FASB issued ASU 2015-03, “Interest—Imputation of Interest” (Subtopic 835-30): “Simplifying the Presentation of Debt Issuance Costs.” Entities that have historically presented debt issuance costs as an asset, related to a recognized debt liability, will be required to present those costs as a direct deduction from the carrying amount of that debt liability. The ASU does not change the recognition, measurement, or subsequent measurement guidance for debt issuance costs. Adoption of this ASU will be applied retrospectively. In August 2015, the FASB issued ASU 2015-15, “Interest—Imputation of Interest” (Subtopic 835-30), which addresses the presentation or subsequent measurement of debt issuance costs related to line-of-credit arrangements, given the absence of authoritative guidance within ASU 2015-03 for debt issuance costs related to line-of-credit arrangements. The amendments are effective for interim and annual reporting periods beginning after December 15, 2015. Therefore, the Company adopted ASU 2015-03 beginning January 1, 2016. Changes to the balance sheet have been applied on a retrospective basis. This resulted in the reclassification of debt issuance costs of $10.3 million associated with our Senior Unsecured Notes from Other assets to Long-term debt in the Consolidated Balance Sheet for the period ended December 31, 2015. Adoption did not have a material impact on the financial position, cash flows or results of operations.

In September 2015, the FASB issued ASU 2015-16, “Business Combinations” (Topic 805): “Simplifying the Measurement-Period Adjustments.” The new standard eliminates the requirement that an acquirer in a business combination account for measurement-period adjustments retrospectively. Instead, an acquirer will recognize a measurement-period adjustment during the period in which it determines the amount of the adjustment. The standard is effective for interim and annual reporting periods beginning after December 15, 2015. Therefore, the Company adopted ASU 2015-16 beginning January 1, 2016. Adoption did not have a material impact on the financial position, cash flows or results of operations.

In August 2016, the FASB issued ASU 2016-15, “Statement of Cash Flows” (Topic 230). This amendment is intended to reduce diversity in practice in how certain transactions are classified in the statement of cash flows, specifically in regard to (1) debt prepayment or debt extinguishment costs, (2) settlement of zero-coupon debt instruments, (3) contingent consideration payments made after a business combination, (4) proceeds from the settlement of insurance claims, (5) proceeds from the settlement of corporate-owned life insurance policies, including bank-owned life insurance policies, (6) distributions received from equity method investments, (7) beneficial interests in securitization transactions, and (8) separately identifiable cash flows and application of the predominance principle. The amendments are effective for interim and annual reporting periods beginning after December 15, 2017. Early adoption is permitted and the Company chose to early adopt ASU 2016-15 beginning October 1, 2016. Adoption did not have a material impact on the financial position, cash flows or results of operations.

In November 2016, the FASB issued ASU 2016-18, “Statement of Cash Flows: Restricted Cash” (Topic 230). The new standard requires that the statement of cash flows explain the change during the period in the total of cash, cash equivalents, and amounts generally described as restricted cash or restricted cash equivalents. This standard also requires entities to reconcile such total to amounts on the balance sheet and disclose the nature of the restrictions. The standard is effective for interim and annual reporting periods beginning after December 15, 2017. Early adoption is permitted and the Company chose to early adopt ASU 2016-18 beginning October 1, 2016. Adoption did not have a material impact on the financial position, cash flows or results of operations.

In January 2017, the FASB issued ASU 2017-01, “Business Combinations” (Topic 805). This amendment is intended to clarify the definition of a business. The standard is effective for interim and annual reporting periods beginning after December 15, 2017. Early adoption is permitted and the Company chose to early adopt ASU 2017-01 beginning October 1, 2016. Adoption did not have a material impact on the financial position, cash flows or results of operations.

To be adopted in a future period:

In May 2014, the FASB issued ASU 2014-09, “Revenue from Contracts with Customers,” which creates a new topic in the Accounting Standards Codification (“ASC”), topic 606, “Revenue from Contracts with Customers.” This ASU sets forth a five-step model for determining when and how revenue is recognized. Under the model, an entity will be required to recognize revenue to depict the transfer of goods or services to a customer at an amount reflecting the consideration it expects to receive in exchange for those goods or services. Additional disclosures will be required to describe the nature, amount, timing and uncertainty of revenue and cash flows arising from customer contracts. In August 2015, the FASB issued ASU 2015-14, which deferred the effective date of ASU 2014-09 by one year. The amendments are now effective for interim and annual reporting periods beginning after December 15, 2017 and may be applied on either a full or modified retrospective basis. Early adoption is permitted. The Company is in the early stages of evaluating the effect that the adoption of Update 2014-09 and Update 2015-14 will have on our financial statements. At this time, we are performing a review on a sample of revenue contracts to determine the impact of adoption. The Company will continue to further evaluate the effect that the adoption of Update 2014-09 and Update 2015-14 will have on our financial statements. We anticipate adoption of Update 2014-09 and Update 2015-14 effective as of January 1, 2018.

In February 2016, the FASB issued ASU 2016-02, “Leases” (Topic 842). This amendment requires, among other things, that lessees recognize the following for all leases (with the exception of short-term leases) at the commencement date: (1) a lease liability, which is a lessee’s obligation to make lease payments arising from a lease, measured on a discounted basis; and (2) a right-of-use asset, which is an asset that represents the lessee’s right to use, or control the use of, a specified asset for the lease term. Lessees and lessors must apply a modified retrospective transition approach for leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements. The amendments are effective for interim and annual reporting periods beginning after December 15, 2018. The Company is currently evaluating the impacts of the amendments to our financial statements and accounting practices for leases. We anticipate adoption of ASU 2016-02 effective as of January 1, 2018.

In March 2016, the FASB issued ASU 2016-09, “Compensation—Stock Compensation” (Topic 718). This amendment is intended to simplify the accounting for share-based payment awards to employees, specifically in regard to (1) the income tax consequences, (2) classification of awards as either equity or liabilities, and (3) classification on the statement of cash flows. The amendments are effective for interim and annual reporting periods beginning after December 15, 2016. Therefore, the Company has adopted ASU 2016-09 effective as of January 1, 2017. Adoption did not have a material impact on the financial position, cash flows or results of operations.

3. Acquisitions

During the year ended December 31, 2016, the Company entered into several purchase and sale agreements (as described below). No business combinations occurred during the twelve months ended December 31, 2015 and 2014.

Merge Acquisition

On August 18, 2016, JEH entered into a definitive purchase and sale agreement with SCOOP Energy Company, LLC, an Oklahoma limited liability company, to acquire oil and gas properties located in the Merge area of the STACK/SCOOP (the “Merge”) play in Central Oklahoma (the “Merge Acquisition”). The oil and gas properties acquired in the Merge Acquisition principally consist of approximately 18,000 undeveloped net acres in Canadian, Grady and McClain Counties, Oklahoma. The Company closed the Merge Acquisition on September 22, 2016, for cash consideration of $136.8 million. This transaction has been accounted for as an asset acquisition. The Company used proceeds from our equity offerings to fund a portion of the purchase. See Note 12, “Stockholders’ and Mezzanine equity”.

Anadarko Acquisition

On August 3, 2016, JEH entered into a definitive agreement to acquire producing and undeveloped oil and gas assets in the Western Anadarko basin (the “Anadarko Acquisition”) for $27.1 million, subject to customary closing adjustments. Upon final closing, which occurred October 24, 2016, the transaction closed for $25.9 million. This transaction was accounted for as a business combination. The Company allocated $32.3 million to “Oil and gas properties,” with $3.0 million allocated to “Unproved” properties, $17.0 million allocated to “Proved” properties, and $12.3 million allocated to “Wells and equipment and related facilities”, based on the respective fair values of the assets acquired. Additionally, the Company allocated $6.4 million to our ARO liability associated with those proved properties. As of December 31, 2016, the measurement-period remains open. The Anadarko Acquisition did not result in a significant impact to revenues or net income and as such, pro forma financial information was not included. The Company funded the Anadarko Acquisition with cash on hand.

The assets acquired in the Anadarko Acquisition included interests in 174 wells, 59% of which were operated by the company, and approximately 25,000 net acres in Lipscomb and Ochiltree Counties in the Texas Panhandle. The Company closed the Anadarko Acquisition on August 25, 2016, at which time, the acquired acreage was producing approximately 900 barrels of oil equivalent per day.

4. Properties, Plant and Equipment

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, 2016 and 2015:

	December 31,			December 31,
(in thousands of dollars)	2016			2015
Mineral interests in properties
Unproved	$	213,153		$	75,308
Proved	1,054,683			1,031,669
Wells and equipment and related facilities	1,395,291			1,289,323
	2,663,127			2,396,300
Less: Accumulated depletion and impairment	(919,539		)	(760,534		)
Net oil and gas properties	$	1,743,588		$	1,635,766

One exploratory well was drilled during the year ended December 31, 2016, for which associated costs of $1.3 million were capitalized. There were no exploratory wells drilled during the year ended December 31, 2015 and, as such, no associated costs were capitalized. No exploratory wells resulted in exploration expense during either year.

The Company did not capitalize any interest during the years ended December 31, 2016 and 2015 as no projects lasted more than six months. Costs incurred to maintain wells and related equipment are charged to expense as incurred.

Depletion of oil and gas properties amounted to $152.7 million, $204.2 million, and $180.6 million for the years ended December 31, 2016, 2015, and 2014, respectively.

Due to recent fluctuations in forward commodity prices, the Company continued to monitor its proved and unproved properties for impairment. No impairments of proved or unproved properties were recorded in 2016, 2015, or 2014.

Other Property, Plant and Equipment

Other property, plant and equipment consisted of the following at December 31, 2016 and 2015:

	December 31,			December 31,
(in thousands of dollars)	2016			2015
Leasehold improvements	$	1,213		$	1,260
Furniture, fixtures, computers and software	4,170			4,090
Vehicles	1,677			1,537
Aircraft	910			910
Other	284			247
	8,254			8,044
Less: Accumulated depreciation and amortization	(5,258		)	(4,171		)
Net other property, plant and equipment	$	2,996		$	3,873

Depreciation and amortization of other property, plant and equipment amounted to $1.2 million, $1.3 million, and $1.1 million during the years ended December 31, 2016, 2015 and 2014, respectively.

5. Long-Term Debt

Long-term debt consisted of the following at December 31, 2016 and 2015:

(in thousands of dollars)	December 31, 2016			December 31, 2015
Revolver	$	178,000		$	110,000
2022 Notes	409,148			500,000
2023 Notes	150,000			250,000
Total principal amount	737,148			860,000
Less: unamortized discount	(6,240		)	(12,088		)
Less: debt issuance costs, net	(6,899		)	(10,258		)
Total carrying amount	$	724,009		$	837,654

Senior Unsecured Notes

On April 1, 2014, JEH and Jones Energy Finance Corp., JEH’s wholly owned subsidiary formed for the sole purpose of co-issuing certain of JEH’s debt (collectively, the “Issuers”), sold $500.0 million in aggregate principal amount of the Issuers’ 6.75% senior notes due 2022 (the “2022 Notes”). The Company used the net proceeds from the issuance of the 2022 Notes to repay all outstanding borrowings under the Term Loan (as defined below) ($160.0 million), a portion of the outstanding borrowings under the Revolver (as defined below) ($308.0 million) and for working capital and general corporate purposes. The Company subsequently terminated the Term Loan in accordance with its terms. The 2022 Notes bear interest at a rate of 6.75% per year, payable semi-annually on April 1 and October 1 of each year beginning October 1, 2014. The 2022 Notes were registered in March 2015.

On February 23, 2015, the Issuers sold $250.0 million in aggregate principal amount of 9.25% senior notes due 2023 (the “2023 Notes”) in a private placement to affiliates of GSO Capital Partners LP and Magnetar Capital LLC. The 2023 Notes were issued at a discounted price equal to 94.59% of the principal amount. The Company used the $236.5 million net proceeds from the issuance of the 2023 Notes to repay outstanding borrowings under the Revolver and for working capital and general corporate purposes. The 2023 Notes bear interest at a rate of 9.25% per year, payable semi-annually on March 15 and September 15 of each year beginning September 15, 2015. The 2023 Notes were registered in February 2016.

During the year ended December 31, 2016, through several open market and privately negotiated purchases, the Company purchased an aggregate principal amount of $190.9 million of its senior unsecured notes. As of December 31,

2016, the Company had purchased $90.9 million principal amount of its 2022 Notes for $38.1 million, and $100.0 million principal amount of its 2023 Notes for $46.5 million, in each case excluding accrued interest and including any associated fees. The Company used cash on hand and borrowings from its Revolver to fund the note purchases. In conjunction with the extinguishment of this debt, JEH recognized cancellation of debt income of $99.5 million during the year ended December 31, 2016, on a pre-tax basis. This income is recorded in Gain on debt extinguishment on the Company’s Consolidated Statement of Operations. Of the Company’s total repurchases, $20.3 million principal amount of its 2022 Notes were not cancelled and are available for future reissuance, subject to applicable securities laws.

The 2022 Notes and 2023 Notes are guaranteed on a senior unsecured basis by the Company and by all of its significant subsidiaries. The 2022 Notes and 2023 Notes will be senior in right of payment to any future subordinated indebtedness of the Issuers.

The Company may redeem the 2022 Notes at any time on or after April 1, 2017 and the 2023 Notes at any time on or after March 15, 2018 at a declining redemption price set forth in the respective indentures, plus accrued and unpaid interest.

The indentures governing the 2022 Notes and 2023 Notes are substantially identical and contain covenants that, among other things, limit the ability of the Company to incur additional indebtedness or issue certain preferred stock, pay dividends on capital stock, transfer or sell assets, make investments, create certain liens, enter into agreements that restrict dividends or other payments from the Company’s restricted subsidiaries to the Company, consolidate, merge or transfer all of the Company’s assets, engage in transactions with affiliates or create unrestricted subsidiaries. If at any time when the 2022 Notes or 2023 Notes are rated investment grade and no default or event of default (as defined in the indenture) has occurred and is continuing, many of the foregoing covenants pertaining to the 2022 Notes or 2023 Notes, as applicable, will be suspended. If the ratings on the 2022 Notes or 2023 Notes, as applicable, were to decline subsequently to below investment grade, the suspended covenants would be reinstated.

As of December 31, 2016, the Company was in compliance with the indentures governing the 2022 Notes and 2023 Notes.

Other 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”). On April 1, 2014, the Term Loan was repaid in full and terminated in connection with the issuance of the 2022 Notes. On November 6, 2014, the Company amended the Revolver to, among other things, extend the maturity date of the Revolver to November 6, 2019. The Company’s oil and gas properties are pledged as collateral to secure its obligations under the Revolver. The borrowing base on the Revolver was subsequently adjusted to $562.5 million in accordance with its terms as a result of the issuance of the 2023 Notes in February 2015 and was reaffirmed at this level effective April 1, 2015. Effective October 8, 2015, the borrowing base was reduced to $510.0 million during the semi-annual borrowing base re-determination.

On August 1, 2016, the Company entered into an amendment to the Revolver to, among other things (i) require that the Company’s deposit accounts and securities accounts (subject to certain exclusions) become subject to control agreements, (ii) restrict the Company from borrowing or receiving Letters of Credit under the Revolver if the Company has, or, after giving effect to such borrowing or issuance of Letter of Credit, will have, a Consolidated Cash Balance (as defined in the Revolver) in excess of $30.0 million (in each case giving effect to the anticipated use of proceeds thereof) and (iii) set the borrowing base under the Revolver at $425.0 million. The borrowing base was reaffirmed at this level during the semi-annual borrowing base re-determination effective October 24, 2016.

The terms of the Revolver require the Company to make periodic payments of interest on the loans outstanding thereunder, with all outstanding principal and interest under the Revolver due on the maturity date. The Revolver is subject to a borrowing base, which limits the amount of borrowings which may be drawn thereunder. The borrowing base will be re-determined by the lenders at least semi-annually on or about April 1 and October 1 of each year, with such re-determination based primarily on reserve reports using lender commodity price expectations at such time. Any reduction in the borrowing base will reduce our liquidity, and, if the reduction results in the outstanding amount under our revolving credit facility exceeding the borrowing base, we will be required to repay the deficiency within a short period of time.

Interest on the Revolver is calculated, at the Company’s option, at either (a) the London Interbank Offered (“LIBO”) rate for the applicable interest period plus a margin of 1.50% to 2.50% based on the level of borrowing base utilization at such time or (b) the greatest of the federal funds rate plus 0.50%, the one month adjusted LIBO rate plus 1.00%, or the prime rate announced by Wells Fargo Bank, N.A. in effect on such day, in each case plus a margin of 0.50% to 1.50% based on the level of borrowing base utilization at such time. For the year ended December 31, 2016, the average interest rate under the Revolver was 2.40% on an average outstanding balance of $172.3 million. For the year ended December 31, 2015, the average interest rate under the Revolver was 2.39% on an average outstanding balance of $144.9 million.

Total interest and commitment fees under the Revolver were $5.3 million, $5.1 million, and $9.5 million for the years ended December 31, 2016, 2015 and 2014, respectively. Total interest and commitment fees under the Term Loan were $3.6 million for the year ended December 31, 2014.

Jones Energy, Inc. and its consolidated subsidiaries are subject to certain covenants under the Revolver, including the requirement to maintain the following financial ratios:

·a total leverage ratio, consisting of consolidated debt to EBITDAX, of not greater than 4.0x to 1.0x as of the last day of any fiscal quarter; and

·a current ratio, consisting of consolidated current assets, including the unused amounts of the total commitments, to consolidated current liabilities, of not less than 1.0x to 1.0x as of the last day of any fiscal quarter.

As of December 31, 2016, our total leverage ratio is approximately 3.9x and our current ratio is approximately 3.5x, as calculated based on the requirements in our covenants. We are in compliance with all terms of our Revolver at December 31, 2016, and we expect to maintain compliance throughout 2017. However, factors including those outside of our control, such as commodity price declines, may prevent us from maintaining compliance with these covenants, at future measurement dates in 2017 and beyond. In the event it were to become necessary, we believe we have the ability to take actions that would prevent us from failing to comply with our covenants, such as hedge restructuring or seeking a waiver of such covenants. If an event of default exists under the Revolver, the lenders will be able to accelerate the obligations outstanding under the Revolver and exercise other rights and remedies. Our Revolver contains customary events of default, including the occurrence of a change of control, as defined in the Revolver.

6. Derivative Instruments and Hedging Activities

The Company uses derivative instruments to mitigate volatility in commodity prices. While the use of these instruments limits the downside risk of adverse price changes, their use may also limit future revenues from favorable price changes. Depending on changes in oil and gas futures markets and management’s view of underlying supply and demand trends, we may increase or decrease our hedging positions.

The following tables summarize our hedging positions as of December 31, 2016 and 2015:

Hedging Positions

	December 31, 2016
						Weighted		Final
		Low		High		Average		Expiration
Oil swaps	Exercise price	$	43.65	$	86.85	$	64.49	June 2019
	Offset exercise price	$	42.00	$	49.00	$	47.14
	Net barrels per month	—		148,000		87,233
Natural gas swaps	Exercise price	$	2.78	$	4.67	$	3.65	June 2019
	Offset exercise price	$	2.75	$	3.02	$	2.83
	Net mmbtu per month	—		1,470,000		1,024,000
Natural gas liquids swaps	Exercise price	$	18.06	$	72.52	$	24.60	December 2017
	Barrels per month	110,000		121,000		114,833
Oil collars	Puts (floors)	$	45.00	$	50.00	$	48.52	December 2019
	Calls (ceilings)	$	56.60	$	61.00	$	59.64
	Net barrels per month	65,000		73,000		67,500
Natural gas collars	Puts (floors)	$	2.55	$	2.55	$	2.55	December 2019
	Calls (ceilings)	$	3.08	$	3.41	$	3.19
	Net barrels per month	950,000		1,050,000		990,833

	December 31, 2015
								Weighted			Final
		Low			High			Average			Expiration
Oil swaps	Exercise price	$	54.53		$	100.87		$	79.16		June 2019
	Barrels per month	54,000			194,000			97,119
Natural gas swaps	Exercise price	$	3.22		$	6.45		$	4.25		June 2019
	mmbtu per month	700,000			1,640,000			1,042,857
Natural gas basis swaps	Contract differential	$	(0.39	)	$	(0.11	)	$	(0.18	)	December 2016
	mmbtu per month	1,190,000			1,730,000			1,360,833
Natural gas liquids swaps	Exercise price	$	8.90		$	95.24		$	32.62		December 2017
	Barrels per month	2,000			112,000			51,792

The Company recognized net losses on derivative instruments of $51.3 million for the year ended December 31, 2016. The Company recognized net gains on derivative instruments of $158.8 million and $189.6 million for the years ended December 31, 2015 and 2014, respectively.

The Company routinely enters into oil and natural gas swap contracts as seller, thus resulting in a fixed price. In early 2016, the Company realized certain mark-to-market gains associated with oil and natural gas hedges the Company had in place for years 2018 and 2019. The gains were effectively realized by purchasing, as opposed to selling, oil and natural gas swap contracts for the equal volume that was associated with the initial hedge transaction. Therefore, as prices fluctuate, the loss (or gain) on any single contract in 2018 and 2019 will be offset by an equal gain (or loss). This essentially leaves the underlying production open to fluctuations in market prices. Based on current contract terms, the gains will be recognized as the hedge contracts mature in 2018 and 2019. Information related to these purchased oil and natural gas swap contracts is presented in the table above as the “offset exercise price”, and the volumes in the table above are presented “net” of such purchased oil and natural gas swap contracts.

Offsetting Assets and Liabilities

As of December 31, 2016, the counterparties to our commodity derivative contracts consisted of six financial institutions. All of our counterparties or their affiliates are also lenders under the Revolver. 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.

The following table presents information about our commodity derivative contracts that are netted on our Consolidated Balance Sheet as of December 31, 2016 and 2015:

							Net Amounts
				Gross			of Assets /			Gross Amounts
	Gross Amounts			Amounts			Liabilities			Not
	of Recognized			Offset in the			Presented in			Offset in the
	Assets /			Balance			the Balance			Balance
(in thousands of dollars)	Liabilities			Sheet			Sheet			Sheet		Net Amount
December 31, 2016
Commodity derivative contracts
Assets	$	79,649		$	(20,805	)	$	58,844		$	—	$	58,844
Liabilities	(36,664		)	20,805			(15,859		)	—		(15,859		)
December 31, 2015
Commodity derivative contracts
Assets	$	218,036		$	(527	)	$	217,509		$	—	$	217,509
Liabilities	(538		)	527			(11		)	—		(11		)

7. 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 high 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.
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, 2016 and 2015, by consolidated balance sheet caption and by valuation hierarchy, as described above are as follows:

	December 31, 2016
(in thousands of dollars)	Fair Value Measurements Using
Commodity Price Hedges	(Level 1)		(Level 2)		(Level 3)			Total
Current assets	$	—	$	24,100	$	—		$	24,100
Long-term assets (1)	—		36,384		(1,640		)	34,744
Current liabilities	—		13,636		1,014			14,650
Long-term liabilities	—		892		317			1,209

	December 31, 2015
(in thousands of dollars)	Fair Value Measurements Using
Commodity Price Hedges	(Level 1)		(Level 2)		(Level 3)		Total
Current assets	$	—	$	122,779	$	1,428	$	124,207
Long-term assets	—		93,302		—		93,302
Current liabilities	—		11		—		11
Long-term liabilities	—		—		—		—

(1)Level 3 long-term assets are negative as a result of the netting of our commodity derivative reflected on our Consolidated Balance Sheet as of December 31, 2016. Our agreements include set-off provisions, as noted in Note 6, “Derivative Instruments and Hedging Activities - Offsetting Assets and Liabilities”.

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, 2016.

	Quantitative Information About Level 3 Fair Value Measurements
	Fair Value				Unobservable
Commodity Price Hedges	(000’s)			Valuation Technique	Input	Range
Natural gas liquid swaps	$	(1,014	)	Use a discounted cash flow approach using inputs including forward price statements from counterparties	Natural gas liquid futures	$23.94 per barrel
Crude oil collars	$	(1,166	)	Use a discounted option model approach using inputs including interpolated volatilities for certain settlement months where market volatility quotes were unavailable for the option strike price	Market volatility quotes at the option strike for certain settlement months in 2019	$45.00 - $61.00 per barrel
Natural gas collars	$	(791	)	Use a discounted option model approach using inputs including interpolated volatilities for certain settlement months where market volatility quotes were unavailable for the option strike price	Market volatility quotes at the option strike for certain settlement months in 2019	$2.55 - $3.41 per barrel

Significant increases/decreases in natural gas liquid prices 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, 2016 and 2015. 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. Transfers from Level 3 to Level 2 represent the Company’s natural gas basis swaps for which observable forward curve pricing information has become readily available.

A summary of the Company’s commodity derivative contract activity, by year, is as follows:

(in thousands of dollars)
Balance at December 31, 2014, net	$	2,780
Purchases	648
Settlements	(960		)
Transfers into Level 3	—
Transfers to Level 2	(1,367		)
Changes in fair value	327
Balance at December 31, 2015, net	$	1,428
Purchases	(5,208		)
Settlements	(171		)
Transfers to Level 2	2,363
Transfers to Level 3	—
Changes in fair value	(1,383		)
Balance at December 31, 2016, net	$	(2,971	)

Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis

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

	December 31, 2016				December 31, 2015
	Principal				Principal
(in thousands of dollars)	Amount		Fair Value		Amount		Fair Value
Debt:
Revolver	$	178,000	$	178,000	$	110,000	$	110,000
2022 Notes	409,148		393,150		500,000		260,000
2023 Notes	150,000		153,375		250,000		153,283

The Revolver (as defined in Note 5) is categorized as Level 3 in the valuation hierarchy as the debt is not publicly traded and no observable market exists to determine the fair value; however, the carrying value of the Revolver approximates fair value, as it is subject to short-term floating interest rates that approximate the rates available to the Company for those periods.

The fair value of the 2022 Notes (as defined in Note 5) is based on pricing that is readily available in the public market. Accordingly, the 2022 Notes are classified as Level 1 in the valuation hierarchy as the pricing is based on quoted market prices for the debt securities and is actively traded.

The fair value of the 2023 Notes (as defined in Note 5) is based on indicative pricing that is available in the public market. Accordingly, the 2023 Notes are classified as Level 2 in the valuation hierarchy as the pricing is based on quoted market prices for the debt securities but is not actively traded.

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.

8. Asset Retirement Obligations

A summary of the Company’s ARO for the years ended December 31, 2016 and 2015 is as follows:

(in thousands of dollars)	2016			2015
ARO liability at beginning of year	$	20,980		$	13,610
Liabilities incurred (1)	6,947			6,349
Accretion of ARO liability	1,263			1,087
Liabilities settled due to sale of related properties	(446		)	(19		)
Liabilities settled due to plugging and abandonment	(463		)	(69		)
Change in estimate (2)	(8,223		)	22
ARO liability at end of year	20,058			20,980
Less: Current portion of ARO at end of year	(600		)	(679		)
Total long-term ARO at end of year	$	19,458		$	20,301

(1)  The 2016 amount includes $6.4 million related to wells acquired in the Anadarko Acquisition. See Note 3,   “Acquisitions”.

(2)The 2016 amount reflects a reduction in the estimated cost per well, consistent with the decline in actual costs experienced by the Company.

9. Stock-based Compensation

Management Unit Awards

Effective January 1, 2010, JEH implemented a management incentive plan that provided indirect awards of membership interests in JEH to members of senior management (“Management Units”). These awards had various vesting schedules, and a portion of the Management Units vested in a lump sum at the IPO date. In connection with the IPO, both the vested and unvested Management Units were converted into the right to receive JEH Units and shares of Class B common stock. The JEH Units (together with a corresponding number of shares of Class B common stock) will become exchangeable under this plan into a like number of shares of Class A common stock upon vesting or forfeiture. No new Management Units have been awarded since the IPO and no new JEH Units or shares of Class B common stock are created upon a vesting event. Grants listed below reflect the transfer of JEH Units that occurred upon forfeiture.

The following table summarizes information related to the vesting of Management Units as of December 31, 2016:

			Weighted Average
			Grant Date Fair Value
	JEH Units		per Share
Unvested at December 31, 2015	189,355		$	15.00
Granted	40,630		15.00
Forfeited	(40,630	)	15.00
Vested	(98,593	)	15.00
Unvested at December 31, 2016	90,762		$	15.00

Stock compensation expense associated with the Management Units for the years ended December 31, 2016, 2015 and 2014 was $1.2 million, $1.3 million, and $1.6 million, respectively, and is included in general and administrative expenses on the Company’s Consolidated Statement of Operations. The weighted average grant date fair value of management units was $15.00 per share for the years ended December 31, 2016 and 2015. Unrecognized expense as of December 31, 2016 for all outstanding management units was $0.9 million and will be recognized over a weighted-average remaining period of 1.3 years.

2013 Omnibus Incentive Plan

Under the Amended and Restated Jones Energy, Inc. 2013 Omnibus Incentive Plan (the “LTIP”), established in conjunction with the Company’s IPO and amended on May 4, 2016 following approval by the Company’s stockholders, the Company has reserved a total of 7,992,559 shares of Class A common stock for non-employee director, consultant, and employee stock-based compensation awards.

The Company granted (i) performance share unit and restricted stock unit awards to certain officers and employees and (ii) restricted shares of Class A common stock to the Company’s non-employee directors under the LTIP during 2014, 2015 and 2016. During 2016, the Company also granted performance unit awards to certain members of the senior management team under the LTIP.

All share and per share information presented for awards made under the LTIP has been recast to retrospectively adjust for the effects of the 0.087423 per share Special Stock Dividend, as defined in Note 16, “Subsequent Events - Special Stock Dividend Declared”, distributed on March 31, 2017.

Restricted Stock Unit Awards

The Company has outstanding restricted stock unit awards granted to certain officers and employees of the Company under the LTIP. The fair value of the restricted stock unit awards is based on the value of the Company’s Class A common stock on the date of grant and is expensed on a straight-line basis over the applicable vesting period, which is typically three years.

The following table summarizes information related to the total number of units awarded to officers and employees as of December 31, 2016:

	Restricted		Weighted Average
	Stock Unit		Grant Date Fair Value
	Awards		per Share
Unvested at December 31, 2015	823,478		$	10.71
Granted	1,024,786		3.67
Forfeited	(222,364	)	8.91
Vested	(266,758	)	11.20
Unvested at December 31, 2016	1,359,142		$	5.60

Stock compensation expense associated with the employee restricted stock unit awards for the years ended December 31, 2016, 2015, and 2014 was $3.0 million, $3.1 million, and $1.1 million, respectively, and is included in general and administrative expenses on the Company’s Consolidated Statement of Operations. The weighted average grant date fair value of restricted stock units was $3.67 per share, $8.81 per share, and $15.92 per share for the years ended December 31, 2016, 2015, and 2014, respectively. Unrecognized expense as of December 31, 2016 for all outstanding restricted stock unit awards was $4.4 million and will be recognized over a weighted-average remaining period of 1.8 years.

Performance Share Unit Awards

The Company has outstanding performance share unit awards granted to certain members of the senior management team of the Company under the LTIP. Prior to the second quarter of 2016, the performance share unit awards were described in the Company’s filings as performance unit awards. During the second quarter of 2016, the Company created a new class of equity award, described below as a performance unit award, that is settled in cash rather than shares of the Company’s Class A common stock. As a result, references to performance unit awards in the Company’s filings prior to the second quarter of 2016 refer to this description of performance share unit awards.

Upon the completion of the applicable three-year performance period, each recipient may vest in a number of performance share units. The percent of awarded performance share units in which each recipient vests at such time, if any, will range from 0% to 200% based on the Company’s total shareholder return relative to an industry peer group over the applicable three-year performance period. Each vested performance share unit is exchangeable for one share of the Company’s Class A common stock. The grant date fair value of the performance share units was determined using a Monte Carlo simulation model, which results in an estimated percentage of performance share units earned. The fair value of the performance share units is expensed on a straight-line basis over the applicable three-year performance period.

The following table summarizes information related to the total number of performance share units awarded to the senior management team as of December 31, 2016:

	Performance		Weighted Average
	Share Unit		Grant Date Fair Value
	Awards		per Share
Unvested at December 31, 2015	586,331		$	13.08
Granted	599,447		4.37
Forfeited	(60,064	)	12.20
Vested	(183,641	)	19.91
Unvested at December 31, 2016	942,073		$	6.25

At the time the performance share units vest, the results of the the Company’s total share return relative to the industry peer group must be certified by the compensation committee of the board of directors before the corresponding shares of Class A common stock are issued. As of December 31, 2016 the 183,641 performance share units that vested during 2016 were awaiting certification by the compensation committee. The Class A shares corresponding to these uncertified awards are not included in the Company’s total outstanding Class A shares reported within stockholder’s equity on the Company’s Consolidated Balance Sheets.

Stock compensation expense associated with the performance share unit awards for the years ended December 31, 2016, 2015, and 2014 was $2.7 million, $2.6 million, and $0.9 million, respectively, and is included in general and administrative expenses on the Company’s Consolidated Statement of Operations. The weighted average grant date fair value of performance share unit awards was $4.37 per share, $9.44 per share, and $19.91 per share for the years ended December 31, 2016, 2015, and 2014, respectively. Unrecognized expense as of December 31, 2016 for all outstanding performance share unit awards was $2.7 million and will be recognized over a weighted-average remaining period of 1.6 years.

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

The following assumptions were used for the Monte Carlo simulation model to determine the grant date fair value and associated stock-based compensation expense during the periods presented:

	Performance Share Unit Awards
	2016		2015		2014
Forecast period (years)	2.60		2.67		2.62
Risk-free interest rate	1.00	%	0.79	%	0.61	%
Jones stock price volatility	71.47	%	52.87	%	40.40	%

The average historical combined volatilities for the Company and each peer company was 70.45%, 55.13%, and 46.95% for the awards made in 2016, 2015, and 2014, respectively. Based on these assumptions, the Monte Carlo simulation model resulted in an expected percentage of performance share units earned of 123.84%, 101.61%, and 126.80% for the 2016, 2015, and 2014 awards, respectively.

Performance Unit Awards

The Company has outstanding performance unit awards, granted initially in 2016, to certain members of the senior management team of the Company under the LTIP. References to performance unit awards in prior filings do not correspond to these newly created performance unit awards. Upon the completion of the applicable three-year performance period, each recipient may vest in a number of performance units. The value of awarded performance units in which each recipient vests at such time, if any, will range from $0.00 to $200.00 per performance unit based on the

Company’s total shareholder return relative to an industry peer group over the applicable three-year performance period. For accounting purposes, the performance units are treated as a liability award with the liability being re-measured at the end of each reporting period. Therefore, the expense associated with these awards is subject to volatility until the payout is finally determined at the end of the performance period. The value of the performance units was determined at award using a Monte Carlo simulation model, as of the grant date, which resulted in an estimated final value upon vesting of $1.3 million. The fair value measured as of December 31, 2016 was $1.2 million.

The following assumptions were used for the Monte Carlo model to determine the grant date fair value and associated stock-based compensation expense of the performance unit awards granted during the year ended December 31, 2016:

	2016
	Performance
	Unit Awards
Forecast period (years)	2.60
Risk-free interest rate	1.00	%
Jones stock price volatility	71.47	%

For the performance units granted during the year ended December 31, 2016, the Monte Carlo simulation model resulted in an expected payout of $67.38 per performance unit as of the grant date.

Stock compensation expense associated with the performance unit awards was $0.3 million for the year ended December 31, 2016, and is included in general and administrative expenses on the Company’s Consolidated Statement of Operations. As of December 31, 2016, $0.9 million of unrecognized compensation expense related to the performance unit awards, subject to re-measurement and adjustment for the change in estimated final value as of the end of each reporting period, is expected to be recognized over the remaining weighted-average remaining period of 2.0 years.

Restricted Stock Awards

The Company has outstanding restricted stock awards granted to the non-employee members of the Board of Directors of the Company under the LTIP. The restricted stock will vest upon the director serving as a director of the Company for a one-year service period in accordance with the terms of the award. The fair value of the awards was based on the price of the Company’s Class A common stock on the date of grant.

The following table summarizes information related to the total value of the awards to the Board of Directors as of December 31, 2016:

			Weighted Average
	Restricted		Grant Date Fair Value
	Stock Awards		per Share
Unvested at December 31, 2015	73,271		$	6.71
Granted	152,050		3.68
Forfeited	—
Vested	(73,271	)	6.71
Unvested at December 31, 2016	152,050		$	3.68

Stock compensation expense associated with awards to the members of the Board of Directors for the years ended December 31, 2016, 2015 and 2014 was $0.6 million, $0.6 million, and $0.4 million, respectively, and is included in general and administrative expenses on the Company’s Consolidated Statement of Operations. The weighted average grant date fair value of restricted stock awards was $3.68 per share, $6.71 per share, and $17.26 per share for the years ended December 31, 2016, 2015, and 2014. Unrecognized expense as of December 31, 2016 for all outstanding restricted stock awards was $0.2 million and will be recognized over the remaining vesting period of 0.4 years.

For the years ended December 31, 2016, 2015, and 2014, the Company had an associated tax benefit of $1.4 million, $1.1 million, and $0.4 million, respectively, related to all stock-based compensation, calculated at the federal statutory rate after adjusting for the non-controlling interest.

10. Benefit Plans

The Company maintains a tax-qualified 401(k) 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 to the Plan.

In addition, since 2013, the Company has maintained a non-qualified deferred compensation plan for the benefit of key employees. The non-qualified deferred compensation plan is an unfunded, account-based plan under which key employees of the Company may elect to defer a portion of their base salary and/or bonus. For the years ended December 31, 2016, 2015, and 2014, our total expense relating to these plans was $0.4 million, $0.5 million, and $0.3 million, respectively.

11. Income Taxes

The Company records federal and state income tax liabilities associated with its status as a corporation. The Company recognizes 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, 2016, 2015, and 2014:

	Year Ended December 31,
(in thousands of dollars)	2016			2015			2014
Current tax expense:
Federal	$	3,758		$	—		$	53
State	223			113			—
Total current expense	3,981			113			53
Deferred tax expense (benefit):
Federal	(27,245		)	(1,137		)	22,140
State	(522		)	(1,757		)	4,025
Total deferred expense (benefit)	(27,767		)	(2,894		)	26,165
Total tax expense (benefit)	$	(23,786	)	$	(2,781	)	$	26,218
Tax expense (benefit) attributable to controlling interests	(23,263		)	(1,160		)	22,819
Tax expense attributable to non-controlling interests	(523		)	(1,621		)	3,399
Total income tax expense (benefit)	$	(23,786	)	$	(2,781	)	$	26,218

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)	2016			2015			2014
Provision calculated at federal statutory income tax rate:
Net income before taxes	$	(108,591	)	$	(11,858	)	$	251,838
Statutory rate	35		%	35		%	35		%
Income tax expense (benefit) computed at statutory rate	$	(38,007	)	$	(4,150	)	$	88,144
Less: Non-controlling interests	14,972			2,911			(65,759		)
Income tax expense (benefit) attributable to controlling interests	(23,035		)	(1,239		)	22,385
State and local income taxes, net of federal benefit	(622		)	(1,011		)	626
Reduction of TRA liability	(282		)	(694		)	—
Equity compensation, shortfall	—			338			—
Change in enacted rate	—			(650		)	—
Change in valuation allowance	950			2,333			—
Other	(274		)	(237		)	(192		)
Tax expense (benefit) attributable to controlling interests	(23,263		)	(1,160		)	22,819
Tax expense attributable to non-controlling interests	(523		)	(1,621		)	3,399
Total income tax expense (benefit)	$	(23,786	)	$	(2,781	)	$	26,218

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.

In 2015, Texas enacted legislation that reduced the Texas franchise tax rate from 1.0% to 0.75%. We recorded a tax benefit of $1.7 million as a result of revaluing our deferred tax assets and liabilities at the newly enacted rate, of which $1.0 million was attributable to the non-controlling interest.

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)	2016			2015
Deferred tax assets
Net operating loss	$	8,687		$	9,414
Section 754 election tax basis adjustment	51,154			47,100
Other deferred tax asset	—			505
Total deferred tax assets	59,841			57,019
Deferred tax liabilities
Investment in consolidated subsidiary JEH	56,888			73,559
Noncurrent state deferred tax liability	2,703			4,099
Total deferred tax liabilities	59,591			77,658
Net deferred tax assets (liabilities)	250			(20,639		)
Valuation allowance	(3,155		)	(2,333		)
Net deferred tax assets (liabilities)	$	(2,905	)	$	(22,972	)

The Company has a federal net operating loss carry-forward totaling $19.5 million and state net operating loss carry-forward of $48.2 million, of which the federal net operating loss carry-forward expires between 2033 and 2035 and with state net operating loss carryforwards expiring between 2033 and 2036. The tax benefits of carryforwards are recorded as an asset to the extent that management assesses the utilization of such carryforwards to be more likely than not. When the future utilization of some portion of the carryforwards is determined not to be more likely than not, a valuation allowance is provided to reduce the recorded tax benefits from such assets. As of December 31, 2016, we had a valuation

allowance of $3.2 million as a result of management’s assessment of the realizability of federal and state deferred tax assets. Management believes that there will be sufficient future taxable income based on the reversal of temporary differences to enable utilization of substantially all other tax carryforwards.

Internal Revenue Code (“IRC”) Section 382 addresses company ownership changes and specifically limits the utilization of certain deductions and other tax attributes on an annual basis following an ownership change. The Company experienced an ownership change within the meaning of IRC Section 382 during 2015 that subjects a portion of the federal net operating loss carryforwards to an IRC Section 382 limitation. Although such limitation is not expected to limit the Company’s ability to utilize its net operating loss carryforwards before expiration, the limitation contributes to a current federal tax liability for the year ended December 31, 2016.

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 2012 through 2016. The tax years 2013 through 2016 remain open to examination by the major taxing jurisdictions to which the Company is subject, however net operating losses originating in prior years are subject to examination when utilized. The Internal Revenue Service is currently examining the 2013 federal partnership income tax return for JEH, but has indicated that the audit will be concluded with no change. The Company’s other income tax returns have not been audited by the Internal Revenue Service or any state 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, 2016, 2015, and 2014 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.

Tax Receivable Agreement

In connection with the IPO, the Company entered into a Tax Receivable Agreement (the “TRA”) which obligates the Company to make payments to certain current and former owners equal to 85% of the applicable cash savings that the Company realizes as a result of tax attributes arising from exchanges of JEH Units and shares of the Company’s Class B common stock held by those owners for shares of the Company’s Class A common stock. The Company will retain the benefit of the remaining 15% of these tax savings. At the time of an exchange, the company records a liability to reflect the future payments under the TRA.

The actual amount and timing of payments to be made under the TRA will depend upon a number of factors, including the amount and timing of taxable income generated in the future, changes in future tax rates, the use of loss carryovers, and the portion of the Company’s payments under the TRA constituting imputed interest. In the event that the Company records a valuation allowance against its deferred tax assets associated with an exchange, the TRA liability will also be reduced as the payment of the TRA liability is dependent on the realizability of the deferred tax assets. As of December 31, 2016 and 2015, the amount of the TRA liability was reduced by $2.7 million, and $2.0 million, respectively, as a result of the valuation allowance recorded against the Company’s deferred tax assets. To the extent the Company does not realize all of the tax benefits in future years or in the event of a change in future tax rates, this liability may change.

As of December 31, 2016, and 2015 the Company had recorded a TRA liability of $43.0 million, and $38.1 million, respectively, for the estimated payments that will be made to the Class B shareholders who have exchanged shares, after adjusting for the TRA liability reduction, along with corresponding deferred tax assets, net of valuation allowance, of $50.6 million, and $44.8 million, respectively, as a result of the increase in tax basis generated arising from such exchanges.

As of December 31, 2016, the Company had not made any payments under the TRA to Class B shareholders who have exchanged JEH units and Class B common stock for Class A common stock. The Company anticipates making a payment of approximately $0.6 million under the TRA with respect to cash savings that the Company will realize on its 2016 tax returns as a result of tax attributes arising from prior exchanges, to be paid in the first quarter of 2018.

Cash Tax Distributions

The holders of JEH Units, including Jones Energy, Inc., incur U.S. federal, state and local income taxes on their share of any taxable income of JEH. Under the terms of its operating agreement, JEH is generally required to make quarterly pro-rata cash tax distributions to its unitholders (including us) based on income allocated to its unitholders through the end of

each relevant quarter, as adjusted to take into account good faith projections by the Company of taxable income or loss for the remainder of the calendar year, to the extent JEH has cash available for such distributions and subject to certain other restrictions.

A Special Committee of the Board of Directors comprised solely of directors who do not have a direct or indirect interest in such distribution approved, and JEH made, aggregate cash tax distributions during 2016 of $41.0 million (including distributions to us) to its unitholders towards its total 2016 projected tax distribution obligation. The distributions were made pro-rata to all members of JEH, and included a $23.7 million payment to the Company and a $17.3 million payment to Class B shareholders. The 2016 tax distributions are the result of taxable income generated by JEH’s operations and debt extinguishment.

12. Stockholders’ and Mezzanine equity

Stockholders’ equity is comprised of two classes of common stock, Class A common stock and Class B common stock. The Class B common stock is held by the owners of JEH prior to the Company’s IPO and can be exchanged (together with a corresponding number of units representing membership interests in 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 holders to one vote on all matters to be voted on by the Company’s stockholders generally.

The Company has classified the Series A preferred stock as mezzanine equity based upon the terms and conditions that contain various redemption and conversion features. For a description of these features, please see below under “—Offering of 8.0% Series A Perpetual Convertible Preferred Stock.”

Equity Distribution Agreement

On May 24, 2016, the Company and JEH entered into an Equity Distribution Agreement (“Equity Distribution Agreement”) with Citigroup Global Markets Inc. and Wells Fargo Securities, LLC (each, a “Manager” and collectively, the “Managers”). Pursuant to the terms of the Equity Distribution Agreement, the Company may sell from time to time through the Managers, as the Company’s sales agents, the Company’s Class A common stock having an aggregate offering price of up to $73.0 million (the “Class A Shares”). Under the terms of the Equity Distribution Agreement, the Company may also sell Class A Shares from time to time to any Manager as principal for its own account at a price to be agreed upon at the time of sale. Any sale of Class A Shares to a Manager as principal would be pursuant to the terms of a separate terms agreement between the Company and such Manager. Sales of the Class A Shares, if any, will be made by means of ordinary brokers’ transactions, to or through a market maker or directly on or through an electronic communication network, a “dark pool” or any similar market venue, or as otherwise agreed by the Company and one or more of the Managers.

During the year ended December 31, 2016, the Company sold approximately 0.5 million Class A Shares under the Equity Distribution Agreement for net proceeds of approximately $1.8 million ($2.1 million gross proceeds, net of approximately $0.3 million in commissions and professional services expenses). The Company used the net proceeds for general corporate purposes. At December 31, 2016, approximately $70.9 million in aggregate offering proceeds remained available to be issued and sold under the Equity Distribution Agreement.

Offering of Class A Common Stock

On August 19, 2016, the Company and JEH entered into an underwriting agreement (the “Common Stock Underwriting Agreement”) with Credit Suisse Securities (USA) LLC and J.P. Morgan Securities LLC, as representatives of the underwriters named therein (the “Common Stock Underwriters”), with respect to the offer and sale of 21,000,000 shares of the Company’s Class A common stock, par value $0.001 per share (the “Class A Common Stock”). The Common Stock Underwriting Agreement also provided the Common Stock Underwriters an option (the “Common Stock Option”) to purchase up to an additional 3,150,000 shares of Class A Common Stock (the “Additional Offering”) within 30 days of the date of the Common Stock Underwriting Agreement. On September 7, 2016, the Underwriters exercised the Common Stock Option in full. The total net proceeds from the offering of Class A Common Stock (after underwriters’ compensation, but before estimated expenses) pursuant to the Common Stock Underwriting Agreement, including the exercise of the Common Stock Option, was $64.0 million. The Class A Common Stock was issued pursuant to the Company’s shelf registration statement on Form S-3 (Registration No. 333-211568), which became effective July 26, 2016, and a prospectus, which consists of a base prospectus, dated as of July 26, 2016, and a prospectus supplement,

dated August 19, 2016. The closing of the sale of Class A Common Stock occurred on August 26, 2016 and the Additional Offering closed on September 12, 2016.

Offering of 8.0% Series A Perpetual Convertible Preferred Stock

On August 19, 2016, the Company and JEH entered into an underwriting agreement (the “Preferred Stock Underwriting Agreement”) with Credit Suisse Securities (USA) LLC and J.P. Morgan Securities LLC (the “Preferred Stock Underwriters”) with respect to the offer and sale of 1,600,000 shares of the Series A preferred stock. The Preferred Stock Underwriting Agreement also provided the Preferred Stock Underwriters an option (the “Preferred Stock Option”) to purchase an additional 240,000 shares of Series A preferred stock, which was exercised in full. The total net proceeds from the offering of Series A preferred stock (after underwriters’ compensation, but before estimated expenses) pursuant to the Preferred Stock Underwriting Agreement, including the exercise of the Preferred Stock Option, was $88.3 million. The Series A preferred stock was issued pursuant to the Company’s shelf registration statement on Form S-3 (Registration No. 333-211568), which became effective July 26, 2016, and an additional registration statement with respect thereto on Form S-3 (Registration No. 333-213201) filed under Rule 462(b) of the Act, which became effective upon filing on August 19, 2016. The closing of the sale of Series A preferred stock occurred on August 26, 2016.

Holders of Series A preferred stock are entitled to receive, when as and if declared by the Company’s Board of Directors, cumulative dividends at the rate of 8.0% per annum (the “dividend rate”) per share on the $50.00 liquidation preference per share of the Series A Preferred Stock, payable quarterly in arrears on February 15, May 15, August 15 and November 15 of each year, beginning on November 15, 2016. Dividends may be paid in cash or, subject to certain conditions, in Class A common stock, or a combination thereof.

Under the terms of the Series A preferred stock, the Company’s ability to declare or pay dividends or make distributions on, or purchase, redeem or otherwise acquire for consideration, shares of the Company’s Class A common stock, or any junior stock or parity stock currently outstanding or issued in the future, will be subject to certain restrictions in the event that the Company does not pay in full or declare and set aside for payment in full all accrued and unpaid dividends on the Series A preferred stock (including certain unpaid excess cash payment amounts excused from payment as a dividend due to restrictions in credit facilities or other indebtedness or legal requirements (“Unpaid Excess Cash Payment Amounts”)).

Each share of Series A preferred stock has a liquidation preference of $50.00 per share and is convertible, at the holder’s option at any time, into approximately 17.0683 shares of Class A common stock after adjusting the conversion ratio for the effects of the Special Stock Dividend, as defined in Note 16, “Subsequent Events - Special Stock Dividend Declared”, distributed on March 31, 2017 (which is equivalent to an conversion price of approximately $2.93 per share after adjusting for the effects of the Special Stock Dividend), subject to specified adjustments and limitations as set forth in the certificate of designations for the Series A preferred stock. Based on the adjusted conversion rate and the full exercise of the Preferred Stock Underwriters’ over-allotment option, approximately 31.4 million shares of Class A common stock would be issuable upon conversion of all the Series A preferred stock.

On or after August 15, 2021, the Company may, at its option, give notice of its election to cause all outstanding shares of Series A preferred stock to be automatically converted into shares of Class A common stock at the conversion rate, if the closing sale price of the Class A common stock equals or exceeds 175% of the conversion price for at least 20 trading days in a period of 30 consecutive trading days.

On August 15, 2024 (the “designated redemption date”), each holder of Series A preferred stock may require us to redeem any or all Series A preferred stock held by such holder outstanding on the designated redemption date at a redemption price equal to a liquidation preference of $50.00 per share plus all accrued dividends on the shares up to but excluding the designated redemption date that have not been paid plus any Unpaid Excess Cash Payment Amounts (the “redemption price”). At our option, the redemption price may be paid in cash or, subject to certain limitations, in Class A common stock, or a combination thereof.

Except as required by law or the Company’s certificate of incorporation, which includes the certificate of designations for the Series A preferred stock, the holders of Series A preferred stock have no voting rights (other than with respect to certain matters regarding the Series A preferred stock or when dividends payable on the Series A preferred stock have not been paid for an aggregate of six quarterly dividend periods, or more, whether or not consecutive, as provided in the certificate of designations for the Series A preferred stock).

The Series A preferred stock is classified as mezzanine equity on the Company’s Consolidated Balance Sheet.

Mezzanine equity consisted of the following at December 31, 2016:

(in thousands of dollars)	December 31, 2016
Series A preferred stock, at issuance (net)	$	87,922
Dividends on preferred stock	940
Accretion on preferred stock	113
Mezzanine equity at December 31, 2016	$	88,975

13. 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. Shares of Class B common stock are 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 potential dilutive effect of shares that could be issued by the Company in conjunction with the Series A preferred stock and from stock awards that have been granted to directors and employees. Awards of non-vested shares are considered outstanding as of the respective grant dates for purposes of computing diluted EPS even though the award is contingent upon vesting. For the year ended December 31, 2016, 1,359,088 restricted stock units, and 1,125,706 performance share units, and 31,405,672 shares from the convertible Class A preferred stock were excluded from the calculation as they would have had an anti-dilutive effect. For the year ended December 31, 2015, 823,446 restricted stock units, and 586,325 performance share units were excluded from the calculation as they would have had an anti-dilutive effect. For the year ended December 31, 2014, 29,828 restricted stock shares, 59,434 restricted stock units and 209,870 performance share units were excluded from the calculation as they would have had an anti-dilutive effect.

The following is a calculation of the basic and diluted weighted-average number of shares of Class A common stock outstanding and EPS:

Earnings per Share

	Year Ended December 31,
(in thousands, except per share data)	2016			2015			2014
Income (numerator):
Net income (loss) attributable to controlling interests	$	(42,552	)	$	(2,381	)	$	41,136
Less: Dividends and accretion on preferred stock	(2,669		)	—			—
Net income (loss) attributable to common shareholder	$	(45,221	)	$	(2,381	)	$	41,136
Weighted-average shares (denominator) (1) :
Weighted-average number of shares of Class A common stock - basic	43,506			29,161			13,622
Weighted-average number of shares of Class A common stock - diluted	43,506			29,161			13,630
Earnings (loss) per share (1) :
Basic - Net income (loss) attributable to common shareholders	$	(1.04	)	$	(0.08	)	$	3.02
Diluted - Net income (loss) attributable to common shareholders	$	(1.04	)	$	(0.08	)	$	3.02

(1)All share and earnings per share information presented has been recast to retrospectively adjust for the effects of the 0.087423 per share Special Stock Dividend, as defined in Note 16, “Subsequent Events - Special Stock Dividend Declared”, distributed on March 31, 2017.

14. Related Parties

Related Party Transactions

Transactions with Our Executive Officers, Directors and 5% Stockholders

On May 7, 2013, the Company entered into a natural gas sale and purchase agreement with Monarch Natural Gas, LLC, (“Monarch”), under which Monarch has the first right to gather the natural gas the Company produces from dedicated 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. The Company produced approximately 1.4 MMBoe of natural gas and NGLs for the year ended December 31, 2014, from the properties that became subject to the Monarch agreement. During the year ended December 31, 2014, the Company recognized $37.0 million of revenue associated with the aforementioned natural gas and NGL production. Effective May 1, 2015, the rights to gather natural gas under the sale and purchase agreement transferred from Monarch to Enable Midstream Partners LP, (“Enable”), an unaffiliated third-party. Prior to closing of the transfer of these rights, the Company produced approximately 1.0 MMBoe of natural gas and NGLs for the year ended December 31, 2015 from the properties that became subject to the Monarch agreement for which the Company recognized $10.6 million of revenue. The revenue, for all years mentioned, is recorded in Oil and gas sales on the Company’s Consolidated Statement of Operations. The initial term of the agreement, which remains unchanged by the transfer to Enable, runs for 10 years from the effective date of September 1, 2013.

At the time the Company entered into the 2013 Monarch 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 2013 Monarch agreement, Monarch issued to JEH equity interests in Monarch, having an estimated fair value of $15.0 million, in return for marketing services to be provided throughout the term of the agreement. The Company recorded this amount as deferred revenue which is being amortized on an estimated units-of-production basis commencing in September 2013, the first month of product sales to Monarch. During the years ended December 31, 2016, 2015, and 2014, the Company amortized $2.4 million, $2.0 million, and $1.2 million, respectively, of the deferred revenue balance. This revenue is recorded in Other revenues on the Company’s Consolidated Statement of Operations.

Following the issuance of the $15.0 million Monarch equity interests, JEH assigned $2.4 million of the equity interests to Jonny Jones, the Company’s chief executive officer and chairman of the board, and reserved $2.6 million of the equity interests for future distribution through an incentive plan to certain of the Company’s officers, including Mike McConnell, Robert Brooks and Eric Niccum. The remaining $10.0 million of Monarch equity interests was distributed to certain of the Class B shareholders, which included Metalmark Capital, Wells Fargo, the Jones family entities, and certain of the Company’s officers and directors, including Jonny Jones, Mike McConnell and Eric Niccum. As of December 31, 2016, equity interests in Monarch of $0.7 million are included in Other assets on the Company’s Consolidated Balance Sheet. During the years ended December 31, 2016, 2015, and 2014, equity interests of $0.6 million, $0.8 million, and $0.5 million, respectively, were distributed to management under the incentive plan. The Company recognized expense of $0.5 million, $0.5 million, and $0.8 million during the years ended December 31, 2016, 2015, and 2014, respectively, in connection with the incentive plan.

In September 2014, the Company signed a 10-year oil gathering and transportation agreement with Monarch Oil Pipeline LLC, pursuant to which Monarch Oil Pipeline LLC built, at its expense, a new oil gathering system and connected the gathering system to dedicated Company leases in Texas. At the time the Company entered into the agreement, Metalmark Capital owned the majority of the outstanding equity interests of Monarch Oil Pipeline LLC and/or its parent. The system began service during the fourth quarter of 2015 and provides connectivity to both a regional refinery market as well as the Cushing market hub. The Company incurred gathering fees, which were paid to Monarch Oil Pipeline LLC, of $2.7 million and $0.4 million associated with the approximately 1.3 MMBoe and 0.2 MMBoe of oil production transported under the agreement for the years ended December 31, 2016 and 2015. These costs are recorded as an offset to Oil and gas sales in the Company’s Consolidated Statement of Operations. The aforementioned production was

recognized as Oil and gas sales on the Company’s Consolidated Statement of Operations at the time it was sold to the purchasers, who are unaffiliated third-parties, after passing through the gathering and transportation system. The audit committee of the Board reviewed and approved the terms of the agreement with Monarch Oil Pipeline LLC.

In May 2015, the Company received a $0.7 million cash distribution associated with its equity interests in Monarch, which was accounted for following the cost method. The initial cash distribution from Monarch was treated as dividend income and is recorded in Other income (expense).

Purchase of Senior Unsecured Notes

On February 29, 2016, JEH and Jones Energy Finance Corp. purchased $50.0 million principal amount of their outstanding 2023 Notes from investment funds managed by Magnetar Capital and its affiliates, which investment funds collectively own more than 5% of a class of voting securities of the Company, for approximately $23.3 million excluding accrued interest and including any associated fees. On the same day, JEH and Jones Energy Finance Corp. purchased an additional $50.0 million principal amount of their outstanding 2023 Notes from investment funds managed by Blackstone Group Management L.L.C. and its affiliates, which investment funds collectively own more than 5% of a class of voting securities of the Company, for approximately $23.3 million excluding accrued interest and including any associated fees. In conjunction with the extinguishment of this $100.0 million principal amount of debt, JEH recognized cancellation of debt income of $48.3 million on a pre-tax basis. This income is recorded in Gain on debt extinguishment on the Company’s Consolidated Statement of Operations.

15. Commitments and Contingencies

Lease obligations

The Company leases approximately 43,000 square feet of office space in Austin, TX under an operating lease arrangement. We also lease approximately 5,500 square feet of office space in Oklahoma City, Oklahoma. Future minimum payments for all noncancellable operating leases extending beyond one year at December 31, 2016 are as follows:

(in thousands of dollars)
Years Ending December 31,
2017	$	1,054
2018	1,118
2019	1,125
2020	375
2021	—
Thereafter	—
	$	3,672

Rent expense under operating leases was $1.6 million, $1.6 million, and $0.9 million for the years ended December 31, 2016, 2015, and 2014, respectively.

Litigation

The Company is subject to legal proceedings and claims that arise in the ordinary course of its business. When applicable, we record accruals for contingencies when it is probable that a liability will be incurred and the amount of loss can be reasonably estimated. While the outcome of lawsuits and other proceedings against us cannot be predicted with certainty, in the opinion of management, individually or in the aggregate, no such lawsuits are expected to have a material effect on our financial position, results of operations, or liquidity.

In an action filed on June 12, 2015 in the 31st District Court of Hemphill County, Texas, Donna Kim Flowers and Mitchell Kirk Flowers v. Jones Energy, LLC f/k/a Jones Energy Limited, LLC f/k/a Jones Energy, Ltd. (Case No. 7225), the Company was sued by Donna Kim Flowers and Mitchell Kirk Flowers (the “plaintiffs”). The plaintiffs own surface rights to property located in Hemphill County, Texas. The mineral rights are leased to third parties, and the Company is the operator of the Oil and Gas Mineral Lease. On May 28, 2010, the plaintiffs and the Company entered into a Surface Use Agreement concerning the Company’s fracking operations on the property, which require the Company to minimize disruption and damage to the plaintiffs’ surface rights. The plaintiffs allege that the Company is in breach of such

contract, and seek monetary damages. In June 2016, the Company presented a settlement offer to the plaintiffs. As a result of this settlement offer, the Company has accrued $1.5 million related to its estimated obligation under this settlement offer. This accrual was included in accrued liabilities on the Company’s Consolidated Balance Sheet as of December 31, 2016, and the charge was recorded as general and administrative expense on the Company’s Consolidated Statement of Operations for the year ended December 31, 2016. However, no certainty exists that a settlement will be reached or if so, the amount of any such settlement. Therefore, the ultimate loss could be greater or less than the amount accrued. In the event the plaintiffs and the Company are not able to reach a settlement, a court date is anticipated to occur during the third quarter of 2017.

16. Subsequent Events

Preferred Stock Dividend Declared

On January 19, 2017, the Company’s Board of Directors declared a quarterly cash dividend per share equal to 8.0% based on the liquidation preference of $50.00 per share on an annualized basis, or $1.00 per share, on the Company’s 8.0% Series A Perpetual Convertible Preferred Stock. This dividend is for the period beginning on the last payment date of November 15, 2016 through February 14, 2017 and was paid in cash on February 15, 2017 to shareholders of record as of February 1, 2017.

Special Stock Dividend Declared

On March 3, 2017, the Company’s Board of Directors declared a special stock dividend (the “Special Stock Dividend”) of 0.087423 shares of the Company’s Class A common stock, $0.001 par value (“Class A Common Stock”), for each outstanding share of Class A Common Stock (based on the number of shares outstanding on the date hereof). The special stock dividend is payable on March 31, 2017 to stockholders of record as of the close of business on March 15, 2017. In lieu of issuing fractional shares of Class A Common Stock, cash will be distributed. All share and EPS information presented herein have been recast to retrospectively adjust for the effects of this special stock dividend. 

From time-to-time, the Company’s subsidiary Jones Energy Holdings, LLC (“JEH”) makes cash distributions to the holders of common units representing membership interests in JEH (“JEH Common Units”) to cover tax obligations that may occur as a result of any net taxable income of JEH allocable to holders of JEH Common Units. As a JEH Common Unit holder, the Company has received such cash distributions from JEH in excess of the amount required to satisfy the Company’s associated tax obligations. As a result, the Company is using the excess cash of approximately $17.5 million in the aggregate to acquire newly-issued JEH Common Units from JEH, who will use the $17.5 million in proceeds to pay down debt outstanding under its credit facility.

The stock dividend has been declared in order to equalize the number of shares of Class A Common Stock outstanding to the number of JEH Common Units held by the Company, and the aggregate number of Class A Common Stock issued in the stock dividend will equal the number of additional JEH Common Units the Company is purchasing from JEH. The JEH Common Units will be purchased at a price of $3.50 per share, which is the volume weighted average price per share of the Class A Common stock for the five trading days ended February 28, 2017. Cash payments in lieu of fractional shares will also be made on the basis of a value per share of Class A Common Stock of $3.50 per share.

The declaration, amount and payment of any future dividends on shares of Class A Common Stock will be at the sole discretion of Jones Energy’s board of directors and the amount and timing of any future dividends cannot be predicted at this time.

17. Subsidiary Guarantors

On April 1, 2014, the Issuers sold $500.0 million in aggregate principal amount of the 2022 Notes. On February 23, 2015, the Issuers sold $250.0 million in aggregate principal amount of the 2023 Notes.

The 2022 Notes and the 2023 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 Revolver. Each subsidiary guarantor is 100% owned by JEH, and all guarantees are full and unconditional, subject to customary exceptions pursuant to the indentures governing our 2022 Notes and 2023 Notes, as discussed below, 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 immaterial.

As of December 31, 2016, the 2022 Notes and the 2023 Notes were guaranteed on a senior unsecured basis by the Company and by all of its significant subsidiaries, other than Nosley SCOOP, LLC and Nosley Acquisition, LLC. During the first quarter of 2017, these subsidiaries became guarantors and therefore, the accompanying condensed consolidated guarantor financial statements have been recast to retrospectively present these subsidiaries as guarantors.

Guarantees of the 2022 Notes and 2023 Notes will be released under certain circumstances, including (i) in connection with any sale or other disposition of (a) all or substantially all of the properties or assets of a guarantor (including by way of merger or consolidation) or (b) all of the capital stock of such guarantor, in each case, to a person that is not the Company or a restricted subsidiary of the Company, (ii) if the Company designates any restricted subsidiary that is a guarantor as an unrestricted subsidiary, (iii) upon legal defeasance, covenant defeasance or satisfaction and discharge of the applicable indenture, or (iv) at such time as such guarantor ceases to guarantee any other indebtedness of the Company or any other guarantor.

The Company is a holding company whose sole material asset is an equity interest in JEH. 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.

As of December 31, 2016, the Company held 57,025,474 JEH Units and all of the preferred units representing membership interests in JEH, and the remaining 29,832,098 JEH Units are held by a group of investors that owned interests in JEH prior to the Company’s IPO (the “Class B shareholders”). The Class B shareholders 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, and one series of preferred stock, Series A preferred 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. Except as required by law or the Company’s certificate of incorporation, which includes the certificate of designations for the Series A preferred stock, the holders of Series A preferred stock have no voting rights (other than with respect to certain matters regarding the Series A preferred stock or when dividends payable on the Series A preferred stock have not been paid for an aggregate of six quarterly dividend periods, or more, whether or not consecutive, as provided in the certificate of designations for the Series A preferred stock).

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 was equal to the number of JEH Units that such Class B shareholder held. 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 Class B shareholders have the right, pursuant to the terms of an exchange agreement by and among the Company, JEH and each of the Class B shareholders (the “Exchange Agreement”), 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 Balance Sheet

December 31, 2016

						Guarantor		Non-Guarantor
(in thousands of dollars)	JEI (Parent)			Issuers		Subsidiaries		Subsidiaries			Eliminations			Consolidated
Assets
Current assets
Cash	$	27,164		$	1,975	$	5,483	$	20		$	—		$	34,642
Accounts receivable, net
Oil and gas sales	—			—		26,568		—			—			26,568
Joint interest owners	—			—		5,267		—			—			5,267
Other	—			5,434		627		—			—			6,061
Commodity derivative assets	—			24,100		—		—			—			24,100
Other current assets	—			422		2,262		—			—			2,684
Intercompany receivable	15,666			1,180,859		—		—			(1,196,525		)	—
Total current assets	42,830			1,212,790		40,207		20			(1,196,525		)	99,322
Oil and gas properties, net, at cost under the successful efforts method	—			—		1,743,588		—			—			1,743,588
Other property, plant and equipment, net	—			—		2,378		618			—			2,996
Commodity derivative assets	—			34,744		—		—			—			34,744
Other assets	—			5,265		785		—			—			6,050
Investment in subsidiaries	531,363			—		—		—			(531,363		)	—
Total assets	$	574,193		$	1,252,799	$	1,786,958	$	638		$	(1,727,888	)	$	1,886,700
Liabilities and Stockholders’ Equity
Current liabilities
Trade accounts payable	$	—		$	13	$	36,514	$	—		$	—		$	36,527
Oil and gas sales payable	—			—		28,339		—			—			28,339
Accrued liabilities	3,874			11,227		10,597		9			—			25,707
Commodity derivative liabilities	—			14,650		—		—			—			14,650
Other current liabilities	—			1,984		600		—			—			2,584
Intercompany payable	—			—		1,566,941		2,796			(1,569,737		)	—
Total current liabilities	3,874			27,874		1,642,991		2,805			(1,569,737		)	107,807
Long-term debt	—			724,009		—		—			—			724,009
Deferred revenue	—			7,049		—		—			—			7,049
Commodity derivative liabilities	—			1,209		—		—			—			1,209
Asset retirement obligations	—			—		19,458		—			—			19,458
Liability under tax receivable agreement	43,045			—		—		—			—			43,045
Other liabilities	—			269		523		—			—			792
Deferred tax liabilities	85			2,820		—		—			—			2,905
Total liabilities	47,004			763,230		1,662,972		2,805			(1,569,737		)	906,274
Mezzanine equity
Series A preferred stock, $0.001 par value; 1,840,000 shares issued and outstanding at December 31, 2016	88,975			—		—		—			—			88,975
Stockholders’/ members’ equity
Members’ equity	—			489,569		123,986		(2,167		)	(611,388		)	—
Class A common stock, $0.001 par value; 57,048,076 shares issued and 57,025,474 shares outstanding at December 31, 2016	57			—		—		—			—			57
Class B common stock, $0.001 par value; 29,832,098 shares issued and outstanding at December 31, 2016	30			—		—		—			—			30
Treasury stock, at cost: 22,602 shares at December 31, 2016	(358		)	—		—		—			—			(358		)
Additional paid-in-capital	447,137			—		—		—			—			447,137
Retained earnings (deficit)	(8,652		)	—		—		—			—			(8,652		)
Stockholders’ equity	438,214			489,569		123,986		(2,167		)	(611,388		)	438,214
Non-controlling interest	—			—		—		—			453,237			453,237
Total stockholders’ equity	438,214			489,569		123,986		(2,167		)	(158,151		)	891,451
Total liabilities and stockholders’ equity	$	574,193		$	1,252,799	$	1,786,958	$	638		$	(1,727,888	)	$	1,886,700

Jones Energy, Inc.

Condensed Consolidating Balance Sheet

December 31, 2015

						Guarantor		Non-Guarantor
(in thousands of dollars)	JEI (Parent)			Issuers		Subsidiaries		Subsidiaries			Eliminations			Consolidated
Assets
Current assets
Cash	$	100		$	12,448	$	9,325	$	20		$	—		$	21,893
Accounts receivable, net
Oil and gas sales	—			—		19,292		—			—			19,292
Joint interest owners	—			—		11,314		—			—			11,314
Other	—			14,444		726		—			—			15,170
Commodity derivative assets	—			124,207		—		—			—			124,207
Other current assets	—			444		1,854		—			—			2,298
Intercompany receivable	12,866			1,161,997		—		—			(1,174,863		)	—
Total current assets	12,966			1,313,540		42,511		20			(1,174,863		)	194,174
Oil and gas properties, net, at cost under the successful efforts method	—			—		1,635,766		—			—			1,635,766
Other property, plant and equipment, net	—			—		3,168		705			—			3,873
Commodity derivative assets	—			93,302		—		—			—			93,302
Other assets	—			7,456		583		—			—			8,039
Investment in subsidiaries	444,362			—		—		—			(444,362		)	—
Total assets	$	457,328		$	1,414,298	$	1,682,028	$	725		$	(1,619,225	)	$	1,935,154
Liabilities and Stockholders’ Equity
Current liabilities
Trade accounts payable	$	—		$	388	$	7,079	$	—		$	—		$	7,467
Oil and gas sales payable	—			—		32,408		—			—			32,408
Accrued liabilities	—			15,741		11,270		—			—			27,011
Commodity derivative liabilities	—			11		—		—			—			11
Other current liabilities	—			—		679		—			—			679
Intercompany payable	—			—		1,391,838		2,434			(1,394,272		)	—
Total current liabilities	—			16,140		1,443,274		2,434			(1,394,272		)	67,576
Long-term debt	—			837,654		—		—			—			837,654
Deferred revenue	—			11,417		—		—			—			11,417
Asset retirement obligations	—			—		20,301		—			—			20,301
Liability under tax receivable agreement	38,052			—		—		—			—			38,052
Other liabilities	—			—		330		—			—			330
Deferred tax liabilities	19,280			3,692		—		—			—			22,972
Total liabilities	57,332			868,903		1,463,905		2,434			(1,394,272		)	998,302
Stockholders’/ members’ equity
Members’ equity	—			545,395		218,123		(1,709		)	(761,809		)	—
Class A common stock, $0.001 par value; 30,573,509 shares issued and 30,550,907 shares outstanding at December 31, 2015	31			—		—		—			—			31
Class B common stock, $0.001 par value; 31,273,130 shares issued and outstanding at December 31, 2015	31			—		—		—			—			31
Treasury stock, at cost: 22,602 shares at December 31, 2015	(358		)	—		—		—			—			(358		)
Additional paid-in-capital	363,723			—		—		—			—			363,723
Retained earnings (deficit)	36,569			—		—		—			—			36,569
Stockholders’ equity	399,996			545,395		218,123		(1,709		)	(761,809		)	399,996
Non-controlling interest	—			—		—		—			536,856			536,856
Total stockholders’ equity	399,996			545,395		218,123		(1,709		)	(224,953		)	936,852
Total liabilities and stockholders’ equity	$	457,328		$	1,414,298	$	1,682,028	$	725		$	(1,619,225	)	$	1,935,154

Jones Energy, Inc.

Condensed Consolidating Statement of Operations

Year Ended December 31, 2016

							Guarantor			Non-Guarantor
(in thousands of dollars)	JEI (Parent)			Issuers			Subsidiaries			Subsidiaries			Eliminations			Consolidated
Operating revenues
Oil and gas sales	$	—		$	—		$	124,877		$	—		$	—		$	124,877
Other revenues	—			2,384			586			—			—			2,970
Total operating revenues	—			2,384			125,463			—			—			127,847
Operating costs and expenses
Lease operating	—			—			32,640			—			—			32,640
Production and ad valorem taxes	—			—			7,768			—			—			7,768
Exploration	—			—			6,673			—			—			6,673
Depletion, depreciation and amortization	—			—			153,843			87			—			153,930
Accretion of ARO liability	—			—			1,263			—			—			1,263
General and administrative	—			12,028			17,244			368			—			29,640
Other operating	—			—			199			—			—			199
Total operating expenses	—			12,028			219,630			455			—			232,113
Operating income (loss)	—			(9,644		)	(94,167		)	(455		)	—			(104,266		)
Other income (expense)
Interest expense	—			(53,080		)	(47		)	—			—			(53,127		)
Gain on debt extinguishment	—			99,530			—			—			—			99,530
Net gain (loss) on commodity derivatives	—			(51,264		)	—			—			—			(51,264		)
Other income (expense)	784			(321		)	73			—			—			536
Other income (expense), net	784			(5,135		)	26			—			—			(4,325		)
Income (loss) before income tax	784			(14,779		)	(94,141		)	(455		)	—			(108,591		)
Equity interest in income	(66,804		)	—			—			—			66,804			—
Income tax provision (benefit)	(23,468		)	(318		)	—			—			—			(23,786		)
Net income (loss)	(42,552		)	(14,461		)	(94,141		)	(455		)	66,804			(84,805		)
Net income (loss) attributable to non-controlling interests	—			—			—			—			(42,253		)	(42,253		)
Net income (loss) attributable to controlling interests	$	(42,552	)	$	—		$	—		$	—		$	—		$	(42,552	)
Dividends and accretion on preferred stock	(2,669		)	—			—			—			—			(2,669		)
Net income (loss) attributable to common shareholders	$	(45,221	)	$	—		$	—		$	—		$	—		$	(45,221	)

Jones Energy, Inc.

Condensed Consolidating Statement of Operations

Year Ended December 31, 2015

							Guarantor			Non-Guarantor
(in thousands of dollars)	JEI (Parent)			Issuers			Subsidiaries			Subsidiaries			Eliminations			Consolidated
Operating revenues
Oil and gas sales	$	—		$	—		$	194,555		$	—		$	—		$	194,555
Other revenues	—			1,960			884			—			—			2,844
Total operating revenues	—			1,960			195,439			—			—			197,399
Operating costs and expenses
Lease operating	—			—			41,027			—			—			41,027
Production and ad valorem taxes	—			—			12,130			—			—			12,130
Exploration	—			—			6,551			—			—			6,551
Depletion, depreciation and amortization	—			—			205,407			91			—			205,498
Accretion of ARO liability	—			—			1,087			—			—			1,087
General and administrative	—			13,565			19,707			116			—			33,388
Other operating				—			4,188			—						4,188
Total operating expenses	—			13,565			290,097			207			—			303,869
Operating income (loss)	—			(11,605		)	(94,658		)	(207		)	—			(106,470		)
Other income (expense)
Interest expense	—			(63,160		)	(1,298		)	—			—			(64,458		)
Net gain (loss) on commodity derivatives	—			158,753			—			—			—			158,753
Other income (expense)	1,984			(1,663		)	(4		)	—			—			317
Other income (expense), net	1,984			93,930			(1,302		)	—			—			94,612
Income (loss) before income tax	1,984			82,325			(95,960		)	(207		)	—			(11,858		)
Equity interest in income	(4,728		)	—			—			—			4,728			—
Income tax provision (benefit)	(363		)	(2,418		)	—			—			—			(2,781		)
Net income (loss)	(2,381		)	84,743			(95,960		)	(207		)	4,728			(9,077		)
Net income (loss) attributable to non-controlling interests	—			—			—			—			(6,696		)	(6,696		)
Net income (loss) attributable to controlling interests	$	(2,381	)	$	—		$	—		$	—		$	—		$	(2,381	)

Jones Energy, Inc.

Condensed Consolidating Statement of Operations

Year Ended December 31, 2014

						Guarantor			Non-Guarantor
(in thousands of dollars)	JEI (Parent)		Issuers			Subsidiaries			Subsidiaries			Eliminations			Consolidated
Operating revenues
Oil and gas sales	$	—	$	—		$	378,401		$	—		$	—		$	378,401
Other revenues	—		1,154			1,042			—			—			2,196
Total operating revenues	—		1,154			379,443			—			—			380,597
Operating costs and expenses
Lease operating	—		—			37,760			—			—			37,760
Production and ad valorem taxes	—		—			22,556			—			—			22,556
Exploration	—		—			3,453			—			—			3,453
Depletion, depreciation and amortization	—		—			181,578			91			—			181,669
Accretion of ARO liability	—		—			770			—			—			770
General and administrative	—		4,493			21,181			89			—			25,763
Total operating expenses	—		4,493			267,298			180			—			271,971
Operating income (loss)	—		(3,339		)	112,145			(180		)	—			108,626
Other income (expense)
Interest expense	—		(40,365		)	(1,510		)	—			—			(41,875		)
Net gain (loss) on commodity derivatives	—		189,641			—			—			—			189,641
Other income (expense)	—		(4,851		)	297			—			—			(4,554		)
Other income (expense), net	—		144,425			(1,213		)	—			—			143,212
Income (loss) before income tax	—		141,086			110,932			(180		)	—			251,838
Equity interest in income	63,197		—			—			—			(63,197		)	—
Income tax provision (benefit)	22,061		4,157			—			—			—			26,218
Net income (loss)	41,136		136,929			110,932			(180		)	(63,197		)	225,620
Net income (loss) attributable to non-controlling interests	—		—			—			—			184,484			184,484
Net income (loss) attributable to controlling interests	$	41,136	$	—		$	—		$	—		$	—		$	41,136

Jones Energy, Inc.

Condensed Consolidating Statement of Cash Flows

Year Ended December 31, 2016

							Guarantor			Non-Guarantor
(in thousands of dollars)	JEI (Parent)			Issuers			Subsidiaries			Subsidiaries			Eliminations			Consolidated
Cash flows from operating activities
Net income (loss)	$	(42,552	)	$	(14,461	)	$	(94,141	)	$	(455	)	$	66,804		$	(84,805	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities	(105,877		)	(70,695		)	353,426			455			(66,804		)	110,505
Net cash (used in) / provided by operations	(148,429		)	(85,156		)	259,285			—			—			25,700
Cash flows from investing activities
Additions to oil and gas properties	—			—			(264,462		)	—			—			(264,462		)
Proceeds from sales of assets	—			—			1,645			—			—			1,645
Acquisition of other property, plant and equipment	—			—			(310		)	—			—			(310		)
Current period settlements of matured derivative contracts	—			132,265			—			—			—			132,265
Net cash (used in) / provided by investing	—			132,265			(263,127		)	—			—			(130,862		)
Cash flows from financing activities
Proceeds from issuance of long-term debt	—			130,000			—			—			—			130,000
Repayment under long-term debt	—			(62,000		)	—			—			—			(62,000		)
Purchase of senior notes	—			(84,589		)	—			—			—			(84,589		)
Payment of dividends on preferred stock	(1,615		)	—			—			—			—			(1,615		)
Net distributions paid to JEH unitholders	23,674			(40,993		)	—			—			—			(17,319		)
Proceeds from sale of common stock	65,446			—			—			—			—			65,446
Proceeds from sale of preferred stock	87,988			—			—			—			—			87,988
Net cash (used in) / provided by financing	175,493			(57,582		)	—			—			—			117,911
Net increase (decrease) in cash	27,064			(10,473		)	(3,842		)	—			—			12,749
Cash
Beginning of period	100			12,448			9,325			20			—			21,893
End of period	$	27,164		$	1,975		$	5,483		$	20		$	—		$	34,642

Jones Energy, Inc.

Condensed Consolidating Statement of Cash Flows

Year Ended December 31, 2015

							Guarantor			Non-Guarantor
(in thousands of dollars)	JEI (Parent)			Issuers			Subsidiaries			Subsidiaries			Eliminations			Consolidated
Cash flows from operating activities
Net income (loss)	$	(2,381	)	$	84,743		$	(95,960	)	$	(207	)	$	4,728		$	(9,077	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities	(120,398		)	(202,359		)	405,214			197			(4,728		)	77,926
Net cash (used in) / provided by operations	(122,779		)	(117,616		)	309,254			(10		)	—			68,849
Cash flows from investing activities
Additions to oil and gas properties	—			—			(311,305		)	—			—			(311,305		)
Proceeds from sales of assets	—			—			41			—			—			41
Acquisition of other property, plant and equipment	—			—			(1,101		)	—			—			(1,101		)
Current period settlements of matured derivative contracts	—			144,145						—			—			144,145
Net cash (used in) / provided by investing	—			144,145			(312,365		)	—			—			(168,220		)
Cash flows from financing activities
Proceeds from issuance of long-term debt	—			85,000			—			—			—			85,000
Repayment under long-term debt	—			(335,000		)	—			—			—			(335,000		)
Proceeds from senior notes	—			236,475			—			—			—			236,475
Payment of debt issuance costs	—			(1,556		)	—			—			—			(1,556		)
Proceeds from sale of common stock, net of expense	122,779			—			—			—			—			122,779
Net cash (used in) / provided by financing	122,779			(15,081		)	—			—			—			107,698
Net increase (decrease) in cash	—			11,448			(3,111		)	(10		)	—			8,327
Cash																—
Beginning of period	100			1,000			12,436			30			—			13,566
End of period	$	100		$	12,448		$	9,325		$	20		$	—		$	21,893

Jones Energy, Inc.

Condensed Consolidating Statement of Cash Flows

Year Ended December 31, 2014

										Non-
							Guarantor			Guarantor
(in thousands of dollars)	JEI (Parent)			Issuers			Subsidiaries			Subsidiaries			Eliminations			Consolidated
Cash flows from operating activities
Net income (loss)	$	41,136		$	136,929		$	110,932		$	(180	)	$	(63,197	)	$	225,620
Adjustments to reconcile net income (loss) to net cash provided by operating activities	(40,778		)	(326,859		)	343,999			140			63,197			39,699
Net cash (used in) / provided by operations	358			(189,930		)	454,931			(40		)	—			265,319
Cash flows from investing activities
Additions to oil and gas properties	—			—			(474,619		)	—			—			(474,619		)
Net adjustments to purchase price of properties acquired	—			—			15,709			—			—			15,709
Proceeds from sales of assets	—			—			448			—			—			448
Acquisition of other property, plant and equipment	—			—			(1,683		)	—			—			(1,683		)
Current period settlements of matured derivative contracts	—			(3,654		)	—			—			—			(3,654		)
Net cash (used in) / provided by investing	—			(3,654		)	(460,145		)	—			—			(463,799		)
Cash flows from financing activities
Proceeds from issuance of long-term debt	—			170,000			—			—			—			170,000
Repayment under long-term debt	—			(468,000		)	—			—			—			(468,000		)
Proceeds from senior notes	—			500,000			—			—			—			500,000
Payment of debt issuance costs	—			(13,416		)	—			—			—			(13,416		)
Purchases of treasury stock	(358		)	—			—			—			—			(358		)
Net cash (used in) / provided by financing	(358		)	188,584			—			—			—			188,226
Net increase (decrease) in cash	—			(5,000		)	(5,214		)	(40		)	—			(10,254		)
Cash
Beginning of period	100			6,000			17,650			70			—			23,820
End of period	$	100		$	1,000		$	12,436		$	30		$	—		$	13,566

Jones Energy, Inc.

Supplemental Information on Oil and Gas Producing Activities (Unaudited)

Geographic Area of Operation

All of our proved reserves are located in the mid-continent United States, spanning areas of Texas and Oklahoma.  Therefore, the following disclosures about our costs incurred, results of operations and proved reserves are on a total-company basis.

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)	2016		2015		2014
Property acquisitions:
Unproved	$	137,844	$	4,036	$	20,030
Proved	51,388		—		10,101
Exploration	412		6,551		3,453
Development	79,617		202,342		488,076
Total costs incurred (1)	$	269,261	$	212,929	$	521,660

(1)Excludes the impact of asset retirement costs.

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 of dollars)	2016			2015
Unproved properties	$	213,153		$	75,308
Proved properties	2,449,974			2,320,992
	2,663,127			2,396,300
Accumulated depletion and impairment	(919,539		)	(760,534		)
Net capitalized costs	$	1,743,588		$	1,635,766

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, 2016, 2015, and 2014. 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 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		NGL		Natural Gas		Total
	(MBbls)		(MBbls)		(MMcf)		(MBoe)(1)
Estimated Proved Reserves
December 31, 2013	16,688		32,915		236,648		89,045
Extensions and discoveries	9,295		8,675		59,248		27,844
Production	(2,475	)	(2,345	)	(21,922	)	(8,474	)
Purchases of minerals in place	3,180		3,073		22,943		10,077
Sales of minerals in place	—		—		—		—
Revisions of previous estimates	995		(3,448	)	(4,640	)	(3,226	)
December 31, 2014	27,683		38,870		292,277		115,266
Extensions and discoveries	1,793		1,691		11,793		5,450
Production	(2,582	)	(2,618	)	(23,839	)	(9,174	)
Purchases of minerals in place	—		—		—		—
Sales of minerals in place	—		—		—		—
Revisions of previous estimates	(1,486	)	(5,294	)	(18,635	)	(9,885	)
December 31, 2015	25,408		32,649		261,596		101,657
Extensions and discoveries	774		750		4,767		2,319
Production	(1,690	)	(2,210	)	(18,878	)	(7,046	)
Purchases of minerals in place	2,326		3,829		42,713		13,275
Sales of minerals in place	(37	)	—		(1	)	(37	)
Revisions of previous estimates	(3,187	)	(593	)	(7,057	)	(4,959	)
December 31, 2016	23,594		34,425		283,140		105,209

(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.

For the year ended December 31, 2016, the Company added 2,319 MBoe through extensions, which represent the conversion of unproved reserves to proved reserves as a result of our drilling activity during the year. There were no discoveries of proved reserves. The Company’s estimated proved reserves were reduced by current year production of 7,046 MBoe. The Company added 13,275 MBoe through the purchases of minerals in place. Purchases were primarily related to leasing and the asset purchases in the Western Anadarko basin. The Company also had sales of minerals in place of 37 MBoe during the year ended December 31, 2016.

For the year ended December 31, 2016, the Company had net negative revisions of 4,959 MBoe, of which 1,685 MBoe was related to commodity pricing and 4,155 MBoe was related to proved undeveloped reserves revisions. The remaining net positive revisions of 881 MBoe were primarily related to changes in working interest, cost reductions, and production performance enhancements.

For the year ended December 31, 2015, the Company added 5,450 MBoe through extensions, which represent the conversion of unproved reserves to proved reserves as a result of our drilling activity during the year. There were no discoveries of proved reserves. The Company’s estimated proved reserves were reduced by current year production of 9,174 MBoe. No purchases or sales of minerals in place occurred during the year ended December 31, 2015.

For the year ended December 31, 2015, the Company had net negative revisions of 9,885 MBoe, of which 56,330 MBoe was related to commodity pricing. The remaining net positive revisions of 46,445 MBoe were primarily related to reduced future development costs and production performance improvements.

For the year ended December 31, 2014, the Company added 27,844 MBoe through extensions, which represent the conversion of unproved reserves to proved reserves as a result of our continued drilling activity throughout the year. There were no discoveries of proved reserves. The Company’s estimated proved reserves were reduced by current year production of 8,474 MBoe. The Company added 10,077 MBoe through the purchases of minerals in place. Purchases were primarily related to leasing in the Western Anadarko basin with associated Cleveland proved reserves. No sales of minerals in place occurred during the year ended December 31, 2014.

For the year ended December 31, 2014, the Company had net negative revisions of 3,226 MBoe, of which 3,534 MBoe was related to production performance in the Arkoma Woodford basin. The remaining net positive revisions of 308 MBoe were primarily related to production performance in the Cleveland basin and other changes.

	Crude Oil	NGL	Natural Gas	Total
	(MBbls)	(MBbls)	(MMcf)	(MBoe)(1)
Estimated Proved Reserves
December 31, 2014
Proved developed	10,773	22,555	160,877	60,141
Proved undeveloped	16,910	16,315	131,400	55,125
Total proved reserves	27,683	38,870	292,277	115,266
December 31, 2015
Proved developed	11,032	19,670	169,651	58,977
Proved undeveloped	14,376	12,980	91,945	42,680
Total proved reserves	25,408	32,650	261,596	101,657
December 31, 2016
Proved developed	11,471	20,941	180,293	62,461
Proved undeveloped	12,123	13,484	102,847	42,748
Total proved reserves	23,594	34,425	283,140	105,209

(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, 2016, 2015, and 2014. 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.

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 of dollars)	2016			2015			2014
Future cash inflows	$	2,158,067		$	2,373,971		$	5,038,212
Less related future:
Production costs	(798,161		)	(821,773		)	(1,216,184		)
Development costs	(451,790		)	(483,060		)	(939,652		)
Income tax expenses	(46,139		)	(31,537		)	(199,727		)
Future net cash flows	861,977			1,037,601			2,682,649
10% annual discount for estimated timing of cash flows	(478,498		)	(572,821		)	(1,294,553		)
Standardized measure of discounted future net cash flows	$	383,479		$	464,780		$	1,388,096

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 of dollars)	2016			2015			2014
Balance, beginning of period	$	464,780		$	1,388,096		$	940,509
Net change in sales and transfer prices, net of production expenses	(90,932		)	(1,063,248		)	98,647
Changes in estimated future development costs	32,678			96,408			(96,245		)
Sales and transfers of oil and gas produced during the period	(94,262		)	(176,301		)	(382,202		)
Net change due to extensions and discoveries	24			6,236			442,340
Net change due to purchases of minerals in place	18,473			—			118,562
Net change due to sales of minerals in place	(1,202		)	—			—
Net change due to revisions in quantity estimates	(51,237		)	(153,689		)	43,032
Previously estimated development costs incurred during the period	73,735			143,560			163,739
Net change in income taxes	(12,824		)	108,409			(36,514		)
Accretion of discount	37,475			120,047			94,051
Other	6,771			(4,738		)	2,177
Balance, end of period	$	383,479		$	464,780		$	1,388,096

Supplemental Quarterly Financial Information (Unaudited)

Following is a summary of the Company’s results of operations by quarter for the years ended December 31, 2016, 2015, and 2014.

	2016
	First			Second			Third			Fourth			Full
(in thousands except per share data)	Quarter			Quarter			Quarter			Quarter			Year
Revenues	$	25,858		$	29,144		$	33,353		$	39,492		$	127,847
Operating income (loss)	(34,081		)	(26,765		)	(20,564		)	(22,856		)	(104,266		)
Net income (loss)	48,514			(58,646		)	(22,429		)	(52,244		)	(84,805		)
Net income (loss) attributable to non-controlling interests	29,603			(35,401		)	(12,576		)	(23,879		)	(42,253		)
Net income (loss) attributable to controlling interests	18,911			(23,245		)	(9,853		)	(28,365		)	(42,552		)
Basic earnings per share	$	0.57		$	(0.69	)	$	(0.24	)	$	(0.49	)	$	(1.04	)
Diluted earnings per share	$	0.57		$	(0.69	)	$	(0.24	)	$	(0.49	)	$	(1.04	)

	2015
	First			Second			Third			Fourth			Full
(in thousands except per share data)	Quarter			Quarter			Quarter			Quarter			Year
Revenues	$	58,096		$	53,917		$	47,152		$	38,234		$	197,399
Operating income	(21,838		)	(23,531		)	(32,393		)	(28,708		)	(106,470		)
Net income (loss)	5,696			(51,180		)	34,842			1,565			(9,077		)
Net income (loss) attributable to non-controlling interests	3,508			(32,737		)	21,604			929			(6,696		)
Net income (loss) attributable to controlling interests	2,188			(18,443		)	13,238			636			(2,381		)
Basic earnings per share	$	0.11		$	(0.61	)	$	0.40		$	0.02		$	(0.08	)
Diluted earnings per share	$	0.11		$	(0.61	)	$	0.40		$	0.02		$	(0.08	)

	2014
	First		Second			Third		Fourth		Full
(in thousands except per share data)	Quarter		Quarter			Quarter		Quarter		Year
Revenues	$	98,244	$	106,390		$	100,346	$	75,617	$	380,597
Operating income	34,017		36,114			26,231		12,264		108,626
Net income (loss)	7,708		(11,454		)	50,025		179,341		225,620
Net income (loss) attributable to non-controlling interests	6,339		(9,397		)	40,893		146,649		184,484
Net loss attributable to controlling interests	1,369		(2,057		)	9,132		32,692		41,136
Basic earnings (loss) per share	$	0.10	$	(0.15	)	$	0.67	$	2.39	$	3.02
Diluted earnings (loss) per share	$	0.10	$	(0.15	)	$	0.67	$	2.39	$	3.02