AUSTIN, Texas--(BUSINESS WIRE)-- Jones Energy, Inc. (NYSE: JONE) (“Jones Energy” or “the Company”) today announced financial and operating results for the quarter ended June 30, 2015. For the quarter ended June 30, 2015, the Company reported a net loss of $51.2 million, an adjusted net loss of $0.2 million, and EBITDAX of $64.0 million.

2015 Second Quarter Highlights

• Liquidity of more than $485 million as of June 30, 2015
• Mark-to-market hedge value of approximately $220 million as of late July with estimated oil and gas volumes over 85% hedged through 2016; natural gas liquids (“NGLs”) estimated volumes hedged roughly 80% in the second half of 2015 and nearly 55% in 2016 ¹
• Average daily net production for the quarter was 25.3 MBoe/d, above the top end of guidance
• Raising full-year 2015 production guidance to 23.0 - 24.5 MBoe/d
• Initiated 2015 leasing program
• Deployed two additional rigs in the Cleveland after achieving greater than 30% cost savings since December 2014; currently running five Cleveland rigs with $2.6 million AFE
• Spud 33 of the thirty-three stage open-hole wells as of August 4, 2015, 25 of which have been completed and placed on production
• Results from 33 stage open-hole wells tracking uplift in oil production

Jonny Jones, the Company’s Founder, Chairman and CEO, stated, “At the beginning of 2015, we set the goals of protecting our balance sheet and executing a focused capital development plan. We took care of the balance sheet and our liquidity needs in the first quarter while beginning our cost reduction efforts. During the second quarter, we continued to drive down costs which allowed for the addition of two rigs at mid-year as previously planned. Individual well cost during the second quarter reached our target AFE of $2.6 million ahead of schedule. As a result, we have maintained a high level of liquidity, a strong production profile and are on track with our capital expenditure expectations through the first half of the year. As the year has progressed, we have achieved higher rig utilization by acquiring additional working interest, allowing for location capture at minimal cost. As a result of the working interest capture and production outperformance, we have increased guidance for this year. We are now beginning to test the leasing market which we believe may provide attractive opportunities for additional growth. As previously discussed, we are continuing to evaluate joint ventures and asset acquisitions as recent market activity seems to indicate that more high quality opportunities are making their way into the market. We have remained busy during the quarter reviewing and high grading what we believe could be the most accretive and beneficial paths to increasing shareholder value.”

Mr. Jones went on to say, “Recent commodity price movements reflect the ‘lower for longer’ potential which was a significant factor in our decision to take advantage of the capital markets during the first quarter of the year. Reducing our overall leverage while simultaneously moving the majority of the balance of our credit facility to term debt has provided us with a significant increase in financial flexibility should the lower price environment persist. Should commodity prices deteriorate to the point where acceptable margins are unattainable, we will revisit our capital allocation decisions. Our goal is always to create the best possible return for our shareholders. We are poised to move in whichever direction necessary to protect our stakeholders’ interests while capitalizing on opportunities. We have executed as promised during the first half of the year and are excited about our prospects for the remainder of 2015.”

¹ Hedging percentages are based upon current 2015 full year guidance and modeled flat production in 2016 based upon 2015 fourth quarter production exit rates.

Financial Results

Total operating revenues for the three months ended June 30, 2015 were $53.9 million as compared to $106.4 million for the three months ended June 30, 2014. The decrease was due to lower commodity prices, which was somewhat offset by higher production.

Total operating expenses for the three months ended June 30, 2015 were $77.4 million as compared to $70.3 million for the three months ended June 30, 2014. The increase was primarily due to increased production which resulted in higher lease operating and depletion, depreciation, and amortization expenses (“DD&A”). The Company also incurred certain non-recurring charges which were included in other operating expenses.

For the three months ended June 30, 2015, the Company reported an adjusted net loss of $0.2 million as compared to adjusted net income of $18.2 million for the three months ended June 30, 2014. The decrease was primarily due to lower average realized prices for all commodities and a slight increase in overall operating expenses, which was primarily related to higher DD&A expenses resulting from higher production volumes.

Operational Results

Cleveland

The Company’s second quarter development activity was focused exclusively on the Cleveland. During the second quarter, the Company spud 15 wells and completed 14 wells, with a total of 11 wells seeing first production during the quarter. As of June 30, 2015, six wells were in various stages of completion, and the Company had four rigs running. The Company added its fifth rig in early July. As of August 4, 2015, the Company had completed nine additional wells since the end of the second quarter.

Daily net production in the Cleveland was 18.0 MBoe/d in the second quarter of 2015, down 5% from the first quarter of 2015 and up 7% from the second quarter of 2014. To date, the Company has spud 33 of the thirty-three stage open-hole wells, 25 of which have been completed and placed on production. Production results for the 33 stage wells continue to reflect the uplifted oil production expectations which were observed during the Company’s completion optimization work in 2014.

The Company’s target well cost of $2.6 million was achieved during the second quarter, approximately two months ahead of expectations. Drilling efficiencies and cost reductions have persisted as rigs have been added over recent months.

Capital Expenditures

During the second quarter of 2015, the Company spent $45.5 million, of which $40.5 million was related to drilling and completing wells, representing 89% of total capital expenditures in the quarter. Quarterly spending continues to reflect budgeted expectations with minimal increases arising from non-operating interest owners electing not to participate in the drilling of wells. The Company had anticipated the potential for working interest capture in its 2015 budget as the initial budget projected an average working interest for wells to be drilled of approximately 80%, which was higher than the Company’s average working interest of 70% owned as of the Company’s 2014 year-end reserve report. Through the first six months of 2015, the actual average working interest of the wells spud was 92%. Based upon the current rate of additional working interest capture, the Company is updating its estimated average working interest per well for 2015 to 90% to 95% versus the previously budgeted 80%.

Through this year’s forecasted average working interest capture of 20% to 25% per drilled well, the Company expects to add the equivalent of between 15 and 18 net locations to its producing well count with minimal cost. This working interest increase achieves the goal of higher rig utilization and net location capture through continued drilling activity.

Specific to the second half of 2015, the Company is increasing the estimated average working interest per well from the budgeted 80% to between 90% and 95%. This is expected to result in average incremental capital per rig line of approximately $3 million during the second half of 2015, or an increase in total drilling and completion expenditures of approximately $15 million. The Company also has allocated additional capital for leasing during the third and fourth quarter, which together with working interest capture, results in total expected capital expenditures for the full year of approximately $240 million.

2015 Capital Expenditure Summary ($mm)
			1Q15				2Q15				YTD 2015
Drilling and Completion			$	76.1			$	40.5			$	116.6
Maintenance and Other				6.5				5.0				11.5
Total Capital Expenditures			$	82.6			$	45.5			$	128.1

Liquidity and Hedging

As of June 30, 2015, the Company had undrawn credit facility availability of $462.5 million and approximately $23 million in cash.

The Company continued to add hedges during the second quarter of 2015, with the mark-to-market value of its hedge book exceeding $220 million as of late July. The Company has hedged over 85% of its estimated oil and natural gas production through 2016 at an average price just below $85 per barrel and $4.50 per Mcf. The Company’s estimated natural gas liquids production for the third and fourth quarter of 2015 is approximately 80% hedged at an average per barrel price above $31.50 and is nearly 55% hedged for 2016.² The Company also has oil and natural gas hedges in place for 2017, 2018, and the first half of 2019, although at less significant levels. Over 100% of the Company’s existing oil and natural gas production, or PDP, is hedged through the first half of 2019. A table providing the latest summary hedge positions is shown below.

² Hedging percentages are based upon current 2015 full year guidance and modeled flat production in 2016 based upon 2015 fourth quarter production exit rates.

			Fiscal Year Ending December 31,
			2H151				2016				2017				2018				1H192
Oil, Natural Gas and NGL Swaps
Oil (MBbl)				1,165				1,897				1,040				803				339
Natural Gas (MMcf)				9,556				16,850				12,300				10,240				3,060
Ethane (MBbl)				193				53				-				-				-
Propane (MBbl)				378				627				-				-				-
Iso Butane (MBbl)				45				76				7				-				-
Butane (MBbl)				134				218				17				-				-
Natural Gasoline (MBbl)				135				227				18				-				-
Total NGLs (MBbl)				885				1,201				42				-				-
Weighted Average Prices
Oil ($ / Bbl)			$	84.11			$	82.74			$	78.69			$	77.47			$	64.65
Natural Gas ($ / Mcf)			$	4.42			$	4.44			$	4.29			$	4.19			$	3.62
Ethane ($ / Gal)			$	0.27			$	0.21				-				-				-
Propane ($ / Gal)			$	0.88			$	0.55				-				-				-
Iso Butane ($ / Gal)			$	0.97			$	0.75			$	1.42				-				-
Butane ($ / Gal)			$	0.95			$	0.72			$	1.37				-				-
Natural Gasoline ($ / Gal)			$	1.81			$	1.46			$	1.73				-				-
1 2015 hedges shown for the remaining two quarters of the year.
2 2019 hedges apply to the first and second quarters of the year.

Guidance

The Company is providing guidance for the third quarter and increasing production and capital expenditure guidance for the full year 2015 as follows:

2015 Guidance
			Revised
			2015E			3Q15E
Total Production (MMBoe)			8.4 - 8.9			2.0 - 2.1
Average Daily Production (MBoe/d)			23.0 - 24.5			22.0 - 23.0
Oil (MBbls/d)			6.8 - 7.3			6.3 - 6.6
Natural Gas (MMcf/d)			58.5 - 62.5			56.5 - 59.0
NGLs (MBbls/d)			6.4 - 6.8			6.3 - 6.6
Lease Operating Expense ($/Boe)			$4.75 - $5.25
Production/Ad Valorem Taxes (% of Unhedged Revenue)			6.5% - 7.5%
Cash G&A Expense ($mm)			$25.0 - $28.0
Total Capital Expenditures ($mm)			$240.0

Conference Call Details

Jones Energy will host a conference call for investors and analysts to discuss its results for the second quarter on Thursday, August 6, 2015 at 10:30 a.m. ET (9:30 a.m. CT). The conference call can be accessed via webcast through the Investor Relations section of Jones Energy’s website, www.jonesenergy.com, or by dialing (877) 201-0168 (for domestic U.S.) or (647) 788-4901 (International) and entering conference code 77863314. If you are not able to participate in the conference call, an audio replay will be available through August 13, 2015, by dialing (855) 859-2056 (for domestic U.S.) or (404) 537-3406 (International) and entering conference code 77863314. A replay of the conference call may also be found on the Company’s website, www.jonesenergy.com.

About Jones Energy

Jones Energy, Inc. is an independent oil and natural gas company engaged in the development and acquisition of oil and natural gas properties in the Anadarko and Arkoma basins of Texas and Oklahoma. Additional information about Jones Energy may be found on the Company’s website at: www.jonesenergy.com.

Forward-Looking Statements

This press release contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements, other than statements of historical facts, included in this press release that address activities, events or developments that the Company expects, believes or anticipates will or may occur in the future are forward-looking statements. Without limiting the generality of the foregoing, forward-looking statements contained in this press release specifically include the expectations of plans, strategies, objectives and anticipated financial and operating results of the Company, including guidance regarding the timing and location of our anticipated drilling and completion activity, our ability to take advantage of additional working interest capture, our ability to increase capital spending in connection with leasing and additional working interest capture, results of our 33 stage open-hole completion technique in the Cleveland formation including projected uplifts in oil production, expectations for the leasing, joint venture, and asset acquisition markets, our ability to mitigate commodity price risk through our hedging program, and our ability to successfully execute our 2015 development plan and guidance for the third quarter and full year 2015. These statements are based on certain assumptions made by the Company based on management's experience and perception of historical trends, current conditions, anticipated future developments and other factors believed to be appropriate. Such statements are subject to a number of assumptions, risks and uncertainties, many of which are beyond the control of the Company, which may cause actual results to differ materially from those implied or expressed by the forward-looking statements. These include, but are not limited to, changes in oil, natural gas liquids, and natural gas prices, weather and environmental conditions, the timing of planned capital expenditures, availability of acquisitions, uncertainties in estimating proved reserves and forecasting production results, operational factors affecting the commencement or maintenance of producing wells, customers’ elections to reject ethane and include it as part of the natural gas stream for the remainder of 2015, the proximity to and capacity of transportation facilities, and uncertainties regarding environmental regulations or litigation and other legal or regulatory developments affecting the Company’s business and other important factors that could cause actual results to differ materially from those projected as described in the Company’s reports filed with the SEC.

Any forward-looking statement speaks only as of the date on which such statement is made and the Company undertakes no obligation to correct or update any forward-looking statement, whether as a result of new information, future events or otherwise, except as required by applicable law.

Jones Energy, Inc.
Consolidated Statements of Operations (Unaudited)
			Three Months Ended June 30,											Six Months Ended June 30,
(in thousands of dollars except per share data)			2015					(Restated) 2014						2015					(Restated) 2014
Operating revenues
Oil and gas sales			$	53,222				$	105,796					$	110,456				$	203,663
Other revenues				695					594						1,557					971
Total operating revenues				53,917					106,390						112,013					204,634
Operating costs and expenses
Lease operating				11,796					10,779						24,058					19,123
Production and ad valorem taxes				3,071					6,772						6,779					13,204
Exploration				464					191						628					3,012
Depletion, depreciation and amortization				51,302					45,799						103,385					86,999
Accretion of ARO liability				206					197						400					367
General and administrative				9,433					6,538						17,944					11,798
Other operating				1,176					—						4,188					—
Total operating expenses				77,448					70,276						157,382					134,503
Operating income (loss)				(23,531	)				36,114						(45,369	)				70,131
Other income (expense)
Interest expense				(16,702	)				(14,767	)					(30,831	)				(22,810	)
Net gain (loss) on commodity derivatives				(25,075	)				(33,698	)					21,231					(50,948	)
Other income (expense)				675					2						(1,624	)				67
Other income (expense), net				(41,102	)				(48,463	)					(11,224	)				(73,691	)
Income (loss) before income tax				(64,633	)				(12,349	)					(56,593	)				(3,560	)
Income tax provision (benefit)				(13,453	)				(895	)					(11,109	)				186
Net income (loss)				(51,180	)				(11,454	)					(45,484	)				(3,746	)
Net income (loss) attributable to non-controlling interests				(32,737	)				(9,397	)					(29,229	)				(3,058	)
Net income (loss) attributable to controlling interests			$	(18,443	)			$	(2,057	)				$	(16,255	)			$	(688	)
Earnings (loss) per share:
Basic			$	(0.66	)			$	(0.16	)				$	(0.70	)			$	(0.05	)
Diluted			$	(0.66	)			$	(0.16	)				$	(0.70	)			$	(0.05	)
Weighted average shares outstanding:
Basic				27,904					12,500						23,131					12,500
Diluted				27,904					12,500						23,131					12,500

Jones Energy, Inc.
Consolidated Balance Sheets (Unaudited)
			June 30,					December 31,
(in thousands of dollars)			2015					2014
Assets
Current assets
Cash			$	22,875				$	13,566
Restricted cash				272					149
Accounts receivable, net
Oil and gas sales				31,025					51,482
Joint interest owners				16,413					41,761
Other				10,681					12,512
Commodity derivative assets				90,448					121,519
Other current assets				2,227					3,374
Total current assets				173,941					244,363
Oil and gas properties, net, at cost under the successful efforts method				1,665,153					1,638,860
Other property, plant and equipment, net				3,827					4,048
Commodity derivative assets				70,979					87,055
Other assets				20,001					20,352
Deferred tax assets				2,554					171
Total assets			$	1,936,455				$	1,994,849
Liabilities and Stockholders’ Equity
Current liabilities
Trade accounts payable			$	41,999				$	136,337
Oil and gas sales payable				47,251					70,469
Accrued liabilities				29,027					19,401
Deferred tax liabilities				434					718
Asset retirement obligations				3,246					3,074
Total current liabilities				121,957					229,999
Long-term debt				100,000					360,000
Senior notes				737,066					500,000
Deferred revenue				12,349					13,377
Commodity derivative liabilities				370					28
Asset retirement obligations				11,706					10,536
Liability under tax receivable agreement				39,873					803
Deferred tax liabilities				16,179					26,756
Total liabilities				1,039,500					1,141,499
Commitments and contingencies
Stockholders’ equity
Class A common stock, $0.001 par value; 30,458,790 shares issued and 30,436,188 shares outstanding at June 30, 2015 and 12,672,260 shares issued and 12,649,658 shares outstanding at December 31, 2014				31					13
Class B common stock, $0.001 par value; 31,288,715 shares issued and outstanding at June 30, 2015 and 36,719,499 shares issued and outstanding at December 31, 2014				31					37
Treasury stock, at cost: 22,602 shares at June 30, 2015 and December 31, 2014				(358	)				(358	)
Additional paid-in-capital				362,072					178,763
Retained earnings				22,695					38,950
Stockholders’ equity				384,471					217,405
Non-controlling interest				512,484					635,945
Total stockholders’ equity				896,955					853,350
Total liabilities and stockholders’ equity			$	1,936,455				$	1,994,849

Jones Energy, Inc.
Consolidated Statements of Cash Flows (Unaudited)
			Six Months Ended June 30,
(in thousands of dollars)			2015					(Restated) 2014
Cash flows from operating activities
Net income (loss)			$	(45,484	)			$	(3,746	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities
Depletion, depreciation, and amortization				103,385					86,999
Accretion of ARO liability				400					367
Amortization of debt issuance costs				2,159					5,282
Stock compensation expense				3,248					1,386
Other non-cash compensation expense				218					253
Amortization of deferred revenue				(1,028	)				(526	)
(Gain) loss on commodity derivatives				(21,231	)				50,948
(Gain) loss on sales of assets				6					(67	)
Deferred income tax provision				(11,109	)				(355	)
Other - net				760					3,023
Changes in assets and liabilities
Accounts receivable				47,947					(13,365	)
Other assets				1,118					(85	)
Accrued interest expense				8,368					7,612
Accounts payable and accrued liabilities				(15,713	)				17,581
Net cash provided by operations				73,044					155,307
Cash flows from investing activities
Additions to oil and gas properties				(229,060	)				(229,582	)
Net adjustments to purchase price of properties acquired				—					13,681
Proceeds from sales of assets				21					67
Acquisition of other property, plant and equipment				(382	)				(639	)
Current period settlements of matured derivative contracts				67,646					(11,255	)
Change in restricted cash				(123	)				(52	)
Net cash used in investing				(161,898	)				(227,780	)
Cash flows from financing activities
Proceeds from issuance of long-term debt				75,000					60,000
Repayment under long-term debt				(335,000	)				(468,000	)
Proceeds from senior notes				236,475					500,000
Purchases of treasury stock				—					(352	)
Payment of debt issuance costs				(1,513	)				(11,204	)
Proceeds from sale of common stock				123,201					—
Net cash provided by financing				98,163					80,444
Net increase in cash				9,309					7,971
Cash
Beginning of period				13,566					23,820
End of period			$	22,875				$	31,791
Supplemental disclosure of cash flow information
Cash paid for interest			$	19,517				$	9,348
Change in accrued additions to oil and gas properties				(100,927	)				7,218
Current additions to ARO				931					844

Jones Energy, Inc.
Selected Financial and Operating Statistics

The following table sets forth summary data regarding production volumes, average prices and average production costs associated with our sale of oil and natural gas for the periods indicated:

			Three Months Ended June 30,														Six Months Ended June 30,
			2015				2014				Change						2015				2014				Change
Net production volumes:
Oil (MBbls)				644				655				(11	)					1,400				1,230				170
Natural gas (MMcf)				6,138				5,550				588						12,103				10,559				1,544
NGLs (MBbls)				637				566				71						1,264				1,089				175
Total (MBoe)				2,304				2,146				158						4,681				4,079				602
Average net (Boe/d)				25,319				23,582				1,737						25,862				22,536				3,326
Average sales price, unhedged:
Oil (per Bbl), unhedged			$	51.73			$	98.51			$	(46.78	)				$	47.62			$	96.30			$	(48.68	)
Natural gas (per Mcf), unhedged				1.73				4.20				(2.47	)					2.07				4.23				(2.16	)
NGLs (per Bbl), unhedged				14.62				31.76				(17.14	)					14.78				37.22				(22.44	)
Combined (per Boe), unhedged				23.10				49.30				(26.20	)					23.60				49.93				(26.33	)
Average sales price, hedged:
Oil (per Bbl), hedged			$	75.59			$	89.97			$	(14.38	)				$	73.64			$	88.85			$	(15.21	)
Natural gas (per Mcf), hedged				3.20				4.31				(1.11	)					3.44				4.19				(0.75	)
NGLs (per Bbl), hedged				27.09				29.99				(2.90	)					27.25				34.20				(6.95	)
Combined (per Boe), hedged				37.14				46.51				(9.37	)					38.28				46.77				(8.49	)
Average costs (per Boe):
Lease operating			$	5.12			$	5.02			$	0.10					$	5.14			$	4.69			$	0.45
Production and ad valorem taxes				1.33				3.16				(1.83	)					1.45				3.24				(1.79	)
Depletion, depreciation and amortization				22.27				21.34				0.93						22.09				21.33				0.76
General and administrative				4.09				3.05				1.04						3.83				2.89				0.94

Jones Energy, Inc.
Non-GAAP Financial Measures and Reconciliations

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

We define EBITDAX as earnings before interest expense, income taxes, depreciation, depletion and amortization, exploration expense, gains and losses from derivatives less the current period settlements of matured derivative contracts and the other items described below, however, we may modify our definition of EBITDAX in the future. EBITDAX is not a measure of net income as determined by United States generally accepted accounting principles, or GAAP. Management believes EBITDAX is useful because it allows them to more effectively evaluate our operating performance and compare the results of our operations from period to period and against our peers without regard to financing methods or capital structure. We exclude the items listed above from net income in arriving at EBITDAX because these amounts can vary substantially from company to company within our industry depending upon accounting methods and book values of assets, capital structures and the method by which the assets were acquired. EBITDAX has limitations as an analytical tool and should not be considered as an alternative to, or more meaningful than, net income as determined in accordance with GAAP or as an indicator of our liquidity. Certain items excluded from EBITDAX are significant components in understanding and assessing a company’s financial performance, such as a company’s cost of capital and tax structure, as well as the historical costs of depreciable assets. Our presentation of EBITDAX should not be construed as an inference that our results will be unaffected by unusual or non-recurring items. Our computations of EBITDAX may not be comparable to other similarly titled measures of other companies.

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

			Three Months Ended June 30,											Six Months Ended June 30,
(in thousands of dollars)			2015					2014						2015					2014
Reconciliation of EBITDAX to net income
Net income (loss)			$	(51,180	)			$	(11,454	)				$	(45,484	)			$	(3,746	)
Interest expense				15,902					10,184						29,263					17,528
Exploration expense				-					191						-					3,012
Income taxes				(13,453	)				(895	)					(11,109	)				186
Amortization of deferred financing costs				800					822						1,568					1,521
Depreciation and depletion				51,302					45,799						103,385					86,999
Accretion of ARO liability				206					197						400					367
Other non-cash charges (benefits)				353					(26	)					760					40
Stock compensation expense				1,824					928						3,248					1,386
Other non-cash compensation expense				109					127						218					253
Net (gain) loss on commodity derivatives				25,075					33,698						(21,231	)				50,948
Current period settlements of matured derivative contracts				32,344					(5,985	)					68,719					(12,895	)
Amortization of deferred revenue				(503	)				(282	)					(1,028	)				(526	)
(Gain) loss on sale of assets				(20	)				(1	)					6					(67	)
Stand-by rig costs				1,176					-						4,188					-
Financing expenses and other loan fees				28					3,761						2,301					3,761
EBITDAX			$	63,963				$	77,064					$	135,204				$	148,767

Jones Energy, Inc.
Non-GAAP Financial Measures and Reconciliations

Adjusted Net Income is a supplemental non-GAAP financial measure that is used by management and external users of the Company’s consolidated financial statements. We define Adjusted Net Income as net income excluding the impact of certain non-cash items - including gains or losses on commodity derivative instruments not yet settled, impairment of oil and gas properties, and non-cash compensation expense - and certain unusual or non-recurring items. We believe adjusted net income is useful to investors because it provides readers with a more meaningful measure of our profitability before recording certain items for which the timing or amount cannot be reasonably determined. However, this measure is provided in addition to, not as an alternative for, and should be read in conjunction with, the information contained in our financial statements prepared in accordance with GAAP. Our computations of adjusted net income may not be comparable to other similarly titled measures of other companies. The following tables provide a reconciliation of net income (loss) as determined in accordance with GAAP to adjusted net income for the periods indicated:

			Three Months Ended June 30,											Six Months Ended June 30,
(in thousands of dollars, except per share data)			2015					2014						2015					2014
Net income (loss)			$	(51,180	)			$	(11,454	)				$	(45,484	)			$	(3,746	)
Net (gain) loss on commodity derivatives				25,075					33,698						(21,231	)				50,948
Current period settlements of matured derivative contracts				32,344					(5,985	)					68,719					(12,895	)
Non-cash stock compensation expense				1,824					928						3,248					1,386
Other non-cash compensation expense				109					127						218					253
Stand-by rig costs				1,176					-						4,188					-
Financing expenses				-					3,761						2,250					3,761
Tax impact(1)				(9,517	)				(2,888	)					(9,177	)				(3,908	)
Adjusted net income (loss)				(169	)				18,187						2,731					35,799
Adjusted net income (loss) attributable to non-controlling interests				645					14,867						2,030					29,308
Adjusted net income (loss) attributable to controlling interests			$	(814	)			$	3,320					$	701				$	6,491
			Three Months Ended June 30,											Six Months Ended June 30,
			2015					2014						2015					2014
Earnings (loss) per share (basic and diluted)			$	(0.66	)			$	(0.16	)				$	(0.70	)			$	(0.05	)
Net (gain) loss on commodity derivatives				0.41					0.68						(0.16	)				1.03
Current period settlements of matured derivative contracts				0.52					(0.12	)					1.15					(0.26	)
Non-cash stock compensation expense				0.03					0.02						0.06					0.03
Other non-cash compensation expense				-					-						-					0.01
Stand-by rig costs				0.02					-						0.05					-
Financing expenses				-					0.08						0.04					0.08
Tax impact(1)				(0.35	)				(0.23	)					(0.41	)				(0.31	)
Adjusted earnings (loss) per share (basic and diluted)			$	(0.03	)			$	0.27					$	0.03				$	0.53
Effective tax rate on net income (loss) attributable to controlling interests				37.0	%				36.4	%					37.0	%				36.4	%

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

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Source: Jones Energy, Inc.