Exhibit

EX-99.1 2 a3q15991pressrelease.htm PRESS RELEASE Exhibit



News	UNIT CORPORATION
	7130 South Lewis Avenue, Suite 1000, Tulsa, Oklahoma 74136
	Telephone 918 493-7700, Fax 918 493-7714



Contact:	Michael D. Earl
	Vice President, Investor Relations
	(918) 493-7700
	www.unitcorp.com

For Immediate Release…

November 3, 2015

UNIT CORPORATION REPORTS 2015 THIRD QUARTER RESULTS

Tulsa, Oklahoma . . . Unit Corporation (NYSE - UNT) today reported its financial and operational results for the third quarter of 2015. Highlights for the quarter include:


•	Total production of 5.1 million barrels of oil equivalent (MMBoe), a 10% increase over the third quarter of 2014


•	Oil and natural gas liquids (NGLs) production increased 5% over the third quarter of 2014


•	Gas gathered and gas processed volumes per day increased 12% and 10%, respectively, over the third quarter of 2014

THIRD QUARTER AND FIRST NINE MONTHS 2015 RESULTS

Adjusted net income for the quarter (which excludes the effect of non-cash commodity derivatives and the effect of the non-cash ceiling test write-down) was $1.7 million, or $0.03 per diluted share (see Non-GAAP Financial Measures below). Lower commodity prices continued to impact Unit’s financial results. For the quarter, lower commodity prices resulted in Unit incurring a pre-tax non-cash ceiling test write-down of $329.9 million in the carrying value of the company’s oil and natural gas properties. Although this write-down was a non-cash item, it resulted in Unit recording a net loss of $205.3 million, or $4.18 per share, for the quarter compared to net income of $67.5 million, or $1.37 per diluted share, for the third quarter of 2014. Total revenues for the quarter were $212.4 million (45% oil and natural gas, 31% contract drilling, and 24% mid-stream), compared to $401.0 million (47% oil and natural gas, 30% contract drilling, and 23% mid-stream) for the third quarter of 2014. Adjusted EBITDA for the 2015 third quarter (which excludes the effect of non-cash commodity derivatives and the effect of the loss on sale of assets primarily attributable to the sale of drilling rigs and equipment) was $102.1 million or $2.07 per diluted share (see Non-GAAP Financial Measures below).

Adjusted net loss for the first nine months (which excludes the effect of non-cash commodity derivatives and the effects of the non-cash write-downs) was $0.5 million, or $0.01 per diluted share (see Non-GAAP Financial Measures below). For the first nine months of 2015, Unit has recorded pre-tax non-cash ceiling test write-downs of $1.1 billion in the carrying value of the company’s oil and natural gas properties and $8.3 million (pre-tax) in its drilling rigs and other assets. Due to these write-downs, Unit recorded a net loss of $728.0 million, or $14.83 per share, compared to net income of $178.8 million, or $3.65 per diluted share, for the first nine months of 2014. Total revenues for the first nine months were $681.9 million (45% oil and natural gas, 32% contract drilling, and 23% mid-stream), compared to $1.2 billion (48% oil and natural gas, 29% contract drilling, and 23% mid-stream) for the first nine months of 2014. Adjusted EBITDA for the first nine months of 2015 (which excludes the effect of non-cash commodity derivatives and the effect of the loss on sale of assets primarily attributable to the sale of drilling rigs and equipment) was $311.1 million or $6.31 per diluted share (see Non-GAAP Financial Measures below).

OIL AND NATURAL GAS SEGMENT INFORMATION

For the quarter, total equivalent production was 5.1 million barrels of oil equivalent (MMBoe), an increase of 10% over the third quarter of 2014 and essentially unchanged from the second quarter of 2015. Liquids (oil and NGLs) production represented 45% of total equivalent production for the quarter. Oil production for the quarter was 10,324 barrels per day, a decrease of 9% from the third quarter of 2014 and a decrease of 1% from the second quarter of 2015. NGLs production for the quarter was 14,557 barrels per day, an increase of 17% over the third quarter of 2014 and essentially unchanged from the

second quarter of 2015. Natural gas production for the quarter was 180,288 thousand cubic feet (Mcf) per day, an increase of 14% over the third quarter of 2014 and a decrease of 2% from the second quarter of 2015. Total production for the first nine months of 2015 was 15.2 MMBoe.

Unit’s average realized per barrel equivalent price for the third quarter was $20.61, a decrease of 48% from the third quarter of 2014 and an 8% decrease from the second quarter of 2015. Unit’s average natural gas price for the quarter was $2.66 per Mcf, a decrease of 28% from the third quarter of 2014 and essentially unchanged from the second quarter of 2015. Unit’s average oil price for the quarter was $50.87 per barrel, a decrease of 44% from the third quarter of 2014 and a decrease of 8% from the second quarter of 2015. Unit’s average NGLs price for the quarter was $8.74 per barrel, a 71% decrease from the third quarter of 2014 and a decrease of 27% from the second quarter of 2015. All prices in this paragraph include the effects of derivative contracts.

The following table summarizes this segment’s outstanding derivative contracts.



	Crude
Period	Structure	Volume Bbl/Day	Weighted Average Fixed Price	Weighted Average Floor Price	Weighted Average Subfloor Price	Weighted Average Ceiling Price
Oct'15 - Dec'15	Swap	1,000	$95.00
Oct'15 - Dec'15	Collar	2,000		$58.00		$64.40
Jan'16 - Dec'16	3-Way Collar	700		$46.50	$35.00	$57.00
Jan'16 - Jun'16	Collar	700		$44.00		$54.00
Jul'16 - Dec'16	3-Way Collar	700		$47.50	$35.00	$63.50
	Natural Gas
Period	Structure	Volume MMBtu/Day	Weighted Average Fixed Price	Weighted Average Floor Price	Weighted Average Subfloor Price	Weighted Average Ceiling Price
Oct'15 - Dec'15	Swap	40,000	$3.98
Nov'15 - Dec'15	3-Way Collar	13,500		$2.70	$2.20	$3.26
Jan'16 - Dec'16	Swap	10,000	$3.25
Jan'16 - Dec'16	3-Way Collar	13,500		$2.70	$2.20	$3.26
Jan'16 - Dec'16	Collar	27,000		$2.50		$3.11

The following table illustrates this segment’s comparative production, realized prices, and operating profit for the periods indicated:



	Three Months Ended					Three Months Ended					Nine Months Ended
	Sept 30, 2015		Sept 30, 2014		Change	Sept 30, 2015		June 30, 2015		Change	Sept 30, 2015		Sept 30, 2014		Change
Oil and NGLs Production, MBbl	2,289		2,188		5%	2,289		2,277		—%	6,950		6,176		13%
Natural Gas Production, Bcf	16.6		14.5		14%	16.6		16.7		—%	49.7		43.4		14%
Production, MBoe	5,053		4,612		10%	5,053		5,054		—%	15,225		13,414		14%
Production, MBoe/day	54.9		50.1		10%	54.9		55.5		(1)%	55.8		49.1		14%
Avg. Realized Natural Gas Price, Mcf ⁽¹⁾	$	2.66	$	3.68	(28)%	$	2.66	$	2.67	—%	$	2.76	$	3.99	(31)%
Avg. Realized NGL Price, Bbl ⁽¹⁾	$	8.74	$	30.11	(71)%	$	8.74	$	12.05	(27)%	$	9.83	$	33.05	(70)%
Avg. Realized Oil Price, Bbl ⁽¹⁾	$	50.87	$	91.57	(44)%	$	50.87	$	55.52	(8)%	$	51.46	$	92.44	(44)%
Realized Price / Boe ⁽¹⁾	$	20.61	$	39.76	(48)%	$	20.61	$	22.38	(8)%	$	21.66	$	40.53	(47)%
Operating Profit Before Depreciation, Depletion, & Amortization (MM) ⁽²⁾	$	57.9	$	139.6	(59)%	$	57.9	$	61.3	(5)%	$	180.1	$	441.2	(59)%


(1)	Realized price includes oil, NGLs, natural gas, and associated derivatives.


(2)	Operating profit before depreciation is calculated by taking operating revenues for this segment less operating expenses excluding depreciation, depletion, amortization, and impairment.

Currently, two Unit drilling rigs are operating for this segment. One is operating in the Southern Oklahoma Hoxbar Oil Trend (SOHOT) and one is drilling in the Wilcox play, located in Southeast Texas. The current plan is to keep these two Unit drilling rigs operating through the end of the year. Unit’s expectations are to be at the top end of the revised upward 2015 production guidance of 6% to 8% growth over 2014. Anticipated capital expenditures are estimated to be in line with projected cash flow. Well service cost reductions and operating efficiencies are resulting in current AFE’s continuing to be approximately 28% lower as compared to 2014.

In the SOHOT area, four horizontal operated Hoxbar wells were completed during the third quarter with one well in the Marchand bench and three wells in the Medrano bench. During the first nine months of 2015, a total of three Marchand wells and nine Medrano wells were completed. The 30 day initial production rate for the 2015 Marchand wells averaged 1,345 Boe per day (79% oil, 11% NGLs) which is 7% higher than the current type curve. The 30 day initial production rate for the 2015 Medrano wells averaged 7.0 MMcfe per day (8% oil, 21% NGLs). Production during the quarter averaged 6,574 Boe per day (31% oil, 25% NGLs), which is an increase of 186% as compared to the third quarter 2014. Going forward, the drilling program for the Hoxbar will focus primarily on the oily Marchand bench, with higher returns under current commodity pricing.

In the Wilcox area, production for the quarter averaged 82 MMcfe per day (11% oil, 31% NGLs) which is a 32% increase over the third quarter of 2014, and an 18% increase over the second quarter 2015. The strong production growth is primarily a result of recent horizontal and vertical well completions. Five new vertical Wilcox wells were completed during the quarter, bringing the total for 2015 to 13 wells (three horizontal) with a 100% completion success rate. The vertical Unit Wing #14 well (75% working interest) was completed in September flowing approximately 8.6 MMcfe per day (13% oil, 29% NGLs) with 6,500 pounds flowing tubing pressure from 83 net feet of Wilcox sand. The completed well cost is approximately $4.6 million. The well has an additional Wilcox zone behind pipe with 62 net feet of potential pay. This well extends the Gilly field approximately 2,000 feet to the east. Preliminary results from the three horizontal wells will be discussed on the conference call.

Larry Pinkston, Unit’s Chief Executive Officer and President, said: “Recently, we announced that strong well results primarily in our SOHOT, Wilcox and our Granite Wash plays, have allowed us to increase our production guidance for 2015 to 6% - 8% from our previous guidance of 2% - 4%. We also announced that our 2015 capital expenditures are expected to be approximately $30 million less than originally budgeted. This reduction is primarily because of the efficiencies we have made in this segment.”

CONTRACT DRILLING SEGMENT INFORMATION

The average number of drilling rigs used in the quarter was 31.2, a decrease of 61% from the third quarter of 2014, and an increase of 2% over the second quarter of 2015. Per day drilling rig rates for the quarter averaged $18,800, a decrease of 6% from the third quarter of 2014 and a 5% decrease from the second quarter of 2015. Average per day operating margin for the quarter was $10,368 (before elimination of intercompany drilling rig profit and bad debt expense of $0.2 million). This compares to $8,449 (before elimination of intercompany drilling rig profit and bad debt expense of $7.6 million) for the third quarter of 2014, an increase of 23%, or $1,919. As compared to $6,821 (before elimination of intercompany drilling rig profit and bad debt expense of $0.5 million) for the second quarter of 2015, third quarter 2015 operating margin increased 52% or $3,547 (in each case regarding eliminating intercompany drilling rig profit and bad debt expense - see Non-GAAP Financial Measures below). Average operating margins for the third quarter of 2015 included early termination fees of approximately $11.4 million, or $3,958 per day, from the cancellation of certain long-term contracts, compared to no early termination fees during the third quarter of 2014 and $1.6 million, or $594 per day, for the second quarter of 2015. Third quarter 2015 average operating margins improved 3% over second quarter 2015 (both periods net of early termination fees.)

Larry Pinkston said: “Drilling rig demand declined somewhat during the quarter due to decreases in commodity prices. Our current drilling rig fleet totals 94 drilling rigs, of which 28 are working under contract. During the third quarter, we were notified of a customer's intent to terminate early the contracts on two BOSS drilling rigs, both of which are under term contracts that contain early termination penalties. We have been in discussions with the customer and it appears likely that they will keep one of the BOSS drilling rigs through its remaining term although the start date is pending. We recently contracted the other BOSS drilling rig to a third party operator. Long-term contracts (contracts with original terms ranging from six months to two years in length) are in place for 11 of the 28 drilling rigs. Of the 11 long-term contracts, one is up for renewal during the fourth quarter, seven in 2016 and three in 2017.”

The following table illustrates certain comparative results from this segment’s operations for the periods indicated:



	Three Months Ended					Three Months Ended					Nine Months Ended
	Sept 30, 2015		Sept 30, 2014		Change	Sept 30, 2015		June 30, 2015		Change	Sept 30, 2015		Sept 30, 2014		Change
Rigs Utilized	31.2		79.1		(61)%	31.2		30.7		2%	37.3		73.5		(49)%
Operating Profit Before Depreciation, Depletion, & Amortization (MM) ⁽¹⁾	$	29.5	$	53.9	(45)%	$	29.5	$	18.5	59%	$	91.4	$	144.5	(37)%


(1)	Operating profit before depreciation is calculated by taking operating revenues for this segment less operating expenses excluding depreciation and impairment.

MID-STREAM SEGMENT INFORMATION

For the quarter, per day gas gathered and gas processed volumes increased 12% and 10%, respectively, while liquids sold volumes decreased 25% as compared to the third quarter of 2014. Compared to the second quarter of 2015, gas gathered, gas processed, and liquids sold volumes per day decreased 2%, 0%, and 3%, respectively. Operating profit (as defined in the footnote below) for the quarter was $10.4 million, a decrease of 21% from the third quarter of 2014 and a decrease of 10% from the second quarter of 2015.

For the first nine months, per day gas gathered and gas processed volumes increased 11% and 17%, respectively, while liquids sold volumes decreased 22% as compared to the first nine months of 2014. Operating profit (as defined in the footnote below) for the first nine months was $31.8 million, a decrease of 20% from the first nine months of 2014.

The following table illustrates certain comparative results from this segment’s operations for the periods indicated:



	Three Months Ended					Three Months Ended					Nine Months Ended
	Sept 30, 2015		Sept 30, 2014		Change	Sept 30, 2015		June 30, 2015		Change	Sept 30, 2015		Sept 30, 2014		Change
Gas Gathering, Mcf/day	357,427		319,692		12%	357,427		362,896		(2)%	351,619		316,658		11%
Gas Processing, Mcf/day	185,625		169,357		10%	185,625		186,041		—%	186,929		160,373		17%
Liquids Sold, Gallons/day	579,556		771,334		(25)%	579,556		599,732		(3)%	582,760		748,805		(22)%
Operating Profit Before Depreciation, Depletion, & Amortization (MM) ⁽¹⁾	$	10.4	$	13.3	(21)%	$	10.4	$	11.6	(10)%	$	31.8	$	39.5	(20)%


(1)	Operating profit before depreciation is calculated by taking operating revenues for this segment less operating expenses excluding depreciation, amortization, and impairment.

Larry Pinkston said: “In the Appalachian area, we continue to make progress with a new well pad being connected to our Pittsburgh Mills gathering system. The pad came online in October 2015. The operator currently plans additional pads in 2016. Our Snowshoe gathering project, located in Centre County, Pennsylvania, is nearing completion and is planned to be operational by year end 2015. At our various gas processing facilities in the Mid-Continent, we continue to operate in full ethane rejection mode due to low liquids prices, which continues to impact our liquids sold volumes.”

FINANCIAL INFORMATION

Unit ended the quarter with long-term debt of $908.2 million (consisting of $646.5 million of senior subordinated notes net of unamortized discount and $261.7 million of borrowings under its credit agreement). During the quarter, Unit’s lenders completed their regularly scheduled semi-annual borrowing base redetermination under its credit agreement. Unit’s borrowing base was determined to be $550 million, which remains above its elected commitment level of $500 million. No other terms under the credit agreement changed because of the redetermination and Unit is fully in compliance with the financial covenants in the credit agreement. Unit has elected to maintain its elected commitment amount at $500 million, which it believes will meet its financing needs during this current commodity cycle.

WEBCAST

Unit will webcast its third quarter earnings conference call live over the Internet on November 3, 2015 at 10:00 a.m. Central Time (11:00 a.m. Eastern). To listen to the live call, please go to http://www.unitcorp.com/investor/calendar.htm at least fifteen minutes prior to the start of the call to download and install any necessary audio software. For those who are not available to listen to the live webcast, a replay will be available shortly after the call and will remain on the site for 90 days.

_____________________________________________________

Unit Corporation is a Tulsa-based, publicly held energy company engaged through its subsidiaries in oil and gas exploration, production, contract drilling, and gas gathering and processing. Unit’s Common Stock is on the New York Stock Exchange under the symbol UNT. For more information about Unit Corporation, visit its website at http://www.unitcorp.com.

FORWARD-LOOKING STATEMENT

This news release contains forward-looking statements within the meaning of the private Securities Litigation Reform Act. All statements, other than statements of historical facts, included in this release that address activities, events, or developments that the company expects or anticipates will or may occur in the future are forward-looking statements. Several risks and uncertainties could cause actual results to differ materially from these statements, including the productive capabilities of the company’s wells, future demand for oil and natural gas, future drilling rig utilization and dayrates, projected growth of the company’s oil and natural gas production, its anticipated borrowing needs under its credit agreement, the number of wells to be drilled by the company’s oil and natural gas segment, and other factors described from time to time in the company’s publicly available SEC reports. The company assumes no obligation to update publicly such forward-looking statements, whether because of new information, future events, or otherwise.

Unit Corporation

Selected Financial Highlights

(In thousands except per share amounts)



	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2015			2014			2015			2014
Statement of Operations:
Revenues:
Oil and natural gas	$	96,619		$	188,471		$	309,944		$	575,176
Contract drilling	65,022			120,652			215,114			341,530
Gas gathering and processing	50,752			91,851			156,881			277,687
Total revenues	212,393			400,974			681,939			1,194,393
Expenses:
Oil and natural gas:
Operating costs	38,688			48,841			129,871			133,979
Depreciation, depletion, and amortization	57,159			70,033			202,378			200,958
Impairment of oil and natural gas properties	329,924			—			1,141,053			—
Contract drilling:
Operating costs	35,486			66,727			123,717			197,025
Depreciation	14,255			22,560			42,533			61,194
Impairment of contract drilling equipment	—			—			8,314			—
Gas gathering and processing:
Operating costs	40,314			78,558			125,081			238,166
Depreciation and amortization	10,976			10,272			32,518			29,972
General and administrative	7,643			10,172			26,637			30,409
(Gain) loss on disposition of assets	7,230			529			6,270			(9,092		)
Total operating expenses	541,675			307,692			1,838,372			882,611

Income (loss) from operations	(329,282		)	93,282			(1,156,433		)	311,782

Other income (expense):
Interest, net	(8,286		)	(4,280		)	(23,482		)	(12,201		)
Gain (loss) on derivatives not designated as hedges	8,250			19,841			12,917			(9,234		)
Other	16			(68		)	38			3
Total other income (expense)	(20		)	15,493			(10,527		)	(21,432		)

Income (loss) before income taxes	(329,302		)	108,775			(1,166,960		)	290,350

Income tax expense (benefit):
Current	(2,584		)	5,451			(1,716		)	23,721
Deferred	(121,437		)	35,802			(437,220		)	87,802
Total income taxes	(124,021		)	41,253			(438,936		)	111,523

Net income (loss)	$	(205,281	)	$	67,522		$	(728,024	)	$	178,827

Net income (loss) per common share:
Basic	$	(4.18	)	$	1.39		$	(14.83	)	$	3.68
Diluted	$	(4.18	)	$	1.37		$	(14.83	)	$	3.65

Weighted average shares outstanding:
Basic	49,155			48,650			49,094			48,596
Diluted	49,155			49,177			49,094			49,054



	September 30,		December 31,
	2015		2014
Balance Sheet Data:
Current assets	$	150,670	$	252,491
Total assets	$	3,284,518	$	4,473,728
Current liabilities	$	182,351	$	304,171
Long-term debt	$	908,234	$	812,163
Other long-term liabilities	$	136,981	$	148,785
Deferred income taxes	$	438,995	$	876,215
Shareholders’ equity	$	1,617,957	$	2,332,394



	Nine Months Ended September 30,
	2015			2014
Statement of Cash Flows Data:
Cash flow from operations before changes in operating assets and liabilities	$	303,719		$	565,135
Net change in operating assets and liabilities	77,763			(15,608		)
Net cash provided by operating activities	$	381,482		$	549,527
Net cash used in investing activities	$	(474,190	)	$	(636,761	)
Net cash provided by financing activities	$	92,553		$	69,536

Non-GAAP Financial Measures

Unit Corporation reports its financial results in accordance with generally accepted accounting principles (“GAAP”). The Company believes certain non-GAAP performance measures provide users of its financial information and its management additional meaningful information to evaluate the performance of the company.

This press release includes net income and earnings per share including impairment adjustments and the effect of the cash settled commodity derivatives, its drilling segment’s average daily operating margin before elimination of intercompany drilling rig profit and bad debt expense, its cash flow from operations before changes in operating assets and liabilities, and its reconciliation of EBITDA and Adjusted EBITDA.

Below is a reconciliation of GAAP financial measures to non-GAAP financial measures for the three and nine months ended September 30, 2015 and 2014. Non-GAAP financial measures should not be considered by themselves or a substitute for results reported in accordance with GAAP.

Unit Corporation

Reconciliation of Adjusted Net Income and Adjusted Diluted Earnings per Share



	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2015			2014			2015			2014
	(In thousands except earnings per share)
Adjusted net income:
Net income (loss)	$	(205,281	)	$	67,522		$	(728,024	)	$	178,827
Impairment adjustment (net of income tax)	205,378			—			715,481			—
(Gain) loss on derivatives not designated as hedges (net of income tax)	(5,272		)	(12,163		)	(8,058		)	5,659
Settlements during the period of matured derivative contracts (net of income tax)	6,837			(630		)	20,060			(11,635		)
Adjusted net income (loss)	$	1,662		$	54,729		$	(541	)	$	172,851

Adjusted diluted earnings per share:
Diluted earnings (loss) per share	$	(4.18	)	$	1.37		$	(14.83	)	$	3.65
Diluted earnings per share from the impairments	4.18			—			14.57			—
Diluted earnings per share from the (gain) loss on derivatives	(0.11		)	(0.25		)	(0.16		)	0.11
Diluted earnings (loss) per share from the settlements of matured derivative contracts	0.14			(0.01		)	0.41			(0.24		)
Adjusted diluted earnings (loss) per share	$	0.03		$	1.11		$	(0.01	)	$	3.52

________________

The Company has included the net income and diluted earnings per share including only the cash settled commodity derivatives because:


•	It uses the adjusted net income to evaluate the operational performance of the company.


•	The adjusted net income is more comparable to earnings estimates provided by securities analysts.

Unit Corporation

Reconciliation of Average Daily Operating Margin Before Elimination of Intercompany Rig Profit and Bad Debt Expense



	Three Months Ended						Nine Months Ended
	June 30,		September 30,				September 30,
	2015		2015		2014		2015		2014
	(In thousands except for operating days and operating margins)
Contract drilling revenue	$	55,015	$	65,022	$	120,652	$	215,114	$	341,530
Contract drilling operating cost	36,485		35,486		66,727		123,717		197,025
Operating profit from contract drilling	18,530		29,536		53,925		91,397		144,505
Add:
Elimination of intercompany rig profit and bad debt expense	537		219		7,553		3,666		20,674
Operating profit from contract drilling before elimination of intercompany rig profit and bad debt expense	19,067		29,755		61,478		95,063		165,179
Contract drilling operating days	2,795		2,870		7,276		10,175		20,073
Average daily operating margin before elimination of intercompany rig profit and bad debt expense	$	6,821	$	10,368	$	8,449	$	9,343	$	8,229

________________

The Company has included the average daily operating margin before elimination of intercompany rig profit and bad debt expense because:


•	Its management uses the measurement to evaluate the cash flow performance of its contract drilling segment and to evaluate the performance of contract drilling management.


•	It is used by investors and financial analysts to evaluate the performance of the company.

Unit Corporation

Reconciliation of Cash Flow From Operations Before Changes in Operating Assets and Liabilities



	Nine Months Ended September 30,
	2015			2014
	(In thousands)
Net cash provided by operating activities	$	381,482		$	549,527
Net change in operating assets and liabilities	(77,763		)	15,608
Cash flow from operations before changes in operating assets and liabilities	$	303,719		$	565,135

________________

The Company has included the cash flow from operations before changes in operating assets and liabilities because:


•	It is an accepted financial indicator used by its management and companies in the industry to measure the company’s ability to generate cash which is used to internally fund its business activities.


•	It is used by investors and financial analysts to evaluate the performance of the company.

Unit Corporation

Reconciliation of EBITDA and Adjusted EBITDA



	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2015			2014			2015			2014
	(In thousand except earnings per share)
Adjusted EBITDA:
Net income (loss)	$	(205,281	)	$	67,522		$	(728,024	)	$	178,827
Income taxes	(124,021		)	41,253			(438,936		)	111,523
Depreciation, depletion and amortization	83,163			103,599			279,739			294,412
Impairments	329,924			—			1,149,367			—
Interest expense	8,286			4,280			23,482			12,201
EBITDA	92,071			216,654			285,628			596,963
(Gain) loss on derivatives not designated as hedges	(8,250		)	(19,841		)	(12,917		)	9,234
Settlements during the period of matured derivative contracts	11,074			(1,029		)	32,156			(18,984		)
(Gain) loss on disposition of assets	7,230			529			6,270			(9,092		)
Adjusted EBITDA	$	102,125		$	196,313		$	311,137		$	578,121

Adjusted EBITDA per diluted share:
Diluted earnings (loss) per share	$	(4.18	)	$	1.37		$	(14.83	)	$	3.65
Diluted earnings per share from income taxes	(2.52		)	0.84			(8.94		)	2.27
Diluted earnings per share from depreciation , depletion and amortization	1.69			2.11			5.70			6.00
Diluted earnings per share from impairments	6.71			—			23.38			—
Diluted earnings per share from interest expense	0.17			0.09			0.48			0.25
EBITDA per diluted share	1.87			4.41			5.79			12.17
Diluted earnings per share from the (gain) loss on derivatives not designated as hedges	(0.17		)	(0.41		)	(0.26		)	0.19
Diluted earnings per share from the settlements during the period of matured derivative contracts	0.22			(0.02		)	0.65			(0.38		)
Diluted earnings per share (gain) loss on disposition of assets	0.15			0.01			0.13			(0.19		)
Adjusted EBITDA per diluted share	$	2.07		$	3.99		$	6.31		$	11.79

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The Company has included the adjusted EBITDA excluding gain or loss on disposition of assets and including only the cash settled commodity derivatives because:


•	It uses the adjusted EBITDA to evaluate the operational performance of the company.


•	The adjusted EBITDA is more comparable to estimates provided by securities analysts.