UNIT CORP - FORM 8-K - EX-99.1 - EXHIBIT 99.1 PRESS RELEASE

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8-K - 8-K - UNIT CORP	form8k_3q18.htm



News	UNIT CORPORATION
	8200 South Unit Drive, Tulsa, Oklahoma 74132
	Telephone 918 493-7700, Fax 918 493-7711



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

For Immediate Release

November 6, 2018

UNIT CORPORATION REPORTS 2018 THIRD QUARTER RESULTS

Tulsa, Oklahoma . . . Unit Corporation (NYSE - UNT) today reported its financial and operational results for the third quarter 2018. The results reported below include those attributable to Unit's consolidated subsidiaries. Third quarter and recent highlights include:


•	Net income attributable to Unit of $18.9 million; adjusted net income attributable to Unit of $15.7 million, a 39% and 195% increase over second quarter 2018 and third quarter 2017 adjusted net income, respectively.


•	Oil and natural gas segment production increased 3% over the second quarter of 2018 and 7% over the third quarter of 2017.


•	Contract drilling segment placed into service its 11^th BOSS drilling rig at the beginning of the third quarter. All eleven BOSS drilling rigs are operating under contract. The 12^th and 13^th BOSS rigs are contracted and expected to be placed into service in the first quarter of 2019.


•	Thirty-four of the contract drilling segment's drilling rigs are operating.


•	Midstream segment gas gathered and liquids sold volumes per day increased 6% and 4%, respectively, as compared to the second quarter of 2018.


•	On October 18, 2018, Unit Corporation amended its credit agreement extending the term of the agreement to October 18, 2023, among other things.

THIRD QUARTER 2018 FINANCIAL RESULTS

Net income attributable to Unit for the quarter was $18.9 million, or $0.36 per diluted share, compared to net income attributable to Unit of $3.7 million, or $0.07 per share, for the third quarter of 2017. Adjusted net income attributable to Unit (which excludes the effect of non-cash commodity derivatives) for the quarter was $15.7 million, or $0.30 per diluted share, as compared to $0.10 per diluted share for the same quarter for 2017, a 195% increase in adjusted net income (see Non-GAAP financial measures below). Total revenues for the quarter were $220.1 million (51% oil and natural gas, 23% contract drilling, and 26% midstream), compared to $188.5 million (45% oil and natural gas, 28% contract drilling, and 27% midstream) for the third quarter of 2017. Adjusted EBITDA attributable to Unit was $90.8 million, or $1.71 per diluted share, compared to $78.4 million, or $1.51 per diluted share, for the third quarter of 2017 (see Non-GAAP financial measures below).

For the first nine months of 2018, net income attributable to Unit was $32.6 million, or $0.62 per diluted share, compared to $28.7 million, or $0.56 per share, for the first nine months of 2017. For the same period adjusted net income attributable to Unit (which excludes the effect of non-cash commodity derivatives) was $38.0 million, or $0.72 per diluted share, as compared to $0.32 per diluted share for the same period for 2017, a 132% increase in adjusted net income (see Non-GAAP financial measures below). Total revenues for the first nine months were $628.5 million (50% oil and natural gas, 23% contract drilling, and 27% midstream), compared to $534.8 million (48% oil and natural gas, 24% contract drilling, and 28% midstream) for the first nine months of 2017. Adjusted EBITDA attributable to Unit for the first nine months was $261.5 million, or $4.96 per diluted share, compared to $222.8 million, or $4.32 per diluted share, for the first nine months of 2017 (see Non-GAAP financial measures below).

OIL AND NATURAL GAS SEGMENT INFORMATION

For the quarter, total equivalent production was 4.4 million barrels of oil equivalent (MMBoe), a 3% increase over the second quarter of 2018. Oil and natural gas liquids (NGLs) production represented 45% of total equivalent production. Oil production was 7,521 barrels per day, a decrease of 1% from the second quarter of 2018. NGLs production was 13,889 barrels per day, a 3% increase over the second quarter of 2018. Natural gas production was 155,825 thousand cubic feet (Mcf) per day, a 3% increase over the second quarter of 2018. Per day equivalent production for the first nine months of 2018 was 46.7 thousand barrels of oil equivalent (MBoe).

Unit’s average realized per barrel equivalent price for the quarter was $24.15, a 6% increase over the second quarter of 2018. Unit’s average oil price was $57.72 per barrel, an increase of 2% over the second quarter of 2018. Unit’s average NGLs price was $25.66 per barrel, an increase of 16% over the second quarter of 2018. Unit’s average natural gas price was $2.27 per Mcf, an increase of 4% over the second quarter of 2018. All prices in this paragraph include the effects of derivative contracts.

In the Southern Oklahoma Hoxbar Oil Trend (SOHOT), in Grady County, Oklahoma, Unit completed the Schenk Trust #2-17HXL well and the #3-17HXL well, which were brought online during August. Each well had an IP30 of approximately 1,500 Boe per day with an oil cut of 75%. Both wells had laterals in excess of 7,000 feet. Unit continues to pursue opportunities to expand its position in the oily areas.

In the Texas Panhandle, Unit recently drilled and completed two Granite Wash "G" wells in the Buffalo Wallow field. The wells are in the early flow-back stages, and it is too soon to discuss EUR's and IP30's. The first of the two wells is currently flowing in excess of 9 MMcfe per day.

Pinkston said: “Our oil and natural gas segment generated solid production growth for the quarter during which we increased activity levels to six operated rigs for a brief period. We have now reduced our operated rig count to three rigs to keep annual capital expenditures in line with our anticipated cash flows."

This table illustrates certain comparative production, realized prices, and operating profit for the periods indicated:



	Three Months Ended					Three Months Ended					Nine Months Ended
	Sep 30, 2018		Sep 30, 2017		Change	Sep 30, 2018		Jun 30, 2018		Change	Sep 30, 2018		Sep 30, 2017		Change
Oil and NGLs Production, MBbl	1,970		1,876		5%	1,970		1,923		2%	5,823		5,466		7%
Natural Gas Production, Bcf	14.3		13.1		10%	14.3		13.7		4%	41.6		37.3		11%
Production, MBoe	4,359		4,057		7%	4,359		4,212		3%	12,752		11,686		9%
Production, MBoe/day	47.4		44.1		7%	47.4		46.3		2%	46.7		42.8		9%
Avg. Realized Natural Gas Price, Mcf ⁽¹⁾	$	2.27	$	2.36	(4)%	$	2.27	$	2.18	4%	$	2.35	$	2.50	(6)%
Avg. Realized NGL Price, Bbl ⁽¹⁾	$	25.66	$	18.35	40%	$	25.66	$	22.18	16%	$	23.03	$	17.05	35%
Avg. Realized Oil Price, Bbl ⁽¹⁾	$	57.72	$	47.29	22%	$	57.72	$	56.46	2%	$	56.40	$	47.62	18%
Realized Price / Boe ⁽¹⁾	$	24.15	$	20.63	17%	$	24.15	$	22.87	6%	$	23.74	$	21.16	12%
Operating Profit Before Depreciation, Depletion, & Amortization (MM) ⁽²⁾	$	79.5	$	51.6	54%	$	79.5	$	69.9	14%	$	216.5	$	160.4	35%


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


(2)	Unit calculates operating profit before depreciation by taking operating revenues for this segment less operating expenses excluding depreciation, depletion, amortization, and impairment. (See non-GAAP financial measures below.)

CONTRACT DRILLING SEGMENT INFORMATION

Unit averaged 34.2 drilling rigs working during the quarter, an increase of 6% over the second quarter of 2018. Per day drilling rig rates averaged $17,589, a 2% increase over the second quarter of 2018. For the first nine months of 2018, per day drilling rig rates averaged $17,327, a 7% increase over the first nine months of 2017. Average per day operating margin for the quarter was $6,291 (before elimination of intercompany drilling rig profit of $1.2 million). This compares to second quarter

2018 average operating margin of $5,412 (before elimination of intercompany drilling rig profit of $0.8 million), an increase of 16%, or $879. Average per day operating margin for the first nine months of 2018 was $5,647 (before elimination of intercompany drilling rig profit of $2.4 million). This compares to the first nine months of 2017 average operating margin of $4,671 (before elimination of intercompany drilling rig profit of $1.0 million), an increase of 21%, or $976 (in each case regarding eliminating intercompany drilling rig profit see Non-GAAP financial measures below).

Pinkston said: “Our contract drilling segment had another strong quarter. Rig utilization remained at 34 rigs working at the end of the quarter, and we currently have 34 rigs operating. All 11 of our BOSS rigs are operating under contract. We obtained long-term contracts for our 12th and 13th BOSS rigs which will be completed and placed into service in the first quarter of 2019. We continue to be very pleased with the performance and acceptance of our BOSS rigs. We had 19 long-term contracts (contracts with original terms ranging from six months to three years in length) as of the end of the quarter. Of those contracts, five are up for renewal in 2018, 13 in 2019, and one in 2020. The long-term contracts at the end of the quarter exclude the two BOSS rig contracts pertaining to the new rigs under construction.”

This table illustrates certain comparative results for the periods indicated:



	Three Months Ended					Three Months Ended					Nine Months Ended
	Sep 30, 2018		Sep 30, 2017		Change	Sep 30, 2018		Jun 30, 2018		Change	Sep 30, 2018		Sep 30, 2017		Change
Rigs Utilized	34.2		34.6		(1)%	34.2		32.2		6%	32.7		29.7		10%
Operating Profit Before Depreciation (MM)⁽¹⁾	$	18.6	$	16.9	10%	$	18.6	$	15.0	24%	$	47.9	$	36.8	30%


(1)	Unit calculates operating profit before depreciation by taking operating revenues for this segment less operating expenses excluding depreciation and impairment. (See non-GAAP financial measures below.)

MIDSTREAM SEGMENT INFORMATION

For the quarter, gas gathered and liquids sold volumes per day increased 6% and 4%, respectively, while gas processed volumes per day remained relatively unchanged as compared to the second quarter of 2018. Operating profit (as defined in the footnote below) for the quarter was $14.7 million, an increase of 2% over the second quarter of 2018.

For the first nine months of 2018, per day gas gathered, gas processed, and liquids sold volumes increased 2%, 17% and 26%, respectively, as compared to the first nine months of 2017. Operating profit (as defined in the footnote below) for the first nine months of 2018 was $43.5 million, an increase of 13% over the first nine months of 2017.

This table illustrates certain comparative results for the periods indicated:



	Three Months Ended					Three Months Ended					Nine Months Ended
	Sep 30, 2018		Sep 30, 2017		Change	Sep 30, 2018		Jun 30, 2018		Change	Sep 30, 2018		Sep 30, 2017		Change
Gas Gathering, Mcf/day	415,862		383,787		8%	415,862		391,047		6%	393,414		385,846		2%
Gas Processing, Mcf/day	160,294		140,246		14%	160,294		160,506		—%	157,313		133,986		17%
Liquids Sold, Gallons/day	700,523		530,028		32%	700,523		676,503		4%	651,979		518,054		26%
Operating Profit Before Depreciation & Amortization (MM) ⁽¹⁾	$	14.7	$	13.3	11%	$	14.7	$	14.4	2%	$	43.5	$	38.6	13%


(1)	Unit calculates operating profit before depreciation by taking operating revenues for this segment less operating expenses excluding depreciation, amortization, and impairment. (See non-GAAP financial measures below.)

Pinkston said: “During the quarter, we continued to grow the midstream business through organic opportunities. We connected several new wells to our Cashion gathering and processing system. That system will serve our new Reeding gas processing plant currently under construction. The new plant is expected to be placed in service in the first quarter of 2019. We recently added new gathering lines and compression for the J R Miller pad on our Pittsburgh Mills gathering system in Pennsylvania for a third-party operator. The operator plans to bring the pad on-line early in the first quarter of 2019. NGLs

recoveries continue to increase with improved NGLs pricing. We continue to pursue additional organic and strategic growth opportunities.”

FINANCIAL INFORMATION

Unit ended the quarter with cash and cash equivalents of $91.6 million and long-term debt of $643.9 million, comprised solely of senior subordinated notes (net of unamortized discount and debt issuance costs) and no borrowings under the Unit or Superior credit agreements. On October 18, 2018, Unit signed the Fifth Amendment to its credit agreement in connection with the renewal and extension of its senior credit facility through October 18, 2023. The agreement is subject to an elected commitment and available borrowing base of $425 million. In addition to extending the term, the amendment increased the company’s flexibility around the issuance of senior notes and lowered pricing on certain borrowings and fees.

WEBCAST

Unit uses its website to disclose material nonpublic information and for complying with its disclosure obligations under Regulation FD. The website includes those disclosures in the 'Investor Information' sections. So, investors should monitor that portion of the website, besides following the press releases, SEC filings, and public conference calls and webcasts.

Unit will webcast its third quarter earnings conference call live over the Internet on November 6, 2018 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 before 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 listed 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, believes, or anticipates will or may occur are forward-looking statements. Several risks and uncertainties could cause actual results to differ materially from these statements, including changes in commodity prices, the productive capabilities of the company’s wells, future demand for oil and natural gas, future drilling rig utilization and dayrates, projected rate of the company’s oil and natural gas production, the amount available to the company for borrowings, its anticipated borrowing needs under its credit agreements, the number of wells to be drilled by the company’s oil and natural gas segment, the potential productive capability of its prospective plays, and other factors described occasionally 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,
	2018			2017			2018			2017
Income Statements:
Revenues:
Oil and natural gas	$	111,623		$	85,470		$	317,040		$	256,241
Contract drilling	50,612			51,619			143,527			128,059
Gas gathering and processing	57,823			51,399			167,926			150,493
Total revenues	220,058			188,488			628,493			534,793
Expenses:
Operating costs:
Oil and natural gas	32,139			33,911			100,519			95,873
Contract drilling	32,032			34,747			95,593			91,213
Gas gathering and processing	43,134			38,116			124,441			111,862
Total operating costs	107,305			106,774			320,553			298,948
Depreciation, depletion, and amortization	63,537			54,533			178,976			151,545
General and administrative	9,278			9,235			28,752			26,902
Gain on disposition of assets	(253		)	(81		)	(575		)	(1,153		)
Total operating expenses	179,867			170,461			527,706			476,242

Income from operations	40,191			18,027			100,787			58,551

Other income (expense):
Interest, net	(7,945		)	(9,944		)	(25,678		)	(28,807		)
Gain (loss) on derivatives	(4,385		)	(2,614		)	(25,608		)	21,019
Other	6			5			17			14
Total other income (expense)	(12,324		)	(12,553		)	(51,269		)	(7,774		)

Income before income taxes	27,867			5,474			49,518			50,777

Income tax expense:
Deferred	6,744			1,769			12,380			22,084
Total income taxes	6,744			1,769			12,380			22,084

Net income	21,123			3,705			37,138			28,693
Net income attributable to non-controlling interest	2,224			—			4,586			—
Net income attributable to Unit Corporation	$	18,899		$	3,705		$	32,552		$	28,693

Net income attributable to Unit Corporation per common share:
Basic	$	0.36		$	0.07		$	0.63		$	0.56
Diluted	$	0.36		$	0.07		$	0.62		$	0.56

Weighted average shares outstanding:
Basic	52,068			51,386			51,951			51,019
Diluted	53,140			51,972			52,759			51,569

Unit Corporation

Selected Financial Highlights - continued

(In thousands)



	September 30,		December 31,
	2018		2017
Balance Sheet Data:
Current assets	$	223,604	$	119,672
Total assets	$	2,820,765	$	2,581,452
Current liabilities	$	239,563	$	181,936
Long-term debt	$	643,921	$	820,276
Other long-term liabilities and non-current derivative liability	$	102,952	$	100,203
Deferred income taxes	$	164,964	$	133,477
Total shareholders’ equity attributable to Unit Corporation	$	1,467,737	$	1,345,560



	Nine Months Ended September 30,
	2018			2017
Statement of Cash Flows Data:
Cash flow from operations before changes in operating assets and liabilities	$	253,693		$	194,912
Net change in operating assets and liabilities	(17,158		)	(10,120		)
Net cash provided by operating activities	$	236,535		$	184,792
Net cash used in investing activities	$	(279,507	)	$	(204,184	)
Net cash provided by financing activities	$	133,828		$	19,321

Non-GAAP Financial Measures

Unit Corporation reports its financial results under generally accepted accounting principles (“GAAP”). The company believes certain non-GAAP 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 and the effect of the cash-settled commodity derivatives, its reconciliation of segment operating profit, 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 net income to adjusted EBITDA.

Below is a reconciliation of GAAP financial measures to non-GAAP financial measures for the three and nine months ended September 30, 2018 and 2017. Non-GAAP financial measures should not be considered by themselves or a substitute for results reported under GAAP. This non-GAAP information should be considered by the reader in addition to, but not instead of, the financial statements prepared under GAAP. The non-GAAP financial information presented may be determined or calculated differently by other companies and may not be comparable to similarly titled measures.

Unit Corporation

Reconciliation of Adjusted Net Income and Adjusted Diluted Earnings per Share



	Three Months Ended					Nine Months Ended
	September 30,					September 30,
	2018			2017		2018			2017
	(In thousands except earnings per share)
Adjusted net income attributable to Unit Corporation:
Net income attributable to Unit Corporation	$	18,899		$	3,705	$	32,552		$	28,693
(Gain) loss on derivatives (net of income tax)	3,531			1,157		18,553			(11,879		)
Settlements during the period of matured derivative contracts (net of income tax)	(6,751		)	453		(13,070		)	(412		)
Adjusted net income attributable to Unit Corporation	$	15,679		$	5,315	$	38,035		$	16,402

Adjusted diluted earnings attributable to Unit Corporation per share:
Diluted earnings per share	$	0.36		$	0.07	$	0.62		$	0.56
Diluted earnings per share from (gain) loss on derivatives	0.07			0.02		0.35			(0.23		)
Diluted earnings per share from settlements of matured derivative contracts	(0.13		)	0.01		(0.25		)	(0.01		)
Adjusted diluted income per share	$	0.30		$	0.10	$	0.72		$	0.32

________________

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 Segment Operating Profit



	Three Months Ended									Nine Months Ended
	June 30,			September 30,						September 30,
	2018			2018			2017			2018			2017
	(In thousands)
Oil and natural gas	$	69,900		$	79,484		$	51,559		$	216,521		$	160,368
Contract drilling	15,032			18,580			16,872			47,934			36,846
Gas gathering and processing	14,356			14,689			13,283			43,485			38,631
Total operating profit	99,288			112,753			81,714			307,940			235,845
Depreciation, depletion and amortization	(58,373		)	(63,537		)	(54,533		)	(178,976		)	(151,545		)
Total operating income	40,915			49,216			27,181			128,964			84,300
General and administrative	(8,712		)	(9,278		)	(9,235		)	(28,752		)	(26,902		)
Gain on disposition of assets	161			253			81			575			1,153
Interest, net	(7,729		)	(7,945		)	(9,944		)	(25,678		)	(28,807		)
Gain (loss) on derivatives	(14,461		)	(4,385		)	(2,614		)	(25,608		)	21,019
Other	5			6			5			17			14
Income before income taxes	$	10,179		$	27,867		$	5,474		$	49,518		$	50,777

_________________

The Company has included segment operating profit because:


•	It considers segment operating profit to be an important supplemental measure of operating performance for presenting trends in its core businesses.


•	Segment operating profit is useful to investors because it provides a means to evaluate the operating performance of the segments and company on an ongoing basis using the criteria used by management.

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,
	2018		2018		2017		2018		2017
	(In thousands except for operating days and operating margins)
Contract drilling revenue	$	46,926	$	50,612	$	51,619	$	143,527	$	128,059
Contract drilling operating cost	31,894		32,032		34,747		95,593		91,213
Operating profit from contract drilling	15,032		18,580		16,872		47,934		36,846
Add:
Elimination of intercompany rig profit and bad debt expense	814		1,186		602		2,434		977
Operating profit from contract drilling before elimination of intercompany rig profit and bad debt expense	15,846		19,766		17,474		50,368		37,823
Contract drilling operating days	2,928		3,142		3,180		8,919		8,097
Average daily operating margin before elimination of intercompany rig profit and bad debt expense	$	5,412	$	6,291	$	5,495	$	5,647	$	4,671

________________

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,
	2018		2017
	(In thousands)
Net cash provided by operating activities	$	236,535	$	184,792
Net change in operating assets and liabilities	17,158		10,120
Cash flow from operations before changes in operating assets and liabilities	$	253,693	$	194,912

________________

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 by other companies in the industry) to measure the company’s ability to generate cash used to fund its business activities internally.


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

Unit Corporation

Reconciliation of Adjusted EBITDA



	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2018			2017			2018			2017
	(In thousands except earnings per share)

Net income	$	21,123		$	3,705		$	37,138		$	28,693
Income taxes	6,744			1,769			12,380			22,084
Depreciation, depletion and amortization	63,537			54,533			178,976			151,545
Interest, net	7,945			9,944			25,678			28,807
(Gain) loss on derivatives	4,385			2,614			25,608			(21,019		)
Settlements during the period of matured derivative contracts	(9,112		)	840			(18,040		)	(729		)
Stock compensation plans	5,324			4,412			17,397			12,478
Other non-cash items	(717		)	654			(1,841		)	2,112
Gain on disposition of assets	(253		)	(81		)	(575		)	(1,153		)
Adjusted EBITDA	98,976			78,390			276,721			222,818
Adjusted EBITDA attributable to non-controlling interest	8,154			—			15,173			—
Adjusted EBITDA attributable to Unit Corporation	$	90,822		$	78,390		$	261,548		$	222,818

Diluted income per share attributable to Unit	$	0.36		$	0.07		$	0.62		$	0.56
Diluted earnings per share from income taxes	0.13			0.03			0.23			0.43
Diluted earnings per share from depreciation, depletion and amortization	1.09			1.06			3.18			2.93
Diluted earnings per share from interest, net	0.14			0.19			0.48			0.56
Diluted earnings per share from (gain) loss on derivatives	0.08			0.05			0.49			(0.41		)
Diluted earnings per share from settlements during the period of matured derivative contracts	(0.17		)	0.02			(0.34		)	(0.01		)
Diluted earnings per share from stock compensation plans	0.10			0.08			0.33			0.24
Diluted earnings per share from other non-cash items	(0.01		)	0.01			(0.02		)	0.04
Diluted earnings per share from gain on disposition of assets	(0.01		)	—			(0.01		)	(0.02		)
Adjusted EBITDA per diluted share	$	1.71		$	1.51		$	4.96		$	4.32

________________

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.


•	It provides a means to assess the ability of the Company to generate cash sufficient to pay interest on its indebtedness.

UNIT CORP - FORM 8-K - EX-99.1 - EXHIBIT 99.1 PRESS RELEASE - November 6, 2018

Attached files

UNIT CORP Reports