194 0 Kommentare Unit Corporation Reports 2019 Second Quarter Results

Unit Corporation (NYSE: UNT) today reported its financial and operational results for the second quarter of 2019. Operational highlights include:

Oil and natural gas segment:

Exploration efforts continue to focus on increasing oil production with second quarter 2019 oil production increasing 6% over first quarter 2019.
In the Red Fork play, the Wingard Farms 2128 well's peak 24-hour IP was 2,850 barrels of oil equivalent (Boe) (80% oil).
In the Red Fork play, the Schrock 2215 well, which started production in October 2018, is producing 600 Boe per day (52% oil) and has cumulatively produced 420 thousand barrels of oil equivalent (MBoe) as of June 30, 2019.
Approximately 2,100 net acres were added to the Penn Sands prospect area inclusive of both Marchand and Red Fork prospects.

Contract drilling segment:

BOSS drilling rigs continue to be 100% contracted.
Obtained a long-term contract with an operator to build the 14^th BOSS drilling rig. The operator for this new rig also agreed to long-term extensions on two existing BOSS drilling rigs.

Mid-stream segment:

Completed the installation of the new 60 million cubic feet (MMcf) per day Reeding processing plant on the Cashion system.
The Cashion system throughput volumes increased by 27% over the second quarter of 2018.
During the first half of 2019, a new well pad was added to the Pittsburgh Mills gathering system resulting in an 82% increase in throughput volume over the second quarter of 2018.

MANAGEMENT COMMENTS

Larry Pinkston, Chief Executive Officer and President, said: “We begin each year setting our capital expenditures budget based on what we then anticipate our cash flow for the year will be. For 2019, we projected a budget range of $336 million to $422 million for the year, consistent with our projected cash flow. At this point in the year and given current commodity prices, we anticipate that both our cash flow and our capital expenditures will end up at the low end of our budget range.

"We concentrated our oil and natural gas segment capital expenditures during the first half of the year so we would have the time needed to allow the new wells to be completed and producing by year-end. Consequently (and by design), borrowings under our bank credit agreement increased during the first and second quarters. Having, for the most part, completed our intended exploration operations, our plans are to now substantially reduce those borrowings by year-end.”

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SECOND QUARTER 2019 FINANCIAL RESULTS

Net loss attributable to Unit for the quarter was $8.5 million, or $0.16 per diluted share, compared to net income attributable to Unit of $5.8 million, or $0.11 per diluted share, for the second quarter of 2018. Adjusted net loss attributable to Unit (which excludes the effect of non-cash commodity derivatives) for the quarter was $12.9 million, or $0.24 per diluted share, as compared to adjusted net income attributable to Unit of $11.3 million, or $0.21 per diluted share, for the same quarter for 2018 (see non-GAAP financial measures below). The loss is primarily attributable to the deterioration in realized natural gas liquids (NGLs) prices and natural gas prices experienced during the quarter. Total revenues for the quarter were $165.1 million (47% oil and natural gas, 26% contract drilling, and 27% mid-stream), compared to $203.3 million (50% oil and natural gas, 23% contract drilling, and 27% mid-stream) for the second quarter of 2018. Adjusted EBITDA attributable to Unit was $59.3 million, or $1.12 per diluted share (see non-GAAP financial measures below).

For the first six months of 2019, net loss attributable to Unit was $12.0 million, or $0.23 per diluted share, compared to net income attributable to Unit of $13.7 million, or $0.26 per diluted share, for the first six months of 2018. Adjusted net loss attributable to Unit (which excludes the effect of non-cash commodity derivatives) was $8.4 million, or $0.16 per diluted share, as compared to adjusted net income attributable to Unit of $22.4 million, or $0.43 per diluted share, for the same period for 2018 (see non-GAAP financial measures below). Total revenues for the first six months were $354.8 million (46% oil and natural gas, 27% contract drilling, and 27% mid-stream), compared to $408.4 million (50% oil and natural gas, 23% contract drilling, and 27% mid-stream) for the first six months of 2018. Adjusted EBITDA attributable to Unit for the first six months was $136.4 million, or $2.59 per diluted share (see non-GAAP financial measures below).

OIL AND NATURAL GAS SEGMENT INFORMATION

For the quarter, total equivalent production was 4.2 million barrels of oil equivalent (MMBoe), a 1% increase over the first quarter of 2019. Oil and NGLs production represented 47% of total equivalent production. Oil production was 7,979 barrels per day, an increase of 4% over the first quarter of 2019. NGLs production was 13,298 barrels per day, a 1% decrease from the first quarter of 2019. Natural gas production was 146.0 MMcf per day, a 2% decrease from the first quarter of 2019. Total equivalent production for the first six months of 2019 was 8.3 MMBoe.

Unit’s average realized per barrel equivalent price for the quarter was $18.75, a 10% decrease from the first quarter of 2019. Unit’s average natural gas price was $1.86 per Mcf, a decrease of 26% from the first quarter of 2019. Unit’s average oil price was $59.94 per barrel, an increase of 6% over the first quarter of 2019. Unit’s average NGLs price was $12.52 per barrel, a decrease of 22% from the first quarter of 2019. All prices in this paragraph include the effects of derivative contracts.

Unit continued to focus on increasing oil production for the quarter. At year-end 2018, oil represented slightly over 17% of Unit's production stream. Unit's expectation is to increase oil production to approximately 19% to 20% by year-end. As such, capital has been deployed in a fashion to provide the best opportunity to achieve this objective.

In the Penn Sands prospect in western Oklahoma, during the quarter, Unit completed the Wingard 1522 #2HX, a Red Fork well that had been drilled to a 7,500-foot lateral length. Following completion, during the drill out, it was determined that the casing had collapsed. The well was brought on-line with an open lateral of only about 1,500 feet and had an IP30 of 413 Boe per day from approximately 20% of the intended lateral length. At the end of the quarter, Unit completed and brought on-line the Wingard Farms 2128 1HX, a Red Fork well in the same play. The Wingard Farms had a peak 24-hour IP rate of approximately 2,850 Boe with an oil cut of approximately 80%. Unit currently has three additional Red Fork wells in various stages of completion.

In the Gulf Coast area, Unit continued delineation of its Shoal Creek prospect with the drilling of its successful Blackstone G #3 well currently flowing at 3.0 MMcf of natural gas per day and 175 barrels of oil per day. Also, the Blackstone G #3 has three up-hole intervals that have not been completed yet. During the quarter, Unit continued drilling in this prospect with two additional delineation wells, the Sentinel #1 and the Guardian #1, which are currently in the early stages of completion.

Pinkston said: “Our oil and natural gas segment's focus remains on expanding on our favorable results in western Oklahoma in both our Red Fork and SOHOT prospect areas. This allows us to increase our oil production and our footprint in a very cost-effective manner.

"As previously stated, it is our objective to maintain a capital budget in-line with anticipated cash flows. As a result, the oil and natural gas segment currently has no rigs operating, which is down from a peak of six during the first half of the year. By design, our acreage positions in our various prospect areas are over 80% held by production. This allows us to govern our drilling pace by our cash flow and not lease expiration.

"We expect year-over-year production for 2019 to be 17.0 MMBoe to 17.2 MMBoe, which is consistent with our capital expenditures being at the low end of our guidance coupled with the first quarter third-party plant shut-down impact of our Wilcox play production."

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

	Three Months Ended					Three Months Ended					Six Months Ended
	Jun 30, 2019		Jun 30, 2018		Change	Jun 30, 2019		Mar 31, 2019		Change	Jun 30, 2019		Jun 30, 2018		Change
Oil Production, MBbl	726		693		5%	726		688		6%	1,414		1,429		(1)%
NGLs Production, MBbl	1,210		1,230		(2)%	1,210		1,207		—%	2,417		2,425		—%
Natural Gas Production, Bcf	13.3		13.7		(3)%	13.3		13.4		(1)%	26.7		27.2		(2)%
Production, MBoe	4,151		4,212		(1)%	4,151		4,123		1%	8,274		8,393		(1)%
Production, MBoe/day	45.6		46.3		(1)%	45.6		45.8		—%	45.7		46.4		(1)%
Avg. Realized Natural Gas Price, Mcf ⁽¹⁾	$	1.86	$	2.18	(15)%	$	1.86	$	2.52	(26)%	$	2.18	$	2.40	(9)%
Avg. Realized NGL Price, Bbl ⁽¹⁾	$	12.52	$	22.18	(44)%	$	12.52	$	16.06	(22)%	$	14.11	$	21.65	(35)%
Avg. Realized Oil Price, Bbl ⁽¹⁾	$	59.94	$	56.46	6%	$	59.94	$	56.29	6%	$	58.16	$	55.76	4%
Avg. Price / Boe for Revenue Recognition	$	(1.17)	$	(0.89)	(31)%	$	(1.17)	$	(1.36)	14%	$	(1.26)	$	(0.82)	(54)%
Realized Price / Boe ⁽¹⁾	$	18.75	$	21.98	(15)%	$	18.75	$	20.92	(10)%	$	19.83	$	22.70	(13)%
Operating Profit Before Depreciation, Depletion, & Amortization (MM) ⁽²⁾	$	41.6	$	69.9	(41)%	$	41.6	$	53.4	(22)%	$	95.0	$	137.0	(31)%

(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. (See non-GAAP financial measures below.)

CONTRACT DRILLING SEGMENT INFORMATION

Unit’s average number of drilling rigs working during the quarter was 28.6, a decrease of 9% from the first quarter of 2019. Per day drilling rig rates averaged $18,491, a 1% increase over the first quarter of 2019. For the first six months of 2019, per day drilling rig rates averaged $18,412, a 7% increase over the first six months of 2018. Average per day operating margin for the quarter was $5,526 (before elimination of intercompany drilling rig profit of $0.7 million). This compares to first quarter 2019 average operating margin of $7,376 (before elimination of intercompany drilling rig profit of $1.1 million), a decrease of 25%, or $1,850. Average operating margins for the first quarter included early termination fees of approximately $4.8 million, or $1,684 per day, from the cancellation of certain third-party long-term contracts. Average per day operating margin for the first six months of 2019 was $6,488 (before elimination of intercompany drilling rig profit of $1.7 million). This compares to the first six months of 2018 average operating margin of $5,298 (before elimination of intercompany drilling rig profit of $1.2 million), an increase of 22%, or $1,190 (in each case regarding eliminating intercompany drilling rig profit - see non-GAAP financial measures below). Average operating margins for the first six months included early termination fees of approximately $4.8 million, or $875 per day, from the cancellation of certain third-party long-term contracts.

Pinkston said: “Our BOSS drilling rigs continue to maintain 100% utilization. We obtained a long-term contract for our 14^th BOSS drilling rig, which is currently under construction. The operator that contracted the drilling rig also agreed to long-term extensions of the contracts for two other BOSS drilling rigs that they are currently operating. Term contracts (contracts with original terms ranging from six months to three years in length) are in place for 14 of our drilling rigs at the end of the quarter. Of the 14 contracts, two are up for renewal in the third quarter of 2019, four in the fourth quarter, five in 2020, and three after 2020.”

This table illustrates certain comparative results for the periods indicated:

	Three Months Ended					Three Months Ended					Six Months Ended
	Jun 30, 2019		Jun 30, 2018		Change	Jun 30, 2019		Mar 31, 2019		Change	Jun 30, 2019		Jun 30, 2018		Change
Rigs Utilized	28.6		32.2		(11)%	28.6		31.4		(9)%	30.0		31.9		(6)%
Operating Profit Before Depreciation (MM)⁽¹⁾	$	13.7	$	15.0	(9)%	$	13.7	$	19.8	(31)%	$	33.5	$	29.4	14%

(1)

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

MID-STREAM SEGMENT INFORMATION

For the quarter, gas processed, gas gathered, and liquids sold volumes per day increased by 2%, 4%, and 9%, respectively, as compared to the first quarter of 2019. Operating profit (as defined in the footnote below) for the quarter was $11.8 million, a 10% decrease from the first quarter of 2019.

For the first six months of 2019, gas processed, gas gathered, and liquids sold volumes per day increased 5%, 20%, and 9%, respectively, as compared to the first six months of 2018. Operating profit (as defined in the footnote below) for the first six months of 2019 was $24.9 million, a decrease of 14% from the first six months of 2018.

This table illustrates certain comparative results for the periods indicated:

	Three Months Ended					Three Months Ended					Six Months Ended
	Jun 30, 2019		Jun 30, 2018		Change	Jun 30, 2019		Mar 31, 2019		Change	Jun 30, 2019		Jun 30, 2018		Change
Gas Gathering, Mcf/day	465,714		391,047		19%	465,714		449,916		4%	457,859		382,005		20%
Gas Processing, Mcf/day	165,682		160,506		3%	165,682		161,748		2%	163,725		155,799		5%
Liquids Sold, Gallons/day	711,192		676,503		5%	711,192		650,614		9%	681,070		627,305		9%
Operating Profit Before Depreciation & Amortization (MM) ⁽¹⁾	$	11.8	$	14.4	(18)%	$	11.8	$	13.1	(10)%	$	24.9	$	28.8	(14)%

(1)

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

Pinkston said: “The mid-stream segment completed the installation of the new 60 MMcf per day Reeding processing plant, which was added to the Cashion system. This system has seen a strong increase in throughput volume on a year-over-year basis, having enjoyed the benefit of the activity levels of three third-party operators in the area. Our Pittsburgh Mills gathering system has also realized a strong increase in throughput volumes because of a third-party operator's addition of the Miller pad.”

FINANCIAL INFORMATION

Unit ended the quarter with long-term debt of $756.6 million, consisting of $645.6 million in senior subordinated notes (net of unamortized discount and debt issuance costs), $103.5 million in borrowings under the Unit credit agreement, and $7.5 million in borrowings under the Superior credit facility. The Unit credit agreement was re-determined in April and is subject to an elected commitment and borrowing base of $425 million. The Superior credit agreement has a facility size of $200 million.

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 second quarter earnings conference call live over the Internet on August 6, 2019, 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				Six Months Ended
	June 30,				June 30,
	2019		2018		2019		2018
Statement of Operations:
Revenues:
Oil and natural gas	77,815		102,318		163,910		205,417
Contract drilling	43,037		46,926		94,192		92,915
Gas gathering and processing	44,294		54,059		96,735		110,103
Total revenues	165,146		203,303		354,837		408,435
Expenses:
Operating costs:
Oil and natural gas	36,242		32,418		68,956		68,380
Contract drilling	29,308		31,894		60,709		63,561
Gas gathering and processing	32,491		39,703		71,846		81,307
Total operating costs	98,041		104,015		201,511		213,248
Depreciation, depletion, and amortization	66,292		58,373		128,418		115,439
General and administrative	10,064		8,712		19,805		19,474
(Gain) loss on disposition of assets	(422)		(161)		1,193		(322)
Total operating expenses	173,975		170,939		350,927		347,839

Income (loss) from operations	(8,829)		32,364		3,910		60,596

Other income (expense):
Interest, net	(8,995)		(7,729)		(17,533)		(17,733)
Gain (loss) on derivatives	7,927		(14,461)		995		(21,223)
Other	6		5		11		11
Total other income (expense)	(1,062)		(22,185)		(16,527)		(38,945)

Income (loss) before income taxes	(9,891)		10,179		(12,617)		21,651

Income tax expense (benefit):
Deferred	(1,874)		2,029		(2,318)		5,636
Total income taxes	(1,874)		2,029		(2,318)		5,636

Net income (loss)	(8,017)		8,150		(10,299)		16,015
Net income attributable to non-controlling interest	492		2,362		1,714		2,362
Net income (loss) attributable to Unit Corporation	$	(8,509)	$	5,788	$	(12,013)	$	13,653

Net income (loss) attributable to Unit Corporation per common share:
Basic	$	(0.16)	$	0.11	$	(0.23)	$	0.26
Diluted	$	(0.16)	$	0.11	$	(0.23)	$	0.26

Weighted average shares outstanding:
Basic	52,930		52,050		52,744		51,891
Diluted	52,930		52,781		52,744		52,542


Unit Corporation
Selected Financial Highlights-continued
(In thousands)

	June 30,		December 31,
	2019		2018
Balance Sheet Data:
Current assets	$	130,585	$	170,359
Total assets	$	2,793,529	$	2,698,053
Current liabilities	$	194,710	$	213,859
Long-term debt	$	756,590	$	644,475
Other long-term liabilities and non-current derivative liability	$	106,512	$	101,527
Deferred income taxes	$	142,485	$	144,748
Total shareholders’ equity attributable to Unit Corporation	$	1,593,232	$	1,593,444

	Six Months Ended June 30,
	2019		2018
Statement of Cash Flows Data:
Cash flow from operations before changes in operating assets and liabilities	$	133,449	$	161,858
Net change in operating assets and liabilities	(5,948)		(2,218)
Net cash provided by operating activities	$	127,501	$	159,640
Net cash used in investing activities	$	(242,611)	$	(167,350)
Net cash provided by financing activities	$	109,327	$	111,317

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 (loss) and earnings (loss) per share excluding 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 are reconciliations of GAAP financial measures to non-GAAP financial measures for the periods below. 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 (Loss) and Adjusted Diluted Earnings per Share


	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2019		2018		2019		2018
	(In thousands except earnings per share)
Adjusted net income (loss) attributable to Unit Corporation:
Net income (loss) attributable to Unit Corporation	$	(8,509)	$	5,788	$	(12,013)	$	13,653
(Gain) loss on derivatives (net of income tax)	(6,638)		10,386		(836)		15,022
Settlements during the period of matured derivative contracts (net of income tax)	2,232		(4,898)		4,456		(6,319)
Adjusted net income (loss) attributable to Unit Corporation	$	(12,915)	$	11,276	$	(8,393)	$	22,356

Adjusted diluted earnings (loss) attributable to Unit Corporation per share:
Diluted earnings (loss) per share	$	(0.16)	$	0.11	$	(0.23)	$	0.26
Diluted earnings (loss) per share from (gain) loss on derivatives	(0.12)		0.19		(0.02)		0.29
Diluted earnings (loss) per share from settlements of matured derivative contracts	0.04		(0.09)		0.09		(0.12)
Adjusted diluted income (loss) per share attributable to Unit	$	(0.24)	$	0.21	$	(0.16)	$	0.43

Weighted shares (denominator)	52,930		52,781		52,744		52,542

________________

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						Six Months Ended
	March 31,		June 30,				June 30,
	2019		2019		2018		2019		2018
	(In thousands)
Oil and natural gas	$	53,381	$	41,573	$	69,900	$	94,954	$	137,037
Contract drilling	19,754		13,729		15,032		33,483		29,354
Gas gathering and processing	13,086		11,803		14,356		24,889		28,796
Total operating profit	86,221		67,105		99,288		153,326		195,187
Depreciation, depletion and amortization	(62,126)		(66,292)		(58,373)		(128,418)		(115,439)
Total operating income	24,095		813		40,915		24,908		79,748
General and administrative	(9,741)		(10,064)		(8,712)		(19,805)		(19,474)
Gain (loss) on disposition of assets	(1,615)		422		161		(1,193)		322
Interest, net	(8,538)		(8,995)		(7,729)		(17,533)		(17,733)
Gain (loss) on derivatives	(6,932)		7,927		(14,461)		995		(21,223)
Other	5		6		5		11		11
Income (loss) before income taxes	$	(2,726)	$	(9,891)	$	10,179	$	(12,617)	$	21,651

_________________

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 using the criteria used by management.


Unit Corporation
Reconciliation of Average Daily Operating Margin Before Elimination of Intercompany Rig Profit
	Three Months Ended						Six Months Ended
	March 31,		June 30,				June 30,
	2019		2019		2018		2019		2018
	(In thousands except for operating days and operating margins)
Contract drilling revenue	$	51,155	$	43,037	$	46,926	$	94,192	$	92,915
Contract drilling operating cost	31,401		29,308		31,894		60,709		63,561
Operating profit from contract drilling	19,754		13,729		15,032		33,483		29,354
Add:
Elimination of intercompany rig profit	1,060		654		814		1,714		1,248
Operating profit from contract drilling before elimination of intercompany rig profit	20,814		14,383		15,846		35,197		30,602
Contract drilling operating days	2,822		2,603		2,928		5,425		5,778
Average daily operating margin before elimination of intercompany rig profit	$	7,376	$	5,526	$	5,412	$	6,488	$	5,296

________________

The company has included the average daily operating margin before elimination of intercompany rig profit 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.
Average operating margins for the first quarter and six months of 2019 included early termination fees of approximately $4.8 million, or $1,684 per day and $875 per day, respectively, from the cancellation of certain third-party long-term contracts.


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

	Six Months Ended June 30,
	2019		2018
	(In thousands)
Net cash provided by operating activities	$	127,501	$	159,640
Net change in operating assets and liabilities	(5,948)		(2,218)
Cash flow from operations before changes in operating assets and liabilities	$	133,449	$	161,858

________________

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 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 Adjusted EBITDA
	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2019		2018		2019		2018
	(In thousands except earnings per share)

Net income (loss)	$	(8,017)	$	8,150	$	(10,299)	$	16,015
Income taxes	(1,874)		2,029		(2,318)		5,636
Depreciation, depletion and amortization	66,292		58,373		128,418		115,439
Interest, net	8,995		7,729		17,533		17,733
(Gain) loss on derivatives	(7,927)		14,461		(995)		21,223
Settlements during the period of matured derivative contracts	2,658		(6,855)		5,314		(8,928)
Stock compensation plans	6,053		5,464		11,187		12,073
Other non-cash items	(33)		(592)		(171)		(1,124)
(Gain) loss on disposition of assets	(422)		(161)		1,193		(322)
Adjusted EBITDA	65,725		88,598		149,862		177,745
Adjusted EBITDA attributable to non-controlling interest	6,474		7,019		13,497		7,019
Adjusted EBITDA attributable to Unit Corporation	$	59,251	$	81,579	$	136,365	$	170,726

Diluted earnings (loss) per share attributable to Unit	$	(0.16)	$	0.11	$	(0.23)	$	0.26
Diluted earnings per share from income taxes	(0.04)		0.04		(0.04)		0.11
Diluted earnings per share from depreciation, depletion and amortization	1.14		1.00		2.21		2.09
Diluted earnings per share from interest, net	0.18		0.15		0.33		0.34
Diluted earnings per share from (gain) loss on derivatives	(0.15)		0.27		(0.02)		0.40
Diluted earnings per share from settlements during the period of matured derivative contracts	0.05		(0.13)		0.10		(0.17)
Diluted earnings per share from stock compensation plans	0.11		0.10		0.21		0.23
Diluted earnings per share from other non-cash items	—		0.01		0.01		—
Diluted earnings per share from (gain) loss on disposition of assets	(0.01)		—		0.02		(0.01)
Adjusted EBITDA per diluted share	$	1.12	$	1.55	$	2.59	$	3.25

Weighted shares (denominator)	52,930		52,781		52,744		52,542

________________

The company has included the adjusted EBITDA, which excludes gain or loss on disposition of assets and includes only the cash-settled commodity derivatives because:

It uses adjusted EBITDA to evaluate the operational performance of the company.
Adjusted EBITDA is more comparable to estimates provided by securities analysts.

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