EX-99.1 2 a2q19991pressrelease.htm EX-99.1 PRESS RELEASE Document


NewsUNIT 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
August 6, 2019

UNIT CORPORATION REPORTS 2019 SECOND QUARTER RESULTS

Tulsa, Oklahoma . . . 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 14th 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.”



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."

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"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 EndedThree Months EndedSix Months Ended
Jun 30, 2019Jun 30, 2018ChangeJun 30, 2019Mar 31, 2019ChangeJun 30, 2019Jun 30, 2018Change
Oil Production, MBbl726 693 5%  726 688 6%  1,414 1,429 (1)% 
NGLs Production, MBbl1,210 1,230 (2)% 1,210 1,207 —%  2,417 2,425 —%  
Natural Gas Production, Bcf13.3 13.7 (3)% 13.3 13.4 (1)% 26.7 27.2 (2)% 
Production, MBoe4,151 4,212 (1)% 4,151 4,123 1%  8,274 8,393 (1)% 
Production, MBoe/day45.6 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 14th 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.”

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This table illustrates certain comparative results for the periods indicated:
Three Months EndedThree Months EndedSix Months Ended
Jun 30, 2019Jun 30, 2018ChangeJun 30, 2019Mar 31,
2019		ChangeJun 30, 2019Jun 30, 2018Change
Rigs Utilized28.6 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 EndedThree Months EndedSix Months Ended
Jun 30,
2019		Jun 30,
2018		ChangeJun 30,
2019		Mar 31,
2019		ChangeJun 30, 2019Jun 30, 2018Change
Gas Gathering, Mcf/day465,714 391,047 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.

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_____________________________________________________

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.
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Unit Corporation
Selected Financial Highlights
(In thousands except per share amounts)
 Three Months EndedSix Months Ended
 June 30,June 30,
 2019 2018 2019 2018 
Statement of Operations:   
Revenues:   
Oil and natural gas77,815 102,318 163,910 205,417 
Contract drilling43,037 46,926 94,192 92,915 
Gas gathering and processing44,294 54,059 96,735 110,103 
Total revenues165,146 203,303 354,837 408,435 
Expenses: 
Operating costs: 
Oil and natural gas36,242 32,418 68,956 68,380 
Contract drilling29,308 31,894 60,709 63,561 
Gas gathering and processing32,491 39,703 71,846 81,307 
Total operating costs98,041 104,015 201,511 213,248 
Depreciation, depletion, and amortization66,292 58,373 128,418 115,439 
General and administrative10,064 8,712 19,805 19,474 
(Gain) loss on disposition of assets(422)(161)1,193 (322)
Total operating expenses173,975 170,939 350,927 347,839 
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 derivatives7,927 (14,461)995 (21,223)
Other6 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 interest492 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:   
Basic52,930 52,050 52,744 51,891 
Diluted52,930 52,781 52,744 52,542 






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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 


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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 EndedSix 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.


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Unit Corporation
Reconciliation of Segment Operating Profit
Three Months EndedSix 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 drilling19,754 13,729 15,032 33,483 29,354 
Gas gathering and processing13,086 11,803 14,356 24,889 28,796 
Total operating profit86,221   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)
Other5 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 EndedSix 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 cost31,401 29,308 31,894 60,709 63,561 
Operating profit from contract drilling19,754   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 days2,822 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.




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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 EndedSix 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 amortization66,292 58,373 128,418 115,439 
Interest, net8,995 7,729 17,533 17,733 
(Gain) loss on derivatives (7,927)14,461 (995)21,223 
Settlements during the period of matured derivative contracts2,658 (6,855)5,314 (8,928)
Stock compensation plans6,053 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 EBITDA65,725 88,598 149,862 177,745 
Adjusted EBITDA attributable to non-controlling interest6,474 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 amortization1.14 1.00 2.21 2.09 
Diluted earnings per share from interest, net0.18 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 
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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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