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
August 9, 2018

UNIT CORPORATION REPORTS 2018 SECOND QUARTER RESULTS

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

Net income attributable to Unit of $5.8 million; adjusted net income attributable to Unit of $11.3 million, a 216% increase over second quarter 2017 adjusted net income.
Oil and natural gas segment production increased 1% over first quarter 2018 and 9% over the second quarter 2017.
Delineation wells in the Wing and Brandt Prospects in Unit's Wilcox play have provided very promising results. Further delineation work continues.
Contract drilling segment completed construction of its 11th BOSS drilling rig placed into service following the end of the quarter.
The 12th BOSS rig is under construction, and a new contract has been signed for the construction of the 13th BOSS rig, both with initial multi-year terms. The 12th and 13th BOSS rigs are expected to be placed into service in the first quarter of 2019.
Thirty-five drilling rigs are operating; all eleven BOSS drilling rigs are under contract.
On April 3, 2018, Unit completed the sale of 50% of the ownership interests in Superior Pipeline Company LLC (Superior) to SP Investor Holdings, LLC for cash consideration of $300 million. The effective date of the sale was April 1st. 
During the second quarter, Superior signed a five-year $200 million senior secured credit facility.
Midstream segment gas processed, gas gathered, and liquids sold volumes per day increased 6%, 5%, and 17%, respectively, as compared to the first quarter of 2018.
Midstream segment began construction of its new Reeding gas processing plant near Cashion, Oklahoma.


SECOND QUARTER 2018 FINANCIAL RESULTS
Unit recorded net income attributable to Unit of $5.8 million for the quarter, or $0.11 per diluted share, compared to net income attributable to Unit of $9.1 million, or $0.17 per share, for the second quarter of 2017. Adjusted net income attributable to Unit (which excludes the effect of non-cash commodity derivatives) for the quarter was $11.3 million, or $0.21 per diluted share, as compared to $0.07 per diluted share for the same quarter for 2017, a 216% increase (see Non-GAAP financial measures below). Total revenues for the quarter were $203.3 million (50% oil and natural gas, 23% contract drilling, and 27% midstream), compared to $170.6 million (49% oil and natural gas, 23% contract drilling, and 28% midstream) for the second quarter of 2017. Adjusted EBITDA attributable to Unit was $81.6 million, or $1.55 per diluted share (see Non-GAAP financial measures below).

For the first six months of 2018, Unit recorded net income attributable to Unit of $13.7 million, or $0.26 per diluted share, compared to net income attributable to Unit of $25.0 million, or $0.49 per share, for the first six months of 2017. Unit recorded adjusted net income attributable to Unit (which excludes the effect of non-cash commodity derivatives) of $22.4 million, or $0.43 per diluted share, as compared to $0.22 per diluted share for the same period for 2017, a 102% increase (see Non-GAAP financial measures below). Total revenues for the first six months were $408.4 million (50% oil and natural gas,

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23% contract drilling, and 27% midstream), compared to $346.3 million (49% oil and natural gas, 22% contract drilling, and 29% midstream) for the first six months of 2017. Adjusted EBITDA attributable to Unit for the first six months was $170.7 million, or $3.25 per diluted share (see Non-GAAP financial measures below).



OIL AND NATURAL GAS SEGMENT INFORMATION
For the quarter, equivalent production was 4.2 million barrels of oil equivalent (MMBoe), a 1% increase over the first quarter of 2018. Oil and natural gas liquids (NGLs) production represented 46% of total equivalent production. Oil production was 7,614 barrels per day, a decrease of 7% from the first quarter of 2018. NGLs production was 13,516 barrels per day, a 2% increase over the first quarter of 2018. Natural gas production was 150,965 thousand cubic feet (Mcf) per day, a 1% increase over the first quarter of 2018. Per day equivalent production for the first six months of 2018 was 46.4 thousand barrels of oil equivalent (MBoe).

Unit’s average realized per barrel equivalent price for the quarter was $22.87, a 5% decrease from the first quarter of 2018. Unit’s average natural gas price was $2.18 per Mcf, a decrease of 17% from the first quarter of 2018. Unit’s average oil price was $56.46 per barrel, an increase of 2% over the first quarter of 2018. Unit’s average NGLs price was $22.18 per barrel, an increase of 5% over the first quarter of 2018. All prices in this paragraph include the effects of derivative contracts.

During the quarter, production from SOHOT was curtailed due to high line pressures when Enable, Unit’s primary midstream gas gatherer and processor, tied in and commissioned their Wildcat pipeline that takes rich gas from Western Oklahoma to a processing plant in North Texas. Production loss from this event coupled with smaller losses due to downtime at processing plants in Unit’s Houston and Texas Panhandle areas was approximately 90 MBoe for the quarter. Without these losses, second quarter production would have averaged 47.3 MBoe or 2% higher than the first quarter. These factors also affected oil production levels for the quarter. Following the commissioning of the Wildcat Pipeline, line pressures have returned to more normal levels.

In the Gulf Coast Wilcox play, the Wing #18 was drilled and completed in April in the BP Fee “C” sand which lies just beneath the BP Fee and BP Fee “A” sand intervals which, to date, have been the primary producing intervals in the Wing prospect. The Wing #18 initially flowed at rates of 6 MMcf per day and 75 barrels of oil per day with pressure of 5,000 psi. After over three months of production, the well is flowing at rates of 6.5 MMcf per day and 55 barrels of oil per day with over 2,700 psi of pressure. Following the success of the Wing #18 well, Unit drilled and completed the Wing #20. Besides the BP Fee “C” sand in the Wing #18, the Wing #20 found pay in the deeper BP Fee “D” and BP Fee “E” sands and all three intervals were fracture stimulated in June flowing at 7.5 MMcf per day and 80 barrels of oil per day with 3,000 psi of flowing pressure. Unit will test two additional exploration prospects adjacent to the Wing prospect over the next year.

In the Brandt Prospect near Goliad, Texas, the Engel #1, Unit’s successful discovery well completed in December of 2017, has a current flow rate of 6 MMcf per day with 1,000 psi of pressure after seven months of production. The Engel #2 was spud to delineate this discovery in early June and is now in the final stages of the completion. Following the Engel #2, a second delineation well was spud that will be completed in the third quarter. Beyond the Brandt prospect, several additional prospects in the Goliad area have been identified.

In the Texas Panhandle, the Buffalo Wallow field continues to be developed with extended length laterals. Four C(1) wells are being brought online after drilling out frack plugs. Unit also has two additional wells that are awaiting completion. During the quarter, an additional Unit rig was temporarily brought in to drill two Granite Wash G extended length laterals. These wells are offsets to a normal length G lateral drilled in 2014 that has been a strong producer.

In the Southern Oklahoma Hoxbar Oil Trend (SOHOT), the McGuffin #2-19H was completed with an initial rate of 700 barrels of oil per day. Two additional Marchand extended lateral wells are being fracture stimulated. The SOHOT play continues to be Unit’s highest oil weighted play. The curtailments discussed above affected Unit’s oil volumes for the second quarter.

Despite these curtailments in the second quarter, the forecast for 2018 production remains unchanged at 17.1 to 17.4 MMBoe, a 7% to 9% increase over 2017.
    
Pinkston said: “Our oil and natural gas segment is on track to deliver on our original growth plan for the year. We continue to see some very solid well results from our various exploration and development programs. We are particularly pleased with the results we are seeing in the Wilcox. The Gilly discovery originally announced in 2012 has been a tremendous

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resource for Unit. With new development in the area and new prospect identification, we believe this asset can continue to be a continuous contributor to the growth of our E&P business."

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, 2018
Jun 30, 2017
Change
 
Jun 30, 2018
Mar 31, 2018
Change
 
Jun 30, 2018
Jun 30, 2017
Change
Oil and NGLs Production, MBbl
1,923

1,851

4%
 
1,923

1,931

—%
 
3,854

3,590

7%
Natural Gas Production, Bcf
13.7

12.0

14%
 
13.7

13.5

2%
 
27.2

24.2

12%
Production, MBoe
4,212

3,852

9%
 
4,212

4,181

1%
 
8,393

7,629

10%
Production, MBoe/day
46.3

42.3

9%
 
46.3

46.5

—%
 
46.4

42.1

10%
Avg. Realized Natural Gas Price, Mcf (1)
$
2.18

$
2.45

(11)%
 
$
2.18

$
2.62

(17)%
 
$
2.40

$
2.57

(7)%
Avg. Realized NGL Price, Bbl (1)
$
22.18

$
14.91

49%
 
$
22.18

$
21.08

5%
 
$
21.65

$
16.34

32%
Avg. Realized Oil Price, Bbl (1)
$
56.46

$
46.96

20%
 
$
56.46

$
55.10

2%
 
$
55.76

$
47.77

17%
Realized Price / Boe (1)
$
22.87

$
20.76

10%
 
$
22.87

$
24.18

(5)%
 
$
23.52

$
21.44

10%
Operating Profit Before Depreciation, Depletion, & Amortization (MM) (2)
$
69.9

$
50.4

39%
 
$
69.9

$
67.1

4%
 
$
137.0

$
108.8

26%
(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’s average number of drilling rigs working during the quarter was 32.2, an increase of 2% over the first quarter of 2018. Per day drilling rig rates averaged $17,330, a 2% increase over the first quarter of 2018. For the first six months of 2018, per day drilling rig rates averaged $17,184, an 8% increase over the first six months of 2017. Average per day operating margin for the quarter was $5,412 (before elimination of intercompany drilling rig profit of $0.8 million). This compares to first quarter 2018 average operating margin of $5,179 (before elimination of intercompany drilling rig profit of $0.4 million), an increase of 4%, or $233. Average per day operating margin for the first six months of 2018 was $5,296 (before elimination of intercompany drilling rig profit of $1.2 million). This compares to the first six months of 2017 average operating margin of $4,139 (before elimination of intercompany drilling rig profit of $0.3 million), an increase of 28%, or $1,157 (in each case regarding eliminating intercompany drilling rig profit - see Non-GAAP financial measures below).

Pinkston said: “Our contract drilling segment had a very strong quarter. Rig utilization increased to 34 rigs working at the end of the quarter, and currently we have 35 rigs operating. 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 completed and deployed our 11th BOSS rig shortly after the end of the quarter, bringing our total fleet to 96 drilling rigs. Additionally, one of our operators signed two-year contract extensions for two of our existing BOSS rigs. We continue to be very pleased with the BOSS rig performance and customer acceptance. Twenty-five SCR rigs continue to operate, and we continue to have inquiries regarding further utilization. We had ten long-term contracts (contracts with original terms ranging from six months to two years in length) as of the end of the quarter. Of the ten long-term contracts, eight are up for renewal in 2018 and two in 2019. The long-term contracts at the end of the quarter exclude the three new BOSS rig contracts discussed herein.”


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This table illustrates certain comparative results for the periods indicated:
 
Three Months Ended
 
Three Months Ended
 
Six Months Ended
 
Jun 30, 2018
Jun 30, 2017
Change
 
Jun 30, 2018
Mar 31,
2018
Change
 
Jun 30, 2018
Jun 30, 2017
Change
Rigs Utilized
32.2

28.8

12%
 
32.2

31.7

2%
 
31.9

27.2

17%
Operating Profit Before Depreciation (MM)(1)
$
15.0

$
12.0

25%
 
$
15.0

$
14.3

5%
 
$
29.4

$
20.0

47%
(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 processed, gas gathered and liquids sold volumes per day increased 6%, 5%, and 17%, respectively, as compared to the first quarter of 2018. Operating profit (as defined in the footnote below) for the quarter was $14.4 million, which was relatively flat compared to the first quarter of 2018.

For the first six months of 2018, per day gas processed and liquids sold volumes increased 19% and 23%, respectively, while gas gathered volumes per day decreased 1% as compared to the first six months of 2017. Operating profit (as defined in the footnote below) for the first six months of 2018 was $28.8 million, an increase of 14% over the first six months of 2017.

During the second quarter, Superior signed a new senior secured credit facility. The credit agreement is a five-year, $200 million senior secured revolving credit facility with an option to increase the credit amount up to $250 million, subject to certain conditions. Borrowings under the credit facility will fund capital expenditures and acquisitions, provide general working capital, and for letters of credit for Superior.

This table illustrates certain comparative results for the periods indicated:
 
Three Months Ended
 
Three Months Ended
 
Six Months Ended
 
Jun 30,
2018
Jun 30,
2017
Change
 
Jun 30,
2018
Mar 31,
2018
Change
 
Jun 30, 2018
Jun 30, 2017
Change
Gas Gathering, Mcf/day
391,047

383,440

2%
 
391,047

372,862

5%
 
382,005

386,893

(1)%
Gas Processing, Mcf/day
160,506

135,002

19%
 
160,506

151,039

6%
 
155,799

130,804

19%
Liquids Sold, Gallons/day
676,503

525,920

29%
 
676,503

577,560

17%
 
627,305

511,969

23%
Operating Profit Before Depreciation & Amortization (MM) (1)
$
14.4

$
12.1

19%
 
$
14.4

$
14.4

—%
 
$
28.8

$
25.3

14%
(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 second quarter, following the sale of the fifty percent equity stake in the business, we continued setting the stage to grow the midstream business. We have seen growth in gas gathering, processing and liquids sold volumes during the quarter. Throughput volume growth during the quarter was due to Unit Petroleum and third party activity levels. Due to increasing activity levels in the Cashion area of Oklahoma, we have begun construction of our new Reeding gas processing facility. The facility will consist of a 60 MMcf per day processing plant, which is being relocated from our Bellmon facility. The Reeding facility will share the gathering system with our Cashion plant and is expected to be in service in the first quarter of 2019. We continue to look for growth opportunities for the midstream segment. Our new credit facility will provide additional liquidity to execute on prospects we identify.”


FINANCIAL INFORMATION
Unit ended the quarter with cash and cash equivalents of $104.3 million and long-term debt of $643.4 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 April 2, 2018, Unit signed a Fourth Amendment to its credit agreement in

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connection with its sale of the 50% ownership interest in Superior. One condition of the sale was the release of Superior from the Unit credit agreement. The Fourth Amendment also provided for a maximum credit amount, a borrowing base, and an elected commitment all of $425 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 9, 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.

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Unit Corporation
Selected Financial Highlights
(In thousands except per share amounts)
 
 
Three Months Ended
 
Six Months Ended
 
 
June 30,
 
June 30,
 
 
2018
 
2017
 
2018
 
2017
Income Statements:
 
 
 
 
 
 
 
 
Revenues:
 
 
 
 
 
 
 
 
Oil and natural gas
 
$
102,318

 
$
83,173

 
$
205,417

 
$
170,771

Contract drilling
 
46,926

 
39,255

 
92,915

 
76,440

Gas gathering and processing
 
54,059

 
48,153

 
110,103

 
99,094

Total revenues
 
203,303

 
170,581

 
408,435

 
346,305

Expenses:
 
 
 
 
 
 
 
 
Operating costs:
 
 
 
 
 
 
 
 
Oil and natural gas
 
32,418

 
32,758

 
68,380

 
61,962

Contract drilling
 
31,894

 
27,239

 
63,561

 
56,466

Gas gathering and processing
 
39,703

 
36,042

 
81,307

 
73,746

Total operating costs
 
104,015

 
96,039

 
213,248

 
192,174

Depreciation, depletion, and amortization
 
58,373

 
50,080

 
115,439

 
97,012

General and administrative
 
8,712

 
8,713

 
19,474

 
17,667

Gain on disposition of assets
 
(161
)
 
(248
)
 
(322
)
 
(1,072
)
Total operating expenses
 
170,939

 
154,584

 
347,839

 
305,781

 
 
 
 
 
 
 
 
 
Income from operations
 
32,364

 
15,997

 
60,596

 
40,524

 
 
 
 
 
 
 
 
 
Other income (expense):
 
 
 
 
 
 
 
 
Interest, net
 
(7,729
)
 
(9,467
)
 
(17,733
)
 
(18,863
)
Gain (loss) on derivatives
 
(14,461
)
 
8,902

 
(21,223
)
 
23,633

Other
 
5

 
6

 
11

 
9

Total other income (expense)
 
(22,185
)
 
(559
)
 
(38,945
)
 
4,779

 
 
 
 
 
 
 
 
 
Income before income taxes
 
10,179

 
15,438

 
21,651

 
45,303

 
 
 
 
 
 
 
 
 
Income tax expense:
 
 
 
 
 
 
 
 
Deferred
 
2,029

 
6,379

 
5,636

 
20,315

Total income taxes
 
2,029

 
6,379

 
5,636

 
20,315

 
 
 
 
 
 
 
 
 
Net income
 
8,150

 
9,059

 
16,015

 
24,988

Net income attributable to non-controlling interest
 
2,362

 

 
2,362

 

Net income attributable to Unit Corporation
 
$
5,788

 
$
9,059

 
$
13,653

 
$
24,988

 
 
 
 
 
 
 
 
 
Net income attributable to Unit Corporation per common share:
 
 
 
 
 
 
 
 
Basic
 
$
0.11

 
$
0.18

 
$
0.26

 
$
0.49

Diluted
 
$
0.11

 
$
0.17

 
$
0.26

 
$
0.49

 
 
 
 
 
 
 
 
 
Weighted average shares outstanding:
 
 
 
 
 
 
 
 
Basic
 
52,050

 
51,366

 
51,891

 
50,832

Diluted
 
52,781

 
51,944

 
52,542

 
51,371








6



Unit Corporation
Selected Financial Highlights - continued
(In thousands)
 
June 30,
 
December 31,
 
2018
 
2017
 Balance Sheet Data:
 
 
 
 Current assets
$
227,044

 
$
119,672

 Total assets
$
2,749,809

 
$
2,581,452

 Current liabilities
$
200,714

 
$
181,936

 Long-term debt
$
643,371

 
$
820,276

 Other long-term liabilities and non-current derivative liability
$
103,838

 
$
100,203

 Deferred income taxes
$
158,232

 
$
133,477

 Total shareholders’ equity attributable to Unit Corporation
$
1,444,250

 
$
1,345,560

 
Six Months Ended June 30,
 
2018
 
2017
Statement of Cash Flows Data:
 
 
 
Cash flow from operations before changes in operating assets and liabilities
$
161,858

 
$
125,481

Net change in operating assets and liabilities
(7,165
)
 
(8,426
)
Net cash provided by operating activities
$
154,693

 
$
117,055

Net cash used in investing activities
$
(167,350
)
 
$
(142,833
)
Net cash provided by financing activities
$
116,264

 
$
25,734




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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 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 six months ended June 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
 
Six Months Ended
 
 
June 30,
 
June 30,
 
 
2018
 
2017
 
2018
 
2017
 
 
(In thousands except earnings per share)
Adjusted net income attributable to Unit Corporation:
 
 
 
 
 
 
 
 
Net income attributable to Unit Corporation
 
$
5,788

 
$
9,059

 
$
13,653

 
$
24,988

(Gain) loss on derivatives (net of income tax)
 
10,386

 
(5,243
)
 
15,022

 
(13,036
)
Settlements during the period of matured derivative contracts (net of income tax)
 
(4,898
)
 
(252
)
 
(6,319
)
 
(865
)
Adjusted net income attributable to Unit Corporation
 
$
11,276

 
$
3,564

 
$
22,356

 
$
11,087

 
 
 
 
 
 
 
 
 
Adjusted diluted earnings attributable to Unit Corporation per share:
 
 
 
 
 
 
 
 
Diluted earnings per share
 
$
0.11

 
$
0.17

 
$
0.26

 
$
0.49

Diluted earnings per share from (gain) loss on derivatives
 
0.19

 
(0.10
)
 
0.29

 
(0.25
)
Diluted earnings per share from settlements of matured derivative contracts
 
(0.09
)
 

 
(0.12
)
 
(0.02
)
Adjusted diluted income per share
 
$
0.21

 
$
0.07

 
$
0.43

 
$
0.22

 ________________ 
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.



8



Unit Corporation
Reconciliation of Segment Operating Profit
 
 
Three Months Ended
 
Six Months Ended
 
 
March 31,
 
June 30,
 
June 30,
 
 
2018
 
2018
 
2017
 
2018
 
2017
 
 
(In thousands)
Oil and natural gas
 
$
67,137

 
$
69,900

 
$
50,415

 
$
137,037

 
$
108,809

Contract drilling
 
14,322

 
15,032

 
12,016

 
29,354

 
19,974

Gas gathering and processing
 
14,440

 
14,356

 
12,111

 
28,796

 
25,348

Total operating profit
 
95,899

 
99,288

 
74,542

 
195,187

 
154,131

Depreciation, depletion and amortization
 
(57,066
)
 
(58,373
)
 
(50,080
)
 
(115,439
)
 
(97,012
)
       Total operating income
 
38,833

 
40,915

 
24,462

 
79,748

 
57,119

General and administrative
 
(10,762
)
 
(8,712
)
 
(8,713
)
 
(19,474
)
 
(17,667
)
Gain (loss) on disposition of assets
 
161

 
161

 
248

 
322

 
1,072

Interest, net
 
(10,004
)
 
(7,729
)
 
(9,467
)
 
(17,733
)
 
(18,863
)
Gain (loss) on derivatives
 
(6,762
)
 
(14,461
)
 
8,902

 
(21,223
)
 
23,633

Other
 
6

 
5

 
6

 
11

 
9

        Income before income taxes
 
$
11,472

 
$
10,179

 
$
15,438

 
$
21,651

 
$
45,303

_________________
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
 
Six Months Ended
 
 
March 31,
 
June 30,
 
June 30,
 
 
2018
 
2018
 
2017
 
2018
 
2017
 
 
(In thousands except for operating days and operating margins)
Contract drilling revenue
 
$
45,989

 
$
46,926

 
$
39,255

 
$
92,915

 
$
76,440

Contract drilling operating cost
 
31,667

 
31,894

 
27,239

 
63,561

 
56,466

Operating profit from contract drilling
 
14,322

 
15,032

 
12,016

 
29,354

 
19,974

Add:
 
 
 
 
 
 
 
 
 
 
Elimination of intercompany rig profit and bad debt expense
 
434

 
814

 
376

 
1,248

 
376

Operating profit from contract drilling before elimination of intercompany rig profit and bad debt expense
 
14,756

 
15,846

 
12,392

 
30,602

 
20,350

Contract drilling operating days
 
2,849

 
2,928

 
2,625

 
5,778

 
4,916

Average daily operating margin before elimination of intercompany rig profit and bad debt expense
 
$
5,179

 
$
5,412

 
$
4,721

 
$
5,296

 
$
4,139

 ________________ 
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.





9



Unit Corporation
Reconciliation of Cash Flow From Operations Before Changes in Operating Assets and Liabilities
 
Six Months Ended June 30,
 
2018
 
2017
 
(In thousands)
Net cash provided by operating activities
$
154,693

 
$
117,055

Net change in operating assets and liabilities
7,165

 
8,426

Cash flow from operations before changes in operating assets and liabilities
$
161,858

 
$
125,481

 ________________ 
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
 
Six Months Ended
 
 
June 30,
 
June 30,
 
 
2018
 
2017
 
2018
 
2017
 
 
(In thousands except earnings per share)
 
 
 
 
 
 
 
 
 
Net income
 
$
8,150

 
$
9,059

 
$
16,015

 
$
24,988

Income taxes
 
2,029

 
6,379

 
5,636

 
20,315

Depreciation, depletion and amortization
 
58,373

 
50,080

 
115,439

 
97,012

Interest, net
 
7,729

 
9,467

 
17,733

 
18,863

(Gain) loss on derivatives
 
14,461

 
(8,902
)
 
21,223

 
(23,633
)
Settlements during the period of matured derivative contracts
 
(6,855
)
 
(410
)
 
(8,928
)
 
(1,569
)
Stock compensation plans
 
5,464

 
4,362

 
12,073

 
8,066

Other non-cash items
 
(592
)
 
673

 
(1,124
)
 
1,458

Gain on disposition of assets
 
(161
)
 
(248
)
 
(322
)
 
(1,072
)
Adjusted EBITDA
 
88,598

 
70,460

 
177,745

 
144,428

Adjusted EBITDA attributable to non-controlling interest
 
7,019

 

 
7,019

 

Adjusted EBITDA attributable to Unit Corporation
 
$
81,579

 
$
70,460

 
$
170,726

 
$
144,428

 
 
 
 
 
 
 
 
 
Diluted income per share attributable to Unit
 
$
0.11

 
$
0.17

 
$
0.26

 
$
0.49

Diluted earnings per share from income taxes
 
0.04

 
0.12

 
0.11

 
0.40

Diluted earnings per share from depreciation, depletion and amortization
 
1.00

 
0.97

 
2.09

 
1.88

Diluted earnings per share from interest, net
 
0.15

 
0.18

 
0.34

 
0.37

Diluted earnings per share from (gain) loss on derivatives
 
0.27

 
(0.17
)
 
0.40

 
(0.46
)
Diluted earnings per share from settlements during the period of matured derivative contracts
 
(0.13
)
 

 
(0.17
)
 
(0.04
)
Diluted earnings per share from stock compensation plans
 
0.10

 
0.08

 
0.23

 
0.16

Diluted earnings per share from other non-cash items
 
0.01

 
0.01

 

 
0.03

Diluted earnings per share from gain on disposition of assets
 

 

 
(0.01
)
 
(0.02
)
Adjusted EBITDA per diluted share
 
$
1.55

 
$
1.36

 
$
3.25

 
$
2.81

 ________________
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.

10

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