UNT
$16.03
Unit
$.61
3.96%
Earnings Details
2nd Quarter June 2017
Thursday, August 3, 2017 7:00:11 AM
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Summary

Unit (UNT) Recent Earnings

Unit (UNT) reported 2nd Quarter June 2017 earnings of $0.07 per share on revenue of $170.6 million. The consensus earnings estimate was $0.06 per share on revenue of $187.7 million. Revenue grew 23.3% on a year-over-year basis.

Unit Corp engages in land contract drilling of natural gas & oil wells, exploration, development, acquisition and production of oil and natural gas properties. Its activities also include buying, selling, gathering, & processing of natural gas in U.S.

Results
Reported Earnings
$0.07
Earnings Whisper
-
Consensus Estimate
$0.06
Reported Revenue
$170.6 Mil
Revenue Estimate
$187.7 Mil
Growth
Earnings Growth
Revenue Growth
Power Rating
Grade
Earnings Release

Unit Corporation Reports 2017 Second Quarter Results

Unit Corporation (UNT) today reported its financial and operational results for the second quarter 2017. Results and recent highlights include:

-- Net income of $9.1 million.

Oil and natural gas segment production increased 2% over the first quarter of 2017 despite service company frac date delays and third party gathering and processing outages adversely impacting production by 94.0 MBoe.

-- Completed the Hoxbar acquisition.

Potential for over 1,000 drilling locations in the STACK and STACK extension plays.

Construction was completed on the tenth BOSS drilling rig, and it was placed into service late in the quarter.

Thirty-six drilling rigs are currently operating; all ten BOSS drilling rigs are under contract.

Midstream segment increased gathered and processed volumes at its Hemphill and Cashion systems resulting in a liquids sold volume increase of 7% over the first quarter of 2017.

SECOND QUARTER AND FIRST SIX MONTHS 2017 FINANCIAL RESULTS

Unit recorded net income of $9.1 million for the quarter, or $0.17 per diluted share, compared to a net loss of $72.1 million, or $1.44 per share, for the second quarter of 2016. Adjusted net income (which excludes the effect of non-cash commodity derivatives) for the quarter was $3.6 million, or $0.07 per diluted share (see Non-GAAP financial measures below). Total revenues were $170.6 million (49% oil and natural gas, 23% contract drilling, and 28% midstream), compared to $138.3 million (50% oil and natural gas, 18% contract drilling, and 32% midstream) for the second quarter of 2016. Adjusted EBITDA was $71.0 million, or $1.37 per diluted share (see Non-GAAP financial measures below).

For the first six months of 2017, Unit recorded net income of $25.0 million, or $0.49 per diluted share, compared to a net loss of $113.3 million, or $2.27 per share, for the first six months of 2016. Unit recorded adjusted net income (which excludes the effect of non-cash commodity derivatives) of $11.1 million, or $0.22 per diluted share (see Non-GAAP financial measures below). Total revenues for the first six months were $346.3 million (49% oil and natural gas, 22% contract drilling, and 29% midstream), compared to $274.5 million (46% oil and natural gas, 23% contract drilling, and 31% midstream) for the first six months of 2016. Adjusted EBITDA for the first six months was $145.5 million, or $2.83 per diluted share (see Non-GAAP financial measures below).

OIL AND NATURAL GAS SEGMENT INFORMATION

For the quarter, total production was 3.9 million barrels of oil equivalent (MMBoe), a 2% increase over the first quarter of 2017. Liquids (oil and NGLs) production represented 48% of total equivalent production. Oil production was 7,851 barrels per day, an increase of 10% over the first quarter of 2017. NGLs production was 12,486 barrels per day, a 2% increase over the first quarter of 2017. Natural gas production was 131,940 thousand cubic feet (Mcf) per day, a 3% decrease from the first quarter of 2017. Total production for the first six months of 2017 was 7.6 MMBoe. Total production for the quarter was adversely impacted by approximately 94.0 thousand barrels of oil equivalent (MBoe) due to third party gas processing outages and the delay of several frac jobs during the quarter.

Unit’s average realized per barrel equivalent price was $20.76, a 6% decrease from the first quarter of 2017. Unit’s average natural gas price was $2.45 per Mcf, a decrease of 9% from the first quarter of 2017. Unit’s average oil price was $46.96 per barrel, a decrease of 4% from the first quarter of 2017. Unit’s average NGLs price was $14.91 per barrel, a decrease of 16% from the first quarter of 2017. All prices in this paragraph include the effects of derivative contracts.

In the Wilcox area, the Trinity #1 exploration well in the Cherry Creek prospect was tested during the quarter with encouraging results. Unit is in the process of securing right of way for pipeline installation to bring production online. It is anticipated the pipeline will be in place early in the fourth quarter. Recompletion and workover activities have been ongoing, although suffering scheduling delays by the fracture stimulation company. Unit’s strategy for the Wilcox area is to build a horizontal well inventory and to continue exploration activities with the goal of identifying additional Gilly-like structures. Unit has recently added an operated rig to the area.

In the Granite Wash, Unit continues its Buffalo Wallow extended lateral drilling program and plans to do so throughout 2017. During the quarter, two additional wells had first production, one each in the A-2 and C-1 intervals. Two additional wells have been drilled in the C-1 interval and were recently completed. Production rates from the 7,500’ extended lateral well program to date are meeting expectations and, at a projected well cost of $6.3 million, have a high rate of return, especially when including the margin realized by Unit’s midstream segment that gathers and processes all gas produced from the Buffalo Wallow field. During the quarter, we added 200 net operated acres contiguous to the Buffalo Wallow field, increasing Unit’s acreage position to approximately 9,000 net acres. Unit is continuing to evaluate additional opportunities to add acreage surrounding its Buffalo Wallow field.

In the Southern Oklahoma Hoxbar Oil Trend (SOHOT) area, Unit completed the acquisition of approximately 8,300 net acres increasing its working interest and providing operatorship in many sections. Unit continued its drilling program with a rig added in late April. The Oklahoma state legislature passed a bill signed into law in June that allows extended lateral drilling across the state beginning in late August. Unit has begun reworking rig schedules to incorporate longer lateral horizontal wells. It is anticipated that longer laterals should result in further improvement in well economics.

The STACK play has continued to expand as industry drilling activity has further delineated its size. Unit’s legacy acreage position is now within the core of the STACK and STACK extension areas. Unit’s acreage position totals approximately 15,000 net acres. Unit estimates it has 90 to 130 operated drilling locations in inventory and 450 to 650 non-operated locations in inventory in its 10,000 net acre core STACK area. In its STACK extension area, Unit has in excess of 5,000 net acres and estimates it has 20 to 50 operated drilling locations in inventory and 100 to 200 non-operated locations in inventory. After the land and regulatory work is complete, Unit anticipates that its drilling program in this area could be implemented by late 2017 or early 2018.

Larry Pinkston, Unit’s Chief Executive Officer and President, said: "Production results for the quarter reflect the beginning of a return to growth. While delays and unplanned outages have slowed our progress, we now see an improving trend. We are pleased to finally be in the position to discuss our legacy STACK acreage position. As we have previously discussed, we have waited for third party operator drilling activities to advance toward our position. Now, nearby well results have helped substantiate the value of this previously unrecognized asset. Our efforts in our other core areas and the STACK acreage continue to add to our prospective well inventory."

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,
Jun 30,
Jun 30,
Mar 31,
Jun 30,
Jun 30,
2017
2016
Change
2017
2017
Change
2017
2016
Change
Oil and NGLs Production, MBbl
1,851
1,950
(5 )%
1,851
1,740
6 %
3,590
4,044
(11 )%
Natural Gas Production, Bcf
12.0
14.5
(17 )%
12.0
12.2
(2 )%
24.2
29.0
(16 )%
Production, MBoe
3,852
4,359
(12 )%
3,852
3,777
2 %
7,629
8,873
(14 )%
Production, MBoe/day
42.3
47.9
(12 )%
42.3
42.0
1 %
42.1
48.8
(14 )%
Avg. Realized Natural Gas Price, Mcf (1)
$
2.45
$
1.80
36 %
$
2.45
$
2.68
(9 )%
$
2.57
$
1.83
40 %
Avg. Realized NGL Price, Bbl (1)
$ 14.91
$ 11.38
31 %
$ 14.91
$ 17.81
(16 )%
$ 16.34
$
8.90
84 %
Avg. Realized Oil Price, Bbl (1)
$ 46.96
$ 41.52
13 %
$ 46.96
$ 48.68
(4 )%
$ 47.77
$ 36.88
30 %
Realized Price / Boe (1)
$ 20.76
$ 16.27
28 %
$ 20.76
$ 22.13
(6 )%
$ 21.44
$ 14.95
43 %
Operating Profit Before Depreciation, Depletion, & Amortization (MM) (2)
$
50.4
$
35.9
41 %
$
50.4
$
58.4
(14 )%
$ 108.8
$
60.8
79 %
(1)
Realized price includes oil, natural gas liquids, 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

The average number of Unit’s drilling rigs working during the quarter was 28.8, an increase of 13% over the first quarter of 2017. Per day drilling rig rates averaged $15,962, a 1% increase over the first quarter of 2017. For the first six months of 2017, per day drilling rig rates averaged $15,905, a 14% decrease from the first six months of 2016. Average dayrates decreased primarily because of the full effect of the repricing of three BOSS rig term contracts, one in the mid-fourth quarter, one early first quarter, and one during the second quarter. Unit reactivated eight stacked SCR rigs during the first quarter and three during the second quarter but at rates below the average dayrate for the rigs then working. Preparing the rigs to return to service carries additional startup and mobilization costs. These factors contributed to the decreased average daily operating margins during the first six months. Average per day operating margin for the quarter was $4,721 (before elimination of intercompany drilling rig profit and bad debt expense of $0.4 million). This compares to first quarter 2017 average operating margin of $3,474 (with no elimination of intercompany drilling rig profit and bad debt expense), an increase of 36%, or $1,247 (in each case regarding eliminating intercompany drilling rig profit and bad debt expense - see Non-GAAP financial measures below). Average operating margins for the quarter included early termination fees of approximately $0.8 million, or $316 per day, compared to no early termination fees for the first quarter of 2017.

Pinkston said: "Contract drilling industry momentum continued to be positive throughout the quarter despite highly volatile commodity prices. Our rig utilization continued to climb to a total of 33 drilling rigs operating at the end of the quarter. We have 95 drilling rigs in our fleet after adding our tenth BOSS rig during the quarter. All 10 of our BOSS rigs are under contract, and we currently have a total of 36 drilling rigs operating. Long-term contracts (contracts with original terms ranging from six months to two years in length) are in place for 15 of our drilling rigs. Of the 15, seven of these contracts are up for renewal in the third quarter of 2017, six in the fourth quarter of 2017, one is up for renewal in 2018, and one in 2019."

This table illustrates certain comparative results for the periods indicated:

Three Months Ended
Three Months Ended
Six Months Ended
Jun 30,
Jun 30,
Jun 30,
Mar 31,
Jun 30,
Jun 30,
2017
2016
Change
2017
2017
Change
2017
2016
Change
Rigs Utilized
28.8
13.5
114 %
28.8
25.5
13 %
27.2
17.1
59 %
Operating Profit Before Depreciation, Depletion, & Amortization (MM) (1)
$ 12.0
$
5.0
140 %
$ 12.0
$
8.0
51 %
$ 20.0
$ 15.6
28 %
(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.)

MIDSTREAM SEGMENT INFORMATION

For the quarter, gas processed and liquids sold volumes per day increased 7% and 6%, respectively, while gas gathered volumes per day decreased 2%, as compared to the first quarter of 2017. Operating profit (as defined in the footnote below) for the quarter was $12.1 million, a decrease of 9% from the first quarter of 2017.

For the first six months of 2017, per day gas gathered, gas processed and liquids sold volumes decreased 6%, 20% and 3%, respectively, as compared to the first six months of 2016. Operating profit (as defined in the footnote below) for the first six months of 2017 was $25.3 million, an increase of 23% over the first six months of 2016.

This table illustrates certain comparative results for the periods indicated:

Three Months Ended
Three Months Ended
Six Months Ended
Jun 30,
Jun 30,
Jun 30,
Mar 31,
Jun 30,
Jun 30,
2017
2016
Change
2017
2017
Change
2017
2016
Change
Gas Gathering, Mcf/day
383,440
439,937
(13 )%
383,440
390,384
(2 )%
386,893
411,671
(6 )%
Gas Processing, Mcf/day
135,002
161,619
(16 )%
135,002
126,559
7 %
130,804
164,333
(20 )%
Liquids Sold, Gallons/day
525,920
532,215
(1 )%
525,920
497,862
6 %
511,969
525,824
(3 )%
Operating Profit Before Depreciation, Depletion, & Amortization (MM) (1)
$
12.1
$
12.5
(3 )%
$
12.1
$
13.2
(9 )%
$
25.3
$
20.6
23 %
(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: "Our midstream segment continued to reject ethane at all processing facilities except Bellmon and Cashion, which have a more attractive transportation and fractionation fee structure for liquids. Processing and liquids sold volumes reflected quarter over quarter improvement due to increasing processing volumes at Hemphill and Cashion. Overall, our midstream segment continues to post solid results as operator activity levels increase."

FINANCIAL INFORMATION

Unit ended the quarter with long-term debt of $806.1 million. Long-term debt consisted of $641.2 million of senior subordinated notes net of unamortized discount and debt issuance costs and $164.9 million of borrowings under its credit agreement. Under the credit agreement, the amount Unit can borrow is the lesser of the amount it elects as the commitment amount ($475 million) or the value of its borrowing base as determined by the lenders ($475 million), but in either event not to exceed $875 million.

On April 4, 2017, Unit established an "at the market" equity offering program under which it may offer and sell, from time-to-time, up to an aggregate of $100 million for shares of its common stock through "at the market" transactions. As of June 30, 2017, Unit has sold 787,547 shares for $18.6 million, net of offering costs of $0.4 million. Approximately $81.0 million remained available for sale under the program. Net proceeds from the offering will be used to fund (or offset costs of) acquisitions, future capital expenditures, repay amounts outstanding under its revolving credit facility, and general corporate purposes.

WEBCAST

Unit intends to use its website as a means of disclosing material non-public information and for complying with its disclosure obligations under Regulation FD. Those disclosures will be included on its website in the ’Investor Information’ sections. Accordingly, investors should monitor that portion of the website, in addition to 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 3, 2017 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">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. The slides Unit intends to use during the call are available through the webcast link and also on its website at http://www.unitcorp.com under ’Quick Links.’ 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 in the future 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 agreement, the number of wells to be drilled by the company’s oil and natural gas segment, the potential productive capability of its prospective plays including the STACK play, the number of additional shares (if any) it may sell under its "at the market" offering, and other factors described from time to time in the company’s publicly available SEC reports. The company assumes no obligation to update publicly such forward-looking statements, whether because of new information, future events, or otherwise.

Unit Corporation
Selected Financial Highlights
(In thousands except per share amounts)
Three Months Ended
Six Months Ended
June 30,
June 30,
2017
2016
2017
2016
Statement of Operations:
Revenues:
Oil and natural gas
$
83,173
$
69,190
$
170,771
$
127,464
Contract drilling
39,255
24,257
76,440
62,967
Gas gathering and processing
48,153
44,858
99,094
84,058
Total revenues
170,581
138,305
346,305
274,489
Expenses:
Operating costs:
Oil and natural gas
32,758
33,331
61,962
66,677
Contract drilling
27,239
19,254
56,466
47,352
Gas gathering and processing
36,042
32,381
73,746
63,447
Total operating costs
96,039
84,966
192,174
177,476
Depreciation, depletion, and amortization
50,080
52,878
97,012
108,468
Impairments
--
74,291
--
112,120
General and administrative
8,713
8,348
17,667
16,959
Gain on disposition of assets
(248 )
(477 )
(1,072 )
(669 )
Total operating expenses
154,584
220,006
305,781
414,354
Income (loss) from operations
15,997
(81,701 )
40,524
(139,865 )
Other income (expense):
Interest, net
(9,467 )
(10,606 )
(18,863 )
(20,223 )
Gain (loss) on derivatives
8,902
(22,672 )
23,633
(11,743 )
Other
6
1
9
(14 )
Total other income (expense)
(559 )
(33,277 )
4,779
(31,980 )
Income (loss) before income taxes
15,438
(114,978 )
45,303
(171,845 )
Income tax expense (benefit):
Deferred
6,379
(42,842 )
20,315
(58,560 )
Total income taxes
6,379
(42,842 )
20,315
(58,560 )
Net income (loss)
$
9,059
$
(72,136 )
$
24,988
$ (113,285 )
Net income (loss) per common share:
Basic
$
0.18
$
(1.44 )
$
0.49
$
(2.27 )
Diluted
$
0.17
$
(1.44 )
$
0.49
$
(2.27 )
Weighted average shares outstanding:
Basic
51,366
50,074
50,832
49,977
Diluted
51,944
50,074
51,371
49,977
June 30,
December 31,
2017
2016
Balance Sheet Data:
Current assets
$
109,504
$
121,196
Total assets
$ 2,523,310
$ 2,479,303
Current liabilities
$
160,921
$
164,915
Long-term debt
$
806,092
$
800,917
Other long-term liabilities and non-current derivative liability
$
100,796
$
103,479
Deferred income taxes
$
211,038
$
215,922
Shareholders’ equity
$ 1,244,463
$ 1,194,070
Six Months Ended June 30,
2017
2016
Statement of Cash Flows Data:
Cash flow from operations before changes in operating assets and
$
125,481
$
77,734
liabilities
Net change in operating assets and liabilities
(8,426 )
54,982
Net cash provided by operating activities
$
117,055
$ 132,716
Net cash used in investing activities
$ (142,833 )
$ (77,386 )
Net cash provided by (used in) financing activities
$
25,734
$ (55,191 )

Non-GAAP Financial Measures

Unit Corporation reports its financial results in accordance with 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 impairment adjustments 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 (loss) 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, 2017 and 2016. Non-GAAP financial measures should not be considered by themselves or a substitute for results reported in accordance with GAAP. This non-GAAP information should be considered by the reader in addition to, but not instead of, the financial statements prepared in accordance with 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 (Loss) per Share
Three Months Ended
Six Months Ended
June 30,
June 30,
2017
2016
2017
2016
(In thousands except earnings per share)
Adjusted net income (loss):
Net income (loss)
$
9,059
$ (72,136 )
$
24,988
$ (113,285 )
Impairments (net of income tax)
--
46,246
--
69,795
(Gain) loss on derivatives (net of income tax)
(5,243 )
15,650
(13,036 )
7,742
Settlements during the period of matured derivative contracts (net
(252 )
2,870
(865 )
8,037
of income tax)
Adjusted net income (loss)
$
3,564
$
(7,370 )
$
11,087
$
(27,711 )
Adjusted diluted earnings (loss) per share:
Diluted earnings (loss) per share
$
0.17
$
(1.44 )
$
0.49
$
(2.27 )
Diluted earnings per share from impairments
--
0.92
--
1.40
Diluted earnings per share from (gain) loss on derivatives
(0.10 )
0.31
(0.25 )
0.16
Diluted earnings (loss) per share from settlements of matured
--
0.06
(0.02 )
0.16
derivative contracts
Adjusted diluted income (loss) per share
$
0.07
$
(0.15 )
$
0.22
$
(0.55 )

________________

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,
2017
2017
2016
2017
2016
(In thousands)
Oil and natural gas
$
58,394
$
50,415
$
35,859
$
108,809
$
60,787
Contract drilling
7,958
12,016
5,003
19,974
15,615
Gas gathering and processing
13,237
12,111
12,477
25,348
20,611
Total operating profit
79,589
74,542
53,339
154,131
97,013
Depreciation, depletion and amortization
(46,932 )
(50,080 )
(52,878 )
(97,012 )
(108,468 )
Impairments
--
--
(74,291 )
--
(112,120 )
Total operating income (loss)
32,657
24,462
(73,830 )
57,119
(123,575 )
General and administrative
(8,954 )
(8,713 )
(8,348 )
(17,667 )
(16,959 )
Gain on disposition of assets
824
248
477
1,072
669
Interest, net
(9,396 )
(9,467 )
(10,606 )
(18,863 )
(20,223 )
Gain (loss) on derivatives
14,731
8,902
(22,672 )
23,633
(11,743 )
Other
3
6
1
9
(14 )
Income (loss) before income taxes
$
29,865
$
15,438
$ (114,978 )
$
45,303
$ (171,845 )

_________________

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 criteria that is 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,
2017
2017
2016
2017
2016
(In thousands except for operating days and operating margins)
Contract drilling revenue
$
37,185
$ 39,255
$ 24,257
$ 76,440
$ 62,967
Contract drilling operating cost
29,227
27,239
19,254
56,466
47,352
Operating profit from contract drilling
7,958
12,016
5,003
19,974
15,615
Add:
Elimination of intercompany rig profit and bad debt expense
--
376
235
376
235
Operating profit from contract drilling before elimination of
7,958
12,392
5,238
20,350
15,850
intercompany rig profit and bad debt expense
Contract drilling operating days
2,291
2,625
1,230
4,916
3,108
Average daily operating margin before elimination of intercompany
$
3,474
$
4,721
$
4,259
$
4,139
$
5,100
rig profit and bad debt expense

________________

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
Six Months Ended June 30,
2017
2016
(In thousands)
Net cash provided by operating activities
$ 117,055
$ 132,716
Net change in operating assets and liabilities
8,426
(54,982 )
Cash flow from operations before changes in operating assets and
$ 125,481
$
77,734
liabilities

________________

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

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

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

Unit Corporation
Reconciliation of Adjusted EBITDA
Three Months Ended
Six Months Ended
June 30,
June 30,
2017
2016
2017
2016
(In thousands except earnings per share)
Net income (loss)
$
9,059
$ (72,136 )
$
24,988
$ (113,285 )
Income taxes
6,379
(42,842 )
20,315
(58,560 )
Depreciation, depletion and amortization
50,080
52,878
97,012
108,468
Amortization of debt issuance costs and debt discount
539
528
1,075
1,054
Impairments
--
74,291
--
112,120
Interest expense
9,467
10,606
18,863
20,223
(Gain) loss on derivatives
(8,902 )
22,672
(23,633 )
11,743
Settlements during the period of matured derivative contracts
(410 )
5,052
(1,569 )
12,192
Stock compensation plans
4,362
2,905
8,066
7,703
Other non-cash items
673
634
1,458
1,513
Gain on disposition of assets
(248 )
(477 )
(1,072 )
(669 )
Adjusted EBITDA
$
70,999
$
54,111
$
145,503
$
102,502
Diluted income (loss) per share
$
0.17
$
(1.44 )
$
0.49
$
(2.27 )
Diluted earnings per share from income taxes
0.12
(0.86 )
0.40
(1.17 )
Diluted earnings per share from depreciation, depletion and
0.97
1.05
1.88
2.16
amortization
Diluted earnings per share from amortization of debt issuance costs
0.01
0.01
0.02
0.02
and debt discount
Diluted earnings per share from impairments
--
1.49
--
2.25
Diluted earnings per share from interest expense
0.18
0.21
0.37
0.40
Diluted earnings per share from (gain) loss on derivatives
(0.17 )
0.45
(0.46 )
0.23
Diluted earnings per share from settlements during the period of
(0.01 )
0.10
(0.04 )
0.25
matured derivative contracts
Diluted earnings per share from stock compensation plans
0.08
0.06
0.16
0.15
Diluted earnings per share from other non-cash items
0.01
0.01
0.03
0.03
Diluted earnings per share from gain on disposition of assets
0.01
(0.01 )
(0.02 )
(0.01 )
Adjusted EBITDA per diluted share
$
1.37
$
1.07
$
2.83
$
2.04

________________

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.

http://cts.businesswire.com/ct/CT?id=bwnews&sty=20170803005229r1&sid=cmtx6&distro=nx&

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SOURCE: Unit Corporation

Unit Corporation
Michael D. Earl, 918-493-7700
Vice President, Investor Relations
www.unitcorp.com