UNT
$24.63
Unit
$.25
1.03%
Earnings Details
3rd Quarter September 2016
Thursday, November 03, 2016 8:00:03 AM
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Summary

Unit (UNT) Recent Earnings

Unit (UNT) reported 3rd Quarter September 2016 earnings of $0.04 per share on revenue of $153.4 million. The consensus estimate was a loss of $0.08 per share on revenue of $154.0 million. Revenue fell 27.8% compared to the same quarter a year ago.

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
$0.04
Earnings Whisper
-
Consensus Estimate
($0.08)
Reported Revenue
$153.4 Mil
Revenue Estimate
$154.0 Mil
Growth
Earnings Growth
Revenue Growth
Power Rating
Grade
Earnings Release

Unit Corporation Reports 2016 Third Quarter Results

Unit Corporation (UNT) today reported its financial and operational results for the third quarter 2016. Third quarter and recent highlights include:

To date, the contract drilling segment increased the number of drilling rigs in service from a low of 13 to 20, a 54% increase. Average drilling rig utilization increased 19% quarter over quarter.

Unit also was awarded a term contract for its ninth BOSS drilling rig, with completion expected in January 2017.

After the quarter, the oil and natural gas segment put one drilling rig back into service in the Southern Oklahoma Hoxbar Oil Trend (SOHOT) play and is planning to put into service a second drilling rig in the Granite Wash play later in the fourth quarter.

Midstream segment connected six new wells to its Pittsburgh Mills gathering system in Butler County, Pennsylvania, increasing the average daily throughput volume to approximately 151 million cubic feet (MMcf) per day, a 6% increase over the second quarter of 2016.

Reduced long-term debt by $21 million from the end of the second quarter, bringing the total year-to-date reduction to $64 million.

October redetermination of Unit’s borrowing base amount was maintained at $475 million.

THIRD QUARTER AND FIRST NINE MONTHS 2016 FINANCIAL RESULTS

Unit recorded a net loss of $24.0 million for the quarter, or $0.48 per share, compared to a net loss of $205.3 million, or $4.18 per share, for the third quarter of 2015. For the third quarter of 2016 and 2015, Unit incurred pre-tax non-cash ceiling test write-downs of $49.4 million and $329.9 million, respectively, in the carrying value of its oil and natural gas properties. These non-cash ceiling test write-downs resulted from continued lower commodity prices. Adjusted net income (which excludes the effect of non-cash commodity derivatives and the effect of the non-cash write-down) for the quarter was $1.7 million, or $0.04 per share (see Non-GAAP financial measures below). Total revenues were $153.4 million (51% oil and natural gas, 17% contract drilling, and 32% midstream), compared to $212.4 million (45% oil and natural gas, 31% contract drilling, and 24% midstream) for the third quarter of 2015. Adjusted EBITDA for the quarter was $67.3 million, or $1.33 per diluted share (see Non-GAAP financial measures below).

For the first nine months of 2016, Unit recorded a net loss of $137.3 million, or $2.75 per share, compared to a net loss of $728.0 million, or $14.83 per share, for the first nine months of 2015. Unit incurred pre-tax non-cash ceiling test write-downs of $161.6 million and $1.1 billion in the carrying value of its oil and natural gas properties during the first nine months of 2016 and 2015, respectively. Unit recorded an adjusted net loss (which excludes the effect of non-cash commodity derivatives and the effect of the non-cash write-down) of $26.0 million, or $0.52 per share, for the first nine months of 2016 (see Non-GAAP financial measures below). Total revenues for the first nine months were $427.9 million (48% oil and natural gas, 21% contract drilling, and 31% midstream), compared to $681.9 million (45% oil and natural gas, 32% contract drilling, and 23% midstream) for the first nine months of 2015. Adjusted EBITDA for the first nine months was $169.8 million, or $3.37 per diluted share (see Non-GAAP financial measures below).

OIL AND NATURAL GAS SEGMENT INFORMATION

For the quarter, total production was 4.2 million barrels of oil equivalent (MMBoe), a decrease of 17% from the third quarter of 2015 and a 4% decrease from the second quarter of 2016. The decrease from the second quarter of 2016 was due primarily to approximately 0.6 billion cubic feet equivalent (Bcfe) of production in the Wilcox play being shut in for six days during the third quarter because of maintenance on a third-party operated processing plant. Liquids (oil and NGLs) production represented 47% of total equivalent production. Oil production was 7,618 barrels per day, a decrease of 26% from the third quarter of 2015 and a decrease of 8% from the second quarter of 2016. NGLs production was 13,698 barrels per day, a decrease of 6% from the third quarter of 2015 and a 4% increase over the second quarter of 2016. Natural gas production was 145,642 thousand cubic feet (Mcf) per day, a decrease of 19% from the third quarter of 2015 and a decrease of 8% from the second quarter of 2016. Total production for the first nine months of 2016 was 13.1 MMBoe.

Unit’s average realized per barrel equivalent price was $18.29, a decrease of 11% from the third quarter of 2015 and a 12% increase over the second quarter of 2016. Unit’s average natural gas price was $2.29 per Mcf, a decrease of 14% from the third quarter of 2015 and an increase of 27% over the second quarter of 2016. Unit’s average oil price was $42.79 per barrel, a decrease of 16% from the third quarter of 2015 and an increase of 3% over the second quarter of 2016. Unit’s average NGLs price was $12.68 per barrel, a 45% increase over the third quarter of 2015 and an increase of 11% over the second quarter of 2016. All prices in this paragraph include the effects of derivative contracts.

In the SOHOT area, Unit’s production per day for the quarter decreased from the second quarter of 2016 in line with its expectations, due to natural decline rates and because no new wells were completed in the third quarter. Unit was able to increase its leasehold in the core area of the play by 2% during the third quarter to over 19,700 net acres. As planned, the company added a Unit drilling rig in late October to drill two horizontal Marchand oil wells within the SOHOT area in the fourth quarter of this year. After drilling these two wells, the drilling rig will be released for three to four months as performance of the two wells is monitored before resuming drilling for the remainder of 2017.

In the Wilcox area, production for the third quarter of 2016 averaged 90 MMcfe per day, which is a 7% decrease as compared to the second quarter of 2016. The decrease in quarter over quarter production was a result of maintenance on a third-party operated processing plant which caused production to be shut in for six days during the quarter. The processing plant was back to full operational capability by early August, and September production averaged 100 MMcfe per day. During the third quarter, Unit completed six new behind pipe Wilcox recompletions and three workovers, which resulted in natural gas and oil production from these nine wells increasing from 1,300 Mcf per day to 15,400 Mcf per day and 140 barrels of oil per day to 850 barrels of oil per day, respectively, from the beginning of the quarter to the end of the quarter.

In the Texas Panhandle, Unit’s Granite Wash play operational results for the third quarter exceeded its expectations as production per day increased 3% as compared to the prior quarter. The increase was due to the Dixon extended lateral well continuing to outperform expectations as well as production increases from several recompletions and workovers that helped offset the natural decline of existing wells. In December, the company will add a Unit drilling rig and initiate an extended lateral Granite Wash drilling program in the Buffalo Wallow field. Current plans are to run this drilling rig for all of 2017.

Larry Pinkston, Unit’s Chief Executive Officer and President, said: "Our Wilcox vertical behind pipe recompletion activity continues to produce strong results. In the Granite Wash, our extended lateral Dixon well is outperforming our type curve. Following two quarters of no new drilling activity, we recommenced our drilling program primarily in the SOHOT and Granite Wash plays. We are continuing our plan of maintaining a capital expenditure level within cash flow. While it is our intention to keep at least a two drilling rig program going for the foreseeable future, such action will be dependent on prevailing conditions."

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

Three Months Ended
Three Months Ended
Nine Months Ended
Sept. 30, 2016
Sept. 30, 2015
Change
Sept. 30, 2016
June 30, 2016
Change
Sept. 30, 2016
Sept. 30, 2015
Change
Oil and NGLs Production, MBbl
1,961
2,289
(14 )%
1,961
1,950
1 %
6,005
6,950
(14 )%
Natural Gas Production, Bcf
13.4
16.6
(19 )%
13.4
14.5
(7 )%
42.4
49.6
(15 )%
Production, MBoe
4,194
5,053
(17 )%
4,194
4,359
(4 )%
13,068
15,225
(14 )%
Production, MBoe/day
45.6
54.9
(17 )%
45.6
47.9
(5 )%
47.7
55.8
(14 )%
Avg. Realized Natural Gas Price, Mcf (1)
$
2.29
$
2.66
14 %
$
2.29
$
1.80
27 %
$
1.98
$
2.76
(28 )%
Avg. Realized NGL Price, Bbl (1)
$
12.68
$
8.74
45 %
$
12.68
$
11.38
11 %
$
10.16
$
9.83
3 %
Avg. Realized Oil Price, Bbl (1)
$
42.79
$
50.87
16 %
$
42.79
$
41.52
3 %
$
38.71
$
51.46
(25 )%
Realized Price / Boe (1)
$
18.29
$
20.61
(11 )%
$
18.29
$
16.27
12 %
$
16.02
$
21.66
(26 )%
Operating Profit Before Depreciation, Depletion, & Amortization (MM) (2)
$
52.8
$
57.9
(9 )%
$
52.8
$
35.9
47 %
$
113.6
$
180.1
(37 )%
(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.)

This table summarizes the outstanding derivative contracts.

Crude
Period
Structure
Volume
Weighted
Weighted
Weighted
Weighted
Bbl/Day
Average
Average
Average
Average
Fixed Price
Floor Price
Subfloor Price
Ceiling Price
Oct’16 - Dec’16
Collar
3,450
$47.79
$54.52
Oct’16 - Dec’16
3-Way Collar
700
$46.50
$35.00
$57.00
Oct’16 - Dec’16
3-Way Collar (1)
700
$47.50
$35.00
$63.50
Jan’17 - Dec’17
3-Way Collar
3,750
$49.79
$39.58
$60.98
Natural Gas
Period
Structure
Volume
Weighted
Weighted
Weighted
Weighted
MMBtu/Day
Average
Average
Average
Average
Fixed Price
Floor Price
Subfloor Price
Ceiling Price
Oct’16 - Dec’16
Swap
45,000
$2.596
Jan’17 - Mar’17
Swap
10,000
$3.550
Jan’17 - Dec’17
Swap
60,000
$2.960
Jan’18 - Dec’18
Swap
10,000
$3.025
Jan’17 - Dec’17
Basis Swap
20,000
$(0.215)
Jan’18 - Dec’18
Basis Swap
10,000
$(0.208)
Oct’16 - Dec’16
Collar
42,000
$2.40
$2.88
Jan’17 - Oct’17
Collar
20,000
$2.88
$3.10
Oct’16 - Dec’16
3-Way Collar
13,500
$2.70
$2.20
$3.26
Jan’17 - Dec’17
3-Way Collar
15,000
$2.50
$2.00
$3.32
(1)
Unit pays its counterparty a premium, which can be and is being
deferred until settlement.

CONTRACT DRILLING SEGMENT INFORMATION

The average number of Unit’s drilling rigs working during the quarter was 16.0, a decrease of 49% from the third quarter of 2015 and an increase of 19% over the second quarter of 2016. Per day drilling rig rates averaged $17,479, a decrease of 7% from the third quarter of 2015 and a 6% decrease from the second quarter of 2016. For the first nine months of 2016, per day drilling rig rates averaged $18,147, an 8% decrease from the first nine months of 2015. Average per day operating margin for the quarter was $4,546 (with no elimination of intercompany drilling rig profit and bad debt expense). This compares to third quarter 2015 average operating margin of $10,368 (before elimination of intercompany drilling rig profit and bad debt expense of $0.2 million), a decrease of 56%, or $5,822. Third quarter 2016 average operating margin increased 7%, or $287, as compared to that of $4,259 for the second quarter of 2016 (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 no early termination fees from the cancellation of certain long-term contracts, compared to early termination fees of $11.4 million, or $3,958 per day, during the third quarter of 2015 and $0.4 million, or $342 per day, for the second quarter of 2016.

Pinkston said: "Commodity prices continued to increase during the quarter, and we have seen an uptick in operator inquiries to contract drilling rigs, resulting in an increase in our average utilization rate over the previous quarter. After the end of the quarter, we contracted our remaining BOSS drilling rig, bringing all eight of our BOSS drilling rigs under contract. Additionally, we were awarded a term contract for a ninth BOSS drilling rig with construction expected to be completed in January 2017. Our drilling rig fleet totals 94 drilling rigs, of which 20 are working under contract after rebounding from a low of 13 drilling rigs during the second quarter. Long-term contracts (contracts with original terms ranging from six months to two years in length) are in place for nine of our drilling rigs. Of the nine, one is up for renewal during the fourth quarter, seven in 2017 and one in 2018."

This table illustrates certain comparative results for the periods indicated:

Three Months Ended
Three Months Ended
Nine Months Ended
Sept. 30,
Sept. 30,
Change
Sept. 30,
June 30,
Change
Sept. 30,
Sept. 30,
Change
2016
2015
2016
2016
2016
2015
Rigs Utilized
16.0
31.2
(49 )%
16.0
13.5
19 %
16.7
37.3
(55 )%
Operating Profit Before Depreciation, Depletion, & Amortization (MM) (1)
$
6.7
$ 29.5
(77 )%
$
6.7
$
5.0
34 %
$ 22.3
$ 91.4
(76 )%
(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, per day gas gathered volumes increased 20%, while gas processed and liquids sold volumes decreased 18% and 4%, respectively, as compared to the third quarter of 2015. Compared to the second quarter of 2016, liquids sold volumes per day increased 5%, while gas gathered and gas processed volumes per day decreased 2% and 6%, respectively. Operating profit (as defined in the footnote below) for the quarter was $13.0 million, an increase of 25% over the third quarter of 2015 and an increase of 4% over the second quarter of 2016.

For the first nine months of 2016, per day gas gathered volumes increased 19%, while gas processed and liquids sold volumes per day decreased 14% and 8%, respectively, as compared to the first nine months of 2015. Operating profit (as defined in the footnote below) for the first nine months of 2016 was $33.6 million, an increase of 6% over the first nine months of 2015.

This table illustrates certain comparative results for the periods indicated:

Three Months Ended
Three Months Ended
Nine Months Ended
Sept. 30,
Sept. 30,
Change
Sept. 30,
June 30,
Change
Sept. 30,
Sept. 30,
Change
2016
2015
2016
2016
2016
2015
Gas Gathering, Mcf/day
429,693
357,427
20 %
429,693
439,937
(2 )%
417,722
351,619
19 %
Gas Processing, Mcf/day
152,651
185,625
(18 )%
152,651
161,619
(6 )%
160,411
186,929
(14 )%
Liquids Sold, Gallons/day
558,843
579,556
(4 )%
558,843
532,215
5 %
536,911
582,760
(8 )%
Operating Profit Before Depreciation, Depletion, & Amortization (MM) (1)
$
13.0
$
10.4
25 %
$
13.0
$
12.5
4 %
$
33.6
$
31.8
6 %
(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: "In the Marcellus, additional well connections to our Pittsburgh Mills system in Butler County, Pennsylvania have increased average daily throughput volume to approximately 151 MMcf per day, a 6% increase over the second quarter of 2016. Due to low liquids prices, our midstream segment remained in ethane rejection mode for most of the quarter at our various gas processing facilities in the Mid-Continent."

FINANCIAL INFORMATION

Unit ended the quarter with long-term debt of $854.6 million (a reduction of $20.5 million from the end of the second quarter and $64.4 million from the end of 2015). Long-term debt consisted of $639.6 million of senior subordinated notes net of unamortized discount and debt issuance costs and $215.0 million of borrowings under its credit agreement. Recently, Unit’s borrowing base was redetermined with no change to availability. 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.

WEBCAST

Unit will webcast its third quarter earnings conference call live over the Internet on November 3, 2016 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 prior to 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 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, 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
Nine Months Ended
September 30,
September 30,
2016
2015
2016
2015
Statement of Operations:
Revenues:
Oil and natural gas
$
78,854
$
96,619
$
206,318
$
309,944
Contract drilling
25,819
65,022
88,786
215,114
Gas gathering and processing
48,735
50,752
132,793
156,881
Total revenues
153,408
212,393
427,897
681,939
Expenses:
Oil and natural gas:
Operating costs
26,014
38,688
92,691
129,871
Depreciation, depletion, and amortization
27,135
57,159
89,378
202,378
Impairment of oil and natural gas properties
49,443
329,924
161,563
1,141,053
Contract drilling:
Operating costs
19,137
35,486
66,489
123,717
Depreciation
11,318
14,255
34,431
42,533
Impairment of contract drilling equipment
--
--
--
8,314
Gas gathering and processing:
Operating costs
35,738
40,314
99,185
125,081
Depreciation and amortization
11,436
10,976
34,410
32,518
General and administrative
8,932
7,643
26,029
26,637
(Gain) loss on disposition of assets
(154 )
7,230
(823 )
6,270
Total operating expenses
188,999
541,675
603,353
1,838,372
Loss from operations
(35,591 )
(329,282 )
(175,456 )
(1,156,433 )
Other income (expense):
Interest, net
(10,002 )
(8,286 )
(30,225 )
(23,482 )
Gain (loss) on derivatives
6,969
8,250
(4,774 )
12,917
Other
3
16
(11 )
38
Total other income (expense)
(3,030 )
(20 )
(35,010 )
(10,527 )
Loss before income taxes
(38,621 )
(329,302 )
(210,466 )
(1,166,960 )
Income tax expense (benefit):
Current
--
(2,584 )
--
(1,716 )
Deferred
(14,599 )
(121,437 )
(73,159 )
(437,220 )
Total income taxes
(14,599 )
(124,021 )
(73,159 )
(438,936 )
Net loss
$
(24,022 )
$
(205,281 )
$
(137,307 )
$
(728,024 )
Net loss per common share:
Basic
$
(0.48 )
$
(4.18 )
$
(2.75 )
$
(14.83 )
Diluted
$
(0.48 )
$
(4.18 )
$
(2.75 )
$
(14.83 )
Weighted average shares outstanding:
Basic
50,081
49,155
50,012
49,094
Diluted
50,081
49,155
50,012
49,094
September 30,
December 31,
2016
2015
Balance Sheet Data:
Current assets
$
93,646
$
140,258
Total assets
$ 2,481,191
$ 2,799,842
Current liabilities
$
135,988
$
150,891
Long-term debt
$
854,583
$
918,995
Other long-term liabilities and non-current derivative liability
$
103,922
$
140,626
Deferred income taxes
$
197,122
$
275,750
Shareholders’ equity
$ 1,189,576
$ 1,313,580
Nine Months Ended September 30,
2016
2015
Statement of Cash Flows Data:
Cash flow from operations before changes in operating assets and
$
134,138
$
303,719
liabilities
Net change in operating assets and liabilities
63,624
77,763
Net cash provided by operating activities
$
197,762
$
381,482
Net cash used in investing activities
$
(107,509 )
$
(474,190 )
Net cash (used in) provided by financing activities
$
(90,175 )
$
92,553

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 nine months ended September 30, 2016 and 2015. 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 and Adjusted Diluted
Earnings per Share
Three Months Ended
Nine Months Ended
September 30,
September 30,
2016
2015
2016
2015
(In thousands except earnings per share)
Adjusted net income:
Net loss
$
(24,022 )
$ (205,281 )
$ (137,307 )
$ (728,024 )
Impairment (net of income tax)
30,778
205,378
100,573
715,481
(Gain) loss on derivatives (net of income tax)
(4,627 )
(5,272 )
3,115
(8,058 )
Settlements during the period of matured derivative contracts (net
(381 )
6,837
7,656
20,060
of income tax)
Adjusted net income (loss)
$
1,748
$
1,662
$
(25,963 )
$
(541 )
Adjusted diluted earnings per share:
Diluted loss per share
$
(0.48 )
$
(4.18 )
$
(2.75 )
$
(14.83 )
Diluted earnings per share from impairments
0.61
4.18
2.01
14.57
Diluted earnings per share from (gain) loss on derivatives
(0.09 )
(0.11 )
0.06
(0.16 )
Diluted earnings (loss) per share from settlements of matured
--
0.14
0.16
0.41
derivative contracts
Adjusted diluted income (loss) per share
$
0.04
$
0.03
$
(0.52 )
$
(0.01 )

________________

The Company has included the net income and diluted earnings per share including only the cash settled commodity derivatives because:

It uses the adjusted net income to evaluate the operational performance of the company.

The adjusted net income is more comparable to earnings estimates provided by securities analysts.

Unit Corporation
Reconciliation of Segment Operating Profit
Three Months Ended
Nine Months Ended
June 30,
September 30,
September 30,
2016
2016
2015
2016
2015
(In thousands)
Oil and natural gas
$
35,859
$
52,840
$
57,931
$
113,627
$
180,073
Contract drilling
5,003
6,682
29,536
22,297
91,397
Gas gathering and processing
12,477
12,997
10,438
33,608
31,800
Total operating profit
53,339
72,519
97,905
169,532
303,270
Depreciation, depletion and amortization
(52,844 )
(49,889 )
(82,390 )
(158,219 )
(277,429 )
Impairments
(74,291 )
(49,443 )
(329,924 )
(161,563 )
(1,149,367 )
Total operating loss
(73,796 )
(26,813 )
(314,409 )
(150,250 )
(1,123,526 )
General and administrative
(8,382 )
(8,932 )
(7,643 )
(26,029 )
(26,637 )
Gain (loss) on disposition of assets
477
154
(7,230 )
823
(6,270 )
Interest, net
(10,606 )
(10,002 )
(8,286 )
(30,225 )
(23,482 )
Gain (loss) on derivatives
(22,672 )
6,969
8,250
(4,774 )
12,917
Other
1
3
16
(11 )
38
Loss before income taxes
$ (114,978 )
$ (38,621 )
$ (329,302 )
$ (210,466 )
$ (1,166,960 )

________________

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
Nine Months Ended
June 30,
September 30,
September 30,
2016
2016
2015
2016
2015
(In thousands except for operating days and operating margins)
Contract drilling revenue
$ 24,257
$
25,819
$ 65,022
$ 88,786
$ 215,114
Contract drilling operating cost
19,254
19,137
35,486
66,489
123,717
Operating profit from contract drilling
5,003
6,682
29,536
22,297
91,397
Add:
Elimination of intercompany rig profit and bad debt expense
235
--
219
235
3,666
Operating profit from contract drilling before elimination of
5,238
6,682
29,755
22,532
95,063
intercompany rig profit and bad debt expense
Contract drilling operating days
1,230
1,470
2,870
4,578
10,175
Average daily operating margin before elimination of intercompany
$
4,259
$
4,546
$ 10,368
$
4,922
$
9,343
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
Nine Months Ended
September 30,
2016
2015
(In thousands)
Net cash provided by operating activities
$ 197,762
$ 381,482
Net change in operating assets and liabilities
(63,624 )
(77,763 )
Cash flow from operations before changes in operating assets and
$ 134,138
$ 303,719
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 and Adjusted EBITDA per Diluted
Share
Three Months Ended
Nine Months Ended
September 30,
September 30,
2016
2015
2016
2015
(In thousands except earnings per share)
Net loss
$
(24,022 )
$
(205,281 )
$ (137,307 )
$
(728,024 )
Income taxes
(14,599 )
(124,021 )
(73,159 )
(438,936 )
Depreciation, depletion and amortization
50,501
83,163
160,023
279,739
Impairment
49,443
329,924
161,563
1,149,367
Interest expense
10,002
8,286
30,225
23,482
(Gain) loss on derivatives
(6,969 )
(8,250 )
4,774
(12,917 )
Settlements during the period of matured derivative contracts
(457 )
11,074
11,735
32,156
Stock compensation plans
2,961
185
10,664
12,514
Other non-cash items
634
843
2,147
2,629
Gain on disposition of assets
(154 )
7,230
(823 )
6,270
Adjusted EBITDA
$
67,340
$
103,153
$
169,842
$
326,280
Diluted loss per share
$
(0.48 )
$
(4.18 )
$
(2.75 )
$
(14.83 )
Diluted earnings per share from income taxes
(0.29 )
(2.52 )
(1.46 )
(8.94 )
Diluted earnings per share from depreciation, depletion and
1.00
1.68
3.17
5.67
amortization
Diluted earnings per share from impairments
0.98
6.71
3.24
23.41
Diluted earnings per share from interest expense
0.20
0.17
0.60
0.48
Diluted earnings per share from (gain) loss on derivatives
(0.14 )
(0.17 )
0.09
(0.26 )
Diluted earnings per share from settlements during the period of
(0.01 )
0.23
0.25
0.66
matured derivative contracts
Diluted earnings per share from stock compensation plans
0.06
--
0.21
0.25
Diluted earnings per share from other non-cash items
0.01
0.02
0.04
0.05
Diluted earnings per share from gain on disposition of assets
--
0.15
(0.02 )
0.13
Adjusted EBITDA per diluted share
$
1.33
$
2.09
$
3.37
$
6.62

________________

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.

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SOURCE: Unit Corporation

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