Press Releases

       
Mar 16, 2020
Unit Corporation Reports 2019 Fourth Quarter and Year-End Results

TULSA, Okla. - Unit Corporation (NYSE: UNT) today reported its financial and operational results for the fourth quarter and year-end 2019. Operational highlights for 2019 include:

Oil and natural gas segment:

  • Segment oil production increased 12% year-over-year.
  • Initiated development drilling program of Red Fork horizontal oil play with outstanding results.
  • Cost cuts identified during the fourth quarter of 2019 expected to reduce lease operating expense by 10% during 2020.
  • Completed sale of non-core eastern Oklahoma gas properties with proceeds of $18 million.

Contract drilling segment:

  • Utilization cycle during 2019:
    • Started the year with 32 drilling rigs operating (including four rigs running for Unit Petroleum).
    • Placed two new BOSS drilling rigs into service in the first quarter and one new BOSS drilling rig in the fourth quarter.
    • Rig utilization averaged between 30-32 drilling rigs operating through the middle of May 2019, as many operators front-end loaded their drilling budgets in the first half of 2019 (including an average of five rigs running for Unit Petroleum).
    • Utilization decreased to 18 drilling rigs at the end of August and remained at that level into early December finishing the year at 20 drilling rigs operating (with no rigs operating for Unit Petroleum).
  • All 14 BOSS drilling rigs were operating during the year.
  • Average drilling rig dayrates increased 7% year-over-year, primarily due to a higher BOSS rig concentration in rigs operating.

Mid-stream segment:

  • Completed the acquisition of Central Oklahoma assets consisting of approximately 600 miles of pipeline and related compressor stations in December 2019.
  • During 2019, per day gas gathered and gas processed volumes increased 11% and 4%, respectively, compared to 2018 per day volumes.

FOURTH QUARTER AND YEAR-END 2019 FINANCIAL RESULTS

Net loss attributable to Unit for the quarter was $335.0 million, or $6.33 per diluted share, compared to net loss attributable to Unit of $77.8 million, or $1.49 per diluted share, for the fourth quarter of 2018. The quarter's results included the following pre-tax non-cash write-downs: $390.0 million ceiling test write-down in the carrying value of Unit's oil and natural gas properties and $0.8 million relating to the write-off of two small gas gathering systems. (For the fourth quarter of 2018, Unit recorded a pre-tax non-cash write-down of $147.9 million associated with the removal of 41 drilling rigs from its drilling fleet along with some other equipment.) Adjusted net loss attributable to Unit (which excludes the effect of non-cash commodity derivatives and the effects of the write-downs) for the quarter was $35.5 million, or $0.67 per diluted share, as compared to adjusted net income attributable to Unit of $13.8 million, or $0.27 per diluted share, for the same quarter for 2018 (see non-GAAP financial measures below). Total revenues for the quarter were $164.4 million (51% oil and natural gas, 22% contract drilling, and 27% mid-stream), compared to $214.8 million (49% oil and natural gas, 25% contract drilling, and 26% mid-stream) for the fourth quarter of 2018. Adjusted EBITDA attributable to Unit was $65.4 million, or $1.23 per diluted share (see non-GAAP financial measures below).

For 2019, net loss attributable to Unit was $553.9 million, or $10.48 per diluted share, compared to net loss attributable to Unit of $45.3 million, or $0.87 per diluted share, for 2018 (which included the non-cash write-down for drilling rigs discussed above). The 2019 results included the following pre-tax non-cash write-downs: $559.4 million ceiling test write-down in the carrying value of Unit's oil and natural gas properties and certain gathering system assets; $62.8 million in goodwill associated with the contract drilling segment; and $3.0 million in the carrying value of line-fill associated with the mid-stream segment and the write-off of two small gas gathering systems. Excluding the effect of the 2019 write-downs and the effect of non-cash commodity derivatives, adjusted net loss attributable to Unit was $59.6 million, or $1.13 per diluted share, as compared to adjusted net income attributable to Unit of $51.9 million, or $1.00 per diluted share, for 2018 (see non-GAAP financial measures below). Total revenues for the year were $674.6 million (48% oil and natural gas, 25% contract drilling, and 27% mid-stream), compared to $843.3 million (50% oil and natural gas, 23% contract drilling, and 27% mid-stream) for 2018. Adjusted EBITDA attributable to Unit for 2019 was $260.5 million, or $4.93 per diluted share (see non-GAAP financial measures below).

OIL AND NATURAL GAS SEGMENT INFORMATION

For the quarter, total equivalent production was 4.2 million barrels of oil equivalent (MMBoe), a 5% decrease from the third quarter. Oil and NGLs production represented 48% of total equivalent production. Oil production was 9,423 barrels per day, a decrease of 6% from the third quarter. NGLs production was 12,132 barrels per day, a 10% decrease from the third quarter. Natural gas production was 141.8 million cubic feet (MMcf) per day, a 2% decrease from the third quarter. Total equivalent production for 2019 was 16.8 MMBoe, a 1% decrease from 2018.

Unit's average realized per barrel equivalent price for the quarter was $20.41, an increase of 9% over the third quarter. Unit's average natural gas price was $1.97 per thousand cubic feet (Mcf), an increase of 8% over the third quarter. Unit's average oil price was $57.33 per barrel, an increase of 1% over the third quarter. Unit's average NGLs price was $13.11 per barrel, an increase of 54% over the third quarter. All prices in this paragraph include the effects of derivative contracts.

In the Southern Oklahoma Hoxbar Oil Trend (SOHOT) and the Red Fork plays in western Oklahoma, 14 horizontal wells were completed in 2019. This mix of Marchand and Red Fork wells enabled the company to increase its oil production percentage. Annual production from western Oklahoma averaged 95.7 MMcfe per day (35% oil, 22% NGLs, and 43% natural gas).

In the Wilcox play in Southeast Texas, seven vertical natural gas and condensate wells were completed in 2019. Annual production from the Wilcox play averaged 76 MMcfe per day (7% oil, 21% NGLs, and 72% natural gas). In addition to the new wells, the company continued its recompletion program.

In the Granite Wash play, two extended length lateral horizontal wells were completed in 2019. Annual production from the Texas panhandle averaged 91.9 MMcfe per day (9% oil, 37% NGLs, and 55% natural gas).

Larry Pinkston, Chief Executive Officer and President, said: "For this segment, our focus for 2019 was to increase the proportion of oil in our production mix, specifically with the results from the new Redfork and Marchand wells, which met or exceeded our expectations. We were able to increase our oil production by 12% year-over-year. We suspended our operated drilling rig program at the beginning of the third quarter, and we are not operating any drilling rigs at this time. We have continued our participation in non-operated wells in the Mid-Continent region, participating in 61 such wells with an average working interest of approximately 4%. In December of 2019, we sold our Panola Field in eastern Oklahoma for $18 million."

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

 

Three Months Ended

 

Three Months Ended

 

Twelve Months Ended

 

Dec 31, 2019

Dec 31, 2018

Change

 

Dec 31, 2019

Sept 30, 2019

Change

 

Dec 31, 2019

Dec 31, 2018

Change

Oil Production, MBbl

 

867

 

 

753

 

15

%

 

 

867

 

 

927

 

(6

)%

 

 

3,208

 

 

2,874

 

12

%

NGLs Production, MBbl

 

1,116

 

 

1,223

 

(9

)%

 

 

1,116

 

 

1,240

 

(10

)%

 

 

4,773

 

 

4,925

 

(3

)%

Natural Gas Production, Bcf

 

13.0

 

 

14.1

 

(7

)%

 

 

13.0

 

 

13.4

 

(2

)%

 

 

53.1

 

 

55.6

 

(5

)%

Production, MBoe

 

4,157

 

 

4,318

 

(4

)%

 

 

4,157

 

 

4,394

 

(5

)%

 

 

16,825

 

 

17,070

 

(1

)%

Production, MBoe/day

 

45.2

 

 

46.9

 

(4

)%

 

 

45.2

 

 

47.8

 

(5

)%

 

 

46.1

 

 

46.8

 

(1

)%

Avg. Realized Natural Gas Price, Mcf (1)

$

1.97

 

$

2.77

 

(29

)%

 

$

1.97

 

$

1.83

 

8

%

 

$

2.04

 

$

2.46

 

(17

)%

Avg. Realized NGL Price, Bbl (1)

$

13.11

 

$

19.61

 

(33

)%

 

$

13.11

 

$

8.50

 

54

%

 

$

12.42

 

$

22.18

 

(44

)%

Avg. Realized Oil Price, Bbl (1)

$

57.33

 

$

54.01

 

6

%

 

$

57.33

 

$

56.62

 

1

%

 

$

57.49

 

$

55.78

 

3

%

Avg. Price / Boe for Revenue Recognition

$

(1.24

)

$

(1.25

)

1

%

 

$

(1.24

)

$

(1.22

)

(2

)%

 

$

(1.24

)

$

(1.03

)

(20

)%

Realized Price / Boe (1)

$

20.41

 

$

22.74

 

(10

)%

 

$

20.41

 

$

18.70

 

9

%

 

$

19.68

 

$

22.78

 

(14

)%

Operating Profit Before Depreciation, Depletion, Amortization & Impairment (MM) (2)

$

53.0

 

$

74.9

 

(29

)%

 

$

53.0

 

$

42.7

 

24

%

 

$

190.7

 

$

291.4

 

(35

)%

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.)

YEAR-END 2019 ESTIMATED PROVED RESERVES

The discount rate (PV-10) value of Unit's estimated year-end 2019 proved reserves decreased 58% from 2018 to $462.0 million. Estimated year-end 2019 proved oil and natural gas reserves were 71.9 MMBoe, or 431.5 billion cubic feet of natural gas equivalents (Bcfe), as compared with 159.7 MMBoe, or 958.1 Bcfe, at year-end 2018, a 55% decrease. Estimated reserves were 17% oil, 32% NGLs, and 51% natural gas.

The following details the changes to Unit's proved oil, NGLs, and natural gas reserves during 2019:

 

 

Oil

(MMbls)

NGLs

(MMbls)

Natural Gas

(Bcf)

Proved

Reserves

(MMBoe)

 

 

 

 

 

 

Proved Reserves, at December 31, 2018

 

22.6

 

47.8

 

536.0

 

159.7

 

Revisions of previous estimates

 

(8.3)

 

(21.0)

 

(234.9)

 

(68.4)

 

Extensions, discoveries, and other

additions

 

1.0

 

1.3

 

13.6

 

4.5

 

Purchases of minerals in place

 

0.2

 

0.1

 

1.3

 

0.5

 

Production

 

(3.2)

 

(4.8)

 

(53.1)

 

(16.8)

 

Sales

 

(0.1)

 

(0.4)

 

(42.7)

 

(7.6)

 

Proved Reserves, at December 31, 2019

 

12.2

 

23.0

 

220.2

 

71.9

 

During 2019, Unit converted 39 proved undeveloped well locations into proved developed wells at a cost of approximately $77.2 million. As of December 31, 2019, Unit did not have any proved undeveloped reserves.

The present value of the estimated future net cash flows from 2019 estimated proved reserves (before income taxes and using a PV-10), is approximately $462.0 million. The present value was determined using the required SEC's pricing methodology. The benchmark price used for all future reserves was $55.69 per barrel of oil, $23.19 per barrel of NGLs, and $2.58 per Mcf of natural gas (then adjusted for price differentials). Ryder Scott Company, L.P. independently audited Unit's 2019 year-end proved reserves. Their audit covered properties accounting for 86% of the discounted future net cash flow (PV-10). See below for the reconciliation of PV-10 to the Standardized Measure of discounted future net cash flows as defined by GAAP.

CONTRACT DRILLING SEGMENT INFORMATION

Unit's average number of drilling rigs working during the quarter was 18.3, a decrease of 10% from the third quarter. Per day drilling rig rates averaged $19,311, a slight increase over the third quarter. For 2019, per day drilling rig rates averaged $18,762, a 7% increase over 2018, primarily due to a higher BOSS rig concentration in rigs operating. Average per day operating margin for the quarter was $6,001 (with no elimination of intercompany drilling rig profit). This compares to third quarter average operating margin of $4,635 (with no elimination of intercompany drilling rig profit), an increase of 30%, or $1,366 (in each case regarding eliminating intercompany drilling rig profit - see non-GAAP financial measures below.

Pinkston said: "During 2019, we placed three new BOSS drilling rigs into service, bringing the total number of BOSS rigs in our fleet to 14. Our BOSS rigs continue to maintain 100% utilization. Term contracts (contracts with original terms ranging from six months to three years in length) are in place for 14 of our drilling rigs at the end of the quarter. Of the 14 contracts, three are up for renewal in the first quarter, three in the second quarter, one in the third quarter, three in the fourth quarter, three in 2021, and one in 2022."

This table illustrates certain comparative results for the periods indicated:

 

Three Months Ended

 

Three Months Ended

 

Twelve Months Ended

 

Dec 31,
2019

Dec 31,
2018

Change

 

Dec 31,
2019

Sept 30,
2019

Change

 

Dec 31,
2019

Dec 31,
2018

Change

Rigs Utilized

 

18.3

 

33.1

(45

)%

 

 

18.3

 

20.4

(10

)%

 

 

24.6

 

32.8

(25

)%

Operating Profit Before Depreciation & Impairment (MM) (1)

$

10.1

$

17.2

(41

)%

 

$

10.1

$

8.8

15

%

 

$

52.4

$

65.1

(20

)%

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.)

MID-STREAM SEGMENT INFORMATION

For the quarter, gas processed and gas gathered volumes per day decreased 3% and 7%, respectively, while liquids sold volumes per day remained relatively unchanged, as compared to the third quarter of 2019. Operating profit (as defined in the footnote below) for the quarter was $10.7 million, a 6% decrease from the third quarter.

For 2019, gas gathered and gas processed volumes per day increased 11% and 4%, respectively, as compared to 2018, while liquids sold volumes per day decreased by 6%. Operating profit (as defined in the footnote below) for 2019 was $46.8 million, a decrease of 16% from 2018.

This table illustrates certain comparative results for the periods indicated:

 

Three Months Ended

 

Three Months Ended

 

Twelve Months Ended

 

Dec 31,
2019

Dec 31,
2018

Change

 

Dec 31,
2019

Sept 30,
2019

Change

 

Dec 31,
2019

Dec 31,
2018

Change

Gas Gathering, Mcf/day

 

399,019

 

394,203

1

%

 

 

399,019

 

428,573

(7

)%

 

 

435,646

 

393,613

11

%

Gas Processing, Mcf/day

 

162,766

 

160,786

1

%

 

 

162,766

 

167,687

(3

)%

 

 

164,482

 

158,189

4

%

Liquids Sold, Gallons/day

 

570,299

 

697,161

(18

)%

 

 

570,299

 

572,852

-%

 

 

625,873

 

663,367

(6

)%

Operating Profit Before Depreciation, Amortization & Impairment (MM) (1)

$

10.7

$

12.4

(14

)%

 

$

10.7

$

11.3

(6

)%

 

$

46.8

$

55.9

(16

)%

 

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: "In an effort to accelerate growth of this segment through the acquisition and consolidation of synergistic assets, we completed an acquisition in December of approximately 600 miles of gathering pipeline and compression in central Oklahoma. The acquired assets will complement this segment's existing infrastructure and allow for greater operational flexibility and efficiency between gathering and processing facilities in the area. Our goal is to continue to search for these types of opportunities that will allow us to grow this segment."

2020 CAPITAL BUDGET

For 2020, Unit's oil and natural gas segment does not currently have any plans to drill wells at this time. The contract drilling segment has no approved capital plan for 2020. Any capital expenditures incurred would be within segment anticipated cash flows. The mid-stream segment has a capital expenditures plan of approximately $28 million, a decrease of 57% from 2019.

FINANCIAL INFORMATION

Unit ended the quarter with long-term debt of $663.2 million, consisting of $646.7 million in senior subordinated notes (net of unamortized discount and debt issuance costs) and $16.5 million in borrowings under the Superior credit facility. Unit's current portion of long-term debt outstanding is $108.2 million under the Unit credit agreement. The Unit Corporation credit agreement borrowing base was re-determined effective as of January 17, 2020 with a new borrowing base set at $200 million. The Superior credit agreement remains in place with a facility size of $200 million.

WEBCAST

Unit uses its website to disclose material nonpublic information and for complying with its disclosure obligations under Regulation FD. The website includes those disclosures in the 'Investor Information' sections. So, investors should monitor that portion of the website, besides following the press releases, SEC filings, and public conference calls and webcasts.

Due to ongoing negotiations with banks and bondholders, Unit will not be hosting a webcast for its fourth quarter and year-end earnings.

_____________________________________________________

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 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 ability to refinance the company's senior subordinated notes, the number of wells to be drilled by the company's oil and natural gas segment, the potential productive capability of its prospective plays, and other factors described occasionally in the company's publicly available SEC reports. The company assumes no obligation to update publicly such forward-looking statements, whether because of new information, future events, or otherwise.

 

Unit Corporation

Selected Financial Highlights

(In thousands except per share amounts)

 

 

 

Three Months Ended

 

Twelve Months Ended

 

 

December 31,

 

December 31,

 

 

2019

 

2018

 

2019

 

2018

Statement of Operations:

 

 

 

 

 

 

 

 

Revenues:

 

 

 

 

 

 

 

 

Oil and natural gas

 

$

83,842

 

 

$

106,019

 

 

$

325,797

 

 

$

423,059

 

Contract drilling

 

36,595

 

 

52,965

 

 

168,383

 

 

196,492

 

Gas gathering and processing

 

43,921

 

 

55,804

 

 

180,454

 

 

223,730

 

Total revenues

 

164,358

 

 

214,788

 

 

674,634

 

 

843,281

 

Expenses:

 

 

 

 

 

 

 

 

Operating costs:

 

 

 

 

 

 

 

 

Oil and natural gas

 

30,804

 

 

31,156

 

 

135,124

 

 

131,675

 

Contract drilling

 

26,493

 

 

35,792

 

 

115,998

 

 

131,385

 

Gas gathering and processing

 

33,267

 

 

43,395

 

 

133,606

 

 

167,836

 

Total operating costs

 

90,564

 

 

110,343

 

 

384,728

 

 

430,896

 

 

 

 

 

 

 

 

 

 

Depreciation, depletion, and amortization

 

76,941

 

 

64,629

 

 

275,573

 

 

243,605

 

Impairments

 

390,836

 

 

147,884

 

 

625,716

 

 

147,884

 

General and administrative

 

8,347

 

 

9,955

 

 

38,246

 

 

38,707

 

(Gain) loss on disposition of assets

 

2,078

 

 

(129)

 

 

3,502

 

 

(704)

 

Total expenses

 

568,766

 

 

332,682

 

 

1,327,765

 

 

860,388

 

 

 

 

 

 

 

 

 

 

Loss from operations

 

(404,408)

 

 

(117,894)

 

 

(653,131)

 

 

(17,107)

 

 

 

 

 

 

 

 

 

 

Other income (expense):

 

 

 

 

 

 

 

 

Interest, net

 

(9,945)

 

 

(7,816)

 

 

(37,012)

 

 

(33,494)

 

Gain (loss) on derivatives

 

(1,007)

 

 

22,424

 

 

4,225

 

 

(3,184)

 

Other

 

375

 

 

5

 

 

(236)

 

 

22

 

Total other income (expense)

 

(10,577)

 

 

14,613

 

 

(33,023)

 

 

(36,656)

 

 

 

 

 

 

 

 

 

 

Loss before income taxes

 

(414,985)

 

 

(103,281)

 

 

(686,154)

 

 

(53,763)

 

 

 

 

 

 

 

 

 

 

Income tax benefit:

 

 

 

 

 

 

 

 

Current

 

(1,281)

 

 

(3,131)

 

 

(1,281)

 

 

(3,131)

 

Deferred

 

(77,964)

 

 

(23,245)

 

 

(131,045)

 

 

(10,865)

 

Total income taxes

 

(79,245)

 

 

(26,376)

 

 

(132,326)

 

 

(13,996)

 

 

 

 

 

 

 

 

 

 

Net loss

 

(335,740)

 

 

(76,905)

 

 

(553,828)

 

 

(39,767)

 

Net income (loss) attributable to non-controlling interest

 

(760)

 

 

935

 

 

51

 

 

5,521

 

Net loss attributable to Unit Corporation

 

$

(334,980)

 

 

$

(77,840)

 

 

$

(553,879)

 

 

$

(45,288)

 

 

 

 

 

 

 

 

 

 

Net income attributable to Unit Corporation per common share

 

 

 

 

 

 

 

 

Basic

 

$

(6.33)

 

 

$

(1.49)

 

 

$

(10.48)

 

 

$

(0.87)

 

Diluted

 

$

(6.33)

 

 

$

(1.49)

 

 

$

(10.48)

 

 

$

(0.87)

 

 

 

 

 

 

 

 

 

 

Weighted average shares outstanding:

 

 

 

 

 

 

 

 

Basic

 

52,953

 

 

52,070

 

 

52,849

 

 

51,981

 

Diluted

 

52,953

 

 

52,070

 

 

52,849

 

 

51,981

 

 

Unit Corporation

Selected Financial Highlights - continued

(In thousands)

 

 

December 31,

 

2019

 

2018

Balance Sheet Data:

 

 

 

Current assets

$

105,051

 

 

$

170,359

 

Total assets

$

2,090,052

 

 

$

2,698,053

 

Current liabilities

$

260,049

 

 

$

213,859

 

Long-term debt

$

663,216

 

 

$

644,475

 

Other long-term liabilities and non-current derivative liability

$

97,439

 

 

$

101,527

 

Deferred income taxes

$

13,713

 

 

$

144,748

 

Total shareholders' equity attributable to Unit Corporation

$

853,878

 

 

$

1,390,881

 

 
 

 

Twelve Months Ended December 31,

 

2019

 

2018

Statement of Cash Flows Data:

 

 

 

Cash flow from operations before changes in operating assets and liabilities

$

249,121

 

 

$

345,167

 

Net change in operating assets and liabilities

20,275

 

 

7,580

 

Net cash provided by operating activities

$

269,396

 

 

$

352,747

 

Net cash used in investing activities

$

(394,563)

 

 

$

(450,342)

 

Net cash provided by financing activities

$

119,286

 

 

$

103,346

 

 

Non-GAAP Financial Measures

Unit Corporation reports its financial results under generally accepted accounting principles ("GAAP"). The company believes certain Non-GAAP performance 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, its exploration and production segment's reconciliation of PV-10 to Standard Measure, 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 are reconciliations of GAAP financial measures to non-GAAP financial measures for the periods below. Non-GAAP financial measures should not be considered by themselves or a substitute for results reported under GAAP. This non-GAAP information should be considered by the reader in addition to, but not instead of, the financial statements prepared under GAAP. The non-GAAP financial information presented may be determined or calculated differently by other companies and may not be comparable to similarly titled measures.

 

Unit Corporation

Reconciliation of Adjusted Net Income (Loss) and Adjusted Diluted Earnings (Loss) per Share

 

 

 

Three Months Ended

 

Twelve Months Ended

 

 

December 31,

 

December 31,

 

 

2019

 

2018

 

2019

 

2018

 

 

(In thousands except earnings per share)

Adjusted net income attributable to Unit Corporation:

 

 

 

 

 

 

 

 

Net loss attributable to Unit Corporation

 

$

(334,980)

 

 

$

(77,840)

 

 

$

(553,879)

 

 

$

(45,288)

 

Impairments (net of income tax)

 

295,081

 

 

111,652

 

 

484,567

 

 

111,652

 

(Gain) loss on derivatives (net of income tax)

 

803

 

 

(16,198)

 

 

(3,410)

 

 

2,356

 

Settlements during the period of matured derivative contracts (net of income tax)

 

3,551

 

 

(3,796)

 

 

13,073

 

 

(16,867)

 

Adjusted net income (loss)

 

$

(35,545)

 

 

$

13,818

 

 

$

(59,649)

 

 

$

51,853

 

 

 

 

 

 

 

 

 

 

Adjusted diluted earnings per share attributable to Unit Corporation:

 

 

 

 

 

 

 

 

Diluted loss per share

 

$

(6.33)

 

 

$

(1.49)

 

 

$

(10.48)

 

 

$

(0.87)

 

Diluted earnings per share from impairments

 

5.57

 

 

2.14

 

 

9.17

 

 

2.14

 

Diluted earnings per share from (gain) loss on derivatives

 

0.02

 

 

(0.31)

 

 

(0.06)

 

 

0.05

 

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

 

0.07

 

 

(0.07)

 

 

0.24

 

 

(0.32)

 

Adjusted diluted earnings (loss) per share attributable to Unit Corporation

 

$

(0.67)

 

 

$

0.27

 

 

$

(1.13)

 

 

$

1.00

 

 

 

 

 

 

 

 

 

 

Weighted Shares (Denominator)

 

52,953

 

 

52,070

 

 

52,849

 

 

51,981

 

________________

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.

Unaudited Reconciliation of PV-10 to Standard Measure
December 31, 2019

PV-10 is the estimated future net cash flows from proved reserves discounted at an annual rate of 10 percent before giving effect to income taxes. Standardized Measure is the after-tax estimated future cash flows from proved reserves discounted at an annual rate of 10 percent, determined under GAAP. The company uses PV-10 as one measure of the value of its proved reserves and to compare relative values of proved reserves among exploration and production companies without regard to income taxes. The company believes that securities analysts and rating agencies use PV-10 in similar ways. The company's management believes PV-10 is a useful measure for comparison of proved reserve values among companies because, unlike Standardized Measure, it excludes future income taxes that often depend principally on the characteristics of the owner of the reserves rather than on the nature, location, and quality of the reserves themselves. Below is a reconciliation of PV-10 to Standardized Measure:

 

 

2019

 

 

 

(In millions)

 

PV-10 at December 31, 2019

 

$

462.0

 

 

Discounted effect of income taxes

 

(0.3)

 

 

Standardized Measure at December 31, 2019

 

$

461.7

 

 

 

Unit Corporation

Reconciliation of Segment Operating Profit

 

 

 

Three Months Ended

 

Twelve Months Ended

 

 

September 30,

 

December 31,

 

December 31,

 

 

2019

 

2019

 

2018

 

2019

 

2018

 

 

(In thousands)

Oil and natural gas

 

$

42,681

 

 

$

53,038

 

 

$

74,863

 

 

$

190,673

 

 

$

291,384

 

Contract drilling

 

8,800

 

 

10,102

 

 

17,173

 

 

52,385

 

 

65,107

 

Gas gathering and processing

 

11,305

 

 

10,654

 

 

12,409

 

 

46,848

 

 

55,894

 

Total operating profit

 

62,786

 

 

73,794

 

 

104,445

 

 

289,906

 

 

412,385

 

Depreciation, depletion and amortization

 

(70,214)

 

 

(76,941)

 

 

(64,629)

 

 

(275,573)

 

 

(243,605)

 

Impairments

 

(234,880)

 

 

(390,836)

 

 

(147,884)

 

 

(625,716)

 

 

(147,884)

 

Total operating income (loss)

 

(242,308)

 

 

(393,983)

 

 

(108,068)

 

 

(611,383)

 

 

20,896

 

General and administrative

 

(10,094)

 

 

(8,347)

 

 

(9,955)

 

 

(38,246)

 

 

(38,707)

 

Gain (loss) on disposition of assets

 

(231)

 

 

(2,078)

 

 

129

 

 

(3,502)

 

 

704

 

Interest, net

 

(9,534)

 

 

(9,945)

 

 

(7,816)

 

 

(37,012)

 

 

(33,494)

 

Gain (loss) on derivatives

 

4,237

 

 

(1,007)

 

 

22,424

 

 

4,225

 

 

(3,184)

 

Other

 

(622)

 

 

375

 

 

5

 

 

(236)

 

 

22

 

(Loss) before income taxes

 

$

(258,552)

 

 

$

(414,985)

 

 

$

(103,281)

 

 

$

(686,154)

 

 

$

(53,763)

 

________________

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 ongoing operating performance of the segments and company using 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

 

Twelve Months Ended

 

 

September 30,

 

December 31,

 

December 31,

 

 

2019

 

2019

 

2018

 

2019

 

2018

 

 

(In thousands except for operating days and operating margins)

Contract drilling revenue

 

$

37,596

 

 

$

36,595

 

 

$

52,965

 

 

$

168,383

 

 

$

196,492

 

Contract drilling operating cost

 

28,796

 

 

26,493

 

 

35,792

 

 

115,998

 

 

131,385

 

Operating profit from contract drilling

 

8,800

 

 

10,102

 

 

17,173

 

 

52,385

 

 

65,107

 

Add:

 

 

 

 

 

 

 

 

 

 

Elimination of intercompany rig profit and bad debt expense

 

(87)

 

 

(8)

 

 

644

 

 

1,619

 

 

3,078

 

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

 

8,713

 

 

10,094

 

 

17,817

 

 

54,004

 

 

68,185

 

Contract drilling operating days

 

1,880

 

 

1,682

 

 

3,041

 

 

8,987

 

 

11,960

 

Average daily operating margin before elimination of intercompany rig profit and bad debt expense

 

$

4,635

 

 

$

6,001

 

 

$

5,859

 

 

$

6,009

 

 

$

5,701

 

________________

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

 

 

Twelve Months Ended

December 31,

 

2019

 

2018

 

(In thousands)

Net cash provided by operating activities

$

269,396

 

 

$

352,747

 

Net change in operating assets and liabilities

(20,275)

 

 

(7,580)

 

Cash flow from operations before changes in operating assets and liabilities

$

249,121

 

 

$

345,167

 

________________

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

  • It is an accepted financial indicator used by its management and companies in the industry to measure the company's ability to generate cash used to internally fund its business activities.
  • It is used by investors and financial analysts to evaluate the performance of the company.
 

Unit Corporation

Reconciliation of Adjusted EBITDA

 

 

 

Three Months Ended

 

Twelve Months Ended

 

 

December 31,

 

December 31,

 

 

2019

 

2018

 

2019

 

2018

 

 

(In thousands except earnings per share)

 

 

 

 

 

 

 

 

 

Net loss

 

$

(335,740)

 

 

$

(76,905)

 

 

$

(553,828)

 

 

$

(39,767)

 

Income taxes

 

(79,245)

 

 

(26,376)

 

 

(132,326)

 

 

(13,996)

 

Depreciation, depletion and amortization

 

76,941

 

 

64,629

 

 

275,573

 

 

243,605

 

Impairments

 

390,836

 

 

147,884

 

 

625,716

 

 

147,884

 

Interest expense

 

9,945

 

 

7,816

 

 

37,012

 

 

33,494

 

(Gain) loss on derivatives

 

1,007

 

 

(22,424)

 

 

(4,225)

 

 

3,184

 

Settlements during the period of matured derivative contracts

 

4,367

 

 

(4,763)

 

 

16,196

 

 

(22,803)

 

Stock compensation plans

 

(4,175)

 

 

5,502

 

 

12,932

 

 

22,899

 

Other non-cash items

 

4,595

 

 

(735)

 

 

5,006

 

 

(2,576)

 

(Gain) loss on disposition of assets

 

2,078

 

 

(129)

 

 

3,502

 

 

(704)

 

Adjusted EBITDA

 

70,609

 

 

94,499

 

 

285,558

 

 

371,220

 

Adjusted EBITDA attributable to non-controlling interest

 

5,218

 

 

6,315

 

 

25,025

 

 

21,488

 

Adjusted EBITDA attributable to Unit Corporation

 

$

65,391

 

 

$

88,184

 

 

$

260,533

 

 

$

349,732

 

 

 

 

 

 

 

 

 

 

Diluted loss per share attributable to Unit

 

$

(6.33)

 

 

$

(1.49)

 

 

$

(10.48)

 

 

$

(0.87)

 

Diluted loss per share from income taxes

 

(1.50)

 

 

(0.52)

 

 

(2.50)

 

 

(0.26)

 

Diluted earnings per share from depreciation, depletion and amortization

 

1.34

 

 

1.13

 

 

4.76

 

 

4.36

 

Diluted earnings per share from impairments

 

7.38

 

 

2.84

 

 

11.81

 

 

2.84

 

Diluted earnings per share from interest expense

 

0.18

 

 

0.15

 

 

0.67

 

 

0.63

 

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

 

0.02

 

 

(0.43)

 

 

(0.08)

 

 

0.06

 

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

 

0.10

 

 

(0.09)

 

 

0.32

 

 

(0.44)

 

Diluted earnings per share from stock compensation plans

 

(0.08)

 

 

0.10

 

 

0.24

 

 

0.43

 

Diluted earnings per share from other non-cash items

 

0.08

 

 

-

 

 

0.12

 

 

(0.01)

 

Diluted earnings per share (gain) loss on disposition of assets

 

0.04

 

 

-

 

 

0.07

 

 

(0.01)

 

Adjusted EBITDA per diluted share

 

$

1.23

 

 

$

1.69

 

 

$

4.93

 

 

$

6.73

 

 

 

 

 

 

 

 

 

 

Weighted Shares (Denominator)

 

52,953

 

 

52,070

 

 

52,849

 

 

51,981

 

________________

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

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

 

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


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