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| Share Name | Share Symbol | Market | Type |
|---|---|---|---|
| Unit Corp | NYSE:UNT | NYSE | Common Stock |
| Price Change | % Change | Share Price | High Price | Low Price | Open Price | Shares Traded | Last Trade | |
|---|---|---|---|---|---|---|---|---|
| 0.00 | 0.00% | 0.2358 | 0 | 00:00:00 |
From Nov 2019 to Nov 2024
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:
Contract drilling segment:
Mid-stream segment:
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:
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:
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:
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:
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:
View source version on businesswire.com: https://www.businesswire.com/news/home/20200316005686/en/
Michael D. Earl Vice President, Investor Relations (918) 493-7700 www.unitcorp.com
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