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Unit Corporation Reports 2018 Fourth Quarter and Year-End Results

TULSA, Okla,--(BUSINESS WIRE)--

Unit Corporation (NYSE - UNT) today reported its financial and operational results for the fourth quarter and year-end 2018. Fourth quarter and 2018 operational highlights include:

  • Oil and natural gas segment production increased 7% year-over-year from 2017.
  • Total year-end 2018 proved oil and natural gas reserves increased 7% over 2017, and 158% of 2018 production was replaced with new reserves.
  • In December, Unit acquired approximately 8,700 net acres in the Penn sands play in western Oklahoma adding additional oil prospects similar to Unit’s existing Southern Oklahoma Hoxbar Oil Trend (SOHOT) play. The final adjusted price of the acquisition totaled approximately $29.6 million and included net proved reserves of 2.6 million barrels of oil equivalent (MMBoe). The acquisition provides Unit with 20 to 30 horizontal drilling locations and 82% of the acreage is held by production.
  • Contract drilling segment placed its 11th BOSS rig into service during the second quarter. Its 12th BOSS rig was placed into service during January 2019. Further, its 13th BOSS rig was recently placed into service under a long-term contract.
  • During the quarter, the mid-stream segment completed the connection of the Miller Pad to its Pittsburgh Mills gathering system. The wells from the new pad began being placed online in late January 2019.
  • The mid-stream segment’s natural gas gathering, processing and liquids sold volumes increased 2%, 15% and 24% year-over-year, respectively.
  • Unit amended its bank credit agreement during the quarter, in part extending its maturity until October 2023.

FOURTH QUARTER AND YEAR-END 2018 FINANCIAL RESULTS

Net loss attributable to Unit for the quarter was $77.8 million, or $1.49 loss per diluted share, compared to net income attributable to Unit of $89.2 million, or $1.71 per diluted share, for the fourth quarter of 2017. (For the fourth quarter of 2017, Unit recorded an $81.3 million net tax benefit related to tax legislation enacted during the quarter.) 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. The drilling rigs removed from service included our remaining 29 mechanical drilling rigs and 12 SCR drilling rigs. The company strategically decided to focus on its new BOSS drilling rigs and specific SCR drilling rigs (good candidates for modification) and sell the other drilling rigs it now chooses not to market. Adjusted net income attributable to Unit for the quarter (which excludes the effect of non-cash commodity derivatives and the write-down) was $13.8 million, or $0.27 per diluted share compared to $0.22 per diluted share for the same quarter for 2017, a 22% increase in adjusted net income (see Non-GAAP financial measures below). Total revenues for the quarter were $214.8 million (49% oil and natural gas, 25% contract drilling, and 26% mid-stream), compared to $204.8 million (49% oil and natural gas, 23% contract drilling, and 28% mid-stream) for the fourth quarter of 2017. Adjusted EBITDA attributable to Unit was $88.2 million, or $1.69 per diluted share (see Non-GAAP financial measures below).

For 2018, net loss attributable to Unit was $45.3 million, or $0.87 loss per diluted share, compared to net income of $117.8 million, or $2.28 per diluted share, for 2017 (which included the net tax benefit discussed above). For the same period, adjusted net income attributable to Unit (which excludes the effect of non-cash commodity derivatives and the write-down) was $51.9 million, or $1.00 per diluted share, compared to $0.54 per diluted share for 2017, an 87% increase in adjusted net income (see Non-GAAP financial measures below). Total revenues for the year were $843.3 million (50% oil and natural gas, 23% contract drilling, and 27% mid-stream), compared to $739.6 million (48% oil and natural gas, 24% contract drilling, and 28% mid-stream) for 2017. Adjusted EBITDA attributable to Unit for 2018 was $349.7 million, or $6.73 per diluted share (see Non-GAAP financial measures below).

MANAGEMENT COMMENTS

Larry Pinkston, Unit’s Chief Executive Officer and President, said: “During the fourth quarter, as part of our periodic evaluation process, we removed 41 drilling rigs from our fleet as well as some other equipment. Those rigs included our 29 remaining mechanical drilling rigs and 12 of our SCR drilling rigs that were not considered to be economic to upgrade to meet market demands. Our remaining rig fleet includes 13 BOSS AC drilling rigs as well as upgraded SCR rigs that are well suited for current operator requirements. Additionally, we have other SCR rigs that are available to return to service as market conditions and demand improve or are good candidates for upgrade to meet future customer demands and requirements. Our drilling rig fleet now totals 57 rigs.”

“For our oil and natural gas segment, we are focusing on increasing the proportion of oil in our production mix. As part of this effort, we are building a position in western Oklahoma to add drilling inventory in prospective areas we believe have a greater concentration of oil. We continue to look for bolt-on opportunities near our existing core areas.”

OIL AND NATURAL GAS SEGMENT INFORMATION

For the quarter, total equivalent production was 4.3 MMBoe, a 1% decrease from the third quarter of 2018. Oil and natural gas liquids (NGLs) production represented 46% of total equivalent production, of which, oil production increased 9% over the third quarter of 2018. Oil production was 8,187 barrels per day. NGLs production was 13,290 barrels per day. Natural gas production was 152.8 million cubic feet (MMcf) per day. Overall, total production for 2018 was 17.1 MMBoe, a 7% increase over 2017.

Unit’s average realized per barrel equivalent price for the quarter was $23.99, a 1% decrease from the third quarter of 2018. Unit’s average oil price was $54.01 per barrel, a decrease of 6% from the third quarter of 2018. Unit’s average NGLs price was $19.61 per barrel, a decrease of 24% from the third quarter of 2018. Unit’s average natural gas price was $2.77 per Mcf, an increase of 22% over the third quarter of 2018. All prices in this paragraph include the effects of derivative contracts.

Late in the third quarter 2018, Unit drilled the Schrock 22/15 #1HX in the Penn sands prospect area in western Oklahoma, the first Red Fork extended lateral well drilled in Oklahoma. The Schrock IP30 was over 2,000 barrels of oil equivalent (Boe) per day with an approximate 80% oil cut. In addition, Unit brought on the Frymire 1-18H, a second Red Fork lateral well in late October, which had an IP30 of 850 Boe per day that was primarily high BTU natural gas with some oil. The well cost for the Red Fork wells was approximately $6 million for a one-mile lateral and $7.5 million for a two-mile lateral. Subsequent to these well results, Unit acquired offsetting oil and natural gas assets in December for $29.6 million. The acquired properties added approximately 8,700 net acres largely held by production to the Penn sands area, including 44 wells and approximately 2.6 MMBoe of proved reserves. The acquisition provides Unit approximately 20 to 30 horizontal Red Fork drilling locations, which are anticipated to have a significant percentage of oil in the total production stream.

In the SOHOT play, in western Oklahoma, primarily in Grady County, Unit continues to drill horizontal wells in the oily Marchand sand. Unit is having success adding small parcels of acreage at a reasonable cost which should permit the company to add a second rig to its drilling program in the second quarter.

In the Texas Panhandle Granite Wash play, Unit continued its one rig drilling program. The results from its first two Granite Wash “G” extended lateral wells in the field have been good with initial rates from each well exceeding 10 MMcfe per day. Unit is continuing with its Granite Wash drilling program through the first quarter of 2019 before moving the rig to its western Oklahoma assets that are likely to have a higher oil cut. Unit’s land position in the Texas Panhandle area is largely held by production allowing it to drill when pricing is most optimal.

In the Wilcox play, Unit continued its development drilling and re-completion program during the fourth quarter. Additionally, Unit drilled a successful delineation well in its Shoal Creek prospect that has continued to increase in production since coming online in October and is currently producing approximately 8.5 MMcfe per day of high BTU gas and oil. Unit will continue delineating this and other prospects in 2019, one of which will be the Wolf Pasture #1, the first delineation well in its Cherry Creek prospect. In addition, Unit plans to complete approximately 10 behind pipe gas and liquids zones during 2019.

Pinkston said: “Our oil and natural gas segment continues to focus on expanding the favorable results we have obtained western Oklahoma by increasing our footprint in that area. Our acquisition in the Penn sands area follows the strong results from our two Red Fork wells described in the operations update. We remain focused on adding to this position."

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,   Dec 31,   Change Dec 31,   Sept 30,   Change Dec 31,   Dec 31,   Change
    2018   2017     2018   2018     2018   2017    
Oil and NGLs Production, MBbl   1,976   1,986   (1)% 1,976   1,970   —% 7,799   7,453   5%
Natural Gas Production, Bcf   14.1   13.9   1% 14.1   14.3   (2)% 55.6   51.3   9%
Production, MBoe   4,318   4,310   —% 4,318   4,359   (1)% 17,070   15,996   7%
Production, MBoe/day   46.9   46.8   —% 46.9   47.4   (1)% 46.8   43.8   7%
Avg. Realized Natural Gas Price, Mcf (1)   $ 2.77   $ 2.38   16% $ 2.77   $ 2.27   22% $ 2.46   $ 2.46   —%
Avg. Realized NGL Price, Bbl (1)   $ 19.61   $ 21.88   (10)% $ 19.61   $ 25.66   (24)% $ 22.18   $ 18.35   21%

Avg. Realized Oil Price, Bbl (1)

  $ 54.01   $ 54.45   (1)% $ 54.01   $ 57.72   (6)% $ 55.78   $ 49.44   13%

Realized Price / Boe (1)

  $ 23.99   $ 23.25   3% $ 23.99   $ 24.15   (1)% $ 23.80   $ 21.72   10%
Operating Profit Before Depreciation, Depletion, Amortization & Impairment (MM) (2)   $ 74.9   $ 66.6   12% $ 74.9   $ 79.5   (6)% $ 291.4   $ 227.0   28%
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 2018 ESTIMATED PROVED RESERVES

The discount rate (PV-10) value of Unit’s estimated year-end 2018 proved reserves increased 23% over 2017 to $1.1 billion. Estimated year-end 2018 proved oil and natural gas reserves were 159.7 MMBoe, or 958.1 billion cubic feet of natural gas equivalents (Bcfe), as compared with 149.8 MMBoe, or 898.6 Bcfe, at year-end 2017, a 7% increase. Estimated reserves were 14% oil, 30% NGLs, and 56% natural gas.

The following details the changes to Unit’s proved oil, NGLs, and natural gas reserves during 2018:

        Proved
Oil NGLs Natural Gas Reserves
(MMbls)   (MMbls)   (Bcf)   (MMBoe)
 
Proved Reserves, at December 31, 2017 19.5 45.5 508.7 149.8
Revisions of previous estimates 0.2 (1.4) (17.9) (4.1)
Extensions, discoveries, and other

additions

5.2 7.9 99.6 29.7
Purchases of minerals in place 0.7 0.9 6.9 2.7
Production (2.9) (4.9) (55.6) (17.1)
Sales (0.1)   (0.2)   (5.7)   (1.3)
Proved Reserves, at December 31, 2018 22.6   47.8   536.0   159.7

Estimated 2018 year-end proved reserves included proved developed reserves of 111.6 MMBoe, or 669.5 Bcfe, (14% oil, 30% NGLs, and 56% natural gas) and proved undeveloped reserves of 48.1 MMBoe, or 288.6 Bcfe, (15% oil, 30% NGLs, and 55% natural gas). Overall, 70% of the estimated proved reserves are proved developed.

The present value of the estimated future net cash flows from 2018 estimated proved reserves (before income taxes and using a PV-10), is approximately $1.1 billion. The present value was determined using the required SEC's pricing methodology. The benchmark price used for all future reserves was $65.56 per barrel of oil, $37.68 per barrel of NGLs, and $3.10 per Mcf of natural gas (then adjusted for price differentials). Ryder Scott Company, L.P. independently audited Unit’s 2018 year-end proved reserves. Their audit covered properties accounting for 82% 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.

Pinkston said: "Our goal is to replace at least 150% of each year's production with new reserves. In 2018, we achieved our goal by replacing 158% of production with new reserves and maintained a capital expenditure program in line with our cash flow and proceeds from divestitures."

CONTRACT DRILLING SEGMENT INFORMATION

Unit's average number of working drilling rigs during the quarter was 33.1, a decrease of 3% from the third quarter of 2018. Per day drilling rig rates averaged $18,047, a 3% increase over the third quarter of 2018. Average per day operating margin for the quarter was $5,859 (before elimination of intercompany drilling rig profit and bad debt expense of $0.6 million). This compares to third quarter 2018 average operating margin of $6,291 (before elimination of intercompany drilling rig profit of $1.2 million), a decrease of 7%, or $432.

Pinkston said: “During the quarter, drilling rig demand declined as operators made adjustments because of the decrease in commodity prices. During January, we completed and placed into service our 12th BOSS rig. And this month our 13th BOSS rig was placed into service under a long-term contract. Currently, we have 32 rigs operating. We had 24 long-term contracts (contracts with original terms ranging from six months to three years in length) as of the end of the quarter. Included in these 24 term contracts are the two new BOSS rigs that have been placed into service, noted above, and two term contracts that rolled over in the first quarter of 2019 to two year terms. Of the remaining 20 long-term contracts, seven are up for renewal in the first quarter of 2019, seven in the second quarter, one in the third quarter, two in the fourth quarter, and three in 2020 and thereafter.”

This table illustrates certain comparative results for the periods indicated:

 
    Three Months Ended   Three Months Ended   Twelve Months Ended
  Dec 31,   Dec 31,   Change Dec 31,   Sept 30,   Change Dec 31,   Dec 31,   Change
    2018   2017     2018   2018     2018   2017    
Rigs Utilized   33.1   31.2   6% 33.1   34.2   (3)% 32.8   30.0   9%
Operating Profit Before Depreciation (MM) (1)   $ 17.2   $ 15.3   12%   $ 17.2   $ 18.6   (8)%   $ 65.1   $ 52.1   25%
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 gathering and liquids sold volumes per day decreased 5% and 1%, respectively, while gas processing volumes per day remained relatively unchanged, as compared to the third quarter of 2018. Operating profit (as defined in the footnote below) for the quarter was $12.5 million, a decrease of 15% from the third quarter of 2018.

This table illustrates certain comparative results for the periods indicated:

 
    Three Months Ended   Three Months Ended   Twelve Months Ended
  Dec 31,   Dec 31,   Change Dec 31,   Sept 30,   Change Dec 31,   Dec 31,   Change
    2018   2017     2018   2018     2018   2017    
Gas Gathering, Mcf/day   394,203   383,319   3% 394,203   415,862   (5)% 393,613   385,209   2%
Gas Processing, Mcf/day   160,786   148,422   8% 160,786   160,294   —% 158,189   137,625   15%
Liquids Sold, Gallons/day   697,161   581,874   20% 697,161   700,523   (1)% 663,367   534,140   24%
Operating Profit Before Depreciation and Amortization (MM) (1)   $ 12.4   $ 13.1   (5)%   $ 12.4   $ 14.7   (16)%   $ 55.9   $ 51.7   8%
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: “Our mid-stream segment completed the connection of the J. R. Miller pad to its Pittsburgh Mills gathering system during the fourth quarter. The operator of that pad began bringing two of the seven new wells on line in January. Superior continues to make progress on the construction of its new Reeding gas processing plant, which will be integrated into its Cashion gathering system. The new gas processing plant is anticipated to commence operation by the end of the first quarter.”

2019 CAPITAL BUDGET AND PRODUCTION GUIDANCE

Unit’s 2019 capital budget is anticipated to range from $336 million to $422 million, a decrease of 27% to 8% from 2018, excluding acquisitions. The decrease is in response to the current commodity price environment and keeps the budget in-line with anticipated cash flow plus proceeds from any non-core asset sales. The capital budget is allocated, as follows, among the three business segments: $271 million to $315 million for the oil and natural gas segment; $30 million to $65 million for the contract drilling segment; and $35 million to $42 million for the mid-stream segment. The budget does not include amounts for any possible acquisitions and is based on realized prices for the year averaging $55.04 per barrel of oil, $24.73 per barrel of natural gas liquids, and $3.00 per Mcf of natural gas (all prices are before differentials and hedges are applied).

Unit’s oil and natural gas segment’s 2019 production is anticipated to be 17.4 to 17.9 MMBoe (an increase of 2% to 5%, year-over-year) based on the capital budget range.

Pinkston said: "We have considerably reduced our 2019 capital expenditure plans from 2018 levels. Historically, we have focused on keeping our capital expenditure budget in line with anticipated cash flow, adjusting our spending mid-year if conditions warranted a change. We begin 2019 with the same objective of maintaining our capital spending in line with anticipated cash flow."

FINANCIAL INFORMATION

Unit ended the quarter with long-term debt of $644.5 million, consisting solely of senior subordinated notes (net of unamortized discount and debt issuance costs) and no borrowings under the Unit or Superior credit agreements. In October, Unit signed the Fifth Amendment to its credit agreement providing in part for the extension of the maturity to October 18, 2023. The Unit credit agreement is subject to an elected commitment and borrowing base of $425 million. Besides extending the term, the amendment increased the company’s flexibility around issuing senior notes and lowered the pricing on certain borrowings and fees.

WEBCAST

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

Unit will webcast its fourth quarter earnings conference call live over the Internet on February 21, 2019, at 10:00 a.m. Central Time (11:00 a.m. Eastern). To listen to the live call, please go to http://www.unitcorp.com/investor/calendar.htm at least fifteen minutes before the start of the call to download and install any necessary audio software. For those who are not available to listen to the live webcast, a replay will be available shortly after the call and will remain on the site for 90 days.

_____________________________________________________

Unit Corporation is a Tulsa-based, publicly held energy company engaged through its subsidiaries in oil and gas exploration, production, contract drilling, and gas gathering and processing. Unit’s Common Stock is 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 agreement, the number of wells to be drilled by the company’s oil and natural gas segment, the potential productive capability of its prospective plays, 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,
    2018   2017 2018   2017
Statement of Operations:  
Revenues:
Oil and natural gas $ 106,019 $ 101,503 $ 423,059 $ 357,744
Contract drilling 52,965 46,661 196,492 174,720
Gas gathering and processing 55,804 56,683 223,730 207,176
Total revenues 214,788 204,847 843,281 739,640
Expenses:
Operating costs:
Oil and natural gas 31,156 34,916 131,675 130,789
Contract drilling 35,792 31,387 131,385 122,600
Gas gathering and processing 43,395 43,621 167,836 155,483
Total operating costs 110,343 109,924 430,896 408,872
 
Depreciation, depletion, and amortization 64,629 57,712 243,605 209,257
Impairments 147,884 147,884
General and administrative 9,955 11,185 38,707 38,087
(Gain) loss on disposition of assets (129) 826 (704) (327)
Total expenses 332,682 179,647 860,388 655,889
 
Income (loss) from operations (117,894) 25,200 (17,107) 83,751
 
Other income (expense):
Interest, net (7,816) (9,527) (33,494) (38,334)
Gain (loss) on derivatives not designated as hedges 22,424 (6,287) (3,184) 14,732
Other 5 7 22 21
Total other income (expense) 14,613 (15,807) (36,656) (23,581)
 
Income (loss) before income taxes (103,281) 9,393 (53,763) 60,170
 
Income tax expense (benefit):
Current (3,131) 5 (3,131) 5
Deferred (23,245) (79,767) (10,865) (57,683)
Total income taxes (26,376) (79,762) (13,996) (57,678)
 
Net income (loss) (76,905) 89,155 (39,767) 117,848
Net income attributable to non-controlling interest 935 5,521
Net income (loss) attributable to Unit Corporation $ (77,840) $ 89,155 $ (45,288) $ 117,848
 
Net income (loss) attributable to Unit Corporation per common share:
Basic $ (1.49) $ 1.71 $ (0.87) $ 2.31
Diluted $ (1.49) $ 1.71 $ (0.87) $ 2.28
 
Weighted average shares outstanding:
Basic 52,070 51,394 51,981 51,113
Diluted 52,070 52,201 51,981 51,748
 
Unit Corporation
Selected Financial Highlights - continued

(In thousands)

 
  Twelve Months Ended December 31,
    2018   2017
Statement of Cash Flows Data:  
Cash flow from operations before changes in operating assets and liabilities $ 345,582 $ 276,811
Net change in operating assets and liabilities 2,177 (10,855)
Net cash provided by operating activities $ 347,759 $ 265,956
Net cash used in investing activities $ (450,342) $ (293,366)
Net cash provided by (used in) financing activities $ 108,334 $ 27,218

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 is a reconciliation of GAAP financial measures to Non-GAAP financial measures for the three and twelve months ended December 31, 2018 and 2017. Non-GAAP financial measures should not be considered by themselves or a substitute for results reported under GAAP. This Non-GAAP information should be considered by the reader beside, 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,
2018   2017   2018   2017
(In thousands except earnings per share)
Adjusted net income attributable to Unit Corporation:    
Net income (loss) attributable to Unit Corporation $ (77,840) $ 89,155 $ (45,288) $ 117,848
Impairment adjustment (net of income tax) 111,652 111,652
(Gain) loss on derivatives (net of income tax) (16,198) 2,930 2,356 (8,949)
Settlements during the period of matured derivative contracts (net of income tax) (3,796) 517 (16,867) 105
Tax Act income tax benefit (81,307) (81,307)
Adjusted net income (loss) $ 13,818 $ 11,295 $ 51,853 $ 27,697
 
Adjusted diluted earnings per share attributable to Unit Corporation:
Diluted earnings (loss) per share $ (1.49) $ 1.71 $ (0.87) $ 2.28
Diluted earnings per share from the impairments 2.14 2.14
Diluted earnings per share from the (gain) loss on derivatives (0.31) 0.06 0.05 (0.17)
Diluted earnings (loss) per share from the settlements of matured derivative contracts (0.07) 0.01 (0.32)
Diluted earnings (loss) per share from the Tax Act income tax benefit (1.56) (1.57)
Adjusted diluted earnings (loss) per share attributable to Unit Corporation $ 0.27 $ 0.22 $ 1.00 $ 0.54
 
Weighted Shares (Denominator) 52,070 52,201 51,981 51,748

________________

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, 2018

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:

  2018
(In millions)
PV-10 at December 31, 2018 $ 1,105.7
Discounted effect of income taxes (122.0)
Standardized Measure at December 31, 2018 $ 983.7
 
Unit Corporation
Reconciliation of Segment Operating Profit
 
  Three Months Ended   Twelve Months Ended
September 30,   December 31, December 31,
2018   2018   2017   2018   2017
(In thousands)
Oil and natural gas $ 79,484 $ 74,863   $ 66,587 $ 291,384   $ 226,955
Contract drilling 18,580 17,173 15,274 65,107 52,120
Gas gathering and processing 14,689 12,409 13,062 55,894 51,693
Total operating profit 112,753 104,445 94,923 412,385 330,768
Depreciation, depletion and amortization (63,537) (64,629) (57,712) (243,605) (209,257)
Impairments (147,884) (147,884)
Total operating income (loss) 49,216 (108,068) 37,211 20,896 121,511
General and administrative (9,278) (9,955) (11,185) (38,707) (38,087)
Gain (loss) on disposition of assets 253 129 (826) 704 327
Interest, net (7,945) (7,816) (9,527) (33,494) (38,334)
Gain (loss) on derivatives (4,385) 22,424 (6,287) (3,184) 14,732
Other 6 5 7 22 21
Income (loss) before income taxes $ 27,867 $ (103,281) $ 9,393 $ (53,763) $ 60,170

________________

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,
2018   2018   2017   2018   2017
(In thousands except for operating days and operating margins)
Contract drilling revenue $ 50,612 $ 52,965   $ 46,661 $ 196,492   $ 174,720
Contract drilling operating cost 32,032 35,792 31,387 131,385 122,600
Operating profit from contract drilling 18,580 17,173 15,274 65,107 52,120
Add:
Elimination of intercompany rig profit and bad debt expense 1,186 644 642 3,078 1,620
Operating profit from contract drilling before elimination of intercompany rig profit and bad debt expense 19,766 17,817 15,916 68,185 53,740
Contract drilling operating days 3,142 3,041 2,868 11,960 10,964
Average daily operating margin before elimination of intercompany rig profit and bad debt expense $ 6,291 $ 5,859 $ 5,550 $ 5,701 $ 4,901

________________

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,
2018   2017
(In thousands)
Net cash provided by operating activities $ 347,759   $ 265,956
Net change in operating assets and liabilities (2,177) 10,855
Cash flow from operations before changes in operating assets and liabilities $ 345,582 $ 276,811

________________

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,
2018   2017   2018   2017
(In thousands except earnings per share)
   
Net income (loss) $ (76,905) $ 89,155 $ (39,767) $ 117,848
Income taxes (26,376) (79,762) (13,996) (57,678)
Depreciation, depletion and amortization 64,629 57,712 243,605 209,257
Impairments 147,884 147,884
Interest expense 7,816 9,527 33,494 38,334
(Gain) loss on derivatives (22,424) 6,287 3,184 (14,732)
Settlements during the period of matured derivative contracts (4,763) 902 (22,803) 173
Stock compensation plans 5,502 5,269 22,899 17,747
Other non-cash items (735) 774 (2,576) 2,886
(Gain) loss on disposition of assets (129) 826 (704) (327)
Adjusted EBITDA 94,499 90,690 371,220 313,508
Adjusted EBITDA attributable to non-controlling interest 6,315 21,488
Adjusted EBITDA attributable to Unit Corporation $ 88,184 $ 90,690 $ 349,732 $ 313,508
 
Diluted earnings (loss) per share attributable to Unit $ (1.49) $ 1.71 $ (0.87) $ 2.28
Diluted earnings per share from income taxes (0.52) (1.53) (0.26) (1.11)
Diluted earnings per share from depreciation, depletion and amortization 1.13 1.11 4.36 4.04
Diluted earnings per share from impairments 2.84 2.84
Diluted earnings per share from interest expense 0.15 0.18 0.63 0.74
Diluted earnings per share from the (gain) loss on derivatives (0.43) 0.12 0.06 (0.28)
Diluted earnings per share from the settlements during the period of matured derivative contracts (0.09) 0.02 (0.44)
Diluted earnings per share from stock compensation plans 0.10 0.10 0.43 0.34
Diluted earnings per share from other non-cash items 0.01 (0.01) 0.06
Diluted earnings per share (gain) loss on disposition of assets 0.02 (0.01) (0.01)
Adjusted EBITDA per diluted share $ 1.69 $ 1.74 $ 6.73 $ 6.06
 
Weighted Shares (Denominator) 52,070 52,201 51,981 51,748

________________

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.

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