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Share Name | Share Symbol | Market | Type |
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Unit Corp | NYSE:UNT | NYSE | Common Stock |
Price Change | % Change | Share Price | High Price | Low Price | Open Price | Shares Traded | Last Trade | |
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0.00 | 0.00% | 0.2358 | 0 | 01:00:00 |
Unit Corporation (NYSE: UNT) today reported its financial and operational results for the second quarter 2016. Highlights include:
SECOND QUARTER AND FIRST SIX MONTHS 2016 FINANCIAL RESULTS
Unit recorded a net loss of $72.1 million for the quarter, or $1.44 per share, compared to a net loss of $274.4 million, or $5.58 per share, for the second quarter of 2015. For the second quarter of 2016 and 2015, Unit incurred pre-tax non-cash ceiling test write-downs of $74.3 million and $410.5 million, respectively, in the carrying value of its oil and natural gas properties. These non-cash ceiling test write-downs have resulted from continued lower commodity prices. Adjusted net loss (which excludes the effect of non-cash commodity derivatives and the effect of the non-cash write-down) for the quarter was $7.4 million, or $0.15 per share (see Non-GAAP financial measures below). Total revenues were $138.3 million (50% oil and natural gas, 18% contract drilling, and 32% mid-stream), compared to $214.4 million (50% oil and natural gas, 26% contract drilling, and 24% mid-stream) for the second quarter of 2015. Adjusted EBITDA was $54.1 million, or $1.07 per diluted share (see Non-GAAP financial measures below).
For the first six months of 2016, Unit recorded a net loss of $113.3 million, or $2.27 per share, compared to a net loss of $522.7 million, or $10.66 per share, for the first six months of 2015. Unit incurred pre-tax non-cash ceiling test write-downs of $112.1 million and $811.1 million in the carrying value of its oil and natural gas properties during the first six months of 2016 and 2015, respectively. Unit recorded an adjusted net loss (which excludes the effect of non-cash commodity derivatives and the effect of the non-cash write-down) of $27.7 million, or $0.55 per share (see Non-GAAP financial measures below). Total revenues for the first six months were $274.5 million (46% oil and natural gas, 23% contract drilling, and 31% mid-stream), compared to $469.5 million (45% oil and natural gas, 32% contract drilling, and 23% mid-stream) for the first six months of 2015. Adjusted EBITDA for the first six months was $102.5 million, or $2.04 per diluted share (see Non-GAAP financial measures below).
OIL AND NATURAL GAS SEGMENT INFORMATION
For the quarter, total production was 4.4 million barrels of oil equivalent (MMBoe), a decrease of 14% from the second quarter of 2015 and a 3% decrease from the first quarter of 2016. The decrease in production resulted primarily from Unit's previous decision to reduce its new well drilling plans because of low commodity prices. Liquids (oil and NGLs) production represented 45% of total equivalent production. Oil production was 8,309 barrels per day, a decrease of 20% from the second quarter of 2015 and a decrease of 6% from the first quarter of 2016. NGLs production was 13,120 barrels per day, a decrease of 10% from the second quarter of 2015 and an 8% decrease from the first quarter of 2016. Natural gas production was 158,844 thousand cubic feet (Mcf) per day, a decrease of 13% from the second quarter of 2015 and essentially flat with the first quarter of 2016. Total production for the first six months of 2016 was 8.9 MMBoe.
Unit’s average realized per barrel equivalent price was $16.27, a decrease of 27% from the second quarter of 2015 and a 19% increase over the first quarter of 2016. Unit’s average natural gas price was $1.80 per Mcf, a decrease of 33% from the second quarter of 2015 and a decrease of 4% from the first quarter of 2016. Unit’s average oil price was $41.52 per barrel, a decrease of 25% from the second quarter of 2015 and an increase of 28% over the first quarter of 2016. Unit’s average NGLs price was $11.38 per barrel, a 6% decrease from the second quarter of 2015 and an increase of 73% over the first quarter of 2016. All prices in this paragraph include the effects of derivative contracts.
For the quarter, Unit achieved record production of approximately 97 MMcfe per day from its Wilcox play, representing a 25% increase over the second quarter of 2015 and a 9% increase over the first quarter of 2016. This production growth is attributed to first oil and natural gas sales from new horizontal wells and behind pipe recompletions that occurred primarily in the first quarter of 2016. Through the end of the second quarter, the company completed new behind pipe Wilcox intervals in four existing wells that are producing 17 MMcfe per day. These same four wells were producing approximately 700 Mcfe per day before the recompletions. Unit anticipates recompleting approximately four to six new behind pipe zones during the second half of the year.
In the Southern Oklahoma Hoxbar Oil Trend (SOHOT), Unit completed one new well during the quarter with an average 30 day IP rate of approximately 720 barrels of oil equivalent (Boe) per day. Unit anticipates resuming drilling Marchand oil wells during the fourth quarter, using a Unit drilling rig.
In the Buffalo Wallow field in the Granite Wash play, a horizontal “C1” well was completed with an extended lateral of approximately 7,500 feet. The well, which is Unit's first extended lateral drilled in this field, is currently producing approximately 12.1 MMcfe per day consisting of 43% natural gas, 15% oil, and 42% NGLs. Unit anticipates beginning a one or two drilling rig extended lateral development program in the Buffalo Wallow field late in the fourth quarter of 2016 or early 2017.
Larry Pinkston, Unit’s Chief Executive Officer and President, said: “We are pleased with the results of the wells that were completed during the first half of the year as well as the results of our behind pipe recompletions. We continue to increase our leasehold in our core areas and identify additional potential drilling locations. Depending on commodity prices, our plan will be to resume our drilling program in the latter part of the year.”
This table illustrates certain comparative production, realized prices, and operating profit for the periods indicated:
Three Months Ended Three Months Ended Six Months EndedJune 30,2016
June 30,2015
ChangeJune 30,2016
Mar. 31,2016
ChangeJune 30,2016
June 30,2015
Change Oil and NGLs Production, MBbl 1,950 2,277 (14 )% 1,950 2,094 (7 )% 4,044 4,661 (13 )% Natural Gas Production, Bcf 14.5 16.7 (13 )% 14.5 14.5 — % 29.0 33.1 (12 )% Production, MBoe 4,359 5,054 (14 )% 4,359 4,514 (3 )% 8,873 10,171 (13 )% Production, MBoe/day 47.9 55.5 (14 )% 47.9 49.6 (3 )% 48.8 56.2 (13 )% Avg. Realized Natural Gas Price, Mcf (1) $ 1.80 $ 2.67 (33 )% $ 1.80 $ 1.87 (4 )% $ 1.83 $ 2.80 (35 )% Avg. Realized NGL Price, Bbl (1) $ 11.38 $ 12.05 (6 )% $ 11.38 $ 6.59 73 % $ 8.90 $ 10.37 (14 )% Avg. Realized Oil Price, Bbl (1) $ 41.52 $ 55.52 (25 )% $ 41.52 $ 32.50 28 % $ 36.88 $ 51.73 (29 )% Realized Price / Boe (1) $ 16.27 $ 22.38 (27 )% $ 16.27 $ 13.67 19 % $ 14.95 $ 22.18 (33 )% Operating Profit Before Depreciation, Depletion, & Amortization (MM) (2) $ 35.9 $ 61.3 (42 )% $ 35.9 $ 24.9 44 % $ 60.8 $ 122.1 (50 )% (1) Realized price includes oil, natural gas liquids, natural gas, and associated derivatives. (2) Operating profit before depreciation is calculated by taking operating revenues for this segment less operating expenses excluding depreciation, depletion, amortization, and impairment. (See non-GAAP financial measures below.)This table summarizes the outstanding derivative contracts.
Crude Period StructureVolumeBbl/Day
WeightedAverageFixed Price
WeightedAverageFloor Price
WeightedAverageSubfloor Price
WeightedAverageCeiling Price
Jul'16 - Sep'16 Swap 1,000 $48.45 Jul'16 - Sep'16 Collar 2,450 $44.44 $52.46 Oct'16 - Dec'16 Collar 1,450 $47.50 $56.40 Jul'16 - Dec'16 3-Way Collar 700 $46.50 $35.00 $57.00 Jul'16 - Dec'16 3-Way Collar (1) 700 $47.50 $35.00 $63.50 Jan'17 - Dec'17 3-Way Collar 750 $50.00 $37.50 $63.90 Natural Gas Period StructureVolumeMMBtu/Day
WeightedAverageFixed Price
WeightedAverageFloor Price
WeightedAverageSubfloor Price
WeightedAverageCeiling Price
Jul'16 - Dec'16 Swap 45,000 $2.596 Jan'17 - Dec'17 Swap 60,000 $2.960 Jan'18 - Dec'18 Swap 10,000 $3.025 Jan'17 - Dec'17 Basis Swap 20,000 $(0.215) Jan'18 - Dec'18 Basis Swap 10,000 $(0.208) Jul'16 - Dec'16 Collar 42,000 $2.40 $2.88 Jan-17 - Oct'17 Collar 20,000 $2.88 $3.10 Jul'16 - Dec'16 3-Way Collar 13,500 $2.70 $2.20 $3.26 Jan'17 - Dec'17 3-Way Collar 15,000 $2.50 $2.00 $3.32 (1) Unit pays its counterparty a premium, which can be and is being deferred until settlement.CONTRACT DRILLING SEGMENT INFORMATION
The average number of Unit's drilling rigs working during the quarter was 13.5, a decrease of 56% from the second quarter of 2015 and a decrease of 34% from the first quarter of 2016. Per day drilling rig rates averaged $18,585, a decrease of 7% from the second quarter of 2015 and a 1% increase over the first quarter of 2016. For the first six months of 2016, per day drilling rig rates averaged $18,468, an 8% decrease from the first six months of 2015. Average per day operating margin for the quarter was $4,259 (before elimination of intercompany drilling rig profit and bad debt expense of $0.2 million). This compares to second quarter 2015 average operating margin of $6,821 (before elimination of intercompany drilling rig profit and bad debt expense of $0.5 million), a decrease of 38%, or $2,562. Second quarter 2016 average operating margin decreased 25%, or $1,392, as compared to that of $5,651 for the first quarter of 2016 (in each case regarding eliminating intercompany drilling rig profit and bad debt expense - see Non-GAAP financial measures below). Average operating margins for the quarter included early termination fees of approximately $0.4 million, or $342 per day, from the cancellation of certain long-term contracts, compared to early termination fees of $1.6 million, or $594 per day, during the second quarter of 2015 and $2.6 million, or $1,410 per day, for the first quarter of 2016.
Pinkston said: “Although we saw a slight increase in commodity prices during the quarter, operators remain cautious about contracting new drilling rigs, resulting in our average utilization rate continuing to fall quarter over quarter. Currently, we have seven of our eight BOSS drilling rigs under contract. Our drilling rig fleet totals 94 drilling rigs, of which 16 are working under contract after rebounding from a low of 13 drilling rigs during the second quarter. Long-term contracts (contracts with original terms ranging from six months to two years in length) are in place for five of our drilling rigs. Of the five, one is up for renewal during the fourth quarter, and four in 2017.”
This table illustrates certain comparative results for the periods indicated:
Three Months Ended Three Months Ended Six Months EndedJune 30,2016
June 30,2015
ChangeJune 30,2016
Mar. 31,2016
ChangeJune 30,2016
June 30,2015
Change Rigs Utilized 13.5 30.7 (56 )% 13.5 20.6 (34 )% 17.1 40.4 (58 )% Operating Profit Before Depreciation, Depletion, & Amortization (MM) (1) $ 5.0 $ 18.5 (73 )% $ 5.0 $ 10.6 (53 )% $ 15.6 $ 61.9 (75 )% (1) Operating profit before depreciation is calculated by taking operating revenues for this segment less operating expenses excluding depreciation and impairment. (See non-GAAP financial measures below.)MID-STREAM SEGMENT INFORMATION
For the quarter, per day gas gathered volumes increased 21%, while gas processed and liquids sold volumes decreased 13% and 11%, respectively, as compared to the second quarter of 2015. Compared to the first quarter of 2016, gas gathered and liquids sold volumes per day increased 15% and 2%, respectively, while gas processed volumes per day decreased 3%. Operating profit (as defined in the footnote below) for the quarter was $12.5 million, an increase of 8% over the second quarter of 2015 and an increase of 53% over the first quarter of 2016.
For the first six months of 2016, per day gas gathered volumes increased 18%, while gas processed and liquids sold volumes per day decreased 12% and 10%, respectively, as compared to the first six months of 2015. Operating profit (as defined in the footnote below) for the first six months of 2016 was $20.6 million, a decrease of 4% from the first six months of 2015.
This table illustrates certain comparative results for the periods indicated:
Three Months Ended Three Months Ended Six Months EndedJune 30,2016
June 30,2015
ChangeJune 30,2016
Mar. 31,2016
ChangeJune 30,2016
June 30,2015
Change Gas Gathering, Mcf/day 439,937 362,896 21 % 439,937 383,405 15 % 411,671 348,666 18 % Gas Processing, Mcf/day 161,619 186,041 (13 )% 161,619 167,048 (3 )% 164,333 187,592 (12 )% Liquids Sold, Gallons/day 532,215 599,732 (11 )% 532,215 519,433 2 % 525,824 584,389 (10 )% Operating Profit Before Depreciation, Depletion, & Amortization (MM) (1) $ 12.5 $ 11.6 8 % $ 12.5 $ 8.1 53 % $ 20.6 $ 21.4 (4 )% (1) Operating profit before depreciation is calculated by taking operating revenues for this segment less operating expenses excluding depreciation, amortization, and impairment. (See non-GAAP financial measures below.)Pinkston said: “In the Wilcox in southeast Texas, our Segno system connected three new wells since the beginning of 2016. The Segno system's average daily gathered volume increased nearly 7% quarter over quarter to more than 90 MMcf per day. In the Marcellus, we connected an additional well pad during the quarter which included two new wells to our Pittsburgh Mills system in Butler County, Pennsylvania. This connection increased average daily gathered volume to 142 MMcf per day, a 54% increase over the first quarter of 2016. We connected a new well pad with three wells to our new Snow Shoe system in Centre County, Pennsylvania. Gathered volumes for this facility continue to increase, averaging 14 MMcf per day in the second quarter. Due to low liquids prices, our midstream segment remained in full ethane rejection mode for most of the quarter at our various gas processing facilities in the Mid-Continent.”
FINANCIAL INFORMATION
Unit ended the quarter with long-term debt of $875.1 million (a reduction of $23.6 million from the end of the first quarter), consisting of $639.1 million of senior subordinated notes net of unamortized discount and debt issuance costs and $236.0 million of borrowings under its credit agreement. Under the credit agreement, the amount Unit can borrow is the lesser of the amount it elects as the commitment amount ($475 million) or the value of its borrowing base as determined by the lenders ($475 million), but in either event not to exceed $875 million. The credit agreement was amended during the quarter to provide, in part, for a borrowing base of $475 million.
WEBCAST
Unit will webcast its second quarter earnings conference call live over the Internet on August 4, 2016 at 10:00 a.m. Central Time (11:00 a.m. Eastern). To listen to the live call, please go to http://www.unitcorp.com/investor/calendar.htm at least fifteen minutes prior to the start of the call to download and install any necessary audio software. For those who are not available to listen to the live webcast, a replay will be available shortly after the call and will remain on the site for 90 days.
Unit Corporation is a Tulsa-based, publicly held energy company engaged through its subsidiaries in oil and gas exploration, production, contract drilling, and gas gathering and processing. Unit’s Common Stock is on the New York Stock Exchange under the symbol UNT. For more information about Unit Corporation, visit its website at http://www.unitcorp.com.
FORWARD-LOOKING STATEMENT
This news release contains forward-looking statements within the meaning of the private Securities Litigation Reform Act. All statements, other than statements of historical facts, included in this release that address activities, events, or developments that the Company expects, believes, or anticipates will or may occur in the future are forward-looking statements. Several risks and uncertainties could cause actual results to differ materially from these statements, including changes in commodity prices, the productive capabilities of the Company’s wells, future demand for oil and natural gas, future drilling rig utilization and dayrates, projected rate of the Company’s oil and natural gas production, the amount available to the Company for borrowings, its anticipated borrowing needs under its credit agreement, the number of wells to be drilled by the Company’s oil and natural gas segment, and other factors described from time to time in the Company’s publicly available SEC reports. The Company assumes no obligation to update publicly such forward-looking statements, whether because of new information, future events, or otherwise.
Unit Corporation Selected Financial Highlights(In thousands except per share amounts)
Three Months Ended Six Months Ended June 30, June 30, 2016 2015 2016 2015 Statement of Operations: Revenues: Oil and natural gas $ 69,190 $ 107,256 $ 127,464 $ 213,325 Contract drilling 24,257 55,015 62,967 150,092 Gas gathering and processing 44,858 52,176 84,058 106,129 Total revenues 138,305 214,447 274,489 469,546 Expenses: Oil and natural gas: Operating costs 33,331 45,972 66,677 91,183 Depreciation, depletion, and amortization 30,411 68,101 62,243 145,219 Impairment of oil and natural gas properties 74,291 410,536 112,120 811,129 Contract drilling: Operating costs 19,254 36,485 47,352 88,231 Depreciation 10,918 13,265 23,113 28,278 Impairment of contract drilling equipment — 8,314 — 8,314 Gas gathering and processing: Operating costs 32,381 40,592 63,447 84,767 Depreciation and amortization 11,515 10,848 22,974 21,542 General and administrative 8,382 9,624 17,097 18,994 Gain on disposition of assets (477 ) (415 ) (669 ) (960 ) Total operating expenses 220,006 643,322 414,354 1,296,697 Loss from operations (81,701 ) (428,875 ) (139,865 ) (827,151 ) Other income (expense): Interest, net (10,606 ) (7,956 ) (20,223 ) (15,196 ) Gain (loss) on derivatives (22,672 ) (1,919 ) (11,743 ) 4,667 Other 1 24 (14 ) 22 Total other income (expense) (33,277 ) (9,851 ) (31,980 ) (10,507 ) Loss before income taxes (114,978 ) (438,726 ) (171,845 ) (837,658 ) Income tax expense (benefit): Current — 803 — 868 Deferred (42,842 ) (165,140 ) (58,560 ) (315,783 ) Total income taxes (42,842 ) (164,337 ) (58,560 ) (314,915 ) Net loss $ (72,136 ) $ (274,389 ) $ (113,285 ) $ (522,743 ) Net loss per common share: Basic $ (1.44 ) $ (5.58 ) $ (2.27 ) $ (10.66 ) Diluted $ (1.44 ) $ (5.58 ) $ (2.27 ) $ (10.66 ) Weighted average shares outstanding: Basic 50,074 49,148 49,977 49,063 Diluted 50,074 49,148 49,977 49,063 June 30, December 31, 2016 2015 Balance Sheet Data: Current assets $ 89,294 $ 140,258 Total assets $ 2,552,096 $ 2,799,842 Current liabilities $ 146,757 $ 150,891 Long-term debt $ 875,051 $ 918,995 Other long-term liabilities $ 103,926 $ 140,341 Deferred income taxes $ 211,721 $ 275,750 Shareholders’ equity $ 1,211,221 $ 1,313,580 Six Months Ended June 30, 2016 2015 Statement of Cash Flows Data: Cash flow from operations before changes in operating assets and liabilities $ 77,734 $ 207,221 Net change in operating assets and liabilities 54,982 50,385 Net cash provided by operating activities $ 132,716 $ 257,606 Net cash used in investing activities $ (77,386 ) $ (366,442 ) Net cash (used in) provided by financing activities $ (55,191 ) $ 108,626Non-GAAP Financial Measures
Unit Corporation reports its financial results in accordance with generally accepted accounting principles (“GAAP”). The Company believes certain non-GAAP measures provide users of its financial information and its management additional meaningful information to evaluate the performance of the company.
This press release includes net income (loss) and earnings (loss) per share excluding impairment adjustments and the effect of the cash settled commodity derivatives, its reconciliation of segment operating profit, its drilling segment’s average daily operating margin before elimination of intercompany drilling rig profit and bad debt expense, its cash flow from operations before changes in operating assets and liabilities, and its reconciliation of net income (loss) to adjusted EBITDA.
Below is a reconciliation of GAAP financial measures to non-GAAP financial measures for the three and six months ended June 30, 2016 and 2015. Non-GAAP financial measures should not be considered by themselves or a substitute for results reported in accordance with GAAP. This non-GAAP information should be considered by the reader in addition to, but not instead of, the financial statements prepared in accordance with GAAP. The non-GAAP financial information presented may be determined or calculated differently by other companies and may not be comparable to similarly titled measures.
Unit Corporation Reconciliation of Adjusted Net Income and Adjusted Diluted Earnings per Share Three Months Ended Six Months Ended June 30, June 30, 2016 2015 2016 2015 (In thousands except earnings per share) Adjusted net income: Net loss $ (72,136 ) $ (274,389 ) $ (113,285 ) $ (522,743 ) Impairment (net of income tax) 46,246 260,734 69,795 510,103 (Gain) loss on derivatives not designated as hedges (net of income tax) 15,650 1,238 7,742 (2,786 ) Settlements during the period of matured derivative contracts (net of income tax) 2,870 6,495 8,037 13,223 Adjusted net loss $ (7,370 ) $ (5,922 ) $ (27,711 ) $ (2,203 ) Adjusted diluted earnings per share: Diluted loss per share $ (1.44 ) $ (5.58 ) $ (2.27 ) $ (10.66 ) Diluted earnings per share from impairments 0.92 5.31 1.40 10.40 Diluted earnings per share from (gain) loss on derivatives 0.31 0.02 0.16 (0.06 ) Diluted earnings (loss) per share from settlements of matured derivative contracts 0.06 0.13 0.16 0.27 Adjusted diluted loss per share $ (0.15 ) $ (0.12 ) $ (0.55 ) $ (0.05 )________________
The Company has included the net income and diluted earnings per share including only the cash settled commodity derivatives because:
________________
The Company has included segment operating profit because:
________________
The Company has included the average daily operating margin before elimination of intercompany rig profit and bad debt expense because:
Six Months EndedJune 30,
2016 2015 (In thousands) Net cash provided by operating activities $ 132,716 $ 257,606 Net change in operating assets and liabilities (54,982 ) (50,385 ) Cash flow from operations before changes in operating assets and liabilities $ 77,734 $ 207,221________________
The Company has included the cash flow from operations before changes in operating assets and liabilities because:
________________
The Company has included the adjusted EBITDA excluding gain or loss on disposition of assets and including only the cash settled commodity derivatives because:
View source version on businesswire.com: http://www.businesswire.com/news/home/20160804005325/en/
Unit CorporationMichael D. Earl, 918-493-7700Vice President, Investor Relationswww.unitcorp.com
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