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 August 4, 2015 - 7:30 AM EDT
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Unit Corporation Reports 2015 Second Quarter Results

Unit Corporation (NYSE: UNT) today reported its financial and operational results for the second quarter of 2015. Highlights for the quarter include:

  • Total production of 5.1 million barrels of oil equivalent (MMBoe), a 9% increase over the second quarter of 2014
  • Oil and natural gas liquids (NGLs) production increased 8% over the second quarter of 2014
  • Placed three BOSS drilling rigs into service during the quarter
  • Gas gathered and gas processed volumes per day increased 11% and 15%, respectively, over the second quarter of 2014

SECOND QUARTER AND FIRST SIX MONTHS 2015 RESULTS

Because of significantly lower commodity prices, Unit’s second quarter of 2015 results include the following pre-tax non-cash write downs: $410.5 million ceiling test write down in the carrying value of the company’s oil and natural gas properties and an $8.3 million pre-tax write down for the decline in the carrying value of certain drilling rigs and other assets removed from service. As a result, Unit recorded a net loss of $274.4 million, or $5.58 per share, compared to net income of $54.4 million, or $1.11 per diluted share, for the second quarter of 2014. Adjusted net loss for the quarter (which excludes the effect of non-cash commodity derivatives and the effects of the write-downs) was $5.9 million, or $0.12 per diluted share (see Non-GAAP Financial Measures below). Total revenues for the quarter were $214.4 million (50% oil and natural gas, 26% contract drilling, and 24% mid-stream), compared to $405.4 million (49% oil and natural gas, 28% contract drilling, and 23% mid-stream) for the second quarter of 2014.

For the first six months of 2015, Unit recorded an $811.1 million pre-tax non-cash ceiling test write down in the carrying value of the company’s oil and natural gas properties and an $8.3 million pre-tax write down for the drilling rigs and other assets discussed above. As a result, Unit recorded a net loss of $522.7 million, or $10.66 per share, compared to net income of $111.3 million, or $2.27 per diluted share, for the first six months of 2014. Adjusted net loss for the first six months (which excludes the effect of non-cash commodity derivatives and the effects of the write-downs) was $2.2 million, or $0.05 per diluted share (see Non-GAAP Financial Measures below). Total revenues for the first six months were $469.5 million (45% oil and natural gas, 32% contract drilling, and 23% mid-stream), compared to $793.4 million (49% oil and natural gas, 28% contract drilling, and 23% mid-stream) for the first six months of 2014.

OIL AND NATURAL GAS SEGMENT INFORMATION

Total equivalent production for the quarter was 5.1 million barrels of oil equivalent (MMBoe), an increase of 9% over the second quarter of 2014 and a 1% decrease from the first quarter of 2015. Liquids (oil and NGLs) production represented 45% of total equivalent production for the quarter. Oil production for the quarter was 10,418 barrels per day, essentially unchanged from the second quarter of 2014 and a decrease of 15% from the first quarter of 2015. NGLs production for the quarter was 14,599 barrels per day, an increase of 14% over the second quarter of 2014 and an increase of 2% over the first quarter of 2015. Natural gas production for the quarter was 183,135 thousand cubic feet (Mcf) per day, an increase of 11% over the second quarter of 2014 and an increase of 1% over the first quarter of 2015. Total production for the first six months of 2015 was 10.2 MMBoe.

Unit’s average realized per barrel equivalent price for the second quarter was $22.38, a decrease of 44% from the second quarter of 2014 and a 2% increase from the first quarter of 2015. Unit’s average natural gas price for the second quarter of 2015 was $2.67 per Mcf, a decrease of 34% from the second quarter of 2014 and a 9% decrease from the first quarter of 2015. Unit’s average oil price for the quarter was $55.52 per barrel, a decrease of 41% from the second quarter of 2014 and an increase of 15% over the first quarter of 2015. Unit’s average NGLs price for the quarter was $12.05 per barrel, a 60% decrease from the second quarter of 2014 and an increase of 39% over the first quarter of 2015. All prices in this paragraph include the effects of derivative contracts.

The following table summarizes this segment’s outstanding derivative contracts.

 
Crude
    Swap Volume     Collar Volume     Weighted Average     Weighted Average     Weighted Average
Period     Bbl/Day     Bbl/Day     Swap Price     Floor Price     Ceiling Price
Q3 2015     1,000     2,000     $95.00     $58.00     $64.40
Q4 2015     1,000     2,000     $95.00     $58.00     $64.40
Natural Gas
Swap Volume Collar Volume Weighted Average Weighted Average Weighted Average
Period     MMBtu/Day     MMBtu/Day     Swap Price     Floor Price     Ceiling Price
Q3 2015     40,000     30,000     $3.98     $2.58     $3.04
Q4 2015     40,000     ---     $3.98     ---     ---
2016     10,000     ---     $3.25     ---     ---
 

The following table illustrates this segment’s comparative production, realized prices, and operating profit for the periods indicated:

                       
      Three Months Ended       Three Months Ended       Six Months Ended
      June 30, 2015     June 30, 2014     Change June 30, 2015     Mar. 31, 2015     Change June 30, 2015     June 30, 2014     Change
Oil and NGLs Production, MBbl       2,277       2,113     8 %   2,277       2,384     (4 )%   4,661       3,989     17 %
Natural Gas Production, Bcf       16.7       15.0     11 %   16.7       16.4     2 %   33.1       28.9     14 %
Production, MBoe       5,054       4,618     9 %   5,054       5,117     (1 )%   10,171       8,802     16 %
Production, MBoe/day       55.5       50.7     9 %   55.5       56.9     (2 )%   56.2       48.6     16 %
Avg. Realized Natural Gas Price, Mcf (1)     $ 2.67     $ 4.05     (34 )% $ 2.67     $ 2.94     (9 )% $ 2.80     $ 4.14     (32 )%
Avg. Realized NGL Price, Bbl (1)     $ 12.05     $ 29.99     (60 )% $ 12.05     $ 8.65     39 % $ 10.37     $ 34.57     (70 )%
Avg. Realized Oil Price, Bbl (1)     $ 55.52     $ 94.17     (41 )% $ 55.52     $ 48.47     15 % $ 51.73     $ 92.95     (44 )%
Realized Price / Boe (1)     $ 22.38     $ 40.10     (44 )% $ 22.38     $ 21.99     2 % $ 22.18     $ 40.93     (46 )%
Operating Profit Before Depreciation, Depletion, & Amortization (MM) (2)     $ 61.3     $ 153.8     (60 )%       $ 61.3     $ 60.9     1 %       $ 122.1     $ 301.6     (60 )%
                           

(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.

Currently, two Unit drilling rigs are operating for this segment. One is operating in the Southern Oklahoma Hoxbar Oil Trend (SOHOT) and one is drilling in the Wilcox play, located in southeast Texas. The current plan is to have two Unit drilling rigs operating through the end of the third quarter at which time adjustments may be made depending on factors such as commodity pricing, service costs and/or well results. Unit’s expectations are to be at the top end of the production guidance of 2% to 4%. Well service cost reductions and operating efficiencies are resulting in current AFE’s being approximately 28% lower as compared to 2014.

In the SOHOT area, production increased 5% during the quarter as compared to the first quarter of 2015. During the first half of 2015, three horizontal operated Hoxbar wells were completed in the first quarter and five horizontal Hoxbar wells were completed in the second quarter for a total of eight wells. Six of the eight new wells were completed in the Medrano member of the Hoxbar and two wells in the Marchand member. The 30 day initial production rate for the six Medrano wells averaged 7 MMcfe per day of which approximately 32% consisted of liquids. The two Marchand wells had a 30 day average initial production rate of approximately 1,571 Boe per day with 84% of the production mix being oil. The current plan for 2015 is to utilize one to two Unit rigs drilling in the prospect for the remainder of 2015, which should equate to approximately 12 to 14 new horizontal Hoxbar completions.

In the Wilcox area, production was essentially unchanged during the quarter as compared to the first quarter 2015 after accounting for a reduction of 0.75 Bcfe due to a third party processing plant being shut in for maintenance. Without the reduction, Wilcox production would have increased approximately 11% for the quarter. For the first half 2015, three Wilcox wells were completed in the first quarter and five Wilcox wells were completed in the second quarter for a total of eight wells (five vertical and three horizontal). Because of a lack of sufficient production history and pending lease acquisition opportunities, we have elected not to discuss the performance of the horizontal wells at this time. Two additional horizontal wells are scheduled to be drilled late in the fourth quarter of 2015. Development of the Gilly Downthrown fault block is progressing favorably. Four vertical Wilcox wells have been drilled and logged an average of approximately 200 feet of potential oil and gas pay from multiple Wilcox sands. Completion operations have begun on all four wells and current plans are to drill two to three additional vertical delineation wells this year. The preliminary field size based on the four wells is estimated at approximately 1,000 acres. In the Wilcox project, the current plan is to utilize one to two Unit drilling rigs in 2015, which should result in approximately 11 vertical and five horizontal Wilcox completions.

In the Granite Wash, a horizontal “C1” well was completed with an extended lateral of approximately 6,600 feet. The well, which is the first extended lateral drilled in this sand, had an average IP 30 rate of 10.7 MMcfe per day consisting of 42% natural gas, 35% oil, and 23% NGLs production. This was a 39% increase in the IP 30 rate over the typical “C1” well with a lateral length of 4,600 feet.

Larry Pinkston, Unit’s Chief Executive Officer and President, said: “Due to the unexpected shut in of some of the production in East Texas because of maintenance of a third party processing facility, production for the quarter was negatively impacted by approximately 125,000 Boe. We have reduced our drilling activities during the quarter because of the continued lower commodity prices. Despite the slowdown, we are pleased with the quality of the wells that we are drilling and completing. In the two core areas where we are allocating capital we have a multi-year inventory of potential drilling locations that can meet or exceed our profitability hurdles in this challenging commodity price environment.”

CONTRACT DRILLING SEGMENT INFORMATION

The average number of drilling rigs used in the quarter was 30.7, a decrease of 58% from the second quarter of 2014, and a decrease of 39% from the first quarter of 2015. Per day drilling rig rates for the quarter averaged $19,881, essentially unchanged from the second quarter of 2014 and a 1% decrease from the first quarter of 2015. Average per day operating margin for the quarter was $6,821 (before elimination of intercompany drilling rig profit and bad debt expense of $0.5 million). This compares to $8,317 (before elimination of intercompany drilling rig profit and bad debt expense of $7.8 million) for the second quarter of 2014, a decrease of 18%, or $1,496. As compared to $10,253 (before elimination of intercompany drilling rig profit and bad debt expense of $2.9 million) for the first quarter of 2015, second quarter 2015 operating margin decreased 33% or $3,432 (in each case regarding eliminating intercompany drilling rig profit and bad debt expense - see Non-GAAP Financial Measures below). Average operating margins for the second quarter of 2015 included early termination fees of approximately $1.6 million, or $594 per day, from the cancellation of certain long-term contracts, compared to no early termination fees during the second quarter of 2014 and $12.7 million for the first quarter of 2015.

Larry Pinkston said: “Drilling rig demand continued to decline during the second quarter because of the significant decrease in commodity prices. During the quarter, our sixth, seventh, and eighth BOSS drilling rigs began operating. With adding these three BOSS drilling rigs, our current drilling rig fleet now totals 94 drilling rigs, of which 32 are now working under contract. We have recently been notified of a customer's intent to terminate early the contracts on two BOSS drilling rigs both of which are under term contracts that contain early termination penalties. Long-term contracts (contracts with original terms ranging from six months to two years in length) are in place for 14 of the 32 drilling rigs. Of the 14 long-term contracts, three are up for renewal during the third quarter, one in the fourth quarter, seven in 2016 and three in 2017.”

The following table illustrates certain comparative results from this segment’s operations for the periods indicated:

                       
      Three Months Ended       Three Months Ended       Six Months Ended
      June 30, 2015     June 30, 2014     Change June 30, 2015     Mar. 31, 2015     Change June 30, 2015     June 30, 2014     Change
Rigs Utilized       30.7       73.5     (58 )%   30.7       50.1     (39 )%   40.4       70.7     (43 )%
Operating Profit Before Depreciation, Depletion, & Amortization (MM) (1)     $ 18.5     $ 47.8     (61 )%       $ 18.5     $ 43.3     (57 )%       $ 61.9     $ 90.6     (32 )%
                           

(1) Operating profit before depreciation is calculated by taking operating revenues for this segment less operating expenses excluding depreciation and impairment.

MID-STREAM SEGMENT INFORMATION

For the quarter, per day gas gathered and gas processed volumes increased 11% and 15%, respectively, while liquids sold volumes decreased 21% as compared to the second quarter of 2014. Compared to the first quarter of 2015, gas gathered and liquids sold volumes per day increased 9% and 5%, respectively, while gas processed volumes per day decreased 2%. Operating profit (as defined in the footnote below) for the quarter was $11.6 million, a decrease of 17% from the second quarter of 2014 and an increase of 18% over the first quarter of 2015.

For the first six months, per day gas gathered and gas processed volumes increased 11% and 20%, respectively, while liquids sold volumes per day decreased 21% as compared to the first six months of 2014. Operating profit (as defined in the footnote below) for the first six months was $21.4 million, a decrease of 18% from the first six months of 2014.

The following table illustrates certain comparative results from this segment’s operations for the periods indicated:

                       
      Three Months Ended       Three Months Ended       Six Months Ended
      June 30, 2015     June 30, 2014     Change June 30, 2015     Mar. 31, 2015     Change June 30, 2015     June 30, 2014     Change
Gas Gathering, Mcf/day       362,896       326,028     11 %   362,896       334,278     9 %   348,666       315,116     11 %
Gas Processing, Mcf/day       186,041       161,509     15 %   186,041       189,160     (2 )%   187,592       155,807     20 %
Liquids Sold, Gallons/day       599,732       762,205     (21 )%   599,732       568,876     5 %   584,389       737,353     (21 )%
Operating Profit Before Depreciation, Depletion, & Amortization (MM) (1)     $ 11.6     $ 14.0     (17 )%       $ 11.6     $ 9.8     18 %       $ 21.4     $ 26.2     (18 )%
                           

(1) Operating profit before depreciation is calculated by taking operating revenues for this segment less operating expenses excluding depreciation, amortization, and impairment.

Larry Pinkston said: “We continue to operate in full ethane rejection mode due to the decline in liquids prices that have adversely impacted our liquids sold volumes. Gathering volumes continue to increase through the second quarter as our facilities are positioned well to take advantage of operator activity. Progress continues to be made on the Snowshoe project in Centre County, Pennsylvania with the completion expected to be by the end of 2015.”

FINANCIAL INFORMATION

Unit ended the quarter with long-term debt of $926.9 million (consisting of $646.4 million of senior subordinated notes net of unamortized discount and $280.5 million of borrowings under its credit agreement). Unit’s credit agreement provides that the amount Unit can borrow is the lesser of the amount it elects as the commitment amount (currently $500 million) or the value of its borrowing base as determined by the lenders (currently $725 million), but in either event not to exceed $900 million. The credit agreement was amended during the second quarter to provide for a new maturity date of April 2020 and establish the current borrowing base amount noted above.

WEBCAST

Unit will webcast its second quarter earnings conference call live over the Internet on August 4, 2015 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 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 the productive capabilities of the company’s wells, future demand for oil and natural gas, future drilling rig utilization and dayrates, projected growth of the company’s oil and natural gas production, oil and gas reserve information, and its ability to meet its future reserve replacement goals, anticipated gas gathering and processing rates and throughput volumes, the prospective capabilities of the reserves associated with the company’s inventory of future drilling sites, anticipated oil and natural gas prices, the number of wells to be drilled by the company’s oil and natural gas segment, development, operational, implementation, and opportunity risks, possible delays caused by limited availability of third party services needed in its operations, possibility of future growth opportunities, 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,
      2015     2014 2015     2014
Statement of Operations:
Revenues:
Oil and natural gas $ 107,256 $ 198,498 $ 213,325 $ 386,705
Contract drilling 55,015 114,278 150,092 220,878
Gas gathering and processing   52,176     92,655     106,129     185,836  
Total revenues   214,447     405,431     469,546     793,419  
Expenses:
Oil and natural gas:
Operating costs 45,972 44,723 91,183 85,138
Depreciation, depletion, and amortization 68,101 71,245 145,219 130,925
Impairment of oil and natural gas properties 410,536 811,129
Contract drilling:
Operating costs 36,485 66,494 88,231 130,298
Depreciation 13,265 20,239 28,278 38,634
Impairment of contract drilling equipment 8,314 8,314
Gas gathering and processing:
Operating costs 40,592 78,648 84,767 159,608
Depreciation and amortization 10,848 10,109 21,542 19,700
General and administrative 9,624 10,600 18,994 20,237
Gain on disposition of assets   (415 )   (195 )   (960 )   (9,621 )
Total operating expenses   643,322     301,863     1,296,697     574,919  
 
Income (loss) from operations   (428,875 )   103,568     (827,151 )   218,500  
 
Other income (expense):
Interest, net (7,956 ) (4,131 ) (15,196 ) (7,921 )
Gain (loss) on derivatives not designated as hedges (1,919 ) (10,709 ) 4,667 (29,075 )
Other   24     (49 )   22     71  
Total other income (expense)   (9,851 )   (14,889 )   (10,507 )   (36,925 )
 
Income (loss) before income taxes (438,726 ) 88,679 (837,658 ) 181,575
 
Income tax expense (benefit):
Current 803 8,475 868 18,270
Deferred   (165,140 )   25,844     (315,783 )   52,000  
Total income taxes   (164,337 )   34,319     (314,915 )   70,270  
 
Net income (loss) $ (274,389 ) $ 54,360   $ (522,743 ) $ 111,305  
 
Net income (loss) per common share:
Basic $ (5.58 ) $ 1.12 $ (10.66 ) $ 2.29
Diluted $ (5.58 ) $ 1.11 $ (10.66 ) $ 2.27
 
Weighted average shares outstanding:
Basic 49,148 48,642 49,063 48,568
Diluted 49,148 49,116 49,063 49,010
 
       
June 30, December 31,
      2015     2014
Balance Sheet Data:
Current assets $ 166,534 $ 252,491
Total assets $ 3,629,993 $ 4,473,728
Current liabilities $ 177,900 $ 304,171
Long-term debt $ 926,908 $ 812,163
Other long-term liabilities $ 141,153 $ 148,785
Deferred income taxes $ 560,432 $ 876,215
Shareholders’ equity $ 1,823,600 $ 2,332,394
 
   
Six Months Ended June 30,
      2015     2014
Statement of Cash Flows Data:    
Cash flow from operations before changes in operating assets and liabilities $ 207,221 $ 370,348
Net change in operating assets and liabilities   50,385     (44,820 )
Net cash provided by operating activities $ 257,606   $ 325,528  
Net cash used in investing activities $ (366,442 ) $ (379,107 )
Net cash provided by financing activities $ 108,626   $ 36,064  
 

Non-GAAP Financial Measures

Unit Corporation reports its financial results in accordance with 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 and earnings per share including impairment adjustments and the effect of the cash settled commodity derivatives, its drilling segment’s average daily operating margin before elimination of intercompany drilling rig profit and bad debt expense, and its cash flow from operations before changes in operating assets and liabilities.

Below is a reconciliation of GAAP financial measures to non-GAAP financial measures for the three and six months ended June 30, 2015 and 2014. Non-GAAP financial measures should not be considered by themselves or a substitute for results reported in accordance with GAAP.

         
Unit Corporation
Reconciliation of Adjusted Net Income and Adjusted Diluted Earnings per Share
 
Three Months Ended Six Months Ended
June 30, June 30,
2015     2014 2015     2014
(In thousands except earnings per share)
Adjusted net income:
Net income (loss) $ (274,389 ) $ 54,360 $ (522,743 ) $ 111,305
Impairment adjustment (net of income tax) 260,734 510,103
(Gain) loss on derivatives not designated as hedges (net of income tax) 1,238 6,564 (2,786 ) 17,822
Settlements during the period of matured derivative contracts (net of income tax)   6,495     (5,567 )   13,223     (11,005 )
Adjusted net income (loss) $ (5,922 ) $ 55,357   $ (2,203 ) $ 118,122  
 
Adjusted diluted earnings per share:
Diluted earnings (loss) per share $ (5.58 ) $ 1.11 $ (10.66 ) $ 2.27
Diluted earnings per share from the impairments 5.31 10.40
Diluted earnings per share from the (gain) loss on derivatives 0.02 0.13 (0.06 ) 0.37
Diluted earnings (loss) per share from the settlements of matured derivative contracts   0.13     (0.11 )   0.27     (0.23 )
Adjusted diluted earnings (loss) per share $ (0.12 ) $ 1.13   $ (0.05 ) $ 2.41  
 

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

  • It uses the adjusted net income to evaluate the operational performance of the company.
  • The adjusted net income is more comparable to earnings estimates provided by securities analysts.
       
Unit Corporation
Reconciliation of Average Daily Operating Margin Before Elimination of Intercompany Rig Profit and Bad Debt Expense
 
Three Months Ended Six Months Ended
March 31,     June 30, June 30,
2015 2015     2014 2015     2014
(In thousands except for operating days and operating margins)
Contract drilling revenue $ 95,077 $ 55,015 $ 114,278 $ 150,092 $ 220,878
Contract drilling operating cost   51,746   36,485   66,494   88,231   130,298
Operating profit from contract drilling 43,331 18,530 47,784 61,861 90,580
Add:
Elimination of intercompany rig profit and bad debt expense   2,910   537   7,808   3,447   13,121
Operating profit from contract drilling before elimination of intercompany rig profit and bad debt expense 46,241 19,067 55,592 65,308 103,701
Contract drilling operating days   4,510   2,795   6,684   7,305   12,797
Average daily operating margin before elimination of intercompany rig profit and bad debt expense $ 10,253 $ 6,821 $ 8,317 $ 8,940 $ 8,104
 

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
 

Six Months Ended
June 30,

2015     2014
(In thousands)
Net cash provided by operating activities $ 257,606 $ 325,528
Net change in operating assets and liabilities   (50,385 )   44,820
Cash flow from operations before changes in operating assets and liabilities $ 207,221   $ 370,348
 

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

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

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


Source: Business Wire (August 4, 2015 - 7:30 AM EDT)

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