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 May 7, 2015 - 7:30 AM EDT
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Unit Corporation Reports 2015 First Quarter Results

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

  • Record total production of 5.1 million barrels of oil equivalent (MMBoe), a 22% increase over the first quarter of 2014
  • Oil and natural gas liquids (NGLs) production increased 27% over the first quarter of 2014
  • Placed two BOSS drilling rigs into service and a third after the end of the quarter
  • Average dayrate of $20,130, a 3% increase over the first quarter of 2014
  • Completed an extension of the Pittsburgh Mills gathering system in Pennsylvania
  • Achieved record gas processed and gas gathered volumes per day with increases of 26% and 10%, respectively, over the first quarter of 2014

FIRST QUARTER 2015 RESULTS

Because of significantly lower commodity prices in the first quarter of 2015, Unit recorded a $400.6 million pre-tax non-cash ceiling test write down in the carrying value of the company’s oil and natural gas properties. As a result, Unit recorded a net loss of $248.4 million, or $5.07 per share, compared to net income of $56.9 million, or $1.17 per diluted share, for the first quarter of 2014. Adjusted net income for the quarter (which excludes the effect of non-cash commodity derivatives and the effects of the write-down) was $3.7 million, or $0.08 per diluted share (see Non-GAAP Financial Measures below). Total revenues for the quarter were $255.1 million (42% oil and natural gas, 37% contract drilling, and 21% mid-stream), compared to $388.0 million (49% oil and natural gas, 27% contract drilling, and 24% mid-stream) for the first quarter of 2014.

OIL AND NATURAL GAS SEGMENT INFORMATION

Total equivalent production per day for the quarter was 56.9 MBoe, an increase of 22% and 7% over the first quarter of 2014 and the fourth quarter of 2014, respectively. Liquids (oil and NGLs) production represented 47% of total equivalent production for the quarter. Oil production for the quarter was 12,197 barrels per day, an increase of 36% and 8% over the first quarter of 2014 and the fourth quarter of 2014, respectively. NGLs production for the quarter was 14,294 barrels per day, an increase of 21% over the first quarter of 2014 and an increase of 5% over the fourth quarter of 2014. Natural gas production for the quarter was 182,203 thousand cubic feet (Mcf) per day, an increase of 18% over the first quarter of 2014 and a 9% increase over the fourth quarter of 2014.

Unit’s average realized per barrel equivalent price for the first quarter was $21.99, a decrease of 47% from the first quarter of 2014 and a decrease of 38% from the fourth quarter of 2014. Unit’s average natural gas price for the first quarter of 2015 was $2.94 per Mcf, a decrease of 31% from the first quarter of 2014 and a 21% decrease from the fourth quarter of 2014. Unit’s average oil price for the quarter was $48.47 per barrel, a decrease of 47% from the first quarter of 2014 and a decrease of 40% from the fourth quarter of 2014. Unit’s average NGLs price for the quarter was $8.65 per barrel, a 78% decrease from the first quarter of 2014 and a decrease of 66% from the fourth quarter of 2014. All prices in this paragraph include the effects of derivative contracts.

The following table summarizes this segment’s remaining 2015 derivative contracts.

 
Crude
    Swap Volume     Collar Volume     Average     Average     Average
Period     Bbl/Day     Bbl/Day     Swap Price     Floor Price     Ceiling Price

Apr - Dec 2015

    1,000     ---     $95.00     ---     ---

May - Dec 2015

          2,000           $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
Q2 2015     70,000     30,000     $3.60     $2.92     $3.26
Q3 2015     40,000     30,000     $3.98     $2.58     $3.04
Q4 2015     40,000     ---     $3.98     ---     ---
 

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

       
      Three Months Ended Three Months Ended
     

Mar. 31,
2015

   

Mar. 31,
2014

    Change

Mar. 31,
2015

   

Dec. 31,
2014

    Change
Oil and NGLs Production, MBbl       2,384       1,875     27 %   2,384       2,296     4 %
Natural Gas Production, Bcf       16.4       13.9     18 %   16.4       15.4     6 %
Production, MBoe       5,117       4,184     22 %   5,117       4,868     5 %
Production, MBoe/day       56.9       46.5     22 %   56.9       52.9     7 %
Avg. Realized Natural Gas Price, Mcfe (1)     $ 2.94     $ 4.24     (31 )% $ 2.94     $ 3.72     (21 )%
Avg. Realized NGL Price, Bbl(1)     $ 8.65     $ 39.56     (78 )% $ 8.65     $ 25.28     (66 )%
Avg. Realized Oil Price, Bbl (1)     $ 48.47     $ 91.53     (47 )% $ 48.47     $ 81.34     (40 )%
Realized Price / Boe (1)     $ 21.99     $ 41.84     (47 )% $ 21.99     $ 35.73     (38 )%
Operating Profit Before Depreciation, Depletion, Amortization, & Impairment

(MM) (2)

    $ 60.9     $ 147.8     (59 )% $ 60.9     $ 111.0     (45 )%
               

(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.

At the end of the quarter, four Unit drilling rigs were operating for this segment. Two were operating in the Southern Oklahoma Hoxbar Oil Trend (SOHOT) and two were drilling in the Wilcox play, located in southeast Texas. The current plan is to have four Unit drilling rigs operating through the end of the second quarter at which time adjustments may be made depending on factors such as commodity pricing, service costs and/or well results.

In the SOHOT area, production increased 86% during the quarter as compared to the fourth quarter of 2014. During the quarter, three new horizontal operated Hoxbar wells were completed. Two wells were completed in the Medrano member of the Hoxbar and one well in the Marchand member. The 30 day initial production rate for the two Medrano wells averaged 12.8 MMcfe per day of which approximately 30% consisted of liquids. The Marchand well had a 30 day, 60 day, and 90 day production rate of approximately 2,444 Boe per day, 2,063 Boe per day, and 2,013 Boe per day, respectively, of which the production mix was 78% oil, 12% NGLs, and 10% natural gas. The current plan for 2015 is to average one to two Unit rigs drilling in the prospect, which should equate to approximately 12 to 14 new horizontal Hoxbar completions. The estimated 2015 capital spending for drilling in the SOHOT is approximately $90 million.

In the Wilcox area, production was essentially unchanged during the quarter as compared to the fourth quarter 2014 and increased 20% as compared to the first quarter 2014. Production for the quarter was hindered by delays in completing wells to allow for the negotiation of better prices associated with the fracking of the wells. During the quarter, three new Wilcox wells were completed. The BS R#1 (100% working interest) is a new Wilcox discovery located in a separate fault block to the south of the Gilly field. The well encountered approximately 238 net feet of potential oil and gas pay from several Wilcox sands. Completion operations have begun and the well is scheduled to be fracked in May. The drilling operations of a confirmation well in the same fault block as the BS R #1 has been finished and is awaiting completion. Two horizontal Wilcox wells were also completed in the first quarter. Both wells were recently fracked and are in the early stages of flow back. Further discussion about the preliminary results for these two wells will be given during the second quarter earnings call. The estimated 2015 capital spending for drilling in the Wilcox area is approximately $100 million. The current plan is to utilize one to two Unit drilling rigs in 2015, which should result in approximately eight vertical and six horizontal Wilcox completions.

Larry Pinkston, Unit’s Chief Executive Officer and President, said: “Despite the substantial reduction of our drilling activity during the quarter, our oil and natural gas segment achieved a very nice quarter over quarter production growth. Our 2015 production guidance is approximately 18.6 to 19.0 MMBoe, an increase of 2% to 4% over 2014, although actual results will continue to be subject to industry conditions. Unit has a strong asset base, and we have a proven record of weathering these unfavorable pricing cycles.”

CONTRACT DRILLING SEGMENT INFORMATION

The average number of drilling rigs used in the quarter was 50.1, a decrease of 26% from the first quarter of 2014, and a decrease of 38% from the fourth quarter of 2014. Per day drilling rig rates for the quarter averaged $20,130, an increase of 3% over the first quarter of 2014 and a 2% decrease from the fourth quarter of 2014. Average per day operating margin for the quarter was $10,253 (before elimination of intercompany drilling rig profit and bad debt expense of $2.9 million). This compares to $7,870 (before elimination of intercompany drilling rig profit and bad debt expense of $5.3 million) for the first quarter of 2014, an increase of 30%, or $2,383. As compared to $8,834 (before elimination of intercompany drilling rig profit and bad debt expense of $8.7 million) for the fourth quarter of 2014, first quarter 2015 operating margin increased 16% or $1,419 (in each case regarding eliminating intercompany drilling rig profit and bad debt expense - see Non-GAAP Financial Measures below). Average operating margins for the first quarter of 2015 included early termination fees of approximately $12.7 million, or $2,807 per day, from the cancellation of certain long-term contracts, compared to no early termination fees during the first quarter of 2014 and $0.2 million for the fourth quarter of 2014.

Larry Pinkston said: “Drilling rig demand continued to decline during the first quarter because of the significant decrease in commodity prices. During the quarter, our fourth and fifth BOSS drilling rig began operating. With the addition of these two BOSS drilling rigs and one that began operating after the end of the quarter, our current drilling rig fleet now totals 92 drilling rigs, of which 30 are now working under contract. Long-term contracts (contracts with original terms ranging from six months to two years in length) are in place for 14 of the 30 drilling rigs. Of the 14 long term contracts, five are up for renewal during the second quarter, two in the third quarter, and seven are up for renewal in 2016 and 2017. Currently, we have six BOSS drilling rigs operating, and two additional BOSS drilling rigs have been contracted to be built for third party operators and are expected to be placed into service later this year. We will delay fabrication of any additional BOSS drilling rigs until contracts for those rigs are received.”

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

       
      Three Months Ended Three Months Ended
     

Mar. 31,
2015

   

Mar. 31,
2014

    Change

Mar. 31,
2015

   

Dec. 31,
2014

    Change
Rigs Utilized       50.1       67.9     (26 )%   50.1       80.9     (38 )%
Operating Profit Before Depreciation & Impairment (MM) (1)     $ 43.3     $ 42.8     1 % $ 43.3     $ 57.1     (24 )%
               

(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 10% and 26%, respectively, while liquids sold volumes decreased 20% as compared to the first quarter of 2014. Compared to the fourth quarter of 2014, gas gathered and gas processed volumes per day increased 2% and 15%, respectively, while liquids sold volumes per day decreased 17%. Liquids sold volumes decreased during the quarter as a result of several plant facilities operating in maximum ethane rejection mode due to the very depressed pricing for ethane. Operating profit (as defined in the footnote below) for the quarter was $9.8 million, a decrease of 20% from the first quarter of 2014 and a decrease of 2% from the fourth quarter of 2014.

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

       
      Three Months Ended Three Months Ended
     

Mar. 31,
2015

   

Mar. 31,
2014

    Change

Mar. 31,
2015

   

Dec. 31,
2014

    Change
Gas Gathering, Mcf/day     334,278     304,083     10% 334,278     327,331     2%
Gas Processing, Mcf/day     189,160     150,042     26% 189,160     163,979     15%
Liquids Sold, Gallons/day     568,876     712,225     (20)% 568,876     687,713     (17)%
Operating Profit Before Depreciation, Depletion, Amortization & Impairment (MM) (1)     $ 9.8     $ 12.2     (20)% $ 9.8     $ 10.0     (2)%
               

(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: “During the quarter, we completed the connection of an additional third party operated well pad to our Pittsburgh Mills gathering system. The well pad began producing at the beginning of the second quarter. We continue to make progress on our Snowshoe project in Centre County, Pennsylvania. The project consists of a seven-mile, 16 inch and 24 inch trunkline to gather Marcellus production for delivery to an interstate pipeline. Construction of this project is expected to be completed in the fourth quarter of 2015.”

FINANCIAL INFORMATION

Unit ended the first quarter with long-term debt of $883.6 million (consisting of $646.3 million of senior subordinated notes net of unamortized discount and $237.3 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 after the first 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 first quarter earnings conference call live over the Internet on May 7, 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
March 31,
        2015     2014
Statement of Operations:    
Revenues:
Oil and natural gas $ 106,069 $ 188,207
Contract drilling 95,077 106,600
Gas gathering and processing   53,953     93,181  
Total revenues   255,099     387,988  
 
Expenses:
Oil and natural gas:
Operating costs 45,211 40,415
Depreciation, depletion, and amortization 77,118 59,680
Impairment of oil and gas properties 400,593 ---
Contract drilling:
Operating costs 51,746 63,804
Depreciation 15,013 18,395
Gas gathering and processing:
Operating costs 44,175 80,960
Depreciation and amortization 10,694 9,591
General and administrative 9,370 9,637
Gain on disposition of assets   (545 )   (9,426 )
Total operating expenses   653,375     273,056  
 
Income (loss) from operations   (398,276 )   114,932  
 
Other income (expense):
Interest, net (7,240 ) (3,790 )
Gain (loss) on derivatives not designated as hedges 6,586 (18,366 )
Other   (2 )   120  
Total other income (expense)   (656 )   (22,036 )
 
Income (loss) before income taxes (398,932 ) 92,896
 
Income tax expense (benefit):
Current 65 9,795
Deferred   (150,643 )   26,156  
Total income taxes   (150,578 )   35,951  
 
Net income (loss) $ (248,354 ) $ 56,945  
 
Net income (loss) per common share:
Basic $ (5.07 ) $ 1.17
Diluted $ (5.07 ) $ 1.17
 
Weighted average shares outstanding:
Basic 48,977 48,493
Diluted 48,977 48,872
 
           
March 31, December 31,
        2015       2014
Balance Sheet Data:
Current assets $ 190,640 $ 252,491
Total assets $ 4,050,905 $ 4,473,728
Current liabilities $ 207,009 $ 304,171
Long-term debt $ 883,584 $ 812,163
Other long-term liabilities $ 142,597 $ 148,785
Deferred income taxes $ 725,572 $ 876,215
Shareholders’ equity $ 2,092,143 $ 2,332,394
 
     
Three Months Ended March 31,
        2015     2014
Statement of Cash Flows Data:    
Cash flow from operations before changes
in operating assets and liabilities $ 116,304 $ 178,224
Net change in operating assets and liabilities   44,005     (54,764 )
Net cash provided by operating activities $ 160,309   $ 123,460  
Net cash used in investing activities $ (231,027 ) $ (160,518 )
Net cash provided by financing activities $ 70,533   $ 19,517  
 

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 months ended March 31, 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
March 31,
2015     2014

 

(In thousands except per share amounts)

Adjusted net income:
Net income (loss) $ (248,354 ) $ 56,945
Impairment adjustment (net of income tax) 249,369 ---
(Gain) loss on derivatives not designated as hedges
(net of income tax) (4,024 ) 11,258
Settlements during the period of matured
derivative contracts (net of income tax)   6,728     (5,438 )
 
Adjusted net income $ 3,719   $ 62,765  
 
Adjusted diluted earnings per share:
Diluted earnings (loss) per share $ (5.07 ) $ 1.17
Diluted earnings per share from the impairments 5.09 ---

Diluted earnings per share from the (gain) loss

on derivatives (0.08

)

0.23
Diluted earnings (loss) per share from the
settlements of matured derivative contracts   0.14     (0.11 )
 
Adjusted diluted earnings per share $ 0.08   $ 1.29  
 

________________

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
December 31,     March 31,
2014 2015     2014

 

(In thousands except operating days
and operating margins)

Contract drilling revenue $ 134,987 $ 95,077 $ 106,600
Contract drilling operating cost   77,908   51,746   63,804
Operating profit from contract drilling 57,079 43,331 42,796
Add:
Elimination of intercompany rig profit
and bad debt expense   8,669   2,910   5,313
Operating profit from contract drilling before
elimination of intercompany rig profit
and bad debt expense 65,748 46,241 48,109
Contract drilling operating days   7,443   4,510   6,113
Average daily operating margin before elimination of
intercompany rig profit and bad debt expense $ 8,834 $ 10,253 $ 7,870
 

________________

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

 
Three Months Ended

March 31,

2015     2014
(In thousands)
Net cash provided by operating activities $ 160,309 $ 123,460
Net change in operating assets and liabilities   (44,005 )   54,764
Cash flow from operations before changes
in operating assets and liabilities $ 116,304   $ 178,224

________________

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 (May 7, 2015 - 7:30 AM EDT)

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