May 4, 2017   SOURCE: BusinessWire

Unit Corporation Reports 2017 First Quarter Results

Unit Corporation (NYSE: UNT) today reported its financial and operational results for the first quarter 2017. Results and recent highlights include:

  • Net income of $15.9 million.
  • The contract drilling segment increased its drilling rigs in service from 21 at the end of the fourth quarter of 2016 to 29 at the end of the first quarter, a 38% increase.
  • Started construction of the tenth BOSS drilling rig.
  • On April 4, 2017, Unit announced the closing of an agreement to acquire additional oil and natural gas assets in its Hoxbar core area.
  • Midstream segment began construction to connect an additional multi-well pad to its Pittsburgh Mills gathering system.
  • Midstream segment entered into a new fee-based agreement with a third party operator to gather and process 10 MMcf per day with a term of five years for the Cashion system.
  • Reduced long-term debt by $10.3 million from the end of the fourth quarter 2016.
  • April redetermination of Unit's borrowing base amount was maintained at $475 million.

FIRST QUARTER 2017 FINANCIAL RESULTS

Unit recorded net income of $15.9 million for the quarter, or $0.31 per diluted share, compared to a net loss of $41.1 million, or $0.83 per share, for the first quarter of 2016. For the first quarter of 2016, Unit incurred a pre-tax non-cash ceiling test write-down of $37.8 million in the carrying value of its oil and natural gas properties. Adjusted net income (which excludes the effect of non-cash commodity derivatives) for the quarter was $7.5 million, or $0.15 per diluted share (see Non-GAAP financial measures below). Total revenues were $175.7 million (50% oil and natural gas, 21% contract drilling, and 29% midstream), compared to $136.2 million (43% oil and natural gas, 28% contract drilling, and 29% midstream) for the first quarter of 2016. Adjusted EBITDA for the quarter was $74.5 million, or $1.46 per diluted share (see Non-GAAP financial measures below).

OIL AND NATURAL GAS SEGMENT INFORMATION

For the quarter, total production averaged 42,000 barrels of oil equivalent (Boe) per day, a decrease of 15% from the first quarter of 2016 and an 8% decrease from the fourth quarter of 2016. Liquids (oil and NGLs) production represented 46% of total equivalent production. Oil production was 7,141 barrels per day, a decrease of 19% from the first quarter of 2016 and a decrease of 8% from the fourth quarter of 2016. NGLs production was 12,190 barrels per day, a decrease of 14% from the first quarter of 2016 and a 12% decrease from the fourth quarter of 2016. Natural gas production was 135,838 thousand cubic feet (Mcf) per day, a decrease of 15% from the first quarter of 2016 and a decrease of 6% from the fourth quarter of 2016. Unit's production for the quarter was in line with its expectations. In addition to the continued production decline of existing wells, the decreases were due primarily to reduced drilling activity, approximately 0.5 billion cubic feet of natural gas equivalent (Bcfe) of production in the Wilcox play being shut in for five days during the quarter because of maintenance on a third-party processing plant, and approximately 0.3 Bcfe of reduced production due to weather related events. Unit’s original 2017 production guidance was 15.9 million barrels of oil equivalent (MMBoe) to 16.4 MMBoe, a decrease of 5% to 8% year over year. Unit anticipates sequential quarterly production growth during the remainder of 2017. Because of the recently completed acquisition of oil and gas assets in Unit's Hoxbar play, production guidance for 2017 is being increased to 16.1 MMBoe to 16.7 MMBoe.

Unit’s average natural gas price was $2.68 per Mcf, an increase of 43% over the first quarter of 2016 and an increase of 13% over the fourth quarter of 2016. Unit’s average oil price was $48.68 per barrel, an increase of 50% over the first quarter of 2016 and an increase of 6% over the fourth quarter of 2016. Unit’s average NGLs price was $17.81 per barrel, a 170% increase over the first quarter of 2016 and an increase of 22% over the fourth quarter of 2016. All prices in this paragraph include the effects of derivative contracts.

In the Wilcox area, Unit continued its recompletion program in and around Gilly Field and picked up a Unit rig and started the first of four wells in mid-January. Three of these wells, which include the first exploration well in the Cherry Creek prospect, an extensional well to Gilly Field, and a development well in the Wing area just east of Gilly Field, have been drilled and completion operations will begin soon. The fourth well, a 5,800’ horizontal well in the Village Mills field, has been fracture stimulated and is currently in the early stages of flowing back the frac load. Initial test rates from the well are encouraging. Unit has released the rig to evaluate the production results of these four wells and plans to pick the rig back up in the third quarter of 2017 to drill three or four additional wells before year end.

In the Granite Wash play, Unit continued the extended lateral drilling program in its Buffalo Wallow field using a Unit rig. This drilling program is planned to continue throughout 2017. During the quarter, Unit fracture stimulated two extended lateral Granite Wash wells, one in the A-2 interval and one in the C-1 interval. The A-2 well is now on production and, while it is too early to make any conclusive statements about the performance of the well, current production rates are meeting expectations. The C-1 well has not been brought on production yet. Picking up a second rig in this area during 2017 is a possibility.

In the Southern Oklahoma Hoxbar Oil Trend (SOHOT) area, Unit completed two horizontal Marchand oil wells during the first quarter and, in late April, picked up a Unit rig and resumed drilling operations. Unit plans to drill six to seven wells within its SOHOT play with this rig during the remainder of 2017 and is considering adding a second rig in the second half of the year.

Larry Pinkston, Unit’s Chief Executive Officer and President, said: “We recently announced the completion of an acquisition of certain oil and natural gas assets including approximately 8,300 net acres primarily in Grady and Caddo Counties in western Oklahoma. The purchase price was approximately $57.0 million in cash plus 180 net acres in McClain County, Oklahoma. As of the effective date of January 1, 2017, the estimated proved reserves of the properties totaled 3.2 MMBoe, and the estimated average daily net production was approximately 1,367 Boe. This acquisition will increase our Hoxbar total core area position to approximately 28,000 net acres and increase our working interest in many sections. We plan to pick up a rig in the second quarter to continue developing the area."

This table illustrates certain comparative production, realized prices, and operating profit for the periods indicated:

      Three Months Ended     Three Months Ended
     

Mar 31,
2017

   

Mar 31,
2016

    Change    

Mar 31,
2017

   

Dec 31,
2016

    Change
Oil and NGLs Production, MBbl       1,740       2,094     (17 )%       1,740       1,983     (12 )%
Natural Gas Production, Bcf       12.2       14.5     (16 )%       12.2       13.4     (8 )%
Production, MBoe       3,777       4,514     (16 )%       3,777       4,209     (10 )%
Production, MBoe/day       42.0       49.6     (15 )%       42.0       45.8     (8 )%
Avg. Realized Natural Gas Price, Mcf (1)     $ 2.68     $ 1.87     43 %     $ 2.68     $ 2.37     13 %
Avg. Realized NGL Price, Bbl (1)     $ 17.81     $ 6.59     170 %     $ 17.81     $ 14.57     22 %
Avg. Realized Oil Price, Bbl (1)     $ 48.68     $ 32.5     50 %     $ 48.68     $ 46.14     6 %
Realized Price / Boe (1)     $ 22.13     $ 13.67     62 %     $ 22.13     $ 19.73     12 %
Operating Profit Before Depreciation, Depletion, & Amortization (MM) (2)     $ 58.4     $ 24.9     134 %     $ 58.4     $ 60.4     (3 )%
(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.)
 

CONTRACT DRILLING SEGMENT INFORMATION

The average number of Unit's drilling rigs working during the quarter was 25.5, an increase of 24% over the first quarter of 2016 and an increase of 31% over the fourth quarter of 2016. Per day drilling rig rates averaged $15,835, a decrease of 14% from the first quarter of 2016 and a 6% decrease from the fourth quarter of 2016. Average dayrates decreased because of the full effect of the repricing of two BOSS rig term contracts, one mid-fourth quarter and the second early first quarter. Unit reactivated eight stacked SCR rigs during the quarter at rates below its current average dayrate. Preparing the rigs to return to service carries additional startup and mobilization costs. These factors contributed to the decreased average daily operating margins during the quarter. Average per day operating margin for the quarter was $3,474 (with no elimination of intercompany drilling rig profit and bad debt expense). This compares to first quarter 2016 average operating margin of $5,651 (with no elimination of intercompany drilling rig profit and bad debt expense), a decrease of 39%, or $2,177. First quarter 2017 average operating margin decreased 46%, or $3,004, as compared to $6,478 for the fourth 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 no early termination fees from the cancellation of certain long-term contracts, compared to early termination fees of $2.6 million, or $1,410 per day, during the first quarter of 2016 and no early termination fees for the fourth quarter of 2016.

Pinkston said: “We saw a nice increase in rig utilization during the quarter. Margins were adversely impacted by long-term contract repricing, additional expenses associated with rig relocations, and general startup expenses. During the latter part of the quarter, we began to obtain some modest dayrate increases on contract renewals. Currently, all nine of our BOSS drilling rigs are operating, and we began construction of our tenth BOSS drilling rig. Improved commodity prices have led to more operator inquiries and more contracts for our drilling rigs. Our fleet totals 94 drilling rigs, of which 29 were working at the end of the quarter after rebounding from a low of 13 drilling rigs during the second quarter of 2016. Long-term contracts (contracts with original terms ranging from six months to two years in length) are in place for eight of our drilling rigs. Of the eight, seven are up for renewal during 2017 and one in 2018.”

This table illustrates certain comparative results for the periods indicated:

      Three Months Ended     Three Months Ended
     

Mar 31,
2017

   

Mar 31,
2016

    Change    

Mar 31,
2017

   

Dec 31,
2016

    Change
Rigs Utilized       25.5       20.6     24 %       25.5       19.5     31 %
Operating Profit Before Depreciation, Depletion, & Amortization (MM) (1)     $ 8.0     $ 10.6     (25 )%     $ 8.0     $ 11.6     (32 )%
(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.)
 

MIDSTREAM SEGMENT INFORMATION

For the quarter, per day gas gathered volumes increased 2%, while gas processed and liquids sold volumes decreased 24% and 4%, respectively, as compared to the first quarter of 2016. Compared to the fourth quarter of 2016, gas gathered, gas processed, and liquids sold volumes per day decreased 8%, 10% and 7%, respectively. Operating profit (as defined in the footnote below) for the quarter was $13.2 million, an increase of 63% over the first quarter of 2016 and a decrease of 10% from the fourth quarter of 2016.

This table illustrates certain comparative results for the periods indicated:

      Three Months Ended     Three Months Ended
     

Mar 31,
2017

    Mar 31,
2016 		    Change     Mar 31,
2017 		    Dec 31,
2016 		    Change
Gas Gathering, Mcf/day       390,384       383,405     2 %       390,384       423,669     (8 )%
Gas Processing, Mcf/day       126,559       167,048     (24 )%       126,559       140,719     (10 )%
Liquids Sold, Gallons/day       497,862       519,433     (4 )%       497,862       535,253     (7 )%
Operating Profit Before Depreciation, Depletion, & Amortization (MM) (1)     $ 13.2     $ 8.1     63 %     $ 13.2     $ 14.7     (10 )%
(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: “Our midstream segment operating profit before depreciation continues to remain relatively stable on a year to year basis, despite a poor commodity price environment and reduced drilling. Fee based contract structures, along with operating cost reductions, are contributing to these results. This segment continues to reject ethane at all processing facilities except Bellmon, which has a more attractive transportation and fractionation fee for its liquids. We successfully negotiated an agreement with a third-party operator to gather 10 MMcf per day with a five year term at our Cashion facility. We began the process to connect an additional multi-well pad to our Pittsburgh Mills gathering system in the Marcellus. The new pad connection is scheduled to be completed in the second quarter of 2017.”

FINANCIAL INFORMATION

Unit ended the quarter with long-term debt of $790.7 million (a reduction of $10.3 million from the end of 2016 and $128.3 million from the end of 2015). Long-term debt consisted of $640.7 million of senior subordinated notes net of unamortized discount and debt issuance costs and $150.0 million of borrowings under its credit agreement. Recently, Unit's borrowing base was redetermined with no change to availability. 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.

On April 4, 2017, Unit established an "at the market" equity offering program under which it may offer and sell, from time-to-time, up to an aggregate of $100 million for shares of its common stock through "at the market" transactions. As of April 21, 2017, Unit has sold 770,660 shares for $18.3 million, net of offering costs of $0.4 million. Approximately $81.3 million remained available for sale under the program. Unit intends to use net proceeds from the offering to fund (or offset costs of) acquisitions, future capital expenditures, repay amounts outstanding under its revolving credit facility, and general corporate purposes.

WEBCAST

Unit will webcast its first quarter earnings conference call live over the Internet on May 4, 2017 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 listed 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, the number of additional shares (if any) it may sell under its “at the market” offering, 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,
      2017     2016
Statement of Operations:    
Revenues:
Oil and natural gas $ 87,598 $ 58,274
Contract drilling 37,185 38,710
Gas gathering and processing   50,941     39,200  
Total revenues   175,724     136,184  
Expenses:
Operating costs:
Oil and natural gas 29,204 33,346
Contract drilling 29,227 28,098
Gas gathering and processing   37,704     31,066  
Total operating costs 96,135 92,510
Depreciation, depletion, and amortization 46,932 55,590
Impairments — 37,829
General and administrative 8,954 8,611
Gain on disposition of assets   (824 )   (192 )
Total operating expenses   151,197     194,348  
 
Income (loss) from operations   24,527     (58,164 )
 
Other income (expense):
Interest, net (9,396 ) (9,617 )
Gain on derivatives 14,731 10,929
Other   3     (15 )
Total other income (expense)   5,338     1,297  
 
Income (loss) before income taxes 29,865 (56,867 )
 
Income tax expense (benefit):
Deferred   13,936     (15,718 )
Total income taxes   13,936     (15,718 )
 
Net income (loss) $ 15,929   $ (41,149 )
 
Net income (loss) per common share:
Basic $ 0.32 $ (0.83 )
Diluted $ 0.31 $ (0.83 )
 
Weighted average shares outstanding:
Basic 50,293 49,880
Diluted 50,861 49,880
       
 
March 31, December 31,
      2017     2016
Balance Sheet Data:
Current assets $ 100,923 $ 121,196
Total assets $ 2,452,550 $ 2,479,303
Current liabilities $ 142,219 $ 164,915
Long-term debt $ 790,653 $ 800,917
Other long-term liabilities and non-current derivative liability $ 101,985 $ 103,479
Deferred income taxes $ 204,647 $ 215,922
Shareholders’ equity $ 1,213,046 $ 1,194,070
   
 
Three Months Ended March 31,
      2017     2016
Statement of Cash Flows Data:    
Cash flow from operations before changes in operating assets and liabilities $ 64,949 $ 36,349
Net change in operating assets and liabilities   703     34,364  
Net cash provided by operating activities $ 65,652   $ 70,713  
Net cash used in investing activities $ (29,028 ) $ (37,486 )
Net cash used in financing activities $ (29,047 ) $ (33,323 )
 

Non-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 months ended March 31, 2017 and 2016. 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 (Loss) and Adjusted Diluted Earnings (Loss) per Share
 
Three Months Ended
March 31,
2017     2016
(In thousands except earnings per share)
Adjusted net income (loss):
Net income (loss) $ 15,929 $ (41,149 )
Impairment (net of income tax) — 23,549
Gain on derivatives (net of income tax) (7,793 ) (7,908 )
Settlements during the period of matured derivative contracts (net of income tax)   (613 )   5,167  
Adjusted net income (loss) $ 7,523   $ (20,341 )
 
Adjusted diluted earnings (loss) per share:
Diluted earnings (loss) per share $ 0.31 $ (0.83 )
Diluted earnings per share from impairments — 0.48
Diluted earnings per share from gain on derivatives (0.15 ) (0.16 )
Diluted earnings (loss) per share from settlements of matured derivative contracts   (0.01 )   0.10  
Adjusted diluted income (loss) per share $ 0.15   $ (0.41 )

________________

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 Segment Operating Profit
 
Three Months Ended
December 31,     March 31,
2016 2017     2016
(In thousands)
Oil and natural gas $ 60,410 $ 58,394 $ 24,928
Contract drilling 11,635 7,958 10,612
Gas gathering and processing   14,653   13,237   8,134
Total operating profit 86,698 79,589 43,674
Depreciation, depletion and amortization (48,925) (46,932) (55,716)
Impairments   —   —   (37,829)
Total operating income (loss) 37,773 32,657 (49,871)
General and administrative (8,517) (8,954) (8,485)
Gain on disposition of assets 1,717 824 192
Interest, net (9,604) (9,396) (9,617)
Gain (loss) on derivatives (18,039) 14,731 10,929
Other   318   3   (15)
Income (loss) before income taxes $ 3,648 $ 29,865 $ (56,867)

________________

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 operating performance of the segments and Company on an ongoing basis using criteria that is used by management.
   
 
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,
2016 2017     2016
(In thousands except for operating days and operating margins)
Contract drilling revenue $ 33,300 $ 37,185 $ 38,710
Contract drilling operating cost   21,665   29,227   28,098
Operating profit from contract drilling 11,635 7,958 10,612
Add:
Elimination of intercompany rig profit and bad debt expense   —   —   —
Operating profit from contract drilling before elimination of intercompany rig profit and bad debt expense 11,635 7,958 10,612
Contract drilling operating days   1,796   2,291   1,878
Average daily operating margin before elimination of intercompany rig profit and bad debt expense $ 6,478 $ 3,474 $ 5,651

________________

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,
2017     2016
(In thousands)
Net cash provided by operating activities $ 65,652 $ 70,713
Net change in operating assets and liabilities   (703 )   (34,364 )
Cash flow from operations before changes in operating assets and liabilities $ 64,949   $ 36,349  

________________

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
Reconciliation of Adjusted EBITDA
 
Three Months Ended
March 31,
2017     2016
(In thousands except earnings per share)
 
Net income (loss) $ 15,929 $ (41,149 )
Income taxes 13,936 (15,718 )
Depreciation, depletion and amortization 46,932 55,590
Amortization of debt issuance costs and debt discount 536 526
Impairment — 37,829
Interest expense 9,396 9,617
Gain on derivatives (14,731 ) (10,929 )
Settlements during the period of matured derivative contracts (1,159 ) 7,140
Stock compensation plans 3,704 4,798
Other non-cash items 785 879
Gain on disposition of assets   (824 )   (192 )
Adjusted EBITDA $ 74,504   $ 48,391  
 
Diluted income (loss) per share $ 0.31 $ (0.83 )
Diluted earnings per share from income taxes 0.27 (0.32 )
Diluted earnings per share from depreciation, depletion and amortization 0.94 1.11
Diluted earnings per share from amortization of debt issuance costs and debt discount 0.01 0.01
Diluted earnings per share from impairments — 0.77
Diluted earnings per share from interest expense 0.18 0.19
Diluted earnings per share from gain on derivatives (0.29 ) (0.22 )
Diluted earnings per share from settlements during the period of matured derivative contracts (0.03 ) 0.14
Diluted earnings per share from stock compensation plans 0.07 0.10
Diluted earnings per share from other non-cash items 0.02 0.02
Diluted earnings per share from gain on disposition of assets   (0.02 )   —  
Adjusted EBITDA per diluted share $ 1.46   $ 0.97  

________________

The Company has included the adjusted EBITDA excluding gain or loss on disposition of assets and including only the cash settled commodity derivatives because:

  • It uses the adjusted EBITDA to evaluate the operational performance of the Company.
  • The adjusted EBITDA is more comparable to estimates provided by securities analysts.
  • It provides a means to assess the ability of the Company to generate cash sufficient to pay interest on its indebtedness.