Unit Corporation Reports 2014 Second Quarter Results

TULSA, Okla.--()--Unit Corporation (NYSE: UNT) today reported its financial and operational results for the second quarter of 2014. Highlights include:

  • Revenue of $405.4 million, an increase of 19% over the second quarter of 2013.
  • Oil and natural gas segment’s total equivalent production increased 12% and 10% over the second quarter of 2013 and the first quarter of 2014, respectively.
  • Oil and natural gas liquids (NGLs) production increased 18% and 13% over the second quarter of 2013 and the first quarter of 2014, respectively.
  • Five additional BOSS drilling rigs now under contract to be built for third party operators. All of the rigs are expected to be placed into service during the balance of 2014 and early 2015.
  • Average drilling rigs working increased 5.6 drilling rigs over the first quarter of 2014.
  • Mid-stream segment’s per day gas gathered volumes and liquids sold volumes both increased 7% over the first quarter of 2014.

Net income for the quarter was $54.4 million, or $1.11 per diluted share, compared to $59.0 million, or $1.22 per diluted share, for the second quarter of 2013. Adjusted net income for the quarter, which excludes the effect of non-cash commodity derivatives, was $55.4 million, or $1.13 per diluted share, compared to $48.8 million, or $1.01 per diluted share, for the same period in 2013 (see Non-GAAP Financial Measures below). Total revenues for the quarter were $405.4 million (49% oil and natural gas, 28% contract drilling, and 23% mid-stream), compared to $340.4 million (48% oil and natural gas, 31% contract drilling, and 21% mid-stream) for the second quarter of 2013.

Net income for the six months ended June 30, 2014 was $111.3 million, or $2.27 per diluted share, compared to $99.2 million, or $2.05 per diluted share, for the first six months of 2013. Adjusted net income for the first six months of 2014, which excludes the effect of non-cash commodity derivatives, was $118.1 million, or $2.41 per diluted share, compared to $93.3 million, or $1.93 per diluted share, for the same period in 2013 (see Non-GAAP Financial Measures below). Total revenues for the first six months of 2014 were $793.4 million (49% oil and natural gas, 28% contract drilling, and 23% mid-stream), compared to $659.0 million (48% oil and natural gas, 32% contract drilling, and 20% mid-stream) for the first six months of 2013.

OIL AND NATURAL GAS SEGMENT INFORMATION

Total equivalent production for the quarter was 4.6 million barrels of oil equivalent (MMBoe), an increase of 12% over the second quarter of 2013 and a 10% increase over the first quarter of 2014. Liquids (oil and NGLs) production represented 46% of total equivalent production for the quarter. Oil production for the quarter was 10,400 barrels per day, an increase of 11% over the second quarter of 2013 and an increase of 16% over the first quarter of 2014. NGLs production for the quarter was 12,800 barrels per day, an increase of 24% over the second quarter of 2013 and an increase of 8% over the first quarter of 2014. Natural gas production for the quarter was 165,100 thousand cubic feet (Mcf) per day, an increase of 8% over the second quarter of 2013 and an increase of 7% over the first quarter of 2014. Total production for the first six months of 2014 was 8.8 MMBoe.

For 2014, Unit has derivative contracts covering 7,000 Bbls per day of oil production and 90,000 MMBtu per day of natural gas production. The contracts for the oil production are swap contracts covering 3,000 Bbls per day and collars for 4,000 Bbls per day. The swap transactions are at a comparable average NYMEX price of $91.77. The collar transactions are at a comparable average NYMEX floor price of $90.00 and ceiling price of $96.08. The contracts for natural gas production are swaps covering 80,000 MMBtu per day and a collar covering 10,000 MMBtu per day. The swap transactions are at a comparable average NYMEX price of $4.24. The collar transaction is at a comparable average NYMEX floor price of $3.75 and ceiling price of $4.37.

For 2015, Unit has a derivative contract covering 1,000 Bbls per day of oil production. This swap transaction is at a comparable average NYMEX price of $95.00.

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,
2014

   

March 31,
2014

    Change    

June 30,
2014

   

June 30,
2013

    Change    

June 30,
2014

   

June 30,
2013

    Change
Oil and NGLs Production, MBbl       2,113       1,875     13 %       2,113       1,794     18 %       3,989       3,395     18 %
Natural Gas Production, Bcf       15.0       13.9     8 %       15.0       13.9     8 %       28.9       28.1     3 %
Production, MBoe       4,618       4,184     10 %       4,618       4,109     12 %       8,802       8,079     9 %
Production, MBoe/day       50.7       46.5     9 %       50.7       45.2     12 %       48.6       44.6     9 %
Avg. Realized Natural Gas Price, Mcfe (1)     $ 4.05     $ 4.24     (4 )%     $ 4.05     $ 3.65     11 %     $ 4.14     $ 3.47     19 %

Avg. Realized NGL Price, Bbl (1)

    $ 29.99     $ 39.56     (24 )%     $ 29.99     $ 30.32     (1 )%     $ 34.57     $ 32.47     6 %

Avg. Realized Oil Price, Bbl (1)

    $ 94.17     $ 91.53     3 %     $ 94.17     $ 94.89     (1 )%     $ 92.95     $ 95.05     (2 )%
Realized Price / Boe (1)     $ 40.10     $ 41.84     (4 )%     $ 40.10     $ 39.10     3 %     $ 40.93     $ 38.56     6 %
Operating Profit Before Depreciation, Depletion, & Amortization (MM) (2)     $ 153.8     $ 147.8     4 %     $ 153.8     $ 119.8     28 %     $ 301.6     $ 230.4     31 %
                                   

(1) Realized price includes oil, natural gas liquids, natural gas and associated derivatives.

(2) Operating profit before depreciation is calculated by taking operating revenues by segment less operating expenses excluding depreciation, depletion, amortization, impairment, general and administrative, and gain on disposition of assets. Operating margins are calculated by dividing operating profit by segment revenue.

Production increased in all five of Unit’s core areas during the quarter as compared to the first quarter. In the Mid Continent, which includes the Granite Wash, Hoxbar (SOHOT), Marmaton, and Mississippian formations, production increased approximately 10%, and in the SE Texas Wilcox formation production increased approximately 17%. At the end of the quarter, 15 Unit drilling rigs were operating as compared to 10 drilling rigs at the end of the first quarter. Currently, there are five drilling rigs in the Granite Wash, three in the SOHOT, two in the Wilcox, two in the Marmaton, one in the Mississippian, one in the Cleveland, and one in the Cherokee for a total of 15 drilling rigs. Unit expects to maintain between 14 and 16 drilling rigs for the remainder of 2014.

In SOHOT, production increased 81% in the quarter as compared to the first quarter, primarily as a result of our first operated Marchand horizontal completion. The Unit operated GB Ranch #1 30H (80% working interest) has produced approximately 105,000 barrels of oil and 60 million cubic feet (MMcf) of gas in 115 days. Current production is approximately 600 barrels of oil per day and 400 Mcf per day. Two additional Unit operated horizontal Marchand wells located in the same section are currently being drilled and completed with anticipated first sales for both wells anticipated to occur in August. In the SOHOT Medrano, Unit recently completed the Cody #1-36H (58% working interest) at a daily peak rate of approximately 5.2 MMcf per day and 324 barrels of oil per day. The 30-day and 60-day initial rate was approximately 3.8 MMcf per day plus 240 barrels of oil per day and 3.5 MMcf per day plus 200 barrels of oil per day, respectively.

In the Granite Wash (GW) Buffalo Wallow field, Unit is continuing to optimize the production operations by testing several types of artificial lift on the initial nine horizontal wells. To date, the GW “C1” and “B” zones have yielded the best results. Three “C1” wells were completed on three separate pads in the field. The average peak daily rate for the three “C1” wells was approximately 7.0 MMcfe per day. The three wells had an average 30-day and 60-day initial rate of approximately 5.2 MMcfe per day and 4.6 MMcfe per day, respectively. The “C1” zone is estimated to contain approximately 51% liquids. The GW “B” zone currently has one completion. The peak daily production rate was approximately 7.1 MMcfe per day. The 30- and 60-day initial rate was approximately 6.1 MMcfe per day and 4.9 MMcfe per day, respectively. The “B” zone contains approximately 40% liquids. The GW “E” (3 wells), “F1” (1 well) and “D” (1 well) zones tested at initial 30-day average rates of approximately 4.0 MMcfe per day, 2.6 MMcfe per day and 2.0 MMcfe per day, respectively. Additional production history is needed for the “E,” “F1” and “D” to determine if these zones will be economic at current commodity prices. Currently, two drilling rigs are drilling in the Buffalo Wallow field, both on three well pads. One pad will target the “B,” “C1” and “G” zones with estimated first sales occurring in the fourth quarter. The second pad will test the “B,” “C1” and “A” zones with estimated first sales in the first quarter of 2015. The average completed well cost for a Buffalo Wallow well is approximately $6.0 million.

Larry Pinkston, Unit’s Chief Executive Officer and President, said: “We are pleased with the results of our exploration program. We have made good progress following a challenging first quarter. Production has begun to ramp up, which we expect to continue throughout the remainder of the year. Our prospect inventory continues to remain strong.”

CONTRACT DRILLING SEGMENT INFORMATION

The average number of drilling rigs used in the quarter was 73.5, an increase of 13% over the second quarter of 2013, and an increase of 8% over the first quarter of 2014. Per day drilling rig rates for the quarter averaged $19,904, an increase of 2% over the second quarter of 2013 and 1% over the first quarter of 2014. Average per day operating margin for the quarter was $8,317 (before elimination of intercompany drilling rig profit and bad debt expense of $7.8 million). This compares to $7,597 (before elimination of intercompany drilling rig profit and bad debt expense of $3.7 million) for the second quarter of 2013, an increase of 9%, or $720. As compared to the first quarter of 2014 ($7,870 before elimination of intercompany drilling rig profit and bad debt expense of $5.3 million), second quarter 2014 operating margin increased 6% or $447 (in each case regarding eliminating intercompany drilling rig profit and bad debt expense - see Non-GAAP Financial Measures below).

For the first six months of 2014, Unit averaged 70.7 drilling rigs working, an increase of 7% over the 65.8 drilling rigs working during the first six months of 2013. Average per day operating margin for the first six months of 2014 was $8,104 (before elimination of intercompany drilling rig profit and bad debt expense of $13.1 million) as compared to $7,565 (before elimination of intercompany drilling rig profit and bad debt expense of $7.1 million) for the first six months of 2013, an increase of 7% (in each case regarding eliminating intercompany drilling rig profit and bad debt expense - see Non-GAAP Financial Measures below).

Larry Pinkston said: “Drilling rig demand continued at a steady increase during the quarter. Almost all of our drilling rigs working today are drilling for oil or NGLs. With our first BOSS drilling rig added in the first quarter, our drilling fleet currently totals 118 drilling rigs. Of the 118 drilling rigs, we currently have 80 drilling rigs working under contract. Long-term contracts (contracts with original terms ranging from six months to two years in length) are in place for 35 of the 80 drilling rigs. Of the 35 long term contracts, five are up for renewal in the third quarter, 12 in the fourth quarter, and 18 are up for renewal in 2015. Our first BOSS drilling rig, which originally was placed into service with our oil and natural gas segment, has now been contracted to a third party operator that plans to take delivery in the fourth quarter of 2014. Five additional BOSS drilling rigs have been contracted to be built for third party operators and are expected to be placed into service during the balance of 2014 and early 2015. Operator reception of this new drilling rig design has been very positive, and we are confident that we will procure additional contracts in the near future. We have modified our building schedule for the BOSS drilling rig with the objective of staying two drilling rigs ahead of contracts in place.”

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,
2014

   

March 31,
2014

    Change    

June 30,
2014

   

June 30,
2013

    Change    

June 30,
2014

   

June 30,
2013

    Change
Rigs Utilized      

73.5

       

67.9

      8 %       73.5         65.2       13 %       70.7         65.8       7 %
Operating Margins (1)       42 %       40 %     5 %       42 %       39 %     8 %       41 %       39 %     5 %

Operating Profit Before Depreciation,

                                   

Depletion, & Amortization (MM) (1)

    $ 47.8       $ 42.8       12 %     $ 47.8       $ 41.4       15 %     $ 90.6       $ 82.9       9 %
 

(1) Operating profit before depreciation is calculated by taking operating revenues by segment less operating expenses excluding depreciation, depletion, amortization, impairment, general and administrative, and gain on disposition of assets. Operating margins are calculated by dividing operating profit by segment revenue.

MID-STREAM SEGMENT INFORMATION

Per day liquids sold and processed volumes increased 50% and 17%, respectively, as compared to the second quarter of 2013. For the quarter, per day gathered volumes were 326,028 Mcf, essentially unchanged from the second quarter of 2013. Compared to the first quarter of 2014, liquids sold and gathered volumes per day both increased 7%, while processed volumes per day increased 8%. Operating profit (as defined in the footnote below) for the quarter was $14.0 million, an increase of 27% over the second quarter of 2013 and an increase of 15% over the first 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     Six Months Ended
     

June 30,
2014

   

March 31,
2014

    Change    

June 30,
2014

   

June 30,
2013

    Change    

June 30,
2014

   

June 30,
2013

    Change
Gas Gathering, Mcf/day       326,028       304,083     7 %       326,028       326,039     0 %       315,116       299,582     5 %
Gas processing, Mcf/day       161,509       150,042     8 %       161,509       138,130     17 %       155,807       134,016     16 %
Liquids Sold, Gallons/day       762,205       712,225     7 %       762,205       508,189     50 %       737,353       464,483     59 %

Operating Profit Before Depreciation,

                                   

Depletion, & Amortization (MM) (1)

    $ 14.0     $ 12.2     15 %     $ 14.0     $ 11.1     27 %     $ 26.2     $ 19.0     38 %
 

(1) Operating profit before depreciation is calculated by taking operating revenues by segment less operating expenses excluding depreciation, depletion, amortization, impairment, general and administrative, and gain on disposition of assets. Operating margins are calculated by dividing operating profit by segment revenue.

Larry Pinkston said: “Our midstream segment continues to grow organically, connecting 44 additional wells during the second quarter. Despite not recovering all ethane during the quarter, our liquids sold volumes and gas processed volumes continue to increase with limited incremental capital expenditure.”

FINANCIAL INFORMATION

Unit ended the quarter with long-term debt of $645.9 million (all consisting of Unit’s senior subordinated notes), and a debt to capitalization ratio of 22%. Unit had no borrowings under its credit agreement. Unit’s credit agreement provides that the amount Unit could 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 $900 million), but in either event not to exceed $900 million.

WEBCAST

Unit will webcast its second quarter earnings conference call live over the Internet on August 5, 2014 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, unexpected delays or operational issues associated with the company’s new drilling rig design, 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 and Operations Highlights

(In thousands except per share amounts)

 
Three Months Ended Six Months Ended
June 30, June 30,
      2014   2013     2014   2013
Statement of Operations:    
Revenues:
Oil and natural gas $ 198,498 $ 164,799 $ 386,705 $ 318,408
Contract drilling 114,278 105,005 220,878 212,533
Gas gathering and processing   92,655     70,617     185,836     128,012  
Total revenues   405,431     340,421     793,419     658,953  
 
Expenses:
Oil and natural gas:
Operating costs 44,723 44,994 85,138 88,032
Depreciation, depletion, and
amortization 71,245 55,335 130,925 107,318
Contract drilling:
Operating costs 66,494 63,590 130,298 129,592
Depreciation 20,239 17,908 38,634 35,168
Gas gathering and processing:
Operating costs 78,648 59,557 159,608 108,967
Depreciation and amortization 10,109 8,214 19,700 15,370
General and administrative 10,600 9,679 20,237 18,352
Gain on disposition of assets   (195 )   (3,483 )   (9,621 )   (3,399 )
Total operating expenses   301,863     255,794     574,919     499,400  
 
Income from operations   103,568     84,627     218,500     159,553  
 
Other income (expense):
Interest, net (4,131 ) (4,591 ) (7,921 ) (8,152 )
Gain (loss) on derivatives (10,709 ) 16,344 (29,075 ) 10,420
Other   (49 )   (91 )   71     (157 )
Total other income (expense)   (14,889 )   11,662     (36,925 )   2,111  
 
Income before income taxes 88,679 96,289 181,575 161,664
 
Income tax expense:
Current 8,475 2,117 18,270 4,634
Deferred   25,844     35,165     52,000     57,817  
Total income taxes   34,319     37,282     70,270     62,451  
 
Net income $ 54,360   $ 59,007   $ 111,305   $ 99,213  
 
Net income per common share:
Basic $ 1.12 $ 1.22 $ 2.29 $ 2.06
Diluted $ 1.11 $ 1.22 $ 2.27 $ 2.05
 
Weighted average shares outstanding:
Basic 48,642 48,208 48,568 48,162
Diluted 49,116 48,506 49,010 48,491
       
June 30, December 31,
      2014     2013
Balance Sheet Data:
Current assets $ 211,266 $ 212,031
Total assets $ 4,277,682 $ 4,022,390
Current liabilities $ 314,550 $ 243,573
Long-term debt $ 645,925 $ 645,696
Other long-term liabilities $ 169,122 $ 158,331
Deferred income taxes $ 853,398 $ 801,398
Shareholders’ equity $ 2,294,687 $ 2,173,392
 
Six Months Ended June 30,
      2014     2013
Statement of Cash Flows Data:
Cash flow from operations before changes
in operating assets and liabilities (1) $ 370,348 $ 317,098
Net change in operating assets and liabilities   (44,820 )   790  
Net cash provided by operating activities $ 325,528   $ 317,888  
Net cash used in investing activities $ (379,107 ) $ (322,471 )
Net cash provided by financing activities $ 36,064   $ 4,650  
 

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 cash flow from operations before changes in operating assets and liabilities, its drilling segment’s average daily operating margin before elimination of intercompany drilling rig profit and bad debt expense, and net income and earnings per share including only the effect of the cash settled commodity derivatives.

Below is a reconciliation of GAAP financial measures to non-GAAP financial measures for the three and six months ended June 30, 2014 and 2013. Non-GAAP financial measures should not be considered by themselves or a substitute for results reported in accordance with GAAP.

Unit Corporation
Reconciliation of Cash Flow From Operations Before Changes in Operating Assets and Liabilities

   

Six Months Ended
June 30,

2014     2013
(In thousands)
Net cash provided by operating activities $ 325,528 $ 317,888
Net change in operating assets and liabilities   44,820   (790 )
Cash flow from operations before changes
in operating assets and liabilities $ 370,348 $ 317,098  

________________

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 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,
2014 2014   2013 2014   2013
(In thousands except operating days and operating margins)
Contract drilling revenue $ 106,600 $ 114,278 $ 105,005 $ 220,878 $ 212,533
Contract drilling operating cost   63,804   66,494   63,590   130,298   129,592
Operating profit from contract drilling 42,796 47,784 41,415 90,580 82,941
Add:

Elimination of intercompany rig profit

and bad debt expense   5,313   7,808   3,686   13,121   7,095
Operating profit from contract drilling before
elimination of intercompany rig profit 48,109 55,592 45,101 103,701 90,036
Contract drilling operating days   6,113   6,684   5,937   12,797   11,901
Average daily operating margin before elimination of
intercompany rig profit and bad debt expense $ 7,870 $ 8,317 $ 7,597 $ 8,104 $ 7,565

________________

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 Adjusted Net Income and Adjusted Diluted Earnings per Share

    Three Months Ended     Six Months Ended
June 30,     June 30,
2014   2013     2014

 

2013

 

 

 

(In thousands except earnings per share)

Adjusted net income:  
Net income $ 54,360 $ 59,007 $ 111,305 $ 99,213
(Gain) loss on derivatives not designated as hedges
and hedge ineffectiveness (net of income tax) 6,564 (10,052 ) 17,822 (6,408 )
Settlements during the period of matured
derivative contracts (net of income tax)   (5,567 )   (111 )   (11,005 )   528  
 
Adjusted net income $ 55,357   $ 48,844   $ 118,122   $ 93,333  
 
Adjusted diluted earnings per share:
Diluted earnings per share $ 1.11 $ 1.22 $ 2.27 $ 2.05

Diluted earnings per share from the (gain) loss

on derivatives 0.13 (0.21

)

0.37 (0.13

)

Diluted earnings per share from the settlements
of matured derivative contracts   (0.11 )   ---     (0.23 )   0.01  
 
Adjusted diluted earnings per share $ 1.13   $ 1.01   $ 2.41   $ 1.93  

________________

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 analyst.

Contacts

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

Contacts

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