Unit Corporation Reports 2013 Third Quarter Results

Continuing to Set the Stage

TULSA, Okla.--()--Unit Corporation (NYSE: UNT) today reported its financial and operational results for the third quarter of 2013.

Larry Pinkston, Unit’s Chief Executive Officer and President, stated, “Unit Corporation is continuing to progress on several strategic initiatives. We have increased the number of operated drilling rigs drilling for our oil and natural gas segment in accordance with our previously stated plans, and we started our pad drilling program in the Granite Wash. In our contact drilling segment, we are nearing the completion of the first BOSS rig which will be placed into service during the fourth quarter, and we have completed the sale of four idle drilling rigs during the year. Our midstream segment continues to see the benefit of its previous capital investments with rising volumes and cash flow growth.

“For our oil and natural gas segment, the Wilcox play has provided consistent production growth during the year, and we are ramping up our exploration programs in our Granite Wash and Mississippian plays. We have initiated pad drilling in the Buffalo Wallow field which was part of our 2012 Noble property acquisition. In the Mississippian play, we resumed our drilling activity which had been suspended awaiting pipeline and processing infrastructure. We entered 2013 with six operated drilling rigs and now have 12 drilling rigs working throughout our core plays. We anticipate seeing the initial results of this increased activity in the fourth quarter of 2013.

“Our contract drilling segment continues to operate in a soft drilling market. Fewer drilling rigs are drilling more wells as drilling efficiencies are realized. Despite the soft market, we have been able to maintain consistent utilization throughout the year. During the year, we initiated a comprehensive evaluation of our drilling rig fleet. Part of that evaluation included a review regarding the possible need to realign our fleet’s capabilities and efficiencies in view of the current demand for drilling rigs using new technologies and capabilities, a demand we believe will continue for some time. As part of our evaluation, we determined that we should pursue the sale of several of our older and larger drilling rigs that have not worked for some time. Since the beginning of the year, we have sold four of our idle 2000 horsepower drilling rigs. Four additional idle 3000 horsepower drilling rigs are under contract to be sold with closings anticipated to occur over the next few months. The proceeds from these sales will be used in our new drilling rig program, a program we launched to design and build a new proprietary drilling rig, the BOSS rig. We anticipate this drilling rig will position us to more effectively meet the demands of our existing customer as well as allowing us to compete for the work of new customers. Our first BOSS drilling rig will go to work for our oil and natural gas segment in the fourth quarter of 2013. Our second BOSS drilling rig is committed to an operator in North Dakota and is planned to go into service in the second quarter of 2014. We are optimistic that the BOSS drilling rig will continue to be well received by operators and will result in additional new-build contract opportunities.

“Our midstream segment is seeing the benefit of our previous capital investments in several of its projects including our Bellmon facility in the Mississippian play in Oklahoma and our Pittsburgh Mills facility in the Appalachian area. Downward price pressure on natural gas liquids (NGLs) has had an impact on this segment’s cash flows. Our goal is to position this segment for more sustainable growth with less cash flow volatility. Where possible, we are restructuring existing commodity price based contracts as they expire to fee based contracts. These changes, while allowing us to remain competitive, should also reduce this segment’s exposure to commodity price risks.”

Notable items for the quarter include:

  • Adjusted non-GAAP net income of $41.2 million, or $0.85 per diluted share (see Non-GAAP Financial Measures below).
  • Total production of 4.2 million barrels of oil equivalent (MMBoe), an increase of 21% over the third quarter of 2012.
  • Total liquids (oil and NGLs) production increased 19% over the comparable quarter of 2012.
  • Equivalent barrel realized prices decreased 9% from the second quarter of 2013, primarily due to a 15% decrease in natural gas prices.
  • Completed the sale of two 2,000 horsepower drilling rigs. After the end of the quarter, Unit sold an additional 2,000 horsepower drilling rig, bringing to four the number of drilling rigs sold in 2013.
  • Mid-stream segment’s gathered volumes per day and liquids sold volumes per day increased by 35% and 2%, respectively, over the third quarter of 2012.
  • Mid-stream operating profit (as defined in the Selected Financial and Operational Highlights) was $12.7 million, an increase of 15% over the second quarter of 2013.

Net income for the quarter was $34.2 million, or $0.70 per diluted share, compared to $46.6 million, or $0.97 per diluted share, for the third quarter of 2012. Adjusted net income, which excludes the effect of non-cash settled commodity derivatives, was $41.2 million, or $0.85 per diluted share (see Non-GAAP Financial Measures below). Total revenues for the quarter were $333.8 million (47% oil and natural gas, 30% contract drilling, and 23% mid-stream), compared to $321.8 million (42% oil and natural gas, 41% contract drilling, and 17% mid-stream) for the third quarter of 2012.

Net income for the nine months ended September 30, 2013 was $133.4 million, or $2.75 per diluted share, compared to $79.7 million, or $1.66 per diluted share, for the first nine months of 2012. Adjusted net income for the first nine months of 2013, which excludes the effect of non-cash settled commodity derivatives, was $134.5 million, or $2.77 per diluted share (see Non-GAAP Financial Measures below). Total revenues for the first nine months of 2013 were $992.7 million (48% oil and natural gas, 32% contract drilling, and 20% mid-stream), compared to $983.5 million (41% oil and natural gas, 43% contract drilling, and 16% mid-stream) for the first nine months of 2012.

OIL AND NATURAL GAS SEGMENT INFORMATION

Unit’s production results reflect its focus on drilling oil or NGLs rich wells. Liquids production represented 43% of total equivalent production for the quarter. Total equivalent production for the quarter was 4.2 MMBoe, an increase of 21% and 3% over the third quarter of 2012 and second quarter of 2013, respectively. Liquids production has increased 149% since the first quarter of 2009 when Unit began focusing on increasing its liquids production. Third quarter 2013 oil production was 814,000 barrels, a decrease of 5% from both the third quarter of 2012 and second quarter of 2013. NGLs production for the quarter was 1,019,000 barrels, an increase of 49% and 9% compared to the third quarter of 2012 and second quarter of 2013, respectively. Natural gas production for the third quarter of 2013 was 14.3 billion cubic feet (Bcf), an increase of 22% and 3% over the third quarter of 2012 and second quarter of 2013, respectively. Total production for the first nine months of 2013 was 12.3 MMBoe, an increase of 22% over the comparable period in 2012.

Unit’s average realized per barrel equivalent price for the third quarter of 2013 was $35.77, a decrease of 6% and 9% from the third quarter of 2012 and second quarter of 2013, respectively. Unit’s average natural gas price for the third quarter of 2013 was $3.11 per thousand cubic feet (Mcf), a decrease of 9% and 15% from the third quarter of 2012 and second quarter of 2013, respectively. Unit’s average oil price for the quarter was $95.49 per barrel, an increase of 5% and 1% over the third quarter of 2012 and second quarter of 2013, respectively. Unit’s average NGLs price for the quarter was $28.10 per barrel, an increase of 32% and a decrease of 7% from the third quarter of 2012 and second quarter of 2013, respectively. For the first nine months of 2013, Unit’s average natural gas price increased 3% to $3.35 per Mcf as compared to $3.26 per Mcf for the first nine months of 2012. Unit’s average oil price for the first nine months of 2013 was $95.20 per barrel compared to $92.96 per barrel during the first nine months of 2012, a 2% increase. Unit’s average NGLs price for the first nine months of 2013 was $30.87 per barrel compared to $30.70 per barrel during the first nine months of 2012, a 1% increase. All prices reflected in this paragraph include the effects of hedges. Operating costs in the third quarter of 2013 increased 39% and 11% over the third quarter of 2012 and second quarter of 2013, respectively. The increase over the third quarter of 2012 was primarily due to costs associated with wells added through acquisitions, higher salt water disposal costs, and wells completed during 2013. The increase over the second quarter of 2013 was primarily due to increases in both salt water disposal costs and well servicing costs. Operating costs for the first nine months of 2013 increased 32% over the comparable period in 2012, primarily due to costs associated with wells added through acquisitions, higher salt water disposal costs and wells completed during 2013.

For 2013, Unit has hedged 8,330 Bbls per day of its oil production and 100,000 MMBtu per day of natural gas production. The oil production is hedged under swap contracts at an average price of $97.94 per barrel. Of the natural gas production, 80,000 MMBtu per day are hedged with swaps and 20,000 MMBtu per day are hedged with a collar. The swap transactions were at a comparable average NYMEX price of $3.65. The collar transaction was at a comparable average NYMEX floor price of $3.25 and ceiling price of $3.72.

For 2014, Unit has hedged 7,248 Bbls per day of its oil production and 50,000 MMBtu per day of natural gas production. Of the oil production, 3,248 Bbls per day are hedged with swaps and 4,000 Bbls per day are hedged with collars. The swap transactions were at an average price of $92.35. The collar transactions were at an average floor price of $90.00 and ceiling price of $96.08. The natural gas production is hedged under swap contracts at a comparable average NYMEX price of $4.24 per MMBtu.

The following table illustrates Unit’s production and realized prices for the periods indicated:

    3rd Qtr 13   2nd Qtr 13   1st Qtr 13   4th Qtr 12   3rd Qtr 12   2nd Qtr 12   1st Qtr 12   4th Qtr 11   3rd Qtr 11

Oil and NGL Production, MBbl

   

 

1,832.9

   

 

1,794.1

   

 

1,600.6

   

 

1,694.1

   

 

1,545.8

   

 

1,460.2

   

 

1,375.2

   

 

1,359.9

   

 

1,197.5

Natural Gas Production, Bcf    

 

14.3

   

 

13.9

   

 

14.2

   

 

14.5

   

 

11.7

   

 

11.3

   

 

11.4

   

 

11.4

   

 

11.6

Production, MBoe    

4,217

   

4,109

   

3,971

   

4,115

   

3,498

   

3,341

   

3,275

   

3,255

   

3,123

Production, MBoe/day    

45.8

   

45.2

   

44.1

   

44.7

   

38.0

   

36.7

   

36.0

   

35.4

   

33.9

Realized Price, Boe (1)

 

$

35.77

 

$

39.10

 

$

37.99

 

$

39.56

 

$

37.99

 

$

38.49

 

$

40.51

 

$

42.65

 

$

41.75

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

The Wilcox play in southeast Texas continues to produce strong results with average daily production for the quarter increasing approximately 5% and 25% compared to the second quarter 2013 and the third quarter 2012, respectively. During the first three quarters of 2013, Unit achieved a 100% success rate by completing six vertical liquids rich Wilcox gas wells with three of the six wells located in the Gilly Field. Unit owns 100% working interest in all six wells. Unit’s first horizontal Wilcox well in the Gilly Field has been drilled and is scheduled to be fracture stimulated in late November 2013. The well will be completed from approximately 1,500 feet of Lower Wilcox lateral. There are currently two Unit drilling rigs drilling in Unit’s Wilcox play which should result in a total of 8 to 10 gross wells drilled in this play during the year at a net cost of approximately $70 million.

In Unit’s Mississippian play in south central Kansas, the average daily production for the quarter increased approximately 62% and 156% compared to the second quarter 2013 and the third quarter 2012, respectively. Unit resumed drilling in the prospect in late July with one Unit drilling rig and plans to add a second Unit drilling rig late in the fourth quarter. There were no new Mississippian completions during the third quarter, and we expect to complete five wells during the fourth quarter. Unit has increased its Mississippian leasehold by 13% during the quarter to approximately 133,000 net acres and plans to spend approximately $32 million (net) drilling and completing approximately 9 wells (100% working interest) during 2013.

In its Granite Wash (GW) play in the Texas Panhandle, average daily production for the quarter increased approximately 6% and 46% compared to the second quarter 2013 and the third quarter 2012, respectively. For the first three quarters of 2013, Unit had first sales on fourteen horizontal wells, having an average peak 30 day IP rate of 5.0 MMcfe per day and an average working interest of 86%. Unit has completed drilling operations on three wells located on its first pad site in the Buffalo Wallow field targeting three different GW sands. One of the three wells was recently fracture stimulated and in the early stages of flowing back while the other two wells are scheduled to be completed in late November. Two additional pad sites in the Buffalo Wallow field are currently being drilled. Unit currently has six Unit drilling rigs working in the GW and anticipates completing approximately 27 gross horizontal wells during the year of which about half will be completed in the fourth quarter.

In the Marmaton horizontal oil play in Beaver County, Oklahoma, Unit had record average daily production of approximately 4,400 barrels of oil equivalent per day for the quarter, an increase of approximately 16% and 21% compared to second quarter 2013 and third quarter 2012, respectively. Unit completed 32 wells through the third quarter of 2013 with an average working interest of 76%. The average 30 day peak rate for those wells is approximately 368 Boe. Unit has leases on approximately 118,000 net acres in this play with approximately 55% of the leasehold held by production. Unit anticipates continuing the two Unit drilling rig program in this play which should result in approximately 46 gross wells being drilled during the year for an approximate net cost of $105 million.

Larry Pinkston said, “We are pleased with the production increase from our oil and natural gas segment and are excited about its production growth outlook. Production has grown during the third quarter of 2013 from the second quarter of 2013 due principally to the gradual ramp up in company operated drilling rigs. We are now operating 12 drilling rigs, which is an increase from 6 at the beginning of the year. We have completed sales of certain non-core oil and natural gas assets during 2013, with total proceeds of $64.4 million.”

CONTRACT DRILLING SEGMENT INFORMATION

The average number of drilling rigs used in the third quarter of 2013 was 63.5, a decrease of 13% from the third quarter of 2012, and a decrease of 3% from the second quarter of 2013. Per day drilling rig rates for the third quarter of 2013 averaged $19,773, a decrease of 1%, or $216, from the third quarter of 2012, and an increase of 1% over the second quarter of 2013. Average per day operating margin for the third quarter of 2013 was $7,920 (before elimination of intercompany drilling rig profit of $4.6 million). This compares to $9,672 (before elimination of intercompany drilling rig profit of $4.0 million) for the third quarter of 2012, a decrease of 18%, or $1,752. As compared to the second quarter of 2013 ($7,597 before elimination of intercompany drilling rig profit of $3.7 million), third quarter 2013 operating margin increased 4% or $323 (in each case regarding eliminating intercompany drilling rig profit see Non-GAAP Financial Measures below). For the third quarter of 2013 average operating margins included early termination fees of approximately $87 per day from the cancellation of certain long-term contracts, compared to $1,007 per day for the third quarter of 2012.

For the first nine months of 2013, Unit averaged 65.0 drilling rigs working, a decrease of 16% from 77.2 drilling rigs working during the first nine months of 2012. Average per day operating margin for the first nine months of 2013 was $7,682 (before elimination of intercompany drilling rig profit of $11.7 million) as compared to $10,063 (before elimination of intercompany drilling rig profit of $12.9 million) for the first nine months of 2012, a decrease of 24% (in each case regarding eliminating intercompany drilling rig profit see Non-GAAP Financial Measures below). For the first nine months of 2013, average operating margins included early termination fees of approximately $32 per day from the cancellation of certain long-term contracts, compared to $1,077 per day for the first nine months of 2012.

Larry Pinkston said, “Drilling rig demand has been fairly flat during the first nine months of 2013. Operators are continuing to focus on shallower oil plays and liquids rich plays providing us the opportunity to put more of our 750 to 1,000 horsepower drilling rigs to work. Almost all of our drilling rigs working today are drilling for oil or NGLs. During the third quarter, we sold two 2,000 horsepower drilling rigs. After the end of the quarter, we sold an additional 2,000 horsepower drilling rig, bringing our fleet’s total to 123 drilling rigs. Of the 123 drilling rigs, we have 67 under contract. Long-term contracts (contracts with original terms ranging from six months to two years in length) are in place for 23 of those 67 drilling rigs. Of these contracts, six are up for renewal during the fourth quarter of 2013. We are constructing a new prototype 1,500 horsepower AC electric drilling rig of proprietary design. This drilling rig, called our “BOSS” rig is expected to be operational in the fourth quarter of 2013 and will operate initially for our oil and natural gas segment. Our second BOSS drilling rig is committed to an operator in North Dakota and is anticipated to be placed into service in the second quarter of 2014.”

The following table illustrates Unit’s drilling segment drilling rig count at the end of each period and average utilization rate during the period:

    3rd Qtr 13   2nd Qtr 13   1st Qtr 13   4th Qtr 12   3rd Qtr 12   2nd Qtr 12   1st Qtr 12   4th Qtr 11   3rd Qtr 11
Drilling Rigs   124     126     127     127     127     128     127     127     126  
Utilization   51 %   51 %   52 %   50 %   58 %   60 %   64 %   65 %   63 %

MID-STREAM SEGMENT INFORMATION

Third quarter of 2013 per day gathered volumes were 326,474 Mcf, an increase of 35% over the third quarter of 2012. Per day liquids sold and processed volumes increased 2% and 8%, respectively, as compared to the third quarter of 2012. Compared to the second quarter of 2013, gathered volumes per day were essentially unchanged, while liquids sold volumes per day and processed volumes per day increased 15% and 5%, respectively. Operating profit (as defined in the Selected Financial and Operational Highlights) for the third quarter of 2013 was $12.7 million, an increase of 91% over the third quarter of 2012 and an increase of 15% over the second quarter of 2013.

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

    3rd Qtr 13   2nd Qtr 13   1st Qtr 13   4th Qtr 12   3rd Qtr 12   2nd Qtr 12   1st Qtr 12   4th Qtr 11   3rd Qtr 11
Gas gathered
Mcf/day
 

326,474

 

326,039

 

272,831

 

279,990

 

241,271

 

262,269

 

217,404

 

222,436

 

198,625

Gas processed
Mcf/day
 

145,020

 

138,130

 

129,857

 

131,570

 

134,907

 

144,257

 

125,231

 

126,628

 

104,351

Liquids sold

Gallons/day

 

586,446

 

508,189

 

420,291

 

441,973

 

576,889

 

629,350

 

522,829

 

511,410

 

449,604

Larry Pinkston said, “In the first quarter of 2013, we completed the installation of a second processing plant at our Bellmon facility, a 30 MMcf per day cryogenic plant. The Bellmon facility is located in the Mississippian play in north central Oklahoma and consists of approximately 142 miles of pipeline. Due to increasing volumes, we are installing an additional 60 MMcf per day processing plant expected to be operational in the fourth quarter of 2013. At our Hemphill facility in Hemphill County, Texas, we now can process 135 MMcf per day of our own and third party Granite Wash natural gas production after relocating two processing plants from Hemphill to the new Reno facility. We are in the process of completing two pipeline extension projects for a total cost of approximately $5.7 million, which will allow us to connect additional production from our oil and natural gas segment to this system. In Reno County, Kansas, we completed initial construction of a new gathering system and processing facility. This new system consists of approximately 20 miles of gathering pipeline and the two processing plants relocated from our Hemphill facility, a 5 MMcf per day refrigeration plant and a 20 MMcf per day turbo expander plant. We began gathering gas at this facility during the second quarter and processing gas in the third quarter of 2013.”

FINANCIAL INFORMATION

Unit ended the third quarter with long-term debt of $645.6 million (comprised entirely of senior subordinated notes), and a debt to capitalization ratio of 23%. Under its credit agreement, the amount available to be borrowed is the lesser of the amount Unit elects as the commitment amount (currently $500 million) or the value of its borrowing base as determined by the lenders (currently $800 million), but in either event not to exceed $900 million. At this time, Unit has no borrowings under its credit agreement.

MANAGEMENT COMMENT

Larry Pinkston said, “We are pleased with the performance of all three of our segments and we are excited about their continued growth opportunities. Each segment is moving forward on key initiatives which should create additional shareholder value for years to come. We continue to maintain a conservative financial profile. We are well positioned for continued growth and to take advantage of new opportunities that may arise.”

WEBCAST

Unit will webcast its third quarter earnings conference call live over the Internet on November 5, 2013 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 and operations data)

 
Three Months Ended Nine Months Ended
September 30, September 30,
    2013   2012   2013   2012
Statement of Income:
Revenues:
Oil and natural gas $ 157,320 $ 135,435 $ 475,728 $ 402,366
Contract drilling 100,647 133,420 313,180 421,198
Gas gathering and processing   75,809     52,935     203,821     159,977  
Total revenues   333,776     321,790     992,729     983,541  
 
Expenses:
Oil and natural gas:
Operating costs 50,139 36,147 138,171 105,035
Depreciation, depletion, and
amortization 56,294 44,489 163,612 153,839

Impairment of oil and natural

gas properties --- --- --- 115,874
Contract drilling:
Operating costs 58,988 72,988 188,580 223,980
Depreciation 17,402 20,094 52,570 62,660
Gas gathering and processing:
Operating costs 63,098 46,267 172,065 136,243
Depreciation and amortization 8,773 5,884 24,143 16,330
General and administrative 9,936 8,434 28,288 23,814
Gain on disposition of assets   (4,345 )   (44 )   (7,744 )   (1,283 )
Total operating expenses   260,285     234,259     759,685     836,492  
 
Income from operations   73,491     87,531     233,044     147,049  
 
Other income (expense):
Interest, net (3,625 ) (7,087 ) (11,777 ) (11,455 )
Loss on derivatives not
designated as hedges and
hedge ineffectiveness, net

(13,760

)

(4,015

)

(3,340

)

(4,621

)

Other   (14 )   (59 )   (171 )   (123 )
Total other income (expense)   (17,399 )   (11,161 )   (15,288 )   (16,199 )
 
Income before income taxes 56,092 76,370 217,756 130,850
 
Income tax expense:
Current 2,111 2,516 6,745 450
Deferred   19,749     27,268     77,566     50,677  
Total income taxes   21,860     29,784     84,311     51,127  
 
Net income $ 34,232   $ 46,586   $ 133,445   $ 79,723  
 
Net income per common share:
Basic $ 0.71 $ 0.97 $ 2.77 $ 1.66
Diluted $ 0.70 $ 0.97 $ 2.75 $ 1.66
 
Weighted average shares outstanding:
Basic 48,254 47,938 48,193 47,891
Diluted 48,658 48,201 48,510 48,106
   
September 30, December 31,
    2013   2012
Balance Sheet Data:
Current assets $ 181,575 $ 195,644
Total assets $ 3,924,695 $ 3,761,120
Current liabilities $ 229,655 $ 207,139
Long-term debt $ 645,584 $ 716,359
Other long-term liabilities $ 159,099 $ 167,545
Deferred income taxes $ 773,412 $ 695,776
Shareholders’ equity $ 2,116,945 $ 1,974,301
 
Nine Months Ended September 30,
    2013   2012
Statement of Cash Flows Data:  
Cash flow from operations before changes
in operating assets and liabilities (1) $ 468,537 $ 499,609
Net change in operating assets and liabilities   32,424     12,531  
Net cash provided by operating activities $ 500,961   $ 512,140  
Net cash used in investing activities $ (422,658 ) $ (888,597 )
Net cash provided by (used in)
financing activities $ (77,536 ) $ 376,645
   
Three Months Ended Nine Months Ended
September 30, September 30,
    2013   2012   2013   2012
Oil and Natural Gas Operations Data:    
Production:
Oil – MBbls 814 861 2,470 2,367
Natural Gas Liquids - MBbls 1,019 684 2,758 2,014
Natural Gas - MMcf 14,304 11,716 42,411 34,403
Average Prices:

Oil price per barrel received

$ 95.49 $ 91.07 $ 95.20 $ 92.96

Oil price per barrel received, excluding hedges

$ 103.09 $ 87.38 $ 95.49 $ 91.93
NGLs price per barrel received $ 28.10 $ 21.34 $ 30.87 $ 30.70
NGLs price per barrel received,
excluding hedges $ 28.10 $ 20.75 $ 30.87 $ 29.61
Natural gas price per Mcf received $ 3.11 $ 3.40 $ 3.35 $ 3.26
Natural gas price per Mcf received,
excluding hedges $ 3.07 $ 2.50 $ 3.38 $ 2.29

Operating profit before depreciation, depletion,

amortization, and impairment (2) ($MM) $ 107.2 $ 99.3 $ 337.6 $ 297.3
 
Contract Drilling Operations Data:
Rigs utilized 63.5 73.4 65.0 77.2
Operating margins (2) 41 % 45 % 40 % 47 %
Operating profit before depreciation (2) ($MM) $ 41.7 $ 60.4 $ 124.6 $ 197.2
 
Mid-Stream Operations Data:
Gas gathering - Mcf/day 326,474 241,271 308,645 240,318
Gas processing - Mcf/day 145,020 134,907 137,725 134,799
Liquids sold – Gallons/day 586,446 576,889 505,584 576,358
Operating profit before depreciation
and amortization (2) ($MM) $ 12.7 $ 6.7 $ 31.8 $ 23.7

(1) The company considers its cash flow from operations before changes in operating assets and liabilities an important measure in meeting the performance goals of the company (see Non-GAAP Financial Measures below).

(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.

Non-GAAP Financial Measures

We report our financial results in accordance with generally accepted accounting principles (“GAAP”). We believe certain non-GAAP performance measures provide users of our financial information and our management additional meaningful information to evaluate the performance of our company.

This press release includes cash flow from operations before changes in operating assets and liabilities, our drilling segment’s average daily operating margin before elimination of intercompany drilling rig profit, and net income and earnings per share including only the effect of the cash settled commodity derivatives and excluding the impairment of oil and natural gas properties.

Below is a reconciliation of GAAP financial measures to non-GAAP financial measures for the three and nine months ended September 30, 2013 and 2012. Non-GAAP financial measures should not be considered by themselves or a substitute for our results reported in accordance with GAAP.

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

 

Nine Months Ended
June 30,
2013 2012
(In thousands)
Net cash provided by operating activities $ 500,961 $ 512,140
Net change in operating assets and liabilities   (32,424 )   (12,531 )
Cash flow from operations before changes
in operating assets and liabilities $ 468,537   $ 499,609  

________________

We have included the cash flow from operations before changes in operating assets and liabilities because:

  • It is an accepted financial indicator used by our management and companies in our industry to measure the company’s ability to generate cash which is used to internally fund our business activities.
  • It is used by investors and financial analysts to evaluate the performance of our company.
         
Unit Corporation
Reconciliation of Average Daily Operating Margin Before Elimination of Intercompany Rig Profit
 
Three Months Ended Nine Months Ended
June 30, September 30, September 30,
2013 2013 2012 2013 2012
(In thousands except operating days and operating margins)
Contract drilling revenue $ 105,005 $ 100,647 $ 133,420 $ 313,180 $ 421,198
Contract drilling operating cost   63,590   58,988   72,988   188,580   223,980
Operating profit from contract drilling 41,415 41,659 60,432 124,600 197,218
Add:

Elimination of intercompany rig profit

 

3,686

 

4,579

 

3,983

 

11,674

 

12,936

Operating profit from contract drilling
before elimination of intercompany
rig profit 45,101 46,238 64,415 136,274 210,154
Contract drilling operating days   5,937   5,838   6,660   17,739   20,884
Average daily operating margin before
elimination of intercompany rig profit $ 7,597 $ 7,920 $ 9,672 $ 7,682 $ 10,063

________________

We have included the average daily operating margin before elimination of intercompany rig profit because:

  • Our management uses the measurement to evaluate the cash flow performance of our 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 our company.
       
Unit Corporation
Reconciliation of Adjusted Net Income and Adjusted Diluted Earnings per Share
 
Three Months Ended Nine Months Ended
September 30,   September 30,
2013   2012   2013   2012
 

 

(In thousands except per share amounts)

Adjusted net income:
Net income $ 34,232 $ 46,586 $ 133,445 $ 79,723
Impairment of oil and natural gas properties --- --- --- 72,132
Loss on derivatives not designated as hedges and
hedge ineffectiveness (net of income tax) 8,455 2,449 2,047 2,821
Settlements during the period of matured
derivative contracts (net of income tax)   (1,493 )   ---   (965 )   ---
 
Adjusted net income $ 41,194   $ 49,035 $ 134,527   $ 154,676
 
Adjusted diluted earnings per share:
Diluted earnings per share $ 0.70 $ 0.97 $ 2.75 $ 1.66
Impairment of oil and natural gas properties --- --- --- 1.50
Diluted earnings per share from the (gain) loss
on derivatives 0.18 0.05 0.04 0.06
Diluted earnings per share from the settlements
of matured derivative contracts   (0.03 )   ---   (0.02 )   ---
 
Adjusted diluted earnings per share $ 0.85   $ 1.02 $ 2.77   $ 3.22

________________

We have included the net income and diluted earnings per share excluding the impairment of oil and natural gas properties and including only the cash settled commodity derivatives because:

  • We use 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

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Contacts

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