Unit Corporation Reports 2011 First Quarter Results

TULSA, Okla.--()--Unit Corporation (NYSE: UNT) reported net income of $41.0 million, or $0.86 per diluted share, for the three months ended March 31, 2011. For the same period in 2010, net income was $36.2 million, or $0.76 per diluted share. Total revenues for the first quarter of 2011 were $247.4 million (40% contract drilling, 44% oil and natural gas, and 16% mid-stream), compared to $206.6 million (30% contract drilling, 48% oil and natural gas, and 20% mid-stream) for the first quarter of 2010.

CONTRACT DRILLING SEGMENT INFORMATION

The average number of drilling rigs used in the first quarter of 2011 was 70.0, an increase of 38% over the first quarter of 2010, and a decrease of 1% from the fourth quarter of 2010. Per day drilling rig rates for the first quarter of 2011 averaged $17,704, up 25% (or $3,577) from the first quarter of 2010, and up 7% (or $1,134) from the fourth quarter of 2010. Average per day operating margin for the first quarter of 2011 was $8,077 (before elimination of intercompany drilling rig profit of $5.0 million). This compares to $4,435 (before elimination of intercompany drilling rig profit of $0.4 million) for the first quarter of 2010, an increase of 82%, or $3,642. As compared to the fourth quarter of 2010 ($7,559 before elimination of intercompany drilling rig profit of $4.4 million) first quarter 2011 operating margin increased 7% or $518 – in each case with regard to the elimination of intercompany drilling rig profit see Non-GAAP Financial Measures below.

Larry Pinkston, Unit’s Chief Executive Officer and President, said: “We are pleased with the results from our contract drilling segment. Our utilization rates have remained strong and we have obtained an increase in drilling rig day rates over the fourth quarter of 2010. Our fleet went through a transition in 2010 to accommodate the growing industry focus on drilling horizontal or directional wells. We refurbished and upgraded 30 drilling rigs in 2010 in order that they could undertake this type of drilling. Approximately 80% of our drilling rigs working today are drilling for oil or natural gas liquids and approximately 99% are drilling horizontal or directional wells. We had previously announced that during 2011 we will add five new drilling rigs to our fleet, all of which are 1,500 horsepower, diesel-electric drilling rigs under two-year term contracts. To date, two of those five drilling rigs have begun operating bringing our current total fleet to 123 drilling rigs. Currently, 76 of our 123 drilling rigs are under contract. Term contracts (contracts with original terms ranging from six months to two years in length) are in place for 41 of the 76 contracted drilling rigs. Of these contracts 13 are up for renewal during the second quarter of 2011, nine during the third quarter of 2011, ten during the fourth quarter of 2011, and nine after 2011. These contracts do not include the term contracts for the three remaining new drilling rigs to be added to our fleet later this year.”

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

                 
1st Qtr 11 4th Qtr 10 3rd Qtr 10 2nd Qtr 10 1st Qtr 10 4th Qtr 09 3rd Qtr 09 2nd Qtr 09 1st Qtr 09
Rigs 122 121 123 123 125 130 130 131 131
Utilization 58% 59% 54% 47% 40% 28% 26% 24% 40%
 

OIL AND NATURAL GAS SEGMENT INFORMATION

  • Completed 34 gross wells in the first quarter of 2011 with a 91% success rate.
  • 38% of first quarter 2011 production was oil and natural gas liquids compared to 29% for the first quarter of 2010.
  • Anticipated 2011 production of 11.0 to 11.3 MMBoe.

First quarter 2011 oil production was 556,000 barrels, in comparison to 303,000 barrels for the same period of 2010, up 84%. Natural gas liquids (NGLs) production during the first quarter of 2011 was 478,000 barrels, an increase of 27% when compared to 377,000 barrels for the same period of 2010. First quarter 2011 natural gas production increased 2% to 10.2 billion cubic feet (Bcf) compared to 10.0 Bcf for the comparable quarter of 2010. First quarter 2011 production averaged 30,436 Boe per day, up 16% over the first quarter of 2010 and up 4% over the fourth quarter of 2010. Total production for the first quarter of 2011 was 2.7 MMBoe.

Unit’s average natural gas price, including the effects of hedges, for the first quarter of 2011 decreased 28% to $4.28 per thousand cubic feet (Mcf) as compared to $5.95 per Mcf for the first quarter of 2010. Unit’s average oil price, including the effects of hedges, for the first quarter of 2011 increased 25% to $84.33 per barrel compared to $67.33 per barrel for the first quarter of 2010. Unit’s average NGLs price, including the effects of hedges, for the first quarter of 2011 was $39.61 per barrel compared to $42.76 per barrel for the first quarter of 2010, down 7%.

Currently for 2011, Unit has hedged 80,000 MMBtu per day of its natural gas production, 4,000 Bbls per day of its oil production and 504 Bbls per day of its NGLs production. The natural gas production is hedged under swap contracts at a comparable average NYMEX price of $4.85. The average basis differential for the swaps is ($0.19). The oil production is hedged under swap contracts at an average price of $84.28 per barrel. The NGLs production is hedged under swap contracts at an average price of $40.48 per barrel.

For 2012, Unit has to-date hedged 30,000 MMBtu per day of its natural gas production and 4,000 Bbls per day of its oil production. The natural gas production is hedged under swap contracts at a comparable average NYMEX price of $5.48. The average basis differential for the swaps is ($0.28). The oil production is hedged under swap contracts at an average price of $95.01 per barrel.

For 2013, Unit has to-date hedged 1,500 Bbls per day of its oil production. The oil production is hedged under swap contracts at an average price of $102.18 per barrel.

The following table illustrates Unit’s production and certain results for the periods indicated:

                 
1st Qtr 11 4th Qtr 10 3rd Qtr 10 2nd Qtr 10 1st Qtr 10 4th Qtr 09 3rd Qtr 09 2nd Qtr 09 1st Qtr 09
Production, MBoe

2,739

2,698

2,478

2,325

2,352

2,389

2,444

2,572

2,713

Production, MBoe/day

30.4

29.3

27.0

25.6

26.1

26.0

26.6

28.3

30.1

Realized price,

Boe (1)

$40.00

$41.58

$38.16

$38.22

$40.92

$36.72

$35.52

$34.50

$32.88

Wells Drilled

34

62

39

39

27

37

21

16

21

Success Rate

91%

95%

85%

92%

96%

92%

90%

100%

90%

 

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

In the Marmaton horizontal oil play located in Beaver County, Oklahoma, Unit had first sales on nine wells during the first quarter, in which it has an average working interest of approximately 91%. The 30-day average production rate for the nine wells was 238 Boe per day. The average ultimate recovery for a Marmaton well is estimated at 130 MBoe comprised of 76% oil, 14% NGLs, and 10% natural gas, with an average cost per well of $2.8 million. Unit has scheduled three to four frac dates per month for 2011 which should cover its current two rig drilling program. For 2011, Unit anticipates having first oil sales on 30 to 36 gross wells within this play at a total net cost of $52 million. Unit currently has leases on approximately 66,000 net acres in the play.

In the Granite Wash (GW) play located in the Texas Panhandle, Unit had first sales on five horizontal wells during the first quarter. Unit’s average working interest in these wells is 76%. Of the five new wells, one well was completed in the GW “A”, two in the GW “B”, one in the GW “D” and one in the GW “F” zone. The average 30 day rate of production for these five wells was 6.0 MMcfe per day, consisting of 16% oil, 33% NGLs and 51% natural gas. Highlighting the first quarter wells was the first horizontal GW “D” zone completion. That completion resulted in a peak daily rate of 483 barrels of oil per day, 474 barrels of NGLs and 4.4 MMcf of natural gas or an equivalent rate of 10.1 MMcfe per day. The 30 day average production rate for this well was 7.0 MMcfe per day. Anticipated reserves for the GW formation production from the five horizontal wells is 4.0 Bcfe per well, comprised of 10% oil, 37% NGLs and 53% natural gas at a total net cost of $5.2 million. In addition, Unit participated in three outside operated GW horizontal wells, with an average working interest of 11%. Unit plans to work three to four Unit drilling rigs drilling Granite Wash horizontal wells in 2011 which should result in 20 to 22 operated GW wells drilled during the year with a projected total net cost of $82 million.

Pinkston said: “We are pleased with the results of our drilling activity for the quarter. The first quarter of 2011 is the third consecutive quarter that production has increased. Our strategy of focusing on oil or NGLs rich prospects is evident in our first quarter 2011 production results of which 38% was oil and NGLs as compared to 29% in the first quarter of 2010 and 34% in the fourth quarter of 2010. For the quarter, we completed 34 gross wells with a success rate of 91% compared to 27 gross wells with a 96% success rate during the first quarter of 2010. For the year, we plan to drill 180 gross wells with an anticipated annual production guidance of approximately 11.0 to 11.3 MMBoe, an increase of 11% to 15% over 2010.”

MID-STREAM SEGMENT INFORMATION

  • Increased first quarter 2011 liquids sold per day volumes, processing volumes per day, and gathering volumes per day by 29%, 13% and 3%, respectively, over the first quarter of 2010.
  • Construction of 16-mile pipeline and related compressor station in Preston County, West Virginia is on schedule to be operational by mid-2011.
  • Signed contract to build a 12-mile pipeline system and compressor station in Tioga and Potter Counties, Pennsylvania.

First quarter of 2011 per day processing volumes were 86,445 MMBtu while liquids sold volumes were 328,333 gallons per day, an increase of 13% and 29%, respectively, over first quarter of 2010. First quarter 2011 per day gathering volumes were 185,730 MMBtu, up 3% over the first quarter of 2010. Operating profit (as defined in the Selected Financial and Operational Highlights) for the first quarter was $10.7 million, an increase of 27% from the first quarter of 2010, primarily due to increased processing margins resulting from increased liquids prices and increased volumes.

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

  1st Qtr 11   4th Qtr 10   3rd Qtr 10   2nd Qtr 10   1st Qtr 10   4th Qtr 09   3rd Qtr 09   2nd Qtr 09   1st Qtr 09
Gas gathered
MMBtu/day

185,730

188,252

183,161

183,858

180,117

177,145

179,047

187,666

192,320

Gas processed
MMBtu/day

86,445

85,195

84,175

82,699

76,513

77,501

77,923

75,481

72,650

Liquids sold

Gallons/day

328,333

291,186

260,519

279,736

253,707

263,668

251,830

239,121

218,762

Pinkston said: “Processing and liquids sold volumes continue to increase and gas gathered volumes remain strong. As previously announced, we completed the installation and startup of a 50.0 MMcf per day turbo-expander natural gas processing plant at our Hemphill facility near Canadian, Texas, during the fourth quarter of 2010. With the completion of this new plant, the total processing capacity at our Hemphill facility has increased to approximately 100.0 MMcf per day. In connection with our Appalachian operations, we recently started construction of a 16-mile, 16" pipeline and a compressor station in Preston County, West Virginia, which will have a capacity of approximately 220.0 MMcf per day. We anticipate this pipeline will be operational by mid-2011. In addition to the Preston County pipeline, we recently signed a contract to build a 12-mile pipeline system and compressor station in Tioga and Potter Counties, Pennsylvania. This system will deliver gas to Dominion Transmission pipeline and is scheduled to be completed in the fourth quarter of this year.”

FINANCIAL INFORMATION

Unit ended the first quarter of 2011 with working capital of $12.7 million, long-term debt of $185.0 million, and a debt to capitalization ratio of 10%. Under its credit facility, the amount available to be borrowed is the lesser of the amount the company elects as the commitment amount (currently $325 million) or the value of the borrowing base as determined by the lenders (currently $600 million), but, in either event, not to exceed the maximum credit facility amount of $400 million.

MANAGEMENT COMMENT

Larry Pinkston said: “Our first quarter 2011 operating results were solid. We continue to focus our exploration efforts on our oil and natural gas liquids rich plays such as the Granite Wash and Marmaton. On the drilling side, we plan to continue responding to the demand for horizontal drilling by our customers by refurbishing and upgrading our existing rigs and, where appropriate, adding new drilling rigs to our fleet. Our mid-stream segment is also exploring for additional opportunities to grow its operations. We are optimistic about 2011, and our balance sheet is well positioned to take advantage of growth opportunities that may arise in all three of our business segments during the year.”

WEBCAST

Unit will webcast its first quarter earnings conference call live over the Internet on May 3, 2011 at 11:00 a.m. Eastern Time. To listen to the live call, please go to www.unitcorp.com at least fifteen minutes before 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.

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. A number of risks and uncertainties could cause actual results to differ materially from these statements, including the impact that the current decline in wells being drilled will have on production and drilling rig utilization, 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, as well as 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 exploration segment, development, operational, implementation and opportunity risks, possible delays caused by limited availability of third party services needed in the course of 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 as a result 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
March 31,
    2011     2010
Statement of Operations:  
Revenues:
Contract drilling $ 97,988 $ 60,854
Oil and natural gas 109,834 99,053
Gas gathering and processing 39,764 41,135
Other, net   (181 )   5,508
Total revenues   247,405   206,550
 
Expenses:
Contract drilling:
Operating costs 52,844 40,900
Depreciation 17,297 13,786
Oil and natural gas:
Operating costs 30,781 25,034
Depreciation, depletion and amortization 40,268 25,336
Gas gathering and processing:
Operating costs 29,055 32,726
Depreciation and amortization 3,773 3,941
General and administrative 6,892 6,279
Interest, net   54   ---
Total expenses   180,964   148,002
Income Before Income Taxes   66,441   58,548
 
Income Tax Expense:
Current --- 2,240
Deferred   25,414   20,155
Total income taxes   25,414   22,395
Net Income $ 41,027 $ 36,153
 
Net Income per Common Share:
Basic $ 0.86 $ 0.77
Diluted $ 0.86 $ 0.76
 
Weighted Average Common Shares Outstanding:
Basic 47,584 47,121
Diluted 47,905 47,686
 
March 31, December 31,
    2011     2010
Balance Sheet Data:
Current assets $ 189,015 $ 188,180
Total assets $ 2,786,044 $ 2,669,240
Current liabilities $ 176,274 $ 147,128
Long-term debt $ 185,000 $ 163,000
Other long-term liabilities $ 100,821 $ 92,389
Deferred income taxes $ 579,085 $ 556,106
Shareholders’ equity $ 1,744,864 $ 1,710,617
 
Three Months Ended March 31,
    2011       2010
Statement of Cash Flows Data:    

Cash Flow From Operations before Changes in Operating Assets and Liabilities (1)

$ 134,697 $ 97,030
Net Change in Operating Assets and Liabilities   (13,492 )   (17,363 )
Net Cash Provided by Operating Activities $ 121,205 $ 79,667
Net Cash Used in Investing Activities $ (169,212 ) $ (86,926 )
Net Cash Provided by Financing Activities $ 47,884 $ 7,158
 
Three Months Ended March 31,
    2011   2010
Contract Drilling Operations Data:  
Rigs Utilized 70.0 50.9
Operating Margins (2) 46% 33%

Operating Profit Before Depreciation (2) ($MM)

$ 45.1 $ 20.0
Oil and Natural Gas Operations Data:
Production:
Oil - MBbls 556 303
Natural Gas Liquids - MBbls 478 377
Natural Gas - MMcf 10,231 10,034
Average Prices:
Oil price per barrel received $ 84.33 $ 67.33
Oil price per barrel received, excluding hedges $ 90.78 $ 75.70
NGLs price per barrel received $ 39.61 $ 42.76
NGLs price per barrel received, excluding hedges $ 40.36 $ 42.76
Natural Gas price per Mcf received $ 4.28 $ 5.95
Natural Gas price per Mcf received, excluding hedges $ 3.85 $ 5.14
Operating Profit Before DD&A (2) ($MM) $ 79.1 $ 74.0
Mid-Stream Operations Data:
Gas Gathering - MMBtu/day 185,730 180,117
Gas Processing - MMBtu/day 86,445 76,513
Liquids Sold – Gallons/day 328,333 253,707

Operating Profit Before Depreciation and Amortization (2) ($MM)

$ 10.7 $ 8.4

(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, general and administrative and interest expense. 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 and our drilling segment’s average daily operating margin before elimination of intercompany drilling rig profit.

Below is a reconciliation of GAAP financial measures to non-GAAP financial measures for the three months ended March 31, 2011 and 2010 and December 31, 2010. 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

 
  March 31,
2011   2010
(In thousands)
Net cash provided by operating activities $ 121,205 $ 79,667
Subtract:
Net change in operating assets and liabilities   (13,492 )   (17,363 )

Cash flow from operations before changes in operating assets and liabilities

$ 134,697   $ 97,030  
 

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

March 31, December 31,
2011   2010   2010
(In thousands)
Contract drilling revenue $ 97,988 $ 60,854 $ 98,465
Contract drilling operating cost   52,844   40,900   53,966
Operating profit from contract drilling 45,144 19,954 44,499
Add:
Elimination of intercompany rig profit   5,044   376   4,440

Operating profit from contract drilling before elimination of intercompany rig profit

50,188 20,330 48,939
Contract drilling operating days   6,214   4,584   6,474

Average daily operating margin before elimination of intercompany rig profit

$ 8,077 $ 4,435 $ 7,559

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 or 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.

Contacts

Unit Corporation
David T. Merrill, 918-493-7700
Chief Financial Officer and Treasurer
www.unitcorp.com

Contacts

Unit Corporation
David T. Merrill, 918-493-7700
Chief Financial Officer and Treasurer
www.unitcorp.com