EX-99.1 2 dex991.htm PRESS RELEASE Press release

Exhibit 99.1

RELEASE: THURSDAY, FEB. 26

CONTINENTAL RESOURCES ENDS 2008 WITH STRONG PRODUCTION AND RESERVE GROWTH

2009 Capital Expenditure Budget Reduced in Line with Cash Flow Outlook

ENID, Okla., February 26, 2009 /PRNewswire-FirstCall/ — Continental Resources, Inc. (NYSE: CLR) today reported continued strong growth in production in the fourth quarter ended December 31, 2008, compared with the third quarter of 2008 and the fourth quarter last year. In addition, the Company reported year-end 2008 proved reserves of 159.3 MMboe, an 18 percent increase over the 134.6 MMboe reported at year-end 2007. Combined drilling and proved undeveloped (PUDs) additions of 47.6 MMboe were almost 400 percent of Continental’s total production of 12.0 MMboe for 2008.

Despite challenging economics in the final quarter of 2008, Continental completed a record year for net income and cash flow growth. Net income increased 74 percent to $321.0 million and EBITDAX increased 61 percent to $757.7 million, compared with full-year 2007 results. For the Company’s definition and reconciliation of EBITDAX to Generally Accepted Accounting Principles, see “Non-GAAP Financial Measures” at the end of this press release. Net income for 2007 is pro forma for income taxes as if the Company had been a subchapter C corporation prior to its initial public offering in May 2007.

For the fourth quarter ended December 31, 2008, the Company reported net income of $416,000, or $0.00 per diluted share, compared with net income of $60.9 million, or $0.36 per diluted share, for the fourth quarter of 2007. Falling commodity prices reduced fourth quarter revenue and earnings compared to the fourth quarter of 2007.

For the fourth quarter of 2008, Continental achieved total production of 36,018 boepd, an eight percent increase over the third quarter of 2008 and a 19 percent increase over the fourth quarter last year. The Company exited the fourth quarter with average production of 37,954 boepd for December 2008, an increase of 27 percent over December 2007. Production growth strengthened despite the Company significantly scaling back its drilling program as commodity prices declined in the fourth quarter of 2008. Continental has reduced its operated drilling rig count from 32 in early October to seven rigs currently and plans to drop additional rigs as drilling contracts expire later in 2009.

With energy prices remaining low, Continental plans to reduce capital expenditures to preserve capital and the value of its assets. “Our first priority is the integrity of our balance sheet,” said Harold Hamm, Chairman and Chief Executive Officer. “We plan to restrain spending until we see commodity prices begin to recover. We remain committed to financing our growth with cash flow and will not use debt to fund a high level of drilling activity, especially in an environment of low energy prices.”

“I’m proud that we achieved our operating goals for 2008, finishing the year with strong fourth quarter production growth and increased reserves,” he said. “The Company’s accomplishments are a strong indicator of the value of our assets and our ability to accelerate growth when the economy and industry conditions rebound.”

The Company has revised its 2009 capital expenditures budget to $275 million, which includes $211 million for drilling and related activities and $58 million for land and seismic, and $6 million for other capital needs. Based on the new budget, 2009 production is expected to be in a range of 12.5 MMboe to 13.0 MMboe, which would constitute growth of up to eight percent over 2008. Under this revised capex budget, Continental expects to average approximately five operated drilling rigs during the year.

Oil and natural gas sales were $130.7 million for the fourth quarter of 2008, compared with oil and gas sales of $183.8 million for the fourth quarter of 2007. The Company’s average sales price per barrel of crude oil equivalent was $38.80 for the fourth quarter of 2008, compared with $68.84 for the fourth quarter of 2007.

Crude oil price differentials averaged $14.45 per barrel for the fourth quarter of 2008 and $9.50 for 2008 as a whole. This compares with $13.05 per barrel in the fourth quarter of 2007 and $8.85 per barrel for the full year. Continental noted that the differential has been improving in the first quarter of 2009.

EBITDAX for the fourth quarter of 2008 was $92.7 million, compared with EBITDAX of $137.4 million for the fourth quarter of 2007.

At December 31, 2008, the Company’s balance sheet included $5.2 million in cash and $376.4 million in long-term debt. Commitments under the Company’s revolving credit facility were recently increased to $672.5 million, compared with $552.5 million at December 31, 2008 and $400.0 million at September 30, 2008. With debt outstanding currently of $474.4 million, the Company has $198.1 million in availability under its revolving credit facility.

Increased Reserves

Continental’s 2008 reserves growth was primarily the result of increased drilling activity in the North Dakota Bakken and in Oklahoma’s Arkoma Woodford in the first nine months of the year.

The Company increased its proved reserves by 24.6 MMboe to a total of 159.3 MMboe. Total proved reserve additions were comprised of 12.7 MMboe in drilling additions, 35.0 MMboe of PUD reserve additions, and 2.2 MMboe in acquisitions. Additions were offset by 13.3 MMboe in downward revisions, of which 64 percent were related to low energy prices at year-end 2008.

Future net cash flows from the year-end 2008 proved reserves, before income taxes, were $3.1 billion, with a present value discounted at 10 percent (PV10) of $1.5 billion. In terms of crude oil/natural gas mix, crude oil reserves were 106.2 million barrels, or 67 percent, of total proved reserves at year-end 2008. Proved developed reserves represented 67 percent of total reserves at year-end 2008.

Operations Update

The following table contains financial and operating highlights for the three months and year ended December 31, 2008 compared to the same periods in 2007.

     Three months ended December 31,    Year ended December 31,
     2008    2007    2008    2007

Average daily production:

            

Oil (Bopd)

      26,857      24,309      24,993      23,832

Natural gas (Mcfd)

      54,963      36,362      46,861      31,599

Oil equivalents (Boepd)

      36,018      30,369      32,803      29,099

Average prices: (1)

            

Oil ($/Bbl)

    $ 43.89    $ 77.53    $ 88.87    $ 63.55

Natural gas ($/Mcf)

      3.93      5.99      6.90      5.87

Oil equivalents ($/Boe)

      38.80      68.84      77.66      58.31

Production expense ($/Boe) (1)

      7.83      6.85      8.40      7.35

EBITDAX (in thousands)

      92,680      137,412      757,708      469,885

Net income (in thousands) (2)

      416      60,892      320,950      184,002

Diluted net income per share

      0.00      0.36      1.89      1.11

 

(1)

Average prices and per-unit production expense are calculated based on sales volumes. Crude oil sales volumes exceeded production in the fourth quarter and full-year 2008 by 54 MBbls and 97 MBbls, respectively. Crude oil production volumes exceeded oil sales in the fourth quarter and full year 2007 by 125 MBbls and 221 MBbls, respectively.

(2)

Net income and diluted net income per share for full-year 2007 are after pro forma adjustments (i) to provide for income taxes as if the Company had been a subchapter C corporation prior to the completion of its initial public offering, and (ii) to eliminate the $198.4 million charge recorded to recognize deferred taxes upon its conversion from a nontaxable subchapter S corporation to a taxable subchapter C corporation in conjunction with the Company’s May 2007 initial public offering.

The following table presents average daily production for the Company’s principal operating areas for the quarters ended December 31, 2008, September 30, 2008 and December 31, 2007.

 

(boe per day)    Q4 2008    Q3 2008    Q4 2007

Red River Units

    14,058    13,375    14,374

Montana Bakken

    6,410    6,187    7,244

North Dakota Bakken

    4,401    3,444    1,382

Other Rockies

    2,507    2,275    1,600

Arkoma Woodford

    3,276    2,627    1,338

Other Mid-Continent

    4,751    4,895    3,767

Gulf Coast

    615    494    664
              

Total

    36,018    33,297    30,369

Production growth continued to accelerate in the North Dakota Bakken and the Arkoma Woodford plays in the fourth quarter of 2008. Based on capital expenditure re-allocations and its revised 2009 budget, production in the Red River Units is expected to be flat or to decline slightly through the first nine months of 2009, then resume growing in the fourth quarter. Continental expects to generate most of its 2009 production growth in the North Dakota Bakken and the Arkoma Woodford plays.

Red River Units

Production in the Red River Units was 14,058 boepd in the fourth quarter of 2008, accounting for 39 percent of Continental’s production in the quarter. This was a five percent increase over the third quarter of 2008, but down slightly from the fourth quarter last year.

The Units accounted for 37 percent of year-end 2008 proved reserves, compared with 50 percent of reserves at the end of 2007.

During fourth quarter 2008, the Company continued to convert producer wells to injectors and to expand its secondary recovery program, but the pace of the secondary recovery program was considerably reduced in November and December.

The Company currently has one operated rig drilling in the Units. Under the revised 2009 capital expenditures budget, Continental has allocated $46 million to the Units, with plans to drill four producer wells, two disposal wells, a sixth water supply well, and converting producer and air injector wells to water injectors.

As noted above, production is expected to resume growing in the Red River Units in late 2009. The Company does not expect changes in the timing of capex funding to reduce total production or ultimate reserve recovery in the Units. The Company expects production to peak at just over 17,000 boepd in the Units in 2010.

Bakken Shale

Production in the Bakken Shale of North Dakota and Montana was 10,811 boepd in the fourth quarter of 2008, or 30 percent of Continental’s production in the quarter. This was a 12 percent increase over the third quarter of 2008 and a 25 percent increase over production for the fourth quarter last year.

Total proved reserves in the Bakken were 45.7 MMboe at December 31, 2008, or 29 percent of the Company’s year-end 2008 reserves. This constituted an increase of 38 percent over proved reserves of 33.2 MMboe in the Bakken Shale at December 31, 2007.

In the North Dakota part of the Bakken play, total proved reserves were 17.5 MMboe at December 31, 2008, or 11 percent of the Company’s total year-end 2008 reserves. This represented growth of 187 percent over reserves of 6.1 MMboe in the North Dakota Bakken at December 31, 2007.

The Company currently has four operated rigs drilling in North Dakota and none in Montana, compared with 10 rigs in North Dakota and three in Montana at the beginning of the fourth quarter of 2008.

During the fourth quarter, Continental participated in the completion of 33 gross wells (8.9 net) in North Dakota. These wells had an average rate of 546 boepd during their seven-day production period tests. All initial production period test results in this press release are seven consecutive day averages.

Since the beginning of the fourth quarter of 2008, notable completions of Company-operated wells targeting the Three Forks/Sanish (TFS) formation in North Dakota are shown below with average production period test results in gross barrels:

 

  •  

Morris 1-23H (29% WI) in Dunn Co. – 1,185 boepd;

 

  •  

Blegen 1-13H (26% WI) in McKenzie Co. – 1,028 boepd;

 

  •  

Mittelstadt 1-20H (44% WI) in Dunn Co. – 998 boepd;

 

  •  

Skachenko 1-31H (34% WI) in Dunn Co. – 809 boepd;

 

  •  

Hamlet 1-11H (39% WI) in Williams Co. – 450 boepd;

 

  •  

Glasoe 1-18H (45% WI) in Divide Co. – 441 boepd;

 

  •  

Arvid 1-34H (42% WI) in Divide Co. – 340 boepd;

 

  •  

Elveida 1-33H (46% WI) in Divide Co. – 302 boepd.

Notable recent well completions in North Dakota targeting the Middle Bakken formation include:

 

  •  

Malcolm 1-29H (45% WI) in Williams Co. – 693 boepd;

 

  •  

Shonna 1-15H (44% WI) in Divide Co. – 436 boepd;

 

  •  

Marlene 1-10H (53% WI) in Williams Co. – 427 boepd;

 

  •  

Viola 1-7H (54% WI) in Divide Co. – 391 boepd.

In the Montana Bakken, the Company continued to implement its 320-acre infield and field-extension program in the fourth quarter of 2008.

Notable completions in Richland County, MT in the fourth quarter of 2008 included the Prevost 3-16H (83% WI), which had a production period test rate of 507 boepd, and the Rita 3-19H (79% WI), which had production period test rate of 412 boepd. Production results have continued to improve in Richland County as the Company implemented multi-stage fracture stimulation technology that it developed in North Dakota.

Continental recently completed its first Montana TFS test well, the Joann 1-32H (89% WI), in Richland County. The well exhibited poor oil shows and reservoir rock quality during drilling, and in its initial production test period yielded an average 60 boepd.

The Company has commenced a pilot carbon dioxide injection project to evaluate the potential for enhanced recovery of oil in the Elm Coulee field. Utilizing the huff-and-puff technique, carbon dioxide was injected in January and will continue to be injected through March. After letting the carbon dioxide soak in for approximately 30 days, the carbon dioxide and associated fluids will be flowed back and analyzed for performance and economics.

Under its revised 2009 capital expenditures budget, Continental has allocated $72 million to drilling-related activity in North Dakota and $7 million to Montana. Another $36 million in land and seismic capex was allocated for the Bakken play in the two states, primarily to extend leases in the play.

Continental plans to participate in 86 gross wells (20.2 net) in North Dakota and no new wells in Montana in 2009. Drilling activity in North Dakota will focus on the Three Forks/Sanish formation.

Arkoma Woodford

Production in the Arkoma Woodford shale play in southeast Oklahoma was 3,276 boepd in the fourth quarter of 2008, accounting for 9 percent of Continental’s production in the period. This was a 25 percent increase over the third quarter of 2008, and was more than double production for the fourth quarter last year.

Total proved reserves in the Arkoma Woodford were 30.7 MMboe at December 31, 2008, or 19 percent of the Company’s year-end 2008 reserves. This represented growth of 245 percent over reserves of 8.9 MMboe in the Arkoma Woodford at December 31, 2007.

During the fourth quarter of 2008, Continental continued to develop its simultaneous fracture stimulation technology in the Arkoma Woodford, most notably with the Pasquali, Luna-Pratt and Wilson simul-fracs in the Ashland development section of the play.

After the simul-frac, the seven Pasquali wells flowed at an average 2,440 Mcfpd during their production period test, with the most prolific well flowing at 3,599 Mcfpd. The six Luna-Pratt wells flowed at an average 3,761 Mcfpd, with the most prolific flowing at 4,576 Mcfpd. The two wells in the Wilson simul-frac flowed at 8,569 Mcfpd and 5,982 Mcfpd, for an average rate of 7,276 Mcfpd.

The Company currently has one operated rig drilling in the Arkoma Woodford, compared to six rigs at the beginning of the fourth quarter of 2008. Under its revised 2009 capital expenditures budget, Continental has allocated $56 million to drilling-related activity in the play, as well as $7 million in land and seismic capex. In 2009, the Company plans to participate in 63 gross wells (8.0 net) in the Arkoma Woodford.

Emerging Plays

In the Anadarko Woodford shale of western Oklahoma, Continental is currently completing two test wells, the Brown 1-2H (100% WI) in Dewey Co. and the McCalla 1-11H (90% WI) in Grady Co.

In Ellis County, OK, the Company completed its initial test well in the Atoka shale play, the Shrewder 1-22H (100% WI), which flowed at 1.3 MMcfpd from a short, 1,300-foot lateral. The Jones-Trust 1-168H (100% WI), completed in Lipscomb Co., TX in the western part of the play, flowed at 700 Mcf per day in its initial production period test.

The Company currently has no operated rig drillings in the Anadarko Woodford or the Atoka, compared to one in each play at the beginning of the fourth quarter of 2008. Under its revised 2009 capital expenditures budget, Continental has allocated $12 million to drilling-related activity in its emerging plays, as well as $6 million in land and seismic. In 2009, the Company plans to participate in six gross wells (1.8 net) in its emerging plays.

Capital Budget and Guidance

Continental’s regional allocations of capital expenditures in 2009 are listed below. Operational capex includes drilling, work-over and facilities capital expenditures.

     2009 Capex Budget
(in millions)		    Net Wells

North Dakota Bakken

    $ 72    20.2

Arkoma Woodford

      56    8.0

Red River Units

      46    3.8

Emerging plays

      12    1.8

Montana Bakken

      7    0.0

Other

      18    3.9
           

Operational capex

      211    37.7

Land and seismic

      58   

Other capital expenditures

      6   
         

Total capex

    $ 275   

Continental announced its previously issued operating and financial guidance for 2009 has been revised and is as follows. As forward-looking information, this guidance is subject to a variety of risks and uncertainties, including adjustments related to fluctuations in commodity prices. Risk factors are discussed further at the end of this press release and in the Company’s filings with the Securities and Exchange Commission.

 

     Year Ended
December 31, 2009

Production volumes:

   

Oil (MMbls)

    8.8 - 9.1

Gas (MMcf)

    22.5 - 23.4

Oil equivalent (MMboe)

    12.5 - 13.0

Price differentials(1) :

   

Oil (Bbl)

    $8.00 - $10.00

Gas (Mcf)

    $1.50 - $2.25

Operating expenses:

   

Production expense (per boe)

    $7.75 - $8.50

Production tax (percent of sales)

    6.25% - 6.75%

Depreciation, depletion, amortization and accretion (per boe)

    $15.00 - $18.00

General and administrative expense (per boe)(2)

    $1.75 - $2.25

Non-cash stock-based compensation (per boe)

    $0.70 - $1.00

Income tax rate (percent of pre-tax income)

    38%

Percent of income tax deferred

    90%

 

(1)

Differential to calendar month average NYMEX futures price for oil and to average of last three trading days of prompt NYMEX futures contract for gas.

(2)

Excludes non-cash stock-based compensation.

Conference Call Information

Continental Resources will host a conference call on Thursday, Feb. 26, 2009, at 10:00 a.m. ET (9 a.m. CT) to discuss its fourth quarter 2008 results. Interested parties may listen to the conference call via the Company’s website at http://www.contres.com or by phone:

 

Dial in:    (888) 713-4217
Intl. dial in:    (617) 213-4869
Pass code:    65130417
Replay number:    (888) 286-8010
Intl. replay:    (617) 801-6888
Pass code:    18971146

Conference Presentations

Continental management is currently scheduled to present at the Raymond James & Associates 30th Annual Institutional Investors Conference in Orlando (March 8-11, 2009) and at the Howard Weil 37th Annual Energy Conference in New Orleans (March 22-26, 2009).

Continental Resources is a crude-oil concentrated, independent oil and natural gas exploration and production company with operations in the Rocky Mountain, Mid-Continent and Gulf Coast regions of the United States. The Company focuses its operations in large new and developing resource plays where horizontal drilling, advanced fracture stimulation and enhanced recovery technologies provide the means to economically develop and produce oil and natural gas reserves from unconventional formations.

This press release includes forward-looking information that is subject to a number of risks and uncertainties, many of which are beyond the Company’s control. All information, other than historical facts included in this press release, regarding strategy, future operations, drilling plans, estimated reserves, future production, estimated capital expenditures, projected costs, the potential of drilling prospects and other plans and objectives of management are forward-looking information. All forward-looking statements speak only as of the date of this press release. Although the Company believes that the plans, intentions and expectations reflected in or suggested by the forward-looking statements are reasonable, there is no assurance that these plans, intentions or expectations will be achieved. Actual results may differ materially from those anticipated due to many factors, including oil and natural gas prices, industry conditions, drilling results, uncertainties in estimating reserves, uncertainties in estimating future production from enhanced recovery operations, availability of drilling rigs and other services, availability of crude oil and natural gas transportation capacity, availability of capital resources and other factors listed in reports we have filed or may file with the Securities and Exchange Commission.

CONTACT: Continental Resources, Inc.

 

J. Warren Henry    Brian Engel
Investors    Media
(580) 548-5127    (580) 249-4731

Condensed Consolidated Statements of Income

(in thousands, except share data)

    Three months ended
December 31,		     Year ended
December 31,		  
   2008     2007     2008     2007  

Revenues:

         

Oil and natural gas sales

    $ 130,668     $ 183,780     $ 939,906     $ 606,514  

Loss on mark-to-market derivatives

      —         (30,476 )     (7,966 )     (44,869 )

Oil and natural gas service operations

      5,128       5,690       28,550       20,570  
                                

Total revenues

      135,796       158,994       960,490       582,215  

Operating costs and expenses:

         

Production expense

      26,362       18,288       101,635       76,489  

Production tax

      10,199       10,251       58,610       32,562  

Exploration expense

      13,882       2,499       40,160       9,163  

Oil and gas service operations

      2,391       3,942       18,188       12,709  

Depreciation, depletion, amortization and accretion

      53,074       26,326       148,902       93,632  

Property impairments

      11,227       4,887       28,847       17,879  

General and administrative (1)

      7,907       5,148       35,719       32,802  

Gain on sale of assets

      (488 )     (650 )     (894 )     (988 )
                                

Total operating costs and expenses

      124,554       70,691       431,167       274,248  

Income from operations

      11,242       88,303       529,323       307,967  

Interest expense and other

      (2,743 )     (2,543 )     (10,793 )     (11,190 )
                                

Net income before income tax expense

      8,499       85,760       518,530       296,777  

Income tax expense

      8,083       24,868       197,580       268,197  
                                

Net income

    $ 416     $ 60,892     $ 320,950     $ 28,580  

Basic net income per share

    $ 0.00     $ 0.36     $ 1.91     $ 0.17  

Diluted net income per share

      0.00       0.36       1.89       0.17  

Basic weighted average shares outstanding

      168,335       167,590       168,087       164,059  

Diluted weighted average shares outstanding

      169,231       169,255       169,392       165,422  

 

(1) Includes non-cash charges for stock-based compensation of $2.6 million and $0.7 million for the three months ended December 31, 2008 and 2007, respectively, and $9.1 million and $12.8 million for the years ended December 31, 2008 and 2007, respectively.

Condensed Consolidated Balance Sheets

(in thousands)

    December 31,
2008		    December 31,
2007

Assets:

      

Cash and cash equivalents

    $ 5,229    $ 8,761

Receivables

      229,079      163,090

Inventories and other

      43,387      33,713

Net property and equipment

      1,935,143      1,157,926

Other assets

      3,041      1,683
             

Total assets

    $ 2,215,879    $ 1,365,173
             

Liabilities and shareholders’ equity:

      

Current liabilities

    $ 403,594    $ 266,106

Long-term debt

      376,400      165,000

Other noncurrent liabilities

      487,177      310,935

Shareholders’ equity

      948,708      623,132
             

Total liabilities and shareholders’ equity

    $ 2,215,879    $ 1,365,173

 

Condensed Consolidated Statements of Cash Flows

(in thousands)

    Year ended
December 31,		  
   2008     2007  

Net income

    $ 320,950     $ 28,580  

Adjustments to reconcile net income to net cash provided by operating activities:

     

Non-cash expenses

      363,801       416,977  

Changes in assets and liabilities

      35,164       (54,909 )
                

Net cash provided by operating activities

      719,915       390,648  

Net cash used in investing activities

      (927,617 )     (483,498 )

Net cash provided by financing activities

      204,170       94,568  

Effect of exchange rate on change in cash and cash equivalents

      —         25  
                

Net change in cash and cash equivalents

      (3,532 )     1,743  

Cash and cash equivalents at beginning of period

      8,761       7,018  
                

Cash and cash equivalents at end of period

    $ 5,229     $ 8,761  

Non-GAAP Financial Measures

EBITDAX represents earnings before interest expense, income taxes, depreciation, depletion, amortization and accretion, property impairments, exploration expense, unrealized derivative gains and losses, and non-cash compensation expense. EBITDAX is not a measure of net income or cash flow as determined by generally accepted accounting principles (GAAP). EBITDAX should not be considered as an alternative to, or more meaningful than, net income or cash flow as determined in accordance with GAAP or as an indicator of a Company’s operating performance or liquidity. Certain items excluded from EBITDAX are significant components in understanding and assessing a company’s financial performance, such as a company’s cost of capital and tax structure, as well as the historic costs of depreciable assets, none of which are components of EBITDAX. The Company’s computations of EBITDAX may not be comparable to other similarly titled measures of other companies. The Company believes that EBITDAX is a widely followed measure of operating performance and may also be used by investors to measure its ability to meet future debt service requirements, if any. The Company’s credit facility requires that it maintain a total funded debt to EBITDAX ratio, as defined therein, of no greater than 3.75 to 1 on a rolling four-quarter basis. The credit facility defines EBITDAX consistently with the definition of EBITDAX utilized and presented by the Company. The following table represents a reconciliation of the Company’s net income to EBITDAX.

 

     Three months ended
December 31,		    Year ended
December 31,
(in thousands)    2008    2007    2008    2007
     (unaudited)

Net income

    $ 416    $ 60,892    $ 320,950    $ 28,580

Loss on mark-to-market derivatives

      —        14,160      —        26,703

Income tax expense

      8,083      24,868      197,580      268,197

Interest expense

      3,406      3,085      12,188      12,939

Depreciation, depletion, amortization and accretion

      53,074      26,326      148,902      93,632

Property impairments

      11,227      4,887      28,847      17,879

Exploration expense

      13,882      2,499      40,160      9,163

Equity compensation

      2,592      695      9,081      12,792
                           

EBITDAX

    $ 92,680    $ 137,412    $ 757,708    $ 469,885