• Open
  • Day's Change
  • % Change
  • Volume
  • Market Cap

Press Releases

Continental Resources' First Quarter 2011 Production Increases 34 Percent Over First Quarter 2010
$268.7 Million in EBITDAX Is 53 Percent Higher than 1Q10
Company Solidly on Track to Achieve 2011 and Five-Year Growth Goals
PR Newswire
ENID, Okla.

ENID, Okla., May 4, 2011 /PRNewswire/ -- Continental Resources, Inc. (NYSE: CLR) reported strong production and EBITDAX growth for the quarter ended March 31, 2011.

(Logo: http://photos.prnewswire.com/prnh/20080505/LAM014LOGO)

Continental produced 51,663 barrels of oil equivalent per day (Boepd) for the first quarter of 2011, a 34 percent increase over production of 38,428 Boepd for the first quarter of 2010 and an eight percent increase over fourth quarter 2010 production of 48,034 Boepd.

The Company reported EBITDAX of $268.7 million for the first quarter of 2011, a 53 percent increase over EBITDAX of $175.6 million for the first quarter of 2010 and a 22 percent increase over EBITDAX for the fourth quarter of 2010 of $220.9 million. For the Company's definition and reconciliation of EBITDAX to net income, see "Non-GAAP Financial Measures" at the end of this press release.

"Production growth continues to trend higher in the second quarter, and we are solidly on track to achieve our 2011 target of 35-to-37 percent growth," said Harold Hamm, Chairman and Chief Executive Officer. "We've made substantial progress in the past 16 months toward achieving our goal of tripling production and proved reserves from year-end 2009 to year-end 2014."

During the first quarter of 2011, Continental announced plans to move its headquarters to Oklahoma City in 2012. "We've enjoyed extraordinary growth in Enid, but we are accelerating so quickly now that the move to Oklahoma City was the natural next step," Mr. Hamm said.

For the first quarter of 2011, the Company reported a net loss of $137.2 million, or $0.80 per diluted share, compared with net income for the first quarter of 2010 of $72.5 million, or $0.43 per diluted share.

The first quarter net loss reflected a $369.3 million loss on mark-to-market derivative instruments, 99 percent of which was non-cash and unrealized. It consisted of a $364.1 million unrealized loss and a $5.2 million realized loss. The unrealized mark-to-market loss relates to derivative instruments covering the period from the current date through year-end 2013. Over this 32-month period, actual realized derivative settlements may differ significantly from the unrealized mark-to-market valuation at March 31, 2011.

Company earnings were reduced by $1.33 per share on an after-tax basis by the combined impact of the non-cash, unrealized derivatives loss and a small property impairment loss, offset partially by a small gain on sale of assets.

"As our growth rate has accelerated, we've layered in derivatives to limit the potential volatility of cash flow that will support our growth," Mr. Hamm said. "We have exceptionally valuable assets in place, including our tremendous acreage position in the Bakken and other crude oil and liquids-rich gas assets. With consistently increasing cash flow, we are well-positioned to accomplish our long-term growth and value-creation plan."

Crude oil and natural gas sales were $326.5 million for the first quarter of 2011, a 50 percent increase over sales of $217.1 million for the first quarter of 2010.

Crude oil accounted for 74 percent of Continental's first quarter 2011 production. Continental's average realized crude oil price was $85.34 per barrel in the first quarter of 2011, while the average realized natural gas price was $5.09 per Mcf, yielding a blended realized price of $71.14 per Boe. In the first quarter of 2010, the Company realized a blended price of $62.07 per Boe.

The Company's crude oil price differential for the first quarter of 2011 was $9.21 per barrel, and its natural gas price differential was a premium of $1.00 per Mcf, reflecting the high liquids content in Anadarko Woodford natural gas.

During the first quarter of 2011, Continental participated in completing 92 gross (31.1 net) wells and invested $412.8 million in capital expenditures. Of this amount, 80 percent was invested in exploration and development drilling.

As of March 31, 2011, the Company's balance sheet included $477.4 million in cash and $896.1 million in long-term debt. The Company's high cash balance reflected its successful offering of 10.1 million shares of common stock at $68 per share ($65.45 per share, net of underwriting discount) just prior to the end of the first quarter of 2011.

Operating Highlights

Three months ended March 31,



Average daily production:

Crude oil (Bbl per day)



Natural gas (Mcf per day)



Crude oil equivalents (Boe per day)



Average sales prices: (1)

Crude oil ($/Bbl)





Natural gas ($/Mcf)



Crude oil equivalents ($/Boe)



Production expenses ($/Boe) (1)



General and administrative expenses ($/Boe) (1) (2)



Net income (loss) (in thousands)



Diluted net income (loss) per share



EBITDAX (in thousands) (3)



(1)  Average sales prices and per unit expenses have been calculated using sales volumes and exclude any effect of derivative transactions.

(2)  General and administrative expense ($/Boe) includes non-cash equity compensation expense of $0.79 per Boe and $0.82 per Boe for the three months ended March 31, 2011 and 2010, respectively.

(3)  EBITDAX represents earnings before interest expense, income taxes, depreciation, depletion, amortization and accretion, property impairments, exploration expenses, unrealized derivative gains and losses and non-cash equity compensation expense. EBITDAX is not a measure of net income or cash flows as determined by U.S. GAAP. A reconciliation of net income to EBITDAX is provided subsequently under the header Non-GAAP Financial Measures.

The following table presents the Company's average daily production by region for the periods presented.

Average Daily Production by Region




Boe per day




North Region:

North Dakota Bakken




Montana Bakken




Red River Units








South Region:

Anadarko Woodford




Arkoma Woodford








East Region








Bakken Production Continues to Increase

Continental's total Bakken production in North Dakota and Montana increased to 25,523 Boepd in the first quarter of 2011, 67 percent higher than the first quarter last year and 13 percent higher than production in the fourth quarter of 2010. During the first quarter of 2011, Continental participated in completing 58 gross (19.4 net) producing wells in the Bakken. This does not include wells drilled, but not yet completed.

Continental operated the completion of 25 gross (15.7 net) wells in the North Dakota and Montana Bakken, with an average initial production rate of 1,048 Boepd in their single-day test periods in the first quarter of 2011.

Continental continues to restrict initial production rates on many wells in North Dakota to minimize natural gas flaring and to deliver as much of the rich gas as possible to market. "Some wells have initial flowing tubing pressures of more than 3,000 psi for several days, so they could easily have tested at double or more their announced rates, if we had opened them up," Mr. Hamm said.

Notable Company-operated wells in North Dakota (with initial test period gross production results) included:

  • Bud 1-19H (70% WI) in Williams Co. – 1,984 Boepd;
  • Seattle 1-35H (38% WI) in McKenzie Co. – 1,883 Boepd;
  • Ivan 1-29H (42% WI) in McKenzie Co. – 1,619 Boepd;
  • Gronfur 1-28H (57% WI) in Williams Co. – 1,589 Boepd;
  • Norway 1-5H (38% WI) in McKenzie Co. – 1,435 Boepd;
  • Buelingo 1-20H (52% WI) in McKenzie Co. – 1,417 Boepd;
  • Missoula 1-21H (94% WI) in McKenzie Co. – 1,403 Boepd;
  • Hartford 1-19H (85% WI) in Williams Co. – 1,396 Boepd;
  • Kleist 1-35H (67% WI) in Divide Co. – 1,181 Boepd;
  • Daniel 1-33H (43% WI) in Divide Co. – 1,179 Boepd;
  • He 1-20H (41% WI) in McKenzie Co. – 1,117 Boepd;
  • Barney 1-29H (71% WI) in Williams Co. – 1,047 Boepd.

"We are seeing continued improvement in initial well productivity," Mr. Hamm said. "In addition, six of our eight best wells in the first quarter were in the Williston Prospect, west of the Nesson Anticline, which is basically an exploratory drilling area for us. Quite a bit of our acreage in this area was acquired in the past 15 months." The Bud, Seattle, Gronfur, Buelingo, Missoula, Hartford and Barney wells are located in the Williston Prospect, where Continental has leased approximately 110,000 net acres.

Just this week, Continental tested an additional well in the Williston Prospect, the Akron 1-27H (57% WI) in McKenzie County. The Akron 1-27H had an initial production test rate of 1,407 Boepd, flowing at 3,600 psi on a 16/64” choke. The well targeted the Middle Bakken zone and was completed with 24 stages.

The Company drilled several multi-well ECO-Pad® projects in the first quarter of 2011 that are expected to be completed in the second quarter of 2011. This design allows four wells (two Middle Bakken, two Three Forks) to be drilled on two adjoining 1,280-acre spacing units from a single pad. The ECO-Pad approach increases recoveries per well and reduces drilling costs, completion costs and environmental impact.

In the Montana Bakken, notable Company-operated wells completed in the first quarter of 2011, with initial test period gross production results, included:

  • Big Sky 3-35H (95% WI) – 1,163 Boepd;
  • Clayton 3-20H (71% WI) – 1,118 Boepd;
  • Amestoy 1-6H (71% WI) – 836 Boepd.

The Big Sky and Clayton wells were the Company's two strongest Montana Bakken completions in recent years, drilled as 320-acre in-fill wells in the fairway of the Elm Coulee Field. Continental is testing several variations on its standard 24-stage, perf-and-plug frac design for well completions in the Bakken. The Big Sky 3-35H was completed with 18 stages using a sliding-sleeve frac system.

"These two were significantly superior to adjacent wells that we had completed in past years with the old open-hole frac technology that was once standard in Elm Coulee," Mr. Hamm said.

At March 31, 2011, Continental had a total of 868,900 net acres leased in the Bakken play. The Company currently has 22 operated drilling rigs in North Dakota and two in Montana.

Oklahoma Woodford Production Continues to Grow

Production in the Anadarko Woodford play in western Oklahoma was 2,685 Boepd in the first quarter of 2011, an increase of 190 percent over the first quarter of 2010 and 57 percent higher than the fourth quarter last year.

The Company participated in 26 gross (6.1 net) wells during the quarter and operated 5 gross (3.8 net) well completions.

Notable Company-operated wells in the Northwest Cana portion of the play completed since January 1, 2011 (with initial test period gross production results) included:

  • Wray 1-1H (46% WI) in Blaine Co. (April 2011) – 6.2 MMcfpd;
  • Helzer 1-35H (84% WI) in Dewey Co. –  5.4 MMcfpd and 57 Bopd;
  • Carter 1-15H (41% WI) in Dewey Co. – 3.2 MMcfpd and 163 Bopd;
  • Duggan 1-3H (59% WI) in Blaine Co. – 2.5 MMcfpd and 137 Bopd.

"Initial production results are improving, and drilling times are trending positively, as well," Mr. Hamm said. "The Helzer 1-35H was Continental's most productive Dewey County test to date.

"We completed the Wray 1-1H in Blaine County early in the second quarter of 2011," he said. "It had the highest test rate of any Company-operated well in the Anadarko Woodford since the Young 2-22H in September 2009. In addition, we drilled the Wray to total depth in a record 51 days." He noted that the Company's new wells in the Northwest Cana are commonly tested at restricted rates, due to insufficient compression capacity being available to handle the high initial volumes of natural gas production. The Wray 1-1H was on a larger capacity system.

"Finally, in April 2011 we finished drilling one of our Dewey County Woodford wells in record time. The Trook 1-1H (66% WI) reached total depth in a total of 42 days, drilling 1,200 feet of lateral in a single day." The Trook is scheduled for completion in the current quarter.

In the Southeast Cana, the Company has just begun completing the Lambakis 1-11H (98% WI) in Grady Co. The Lambakis is 24 miles southeast of the nearest previous Southeast Cana completion.

The Oklahoma legislature recently approved a bill that will allow cross-unit spacing in the state. Cross-unit spacing will allow operators to combine two 640-acre units and drill longer laterals, which Continental believes will significantly benefit Anadarko Woodford well economics. Continental hopes to drill its first 1,280-spaced well later this year, using the new rules that will be provided under the law.

Continental is currently participating in the acquisition of approximately 500 square miles of 3-D seismic to facilitate drilling and development of its Northwest Cana and Southeast Cana projects.

In the Arkoma Woodford play of eastern Oklahoma, the Company's production was 4,065 Boepd in the first quarter of 2011, an increase of 17 percent over production of 3,481 in the first quarter of 2010. The increase reflected drilling activity in the East Krebs portion of the Arkoma Woodford in the past year. The Company currently has one operated rig active in the area.

At March 31, 2011, the Company had 324,000 net acres leased in the Oklahoma Woodford, of which 270,000 net acres are in the Anadarko Woodford. The Company currently has 10 operated rigs in the Anadarko Woodford.

Red River Units (Montana, North Dakota and South Dakota)

The Company's production in the Red River Units averaged 14,066 Boepd in the first quarter of 2011, slightly above production in the fourth and first quarters of 2010. Continental has been upgrading its air-injection systems in the Buffalo and Medicine Pole Hills units to increase air injection volumes, which is expected to extend current levels of production in the Red River Units.

Continental currently has one operated rig active in the Units, completing its increased density drilling pattern in the water-flood secondary recovery project.

Niobrara Play (Colorado and Wyoming)

Continental drilled and fracture stimulated the Newton 1-4H (89% WI) located in Weld County, Colorado, and is currently in the early stages of recovering frac fluid in the well. The Newton 1-4H is the first 1,280-acre spaced well in the Niobrara play, where the Company plans to drill an additional five gross (3.3 net) wells by year-end. Continental currently has 83,100 net acres leased in DJ Basin-Niobrara.

Conference Call Information

Continental Resources plans to host its first quarter 2011 earnings conference call on Thursday, May 5, 2011 at 10 a.m. ET to discuss its results for the quarter. Those wishing to listen to the conference call may do so via the Company's web site at www.contres.com or by phone:

Time and date:

10 a.m. ET

Thursday, May 5, 2011

Dial in:

(888) 679-8034

Intl. dial in:

(617) 213-4847

Pass code:


A replay of the call will be available later for 30 days on the Company's web site or by dialing:

Replay number:

(888) 286-8010

Intl. replay

(617) 801-6888

Pass code:


Conference Presentations

Continental management is currently scheduled to present at the following research conferences. Presentation materials will be available on the Company's web site on the day of the presentation.

May 12

Platt's 4th Annual Midstream Development & Management Conference, Houston

May 24

UBS 10th Annual Global Oil and Gas Conference, Austin

May 24

Hart's Oil Prone Shales DUO Conference, Denver

June 7

RBC Capital Markets 2011 Global Energy & Power Conference, New York

Continental Resources is a crude-oil concentrated, independent oil and natural gas exploration and production company. The Company focuses its operations in large new and developing plays where horizontal drilling, advanced fracture stimulation and enhanced recovery technologies provide the means to economically develop and produce oil and natural gas reserves in U.S. resource plays.

Forward-Looking Statements

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. Other than historical facts included in this press release, all information 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, changes in estimates of projected crude oil and natural gas recoveries from certain fields, 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, changes in regulatory constraints, and other factors listed in reports we have filed or may file with the Securities and Exchange Commission. The Company undertakes no obligation to publicly update any forward-looking statement to reflect events or circumstances that may arise after the date of this press release.


Investor Relations


Warren Henry, VP Investor Relations

Brian Engel, VP Public Affairs

(580) 548-5127

(405) 605-0784

Unaudited Condensed Consolidated Statements of Operations

Three months ended March 31,




In thousands, except per share data

Crude oil and natural gas sales





Gain (loss) on derivative instruments, net



Crude oil and natural gas service operations



Total revenues



Operating costs and expenses:

Production expenses



Production taxes and other expenses



Exploration expenses



Crude oil and natural gas service operations



Depreciation, depletion, amortization and accretion



Property impairments



General and administrative expenses



Gain on sale of assets



Total operating costs and expenses



Income (loss) from operations



Other income (expense):

Interest expense








Income (loss) before income taxes



Provision (benefit) for income taxes



Net income (loss)





Basic net income (loss) per share





Diluted net income (loss) per share





Unaudited Condensed Consolidated Balance Sheets

March 31,

December 31,




In thousands

Current assets





Net property and equipment



Debt issuance costs and other assets



Total assets





Liabilities and shareholders' equity

Current liabilities





Long-term debt



Other noncurrent liabilities



Total shareholders' equity



Total liabilities and shareholders' equity





Unaudited Condensed Consolidated Statements of Cash Flows

Three months ended March 31,



In thousands

Net income (loss)





Adjustments to reconcile net income (loss) to net cash provided by operating activities:

Non-cash expenses



Changes in assets and liabilities



Net cash provided by operating activities



Net cash used in investing activities



Net cash provided by (used in) financing activities



Net change in cash and cash equivalents



Cash and cash equivalents at beginning of period



Cash and cash equivalents at end of period





Non-GAAP Financial Measures

EBITDAX represents earnings before interest expense, income taxes, depreciation, depletion, amortization and accretion, property impairments, exploration expenses, unrealized derivative gains and losses, and non-cash equity compensation expense. EBITDAX is not a measure of net income or cash flows as determined by U.S. GAAP. Management believes EBITDAX is useful because it allows them to more effectively evaluate our operating performance and compare the results of our operations from period to period without regard to our financing methods or capital structure. We exclude the items listed above from net income in arriving at EBITDAX because these amounts can vary substantially from company to company within our industry depending upon accounting methods and book values of assets, capital structures and the method by which the assets were acquired. EBITDAX should not be considered as an alternative to, or more meaningful than, net income or cash flows as determined in accordance with U.S. 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. Our computations of EBITDAX may not be comparable to other similarly titled measures of other companies. We believe that EBITDAX is a widely followed measure of operating performance and may also be used by investors to measure our ability to meet future debt service requirements, if any. Our revolving credit facility requires that we maintain a total debt to EBITDAX ratio of no greater than 3.75 to 1.0 on a rolling four-quarter basis. Our revolving credit facility defines EBITDAX consistently with the definition of EBITDAX utilized and presented by us. The following table is a reconciliation of our net income to EBITDAX.

Three months ended March 31,



in thousands

Net income (loss)





Interest expense



Provision (benefit) for income taxes



Depreciation, depletion, amortization and accretion



Property impairments



Exploration expenses



Unrealized losses (gains) on derivatives



Non-cash equity compensation








SOURCE Continental Resources