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Continental Resources Increases EBITDAX 86 Percent to $411.9 Million for Fourth Quarter of 2011: Full-Year EBITDAX $1.3 Billion
Company Acquires 35,178 Net Acres and Production in the North Dakota Bakken
Toms 1-21XH Cross-Unit Well Producing Oil at a High Rate in the Anadarko Woodford
Company Expects 2012 Production Growth of up to 40 Percent

OKLAHOMA CITY, Feb. 22, 2012 /PRNewswire/ -- Continental Resources, Inc. (NYSE: CLR) reported EBITDAX of $411.9 million for the fourth quarter of 2011, an 86 percent increase over EBITDAX for the fourth quarter of 2010. The Company attributed the EBITDAX growth to strong oil and natural gas production growth.

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

For full-year 2011, the Company generated $1.3 billion in EBITDAX, a 61 percent increase over 2010. For the Company's definition and reconciliation of EBITDAX to net income, see "Non-GAAP Financial Measures" at the end of this press release.

Primarily due to an unrealized mark-to-market loss on derivatives, Continental reported a net loss of $112.1 million, or $0.62 per diluted share, for the fourth quarter of 2011. This included a $399.4 million pre-tax unrealized loss on mark-to-market derivative instruments, a $42.1 million pre-tax property impairment charge and a small pre-tax gain on sale of property. The combined effects of the non-cash, unrealized derivatives loss, property impairment charge and the gain on sale reduced net income by $1.50 per diluted share for the fourth quarter of 2011.

For the fourth quarter of 2010, Continental reported a net loss of $45.0 million, or $0.27 per diluted share.

For full-year 2011, Continental reported net income of $429.1 million, or $2.41 per diluted share. This included a small pre-tax unrealized gain on mark-to-market derivative instruments and a small pre-tax gain on sale of assets, more than offset by a pre-tax charge of $108.5 million for property impairments. The combined effects of the non-cash, unrealized derivatives gain, the gain on sale of assets, and property impairment charge reduced 2011 net income by $0.29 per diluted share.

For 2010, the Company reported net income of $168.3 million, or $0.99 per diluted share.

Continental's production averaged 75,219 Boepd (barrels of oil equivalent per day) for the fourth quarter of 2011, a 57 percent increase over production of 48,034 Boepd for the fourth quarter of 2010. Crude oil accounted for 72 percent of Continental's fourth quarter 2011 total production.

Full-year 2011 production was 22.6 million barrels of oil equivalent (MMBoe), a 43 percent increase over 2010 production of 15.8 MMBoe. Crude oil accounted for 73 percent of Continental's 2011 production.

"As we reported on January 25, 2012, production growth was very strong in late 2011 and in early 2012," said Harold Hamm, Chairman and Chief Executive Officer.

"With this momentum, we now expect to grow production in a range of 37 percent to 40 percent for the year," Mr. Hamm said. This compares to Continental's original 2012 production growth guidance of 26 percent to 28 percent.

"Since we set our 2012 budget in early November, cash flow has benefited from strong oil prices and generally moderate transportation costs. We are also experiencing operating efficiency and productivity gains. Specifically, wells recently completed in extension areas in the Bakken and the Anadarko Woodford, where we previously had little drilling experience, were stronger than expected. We had applied a risking factor in these extension areas, and actual results were instead equal to or better than typical Continental wells in our established areas in the Bakken and Anadarko Woodford."

Continental increased total proved reserves to 508 MMBoe at year-end 2011, as previously announced. This was 39 percent higher than proved reserves of 365 MMBoe for 2010.

Bakken Acreage Acquired

Continental Resources announced the acquisition of 23,161 net acres in Williams County, North Dakota, associated production of approximately 1,000 net Boepd, and eight wells that are drilled but not yet completed. The transaction was completed in February 2012 for $276 million. Continental will act as operator on 89 percent of the newly acquired acreage, most of which is already held by production. In total, the new acreage represents 29 operated spacing units for Continental.

The Company also announced the acquisition of leases covering an additional 12,017 net acres in February 2012.

"These acquisitions are a great fit with our current Bakken position and are 100 percent ready to drill," Mr. Hamm said.

"Our goal is to add to and high-grade our strategic leasehold, concentrating on Bakken acreage where we will have a dominant working interest and operating control. Secondly, we're focused on developing high-liquids areas in the Anadarko Woodford where we can deliver the most attractive returns," he said. "We have opportunities to offset some of this investment by selling non-core assets, including acreage where we have a low working interest. The key driver in this process is growth that maximizes value-creation."

Additional Fourth Quarter 2011 Results

Oil and natural gas sales were $508.3 million for the fourth quarter of 2011, compared with $273.1 million for the same period of 2010.

Continental's average realized crude oil price was $89.24 per barrel in the fourth quarter of 2011, while the average realized natural gas price was $4.97 per Mcf, yielding a blended realized price of $72.60 per Boe. In the fourth quarter of 2010, the Company reported a blended realized price of $61.98 per Boe.

The Company's crude oil price differential was $5.00 per barrel and its natural gas price differential was a premium of $1.41 per Mcf for the fourth quarter of 2011, due to the liquids content of the gas.

Production expense was $5.73 per Boe for the fourth quarter of 2011, compared with $5.31 per Boe for the fourth quarter of 2010. General and administrative expense was $3.02 per Boe, compared with $3.09 per Boe for the fourth quarter of 2010.

To support consistent production growth and its capital program, Continental placed derivative financial instruments (price swaps and collars) representing approximately 16 million barrels of oil (MMBo) in 2012 and 15 MMBo in 2013. The Company also placed natural gas derivative financial price swaps representing 8,850,000 million Btus (MMBtus) in 2012 and 7,300,000 MMBtus in 2013. Details on these instruments will be reported in Continental's 2011 annual report on Form 10-K, which the Company plans to file in the next several days.

Capital expenditures for the fourth quarter of 2011 were $806 million, bringing full-year capital expenditures to $2.2 billion, including $178 million invested in lease and production acquisitions.

As of December 31, 2011, the Company's balance sheet included $53.5 million in cash and $1.25 billion in total long-term debt. Total long-term debt at year-end 2011 included $358 million in borrowings under Continental's revolving credit facility. Commitments under the facility were recently increased from $750 million to $1.25 billion.

Operating Highlights






Three months ended December 31,


Year ended December 31,


2011


2010


2011


2010

Average daily production:












Crude oil (Bbl per day)


53,905



35,296



45,121



32,385

Natural gas (Mcf per day)


127,883



76,427



100,469



65,598

Crude oil equivalents (Boe per day)


75,219



48,034



61,865



43,318

Average sales prices: (1)












Crude oil ($/Bbl)

$

89.24


$

75.41


$

88.51


$

70.69

Natural gas ($/Mcf)


4.97



4.15



5.24



4.49

Crude oil equivalents ($/Boe)


72.60



61.98



73.05



59.70

Production expenses ($/Boe) (1)


5.73



5.31



6.13



5.87

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


3.02



3.09



3.23



3.09

Net income (loss) (in thousands)


(112,064)



(45,028)



429,072



168,255

Diluted net income (loss) per share


(0.62)



(0.27)



2.41



0.99

EBITDAX (in thousands) (3)


411,919



220,917



1,303,959



810,877




(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 $0.69 per Boe and $0.70 per Boe for the three months ended December 31, 2011 and 2010, respectively, and $0.73 per Boe and $0.74 per Boe for the years ended December 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.



4Q


3Q


4Q

Boe per day


2011


2011


2010

North Region:







North Dakota Bakken


35,565


28,987


17,834

Montana Bakken


5,678


5,518


4,686

Red River Units


15,246


14,954


13,896

Other


964


1,052


1,207








South Region:







Anadarko Woodford


9,820


7,164


1,705

Arkoma Woodford


3,688


4,099


4,403

Other


3,080


3,387


2,989

East Region


1,178


1,128


1,314

Total


75,219


66,289


48,034



Bakken Play (North Dakota and Montana)

Bakken production was 41,243 Boepd in the fourth quarter of 2011, an increase of 83 percent over the fourth quarter of 2010. Bakken production in the fourth quarter 2011 was 55 percent of total Continental production, compared with 47 percent of total production in the fourth quarter last year.

In the North Dakota portion of the Bakken, Continental's fourth quarter 2011 production was 35,565 Boepd, a 99 percent increase over the fourth quarter of 2010 and a 23 percent increase over North Dakota Bakken production in the third quarter of 2011.

The Company participated in completing 114 gross wells in the Bakken in the fourth quarter of 2011.

In terms of Company-operated wells, Continental completed 61 gross operated wells during the fourth quarter, with 54 gross (32 net) in North Dakota and 7 gross (6 net) in Montana.  

Continental announced results for its fourth quarter 2011 operated wells on January 25, 2012. Since the beginning of 2012, Continental's operated completions have included three gross wells in Montana and 18 in North Dakota. Half of the North Dakota wells had initial test period production rates of more than 1,200 Boepd.

  • Quale 1-1H (67% WI) in McKenzie Co. – 1,756 Boepd;
  • Edward 1-23H (51% WI) in Dunn Co. – 1,620 Boepd;
  • Addyson 1-23H (81% WI) in Williams Co. – 1,604 Boepd;
  • Benner 1-6H (39% WI) in Dunn Co. – 1,408 Boepd;
  • Richmond 1-26H (88% WI) in Williams Co. – 1,381 Boepd;
  • Springfield 1-8H (82% WI) in Williams Co. – 1,329 Boepd;
  • Sacramento 1-10H (89% WI) in Williams Co. – 1,277 Boepd;
  • Rochester 1-24H (50% WI) in McKenzie Co. – 1,241 Boepd;
  • Salem 1-6H (57% WI) in Williams Co. – 1,211 Boepd.

For 2011 as a whole, Continental participated in completing 390 gross wells in the Bakken play.

In terms of Company-operated wells, Continental completed 167 gross (98 net) wells in the Bakken during 2011, about 90 percent of which were in North Dakota.

At year-end 2011, Continental's acreage position in the Bakken totaled 915,863 net acres, with 663,237 net acres leased in the North Dakota portion of the play and 252,626 net acres in the Montana Bakken. These totals do not include the 35,178 net acres acquired in North Dakota in February 2012.

The Company currently has 24 operated drilling rigs in the Bakken, with 21 in North Dakota and three in Montana.

Woodford Play (Oklahoma)

Fourth quarter 2011 production in the Anadarko Woodford play in western Oklahoma was 9,820 Boepd, almost six times more than fourth quarter 2010 production of 1,705 Boepd and 37 percent higher than production of 7,164 Boepd for the third quarter of 2011.

Continental participated in completing 26 gross wells in the Anadarko Woodford in the fourth quarter of 2011. In terms of Company's operated wells, Continental completed 13 gross (10 net) wells in the quarter.

For 2011 as a whole, the Company completed 103 gross wells in the Anadarko Woodford, including 43 Company-operated gross (32 net) wells.  

In early 2012, Continental completed the Toms 1-21XH (90% WI) well in Blaine County, in the Northwest Cana portion of the Anadarko Woodford, and the Poteet 1-17H (74% WI) well in Stephens County, in the Southeast Cana.

The Toms 1-21XH is the first cross-unit well completed in Oklahoma, with a 9,500-foot lateral completed in 26 stages. The Toms 1-21XH flowed 1,268 Boepd (965 Bopd and 1.9 MMcfpd) in its initial one-day test period, flowing at 1,150 psi on a 40/64-inch choke. "This is a significant success, confirming that the longer lateral cross-unit concept greatly enhances well economics," Mr. Hamm said. "We look forward to additional cross-unit tests in northern Blaine and Dewey counties."

The Poteet 1-17H flowed 1,414 Boepd (247 Bopd and 7.0 MMcfpd) in its initial one-day test period, flowing at 2,100 psi on a 32/64-inch choke.

"The Poteet well is located four miles south of the Lyle 1-30H," Mr. Hamm said. "The Poteet's success demonstrates that a significant portion of the Southeast Cana is de-risked and prospective for full development."

In May 2011 the Company completed the Lambakis 1-11H (98% WI), its first test well in the southern portion of the Southeast Cana. The Lambakis flowed 1,060 Boepd (160 Bopd and 5.4 MMcfpd) in its initial production test period and has produced a cumulative 191 MBoe (22.7 MBo and 1,012 MMcf) to date. The Lambakis was assigned an estimated ultimate recovery (EUR) of 1.5 MMBoe (144 MBo and 8.4 Bcf). At current strip commodity prices, the Lambakis' estimated production equates to a rate of return of 50 percent.

Continental believes the Lyle 1-30H, Toms 1-21XH and Poteet 1-17H are stronger wells and will generate higher rates of return than the Lambakis 1-11H.

Continental currently has 12 operated rigs in the Anadarko Woodford, with two in the Southeast Cana and 10 in the Northwest Cana part of the play. In the course of 2012, the Company plans to drop two rigs and relocate others to have eight operated rigs in the Southeast Cana and two in the Northwest Cana.

In the Arkoma Woodford of Oklahoma, the Company's production was 3,688 Boepd in the fourth quarter of 2011, compared with 4,403 Boepd in the fourth quarter of 2010. Continental has suspended drilling in the Arkoma Woodford due to the low price for dry gas and consequently declassed 23.4 MMBoe of Proved Undeveloped reserves in the play to Probable Undeveloped.

At year-end 2011, the Company had 278,116 net acres leased in the Anadarko Woodford and 39,594 in the Arkoma Woodford.

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

The Company's production in the Red River Units totaled 15,246 Boepd in the fourth quarter of 2011, a 10 percent increase over production of 13,896 Boepd in the fourth quarter of 2010 and two percent higher than production in the third quarter of 2011.

"Our Red River Units team is doing a tremendous job optimizing productivity in this legacy play," Mr. Hamm said.

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

Niobrara Play (Colorado and Wyoming)

In Weld County, Colorado, in the Niobrara/DJ Basin, Continental announced on January 25, 2012, the completion of the Staudinger 1-31H (56% WI). Subsequent to the initial announcement, the well's production rate increased to 739 Boepd. Several other wells have been put on pump or are in various stages of completion. Continental had 93,339 net acres in the Niobrara/DJ Basin at year-end 2011, with approximately 25,000 net acres in the de-risked oil fairway section.

2012 Drilling Plans

Continental's 2012 capital expenditure budget is $1.75 billion, which includes $94 million for new leases and renewals. This 2012 budget does not include capital investments in lease and production acquisitions, such as the February 2012 acquisitions of a total 35,178 net acres in the North Dakota Bakken.

The Company plans to participate in the completion of 759 gross (249 net) wells in 2012.

In terms of Company-operated wells, Continental plans to complete 325 gross (214 net) wells. These include 176 gross (103 net) wells in the Bakken; 63 gross (39 net) wells in the Anadarko Woodford; 14 gross (9 net) wells in the Niobrara/DJ Basin; and 12 gross (12 net) wells in the Red River Units.

Conference Call Information

Continental Resources plans to host its fourth quarter 2011 earnings conference call on Thursday, February 23, 2012, at 10 a.m. ET. 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, February 23, 2012

Dial in:

888 713 4214

Intl. dial in:

617 213 4866

Pass code:

10023690


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

Replay number:

888 286 8010

Intl. replay

617 801 6888

Pass code:

45421548



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.

March 1

12th Annual Simmons & Co. International Energy Conference, Las Vegas

March 6

Raymond James 33rd Annual Institutional Investors Conference, Orlando

March 8

Global Hunter Mini-Conference, Dallas

March 28

Howard Weil Energy Conference, New Orleans



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 from unconventional formations.

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, 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. 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.

Contact:

Investor Relations

Media


Warren Henry, VP Investor Relations

Kristin Miskovsky, VP Public Affairs


(580) 548-5127

(405) 234-4480



Consolidated Statements of Income






Three months ended December 31,


Year ended December 31,


2011


2010


2011


2010

Revenues:

In thousands, except per share data

Crude oil and natural gas sales

$

508,309


$

273,148


$

1,647,419


$

948,524

Loss on derivative instruments, net


(402,539)



(188,388)



(30,049)



(130,762)

Crude oil and natural gas service operations


8,348



6,619



32,419



21,303

Total revenues


114,118



91,379



1,649,789



839,065













Operating costs and expenses:












Production expenses


40,146



23,397



138,236



93,203

Production taxes and other expenses


44,495



22,904



144,810



76,659

Exploration expenses


6,260



5,178



27,920



12,763

Crude oil and natural gas service operations


7,022



5,083



26,735



18,065

Depreciation, depletion, amortization and accretion


126,663



69,274



390,899



243,601

Property impairments


42,143



15,564



108,458



64,951

General and administrative expenses (1)


21,121



13,599



72,817



49,090

(Gain) loss on sale of assets


(5,451)



3,267



(20,838)



(29,588)

Total operating costs and expenses


282,399



158,266



889,037



528,744

Income (loss) from operations


(168,281)



(66,887)



760,752



310,321

Other income (expense):












Interest expense


(19,985)



(20,272)



(76,722)



(53,147)

Other


890



272



3,415



1,293



(19,095)



(20,000)



(73,307)



(51,854)

Income (loss) before income taxes


(187,376)



(86,887)



687,445



258,467

Provision (benefit) for income taxes


(75,312)



(41,859)



258,373



90,212

Net income (loss)

$

(112,064)


$

(45,028)


$

429,072


$

168,255

Basic net income (loss) per share

$

(0.62)


$

(0.27)


$

2.42


$

1.00

Diluted net income (loss) per share

$

(0.62)


$

(0.27)


$

2.41


$

0.99


(1) Includes non-cash charges for stock-based compensation of $4.8 million and $3.1 million for the three months ended December 31, 2011 and 2010, respectively, and $16.6 million and $11.7 million for the years ended December 31, 2011 and 2010, respectively.



Consolidated Balance Sheets




December 31,


2011


2010





Assets

In thousands

Current assets

$

936,373


$

582,326

Net property and equipment


4,681,733



2,981,991

Other noncurrent assets


27,980



27,468

Total assets

$

5,646,086


$

3,591,785







Liabilities and shareholders' equity






Current liabilities

$

1,111,801


$

702,222

Long-term debt


1,254,301



925,991

Other noncurrent liabilities


971,858



755,417

Total shareholders' equity


2,308,126



1,208,155

Total liabilities and shareholders' equity

$

5,646,086


$

3,591,785



Consolidated Statements of Cash Flows




Year ended December 31,


2011


2010


In thousands

Net income

$

429,072


$

168,255

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






Non-cash expenses


748,792



535,578

Changes in assets and liabilities


(109,949)



(50,666)

Net cash provided by operating activities


1,067,915



653,167







Net cash used in investing activities


(2,004,714)



(1,039,416)







Net cash provided by financing activities


982,427



379,943







Net change in cash and cash equivalents


45,628



(6,306)

Cash and cash equivalents at beginning of period


7,916



14,222

Cash and cash equivalents at end of period

$

53,544


$

7,916



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 us 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 December 31,


Year ended December 31,



2011


2010


2011


2010



in thousands


in thousands

Net income (loss)


$

(112,064)


$

(45,028)


$

429,072


$

168,255

Interest expense



19,985



20,272



76,722



53,147

Provision (benefit) for income taxes



(75,312)



(41,859)



258,373



90,212

Depreciation, depletion, amortization and accretion



126,663



69,274



390,899



243,601

Property impairments



42,143



15,564



108,458



64,951

Exploration expenses



6,260



5,178



27,920



12,763

Unrealized (gains) losses on derivatives



399,414



194,420



(4,057)



166,257

Non-cash equity compensation



4,830



3,096



16,572



11,691

EBITDAX


$

411,919


$

220,917


$

1,303,959


$

810,877



SOURCE Continental Resources

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