Continental Resources Reports 66 Percent Increase in Daily Production in the First Quarter of 2012 Compared with the First Quarter of 2011
OKLAHOMA CITY, May 2, 2012 /PRNewswire-FirstCall/–Continental Resources, Inc. (NYSE: CLR) reported production of 85,526 Boepd (barrels of oil equivalent per day) for the first quarter of 2012, a 66 percent increase over production of 51,663 Boepd for the first quarter of 2011.
The Company’s first quarter 2012 production of 85,526 Boepd was 14 percent higher than production of 75,219 Boepd for the fourth quarter of 2011.
Continental entered May 2012 with production in excess of 91,000 Boepd, benefiting from strong well results throughout the Bakken and Anadarko Woodford of Oklahoma.
“Along with good well performance, the two factors driving our results are faster drilling cycle times and our increased working interest ownership in Bakken wells,” said Harold Hamm, Chairman and Chief Executive Officer.
He noted the Company has reduced spud-to-spud drilling cycle times for Bakken wells by approximately 30 percent in the last six months.
Additionally, by acquiring almost 46,000 net acres in targeted areas of the North Dakota Bakken since mid-2011, the Company increased its average net working interest in both operated and non-operated wells. “Through successful acquisitions, we increased and concentrated our ownership in the play,” Mr. Hamm said. “This acquired acreage is in prime areas where we have significant operating history.”
With higher average working interest has come an increased need for additional development and capital investment. “Faster cycle times and increased ownership are enabling us to accelerate development of our acreage without adding rigs,” he said.
Continental experienced strong year-over-year production growth across its three principal operating areas, the Bakken, Anadarko Woodford, and the Red River Units of Montana, and North and South Dakota.
- Bakken production increased 88 percent to 48,024 Boepd in the first quarter of 2012, compared with 25,523 in the first quarter of 2011.
- Production in the North Dakota Bakken was 41,895 Boepd in the first quarter of 2012, a 107 percent increase over production of 20,238 in the first quarter of 2011. Montana Bakken production increased 16 percent to 6,129 Boepd in the first quarter of 2012, compared with the first quarter of 2011.
- The Company’s Anadarko Woodford production was 12,826 Boepd, nearly five times higher than production of 2,685 Boepd in the first quarter of 2011.
- Production in the Red River Units was 15,415 Boepd for the first quarter of 2012, a 10 percent increase over production of 14,066 Boepd for the first quarter of 2011.
Three acquisitions completed since mid-2011 had a minimal impact on first quarter 2012 production, after the effect of the Company’s $84 million sale of its Worland, WY properties and associated production in early 2012. The net combined effect of the acquisitions and sale is an increase in production of approximately 800 Boepd going forward.
Continental currently has 35 operated drilling rigs, with 24 in the Bakken, 10 in the Anadarko Woodford, and one in the Red River Units. This compares with a peak of 44 operated rigs in the fourth quarter of 2011. “The biggest reduction has been in the Woodford, where we’ve reduced our operated rigs from 16 to 10,” Mr. Hamm said.
EBITDAX of $454.5 million for the first quarter of 2012 was 69 percent higher than EBITDAX of $268.7 million for the first quarter of 2011. For the Company’s definition and reconciliation of EBITDAX to net income, see “Non-GAAP Financial Measures — EBITDAX” at the end of this press release.
After accounting for an unrealized mark-to-market loss on derivatives, Continental reported net income of $69.1 million, or $0.38 per diluted share, for the first quarter of 2012. Net income included a $129.1 million pre-tax unrealized loss on mark-to-market derivative instruments, a $29.9 million pre-tax property impairment charge, and a $49.6 million pre-tax gain on sales of assets. Excluding the combined effects of the non-cash, unrealized derivatives loss, property impairment charge and gain on asset sales, Continental’s net income would have been $0.76 per diluted share for the first quarter of 2012. For the reconciliation of this result to GAAP earnings per share, see “Non-GAAP Financial Measures – Adjusted earnings per share” at the end of this press release.
For the first quarter of 2011, Continental reported a net loss of $137.2 million, or $0.80 per diluted share. Excluding the combined effects of a non-cash, unrealized derivatives loss, a property impairment charge, and a gain on sale of assets, the Company’s net income would have been $0.53 per diluted share for the first quarter of 2011. For the reconciliation of this result to GAAP earnings per share, see “Non-GAAP Financial Measures – Adjusted earnings per share” at the end of this press release.
Increased 2012 Capital Expenditures and Growth Rate
Continental is increasing its 2012 capital expenditure budget to $2.3 billion, excluding acquisitions, to continue development of recently acquired acreage and to fund accelerated drilling due to faster cycle times. Resulting production growth from these expenditures is expected to range from 47 percent to 50 percent for the year.
The Company’s previous 2012 capital expenditures budget was $1.75 billion, with 88 percent of the budget allocated to drilling. The budget envisioned the Company participating in completing 759 gross (249 net) wells in 2012. Company-operated wells represented 325 gross (214 net) wells in the initial 2012 plan.
Under the revised 2012 capital expenditures budget, Continental plans to participate in completing 842 gross (300 net) wells this year. Company-operated wells represent 342 gross (240 net) wells in the revised 2012 plan. Nearly all of the additional 2012 Company-operated wells are planned for the Bakken play.
Operating and Financial Results
Crude oil accounted for 70 percent of Continental’s first quarter 2012 total production.
Crude oil and natural gas sales were $552.3 million for the first quarter of 2012, compared with $326.5 million for the same period of 2011.
Continental’s average realized crude oil price was $90.58 per barrel in the first quarter of 2012, while the average realized natural gas price was $4.48 per Mcf, yielding a blended realized price of $71.39 per Boe. In the first quarter of 2011, the Company reported a blended realized price of $71.14 per Boe.
The Company’s crude oil price differential was $12.27 per barrel and its natural gas price differential was a premium of $1.76 per Mcf for the first quarter of 2012, due to the high liquids content of the gas. A spike in oil price differentials at the Clearbrook, MN and Guernsey, WY markets negatively affected realized prices for March and April 2012, but differentials at these markets have since improved. Due to increased oil differentials and volatility at Clearbrook, MN and Guernsey, WY, the Company expects average differentials for the year will be in a range of $9 to $11 per barrel.
Production expense was $5.18 per Boe for the first quarter of 2012, down from $6.38 per Boe for the first quarter of 2011. General and administrative expense was $3.23 per Boe, compared with $3.56 per Boe for the first quarter of 2011.
Capital expenditures for the first quarter of 2012 were $1.0 billion, including $345 million invested in lease and production acquisitions. The Company’s Worland, WY property sale added back $84 million in proceeds.
As of March 31, 2012, the Company’s balance sheet included $43 million in cash and cash equivalents and $1.9 billion in total long-term debt. Total long-term debt at March 31, 2012 included $176 million in borrowings under Continental’s revolving credit facility. Commitments under the facility are $1.25 billion, and its total borrowing base is $2.25 billion.
Three months ended March 31, ---------------------------- 2012 2011 ---- ---- Average daily production: Crude oil (Bbl per day) 59,901 38,446 Natural gas (Mcf per day) 153,751 79,297 Crude oil equivalents (Boe per day) 85,526 51,663 Average sales prices :(1) Crude oil ($/Bbl) $90.58 $85.34 Natural gas ($/Mcf) 4.48 5.09 Crude oil equivalents ($/Boe) 71.39 71.14 Production expenses ($/Boe)(1) 5.18 6.38 General and administrative expenses ($/Boe) (1) (2) 3.23 3.56 Net income (loss) (in thousands) 69,094 (137,201) Diluted net income (loss) per share 0.38 (0.80) EBITDAX (in thousands) (3) 454,532 268,655
(1) Average sales prices and per unit expenses have been calculated using sales volumes and exclude any effect of derivative transactions. --------------------------------- (2) General and administrative expense ($/Boe) includes non-cash equity compensation expense of $0.71 per Boe and $0.79 per Boe for the three months ended March 31, 2012 and 2011, respectively, and corporate relocation expenses of $0.23 per Boe for the three months ended March 31, 2012. (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. 1Q 4Q 1Q Boe per day 2012 2011 2011 ----------- ---- ---- ---- North Region: North Dakota Bakken 41,895 35,565 20,238 Montana Bakken 6,129 5,678 5,285 Red River Units 15,415 15,246 14,066 Other 1,445 964 1,072 South Region: Anadarko Woodford 12,826 9,820 2,685 Arkoma Woodford 3,637 3,688 4,065 Other 2,988 3,080 3,097 East Region 1,191 1,178 1,155 ----- ----- ----- Total 85,526 75,219 51,663
Bakken production of 48,024 Boepd accounted for 56 percent of total Continental production, compared with 49 percent of total production in the first quarter last year.
The Company participated in completing 103 gross wells in the Bakken in the first quarter of 2012.
In terms of Company-operated wells, Continental completed 54 gross (36 net) operated wells during the first quarter of 2012, with 47 gross (30 net) in North Dakota and 7 gross (6 net) in Montana. Initial one-day test production rates for Company-operated wells in North Dakota averaged approximately 947 Boepd.
The Company currently has 24 operated drilling rigs in the Bakken, with 21 in North Dakota and three in Montana. Four of Continental’s operated rigs are drilling multi-well ECO-Pad® projects in North Dakota, and that total is expected to increase throughout the remainder of the year.
Continental completed three ECO-Pad projects in late December 2011, and consequently did not complete a multi-well project during the first quarter ended March 31, 2012. The ECO-Pad design involves drilling four wells on two adjoining 1,280-acre spacing units from a single drilling pad. This approach reduces well costs, as well as reducing the surface impact of each well.
In April 2012, the Company completed the Candee-Kukla ECO-Pad project, which was comprised of the Candee 2-9H and 3-9H (56% WI) wells and the Kukla 2-16H and 3-16H (56% WI) wells in Dunn County, ND. The four wells produced a total 5,913 Boepd in their initial one-day test periods, for an average of 1,478 Boepd per well. Continental expects to complete at least two more ECO-Pad projects by the end of the second quarter of 2012.
At March 31, 2012, Continental’s acreage position in the Bakken totaled 938,940 net acres, with 684,109 net acres leased in the North Dakota portion of the play and 254,831 net acres in the Montana Bakken.
The Woodford Play
Highlighting the Company’s Anadarko Woodford operations in the first quarter was the completion of the Tom’s 1-21XH (84% WI) in Blaine County in January 2012. The Tom’s 1-21XH was the first multiple-unit spaced well drilled in Oklahoma, and its horizontal section was twice the length of previous Anadarko Woodford wells drilled in the play. The Tom’s 1-21XH flowed 1,270 Boepd (76% oil) in its initial one-day test period.
Continental expects longer laterals in the Anadarko Woodford will have a significant, positive impact on well productivity and economics. It is currently completing its second multiple-unit well.
Overall, Continental participated in completing 21 gross wells in the Anadarko Woodford in the first quarter of 2012. In terms of operated wells, Continental completed 12 gross (9 net) wells in the quarter. Initial one-day test production rates for Company-operated wells in the Anadarko Woodford averaged approximately 728 Boepd.
Continental currently has eight operated rigs in the Southeast Cana section of the Anadarko Woodford and two in the Northwest Cana, all of which are focused on crude oil and liquids-rich areas.
In the Arkoma Woodford of Oklahoma, the Company’s production was 3,637 Boepd in the first quarter of 2012, compared with 4,065 Boepd in the first quarter of 2011. Continental has suspended drilling in the Arkoma Woodford due to the low price for dry gas.
At March 31, 2012, the Company had 280,610 net acres leased in the Anadarko Woodford and 36,729 in the Arkoma Woodford.
The Red River Units
The Company’s production in the Red River Units increased to 15,415 Boepd in the first quarter of 2012, a 10 percent increase over production of 14,066 Boepd in the first quarter of 2011. “Much of the improvement was in the Buffalo Units in South Dakota, where we’ve been increasing our injection volumes over the past year,” Mr. Hamm said. “We’re seeing excellent results in this enhanced oil recovery project.”
Niobrara Play (Colorado and Wyoming)
In the Niobrara/DJ Basin, Continental completed the Buchner 1-2H (82% WI) in Weld County, CO, during the first quarter of 2012. The Buchner 1-2H produced 910 Boepd (90 percent oil) in its initial one-day test period.
As previously announced, the Company completed the Staudinger 1-31H (56% WI) in January 2012, which produced 739 Boepd in its initial one-day test production period.
“We’re currently assessing results for our first nine Niobrara wells and preparing to initiate the second phase of our development program,” Mr. Hamm said.
Continental had 92,842 net acres in the Niobrara/DJ Basin at March 31, 2012, with approximately 25,000 net acres in the identified oil fairway of the play.
First Quarter 2012 Earnings Conference Call
The Company plans to host a conference call on Thursday, May 3 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.CLR.com or by phone:
Continental Resources First Quarter 2012 Earnings Conference Call Time and date: 10 a.m. ET Thursday, May 3, 2012 Dial in: 888-679-8035 Intl. dial in: 617-213-4848 Pass code: 24687880 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: 63400980
Please use the following link to pre-register for this conference call. Callers who pre-register will be given a unique PIN to gain immediate access to the call and bypass the live operator. You may pre-register at any time, including up to and after the call start time. To pre-register please go to: https://www.theconferencingservice.com/prereg/key.process?key=P8LNPW7LB
Continental plans to participate in the following research conferences. Presentation materials will be available on the Company’s web site at www.CLR.com :
May 8 RW Baird 2012 Growth Stock Conference, Chicago June 4-5 RBC Global Energy Conference, New York June 25 3rd Annual Global Hunter Securities Investor Conference, San Francisco
About Continental Resources
Continental Resources is a Top 10 petroleum liquids producer in the United States and the largest leaseholder in the nation’s premier oil play, the Bakken play of North Dakota and Montana. Based in Oklahoma City, the company also has a leading presence in the Anadarko Woodford play of Oklahoma and the Red River Units play of North Dakota, South Dakota and Montana. Founded in 1967, Continental’s growth strategy has focused on crude oil since the 1980s. The company reported total revenues of $1.6 billion for 2011 and is ahead of plan to triple production and proved reserves from 2009 to 2014. Visit www.CLR.com for more information.
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.
CONTACTS: Continental Resources, Inc. Investors Media Warren Henry, VP Investor Relations Kristin Miskovsky, VP Public Relations 405-234-9127 405-234-9480 Warren.Henry@CLR.com Kristin.Miskovsky@CLR.com
Continental Resources, Inc. and Subsidiaries Unaudited Condensed Consolidated Statements of Operations Three months ended March 31, ---------------------------- 2012 2011 ---- ---- Revenues: In thousands, except per share data Crude oil and natural gas sales $535,312 $316,740 Crude oil and natural gas sales to affiliates 16,946 9,727 Loss on derivative instruments, net (169,057) (369,303) Crude oil and natural gas service operations 11,899 6,626 ------ ----- Total revenues 395,100 (36,210) Operating costs and expenses: Production expenses 40,016 28,398 Production and other expenses to affiliates 1,069 872 Production taxes and other expenses 49,730 27,562 Exploration expenses 4,151 6,812 Crude oil and natural gas service operations 9,842 5,451 Depreciation, depletion, amortization and accretion 149,455 75,650 Property impairments 29,907 20,848 General and administrative expenses (1) 24,966 16,347 Gain on sale of assets, net (49,627) (15,257) ------- ------- Total operating costs and expenses 259,509 166,683 ------- ------- Income (loss) from operations 135,591 (202,893) Other income (expense): Interest expense (24,278) (18,971) Other 781 509 (23,497) (18,462) ------- ------- Income (loss) before income taxes 112,094 (221,355) Provision (benefit) for income taxes 43,000 (84,154) ------ ------- Net income (loss) $69,094 $(137,201) ------- --------- Basic net income (loss) per share $0.38 $(0.80) Diluted net income (loss) per share $0.38 $(0.80) (1) Includes non-cash charges for stock-based compensation of $5.5 million and $3.6 million for the three months ended March 31, 2012 and 2011, respectively.
Unaudited Condensed Consolidated Balance Sheets March 31, December 31, 2012 2011 ---- ---- Assets (Unaudited) In thousands Current assets $985,375 $936,373 Net property and equipment 5,501,142 4,681,733 Debt issuance costs and other assets 43,680 27,980 Total assets $6,530,197 $5,646,086 ---------- ---------- Liabilities and shareholders' equity Current liabilities $1,176,051 $1,111,801 Long-term debt, net of current portion 1,891,651 1,254,301 Other noncurrent liabilities 1,083,126 971,858 Total shareholders' equity 2,379,369 2,308,126 --------- --------- Total liabilities and shareholders' equity $6,530,197 $5,646,086 ---------- ----------
Unaudited Condensed Consolidated Statements of Cash Flows Three months ended March 31, ---------------------------- 2012 2011 ---- ---- In thousands Net income (loss) $69,094 $(137,201) Adjustments to reconcile net income (loss) to net cash provided by operating activities: Non-cash expenses 306,966 368,361 Changes in assets and liabilities (11,116) (35,525) ------- ------- Net cash provided by operating activities 364,944 195,635 Net cash used in investing activities (995,115) (355,323) Net cash provided by financing activities 619,310 629,212 ------- ------- Net change in cash and cash equivalents (10,861) 469,524 Cash and cash equivalents at beginning of period 53,544 7,916 ------ ----- Cash and cash equivalents at end of period $42,683 $477,440Non-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 March 31, ---------------------------- 2012 2011 ---- ---- in thousands Net income (loss) $69,094 $(137,201) Interest expense 24,278 18,971 Provision (benefit) for income taxes 43,000 (84,154) Depreciation, depletion, amortization and accretion 149,455 75,650 Property impairments 29,907 20,848 Exploration expenses 4,151 6,812 Unrealized losses on derivatives 129,132 364,087 Non-cash equity compensation 5,515 3,642 ----- ----- EBITDAX $454,532 $268,655
Adjusted earnings per share
Our presentation of adjusted earnings per share that excludes the effect of certain items is a non-GAAP financial measure. Adjusted earnings per share represents diluted earnings per share determined under U.S. GAAP without regard to unrealized mark-to-market gains and losses on derivative instruments, property impairments, and gains and losses on asset sales. Management believes this measure provides useful information to analysts and investors for analysis of our operating results on a recurring, comparable basis from period to period. In addition, management believes this measure is used by analysts and others in valuation, comparison and investment recommendations of companies in the oil and gas industry to allow for analysis without regard to an entity’s specific derivative portfolio, impairment methodologies, and nonrecurring transactions. Adjusted earnings per share should not be considered in isolation or as a substitute for earnings per share as determined in accordance with U.S. GAAP and may not be comparable to other similarly titled measures of other companies. The following table reconciles earnings and diluted earnings per share as determined under U.S. GAAP to adjusted earnings and adjusted diluted earnings per share.
Three months ended March 31, ---------------------------- 2012 2011 ---- ---- In thousands, except per share data After-Tax $ Diluted EPS After-Tax $ Diluted EPS ----------- ----------- ----------- ----------- Net income (loss) (GAAP) $69,094 $0.38 $(137,201) $(0.80) Adjustments, net of tax: Unrealized losses on derivatives 79,933 0.44 225,370 1.31 Property impairments 18,512 0.10 12,905 0.07 Gain on sale of assets (30,719) (0.16) (9,444) (0.05) ------- ----- ------ ----- Adjusted net income (Non- GAAP) $136,820 $0.76 $91,630 $0.53 Weighted average diluted shares outstanding 180,283 171,729 ------- ------- Adjusted diluted net income per share (Non- GAAP) $0.76 $0.53
SOURCE Continental Resources