Exhibit 99.1
Continental Resources Announces Strong Third Quarter 2009 Results
Third Quarter Operating and Net Income Are Double Those for Second Quarter 2009
Company Accelerating Drilling Operations in Fourth Quarter 2009
$650 Million Capital Budget Expected to Boost Production Approximately 10 Percent in 2010
ENID, Okla., Nov. 5 /PRNewswire-FirstCall/ — Continental Resources, Inc. (NYSE: CLR) today announced that it doubled operating earnings and net income for the third quarter of 2009, compared with results for the second quarter of 2009, based on higher crude oil prices and lower production costs. Compared with the third quarter of 2008, when crude oil and natural gas prices peaked, operating and net income were lower for the quarter ended September 30, 2009, (Logo: http://www.newscom.com/cgi-bin/prnh/20080505/LAM014LOGO)
Based on strong third quarter cash flow and its positive outlook, Continental announced plans to accelerate drilling operations in the fourth quarter of 2009 and in 2010.
Continental has increased its 2009 capital expenditure budget to $415 million from $390 million, with expected cash flow sufficient to cover its increased capex budget. The Company now plans to exit 2009 with 12 operated drilling rigs, compared with the previous target of six. Of its 12 rigs at year end, six additional rigs will be deployed in the North Dakota Bakken and one in the Montana part of the play.
The Company announced a 2010 capital expenditure budget of $650 million. Continental expects to have up to 23 operated drilling rigs deployed by mid-2010.
“Consistent with our growth strategy, we are accelerating drilling operations in response to the improved crude oil market,” said Harold Hamm, Chairman and Chief Executive Officer. “Our shareholders value Continental’s capital discipline and focus on operating costs. We aggressively reduced drilling and other spending as prices fell in late 2008. We are ramping up operations in anticipation of strong cash flows in 2010, although we will continue to adapt to pricing trends and cash flow.
“We expect this budget to drive 2010 production growth of approximately 10 percent,” he said. “Along with strong execution and cost management, our focus will be to accelerate production growth momentum by mid-year and then sustain that growth in 2011.”
The Company now expects 2009 total production will be approximately 13.3 MMBoe (million barrels of oil equivalent), which would exceed its guidance of 12.5-to-13 MMBoe.
For the third quarter of 2009, Continental reported net income of $34.9 million, or $0.21 per diluted share, compared with net income of $105.3 million, or $0.62 per diluted share, for the third quarter of 2008. On a consecutive-quarter basis, third quarter 2009 net income represented a 159 percent increase over net income of $13.5 million for the second quarter of 2009.
Net income for the third quarter of 2009 included a pre-tax leasehold property impairment charge of $11.8 million and mark-to-market losses on natural gas fixed price and basis swaps of $2.1 million. Apart from these non-cash items, Continental’s net income was $44.4 million, or $0.26 per diluted share, for the third quarter of 2009. In the third quarter of 2008, the Company recorded a $9.9 million pre-tax leasehold property impairment charge.
Average daily production was 37,384 Boepd (barrels of oil equivalent per day) for the third quarter of 2009, 12 percent higher than production of 33,297 Boepd in the third quarter of 2008.
Average realized sales price per Boe was $48.19 for the third quarter of 2009, a decline of 48 percent from the average realized sales price of $93.21 per Boe for the third quarter of 2008.
Crude oil accounted for 74 percent of Continental’s third quarter 2009 total production. The average realized price for crude oil was $58.78 per barrel in the third quarter of 2009, while the average realized natural gas price was $2.98 per Mcf. Average realized prices were $108.37 per barrel and $7.97 per Mcf in the third quarter last year.
Crude oil price differentials averaged $9.39 per barrel for the third quarter of 2009, compared with $6.02 in the second quarter of 2009 and $9.68 for the third quarter of 2008.
Total oil and natural gas sales were $168.4 million for the third quarter of 2009, compared with $286.2 million for the third quarter of 2008. Sales exceeded production in the third quarter as the Company sold 55 MBbls of crude oil from storage. The Company sold 124 MBbls of crude oil in storage in October 2009. Minimum pipeline line fill requirements resulted in inventory balances of 341 MBbls of crude oil at September 30, 2009.
Continental reduced production expenses during the third quarter. Production expense was $6.50 per Boe for the third quarter of 2009, compared with $7.14 for the second quarter of 2009 and $8.22 for the third quarter of 2008.
Income from operations was $59.3 million for the third quarter of 2009, compared with $171.2 million for the third quarter last year. On a consecutive-quarter basis, third quarter 2009 income from operations represented a 126 percent increase over operating income of $26.2 million for the second quarter of 2009.
EBITDAX was $128.7 million for the third quarter of 2009, compared with $238.3 million for the third quarter last year. For the Company’s definition and reconciliation of EBITDAX to net income, see “Non-GAAP Financial Measures” at the end of this press release.
At September 30, 2009, the Company’s balance sheet included $5.3 million in cash and $546.3 million in long-term debt. As of November 5, 2009, $235 million was drawn against its revolving credit facility, leaving available borrowing capacity at $515 million, based on commitments of $750 million.
Company Announces 2010 Capital Expenditure Budget
Continental’s 2010 capital expenditures budget of $650 million will primarily focus on increased development in the North Dakota Bakken, the Arkoma and Anadarko Woodford shale natural gas plays in Oklahoma and the Red River Units, with total operated drilling rigs increasing to as many as 23 by mid-2010.
Operational capital expenditures – investment in drilling, work-over and related facilities – account for $563 million, or 87 percent, of the Company’s 2010 capex budget. In addition, the Company plans $73 million in land capex for new leases and lease retention, primarily in the Bakken and Woodford plays.
Continental has allocated $373 million, or 66 percent, of its 2010 operational capex to accelerate development in the Bakken shale play of North Dakota and Montana. The Company expects to complete 193 gross (61.9 net) wells in North Dakota and 11 gross (4.6 net) wells in Montana in 2010. Starting with seven operated rigs on January 1, the Company plans to have up to 15 operated drilling rigs by mid-2010, with all but one in North Dakota.
In Oklahoma, Continental plans to complete 62 gross (13.2 net) wells in the Arkoma Woodford and 11 gross (5.6 net) wells in the Anadarko Woodford during 2010. A total of $84 million, or 15 percent, of its operating capex is allocated to the Woodford plays in 2010. The Company plans to have an average of three operated rigs in the Woodford plays in 2010.
In the Red River Units, Continental plans to complete pattern drilling on its water flood project in the Cedar Hills Units and to resume development activity in the Medicine Pole Hills and Buffalo units in 2010. It has allocated $66 million, or 12 percent, of its operational capex to the Units, which will support one operated rig and significant investment in facilities and infrastructure. Production in the units is expected to peak mid-year in a range of 15,000 Boepd to 15,500 Boepd and then level off through the remainder of 2010.
Continental’s regional allocations of capital expenditures in 2010 are listed below.
| | | | | |
| Dollars in millions | | 2010 Capex
Budget | | Net
Wells |
North Dakota Bakken | | $ | 341 | | 61.9 |
Montana Bakken | | | 32 | | 4.6 |
Arkoma Woodford | | | 52 | | 13.2 |
Anadarko Woodford | | | 32 | | 5.6 |
Red River Units | | | 66 | | 14.6 |
Other | | | 40 | | 11.5 |
| | | | | |
Operational capex | | $ | 563 | | 111.4 |
Land, seismic and other | | | 87 | | |
| | | | | |
Total capex | | $ | 650 | | |
Additional 2010 Guidance
Continental expects to achieve 2010 operating and financial performance 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,
2010 |
| |
Production growth | | Approximately 10% |
| |
Price differentials(1) : | | |
Oil (Bbl) | | $8.00 to $10.00 |
Gas (Mcf) | | $1.25 to $1.75 |
| |
Operating expenses: | | |
Production expense (per Boe) | | $7.75 to $8.25 |
Production tax (percent of sales) | | 6.50% to 7.00% |
Depreciation, depletion, amortization and accretion (per Boe) | | $15.00 to $18.00 |
General and administrative expense (per Boe)(2) | | $2.00 to $2.40 |
Non-cash stock-based compensation (per Boe) | | $0.75 to $1.00 |
| |
Income tax rate (percent of pre-tax income) | | 38% |
Percent of income tax deferred | | 90% to 95% |
| (1) | Differential to calendar month average NYMEX futures price for oil and to average of last three trading days of prompt NYMEX futures contract for gas. |
| (2) | Excludes non-cash stock-based compensation. |
“We view 2010 as a strong first step toward the goal of doubling our proved reserves over the next five years,” Mr. Hamm said.
“Our operating focus is quite different today than it was in late 2008. A year ago, we were cutting capex due to falling commodity prices. We had so much momentum at the time, however, that we entered 2009 with a backlog of 40 completions that boosted production at the beginning of the year,” he said.
“Today we are accelerating drilling activity, and we will rely on that acceleration to generate 2010’s production growth, rather than an early-year backlog of completions,” he said. “Our goal is to establish a level of drilling activity that supports steady growth in 2011 and beyond.”
Operations Update
The following table contains financial and operating highlights for the third quarter of 2009 compared to the third quarter of 2008.
| | | | | | | | | | | | |
| | | Three months ended
September 30, | | Nine months ended
September 30, |
| | | 2009 | | 2008 | | 2009 | | 2008 |
Average daily production: | | | | | | | | | | | | |
Oil (Bbl) | | | 27,552 | | | 24,937 | | | 27,265 | | | 24,368 |
Natural gas (Mcf) | | | 58,995 | | | 50,156 | | | 59,503 | | | 44,139 |
Oil equivalent (Boe) | | | 37,384 | | | 33,297 | | | 37,182 | | | 31,725 |
Average prices: (1) | | | | | | | | | | | | |
Oil ($/ Bbl) | | $ | 58.78 | | $ | 108.37 | | $ | 49.81 | | $ | 105.78 |
Natural gas ($/Mcf) | | | 2.98 | | | 7.97 | | | 2.86 | | | 8.14 |
Oil equivalent ($/Boe) | | | 48.19 | | | 93.21 | | | 40.92 | | | 92.64 |
Production expense ($/Boe) (1) | | | 6.50 | | | 8.22 | | | 6.95 | | | 8.62 |
EBITDAX (in thousands) | | | 128,655 | | | 238,289 | | | 292,578 | | | 665,027 |
Net income (in thousands) | | | 34,929 | | | 105,256 | | | 21,824 | | | 320,534 |
Diluted net income per share | | | 0.21 | | | 0.62 | | | 0.13 | | | 1.89 |
| (1) | Average prices and per-unit production expense are calculated based on sales volumes. Crude oil sales exceeded production volumes in the third quarter of 2009 by 55 MBbls. Crude oil sales volumes exceeded oil production in the third quarter of 2008 by 7 MBbls. |
The following table presents average daily production for the Company’s principal operating areas for the quarters ended September 30, 2009, June 30, 2009, and September 30, 2008.
| | | | | | |
| (Boe per day) | | Q3 2009 | | Q2 2009 | | Q3 2008 |
Red River Units | | 13,942 | | 14,092 | | 13,375 |
Montana Bakken | | 5,581 | | 6,105 | | 6,187 |
North Dakota Bakken | | 6,943 | | 6,286 | | 3,444 |
Other Rockies | | 1,874 | | 1,928 | | 2,275 |
Arkoma Woodford | | 4,260 | | 4,235 | | 2,627 |
Other Mid-Continent | | 4,338 | | 4,179 | | 4,895 |
Gulf Coast | | 446 | | 522 | | 494 |
| | | | | | |
Total | | 37,384 | | 37,347 | | 33,297 |
North Dakota Bakken
North Dakota Bakken production of 6,943 Boepd accounted for 19 percent of total production for the third quarter 2009, compared with 17 percent in the second quarter this year. North Dakota production was more than twice that of the third quarter of 2008 and increased 11 percent in the third quarter of 2009 compared with the second quarter of 2009.
Continental participated in completing 21 gross wells (7.6 net) in North Dakota during the third quarter of 2009. As a group, the wells’ initial test period results averaged 761 Boepd. All initial well results discussed in this press release are seven consecutive day averages.
In terms of Company-operated wells, Continental completed 11 gross wells (6.6 net) targeting the Three Forks/Sanish (TFS) zone in the play in the third quarter of 2009, including:
— Bohmbach 1-35H (76% WI) in McKenzie Co. – 1,366 Boepd;
— Rollefstad 1-3H (78% WI) in McKenzie Co. – 1,275 Boepd;
— Radermecher 1-15H (41% WI) in McKenzie Co. – 912 Boepd;
— Tangsrud 1-1H (91% WI) in Divide Co. – 834 Boepd;
— Dolezal 1-5H (55% WI) in Dunn Co. – 731 Boepd;
— Bratlien 1-35H (45% WI) in Divide Co. – 661 Boepd;
— Myhre 1-18H (73% WI) in Divide Co. – 581 Boepd;
In early October 2009, Continental completed the Tande 1-23H (47% WI) in Williams Co. It produced 1,036 Boepd in its initial seven-day production test period
Montana Bakken
Montana Bakken production was 5,581 Boepd in the third quarter of 2009, a 10 percent decline from the third quarter of 2008, reflecting the deferral of drilling due to low prices and natural well declines. Third quarter 2009 production in the play accounted for 15 percent of the Company’s total production.
Red River Units
Production in the Red River Units was 13,942 Boepd in the third quarter of 2009, accounting for 37 percent of Continental’s total output. Production has been basically flat in 2009, reflecting the deferral of investment until commodity prices recovered. The Company is converting producing wells to injector wells as part of its secondary recovery program in the Units.
Arkoma Woodford
Production in the Arkoma Woodford shale play was 4,260 Boepd in the third quarter of 2009, which represented a 62 percent increase over the third quarter last year and was flat compared with the second quarter of 2009, reflecting reduced drilling activity since the beginning of 2009. Arkoma production was 11 percent of total third quarter 2009 production for the Company.
Continental currently has one operated drilling rig in the Arkoma Woodford play and one rig in the Anadarko Woodford play in Oklahoma. The Company continues to engage in exploratory drilling in various areas of the Anadarko Woodford, with increased activity planned for 2010.
Conference Call Information
Continental Resources will host a conference call on Thursday, November 5, 2009, at 10:00 a.m. ET (9 a.m. CT) to discuss its third quarter 2009 results. Interested parties may listen to the conference call via the Company’s website at http://www.contres.com or by phone:
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Dial in: | | (888) 713-4217 |
Intl. dial in: | | (617) 213-4869 |
Pass code: | | 35501502 |
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Replay number: | | (888) 286-8010 |
Intl. replay: | | (617) 801-6888 |
Pass code: | | 99956805 |
Conference Presentations
Continental management is currently scheduled to present at the following research conferences:
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November 17, 2009 | | Bank of America/Merrill Lynch 2009 Energy Conference, New York |
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December 2, 2009 | | Jefferies Energy Summit, New York |
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December 2, 2009 | | Bank of America High Yield Conference, New York |
| |
December 3, 2009 | | Raymond James Winter SMID-Cap Conference, Boston |
Presentation materials will be available on the Company’s web site on the day of each presentation.
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 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. 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.
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| CONTACT: | | Continental Resources, Inc. |
| | J. Warren Henry | | Brian Engel |
| | Investors | | Media |
| | (580) 548-5127 | | (580) 249-4731 |
Condensed Consolidated Statements of Operations
(in thousands, except per share amounts)
| | | | | | | | | | | | | | | | |
| | | Three months ended
September 30, | | | Nine months ended
September 30, | |
| | | 2009 | | | 2008 | | | 2009 | | | 2008 | |
| | | (unaudited) | |
Revenues: | | | | | | | | | | | | | | | | |
Oil and natural gas sales | | $ | 168,372 | | | $ | 286,194 | | | $ | 407,379 | | | $ | 809,238 | |
Loss on mark-to-market derivatives | | | (2,105 | ) | | | – | | | | (1,215 | ) | | | (7,966 | ) |
Oil and natural gas service operations | | | 3,937 | | | | 7,415 | | | | 12,409 | | | | 23,422 | |
| | | | | | | | | | | | | | | | |
Total revenues | | | 170,204 | | | | 293,609 | | | | 418,573 | | | | 824,694 | |
| | | | | | | | | | | | | | | | |
| | | | |
Operating costs and expenses: | | | | | | | | | | | | | | | | |
Production expense | | | 22,719 | | | | 25,247 | | | | 69,183 | | | | 75,273 | |
Production tax | | | 12,378 | | | | 17,941 | | | | 30,829 | | | | 48,411 | |
Exploration expense | | | 1,077 | | | | 15,285 | | | | 9,726 | | | | 26,278 | |
Oil and natural gas service operations | | | 2,326 | | | | 5,099 | | | | 7,423 | | | | 15,797 | |
Depreciation, depletion, amortization and accretion | | | 51,030 | | | | 39,120 | | | | 154,875 | | | | 95,828 | |
Property impairments | | | 11,791 | | | | 9,947 | | | | 70,491 | | | | 17,620 | |
General and administrative (1) | | | 10,049 | | | | 10,005 | | | | 29,684 | | | | 27,812 | |
Gain on sale of assets | | | (452 | ) | | | (194 | ) | | | (673 | ) | | | (406 | ) |
| | | | | | | | | | | | | | | | |
| | | | |
Total operating costs and expenses | | | 110,918 | | | | 122,450 | | | | 371,538 | | | | 306,613 | |
| | | | |
Income from operations | | | 59,286 | | | | 171,159 | | | | 47,035 | | | | 518,081 | |
Interest expense and other | | | 4,569 | | | | 2,321 | | | | 13,431 | | | | 8,050 | |
| | | | | | | | | | | | | | | | |
Net income before income tax expense | | | 54,717 | | | | 168,838 | | | | 33,604 | | | | 510,031 | |
Income tax expense | | | 19,788 | | | | 63,582 | | | | 11,780 | | | | 189,497 | |
| | | | | | | | | | | | | | | | |
Net income | | $ | 34,929 | | | $ | 105,256 | | | $ | 21,824 | | | $ | 320,534 | |
| | | | |
Basic net income per share | | $ | 0.21 | | | $ | 0.63 | | | $ | 0.13 | | | $ | 1.91 | |
Diluted net income per share | | | 0.21 | | | | 0.62 | | | | 0.13 | | | | 1.89 | |
| | | | |
Basic weighted average shares outstanding | | | 168,516 | | | | 168,097 | | | | 168,492 | | | | 168,008 | |
Diluted weighted average shares outstanding | | | 169,706 | | | | 169,526 | | | | 169,399 | | | | 169,477 | |
| | | | | | | | | | | | | | | | |
| (1) | Includes non-cash charges for stock-based compensation of $3.2 million and $2.6 million for the three months ended September 30, 2009 and 2008, respectively and $8.6 million and $6.5 million for the nine months ended September 30, 2009 and 2008, respectively. |
Condensed Consolidated Balance Sheets
(in Thousands)
| | | | | | |
| | | September 30,
2009 | | December 31,
2008 |
| | | (unaudited) | | |
Assets: | | | | | | |
Cash and cash equivalents | | $ | 5,295 | | $ | 5,229 |
Receivables | | | 158,561 | | | 229,079 |
Inventories and other | | | 44,668 | | | 43,387 |
Net property and equipment | | | 2,003,348 | | | 1,935,143 |
Other assets | | | 11,177 | | | 3,041 |
| | | | | | |
| | |
Total assets | | $ | 2,223,049 | | $ | 2,215,879 |
| | | | | | |
| | |
Liabilities and shareholders’ equity: | | | | | | |
Current liabilities | | $ | 184,524 | | $ | 403,594 |
Long-term debt | | | 546,305 | | | 376,400 |
Other noncurrent liabilities | | | 513,667 | | | 487,177 |
Shareholders’ equity | | | 978,553 | | | 948,708 |
| | | | | | |
| | |
Total liabilities and shareholders’ equity | | $ | 2,223,049 | | $ | 2,215,879 |
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Condensed Consolidated Statements of Cash Flows
(in thousands)
| | | | | | | | |
| | | Nine months ended
September 30, | |
| | | 2009 | | | 2008 | |
| | | (unaudited) | |
Net income | | $ | 21,824 | | | $ | 320,534 | |
Adjustments to reconcile net income to net cash provided by operating activities: | | | | | | | | |
Non-cash expenses | | | 255,831 | | | | 251,374 | |
Changes in assets and liabilities | | | (61,660 | ) | | | 18,024 | |
| | | | | | | | |
| | |
Net cash provided by operating activities | | | 215,995 | | | | 589,932 | |
| | | | | | | | |
| | |
Net cash used in investing activities | | | (375,421 | ) | | | (660,116 | ) |
| | | | | | | | |
| | |
Net cash provided by financing activities | | | 159,492 | | | | 64,556 | |
| | | | | | | | |
Net change in cash and cash equivalents | | | 66 | | | | (5,628 | ) |
Cash and cash equivalents at beginning of period | | | 5,229 | | | | 8,761 | |
| | | | | | | | |
| | |
Cash and cash equivalents at end of period | | $ | 5,295 | | | $ | 3,133 | |
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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). Management believes EBITDAX is useful because it allows them to more effectively evaluate the Company’s operating performance and compare the results of its operations from period to period without regard to its financing methods or capital structure. The Company excludes the items listed above from net income in arriving at EBITDAX because as these amounts can vary substantially from company to company within its 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 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 debt to EBITDAX ratio 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
September 30, | | Nine months ended
September 30, |
| (in thousands) | | 2009 | | 2008 | | 2009 | | 2008 |
Net income | | $ | 34,929 | | $ | 105,256 | | $ | 21,824 | | $ | 320,534 |
Unrealized derivative loss | | | 2,105 | | | – | | | 1,215 | | | – |
Interest expense | | | 4,763 | | | 2,506 | | | 14,073 | | | 8,782 |
Provision for income taxes | | | 19,788 | | | 63,582 | | | 11,780 | | | 189,497 |
Depreciation, depletion, amortization and accretion | | | 51,030 | | | 39,120 | | | 154,875 | | | 95,828 |
Property impairments | | | 11,791 | | | 9,947 | | | 70,491 | | | 17,620 |
Exploration expense | | | 1,077 | | | 15,285 | | | 9,726 | | | 26,278 |
Non-cash compensation expense | | | 3,172 | | | 2,593 | | | 8,594 | | | 6,488 |
| | | | | | | | | | | | |
EBITDAX | | $ | 128,655 | | $ | 238,289 | | $ | 292,578 | | $ | 665,027 |
CONTACT: Investors, J. Warren Henry, +1-580-548-5127 or Media, Brian Engel, +1-580-249-4731, both of Continental Resources, Inc.
