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CLR > SEC Filings for CLR > Form 10-Q on 8-Nov-2012All Recent SEC Filings

Show all filings for CONTINENTAL RESOURCES, INC | Request a Trial to NEW EDGAR Online Pro

Form 10-Q for CONTINENTAL RESOURCES, INC


8-Nov-2012

Quarterly Report


ITEM 2. Management's Discussion and Analysis of Financial Condition and Results of Operations

The following discussion and analysis should be read in conjunction with our historical consolidated financial statements and notes included in our Annual Report on Form 10-K for the year ended December 31, 2011. Our operating results for the periods discussed may not be indicative of future performance. The following discussion and analysis includes forward-looking statements and should be read in conjunction with the risk factors described under the heading Part II, Item 1A. Risk Factors included in this report, if any, and in our Annual Report on Form 10-K for the year ended December 31, 2011, along with Cautionary Statement for the Purpose of the "Safe Harbor" Provisions of the Private Securities Litigation Reform Act of 1995 at the beginning of this report, for information about the risks and uncertainties that could cause our actual results to be materially different than our forward-looking statements.

Overview

We are engaged in crude oil and natural gas exploration, development and production activities in the North, South, and East regions of the United States. The North region consists of properties north of Kansas and west of the Mississippi river and includes North Dakota Bakken, Montana Bakken, and the Red River units. The South region includes Kansas and all properties south of Kansas and west of the Mississippi river including the South Central Oklahoma Oil Province ("SCOOP"), Northwest Cana, and Arkoma Woodford plays in Oklahoma. The SCOOP and Northwest Cana plays were previously combined by us and referred to as the Anadarko Woodford play. The East region primarily includes properties east of the Mississippi river including the Illinois Basin and the state of Michigan. Our operations are geographically concentrated in the North region, with that region comprising approximately 76% of our crude oil and natural gas production for the nine months ended September 30, 2012.

We focus our exploration activities in large new or developing plays that provide us the opportunity to acquire undeveloped acreage positions for future drilling operations. We have been successful in targeting large repeatable resource plays where horizontal drilling, advanced fracture stimulation and enhanced recovery technologies provide the means to economically develop and produce crude oil and natural gas reserves from unconventional formations. We derive the majority of our operating income and cash flows from the sale of crude oil and natural gas. We expect growth in our revenues and operating income will primarily depend on commodity prices and our ability to increase our crude oil and natural gas production. In recent months and years, there has been significant volatility in crude oil and natural gas prices due to a variety of factors we cannot control or predict, including political and economic events, weather conditions, and competition from other energy sources. These factors impact supply and demand for crude oil and natural gas, which affect crude oil and natural gas prices. In addition, the prices we realize for our crude oil and natural gas production are affected by price differences in the markets where we deliver our production.

For the third quarter of 2012, our crude oil and natural gas production averaged 102,964 Boe per day, a 9% increase over average daily production of 94,852 Boe per day for the second quarter of 2012 and a 55% increase over average daily production of 66,289 Boe per day for the third quarter of 2011. Crude oil and natural gas production averaged 94,478 Boe per day for the nine months ended September 30, 2012, a 65% increase over average daily production of 57,365 Boe per day for the comparable 2011 period. Crude oil accounted for approximately 70% of our production for both the three and nine month periods ended September 30, 2012. The increase in 2012 production was primarily driven by an increase in production from our properties in the North Dakota Bakken field and the Northwest Cana and SCOOP plays in Oklahoma due to the continued success of our drilling programs in those areas. Our Bakken production in North Dakota averaged 48,354 Boe per day for the first nine months of 2012, a 104% increase over the first nine months of 2011. Third quarter 2012 average daily production in the North Dakota Bakken field increased 93% over the third quarter of 2011. Our production in the Northwest Cana play averaged 11,711 Boe per day for the first nine months of 2012, 212% higher than the same period in 2011. Northwest Cana average daily production for the third quarter of 2012 increased 90% compared to the third quarter of 2011, yet decreased 16% from the second quarter of 2012 due to reduced drilling activity and third-party infrastructure downtime. Production from our properties in the emerging SCOOP play in south-central Oklahoma averaged 5,183 Boe per day for the third quarter of 2012, a 327% increase over the third quarter of 2011. SCOOP production averaged 3,627 Boe per day for the first nine months of 2012, 307% higher than the same period in 2011.

Our crude oil and natural gas revenues for the third quarter of 2012 increased 49% to $633.3 million due to a 58% increase in sales volumes partially offset by a 6% decrease in realized commodity prices when compared to the third quarter of 2011. For the nine months ended September 30, 2012, crude oil and natural gas revenues were $1.71 billion, a 50% increase from the comparable 2011 period due to a 66% increase in sales volumes partially offset by a 10% decrease in realized commodity prices.

Our cash flows from operating activities for the first nine months of 2012 were $1.15 billion, an increase from $669.8 million provided by our operating activities during the comparable 2011 period. The increase in operating cash flows was primarily due to increased crude oil and natural gas revenues driven mainly by increased sales volumes, partially offset by lower realized sales prices, an increase in realized losses on derivatives and higher production expenses, production taxes, general and administrative expenses, and other expenses associated with the growth of our operations over the past year.


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The previously announced relocation of our corporate headquarters from Enid, Oklahoma to Oklahoma City was in essence completed during the third quarter of 2012. For the three and nine months ended September 30, 2012, we recognized $2.3 million and $7.4 million, respectively, of costs associated with our relocation efforts. Cumulative relocation costs recognized through September 30, 2012 have totaled approximately $10.6 million.

In February 2012, we assigned certain non-strategic leaseholds and producing properties in Wyoming to a third party for cash proceeds of $84.4 million and recognized a pre-tax gain on the transaction of $50.1 million. Additionally, in June 2012 we assigned certain non-strategic leaseholds and producing properties in Oklahoma to a third party for cash proceeds of $15.9 million and recognized a pre-tax gain on the transaction of $15.9 million. The disposed properties represented an immaterial portion of our total proved reserves and production. We may continue to seek opportunities to sell non-strategic crude oil and natural gas properties if and when we have the ability to dispose of such assets at favorable terms.

On July 26, 2012, certain terms of our credit agreement were amended. Amendments included the following, among other changes:

Borrowing base increased from $2.25 billion to $2.75 billion;

Aggregate credit facility commitments increased from $1.25 billion to $1.5 billion;

Interest margins on advances decreased by 25 basis points for all utilization levels. LIBOR margins now range from 150 to 250 basis points and reference rate margins now range from 50 to 150 basis points, depending on the percentage of the borrowing base utilized;

Commitment fees on unused borrowing capacity decreased from 0.50% to 0.375% when utilization of the credit facility is below 50%;

Reduced the security requirement from 85% to 80% by value of all proved reserves and associated crude oil and natural gas properties, unless the Collateral Coverage Ratio, as defined in the amended credit agreement, is greater than or equal to 1.75 to 1.0, in which case the security requirement will not apply; and

Total Funded Debt to EBITDAX covenant ratio requirement was increased from 3.75:1.0 to 4.0:1.0.

The amendments noted above will provide us with additional available liquidity, if needed, to maintain our growth strategy, take advantage of business opportunities, and fund our capital program.

On August 13, 2012 we completed our acquisition of the assets of Wheatland Oil Inc. The transaction provided for the acquisition by us, through the issuance of shares of our common stock, of all of Wheatland's right, title and interest in and to certain crude oil and natural gas properties and related assets in the states of Mississippi, Montana, North Dakota and Oklahoma and the assumption of certain liabilities related thereto. At closing, we issued an aggregate of approximately 3.9 million shares of our common stock to the shareholders of Wheatland. The fair value of the consideration transferred at closing was approximately $279 million. Our condensed consolidated financial statements at September 30, 2012 include the results of operations and cash flows for the acquired properties subsequent to the closing date. For both the three and nine month periods ended September 30, 2012, the acquired Wheatland properties comprised approximately 198 MBoe of our crude oil and natural gas production and approximately $16 million of our crude oil and natural gas revenues. See Note
10. Property Transaction with Related Party in Notes to Unaudited Condensed Consolidated Financial Statements for a discussion of the accounting applicable to the transaction.

In August 2012, we issued $1.2 billion of 5% Senior Notes due 2022 (the "New Notes"). The New Notes were issued pursuant to the indenture applicable to the $800 million of 2022 Notes previously issued in March 2012, resulting in a total of $2.0 billion aggregate principal amount of 5% Senior Notes due 2022 being issued under that indenture. The New Notes were sold at 102.375% of par value, resulting in net proceeds of approximately $1.21 billion after deducting the initial purchasers' fees. We used a portion of the net proceeds from the offering to repay all amounts then outstanding under our credit facility and expect to use the remaining net proceeds to fund a portion of our remaining 2012 capital budget and for general corporate purposes.

During the first nine months of 2012, we invested approximately $2.89 billion in our capital program (including $12.5 million of seismic costs and $4.5 million of capital costs associated with increased accruals for capital expenditures), focusing primarily on increased development in the Bakken field of North Dakota and Montana and the SCOOP play in south-central Oklahoma. Our 2012 year-to-date capital expenditures include $594.0 million of unbudgeted property acquisitions, most notably from an unbudgeted acquisition of producing and undeveloped properties in the Bakken play of North Dakota in February 2012 for $276 million and the non-cash acquisition of producing and undeveloped properties from Wheatland in August 2012 recorded at $177 million. We expect to continue participating as a buyer of properties if and when we have the ability to increase our position in strategic plays at favorable terms.

In October 2012, our Board of Directors approved a 2013 capital expenditures budget of $3.4 billion, excluding acquisitions. Our 2013 capital plan is expected to focus on increased exploratory and development drilling in the North Dakota Bakken field and the SCOOP play in Oklahoma.

Due to the volatility of crude oil and natural gas prices and our desire to develop our substantial inventory of undeveloped reserves as part of our capital program, we have hedged a portion of our forecasted production. We expect our cash flows from operations, our remaining cash balance, and amounts available under our credit facility will be sufficient to meet our planned capital expenditure needs for the next 12 months.

How We Evaluate Our Operations

We use a variety of financial and operating measures to assess our performance. Among these measures are:


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Volumes of crude oil and natural gas produced,

Crude oil and natural gas prices realized,

Per unit operating and administrative costs, and

EBITDAX (a non-GAAP financial measure).

The following table contains financial and operating highlights for the periods presented.

                                           Three months ended September 30,             Nine months ended September 30,
                                              2012                   2011                  2012                   2011
Average daily production:
Crude oil (Bbl per day)                           72,235                 47,552                 65,826               42,160
Natural gas (Mcf per day)                        184,377                112,423                171,912               91,231
Crude oil equivalents (Boe per day)              102,964                 66,289                 94,478               57,365
Average sales prices: (1)
Crude oil ($/Bbl)                       $          82.87       $          84.02      $           84.44       $        88.19
Natural gas ($/Mcf)                                 4.00                   5.50                   3.97                 5.37
Crude oil equivalents ($/Boe)                      65.62                  69.57                  66.06                73.25
Production expenses ($/Boe) (1)                     5.62                   5.98                   5.34                 6.31
General and administrative expenses
($/Boe) (1)                                         3.31                   2.98                   3.35                 3.32
Net income (in thousands)                         44,096                439,143                518,874              541,136
Diluted net income per share                        0.24                   2.44                   2.86                 3.05
EBITDAX (in thousands) (2)                       492,279                337,754              1,368,671              892,040

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

(2) EBITDAX represents earnings before interest expense, income taxes, depreciation, depletion, amortization and accretion, property impairments, exploration expenses, non-cash gains and losses resulting from the requirements of accounting for derivatives, and non-cash equity compensation expense. EBITDAX is not a measure of net income or operating cash flows as determined by U.S. GAAP. Reconciliations of net income and operating cash flows to EBITDAX are provided subsequently under the heading Non-GAAP Financial Measures.


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Three months ended September 30, 2012 compared to the three months ended September 30, 2011

Results of Operations

The following table presents selected financial and operating information for
the periods presented.



                                                          Three months ended September 30,
                                                           2012                     2011
                                                       In thousands, except sales price data
Crude oil and natural gas sales                      $         633,344        $         423,859
Gain (loss) on derivative instruments, net (1)                (158,294 )                537,340
Crude oil and natural gas service operations                     8,679                    7,790

Total revenues                                                 483,729                  968,989
Operating costs and expenses                                  (378,207 )               (241,371 )
Other expenses, net                                            (38,495 )                (17,987 )

Income before income taxes                                      67,027                  709,631
Provision for income taxes                                     (22,931 )               (270,488 )

Net income                                           $          44,096        $         439,143
Production volumes:
Crude oil (MBbl) (2)                                             6,645                    4,375
Natural gas (MMcf)                                              16,963                   10,343
Crude oil equivalents (MBoe)                                     9,472                    6,099
Sales volumes:
Crude oil (MBbl) (2)                                             6,825                    4,368
Natural gas (MMcf)                                              16,963                   10,343
Crude oil equivalents (MBoe)                                     9,651                    6,092
Average sales prices: (3)
Crude oil ($/Bbl)                                    $           82.87        $           84.02
Natural gas ($/Mcf)                                               4.00                     5.50
Crude oil equivalents ($/Boe)                                    65.62                    69.57

(1) Amounts include an unrealized non-cash mark-to-market loss on derivatives of $156.9 million for the three months ended September 30, 2012 and an unrealized non-cash mark-to-market gain on derivatives of $536.2 million for the three months ended September 30, 2011.

(2) At various times we have stored crude oil due to pipeline line fill requirements, low commodity prices, or transportation constraints or we have sold crude oil from inventory. These actions result in differences between produced and sold crude oil volumes. Crude oil sales volumes were 180 MBbls more than crude oil production for the three months ended September 30, 2012 and 7 MBbls less than crude oil production for the three months ended September 30, 2011.

(3) Average sales prices have been calculated using sales volumes and exclude any effect of derivative transactions.

Production

The following tables reflect our production by product and region for the
periods presented.



                                                Three months ended September 30,

                                                2012                          2011                                  Volume
                                                                                                   Volume           percent
                                        Volume         Percent        Volume       Percent        increase         increase
Crude oil (MBbl)                           6,645             70 %       4,375            72 %          2,270               52 %
Natural gas (MMcf)                        16,963             30 %      10,343            28 %          6,620               64 %

Total (MBoe)                               9,472            100 %       6,099           100 %          3,373               55 %

                                                Three months ended September 30,
                                                                                                                    Volume
                                                2012                          2011                 Volume           percent
                                                                                                  increase         increase
                                         MBoe          Percent         MBoe        Percent       (decrease)       (decrease)
North Region                               7,241             76 %       4,647            76 %          2,594               56 %
South Region                               2,130             23 %       1,348            22 %            782               58 %
East Region                                  101              1 %         104             2 %             (3 )             (3 %)

Total                                      9,472            100 %       6,099           100 %          3,373               55 %

Crude oil production volumes increased 52% during the three months ended September 30, 2012 compared to the three months ended September 30, 2011. Production increases in the Bakken field, the Northwest Cana play and SCOOP play contributed incremental production volumes in 2012 of 2,314 MBbls, an 82% increase over production in these areas for the third quarter of 2011. Production growth in these areas is primarily due to increased drilling and completion activity resulting from our drilling program.

Natural gas production volumes increased 6,620 MMcf, or 64%, during the three months ended September 30, 2012 compared to the same period in 2011. Natural gas production in the Bakken field increased 2,531 MMcf, or 102%, for the three months ended September 30, 2012 compared to the same period in 2011 due to new wells being completed and gas from existing wells being connected to natural gas processing plants in the play. Natural gas production in the Northwest Cana and SCOOP plays in


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Oklahoma increased 4,165 MMcf, or 118%, due to additional wells being completed in the three months ended September 30, 2012 compared to the same period in 2011. Further, natural gas production increased 215 MMcf, or 89%, in non-Bakken areas of our North region due to the completion of new wells during the period. These increases were partially offset by a decrease in production volumes of 237 MMcf from non-core areas in our South region due to a combination of natural declines in production and reduced drilling activity prompted by the unfavorable pricing environment for natural gas in those areas.

Revenues

Our total revenues consist of sales of crude oil and natural gas, realized and unrealized changes in the fair value of our derivative instruments, and revenues associated with crude oil and natural gas service operations.

Crude Oil and Natural Gas Sales. Crude oil and natural gas sales for the three months ended September 30, 2012 were $633.3 million, a 49% increase from sales of $423.9 million for the same period in 2011. Our sales volumes increased 3,559 MBoe, or 58%, over the same period in 2011 due to the continuing success of our drilling programs in the North Dakota Bakken field and Northwest Cana play, along with early success being achieved in the emerging SCOOP play in Oklahoma. Our realized price per Boe decreased $3.95 to $65.62 for the three months ended September 30, 2012 from $69.57 for the three months ended September 30, 2011 due to lower commodity prices and higher crude oil differentials.

The differential between NYMEX calendar month average crude oil prices and our realized crude oil price per barrel for the three months ended September 30, 2012 was $9.45 compared to $5.62 for the three months ended September 30, 2011 and $6.39 for the year ended December 31, 2011. Factors contributing to the changing differential included a continued increase in crude oil production across the Williston Basin from the Bakken play as well as increased production and imports from Canada. Additionally, pipeline transportation capacity constraints in the Williston Basin have not improved and greater rail transportation takeaway capacity is just now beginning to have a positive effect on differentials. Rail costs through the 2012 third quarter remained high with the positive effect of stronger pricing in coastal markets just beginning to be realized. Overall increased production and constrained logistical factors have had a negative effect on our realized crude oil prices during the third quarter of 2012 and resulted in higher differentials compared to 2011. Our crude oil differentials to NYMEX improved in the latter part of the 2012 third quarter.

Derivatives. We have entered into a number of derivative instruments, including fixed price swaps and zero-cost collars, to reduce the uncertainty of future cash flows in order to underpin our capital expenditures and drilling program. We are required to recognize all derivative instruments on the balance sheet as either assets or liabilities measured at fair value. We have not designated our derivative instruments as hedges for accounting purposes. As a result, we mark our derivative instruments to fair value and recognize the realized and unrealized changes in fair value in the unaudited condensed consolidated statements of income under the caption "Gain (loss) on derivative instruments, net", which is a component of total revenues.

Changes in commodity futures price strips during the third quarter of 2012 had a negative impact on the fair value of our derivatives, which resulted in negative revenue adjustments of $158.3 million for the three months ended September 30, 2012. We expect our revenues will continue to be significantly impacted, either positively or negatively, by changes in the fair value of our derivative instruments as a result of volatility in crude oil and natural gas prices. The following table presents the impact on total revenues related to realized and unrealized gains and losses on derivative instruments for the periods presented.

                                                           Three months ended September 30,
                                                             2012                    2011
                                                                     In thousands
Realized gain (loss) on derivatives:
Crude oil derivatives                                  $         (4,943 )       $        (7,282 )
Natural gas derivatives                                           3,549                   8,395

Total realized gain (loss) on derivatives              $         (1,394 )       $         1,113
Unrealized gain (loss) on derivatives:
Crude oil derivatives                                  $       (147,409 )       $       535,619
Natural gas derivatives                                          (9,491 )                   608

Total unrealized gain (loss) on derivatives            $       (156,900 )       $       536,227

Gain (loss) on derivative instruments, net             $       (158,294 )       $       537,340


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The unrealized mark-to-market losses reflected above at September 30, 2012 relate to derivative instruments with various terms that are scheduled to be realized over the period from October 2012 to December 2014. Over this period, actual realized derivative settlements may differ significantly from the unrealized mark-to-market valuation at September 30, 2012.

Operating Costs and Expenses

Production Expenses and Production Taxes and Other Expenses. Production expenses increased 49% to $54.2 million during the three months ended September 30, 2012 from $36.5 million during the three months ended September 30, 2011. This increase is primarily the result of higher production volumes from an increase in the number of producing wells, which helped generate lower costs realized on a per Boe basis. Production expense per Boe was $5.62 for the three months ended September 30, 2012 compared to $5.98 per Boe for the three months ended September 30, 2011.

Production taxes and other expenses increased $23.7 million, or 60%, to $62.9 million during the three months ended September 30, 2012 compared to the three months ended September 30, 2011 primarily as a result of higher crude oil and natural gas revenues resulting from increased sales volumes. Production taxes and other expenses include charges for marketing, gathering, dehydration and . . .

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