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Note 1. Significant Accounting Policies
Organization and Nature of Operations
Denbury Resources Inc., a Delaware corporation, is a growing independent oil and natural gas company. We are the largest combined oil and natural gas producer in both Mississippi and Montana, own the largest reserves of CO2 used for tertiary oil recovery east of the Mississippi River, and hold significant operating acreage in the Rocky Mountain and Gulf Coast regions. Our goal is to increase the value of our acquired properties through a combination of exploitation, drilling and proven engineering extraction practices, with our most significant emphasis on our CO2 tertiary recovery operations.
Encore Merger. On March 9, 2010, we acquired Encore Acquisition Company (“Encore”), pursuant to an Agreement and Plan of Merger (the “Encore Merger Agreement”), under which Encore was merged with and into Denbury (the “Encore Merger”), with Denbury surviving the Encore Merger following approval by the stockholders of both Denbury and Encore, closing of a new revolving credit facility as part of the financing for the Encore Merger, and satisfaction of conditions precedent. The Encore Merger provided Encore stockholders stock and/or cash and included the assumption of Encore's debt by Denbury. Denbury has consolidated Encore's results of operations since March 9, 2010, the acquisition date. See Note 2, Acquisitions and Divestitures, for more information.
Principles of Reporting and Consolidation
The consolidated financial statements herein have been prepared in accordance with accounting principles generally accepted in the United States (“GAAP”) and include the accounts of Denbury and entities in which we hold a controlling financial interest. Undivided interests in oil and gas joint ventures are consolidated on a proportionate basis. Investments in non-controlled entities over which we exercise significant influence are accounted for under the equity method. Other investments are carried at cost. All intercompany balances and transactions have been eliminated.
From March 9, 2010 through December 31, 2010, we owned approximately 46% of Encore Energy Partners LP (“ENP”) outstanding common units and 100% of Encore Energy Partners GP LLC (“GP LLC”), which was ENP's general partner. Considering the presumption of control of GP LLC in accordance with the Consolidation topic of the Financial Accounting Standards Board Codification (“FASC”), the results of operations and cash flows of ENP were consolidated with those of Denbury for this period. On December 31, 2010, we sold all of our ownership interests in ENP and GP LLC and, therefore, we did not consolidate ENP in our Consolidated Balance Sheet as of December 31, 2010. As presented in the accompanying Consolidated Statement of Operations for the year ended December 31, 2010, “Net income attributable to noncontrolling interest” of $13.8 million represents ENP's results of operations attributable to limited partners other than Denbury for the portion of the year for which we consolidated ENP.
At December 31, 2009, we owned the general partner of Genesis Energy, L.P. (“Genesis”), a publicly-traded master limited partnership, and approximately 10% of Genesis' outstanding common units. In aggregate, our ownership interests represented approximately a 12% ownership interest in Genesis, which we accounted for under the equity method of accounting. On February 5, 2010, we sold our general partner interest in Genesis, and in March 2010 we sold our Genesis common units. See Note 2, Acquisitions and Divestitures, for more information.
Use of Estimates
The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amount of certain assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during each reporting period. Management believes its estimates and assumptions are reasonable; however, such estimates and assumptions are subject to a number of risks and uncertainties that may cause actual results to differ materially from such estimates. Significant estimates underlying these financial statements include (1) the fair value of financial derivative instruments, (2) the estimated quantities of proved oil and natural gas reserves used to compute depletion of oil and natural gas properties, the related present value of estimated future net cash flows therefrom and the ceiling test, (3) accruals related to oil and natural gas sales volumes and revenues, capital expenditures and lease operating expenses, (4) the estimated costs and timing of future asset retirement obligations, (5) estimates made in the calculation of income taxes, and (6) estimates made in determining the fair values for purchase price allocations, including goodwill. While management is not aware of any significant revisions to any of its estimates, there will likely be future revisions to its estimates resulting from matters such as revisions in estimated oil and natural gas volumes, changes in ownership interests, payouts, joint venture audits, re-allocations by purchasers or pipelines, or other corrections and adjustments common in the oil and natural gas industry, many of which require retroactive application. These types of adjustments cannot be currently estimated and will be recorded in the period in which the adjustment occurs.
Reclassifications
Certain prior period amounts have been reclassified to conform with the current year presentation. On the Consolidated Statements of Operations for the years ended December 31, 2010 and 2009, “Taxes other than income” is a new line item and includes oil and natural gas ad valorem taxes, which were reclassified from “Lease operating expenses,” franchise taxes and property taxes on buildings, which were reclassified from “General and administrative expenses,” oil and natural gas production taxes, which were reclassified from “Production taxes and marketing expenses” used in prior reports and CO2 property ad valorem and production taxes, which were classified from “CO2 discovery and operating expense.” On the Consolidated Balance Sheet as of December 31, 2010, “Pipelines and plants” was reclassified from “CO2 and other products – properties and pipelines” used in prior reports, helium properties were reclassified to “Other property and equipment” from “CO2 and other products - properties and pipelines” used in prior reports, and “Other current assets” was reclassified from “Trade and other receivables, net.” Such reclassifications had no impact on our reported total expenses, net income, current assets, total assets, current liabilities, total liabilities or stockholders' equity.
Cash Equivalents
We consider all highly liquid investments to be cash equivalents if they have maturities of three months or less at the date of purchase.
Short-term Investments
Short-term investments are available-for-sale securities recorded at fair value with any unrealized gains or losses included in accumulated other comprehensive income. At December 31, 2011 and 2010, short-term investments consisted entirely of our investment in Vanguard Natural Resources LLC (“Vanguard”) common units obtained as partial consideration for the sale of our interests in ENP to a subsidiary of Vanguard on December 31, 2010. See Note 2, Acquisitions and Divestitures. Our original cost basis of this investment was $93.0 million. We received distributions of $7.2 million on the Vanguard common units we own for the year ended December 31, 2011, which are included in “Interest income and other income” on our Consolidated Statements of Operations. Due to the decline in the market value of this investment and the expectation that the investment would not recover to its cost basis prior to the time of sale, we recorded a $6.3 million “other-than-temporary” impairment loss on this investment for the year ended December 31, 2011, which is included in “Impairment of assets” on our Consolidated Statements of Operations. This investment was sold in January 2012 for cash consideration of $83.5 million, net of related transaction fees. See Note 14, Subsequent Events.
Oil and Natural Gas Properties
Capitalized Costs. We follow the full cost method of accounting for oil and natural gas properties. Under this method, all costs related to acquisitions, exploration and development of oil and natural gas reserves are capitalized and accumulated in a single cost center representing our activities, which are undertaken exclusively in the United States. Such costs include lease acquisition costs, geological and geophysical expenditures, lease rentals on undeveloped properties, costs of drilling both productive and non-productive wells, capitalized interest on qualifying projects, and general and administrative expenses directly related to exploration and development activities, and do not include any costs related to production, general corporate overhead or similar activities. We assign the purchase price of oil and natural gas properties we acquire to proved and unevaluated properties based on the estimated fair values as defined in the FASC Fair Value Measurements and Disclosures topic. Proceeds received from disposals are credited against accumulated costs except when the sale represents a significant disposal of reserves, in which case a gain or loss would be recognized.
Depletion and Depreciation. The costs capitalized, including production equipment and future development costs, are depleted or depreciated using the unit-of-production method, based on proved oil and natural gas reserves as determined by independent petroleum engineers. Oil and natural gas reserves are converted to equivalent units on a basis of 6,000 cubic feet of natural gas to one barrel of crude oil. The depletion and depreciation rate per BOE associated with our oil and gas producing activities was $16.42 in 2011, $15.82 in 2010 and $13.39 in 2009.
Under full cost accounting, we may exclude certain unevaluated costs from the amortization base pending determination of whether proved reserves can be assigned to such properties. The costs classified as unevaluated are transferred to the full cost amortization base as the properties are developed, tested and evaluated.
Ceiling Test. The net capitalized costs of oil and natural gas properties are limited to the lower of unamortized cost or the cost center ceiling. The cost center ceiling is defined as the sum of (1) the present value of estimated future net revenues from proved reserves before future abandonment costs (discounted at 10%), based on unescalated period-end oil and natural gas prices during the first three quarters of 2009; and beginning in the fourth quarter of 2009, the average first-day-of-the-month oil and natural gas price for each month during the 12-month period prior to the end of a particular reporting period; (2) plus the cost of properties not being amortized; (3) plus the lower of cost or estimated fair value of unproved properties included in the costs being amortized, if any; (4) less related income tax effects. Our future net revenues from proved reserves are not reduced for development costs related to the cost of drilling for and developing CO2 reserves nor those related to the cost of constructing CO2 pipelines, as those costs have previously been incurred by the Company. Therefore, we include in the ceiling test, as a reduction of future net revenues, that portion of the Company's capitalized CO2 costs related to CO2 reserves and CO2 pipelines that we estimate will be consumed in the process of producing our proved oil and natural gas reserves. The fair value of our oil and natural gas derivative contracts is not included in the ceiling test, as we do not designate these contracts as hedge instruments for accounting purposes. The cost center ceiling test is prepared quarterly. We did not have a ceiling test write-down during the years ended December 31, 2011, 2010 or 2009.
Joint Interest Operations. Substantially all of our oil and natural gas exploration and production activities are conducted jointly with others. These financial statements reflect only Denbury's proportionate interest in such activities, and any amounts due from other partners are included in trade receivables.
Tertiary Injection Costs. Our tertiary operations are conducted in reservoirs that have already produced significant amounts of oil over many years; however, in accordance with the SEC rules and regulations for recording proved reserves, we cannot recognize proved reserves associated with enhanced recovery techniques, such as CO2 injection, until there is a production response to the injected CO2, or unless the field is analogous to an existing flood. Our costs associated with the CO2 we produce and inject are principally our costs of production, transportation and acquisition, and payment of royalties.
We capitalize, as a development cost, injection costs in fields that are in their development stage, which means we have not yet seen incremental oil production due to the CO2 injections (i.e., a production response). These capitalized development costs are included in our unevaluated property costs if there are not already proved tertiary reserves in that field. After we see a production response to the CO2 injections (i.e., the production stage), injection costs are expensed as incurred, and once proved reserves are recognized, previously deferred unevaluated development costs will become subject to depletion.
CO2 Properties
We own and produce CO2 reserves, a non-hydrocarbon resource, that are used in our tertiary oil recovery operations on our own behalf and on behalf of other working interest owners in our enhanced recovery fields, with a portion sold to third-party industrial users. We record revenue from our sales of CO2 to third parties when it is produced and sold. Expenses related to the production of CO2 are allocated between volumes sold to third parties and volumes consumed internally that are directly related to our tertiary production. The expenses related to third-party sales are recorded in “CO2 discovery and operating expenses,” and the expenses related to internal use are recorded in “Lease operating expenses” in the Consolidated Statements of Operations, or are capitalized as oil and gas properties in our Consolidated Balance Sheets, depending on the status of floods that receive the CO2 (see Tertiary Injection Cost above for further discussion).
During 2010 and 2011, we acquired interests in the Riley Ridge Federal Unit (“Riley Ridge”), in which helium, a non-hydrocarbon resource, as well as natural gas, a hydrocarbon, are present. It is not possible to separately identify the capitalized costs related to the development of each product in the comingled gas stream; thus, these costs are allocated between “Oil and natural gas properties”, “CO2 properties” and “Other property and equipment” on the Consolidated Balance Sheets based on the relative future revenue value of each product line.
During 2010, we revised our capitalization policies for CO2 properties. Previously, we accounted for our CO2 source properties in a manner similar to our method of accounting for oil and natural gas properties, as the process and activities to identify, develop and produce CO2 reserves are virtually identical to those used to identify, develop and produce oil and natural gas reserves. However, because CO2 is not a hydrocarbon, it is excluded from the scope of FASC Topic 932, Extractive Industries – Oil and Gas, and, therefore, we are precluded from accounting for our CO2 operations in accordance with FASC Topic 932. Accordingly, commencing in July 2010, costs incurred to search for CO2 are expensed as incurred until proved or probable reserves are established. Once proved or probable reserves are established, costs incurred to obtain those reserves are capitalized and classified as “CO2 properties” on our Consolidated Balance Sheets. Capitalized CO2 is aggregated by geologic formation and depleted on a unit-of-production basis over proved and probable reserves. The impact of the revised accounting policy on our financial statements was not material to any individual year. The Company recognized the cumulative impact of the revised accounting policy as a non-cash net reduction to depletion, depreciation and amortization during the year ended December 31, 2010, resulting in a pretax credit of $9.6 million ($6.0 million after tax), which reflected a reduction to “CO2 properties” of $26.1 million offset by a decrease in “Accumulated depletion, depreciation and amortization” of $35.7 million. The cumulative adjustment did not have an impact on our net cash flows.
The portion of the Company's capitalized CO2 costs related to CO2 reserves and CO2 pipelines that we estimate will be consumed in the process of producing our proved oil reserves is included in the ceiling test as a reduction to future net revenues. The remaining net capitalized CO2 properties, equipment and pipelines balance is evaluated for impairment by comparing the net carrying costs to the expected future net revenues from (1) the production of our probable and possible tertiary oil reserves and (2) the sale of CO2 to third-party industrial users.
Pipelines and Plants
CO2 used in our tertiary floods is transported to our fields through CO2 pipelines. Costs of CO2 pipelines under construction are not depreciated until the pipelines are placed into service. Pipelines are depreciated on a straight-line basis over their estimated useful lives, which range from 15 to 50 years.
Pipelines and plants include the Riley Ridge gas plant in southwestern Wyoming, which is currently under construction. The plant is being withheld from depreciation until it is placed in service, which we currently expect to occur during the second quarter of 2012.
Property and Equipment – Other
Other property and equipment, which includes furniture and fixtures, vehicles, computer equipment and software, and capitalized leases, is depreciated principally on a straight-line basis over estimated useful lives. Vehicles and furniture and fixtures are generally depreciated over a useful life of five to ten years, and computer equipment and software are generally depreciated over a useful life of three to five years. Leasehold improvements are amortized over the shorter of the estimated useful life or the remaining lease term.
Leased property meeting certain capital lease criteria is capitalized, and the present value of the related lease payments is recorded as a liability. Amortization of capitalized leased assets is computed using the straight-line method over the shorter of the estimated useful life or the initial lease term.
Maintenance and repair costs that do not extend the useful lives of property and equipment are charged to expense as incurred.
Asset Retirement Obligations
In general, our future asset retirement obligations relate to future costs associated with plugging and abandonment of our oil, natural gas and CO2 wells, removing equipment and facilities from leased acreage, and returning land to its original condition. The fair value of a liability for an asset retirement obligation is recorded in the period in which it is incurred, discounted to its present value using our credit-adjusted-risk-free interest rate, and a corresponding amount capitalized by increasing the carrying amount of the related long-lived asset. The liability is accreted each period, and the capitalized cost is depreciated over the useful life of the related asset. Revisions to estimated retirement obligations will result in an adjustment to the related capitalized asset and corresponding liability. If the liability is settled for an amount other than the recorded amount, the difference is recorded to the full cost pool, unless significant.
Asset retirement obligations are estimated at the present value of expected future net cash flows and are discounted using the Company's credit-adjusted-risk-free rate. We utilize unobservable inputs in the estimation of asset retirement obligations that include, but are not limited to, costs of labor, costs of materials, profits on costs of labor and materials, the effect of inflation on estimated costs, and the discount rate. Accordingly, asset retirement obligations are considered a Level 3 measurement under the FASC Fair Value Measurements and Disclosures topic.
Derivative Instruments and Hedging Activities
We utilize oil and natural gas derivative contracts to mitigate our exposure to commodity price risk associated with our future oil and natural gas production. These derivative contracts have historically consisted of options, in the form of price floors or collars, and fixed price swaps. From time to time, we have also used interest rate lock contracts to mitigate our exposure to interest rate fluctuations related to sale-leaseback financing of certain equipment used at our oilfield facilities. Our derivative financial instruments are recorded on the balance sheet as either an asset or a liability measured at fair value. We do not apply hedge accounting to our oil and natural gas derivative contracts; accordingly, the changes in the fair value of these instruments are recognized in our Consolidated Statements of Operations in the period of change.
Financial Instruments with Off-Balance-Sheet Risk and Concentrations of Credit Risk
Our financial instruments that are exposed to concentrations of credit risk consist primarily of cash equivalents, trade and accrued production receivables, and the derivative instruments discussed above. Our cash equivalents represent high-quality securities placed with various investment-grade institutions. This investment practice limits our exposure to concentrations of credit risk. Our trade and accrued production receivables are dispersed among various customers and purchasers; therefore, concentrations of credit risk are limited. We evaluate the credit ratings of our purchasers, and if customers are considered a credit risk, letters of credit are the primary security obtained to support lines of credit. We attempt to minimize our credit risk exposure to the counterparties of our oil and natural gas derivative contracts through formal credit policies, monitoring procedures and diversification. All of our derivative contracts are with banks, which are part of the syndicate of banks in our bank credit facility, or with their affiliates. There are no margin requirements with the counterparties of our derivative contracts.
Goodwill
Goodwill represents the excess of the purchase price over the estimated fair value of the net assets acquired in the acquisition of a business. Goodwill is not amortized; rather, it is tested for impairment annually during the fourth quarter and when events or changes in circumstances indicate that fair value of a reporting unit with goodwill has been reduced below carrying value. The impairment test requires allocating goodwill and other assets and liabilities to reporting units. However, we have only one reporting unit. To assess impairment, we have the option to qualitatively assess if it is more likely than not that the fair value of the reporting unit is less than the book value. Absent a qualitative assessment, or, through the qualitative assessment, if we determine it is more likely than not that the fair value of the reporting unit is less than the book value, a quantitative assessment is prepared to calculate the fair market value of the reporting unit. If it is determined that the fair value of the reporting unit is less than the book value, the recorded goodwill is impaired to its implied fair value with a charge to operating expense. We completed our annual goodwill impairment assessment during the fourth quarter of 2011 and did not record any goodwill impairment during 2011, nor have we recorded a goodwill impairment historically.
The following table summarizes the changes in goodwill for the years ended December 31, 2011 and 2010:
In thousands | 2011 | 2010 | |||||
Beginning of year balance | $ | 1,232,418 | $ | 169,517 | |||
Adjustment to goodwill related to the acquisition of interests in the Conroe Field | - | 318 | |||||
Goodwill related to the Encore Merger | - | 1,061,123 | |||||
Goodwill related to the Riley Ridge acquisition | 3,900 | 1,460 | |||||
End of year balance | $ | 1,236,318 | $ | 1,232,418 |
Revenue Recognition
Revenue is recognized at the time oil and natural gas is produced and sold. Any amounts due from purchasers of oil and natural gas are included in accrued production receivable.
We follow the sales method of accounting for our oil and natural gas revenue, whereby we recognize revenue on all oil or natural gas sold to our purchasers regardless of whether the sales are proportionate to our ownership in the property. A receivable or liability is recognized only to the extent that we have an imbalance on a specific property greater than the expected remaining proved reserves. As of December 31, 2011 and 2010, our aggregate oil and natural gas imbalances were not material to our consolidated financial statements.
We recognize revenue and expenses of purchased producing properties at the time we assume effective control, commencing from either the closing or purchase agreement date, depending on the underlying terms and agreements. We follow the same methodology in reverse when we sell properties by recognizing revenue and expenses of the sold properties until either the closing or purchase agreement date, depending on the underlying terms and agreements.
Income Taxes
Income taxes are accounted for using the liability method, under which deferred income taxes are recognized for the future tax effects of temporary differences between the financial statement carrying amounts and the tax basis of existing assets and liabilities using the enacted statutory tax rates in effect at year-end. The effect on deferred taxes for a change in tax rates is recognized in income in the period that includes the enactment date. A valuation allowance for deferred tax assets is recorded when it is more likely than not that the benefit from the deferred tax asset will not be realized.
We recognize the tax benefit from an uncertain tax position only if it is more likely than not that the tax position will be sustained upon examination by the taxing authorities, based on the technical merits of the position. The tax benefits recognized in the financial statements from such a position are measured based on the largest benefit that has a greater than 50% likelihood of being realized upon ultimate settlement.
Net Income Per Common Share
Basic net income per common share is computed by dividing the net income attributable to common stockholders by the weighted average number of shares of common stock outstanding during the period. Diluted net income per common share is calculated in the same manner, but also considers the impact to net income and common shares of the potential dilution from stock options, stock appreciation rights (“SARs”), non-vested restricted stock and non-vested performance equity awards.
For each of the three years in the period ended December 31, 2011, there were no adjustments to net income for purposes of calculating basic and diluted net income per common share.
The following is a reconciliation of the weighted average shares used in the basic and diluted net income per common share calculations for the periods indicated:
Year Ended December 31, | |||||||
In thousands | 2011 | 2010 | 2009 | ||||
Basic weighted average common shares | 396,023 | 370,876 | 246,917 | ||||
Potentially dilutive securities: | |||||||
Stock options and SARs | 3,539 | 3,844 | - | ||||
Performance equity awards | 38 | 319 | - | ||||
Restricted stock | 1,358 | 1,216 | - | ||||
Diluted weighted average common shares | 400,958 | 376,255 | 246,917 |
Basic weighted average common shares excludes 3.4 million, 3.2 million and 2.5 million shares of non-vested restricted stock during the year ended December 31, 2011, 2010 and 2009, respectively. As these restricted shares vest or become retirement eligible, they will be included in the shares outstanding used to calculate basic net income per common share (although all restricted stock is issued and outstanding upon grant). For purposes of calculating diluted weighted average common shares, the non-vested restricted stock is included in the computation using the treasury stock method, with the deemed proceeds equal to the average unrecognized compensation during the period, adjusted for any estimated future tax consequences recognized directly in equity.
The following securities could potentially dilute earnings per share in the future but were not included in the computation of diluted net income per share, as their effect would have been anti-dilutive:
Year Ended December 31, | |||||||
In thousands | 2011 | 2010 | 2009 | ||||
Stock options and SARs | 5,017 | 3,671 | 10,764 | ||||
Performance equity awards | - | - | 523 | ||||
Restricted stock | 104 | 17 | 2,507 | ||||
Total | 5,121 | 3,688 | 13,794 |
Recently Adopted Accounting Pronouncements
Goodwill. In September 2011, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2011-08, Testing Goodwill for Impairment, (“ASU 2011-08”). ASU 2011-08 amends the FASC Intangibles – Goodwill and Other topic by permitting entities to assess qualitative factors to determine whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount as a basis for determining whether it is necessary to perform the two-step goodwill impairment test described in the FASC Intangibles – Goodwill and Other topic. We adopted ASU 2011-08 in 2011.
Recently Issued Accounting Pronouncements
Balance Sheet Offsetting. In December 2011, the FASB issued ASU 2011-11, Disclosure about Offsetting Assets and Liabilities (“ASU 2011-11”). ASU 2011-11 requires an entity to disclose information about offsetting and related arrangements to enable users of its financial statements to understand the effect of those arrangements on its financial position. ASU 2011-11 will be effective for our fiscal year beginning January 1, 2013 and will be applied retrospectively for all comparative periods presented. The adoption of ASU 2011-11 is not expected to have a material effect on our consolidated financial statements, but may require additional disclosures.
Comprehensive Income. In June 2011, the FASB issued ASU 2011-05, Presentation of Comprehensive Income, (“ASU 2011-05”). ASU 2011-05 requires the presentation of comprehensive income in either 1) a continuous statement of comprehensive income or 2) two separate but consecutive statements. In December 2011, the FASB issued ASU 2011-12, which defers certain requirements within ASU 2011-05. These amendments are being made to allow the FASB time to redeliberate whether to present on the face of the financial statements the effects of reclassifications out of accumulated other comprehensive income on the components of net income and other comprehensive income in all periods presented. ASU 2011-05 and the amendments in ASU 2011-12 will be effective for our fiscal year beginning January 1, 2012. Since the ASUs will only amend presentation requirements, they are not expected to have a material effect on our consolidated financial statements.
Fair Value. In May 2011, the FASB issued ASU 2011-04, Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRSs, (“ASU 2011-04”). ASU 2011-04 amends the FASC Fair Value Measurements topic by providing a consistent definition and measurement of fair value, as well as similar disclosure requirements between U.S. GAAP and International Financial Reporting Standards. ASU 2011-04 changes certain fair value measurement principles, clarifies the application of existing fair value measurements and expands the fair value disclosure requirements, particularly for Level 3 fair value measurements. ASU 2011-04 will be effective for our fiscal year beginning January 1, 2012. The adoption of ASU 2011-04 will not have a material effect on our consolidated financial statements but may require additional disclosures.
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Note 2. Acquisitions and Divestitures
Acquisitions
Fair Value. The FASC Fair Value Measurements and Disclosures topic defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (often referred to as the “exit price”). The fair value measurement is based on the assumptions of market participants and not those of the reporting entity. Therefore, entity-specific intentions do not impact the measurement of fair value unless those assumptions are consistent with market participant views.
The fair value of oil and natural gas properties is based on significant inputs not observable in the market, which the FASC Fair Value Measurements and Disclosures topic defines as Level 3 inputs. Key assumptions include (1) NYMEX oil and natural gas futures (this input is observable), (2) projections of the estimated quantities of oil and natural gas reserves, including those classified as proved, probable, and possible, (3) projections of future rates of production, (4) timing and amount of future development and operating costs, (5) projected cost of CO2 (to a market participant), (6) projected reserve recovery factors, and (7) risk-adjusted discount rates. Fair value is determined using a risk-adjusted after-tax discounted cash flow analysis.
October 2010 and August 2011 Riley Ridge Acquisitions. In October 2010, we acquired a 42.5% non-operated working interest in Riley Ridge, located in southwestern Wyoming, for $132.3 million after closing adjustments. Riley Ridge contains natural gas resources, as well as helium and CO2 resources. The purchase includes a 42.5% interest in a gas plant, currently under construction, which will separate the helium and natural gas from the comingled gas stream, and interests in certain surrounding properties. The fair values assigned to assets acquired and liabilities assumed in the October 2010 acquisition have been finalized, and no adjustments have been made to amounts previously disclosed in our Form 10-K for the year ended December 31, 2010.
On August 1, 2011, we acquired the remaining 57.5% working interest in Riley Ridge we did not already own, the remaining 57.5% interest in the gas plant, and interests in certain surrounding properties. As a result of the transaction, we became the operator of both projects. The purchase price was approximately $214.8 million after closing adjustments, including a $15 million deferred payment to be made at the time the property's gas plant is operational and meets specific performance conditions. We currently expect the gas plant to be operational during the second quarter of 2012.
Because the Riley Ridge plant remains under construction, current production at the field is negligible. As a result, pro forma information has not been disclosed due to the immateriality of revenues and expenses during 2011 and 2010.
The acquisition of Riley Ridge meets the definition of a business under the FASC Business Combinations topic. Goodwill associated with the acquisition is deductible for income tax purposes. The following table presents a summary of the preliminary fair value of assets acquired:
In thousands | |||||
Consideration: | |||||
Cash payment | $ | 199,779 | |||
Deferred payment(1) | 15,000 | ||||
Total consideration | 214,779 | ||||
Less: Fair value of assets acquired and liabilities assumed: | |||||
Oil and natural gas properties | |||||
Proved | 48,731 | ||||
Unproved | 12,542 | ||||
CO2 properties | 9,741 | ||||
Pipelines and plants | 91,594 | ||||
Other assets(2) | 48,660 | ||||
Asset retirement obligations | (389) | ||||
210,879 | |||||
Goodwill | $ | 3,900 | |||
(1) | The deferred payment is included in "Accounts payable and accrued liabilities" on the accompanying balance sheet and will be paid at the time the property's gas plant is operational and meets specific performance conditions as described above. | ||||
(2) | Other assets includes helium extraction rights of $36.7 million. Helium reserves at Riley Ridge are owned by the U.S. Government. The fair value assigned to helium extraction rights was calculated using the income approach and represents the discounted future net revenues associated with the Company's right to extract and sell the helium on behalf of the helium resource owners. Upon commencement of helium production, helium extraction rights will be amortized on a units-of-production basis. |
2010 Merger with Encore Acquisition Company. On March 9, 2010, we acquired Encore pursuant to the Encore Merger Agreement entered into with Encore on October 31, 2009. The Encore Merger Agreement provided for a stock and cash transaction valued at approximately $4.8 billion at the acquisition date, including the assumption of debt and the value of the noncontrolling interest in ENP. Under the Encore Merger Agreement, Encore was merged with and into Denbury, with Denbury surviving the Encore Merger.
In the Encore Merger, we issued approximately 135.2 million shares of common stock and paid approximately $833.9 million in cash to Encore stockholders. The Denbury shares issued to Encore stockholders represented approximately 34% of Denbury's common stock issued and outstanding immediately after the Encore Merger. The total fair value of our common stock issued to Encore stockholders in the Encore Merger was approximately $2.1 billion based upon our closing price of $15.43 per share on March 9, 2010.
The Encore Merger was financed through a combination of issuing $1.0 billion of 8¼% Senior Subordinated Notes due 2020 (the “2020 Notes”), which we issued on February 10, 2010, borrowings under a new $1.6 billion revolving credit agreement (the “Credit Agreement”) entered into on March 9, 2010, and the assumption of Encore's remaining outstanding senior subordinated notes.
The Encore Merger met the definition of a business combination under the FASC Business Combinations topic. As such, we estimated the fair value of Encore as of the acquisition date, which is the date on which we obtained control of Encore. The acquisition date for the Encore Merger was March 9, 2010.
In applying these accounting principles, we estimated the fair value of the Encore assets acquired less liabilities assumed on the acquisition date to be approximately $2.4 billion. This measurement resulted in the recognition of goodwill totaling approximately $1.1 billion. Goodwill was calculated as the excess of the consideration transferred to acquire Encore plus the fair value of the noncontrolling interest in ENP, over the acquisition date estimated fair value of the net assets acquired. Goodwill recorded in the Encore Merger primarily represents the value of the opportunity to expand Encore's CO2 EOR operations in the Rocky Mountain region, the experience and technical expertise of former Encore employees who have joined Denbury, and the addition of strategic areas of operations in which we did not previously have a significant presence. None of the goodwill is deductible for income tax purposes.
The following table is a summary of the consideration issued in the Encore Merger and the fair value of the assets acquired and liabilities assumed at the acquisition date, as well as the fair value at the acquisition date of the noncontrolling interest in ENP.
In thousands | |||
Consideration and noncontrolling interest: | |||
Fair value of Denbury common stock issued (1) | $ | 2,085,681 | |
Cash payment to Encore stockholders (2) | 833,909 | ||
Severance payments | 32,925 | ||
Consideration issued | 2,952,515 | ||
Fair value of noncontrolling interest of ENP (3) | 515,210 | ||
Consideration and noncontrolling interest of ENP (4) | 3,467,725 | ||
Add: fair value of liabilities assumed: | |||
Accounts payable and accrued liabilities | 116,236 | ||
Oil and natural gas production payable | 54,201 | ||
Current derivatives | 65,954 | ||
Other current liabilities | 38,407 | ||
Long-term debt | 1,375,149 | ||
Asset retirement obligations | 42,360 | ||
Long-term derivatives | 35,631 | ||
Long-term deferred taxes | 871,912 | ||
Other long-term liabilities | 2,717 | ||
Amount attributable to liabilities assumed | 2,602,567 | ||
Less: fair value of assets acquired: | |||
Cash and cash equivalents | 51,850 | ||
Accrued production receivable | 124,494 | ||
Trade and other receivables | 43,643 | ||
Current derivatives | 29,737 | ||
Other current assets | 2,740 | ||
Oil and natural gas properties – proved | 3,340,141 | ||
Oil and natural gas properties – unevaluated | 1,279,000 | ||
Pipelines and plants | 7,254 | ||
Other property, plant and equipment | 11,475 | ||
Long-term derivatives | 35,207 | ||
Other long-term assets | 83,628 | ||
Amount attributable to assets acquired | 5,009,169 | ||
Goodwill | $ | 1,061,123 | |
(1) | 135.2 million Denbury common shares at $15.43 per share. | ||
(2) | Based on cash paid to holders of Encore issued and outstanding common stock who elected to receive all cash or who received a combination of cash and stock; also includes cash payment to stock option holders of $4.5 million. | ||
(3) | Represents fair value of the noncontrolling interest of ENP. As of March 9, 2010, there were 45.3 million ENP common units outstanding, and the closing price was $21.10 per common unit. As of March 9, 2010, Encore owned approximately 46% of ENP’s outstanding units. | ||
(4) | The sum of the consideration issued, the noncontrolling interest of ENP and the fair value of Encore’s long-term debt assumed totals approximately $4.8 billion, representing the aggregate purchase price. |
For the period from March 9, 2010 to December 31, 2010, we recognized $623.4 million of oil, natural gas and related product sales related to properties acquired in the Encore Merger. For the period from March 9, 2010, to December 31, 2010, we recognized $426.0 million net field operating income (oil, natural gas and related product sales less lease operating expenses and production taxes and marketing expenses) related to properties acquired in the Encore Merger. Transaction and other costs related to the Encore Merger included in the Consolidated Statement of Operations for the year ended December 31, 2010, include $48.5 million of third-party, legal and accounting fees, which have been expensed as incurred, and $43.8 million of employee-related severance and termination costs, which are accrued over the employees' service period. Accrued employee-related severance costs totaled $19.8 million at December 31, 2010, of which $16.5 million was classified as Accounts payable and accrued liabilities, and $3.3 million was classified as long-term Other liabilities on our balance sheet. Transaction and other costs related to the Encore Merger included in the Consolidated Statement of Operations for the year ended December 31, 2011, include $0.8 million of third-party, legal and accounting fees, which have been expensed as incurred, and $3.6 million of employee-related severance and termination costs.
2010 Unaudited Pro Forma Acquisition Information. Had our acquisition of Encore occurred on January 1, 2010, our combined pro forma revenue and net income (loss) would have been as follows:
Year Ended December 31, | |||||||
In thousands | 2010 | 2009 | |||||
Pro forma total revenues and other income | $ | 2,098,241 | $ | 1,568,050 | |||
Pro forma net income (loss) attributable to Denbury stockholders | 286,891 | (137,227) | |||||
Pro forma net income (loss) per common share: | |||||||
Basic | 0.73 | (0.35) | |||||
Diluted | 0.72 | (0.35) |
Dispositions
2010 Sale of Interests in Genesis. In February 2010, we sold our interest in Genesis Energy, LLC, the general partner of Genesis, for net proceeds of approximately $84 million, after giving effect to the change of control provision of the incentive compensation agreement with Genesis' management, which was triggered and under which we paid a total of $14.9 million. In March 2010, we sold all of our Genesis common units in a secondary public offering for net proceeds of approximately $79 million. We recognized a pre-tax gain of approximately $101.5 million ($63.0 million after tax) on these dispositions.
2010 Sales of Non-strategic Encore Legacy Properties. Pursuant to our plan of divesting non-strategic legacy Encore properties, certain oil and gas properties in the Permian Basin, Mid-continent area and East Texas Basin were sold in May 2010 for consideration of $892.1 million after final closing adjustments. We subsequently divested our production and acreage in the Cleveland Sand Play of western Oklahoma for consideration of $32.1 million after closing adjustments, and the Haynesville and East Texas natural gas properties for consideration of $213.8 million after closing adjustments. In addition to the property sales, we sold our ownership interests in ENP and GP LLC on December 31, 2010. Collectively, we received $1.5 billion in total consideration from these divestitures in 2010. For all Encore legacy property dispositions during 2010, we reduced our full cost pool by the amount of the net proceeds and did not record a gain or loss on the sale in accordance with the full cost method of accounting.
2010 Sale of Ownership Interests in ENP. In December 2010, we sold our ownership interests in ENP, which consisted of our 100% ownership in GP LLC, ENP's general partner, and 20.9 million ENP common units, to a subsidiary of Vanguard for consideration consisting of $300.0 million cash and 3,137,255 Vanguard common units valued at $93.0 million at the time of closing. In addition, Vanguard assumed all of ENP's long-term bank debt of $234.0 million. We have classified the units as available-for-sale securities in “Short-term investments” on the Consolidated Balance Sheets. We did not record a gain or loss on the sale of oil and gas properties in accordance with the full cost method of accounting, nor did we record a gain or loss on the remainder of the net assets sold as the book value approximated fair value.
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Note 3. Asset Retirement Obligations
The following table summarizes the changes in our asset retirement obligations for the years ended December 31, 2011 and 2010:
Year Ended December 31, | |||||||
In thousands | 2011 | 2010 | |||||
Beginning asset retirement obligation | $ | 85,744 | $ | 54,338 | |||
Liabilities incurred and assumed during period | 12,477 | 4,291 | |||||
Liabilities assumed in the Encore Merger | - | 43,783 | |||||
Revisions in estimated retirement obligations | 12,217 | 5,505 | |||||
Liabilities settled during period | (23,225) | (6,622) | |||||
Accretion expense | 6,287 | 6,443 | |||||
Sales of properties | (32) | (21,994) | |||||
Ending asset retirement obligation | 93,468 | 85,744 | |||||
Less: current asset retirement obligation(1) | (4,742) | (4,454) | |||||
Long-term asset retirement obligation | $ | 88,726 | $ | 81,290 | |||
(1) | Included in "Accounts payable and accrued liabilities" in our Consolidated Balance Sheets |
Liabilities incurred and assumed are primarily related to the drilling of incremental wells, during 2011 to the plugging of old wells in the Tinsley Field, and during 2010 to the Encore Merger. Sales of properties during 2010 are primarily related to the disposition of our non-strategic legacy Encore properties and our interests in ENP. The reversal of these asset retirement obligations, which were assumed by the purchasers, was recorded as an adjustment to the full cost pool with no gain or loss recognized, in accordance with the full cost method of accounting.
We have escrow accounts that are legally restricted for certain of our asset retirement obligations. The balances of these escrow accounts were $34.1 million and $33.1 million at December 31, 2011 and 2010, respectively. These balances are recorded at amortized cost and are included in “Other assets” in our Consolidated Balance Sheets. The estimated fair market value of these investments at December 31, 2011 and 2010 approximate cost.
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Note 4. Property and Equipment
The following table presents a summary of our net property and equipment balances as of December 31, 2011 and 2010:
December 31, | ||||||||
In thousands | 2011 | 2010 | ||||||
Oil and natural gas properties | ||||||||
Proved properties | $ | 7,026,579 | $ | 6,042,442 | ||||
Unevaluated properties | 1,157,106 | 870,130 | ||||||
Total | 8,183,685 | 6,912,572 | ||||||
Accumulated depletion and depreciation | (2,407,520) | (2,045,091) | ||||||
Net oil and natural gas properties | 5,776,165 | 4,867,481 | ||||||
CO2 properties | ||||||||
CO2 properties | 596,003 | 522,091 | ||||||
Accumulated depletion and depreciation | (91,666) | (68,479) | ||||||
Net CO2 properties | 504,337 | 453,612 | ||||||
Pipelines and plants | ||||||||
CO2 pipelines in service | 1,277,326 | 1,240,710 | ||||||
CO2 pipelines under construction(1) | 155,320 | 53,922 | ||||||
Plants under construction(1) | 269,110 | 83,607 | ||||||
Total | 1,701,756 | 1,378,239 | ||||||
Accumulated depletion and depreciation | (65,392) | (31,866) | ||||||
Net plants and pipelines | 1,636,364 | 1,346,373 | ||||||
Other property and equipment | ||||||||
Other property and equipment | 157,674 | 121,973 | ||||||
Accumulated depletion and depreciation | (62,915) | (52,081) | ||||||
Net other property and equipment | 94,759 | 69,892 | ||||||
Net property and equipment | $ | 8,011,625 | $ | 6,737,358 | ||||
(1) | Amounts primarily include the Greencore pipeline in southwestern Wyoming, which is expected to be completed in late 2012, and the Riley Ridge gas plant, which is currently expected to be placed in service in the second quarter of 2012. Amounts are excluded from DD&A expense until placed into service. |
A summary of the unevaluated properties excluded from oil and natural gas properties being amortized at December 31, 2011, and the year in which they were incurred follows:
December 31, 2011 | ||||||||||||||||
Costs Incurred During: | ||||||||||||||||
In thousands | 2011 | 2010 | 2009 | 2008 and prior | Total | |||||||||||
Property acquisition costs | $ | 12,543 | $ | 560,314 | $ | 94,969 | $ | 49,566 | $ | 717,392 | ||||||
Exploration and development | 270,062 | 86,251 | 3,758 | 6,682 | 366,753 | |||||||||||
Capitalized interest | 44,853 | 20,958 | 3,228 | 3,922 | 72,961 | |||||||||||
Total | $ | 327,458 | $ | 667,523 | $ | 101,955 | $ | 60,170 | $ | 1,157,106 |
Exploration and development costs shown as unevaluated properties are primarily associated with our tertiary oil fields that are under development but did not have proved reserves at December 31, 2011. The most significant of these costs during 2011 related to Oyster Bayou and Hastings Fields, for which we have initiated CO2 floods but have not yet recognized proved reserves. Our 2010 property acquisition costs were primarily related to the fair value allocated to CO2 tertiary potential at our Bell Creek and Cedar Creek Anticline properties and the undeveloped potential assigned to our Bakken properties, all acquired as part of the Encore Merger. Our 2009 property acquisition costs were primarily related to CO2 tertiary potential at our Conroe Field. Property acquisition costs for 2008 and prior were primarily for CO2 tertiary potential at Oyster Bayou.
During 2011, we established proved reserves in the Williston and Bakken areas, and as a result we transferred $51.2 million of costs incurred on this project into the amortization base. Costs are transferred into the amortization base on an ongoing basis as projects are evaluated and proved reserves established or impairment determined. We review the excluded properties for impairment at least annually. We currently estimate that evaluation of most of these properties and the inclusion of their costs in the amortization base is expected to be completed within five years. Until we are able to determine whether there are any proved reserves attributable to the above costs, we are not able to assess the future impact on the amortization rate of the full cost pool.
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Note 5. Long-Term Debt
The following long-term debt and capital lease obligations were outstanding as of December 31, 2011 and 2010:
December 31, | |||||||
In thousands | 2011 | 2010 | |||||
Bank Credit Agreement | $ | 385,000 | $ | - | |||
7½% Senior Subordinated Notes due 2013, including discount of $437 | - | 224,563 | |||||
7½% Senior Subordinated Notes due 2015, including premium of $427 | - | 300,427 | |||||
9½% Senior Subordinated Notes due 2016, including premium of $11,854 and $14,589, respectively | 236,774 | 239,509 | |||||
9¾% Senior Subordinated Notes due 2016, including discount of $17,854 and $22,139, respectively | 408,496 | 404,211 | |||||
8¼% Senior Subordinated Notes due 2020 | 996,273 | 996,273 | |||||
6⅜% Senior Subordinated Notes due 2021 | 400,000 | - | |||||
Other Subordinated Notes, including premium of $33 and $41, respectively | 3,840 | 3,848 | |||||
NEJD financing | 163,677 | 167,331 | |||||
Free State financing | 79,597 | 81,188 | |||||
Capital lease obligations | 4,388 | 6,806 | |||||
Total | 2,678,045 | 2,424,156 | |||||
Less: current obligations | (8,316) | (7,948) | |||||
Long-term debt and capital lease obligations | $ | 2,669,729 | $ | 2,416,208 |
The parent company, Denbury Resources Inc. (“DRI”), is the sole issuer of all of our outstanding senior subordinated notes. DRI has no independent assets or operations. Each of the subsidiary guarantors is 100% owned by DRI; any subsidiaries of DRI other than the subsidiary guarantors are minor subsidiaries, and the guarantees are full and unconditional and joint and several.
$1.6 Billion Revolving Credit Agreement
In March 2010, we entered into a $1.6 billion revolving credit agreement with JPMorgan Chase Bank, N.A. (“JPMorgan”), as administrative agent, and other lenders as party thereto (the “Bank Credit Agreement”). Availability under the Bank Credit Agreement is subject to a borrowing base, which is redetermined semi-annually on or prior to May 1 and November 1 and upon requested special redeterminations. The borrowing base is adjusted at the banks' discretion and is based in part upon external factors over which we have no control. If the borrowing base were to be less than outstanding borrowings under the Bank Credit Agreement, we would be required to repay the deficit over a period not to exceed four months. As part of the semi-annual review completed in September 2011 pursuant to the terms of the Bank Credit Agreement, our borrowing base was reaffirmed at $1.6 billion. Loans under the Bank Credit Agreement mature in May 2016.
The Bank Credit Agreement is secured by substantially all of the proved oil and natural gas properties of our restricted subsidiaries and by the equity interests of our restricted subsidiaries. In addition, our obligations under the Bank Credit Agreement are guaranteed jointly and severally by all of our subsidiaries, other than minor subsidiaries.
The Bank Credit Agreement contains several restrictive covenants including, among others:
The Bank Credit Agreement also includes a limitation on the aggregate amount of forecasted oil and natural gas production that can be economically hedged with oil or natural gas derivative contracts.
Loans under the Bank Credit Agreement are subject to varying rates of interest based on (1) the total outstanding borrowings in relation to the borrowing base and (2) whether the loan is a Eurodollar loan or a base rate loan. Eurodollar loans bear interest at the Adjusted Eurodollar Rate (as defined in the Bank Credit Agreement) plus the applicable margin of 1.5% to 2.5% based on the ratio of outstanding borrowings to the borrowing base, and base rate loans bear interest at the Base Rate (as defined in the Bank Credit Agreement) plus the applicable margin of 0.5% to 1.5% based on the ratio of outstanding borrowings to the borrowing base. The “Eurodollar rate” for any interest period (either one, two, three, six, nine or twelve months, as selected by us) is the rate per year equal to LIBOR, as published by Reuters or another source designated by JPMorgan, for deposits in dollars for a similar interest period. The “base rate” is calculated as the highest of (1) the annual rate of interest announced by JPMorgan as its “prime rate,” (2) the federal funds effective rate plus 0.5%, and (3) the Adjusted Eurodollar Rate for a one-month interest period plus 1.0%. We incur a commitment fee of either 0.375% or 0.5%, based on the ratio of outstanding borrowings on the borrowing base, on the unused portion of the credit facility or, if less, the borrowing base.
7½% Senior Subordinated Notes due 2013 and 7½% Senior Subordinated Notes due 2015
In March 2003, we issued $225 million of 7½% Senior Subordinated Notes due 2013 (“2013 Notes”). The 2013 Notes, which carried a coupon rate of 7.5%, were sold at 99.135% of par. In December 2005, we issued $150 million of 7½% Senior Subordinated Notes due 2015, which carried a coupon rate of 7.5%, at par. In April 2007, we issued an additional $150 million of 7½% Senior Subordinated Notes due 2015 (collectively the “2015 Notes”) at 100.5% of par, equating to an effective yield to maturity of approximately 7.4%. On March 3, 2011, we purchased in a tender offer $169.6 million in principal of the 2013 Notes at 100.625% of par, and $220.9 million in principal of the 2015 Notes at 104.125% of par. We called the remaining 2013 and 2015 Notes, repurchasing all of the remaining outstanding 2015 Notes ($79.1 million) at 103.75% of par on March 21, 2011, and all of the remaining outstanding 2013 Notes ($55.4 million) at par on April 1, 2011. We recognized a $16.1 million loss during the year ended December 31, 2011 associated with the debt repurchases, which is included in our Unaudited Condensed Consolidated Statements of Operations under the caption “Loss on early extinguishment of debt”.
Supplements to Indentures Governing Encore's Senior Subordinated Notes
On March 9, 2010, upon closing of the Encore Merger, we became an obligor, as successor in interest to Encore, with respect to Encore's senior subordinated notes, which are governed by four indentures covering an aggregate original principal amount of $825 million. In conjunction with the closing of the Encore Merger, we and our subsidiaries other than minor subsidiaries entered into supplemental indentures to become subsidiary guarantors under Encore's senior subordinated notes, as required under the Encore indentures, as well as the indentures governing our senior subordinated notes. The Encore legacy subsidiaries, with permitted exceptions, became guarantors under the indentures that were in effect prior to the Encore Merger.
Tender Offers and Consent Solicitations for Encore's Senior Subordinated Notes; Supplements to Indentures Governing Encore's Senior Subordinated Notes
On March 10, 2010, we purchased in a cash tender offer $500.5 million of $600 million principal amount of Encore's senior subordinated notes that were governed by three of Encore's four indentures, leaving approximately $99.5 million of the $600 million of notes outstanding. Those indentures to which Encore was a party prior to the Encore Merger govern their 6¼% Senior Subordinated Notes due 2014, their 6% Senior Subordinated Notes due 2015 and their 7¼% Senior Subordinated Notes due 2017 (collectively, the “Other Subordinated Notes”).
The tender of the notes also constituted the delivery of consents of holders of the notes to eliminate or modify certain provisions contained in each of the three indentures governing the Other Subordinated Notes, which was sufficient to amend these three Encore indentures effective upon the date of the Encore Merger. The amendments of the three indentures governing the $600 million of Other Subordinated Notes eliminated most of the restrictive covenants and certain events of default in the indentures. The amendments do not apply to the 9½% Senior Subordinated Notes due 2016 (the “9½% Notes”). The Encore indentures required us to effect a second tender offer to repurchase, for 101% of the face amount, the $99.5 million of notes that remained outstanding after completion of the February 8, 2010 tender, plus an initial offer to purchase, for 101% of the face amount, the $225 million of outstanding 9½% Notes. In April 2010, we purchased approximately $95.7 million of these senior subordinated notes, leaving approximately $228.7 million of former Encore notes outstanding.
Encore Indentures
In addition to the three indentures that govern the Other Subordinated Notes, as a result of the Encore Merger, we also became successor in interest to Encore under the Encore indenture with respect to the 9½% Notes in the original principal amount of $225 million. Interest on the 9½% Notes is due semi-annually, on May 1 and November 1, at a rate of 9.5%. The 9½% Notes mature on May 1, 2016. We may redeem the 9½% Notes, in whole or in part at our option beginning May 1, 2013, at the following redemption prices: 104.75% after May 1, 2013, 102.375% after May 1, 2014 and 100% after May 1, 2015. Prior to May 1, 2012, we may, at our option, redeem up to an aggregate of 35% of the principal amount of the 9½% Notes at a price of 109.5% with the proceeds of certain equity offerings. In addition, at any time prior to May 1, 2013, we may redeem 100% of the principal amount of the 9½% Notes at a price equal to 100% of the principal amount plus a “make-whole” premium and accrued and unpaid interest. The material terms of the indenture governing the 9½% Notes include covenants requiring the filing of SEC reports, restricting certain payments, limiting indebtedness, restricting distributions from certain restricted subsidiaries, restricting affiliate transactions, restricting the creation of liens, requiring certain subsidiaries to deliver guarantees of the notes, requiring the delivery of certificates concerning compliance with the indenture, and covenants relating to mergers and consolidations.
All of the Encore indentures, including the indenture governing the 9½% Notes, have covenants limiting the sale of assets and providing a put right by holders upon a change of control, as well as other certain affirmative and negative covenants.
9¾% Senior Subordinated Notes due 2016
In February 2009, we issued $420 million of 9¾% Senior Subordinated Notes due 2016 (“2016 Notes”). The 2016 Notes, which carry a coupon rate of 9.75%, were sold at a discount (92.816% of par), which equates to an effective yield to maturity of approximately 11.25%.
In June 2009, we issued an additional $6.35 million of 2016 Notes to our founder, Gareth Roberts, as part of a Founder's Retirement Agreement. In connection with this issuance, we recorded compensation expense of $6.35 million in “General and administrative” expense in our Consolidated Statement of Operations during the year ended December 31, 2009.
The 2016 Notes mature on March 1, 2016, and interest on the 2016 Notes is payable March 1 and September 1 of each year. We may redeem the 2016 Notes in whole or in part at our option beginning March 1, 2013, at the following redemption prices: 104.875% after March 1, 2013, 102.4375% after March 1, 2014, and 100% after March 1, 2015. In addition, we may, at our option, redeem up to an aggregate of 35% of the 2016 Notes before March 1, 2012, at a price of 109.75%. The indenture governing the 2016 Notes contains certain restrictions on our ability to incur additional debt, pay dividends on our common stock, make investments, create liens on our assets, engage in transactions with our affiliates, transfer or sell assets, consolidate or merge, or sell substantially all of our assets. The 2016 Notes are not subject to any sinking fund requirements. All of our subsidiaries, other than minor subsidiaries, guarantee this debt jointly and severally.
8¼% Senior Subordinated Notes due 2020
In February 2010, we issued $1.0 billion of 8¼% Senior Subordinated Notes due 2020 (the “2020 Notes”), for net proceeds after underwriting discounts and commissions of $980 million. The 2020 Notes, which carry a coupon rate of 8.25%, were sold at par. We subsequently redeemed $3.7 million principal amount of the 2020 Notes, as required under the indenture governing the 2020 Notes. See Tender Offers and Consent Solicitations for Encore's Senior Subordinated Notes; Supplements to Indentures Governing Encore's Senior Subordinated Notes above.
The 2020 Notes mature on February 15, 2020, and interest is payable on February 15 and August 15 of each year. We may redeem the 2020 Notes in whole or in part at our option beginning February 15, 2015, at the following redemption prices: 104.125% after February 15, 2015, 102.75% after February 15, 2016, 101.375% after February 15, 2017, and 100% after February 15, 2018. Prior to February 15, 2013, we may, at our option, redeem up to an aggregate of 35% of the principal amount of the 2020 Notes at a price of 108.25% with the proceeds of certain equity offerings. In addition, at any time prior to February 15, 2015, we may redeem 100% of the principal amount of the 2020 Notes at a price equal to 100% of the principal amount plus a “make-whole” premium and accrued and unpaid interest. The indenture governing the 2020 Notes contains certain restrictions on our ability to incur additional debt, pay dividends on our common stock, make investments, create liens on our assets, engage in transactions with our affiliates, transfer or sell assets, consolidate or merge, or sell substantially all of our assets. The 2020 Notes are not subject to any sinking fund requirements. All of our subsidiaries, other than minor subsidiaries, guarantee this debt jointly and severally.
6⅜% Senior Subordinated Notes due 2021
In February 2011, we issued $400 million of 6⅜% Senior Subordinated Notes due 2021 (“2021 Notes”). The 2021 Notes, which carry a coupon rate of 6.375%, were sold at par. The net proceeds of $393 million were used to repurchase a portion of our 2013 Notes and 2015 Notes (see 7½% Senior Subordinated Notes due 2013 and 7½% Senior Subordinated Notes due 2015 above). The 2021 Notes mature on August 15, 2021, and interest is payable on February 15 and August 15 of each year, beginning August 15, 2011. We may redeem the 2021 Notes in whole or in part at our option beginning August 15, 2016 at the following redemption prices: 103.188% on or after August 15, 2016; 102.125% on or after August 15, 2017; 101.062% on or after August 15, 2018; and 100% on or after August 15, 2019. Prior to August 15, 2014, we may at our option redeem up to an aggregate of 35% of the principal amount of the 2021 Notes at a price of 106.375% with the proceeds of certain equity offerings. In addition, at any time prior to August 15, 2016, we may redeem 100% of the principal amount of the 2021 Notes at a price equal to 100% of the principal amount plus a “make-whole” premium and accrued and unpaid interest. The indenture governing the 2021 Notes contains certain restrictions on our ability to incur additional debt, pay dividends on our common stock, make investments, create liens on our assets, engage in transactions with our affiliates, transfer or sell assets, consolidate or merge, or sell substantially all of our assets. The 2021 Notes are not subject to any sinking fund requirements. All of our subsidiaries, other than minor subsidiaries, guarantee this debt jointly and severally.
NEJD Financing and Free State Financing
In May 2008, we closed two transactions with Genesis involving two of our pipelines. The NEJD pipeline system included a 20-year financing lease, and the Free State Pipeline included a long-term transportation service agreement. We recorded both of these transactions as financing leases.
Debt Issuance Costs
In connection with the issuance of our outstanding long-term debt, the Company has incurred debt issuance costs, which are being amortized to interest expense using the effective interest method over the term of each related facility. Remaining unamortized debt issuance costs were $69.6 million and $74.8 million at December 31, 2011 and 2010, respectively. These balances are included in “Other assets” in our Consolidated Balance Sheets.
Indebtedness Repayment Schedule
At December 31, 2011, our indebtedness, including our capital and financing lease obligations but excluding the discount and premium on our senior subordinated debt, is payable over the next five years and thereafter as follows:
In thousands | ||||
2012 | $ | 8,316 | ||
2013 | 10,148 | |||
2014 | 12,963 | |||
2015 | 10,603 | |||
2016 | 1,046,359 | |||
Thereafter | 1,595,623 | |||
Total indebtedness | $ | 2,684,012 |
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Note 6. Income Taxes
Our income tax provision (benefit) is as follows:
Year Ended December 31, | ||||||||||||
In thousands | 2011 | 2010 | 2009 | |||||||||
Current income tax expense (benefit) | ||||||||||||
Federal | $ | (12,552) | $ | 15,683 | $ | 7,090 | ||||||
State | 20,801 | 17,511 | (2,479) | |||||||||
Total current income tax expense | 8,249 | 33,194 | 4,611 | |||||||||
Deferred income tax expense (benefit) | ||||||||||||
Federal | 329,715 | 143,381 | (50,457) | |||||||||
State | 12,748 | 16,968 | (1,187) | |||||||||
Total deferred income tax expense (benefit) | 342,463 | 160,349 | (51,644) | |||||||||
Total income tax expense (benefit) | $ | 350,712 | $ | 193,543 | $ | (47,033) |
We recognized current state and federal tax benefits during 2011 due to a change in treatment of certain items between our 2010 tax provision and our 2010 filed tax returns that reduced both state and federal current tax expense. This change in treatment resulted in a reclassification of approximately $16.9 million from current to deferred taxes.
At December 31, 2011, we had tax-effected federal net operating loss carryforwards (“NOLs”) totaling $14.0 million, state NOLs totaling $42.0 million, an estimated $53.4 million of enhanced oil recovery credits to carry forward related to our tertiary operations, and $34.8 million of alternative minimum tax credits. Our federal NOLs expire in 2031, while our state NOLs expire in various years, starting in 2015; however, the significant portion of our state NOLs begin to expire in 2023. Our enhanced oil recovery credits will begin to expire in 2023.
To the extent that tax deductions generated by the exercise of stock-based compensation reduce current taxes payable in a given period, a tax benefit is recorded for the excess of the tax deduction over the cumulative book compensation expense as additional paid-in capital. At December 31, 2011, our tax-effected federal tax loss carryforwards were approximately $21.0 million, of which $7.0 million relates to excess tax benefits from exercise of stock-based compensation. The income tax benefit from these stock-based compensation deductions will be recorded as an increase to additional paid-in capital upon utilization of the federal tax loss carryforwards.
Deferred income taxes reflect the available tax carryforwards and the temporary differences based on tax laws and statutory rates in effect at the December 31, 2011 and 2010 balance sheet dates. We believe that we will be able to realize all of our deferred tax assets at December 31, 2011, and therefore have provided no valuation allowance against our deferred tax assets.
Significant components of our deferred tax assets and liabilities as of December 31, 2011 and 2010 are as follows:
December 31, | |||||||||
In thousands | 2011 | 2010 | |||||||
Deferred tax assets: | |||||||||
Loss carryforwards — federal | $ | 13,970 | $ | - | |||||
Loss carryforwards — state | 41,960 | 44,595 | |||||||
Tax credit carryover | 34,829 | 34,476 | |||||||
Derivative contracts | 3,551 | 24,918 | |||||||
Enhanced oil recovery credit carryforwards | 53,381 | 39,810 | |||||||
Stock based compensation | 32,566 | 38,947 | |||||||
Other | 35,279 | 45,950 | |||||||
Total deferred tax assets | 215,536 | 228,696 | |||||||
Deferred tax liabilities: | |||||||||
Property and equipment | (2,078,143) | (1,738,269) | |||||||
Other | (5,813) | (10,965) | |||||||
Total deferred tax liabilities | (2,083,956) | (1,749,234) | |||||||
Total net deferred tax liability | $ | (1,868,420) | $ | (1,520,538) |
Our reconciliation of income tax expense (benefit) computed by applying the U.S. federal statutory rate and the reported effective tax rate on income (loss) from continuing operations is as follows:
Year Ended December 31, | |||||||||||
In thousands | 2011 | 2010 | 2009 | ||||||||
Income tax provision (benefit) calculated using the federal statutory income tax rate | $ | 323,416 | $ | 167,674 | $ | (42,765) | |||||
State income taxes, net of federal income tax benefit | 29,555 | 13,087 | (3,666) | ||||||||
Revaluation of deferred tax liabilities, net | (578) | 11,502 | - | ||||||||
Other | (1,681) | 1,280 | (602) | ||||||||
Total income tax expense (benefit) | $ | 350,712 | $ | 193,543 | $ | (47,033) |
In the third quarter of 2008, we obtained approval from the National Office of the Internal Revenue Service (“IRS”) to change our method of tax accounting for certain assets used in our tertiary oilfield recovery operations. As a result of the approved change in method of tax accounting, beginning with the 2007 tax year we began to deduct, rather than capitalize, such costs for tax purposes, and applied for tax refunds associated with such change for our 2004 and 2006 tax years. Notwithstanding its consent to our change in tax accounting in 2008, the IRS exercised its prerogative to challenge the tax accounting method we used. In late January 2011, we received a Technical Advice Memorandum (“TAM”) issued by the IRS National Office disapproving our method of accounting and revoking its consent to our change, on a prospective basis only, commencing January 1, 2011. Beginning with the 2011 tax year, we returned to capitalizing and depreciating the costs of these assets for tax purposes. As a result of the prospective nature of the IRS's determination, there was no change in our position with respect to the deductibility of these costs for 2007, 2008, 2009 and 2010. In December 2011, we received notification from the IRS that the review process was completed and that all issues related to the TAM were settled without further adjustments. Refund claims of $10.6 million for tax years through 2006 were received, plus accrued interest, in early 2012.
Uncertain Tax Positions
During 2011, as a result of settling the IRS audit through 2008, we removed the remaining uncertain tax position benefits of $0.2 million. Total unrecognized tax benefits were $0.2 million and $1.0 million as of December 31, 2010 and 2009, respectively. Our previously recognized uncertain tax positions related primarily to timing differences and did not materially impact our effective tax rate.
We file consolidated and separate income tax returns in the U.S. federal jurisdiction and in many state jurisdictions. The IRS concluded its examination of the Company's 2006, 2007 and 2008 tax years during the fourth quarter of 2011 with no adjustments. In the fourth quarter of 2011, the IRS began its audit of Encore Acquisition Company and Subsidiaries, including Encore Operating LP, for the open tax years 2008, 2009 and 2010. The IRS has audited Encore Acquisition Company and Subsidiaries through tax year 2007. We are currently under examination by the state of Mississippi for the 2004, 2005, 2006 and 2007 tax years. We are also concurrently under examination by the state of Oklahoma for the 2010 tax year. We have not paid any significant interest or penalties associated with our income taxes, but classify both interest expense and penalties as part of our income tax expense.
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Note 7. Stockholders' Equity
Stock Repurchase Program
In October 2011, we commenced a common share repurchase program for up to $500 million of Denbury common shares, as approved by the Company's Board of Directors. The program has no pre-established ending date, and may be suspended or discontinued at any time. We are not obligated to repurchase any dollar amount or specific number of shares of our common stock under the program. Between early October 2011 and December 31, 2011, we repurchased 14,112,610 shares of Denbury common stock (approximately 3.5% of our outstanding shares of common stock at September 30, 2011) at a cost of $195.2 million or $13.83 per share under this share repurchase program.
Our remaining share repurchases during 2011, and all of our share repurchases during 2010 and 2009 were from our employees who surrendered shares to the Company to satisfy their minimum tax withholding requirements as provided for under our stock compensation plans and were not part of a formal stock repurchase plan.
Employee Stock Purchase Plan
We have an Employee Stock Purchase Plan that is authorized to issue up to 9,900,000 shares of common stock. As of December 31, 2011, there were 1,277,516 authorized shares remaining to be issued under the plan. In accordance with the plan, eligible employees may contribute up to 10% of their base salary, and we match 75% of their contribution. The combined funds are used to purchase previously unissued Denbury common stock or treasury stock that we purchased in the open market for that purpose, in either case, based on the market value of our common stock at the end of each quarter. We recognize compensation expense for the 75% Company match portion, which totaled $4.8 million, $3.5 million and $3.1 million for the years ended December 31, 2011, 2010 and 2009, respectively. This plan is administered by the Compensation Committee of our Board of Directors.
401(k) Plan
We offer a 401(k) plan to which employees may contribute tax-deferred earnings subject to IRS limitations. We match 100% of an employee's contribution, up to 6% of compensation, as defined by the plan, which is vested immediately. During 2011, 2010 and 2009, our matching contributions to the 401(k) Plan were approximately $7.1 million, $5.7 million and $4.0 million, respectively.
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Note 8. Stock Compensation Plans
Stock Incentive Plans
We have two stock compensation plans. The first plan has been in existence since 1995 (the “1995 Plan”) and expired in August 2005 (although options granted under the 1995 Plan prior to that time can remain outstanding for up to 10 years). The 1995 Plan provided only for the issuance of stock options, and in January 2005 we issued stock options under the 1995 Plan that utilized substantially all of the remaining authorized shares. The second plan, the 2004 Omnibus Stock and Incentive Plan (the “2004 Plan”), has a 10-year term and was approved by the stockholders in May 2004. The 2004 Plan provides for the issuance of incentive and non-qualified stock options, restricted stock awards, stock appreciation rights (“SARs”) settled in stock, and performance awards that may be issued to officers, employees, directors and consultants. Awards covering a total of 29.5 million shares of common stock are authorized for issuance pursuant to the 2004 Plan, of which awards covering no more than 22.2 million shares may be issued in the form of restricted stock or performance vesting awards. At December 31, 2011, 9,700,640 shares were available under the 2004 Plan for future issuance of awards, all of which could be issued in the form of restricted stock or performance vesting awards. Our incentive compensation program is administered by the Compensation Committee of our Board of Directors.
Prior to January 1, 2006, we granted incentive and non-qualified stock options to our employees. Effective January 1, 2006, we completely replaced the use of stock options for employees with SARs settled in stock, as SARs are less dilutive to our stockholders while providing an employee with essentially the same economic benefits as stock options. The stock options and SARs generally become exercisable over a four-year vesting period, with the specific terms of vesting determined at the time of grant based on guidelines established by the Board of Directors. The stock options and SARs expire over terms not to exceed 10 years from the date of grant, 90 days after termination of employment, 90 days or one year after permanent disability, depending on the plan, or one year after the death of the optionee. The stock options and SARs are granted at the fair market value at the time of grant, which is defined in the 2004 Plan as the closing price on the NYSE on the date of grant.
In 2004, we began the use of restricted stock awards. The holders of these shares have the rights and privileges of owning the shares (including voting rights) except that the holders are not entitled to delivery of a portion thereof until certain requirements are met. Restricted stock awards vest over three-to-four-year vesting periods, with the specific terms of vesting determined at the time of grant.
Beginning in 2007, the Board of Directors has awarded an annual grant of performance equity awards to officers of Denbury. These performance-based shares originally vested over 3.25 years, but beginning with awards granted in 2009, the vesting period was 1.25 years. The number of performance-based shares earned (and eligible to vest) during the performance period will depend on the Company's level of success in achieving four specifically identified performance targets. Generally, one-half of the maximum number of shares that could be earned under the performance-based awards will be earned for performance at the designated target levels (100% target vesting levels) or upon any earlier change of control, and twice the number of shares will be earned if the higher maximum target levels are met. If performance is below the designated minimum levels for all performance targets, no performance-based shares will be earned. Any portion of the performance shares that are not earned by the end of the measurement period will be forfeited. In certain change of control events, one-half (i.e., the target level amount) of the performance-based shares would vest.
Stock-based compensation expense associated with our field employees is included in “Lease operating expense,” while such expense associated with non-field employees is included in “General and administrative expense” in the Consolidated Statements of Operations. Stock-based compensation associated with Encore Merger transition employees is included in “Transaction and other costs related to the Encore Merger” in the Consolidated Statements of Operations. Stock-based compensation associated with our employees involved in exploration and drilling activities is capitalized as part of “Oil and natural gas properties” in the Consolidated Balance Sheets.
Stock-based compensation costs for the years ended December 31, 2011, 2010 and 2009, respectively, are as follows:
Year Ended December 31, | |||||||||||
In thousands | 2011 | 2010 | 2009 | ||||||||
Stock-based compensation expensed: | |||||||||||
General and administrative expense | $ | 30,256 | $ | 28,169 | $ | 20,435 | |||||
Lease operating expense | 2,621 | 2,056 | 1,432 | ||||||||
Transaction and other costs related to the Encore Merger | 313 | 5,866 | - | ||||||||
Total stock-based compensation expensed | 33,190 | 36,091 | 21,867 | ||||||||
Stock-based compensation capitalized | 6,998 | 3,702 | 2,455 | ||||||||
Total cost of stock-based compensation arrangements | $ | 40,188 | $ | 39,793 | $ | 24,322 | |||||
Income tax benefit recognized for stock-based compensation arrangements | $ | 12,902 | $ | 14,359 | $ | 8,749 |
Stock Options and SARs
The fair value of each SAR award is estimated on the date of grant using the Black-Scholes option pricing model with the assumptions noted in the following table. The risk-free rate for periods within the contractual life of the option is based on the U.S. Treasury yield curve in effect at the time of grant. The expected life of stock options and SARs granted was derived from examination of our historical option grants and subsequent exercises. The contractual terms (cliff vesting and graded vesting) are evaluated separately for the expected life, as the exercise behavior for each is different. Expected volatilities are based on the historical volatility of our stock. Implied volatility was not used in this analysis, as our tradable call option terms are short and the trading volume is low. Our dividend yield is zero, as we do not pay a dividend.
2011 | 2010 | 2009 | ||||||||
Weighted average fair value of SARs granted | $ | 9.68 | $ | 8.45 | $ | 6.40 | ||||
Risk-free interest rate | 1.74% | 2.19% | 1.58% | |||||||
Expected life | 4.0 to 5.0 years | 4.0 to 4.3 years | 3.9 to 4.7 years | |||||||
Expected volatility | 63.3% | 65.0% | 60.1% | |||||||
Dividend yield | - | - | - |
The following is a summary of our stock option and SAR activity:
Year Ended December 31, | |||||||||||||||
2011 | 2010 | 2009 | |||||||||||||
Weighted | Weighted | Weighted | |||||||||||||
Number | Average | Number | Average | Number | Average | ||||||||||
of Awards | Exercise Price | of Awards | Exercise Price | of Awards | Exercise Price | ||||||||||
Outstanding at beginning of period | 12,269,340 | $ | 12.28 | 10,763,955 | $ | 10.77 | 9,514,999 | $ | 9.32 | ||||||
Granted | 1,507,992 | 18.69 | 3,444,494 | 16.30 | 2,883,311 | 13.23 | |||||||||
Exercised | (1,448,358) | 6.97 | (1,119,853) | 6.21 | (1,315,535) | 4.33 | |||||||||
Forfeited or expired | (379,364) | 17.89 | (819,256) | 17.57 | (318,820) | 16.36 | |||||||||
Outstanding at end of period | 11,949,610 | 13.56 | 12,269,340 | 12.28 | 10,763,955 | 10.77 | |||||||||
Exercisable at end of period | 6,179,154 | $ | 10.18 | 6,214,546 | $ | 8.07 | 6,087,019 | $ | 6.48 |
The total intrinsic value of stock options and SARs exercised during the years ended December 31, 2011, 2010 and 2009, was approximately $20.5 million, $12.7 million and $14.8 million, respectively. The total grant-date fair value of stock options and SARs vested during the years ended December 31, 2011, 2010 and 2009, was approximately $11.4 million, $8.7 million and $10.1 million, respectively. The aggregate intrinsic value of stock options and SARs outstanding at December 31, 2011, was approximately $39.9 million, and these options and SARs have a weighted-average remaining contractual life of 4.2 years. The aggregate intrinsic value of options and SARs exercisable at December 31, 2011, was approximately $35.8 million, and these stock options and SARs have a weighted-average remaining contractual life of 3.4 years.
A summary of the status of our non-vested stock options and SARs as of December 31, 2011, and the changes during the year ended December 31, 2011, is presented below:
Weighted | |||||
Average | |||||
Grant-Date | |||||
Awards | Fair Value | ||||
Non-vested at December 31, 2010 | 6,054,794 | $ | 8.02 | ||
Granted | 1,507,992 | 9.68 | |||
Vested | (1,452,626) | 7.85 | |||
Forfeited | (339,704) | 8.87 | |||
Non-vested at December 31, 2011 | 5,770,456 | 8.44 |
As of December 31, 2011, there was $20.4 million of total compensation cost to be recognized in future periods related to non-vested stock option and SAR share-based compensation arrangements. The cost is expected to be recognized over a weighted-average period of 2.2 years. Cash received from stock option exercises under share-based payment arrangements for the years ended December 31, 2011, 2010 and 2009, was $4.7 million, $4.9 million and $5.7 million, respectively. The tax benefit realized from the exercises of stock options and SARs totaled $0.9 million for 2011, $4.6 million for 2010, and $3.1 million for 2009.
Restricted Stock – 2004 Plan
As of December 31, 2011, there was $22.3 million of unrecognized compensation expense related to non-vested restricted stock grants. This unrecognized compensation cost is expected to be recognized over a weighted-average period of 2.6 years. The total vesting date fair value of restricted stock vested during the years ended December 31, 2011, 2010 and 2009 under the 2004 Plan was $12.4 million, $12.7 million and $10.0 million, respectively.
A summary of the status of our non-vested restricted stock grants and the changes during the year ended December 31, 2011, is presented below:
Weighted | |||||
Average | |||||
Grant-Date | |||||
Shares | Fair Value | ||||
Non-vested at December 31, 2010 | 2,948,834 | $ | 13.70 | ||
Granted | 1,134,627 | 18.83 | |||
Vested | (818,215) | 15.89 | |||
Forfeited | (133,811) | 17.74 | |||
Non-vested at December 31, 2011 | 3,131,435 | 14.82 |
Restricted Stock – Legacy Encore Plan
In February 2010, prior to the consummation of the Encore Merger, Encore issued a restricted stock grant to its employees under the Encore Acquisition Company 2008 Incentive Stock Plan (“Encore Plan”). At the time of the Encore Merger, the shares were converted to shares of Denbury restricted stock. The shares vest ratably over a four-year graded vesting period; however, legacy Encore employees who terminate their employment for Good Reason, as defined by Encore's legacy Employee Severance Protection Plan, will automatically vest in their awards upon termination. Encore employees who did not accept permanent positions with Denbury but who continued their employment through a predefined transition period were considered to have terminated for Good Reason and, accordingly, vested in their awards upon termination. As of December 31, 2011, there was $2.3 million of unrecognized compensation expense related to non-vested restricted stock issued under the Encore Plan, which is expected to be recognized over a weighted-average period of 2.0 years. The total vesting date fair value of restricted stock vested during the years ended December 31, 2011 and 2010 under the Encore Plan was $2.3 million and $6.6 million, respectively.
A summary of the status of the non-vested restricted stock grants under the Encore Plan and the changes during the year ended December 31, 2011, is presented below:
Weighted | |||||
Average | |||||
Grant-Date | |||||
Shares | Fair Value | ||||
Non-vested at December 31, 2010 | 276,620 | $ | 15.42 | ||
Granted | - | - | |||
Vested | (149,577) | 15.43 | |||
Forfeited | (24,000) | 15.43 | |||
Non-vested at December 31, 2011 | 103,043 | 15.43 |
Performance Equity Awards
During 2011, we granted performance-based equity awards (214,627 shares reflecting the 100% targeted vesting level) to the Company's officers, with an average grant-date fair value of $18.71 per share. The actual number of shares to be delivered pursuant to the performance-based awards could range from zero to 200% (429,254 shares) of the stated 100% targeted amount, although we currently estimate that shares to be delivered will approximate 56% of the targeted amount. During 2011, the performance-based equity awards originally granted in 2008 vested at 120% of their original targeted amount, resulting in the issuance of 115,056 shares of Denbury stock with a weighted average grant date fair value of $31.47 per share. Also during 2011, the performance-based equity awards originally granted in 2010 vested at 162% of their originally targeted amount, resulting in the issuance of 331,331 shares of Denbury stock with a weighted average grant-date fair value of $15.63 per share. The total vesting date fair value of performance-based equity awards during the years ended December 31, 2011 and 2010 was $10.9 million and $7.5 million, respectively. The Company recognizes compensation expense when it becomes probable that the performance criteria specified in the plan will be achieved.
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Note 9. Derivative Instruments and Hedging Activities
Oil and Natural Gas Derivative Contracts
We do not apply hedge accounting treatment to our oil and natural gas derivative contracts; therefore, the changes in the fair values of these instruments are recognized in income in the period of change. These fair value changes, along with the cash settlements of expired contracts, are shown under “Derivatives expense (income)” in our Consolidated Statements of Operations.
From time to time, we enter into various oil and natural gas derivative contracts to provide an economic hedge of our exposure to commodity price risk associated with anticipated future oil and natural gas production. We do not hold or issue derivative financial instruments for trading purposes. These contracts have consisted of price floors, collars and fixed price swaps. The production that we hedge has varied from year to year depending on our levels of debt and financial strength and expectation of future commodity prices. We currently employ a strategy to hedge a portion of our forecasted production approximately 12 to 15 months in advance, as we believe it is important to protect our future cash flow to provide a level of assurance for our capital spending in those future periods in light of current worldwide economic uncertainties and commodity price volatility.
The following is a summary of “Derivatives expense (income)” included in our Consolidated Statements of Operations:
Year Ended December 31, | |||||||||||
In thousands | 2011 | 2010 | 2009 | ||||||||
Oil | |||||||||||
Payment (receipt) on settlements of derivative contracts | $ | 25,128 | $ | 93,417 | $ | (146,734) | |||||
Fair value adjustments to derivative contracts – expense (income) | (58,980) | (44,441) | 375,750 | ||||||||
Total derivative expense (income) – oil | (33,852) | 48,976 | 229,016 | ||||||||
Natural gas | |||||||||||
Payment (receipt) on settlements of derivative contracts | (27,505) | (61,805) | - | ||||||||
Fair value adjustments to derivative contracts – expense (income) | 8,860 | (8,585) | 7,210 | ||||||||
Total derivative expense (income) – natural gas | (18,645) | (70,390) | 7,210 | ||||||||
Ineffectiveness on interest rate swaps | - | (2,419) | - | ||||||||
Derivative expense (income) | $ | (52,497) | $ | (23,833) | $ | 236,226 |
Commodity Derivative Contracts Not Classified as Hedging Instruments | ||||||||||||||||||||
Contract Prices(1) | ||||||||||||||||||||
Type of | Weighted Average Price(2) | |||||||||||||||||||
Year | Months | Contract | Volume(1) | Range | Swap | Floor | Ceiling | |||||||||||||
Oil Contracts: | ||||||||||||||||||||
2012 | Jan – Mar | Swap | 625 | $ | 80.28 – 81.75 | $ | 81.04 | $ | - | $ | - | |||||||||
Collar | 52,000 | 70.00 – 139.60 | - | 70.00 | 106.86 | |||||||||||||||
Put | 625 | 65.00 – 65.00 | - | 65.00 | - | |||||||||||||||
Total Jan – Mar 2012 | 53,250 | |||||||||||||||||||
Apr – June | Swap | 625 | $ | 80.28 – 81.75 | $ | 81.04 | $ | - | $ | - | ||||||||||
Collar | 53,000 | 70.00 – 137.50 | - | 70.00 | 119.44 | |||||||||||||||
Put | 625 | 65.00 – 65.00 | - | 65.00 | - | |||||||||||||||
Total Apr – June 2012 | 54,250 | |||||||||||||||||||
July – Sept | Swap | 625 | $ | 80.28 – 81.75 | $ | 81.04 | $ | - | $ | - | ||||||||||
Collar | 53,000 | 80.00 – 140.65 | - | 80.00 | 128.57 | |||||||||||||||
Put | 625 | 65.00 – 65.00 | - | 65.00 | - | |||||||||||||||
Total July – Sept 2012 | 54,250 | |||||||||||||||||||
Oct – Dec | Swap | 625 | $ | 80.28 – 81.75 | $ | 81.04 | $ | - | $ | - | ||||||||||
Collar | 53,000 | 80.00 – 140.65 | - | 80.00 | 128.57 | |||||||||||||||
Put | 625 | 65.00 – 65.00 | - | 65.00 | - | |||||||||||||||
Total Oct – Dec 2012 | 54,250 | |||||||||||||||||||
2013 | Jan – Mar | Swap | - | $ | - | $ | - | $ | - | $ | - | |||||||||
Collar | 55,000 | 70.00 – 117.00 | - | 70.00 | 110.32 | |||||||||||||||
Put | - | - | - | - | - | |||||||||||||||
Total Jan – Mar 2013 | 55,000 | |||||||||||||||||||
Apr – June | Swap | - | $ | - | $ | - | $ | - | $ | - | ||||||||||
Collar | 42,000 | 75.00 – 118.00 | - | 75.00 | 115.91 | |||||||||||||||
Put | - | - | - | - | - | |||||||||||||||
Total Apr – June 2013 | 42,000 | |||||||||||||||||||
Natural Gas Contracts: | ||||||||||||||||||||
2012 | Jan – Dec | Swap | 20,000 | $ | 6.30 – 6.85 | $ | 6.53 | $ | - | $ | - | |||||||||
Collar | - | - | - | - | - | |||||||||||||||
Put | - | - | - | - | - | |||||||||||||||
Total Jan – Dec 2012 | 20,000 | |||||||||||||||||||
(1) | Contract volumes are stated in BBl/d and MMBtu/d for oil and natural gas contracts, respectively. | |||||||||||||||||||
(2) | Contract prices are stated in $/BBl and $/MMBtu for oil and natural gas contracts, respectively. |
Additional Disclosures about Derivative Instruments:
At December 31, 2011 and 2010, we had derivative financial instruments recorded in our Consolidated Balance Sheets as follows:
Estimated Fair Value | |||||||||||
Asset (Liability) | |||||||||||
December 31, | |||||||||||
Type of Contract | Balance Sheet Location | 2011 | 2010 | ||||||||
In thousands | |||||||||||
Derivatives not designated as hedging instruments: | |||||||||||
Derivative Assets | |||||||||||
Crude oil contracts | Derivative assets – current | $ | 23,452 | $ | 3,050 | ||||||
Natural gas contracts | Derivative assets – current | 23,950 | 21,192 | ||||||||
Crude oil contracts | Derivative assets – long-term | 29 | 1,301 | ||||||||
Natural gas contracts | Derivative assets – long-term | - | 11,618 | ||||||||
Derivative Liabilities | |||||||||||
Crude oil contracts | Derivative liabilities – current | (22,610) | (55,256) | ||||||||
Natural gas contracts | Derivative liabilities – current | - | - | ||||||||
Deferred premiums(1) | Derivative liabilities – current | (3,913) | (22,928) | ||||||||
Crude oil contracts | Derivative liabilities – long-term | (18,702) | (25,906) | ||||||||
Natural gas contracts | Derivative liabilities – long-term | - | - | ||||||||
Deferred premiums(1) | Derivative liabilities – long-term | (170) | (3,781) | ||||||||
Total derivatives not designated as hedging instruments | $ | 2,036 | $ | (70,710) | |||||||
(1) | Deferred premiums payable relate to various oil and natural gas floor contracts and are payable on a monthly basis through December 2012. |
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Note 10. Fair Value Measurements
Fair value is the price that would be received to sell an asset or would be paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). We utilize market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated or generally unobservable. We primarily apply the market approach for recurring fair value measurements and endeavor to utilize the best available information. Accordingly, we utilize valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. We are able to classify fair value balances based on the observability of those inputs. The FASC establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). The three levels of the fair value hierarchy are as follows:
We adjust the valuations from the valuation model for nonperformance risk, using our estimate of the counterparty's credit quality for asset positions and Denbury's credit quality for liability positions. Denbury uses multiple sources of third-party credit data in determining counterparty nonperformance risk, including credit default swaps.
The following table sets forth by level within the fair value hierarchy our financial assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2011 and 2010:
Fair Value Measurements Using: | ||||||||||||||
Significant | ||||||||||||||
Quoted Prices | Other | Significant | ||||||||||||
in Active | Observable | Unobservable | ||||||||||||
Markets | Inputs | Inputs | ||||||||||||
In thousands | (Level 1) | (Level 2) | (Level 3) | Total | ||||||||||
December 31, 2011 | ||||||||||||||
Assets: | ||||||||||||||
Short-term investments | $ | 86,682 | $ | - | $ | - | $ | 86,682 | ||||||
Oil and natural gas derivative contracts | - | 23,481 | 23,950 | 47,431 | ||||||||||
Liabilities: | ||||||||||||||
Oil and natural gas derivative contracts | - | (41,312) | - | (41,312) | ||||||||||
Total | $ | 86,682 | $ | (17,831) | $ | 23,950 | $ | 92,801 | ||||||
December 31, 2010 | ||||||||||||||
Assets: | ||||||||||||||
Short-term investments | $ | 93,020 | $ | - | $ | - | $ | 93,020 | ||||||
Oil and natural gas derivative contracts | - | 20,683 | 16,478 | 37,161 | ||||||||||
Liabilities: | ||||||||||||||
Oil and natural gas derivative contracts | - | (81,162) | - | (81,162) | ||||||||||
Total | $ | 93,020 | $ | (60,479) | $ | 16,478 | $ | 49,019 |
The following table summarizes the changes in the fair value of our Level 3 assets and liabilities for the years ended December 31, 2011 and 2010:
Year Ended December 31, | ||||||||
In thousands | 2011 | 2010 | ||||||
Fair value of Level 3 instruments, beginning of year | $ | 16,478 | $ | - | ||||
Commodity derivative contracts acquired in Encore Merger | - | 38,093 | ||||||
Unrealized gains (losses) on commodity derivative contracts included in earnings | 13,384 | 21,240 | ||||||
Receipts on settlement of commodity derivative contracts | (5,912) | (42,855) | ||||||
Fair value of Level 3 instruments, end of year | $ | 23,950 | $ | 16,478 | ||||
The amount of total gains for the period included in earnings attributable to the change in | ||||||||
unrealized gains relating to assets still held at the reporting date | $ | 13,384 | $ | 21,240 |
Since we do not use hedge accounting for our commodity derivative contracts, any gains and losses on our assets and liabilities are included in “Derivatives expense (income)” in the accompanying Consolidated Statements of Operations.
The carrying value of our revolving bank credit facility approximates fair value, as it is subject to short-term floating interest rates that approximate the rates available to us for those periods. The fair values of our senior subordinated notes are based on quoted market prices. The estimated fair value of our total long-term debt as of December 31, 2011 and 2010 is $2,638.2 million and $2,348.7 million, respectively. We have other financial instruments consisting primarily of cash, cash equivalents, short-term receivables and payables that approximate fair value due to the nature of the instrument and the relatively short maturities.
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Note 11. Commitments and Contingencies
Leases
We lease office space, equipment and vehicles that have non-cancelable lease terms. Leases entered into during 2011 have terms up to eleven years. Lease payments associated with these operating leases were $52.3 million, $42.4 million and $37.6 million in 2011, 2010 and 2009, respectively. We have subleased part of the office space included in our operating leases for which we received approximately $2.4 million, $0.5 million and $0.6 million in 2011, 2010 and 2009, respectively. In addition, we expect to receive approximately $2.0 million for 2012 and $0.3 million for 2013 under these sublease agreements.
The following table summarizes by year the remaining non-cancelable future payments under these operating leases as of December 31, 2011:
Pipeline | |||||||||||
Financing | Capital | Operating | |||||||||
In thousands | Leases | Leases | Leases | ||||||||
2012 | $ | 30,689 | $ | 2,206 | $ | 36,207 | |||||
2013 | 32,469 | 1,447 | 37,509 | ||||||||
2014 | 34,036 | 664 | 34,369 | ||||||||
2015 | 31,847 | 106 | 33,536 | ||||||||
2016 | 30,912 | 106 | 31,349 | ||||||||
Thereafter | 344,233 | 510 | 74,269 | ||||||||
Total minimum lease payments | 504,186 | 5,039 | $ | 247,239 | |||||||
Less: Amount representing interest | (260,912) | (651) | |||||||||
Present value of minimum lease payments | $ | 243,274 | $ | 4,388 |
Commitments
We have entered into four long-term purchase commitments to purchase CO2 that are either non-cancelable or cancelable only upon the occurrence of specified future events. The commitments begin as early as 2012 and continue for up to 16 years. The price we will pay for CO2 varies depending on the amount of CO2 delivered and the price of oil. We anticipate the contracts will provide us with approximately 200 MMcf/d to 375 MMcf/d of CO2 at a cost of approximately $75 million – $135 million per year, assuming a $100 per Bbl NYMEX oil price. We have invested a total of $13.8 million in preferred stock of a proposed plant from which we would offtake CO2. All of our investment may later be redeemed, with a return or converted to equity after construction financing for the project has been obtained. We have recorded our investment in this security at cost and classified it as held-to-maturity, since we have the intent and ability to hold it until it is redeemed. The developer of the proposed plant is soliciting other potential investors for the project, and a third-party is currently engaged in due diligence. The investment is included in “Other assets” in our Consolidated Balance Sheets.
In conjunction with the August 1, 2011 Riley Ridge acquisition, we assumed the 20-year helium supply contract under which the original participants in Riley Ridge agreed to supply helium to a third-party purchaser. Subsequently, we amended this contract to provide for annual delivery (to the 8/8ths working interest) of 127 MMcf of helium (previously 200 MMcf) during the first two years of the contract and thereafter to provide for delivery of 400 MMcf per year. If the contracted quantity of helium is not supplied, we are obligated to compensate the third-party helium purchaser for the amount of the shortfall in an amount not to exceed $8.0 million per year.
Under the terms of our agreement to purchase Hastings Field in February 2009, we are required to make capital expenditures in Hastings Field of approximately $179 million prior to December 31, 2014. If we fail to spend certain amounts by specified interim due dates, we are required to make a cash payment equal to 10% of the cumulative shortfall at each applicable date. Further, we are committed to inject at least an average of 50 MMcf/day of CO2 (total of purchased and recycled) in the West Hastings Unit for the 90-day period prior to January 1, 2013. If such injections do not occur, we must either (1) relinquish our rights to initiate (or continue) tertiary operations and reassign to the seller all assets previously purchased for the value of such assets at that time based upon the discounted value of the field's proved reserves using a 20% discount rate, or (2) make an additional payment of $20 million in January 2013, less any payments made for failure to meet the capital spending requirements as of December 31, 2012, and a $30 million payment for each subsequent year (less amounts paid for capital expenditure shortfalls) until the CO2 injection rate in the Hastings Field equals or exceeds the minimum required injection rate. At December 31, 2011, we are, and believe that we will continue to be, compliant with both of these commitments.
We are party to long-term contracts that require us to deliver CO2 to our industrial CO2 customers at various contracted prices, plus we have a CO2 delivery obligation to Genesis related to three CO2 volumetric production payments (“VPPs”). See Note 13, Related Party Transactions – Genesis. Based upon the maximum amounts deliverable as stated in the industrial contracts and the volumetric production payments, we estimate that we may be obligated to deliver up to 327 Bcf of CO2 to these customers over the next 14 years; however, since the group as a whole has historically purchased less CO2 than the maximum allowed in their contracts, based on the current level of deliveries, we project that the amount of CO2 that we will ultimately be required to deliver would likely be reduced to 240 Bcf. The maximum volume required in any given year is approximately 109 MMcf/d. Given the size of our Jackson Dome proven CO2 reserves at December 31, 2011 (approximately 6.7 Tcf before deducting approximately 84.7 Bcf for the three VPPs), our current production capabilities and our projected levels of CO2 usage for our own tertiary flooding program, we believe that we can meet these contractual delivery obligations.
Litigation
We are involved in various lawsuits, claims and regulatory proceedings incidental to our businesses. While we currently believe that the ultimate outcome of these proceedings, individually and in the aggregate, will not have a material adverse effect on our financial position or overall trends in results of operations or cash flows, litigation is subject to inherent uncertainties. If an unfavorable ruling were to occur, there exists the possibility of a material adverse impact on our net income in the period in which the ruling occurs. We provide accruals for litigation and claims if we determine that a loss is probable and the amount can be reasonably estimated.
Other Contingencies
We are subject to audits in the various states in which we operate for sales and use taxes and severance taxes, and from time to time receive assessments for potential taxes that we may owe. In the past, settlement of these matters has not had a material adverse financial impact on us, and currently we have no material assessments for potential taxes.
We are subject to various possible contingencies that arise primarily from interpretation of federal and state laws and regulations affecting the oil and natural gas industry. Such contingencies include differing interpretations as to the prices at which oil and natural gas sales may be made, the prices at which royalty owners may be paid for production from their leases, environmental issues and other matters. Although we believe that we have complied with the various laws and regulations, administrative rulings and interpretations thereof, adjustments could be required as new interpretations and regulations are issued. In addition, production rates, marketing and environmental matters are subject to regulation by various federal and state agencies.
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Note 12. Supplemental Information
Significant Oil and Natural Gas Purchasers
Oil and natural gas sales are made on a day-to-day basis or under short-term contracts at the current area market price. We do not expect that the loss of any purchaser would have a material adverse effect upon our operations. For the years ended December 31, 2011 and 2010, two purchasers accounted for 10% or more of our oil and natural gas revenues: Marathon Petroleum Company LLC (43% in 2011 and 46% in 2010) and Plains Marketing LP (16% in 2011 and 14% in 2010). For the year ended December 31, 2009, two purchasers accounted for 10% or more of our oil and natural gas revenues: Marathon Petroleum Company LLC (52%) and Hunt Crude Oil Supply Co. (21%).
Allowance for Doubtful Accounts
The Company records an allowance for doubtful accounts for receivables that the Company determines to be uncollectible based on the specific identification basis. The allowance for doubtful accounts, which is netted against “Trade and other receivables” on the Consolidated Balance Sheets, was $0.3 million and $0.5 million at December 31, 2011 and 2010, respectively.
Accounts Payable and Accrued Liabilities
December 31, | |||||||
In thousands | 2011 | 2010 | |||||
Accrued exploration and development costs | $ | 141,868 | $ | 101,758 | |||
Accounts payable | 99,444 | 47,660 | |||||
Accrued interest | 60,923 | 57,077 | |||||
Accrued compensation | 35,861 | 39,757 | |||||
Accrued lease operating expenses | 24,185 | 23,557 | |||||
Deferred Riley Ridge acquisition consideration | 15,000 | - | |||||
Taxes payable | 13,455 | 34,371 | |||||
Other | 38,600 | 45,888 | |||||
Total | $ | 429,336 | $ | 350,068 |
Supplemental Cash Flow Information
Year Ended December 31, | ||||||||||
In thousands, except shares | 2011 | 2010 | 2009 | |||||||
Supplemental cash flow information: | ||||||||||
Cash paid for interest, expensed | $ | 137,259 | $ | 151,831 | $ | 20,924 | ||||
Cash paid for interest, capitalized | 60,540 | 66,815 | 68,596 | |||||||
Cash paid for income taxes | 45,912 | 17,960 | 16,002 | |||||||
Cash received from income tax refunds | 24,677 | 15,107 | 15,761 | |||||||
Non-cash investing activities: | ||||||||||
Increase in asset retirement obligations | 24,694 | 53,579 | 11,268 | |||||||
Increase (decrease) in liabilities for capital expenditures | 74,697 | (237) | (76,605) | |||||||
Issuance of Denbury common stock in connection with the Encore Merger | - | 2,085,681 | - | |||||||
Vanguard common units received as consideration for sale of ENP | - | 93,020 | - | |||||||
Issuance of Denbury common stock pursuant to Conroe Field acquisition | - | - | 168,723 |
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Note 13. Former Related Party Transactions – Genesis
During 2009, we held a 12% ownership interest in Genesis, which we disposed of during the first quarter of 2010.
Interest in and Transactions with Genesis
During February 2010, we sold our interest in Genesis Energy, LLC, the general partner of Genesis, which is a publicly traded master limited partnership. In March 2010, we sold all of our Genesis common units in a secondary public offering. As a result, we no longer hold any interests in Genesis, and Genesis is no longer considered a related party. Prior to these sales, we accounted for our 12% ownership in Genesis under the equity method of accounting. We received cash distributions from Genesis of $11.6 million in 2009.
Incentive Compensation Agreement
In late December 2008, our subsidiary, Genesis Energy, LLC, entered into agreements with three members of Genesis management for the purpose of providing them incentive compensation. The awards were mandatorily redeemable upon a change in control, and upon the sale of our interest in Genesis Energy, LLC, the change-in-control provision of each member's compensation agreement was triggered. As such, the awards were settled for cash in February 2010 for $14.9 million comprised of deferred compensation of $1.9 million and change of control redemption amounts of $13.0 million. In February 2010, we recognized general and administrative expense of $1.1 million associated with the $14.9 million payment. The remainder of the payment had been previously accrued in our financial statements as of December 31, 2009. We recorded approximately $14.2 million of expense during the year ended December 31, 2009, which is classified as “General and administrative” expenses on our Consolidated Statement of Operations.
Oil Sales and Transportation Services
We utilize Genesis' trucking services and common carrier pipeline to transport certain of our crude oil production to sales points where it is sold to third-party purchasers. We expensed $7.9 million in 2009 for these transportation services.
CO2 Volumetric Production Payments
During 2003 through 2005, we sold 280.5 Bcf of CO2 to Genesis under three separate volumetric production payment agreements. We have recorded the net proceeds of these volumetric production payment sales as deferred revenue and recognize such revenue as CO2 is delivered under the volumetric production payments. We recognized deferred revenue of $4.2 million for the year ended December 31, 2009 for deliveries under these volumetric production payments. In 2009, we recognized revenues of $5.5 million for certain processing and transportation services provided to Genesis.
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Note 14. Subsequent Events
Equity Award Grant
In January 2012, we granted equity incentive awards to our employees under the 2004 Plan. The grant included 1,358,970 shares of restricted stock valued at $17.27 per share (the closing price of Denbury's common stock on January 6, 2012) and 775,663 SARs with an exercise price of $17.27 and a weighted average grant date fair value ranging between $9.03 and $9.15 per unit. The awards generally vest 25% per year over a four-year period.
Agreement to Sell Non-Core Gulf Coast Assets
On January 12, 2012, the Company entered into a definitive agreement with a privately held entity in which a member of our Board of Directors serves as Chairman of the Board, to sell certain non-core assets primarily located in central and southern Mississippi and in southern Louisiana for $155 million, subject to customary closing adjustments in a sale for which there was a competing bid contained in a multi-property purchase proposal. The sale is expected to close by late February 2012, subject to customary closing conditions, and would have an effective date of December 1, 2011.
Vanguard Common Units Sale
In January 2012, the Company sold its investment in Vanguard for cash consideration of $83.5 million, net of related transaction fees. In connection with the sale, the Company realized a pre-tax loss on the sale of $3.1 million, after consideration of “other-than-temporary” impairment charges recognized for the year ended December 31, 2011.
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Note 15. Supplemental Oil and Natural Gas Disclosures (Unaudited)
Costs Incurred
The following table summarizes costs incurred and capitalized in oil and natural gas property acquisition, exploration and development activities. Property acquisition costs are those costs incurred to purchase, lease or otherwise acquire property, including both undeveloped leasehold and the purchase of reserves in place. Exploration costs include costs of identifying areas that may warrant examination and examining specific areas that are considered to have prospects containing oil and natural gas reserves, including costs of drilling exploratory wells, geological and geophysical costs, and carrying costs on undeveloped properties. Development costs are incurred to obtain access to proved reserves, including the cost of drilling development wells, and to provide facilities for extracting, treating, gathering and storing the oil and natural gas, and the cost of improved recovery systems.
The Company capitalizes interest on unevaluated oil and natural gas properties that have ongoing development activities. Included in the costs incurred below is capitalized interest of $44.9 million in 2011, $32.6 million in 2010 and $14.3 million in 2009. Costs incurred also include new asset retirement obligations established, as well as changes to asset retirement obligations resulting from revisions in cost estimates or abandonment dates. Asset retirement obligations included in the table below were $24.2 million in 2011, $45.1 million in 2010 and $11.2 million in 2009. See Note 3, Asset Retirement Obligations, for additional information.
Costs incurred in oil and natural gas activities were as follows:
Year Ended December 31, | |||||||||||
In thousands | 2011 | 2010 | 2009 | ||||||||
Property acquisitions: | |||||||||||
Proved | $ | 86,465 | $ | 3,373,450 | $ | 585,637 | |||||
Unevaluated | 17,858 | 1,297,695 | 104,772 | ||||||||
Exploration | 31,483 | 8,728 | 4,635 | ||||||||
Development | 1,144,243 | 658,758 | 292,545 | ||||||||
Total costs incurred (1) | $ | 1,280,049 | $ | 5,338,631 | $ | 987,589 | |||||
(1) | Capitalized general and administrative costs that directly relate to exploration and development activities were $35.0 million, $20.1 million and $14.0 million for the years ended December 31, 2011, 2010 and 2009, respectively. |
Oil and Natural Gas Operating Results
Results of operations from oil and natural gas producing activities, excluding corporate overhead and interest costs, were as follows:
Year Ended December 31, | |||||||||||
In thousands, except per BOE data | 2011 | 2010 | 2009 | ||||||||
Oil, natural gas and related product sales | $ | 2,269,151 | $ | 1,793,292 | $ | 866,709 | |||||
Lease operating costs | 507,397 | 470,364 | 314,689 | ||||||||
Marketing expenses | 26,047 | 31,036 | 16,890 | ||||||||
Taxes other than income | 138,419 | 114,569 | 37,037 | ||||||||
Depletion, depreciation and amortization | 369,075 | 391,782 | 206,999 | ||||||||
CO2 depletion, depreciation and amortization (1) | 24,460 | 29,206 | 29,076 | ||||||||
Commodity derivative expense (income) | (52,497) | (21,414) | 236,226 | ||||||||
Net operating income | 1,256,250 | 777,749 | 25,792 | ||||||||
Income tax provision | 477,375 | 295,545 | 9,927 | ||||||||
Results of operations from oil and natural gas producing activities | $ | 778,875 | $ | 482,204 | $ | 15,865 | |||||
Depletion, depreciation and amortization per BOE | $ | 16.42 | $ | 15.82 | $ | 13.39 | |||||
(1) | Represents an allocation of the depletion, depreciation and amortization of our CO2 properties and pipelines associated with our tertiary oil producing activities. |
Oil and Natural Gas Reserves
Net proved oil and natural gas reserve estimates for all years presented were prepared by DeGolyer and MacNaughton, independent petroleum engineers located in Dallas, Texas. Oil and natural gas reserve estimates do not include any value for probable or possible reserves that may exist, nor do they include any value for undeveloped acreage. The reserve estimates represent our net revenue interest in our properties. See Standardized Measure of Discounted Future Net Cash Flows and Changes Therein Relating to Proved Oil and Natural Gas Reserves below for a discussion of the effect of the different prices on reserve quantities and values. Operating costs, production and ad valorem taxes, and future development costs were based on current costs.
There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting the future rates of production and timing of development expenditures. The following reserve data represents estimates only and should not be construed as being exact. Moreover, the present values should not be construed as the current market value of our oil and natural gas reserves or the costs that would be incurred to obtain equivalent reserves. Estimates of reserves as of year-end 2011, 2010 and 2009 were prepared using an average price equal to the unweighted arithmetic average of hydrocarbon prices received on a field-by-field basis on the first day of each month within the applicable fiscal 12-month period. All of our reserves are located in the United States.
Estimated Quantities of Reserves
Year Ended December 31, | |||||||||||||||||||
2011 | 2010 | 2009 | |||||||||||||||||
Oil | Gas | Total | Oil | Gas | Total | Oil | Gas | Total | |||||||||||
(MBbl) | (MMcf) | (MBOE) | (MBbl) | (MMcf) | (MBOE) | (MBbl) | (MMcf) | (MBOE) | |||||||||||
Balance at beginning of year | 338,276 | 357,893 | 397,925 | 192,879 | 87,975 | 207,542 | 179,126 | 427,955 | 250,452 | ||||||||||
Revisions of previous estimates | (4,478) | (14,058) | (6,821) | 3,538 | 16,171 | 6,233 | (69) | (1,298) | (285) | ||||||||||
Revisions due to price changes | 2,558 | 485 | 2,639 | 2,780 | 811 | 2,915 | 4,557 | (2,079) | 4,211 | ||||||||||
Extensions and discoveries | 42,936 | 52,339 | 51,658 | 26,313 | 130,245 | 48,021 | 334 | 11,785 | 2,298 | ||||||||||
Improved recovery(1) | 264 | - | 264 | 30,173 | - | 30,173 | 13,875 | - | 13,875 | ||||||||||
Production | (22,169) | (10,783) | (23,966) | (21,870) | (28,491) | (26,619) | (13,495) | (24,764) | (17,622) | ||||||||||
Acquisition of minerals in place | 346 | 239,332 | 40,235 | 155,021 | 622,984 | 258,852 | 28,379 | 2,317 | 28,765 | ||||||||||
Sales of minerals in place | - | - | - | (50,558) | (471,802) | (129,192) | (19,828) | (325,941) | (74,152) | ||||||||||
Balance at end of year | 357,733 | 625,208 | 461,934 | 338,276 | 357,893 | 397,925 | 192,879 | 87,975 | 207,542 | ||||||||||
Proved Developed Reserves: | |||||||||||||||||||
Balance at beginning of year | 219,077 | 110,516 | 237,496 | 116,192 | 69,513 | 127,778 | 96,746 | 298,114 | 146,432 | ||||||||||
Balance at end of year | 239,741 | 125,970 | 260,736 | 219,077 | 110,516 | 237,496 | 116,192 | 69,513 | 127,778 | ||||||||||
(1) Improved recovery additions result from the application of secondary recovery methods such as water flooding, or tertiary recovery methods such as CO2 flooding. |
Acquisitions of minerals in place during 2011 were primarily related to the acquisition of the remaining interest in Riley Ridge. Extensions and discoveries primarily include proved undeveloped reserves and were added primarily through additional drilling in the Bakken.
Acquisitions of minerals in place during 2010 were primarily from the Encore Merger and the Riley Ridge acquisition. The sales of minerals in place during 2010 were primarily due to the sale of the non-strategic Encore properties and our ownership interests in ENP. Extensions and discoveries primarily include reserves added at our Bakken and Haynesville fields. We added 39.4 MMBbls of tertiary proved oil reserves during 2010, primarily initial proved tertiary oil reserves at Delhi Field in Phase 5, plus upward revisions to reserves in other tertiary floods. In order to recognize proved tertiary oil reserves, we must either have an oil production response to CO2 injections or the field must be analogous to an existing tertiary flood. The magnitude of proved reserves that we can book in any given year will depend on our progress with new floods and the timing of the production response.
Standardized Measure of Discounted Future Net Cash Flows and Changes Therein Relating to Proved Oil and Natural Gas Reserves
The Standardized Measure of Discounted Future Net Cash Flows and Changes Therein Relating to Proved Oil and Natural Gas Reserves (“Standardized Measure”) does not purport to present the fair market value of our oil and natural gas properties. An estimate of such value should consider, among other factors, anticipated future prices of oil and natural gas, the probability of recoveries in excess of existing proved reserves, the value of probable reserves and acreage prospects, and perhaps different discount rates. It should be noted that estimates of reserve quantities, especially from new discoveries, are inherently imprecise and subject to substantial revision.
Under the Standardized Measure, future cash inflows were estimated by applying a first-day-of-the-month 12-month average price to the estimated future production of year-end proved reserves. The product prices used in calculating these reserves have varied widely during the three-year period. These prices have a significant impact on both the quantities and value of the proved reserves, as reductions in oil and natural gas prices can cause wells to reach the end of their economic life much sooner and can make certain proved undeveloped locations uneconomical, both of which reduce the reserves. The following representative oil and natural gas prices were used in the Standardized Measure. These prices were adjusted by field to arrive at the appropriate corporate net price.
December 31, | |||||||||
2011 | 2010 | 2009 | |||||||
Oil (NYMEX) | $ | 96.19 | $ | 79.43 | $ | 61.18 | |||
Natural Gas (Henry Hub) | 4.16 | 4.40 | 3.87 |
Future cash inflows were reduced by estimated future production, development and abandonment costs based on current cost, with no escalation to determine pre-tax cash inflows. Our future net inflows do not include a reduction for cash previously expended on our capitalized CO2 assets that will be consumed in the production of proved tertiary reserves. Future income taxes were computed by applying the statutory tax rate to the excess of net cash inflows over our tax basis in the associated proved oil and natural gas properties. Tax credits and net operating loss carryforwards were also considered in the future income tax calculation. Future net cash inflows after income taxes were discounted using a 10% annual discount rate to arrive at the Standardized Measure.
December 31, | ||||||||||
In thousands | 2011 | 2010 | 2009 | |||||||
Future cash inflows | $ | 38,165,122 | $ | 26,698,819 | $ | 11,579,159 | ||||
Future production costs | (12,570,015) | (9,702,896) | (5,034,393) | |||||||
Future development costs | (3,026,898) | (1,912,457) | (836,455) | |||||||
Future income taxes | (7,379,972) | (4,700,023) | (1,257,844) | |||||||
Future net cash flows | 15,188,237 | 10,383,443 | 4,450,467 | |||||||
10% annual discount for estimated timing of cash flows | (8,180,632) | (5,465,516) | (1,993,082) | |||||||
Standardized measure of discounted future net cash flows | $ | 7,007,605 | $ | 4,917,927 | $ | 2,457,385 |
The following table sets forth an analysis of changes in the Standardized Measure of Discounted Future Net Cash Flows from proved oil and natural gas reserves:
Year Ended December 31, | |||||||||||
In thousands | 2011 | 2010 | 2009 | ||||||||
Beginning of year | $ | 4,917,927 | $ | 2,457,385 | $ | 1,415,498 | |||||
Sales of oil and natural gas produced, net of production costs | (1,597,288) | (1,177,322) | (498,093) | ||||||||
Net changes in sales prices | 4,646,086 | 2,062,181 | 1,263,346 | ||||||||
Extensions and discoveries, less applicable future development and production costs | 762,370 | 295,074 | 6,735 | ||||||||
Improved recovery(1) | 15,708 | 623,622 | 202,145 | ||||||||
Previously estimated development costs incurred | 354,228 | 193,947 | 98,659 | ||||||||
Revisions of previous estimates, including revised estimates of development costs, reserves and rates of production | (1,673,283) | (285,158) | (63,044) | ||||||||
Accretion of discount | 729,234 | 307,546 | 192,686 | ||||||||
Acquisition of minerals in place | 29,737 | 3,671,439 | 365,771 | ||||||||
Sales of minerals in place | - | (1,474,443) | (419,601) | ||||||||
Net change in income taxes | (1,177,114) | (1,756,344) | (106,717) | ||||||||
End of year | $ | 7,007,605 | $ | 4,917,927 | $ | 2,457,385 | |||||
(1) | Improved recovery additions result from the application of secondary recovery methods such as water flooding or tertiary recovery methods such as CO2 flooding. |
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Note 16. Supplemental CO2 and Helium Disclosures (Unaudited)
Based on engineering reports prepared by DeGolyer and MacNaughton, proved CO2 and helium reserves were estimated as follows (in MMcf):
Year Ended December 31, | ||||||||
2011 | 2010 | 2009 | ||||||
CO2 Reserves | ||||||||
Gulf Coast region(1) | 6,685,412 | 7,085,131 | 6,302,836 | |||||
Rocky Mountain region(2) | 2,195,534 | 2,189,756 | - | |||||
Helium Reserves Associated with Denbury's Production Rights | ||||||||
Rocky Mountain region(3) | 12,004 | 7,159 | - | |||||
(1) | Proved CO2 reserves in the Gulf Coast region consist of reserves from our reservoirs at Jackson Dome and are presented on a gross working interest basis, of which Denbury’s net revenue interest was approximately 5.3 Tcf, 5.6 Tcf and 5.0 Tcf at December 31, 2011, 2010 and 2009, respectively, and include reserves dedicated to volumetric production payments of 84.7 Bcf, 100.2 Bcf and 127.1 Bcf at December 31, 2011, 2010 and 2009, respectively. | |||||||
(2) | Proved CO2 reserves in the Rocky Mountain region consist of our reserves at Riley Ridge and are presented on a gross working interest basis, of which Denbury’s net revenue interest was approximately 1.6 Tcf and 0.9 Tcf at December 31, 2011 and 2010, respectively. | |||||||
(3) | Reserves associated with helium production rights include helium reserves located in the acreage in the Rocky Mountain region for which we have the right to extract the helium. The U.S. government retains title to the helium reserves and we retain the right to extract and sell the helium on behalf of the government in exchange for a fee. The helium reserves are presented net of the fee we will remit to the U.S. government. |
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Note 17. Unaudited Quarterly Information
In thousands, except per share amounts | March 31 | June 30 | September 30 | December 31 | |||||||||
2011 | |||||||||||||
Revenues and other income | $ | 514,165 | $ | 601,397 | $ | 576,505 | $ | 617,257 | |||||
Expenses | 537,111 | 177,595 | 133,185 | 537,388 | |||||||||
Net income (loss) | (14,190) | 259,246 | 275,670 | 52,607 | |||||||||
Net income (loss) per share: | |||||||||||||
Basic | (0.04) | 0.65 | 0.69 | 0.14 | |||||||||
Diluted | (0.04) | 0.64 | 0.68 | 0.13 | |||||||||
Cash flow from operating activities | 124,832 | 398,521 | 315,739 | 365,722 | |||||||||
Cash flow used for investing activities | (285,043) | (347,797) | (525,412) | (447,706) | |||||||||
Cash flow provided by (used for) financing activities | (93,801) | (56,789) | 112,244 | 76,314 | |||||||||
2010 | |||||||||||||
Revenues and other income | $ | 438,821 | $ | 497,210 | $ | 466,703 | $ | 519,057 | |||||
Expenses | 261,676 | 265,518 | 415,170 | 500,357 | |||||||||
Net income | 96,888 | 135,367 | 29,104 | 10,364 | |||||||||
Net income per share: | |||||||||||||
Basic | 0.33 | 0.34 | 0.07 | 0.03 | |||||||||
Diluted | 0.32 | 0.34 | 0.07 | 0.03 | |||||||||
Cash flow from operating activities | 113,168 | 271,123 | 208,484 | 263,036 | |||||||||
Cash flow provided by (used for) investing activities | (764,327) | 505,713 | (261,539) | 165,373 | |||||||||
Cash flow provided by (used for) financing activities | 739,753 | (818,547) | 71,926 | (132,885) |
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Organization and Nature of Operations
Denbury Resources Inc., a Delaware corporation, is a growing independent oil and natural gas company. We are the largest combined oil and natural gas producer in both Mississippi and Montana, own the largest reserves of CO2 used for tertiary oil recovery east of the Mississippi River, and hold significant operating acreage in the Rocky Mountain and Gulf Coast regions. Our goal is to increase the value of our acquired properties through a combination of exploitation, drilling and proven engineering extraction practices, with our most significant emphasis on our CO2 tertiary recovery operations.
Encore Merger. On March 9, 2010, we acquired Encore Acquisition Company (“Encore”), pursuant to an Agreement and Plan of Merger (the “Encore Merger Agreement”), under which Encore was merged with and into Denbury (the “Encore Merger”), with Denbury surviving the Encore Merger following approval by the stockholders of both Denbury and Encore, closing of a new revolving credit facility as part of the financing for the Encore Merger, and satisfaction of conditions precedent. The Encore Merger provided Encore stockholders stock and/or cash and included the assumption of Encore's debt by Denbury. Denbury has consolidated Encore's results of operations since March 9, 2010, the acquisition date. See Note 2, Acquisitions and Divestitures, for more information.
Principles of Reporting and Consolidation
The consolidated financial statements herein have been prepared in accordance with accounting principles generally accepted in the United States (“GAAP”) and include the accounts of Denbury and entities in which we hold a controlling financial interest. Undivided interests in oil and gas joint ventures are consolidated on a proportionate basis. Investments in non-controlled entities over which we exercise significant influence are accounted for under the equity method. Other investments are carried at cost. All intercompany balances and transactions have been eliminated.
From March 9, 2010 through December 31, 2010, we owned approximately 46% of Encore Energy Partners LP (“ENP”) outstanding common units and 100% of Encore Energy Partners GP LLC (“GP LLC”), which was ENP's general partner. Considering the presumption of control of GP LLC in accordance with the Consolidation topic of the Financial Accounting Standards Board Codification (“FASC”), the results of operations and cash flows of ENP were consolidated with those of Denbury for this period. On December 31, 2010, we sold all of our ownership interests in ENP and GP LLC and, therefore, we did not consolidate ENP in our Consolidated Balance Sheet as of December 31, 2010. As presented in the accompanying Consolidated Statement of Operations for the year ended December 31, 2010, “Net income attributable to noncontrolling interest” of $13.8 million represents ENP's results of operations attributable to limited partners other than Denbury for the portion of the year for which we consolidated ENP.
At December 31, 2009, we owned the general partner of Genesis Energy, L.P. (“Genesis”), a publicly-traded master limited partnership, and approximately 10% of Genesis' outstanding common units. In aggregate, our ownership interests represented approximately a 12% ownership interest in Genesis, which we accounted for under the equity method of accounting. On February 5, 2010, we sold our general partner interest in Genesis, and in March 2010 we sold our Genesis common units. See Note 2, Acquisitions and Divestitures, for more information.
Use of Estimates
The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amount of certain assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during each reporting period. Management believes its estimates and assumptions are reasonable; however, such estimates and assumptions are subject to a number of risks and uncertainties that may cause actual results to differ materially from such estimates. Significant estimates underlying these financial statements include (1) the fair value of financial derivative instruments, (2) the estimated quantities of proved oil and natural gas reserves used to compute depletion of oil and natural gas properties, the related present value of estimated future net cash flows therefrom and the ceiling test, (3) accruals related to oil and natural gas sales volumes and revenues, capital expenditures and lease operating expenses, (4) the estimated costs and timing of future asset retirement obligations, (5) estimates made in the calculation of income taxes, and (6) estimates made in determining the fair values for purchase price allocations, including goodwill. While management is not aware of any significant revisions to any of its estimates, there will likely be future revisions to its estimates resulting from matters such as revisions in estimated oil and natural gas volumes, changes in ownership interests, payouts, joint venture audits, re-allocations by purchasers or pipelines, or other corrections and adjustments common in the oil and natural gas industry, many of which require retroactive application. These types of adjustments cannot be currently estimated and will be recorded in the period in which the adjustment occurs.
Reclassifications
Certain prior period amounts have been reclassified to conform with the current year presentation. On the Consolidated Statements of Operations for the years ended December 31, 2010 and 2009, “Taxes other than income” is a new line item and includes oil and natural gas ad valorem taxes, which were reclassified from “Lease operating expenses,” franchise taxes and property taxes on buildings, which were reclassified from “General and administrative expenses,” oil and natural gas production taxes, which were reclassified from “Production taxes and marketing expenses” used in prior reports and CO2 property ad valorem and production taxes, which were classified from “CO2 discovery and operating expense.” On the Consolidated Balance Sheet as of December 31, 2010, “Pipelines and plants” was reclassified from “CO2 and other products – properties and pipelines” used in prior reports, helium properties were reclassified to “Other property and equipment” from “CO2 and other products - properties and pipelines” used in prior reports, and “Other current assets” was reclassified from “Trade and other receivables, net.” Such reclassifications had no impact on our reported total expenses, net income, current assets, total assets, current liabilities, total liabilities or stockholders' equity.
Cash Equivalents
We consider all highly liquid investments to be cash equivalents if they have maturities of three months or less at the date of purchase.
Short-term Investments
Short-term investments are available-for-sale securities recorded at fair value with any unrealized gains or losses included in accumulated other comprehensive income. At December 31, 2011 and 2010, short-term investments consisted entirely of our investment in Vanguard Natural Resources LLC (“Vanguard”) common units obtained as partial consideration for the sale of our interests in ENP to a subsidiary of Vanguard on December 31, 2010. See Note 2, Acquisitions and Divestitures. Our original cost basis of this investment was $93.0 million. We received distributions of $7.2 million on the Vanguard common units we own for the year ended December 31, 2011, which are included in “Interest income and other income” on our Consolidated Statements of Operations. Due to the decline in the market value of this investment and the expectation that the investment would not recover to its cost basis prior to the time of sale, we recorded a $6.3 million “other-than-temporary” impairment loss on this investment for the year ended December 31, 2011, which is included in “Impairment of assets” on our Consolidated Statements of Operations. This investment was sold in January 2012 for cash consideration of $83.5 million, net of related transaction fees. See Note 14, Subsequent Events.
Oil and Natural Gas Properties
Capitalized Costs. We follow the full cost method of accounting for oil and natural gas properties. Under this method, all costs related to acquisitions, exploration and development of oil and natural gas reserves are capitalized and accumulated in a single cost center representing our activities, which are undertaken exclusively in the United States. Such costs include lease acquisition costs, geological and geophysical expenditures, lease rentals on undeveloped properties, costs of drilling both productive and non-productive wells, capitalized interest on qualifying projects, and general and administrative expenses directly related to exploration and development activities, and do not include any costs related to production, general corporate overhead or similar activities. We assign the purchase price of oil and natural gas properties we acquire to proved and unevaluated properties based on the estimated fair values as defined in the FASC Fair Value Measurements and Disclosures topic. Proceeds received from disposals are credited against accumulated costs except when the sale represents a significant disposal of reserves, in which case a gain or loss would be recognized.
Depletion and Depreciation. The costs capitalized, including production equipment and future development costs, are depleted or depreciated using the unit-of-production method, based on proved oil and natural gas reserves as determined by independent petroleum engineers. Oil and natural gas reserves are converted to equivalent units on a basis of 6,000 cubic feet of natural gas to one barrel of crude oil. The depletion and depreciation rate per BOE associated with our oil and gas producing activities was $16.42 in 2011, $15.82 in 2010 and $13.39 in 2009.
Under full cost accounting, we may exclude certain unevaluated costs from the amortization base pending determination of whether proved reserves can be assigned to such properties. The costs classified as unevaluated are transferred to the full cost amortization base as the properties are developed, tested and evaluated.
Ceiling Test. The net capitalized costs of oil and natural gas properties are limited to the lower of unamortized cost or the cost center ceiling. The cost center ceiling is defined as the sum of (1) the present value of estimated future net revenues from proved reserves before future abandonment costs (discounted at 10%), based on unescalated period-end oil and natural gas prices during the first three quarters of 2009; and beginning in the fourth quarter of 2009, the average first-day-of-the-month oil and natural gas price for each month during the 12-month period prior to the end of a particular reporting period; (2) plus the cost of properties not being amortized; (3) plus the lower of cost or estimated fair value of unproved properties included in the costs being amortized, if any; (4) less related income tax effects. Our future net revenues from proved reserves are not reduced for development costs related to the cost of drilling for and developing CO2 reserves nor those related to the cost of constructing CO2 pipelines, as those costs have previously been incurred by the Company. Therefore, we include in the ceiling test, as a reduction of future net revenues, that portion of the Company's capitalized CO2 costs related to CO2 reserves and CO2 pipelines that we estimate will be consumed in the process of producing our proved oil and natural gas reserves. The fair value of our oil and natural gas derivative contracts is not included in the ceiling test, as we do not designate these contracts as hedge instruments for accounting purposes. The cost center ceiling test is prepared quarterly. We did not have a ceiling test write-down during the years ended December 31, 2011, 2010 or 2009.
Joint Interest Operations. Substantially all of our oil and natural gas exploration and production activities are conducted jointly with others. These financial statements reflect only Denbury's proportionate interest in such activities, and any amounts due from other partners are included in trade receivables.
Tertiary Injection Costs. Our tertiary operations are conducted in reservoirs that have already produced significant amounts of oil over many years; however, in accordance with the SEC rules and regulations for recording proved reserves, we cannot recognize proved reserves associated with enhanced recovery techniques, such as CO2 injection, until there is a production response to the injected CO2, or unless the field is analogous to an existing flood. Our costs associated with the CO2 we produce and inject are principally our costs of production, transportation and acquisition, and payment of royalties.
We capitalize, as a development cost, injection costs in fields that are in their development stage, which means we have not yet seen incremental oil production due to the CO2 injections (i.e., a production response). These capitalized development costs are included in our unevaluated property costs if there are not already proved tertiary reserves in that field. After we see a production response to the CO2 injections (i.e., the production stage), injection costs are expensed as incurred, and once proved reserves are recognized, previously deferred unevaluated development costs will become subject to depletion.
CO2 Properties
We own and produce CO2 reserves, a non-hydrocarbon resource, that are used in our tertiary oil recovery operations on our own behalf and on behalf of other working interest owners in our enhanced recovery fields, with a portion sold to third-party industrial users. We record revenue from our sales of CO2 to third parties when it is produced and sold. Expenses related to the production of CO2 are allocated between volumes sold to third parties and volumes consumed internally that are directly related to our tertiary production. The expenses related to third-party sales are recorded in “CO2 discovery and operating expenses,” and the expenses related to internal use are recorded in “Lease operating expenses” in the Consolidated Statements of Operations, or are capitalized as oil and gas properties in our Consolidated Balance Sheets, depending on the status of floods that receive the CO2 (see Tertiary Injection Cost above for further discussion).
During 2010 and 2011, we acquired interests in the Riley Ridge Federal Unit (“Riley Ridge”), in which helium, a non-hydrocarbon resource, as well as natural gas, a hydrocarbon, are present. It is not possible to separately identify the capitalized costs related to the development of each product in the comingled gas stream; thus, these costs are allocated between “Oil and natural gas properties”, “CO2 properties” and “Other property and equipment” on the Consolidated Balance Sheets based on the relative future revenue value of each product line.
During 2010, we revised our capitalization policies for CO2 properties. Previously, we accounted for our CO2 source properties in a manner similar to our method of accounting for oil and natural gas properties, as the process and activities to identify, develop and produce CO2 reserves are virtually identical to those used to identify, develop and produce oil and natural gas reserves. However, because CO2 is not a hydrocarbon, it is excluded from the scope of FASC Topic 932, Extractive Industries – Oil and Gas, and, therefore, we are precluded from accounting for our CO2 operations in accordance with FASC Topic 932. Accordingly, commencing in July 2010, costs incurred to search for CO2 are expensed as incurred until proved or probable reserves are established. Once proved or probable reserves are established, costs incurred to obtain those reserves are capitalized and classified as “CO2 properties” on our Consolidated Balance Sheets. Capitalized CO2 is aggregated by geologic formation and depleted on a unit-of-production basis over proved and probable reserves. The impact of the revised accounting policy on our financial statements was not material to any individual year. The Company recognized the cumulative impact of the revised accounting policy as a non-cash net reduction to depletion, depreciation and amortization during the year ended December 31, 2010, resulting in a pretax credit of $9.6 million ($6.0 million after tax), which reflected a reduction to “CO2 properties” of $26.1 million offset by a decrease in “Accumulated depletion, depreciation and amortization” of $35.7 million. The cumulative adjustment did not have an impact on our net cash flows.
The portion of the Company's capitalized CO2 costs related to CO2 reserves and CO2 pipelines that we estimate will be consumed in the process of producing our proved oil reserves is included in the ceiling test as a reduction to future net revenues. The remaining net capitalized CO2 properties, equipment and pipelines balance is evaluated for impairment by comparing the net carrying costs to the expected future net revenues from (1) the production of our probable and possible tertiary oil reserves and (2) the sale of CO2 to third-party industrial users.
Pipelines and Plants
CO2 used in our tertiary floods is transported to our fields through CO2 pipelines. Costs of CO2 pipelines under construction are not depreciated until the pipelines are placed into service. Pipelines are depreciated on a straight-line basis over their estimated useful lives, which range from 15 to 50 years.
Pipelines and plants include the Riley Ridge gas plant in southwestern Wyoming, which is currently under construction. The plant is being withheld from depreciation until it is placed in service, which we currently expect to occur during the second quarter of 2012.
Property and Equipment – Other
Other property and equipment, which includes furniture and fixtures, vehicles, computer equipment and software, and capitalized leases, is depreciated principally on a straight-line basis over estimated useful lives. Vehicles and furniture and fixtures are generally depreciated over a useful life of five to ten years, and computer equipment and software are generally depreciated over a useful life of three to five years. Leasehold improvements are amortized over the shorter of the estimated useful life or the remaining lease term.
Leased property meeting certain capital lease criteria is capitalized, and the present value of the related lease payments is recorded as a liability. Amortization of capitalized leased assets is computed using the straight-line method over the shorter of the estimated useful life or the initial lease term.
Maintenance and repair costs that do not extend the useful lives of property and equipment are charged to expense as incurred.
Asset Retirement Obligations
In general, our future asset retirement obligations relate to future costs associated with plugging and abandonment of our oil, natural gas and CO2 wells, removing equipment and facilities from leased acreage, and returning land to its original condition. The fair value of a liability for an asset retirement obligation is recorded in the period in which it is incurred, discounted to its present value using our credit-adjusted-risk-free interest rate, and a corresponding amount capitalized by increasing the carrying amount of the related long-lived asset. The liability is accreted each period, and the capitalized cost is depreciated over the useful life of the related asset. Revisions to estimated retirement obligations will result in an adjustment to the related capitalized asset and corresponding liability. If the liability is settled for an amount other than the recorded amount, the difference is recorded to the full cost pool, unless significant.
Asset retirement obligations are estimated at the present value of expected future net cash flows and are discounted using the Company's credit-adjusted-risk-free rate. We utilize unobservable inputs in the estimation of asset retirement obligations that include, but are not limited to, costs of labor, costs of materials, profits on costs of labor and materials, the effect of inflation on estimated costs, and the discount rate. Accordingly, asset retirement obligations are considered a Level 3 measurement under the FASC Fair Value Measurements and Disclosures topic.
Derivative Instruments and Hedging Activities
We utilize oil and natural gas derivative contracts to mitigate our exposure to commodity price risk associated with our future oil and natural gas production. These derivative contracts have historically consisted of options, in the form of price floors or collars, and fixed price swaps. From time to time, we have also used interest rate lock contracts to mitigate our exposure to interest rate fluctuations related to sale-leaseback financing of certain equipment used at our oilfield facilities. Our derivative financial instruments are recorded on the balance sheet as either an asset or a liability measured at fair value. We do not apply hedge accounting to our oil and natural gas derivative contracts; accordingly, the changes in the fair value of these instruments are recognized in our Consolidated Statements of Operations in the period of change.
Oil and Natural Gas Derivative Contracts
We do not apply hedge accounting treatment to our oil and natural gas derivative contracts; therefore, the changes in the fair values of these instruments are recognized in income in the period of change. These fair value changes, along with the cash settlements of expired contracts, are shown under “Derivatives expense (income)” in our Consolidated Statements of Operations.
From time to time, we enter into various oil and natural gas derivative contracts to provide an economic hedge of our exposure to commodity price risk associated with anticipated future oil and natural gas production. We do not hold or issue derivative financial instruments for trading purposes. These contracts have consisted of price floors, collars and fixed price swaps. The production that we hedge has varied from year to year depending on our levels of debt and financial strength and expectation of future commodity prices. We currently employ a strategy to hedge a portion of our forecasted production approximately 12 to 15 months in advance, as we believe it is important to protect our future cash flow to provide a level of assurance for our capital spending in those future periods in light of current worldwide economic uncertainties and commodity price volatility.
Financial Instruments with Off-Balance-Sheet Risk and Concentrations of Credit Risk
Our financial instruments that are exposed to concentrations of credit risk consist primarily of cash equivalents, trade and accrued production receivables, and the derivative instruments discussed above. Our cash equivalents represent high-quality securities placed with various investment-grade institutions. This investment practice limits our exposure to concentrations of credit risk. Our trade and accrued production receivables are dispersed among various customers and purchasers; therefore, concentrations of credit risk are limited. We evaluate the credit ratings of our purchasers, and if customers are considered a credit risk, letters of credit are the primary security obtained to support lines of credit. We attempt to minimize our credit risk exposure to the counterparties of our oil and natural gas derivative contracts through formal credit policies, monitoring procedures and diversification. All of our derivative contracts are with banks, which are part of the syndicate of banks in our bank credit facility, or with their affiliates. There are no margin requirements with the counterparties of our derivative contracts.
Goodwill
Goodwill represents the excess of the purchase price over the estimated fair value of the net assets acquired in the acquisition of a business. Goodwill is not amortized; rather, it is tested for impairment annually during the fourth quarter and when events or changes in circumstances indicate that fair value of a reporting unit with goodwill has been reduced below carrying value. The impairment test requires allocating goodwill and other assets and liabilities to reporting units. However, we have only one reporting unit. To assess impairment, we have the option to qualitatively assess if it is more likely than not that the fair value of the reporting unit is less than the book value. Absent a qualitative assessment, or, through the qualitative assessment, if we determine it is more likely than not that the fair value of the reporting unit is less than the book value, a quantitative assessment is prepared to calculate the fair market value of the reporting unit. If it is determined that the fair value of the reporting unit is less than the book value, the recorded goodwill is impaired to its implied fair value with a charge to operating expense. We completed our annual goodwill impairment assessment during the fourth quarter of 2011 and did not record any goodwill impairment during 2011, nor have we recorded a goodwill impairment historically.
Revenue Recognition
Revenue is recognized at the time oil and natural gas is produced and sold. Any amounts due from purchasers of oil and natural gas are included in accrued production receivable.
We follow the sales method of accounting for our oil and natural gas revenue, whereby we recognize revenue on all oil or natural gas sold to our purchasers regardless of whether the sales are proportionate to our ownership in the property. A receivable or liability is recognized only to the extent that we have an imbalance on a specific property greater than the expected remaining proved reserves. As of December 31, 2011 and 2010, our aggregate oil and natural gas imbalances were not material to our consolidated financial statements.
We recognize revenue and expenses of purchased producing properties at the time we assume effective control, commencing from either the closing or purchase agreement date, depending on the underlying terms and agreements. We follow the same methodology in reverse when we sell properties by recognizing revenue and expenses of the sold properties until either the closing or purchase agreement date, depending on the underlying terms and agreements.
Income Taxes
Income taxes are accounted for using the liability method, under which deferred income taxes are recognized for the future tax effects of temporary differences between the financial statement carrying amounts and the tax basis of existing assets and liabilities using the enacted statutory tax rates in effect at year-end. The effect on deferred taxes for a change in tax rates is recognized in income in the period that includes the enactment date. A valuation allowance for deferred tax assets is recorded when it is more likely than not that the benefit from the deferred tax asset will not be realized.
We recognize the tax benefit from an uncertain tax position only if it is more likely than not that the tax position will be sustained upon examination by the taxing authorities, based on the technical merits of the position. The tax benefits recognized in the financial statements from such a position are measured based on the largest benefit that has a greater than 50% likelihood of being realized upon ultimate settlement.
Net Income Per Common Share
Basic net income per common share is computed by dividing the net income attributable to common stockholders by the weighted average number of shares of common stock outstanding during the period. Diluted net income per common share is calculated in the same manner, but also considers the impact to net income and common shares of the potential dilution from stock options, stock appreciation rights (“SARs”), non-vested restricted stock and non-vested performance equity awards.
For each of the three years in the period ended December 31, 2011, there were no adjustments to net income for purposes of calculating basic and diluted net income per common share.
Basic weighted average common shares excludes 3.4 million, 3.2 million and 2.5 million shares of non-vested restricted stock during the year ended December 31, 2011, 2010 and 2009, respectively. As these restricted shares vest or become retirement eligible, they will be included in the shares outstanding used to calculate basic net income per common share (although all restricted stock is issued and outstanding upon grant). For purposes of calculating diluted weighted average common shares, the non-vested restricted stock is included in the computation using the treasury stock method, with the deemed proceeds equal to the average unrecognized compensation during the period, adjusted for any estimated future tax consequences recognized directly in equity.
Recently Adopted Accounting Pronouncements
Goodwill. In September 2011, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2011-08, Testing Goodwill for Impairment, (“ASU 2011-08”). ASU 2011-08 amends the FASC Intangibles – Goodwill and Other topic by permitting entities to assess qualitative factors to determine whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount as a basis for determining whether it is necessary to perform the two-step goodwill impairment test described in the FASC Intangibles – Goodwill and Other topic. We adopted ASU 2011-08 in 2011.
Recently Issued Accounting Pronouncements
Balance Sheet Offsetting. In December 2011, the FASB issued ASU 2011-11, Disclosure about Offsetting Assets and Liabilities (“ASU 2011-11”). ASU 2011-11 requires an entity to disclose information about offsetting and related arrangements to enable users of its financial statements to understand the effect of those arrangements on its financial position. ASU 2011-11 will be effective for our fiscal year beginning January 1, 2013 and will be applied retrospectively for all comparative periods presented. The adoption of ASU 2011-11 is not expected to have a material effect on our consolidated financial statements, but may require additional disclosures.
Comprehensive Income. In June 2011, the FASB issued ASU 2011-05, Presentation of Comprehensive Income, (“ASU 2011-05”). ASU 2011-05 requires the presentation of comprehensive income in either 1) a continuous statement of comprehensive income or 2) two separate but consecutive statements. In December 2011, the FASB issued ASU 2011-12, which defers certain requirements within ASU 2011-05. These amendments are being made to allow the FASB time to redeliberate whether to present on the face of the financial statements the effects of reclassifications out of accumulated other comprehensive income on the components of net income and other comprehensive income in all periods presented. ASU 2011-05 and the amendments in ASU 2011-12 will be effective for our fiscal year beginning January 1, 2012. Since the ASUs will only amend presentation requirements, they are not expected to have a material effect on our consolidated financial statements.
Fair Value. In May 2011, the FASB issued ASU 2011-04, Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRSs, (“ASU 2011-04”). ASU 2011-04 amends the FASC Fair Value Measurements topic by providing a consistent definition and measurement of fair value, as well as similar disclosure requirements between U.S. GAAP and International Financial Reporting Standards. ASU 2011-04 changes certain fair value measurement principles, clarifies the application of existing fair value measurements and expands the fair value disclosure requirements, particularly for Level 3 fair value measurements. ASU 2011-04 will be effective for our fiscal year beginning January 1, 2012. The adoption of ASU 2011-04 will not have a material effect on our consolidated financial statements but may require additional disclosures.
Fair value is the price that would be received to sell an asset or would be paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). We utilize market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated or generally unobservable. We primarily apply the market approach for recurring fair value measurements and endeavor to utilize the best available information. Accordingly, we utilize valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. We are able to classify fair value balances based on the observability of those inputs. The FASC establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). The three levels of the fair value hierarchy are as follows:
We adjust the valuations from the valuation model for nonperformance risk, using our estimate of the counterparty's credit quality for asset positions and Denbury's credit quality for liability positions. Denbury uses multiple sources of third-party credit data in determining counterparty nonperformance risk, including credit default swaps.
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The following table summarizes the changes in goodwill for the years ended December 31, 2011 and 2010:
In thousands | 2011 | 2010 | |||||
Beginning of year balance | $ | 1,232,418 | $ | 169,517 | |||
Adjustment to goodwill related to the acquisition of interests in the Conroe Field | - | 318 | |||||
Goodwill related to the Encore Merger | - | 1,061,123 | |||||
Goodwill related to the Riley Ridge acquisition | 3,900 | 1,460 | |||||
End of year balance | $ | 1,236,318 | $ | 1,232,418 |
The following is a reconciliation of the weighted average shares used in the basic and diluted net income per common share calculations for the periods indicated:
Year Ended December 31, | |||||||
In thousands | 2011 | 2010 | 2009 | ||||
Basic weighted average common shares | 396,023 | 370,876 | 246,917 | ||||
Potentially dilutive securities: | |||||||
Stock options and SARs | 3,539 | 3,844 | - | ||||
Performance equity awards | 38 | 319 | - | ||||
Restricted stock | 1,358 | 1,216 | - | ||||
Diluted weighted average common shares | 400,958 | 376,255 | 246,917 |
The following securities could potentially dilute earnings per share in the future but were not included in the computation of diluted net income per share, as their effect would have been anti-dilutive:
Year Ended December 31, | |||||||
In thousands | 2011 | 2010 | 2009 | ||||
Stock options and SARs | 5,017 | 3,671 | 10,764 | ||||
Performance equity awards | - | - | 523 | ||||
Restricted stock | 104 | 17 | 2,507 | ||||
Total | 5,121 | 3,688 | 13,794 |
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The following table presents a summary of the preliminary fair value of assets acquired:
In thousands | |||||
Consideration: | |||||
Cash payment | $ | 199,779 | |||
Deferred payment(1) | 15,000 | ||||
Total consideration | 214,779 | ||||
Less: Fair value of assets acquired and liabilities assumed: | |||||
Oil and natural gas properties | |||||
Proved | 48,731 | ||||
Unproved | 12,542 | ||||
CO2 properties | 9,741 | ||||
Pipelines and plants | 91,594 | ||||
Other assets(2) | 48,660 | ||||
Asset retirement obligations | (389) | ||||
210,879 | |||||
Goodwill | $ | 3,900 | |||
(1) | The deferred payment is included in "Accounts payable and accrued liabilities" on the accompanying balance sheet and will be paid at the time the property's gas plant is operational and meets specific performance conditions as described above. | ||||
(2) | Other assets includes helium extraction rights of $36.7 million. Helium reserves at Riley Ridge are owned by the U.S. Government. The fair value assigned to helium extraction rights was calculated using the income approach and represents the discounted future net revenues associated with the Company's right to extract and sell the helium on behalf of the helium resource owners. Upon commencement of helium production, helium extraction rights will be amortized on a units-of-production basis. |
The following table is a summary of the consideration issued in the Encore Merger and the fair value of the assets acquired and liabilities assumed at the acquisition date, as well as the fair value at the acquisition date of the noncontrolling interest in ENP.
In thousands | |||
Consideration and noncontrolling interest: | |||
Fair value of Denbury common stock issued (1) | $ | 2,085,681 | |
Cash payment to Encore stockholders (2) | 833,909 | ||
Severance payments | 32,925 | ||
Consideration issued | 2,952,515 | ||
Fair value of noncontrolling interest of ENP (3) | 515,210 | ||
Consideration and noncontrolling interest of ENP (4) | 3,467,725 | ||
Add: fair value of liabilities assumed: | |||
Accounts payable and accrued liabilities | 116,236 | ||
Oil and natural gas production payable | 54,201 | ||
Current derivatives | 65,954 | ||
Other current liabilities | 38,407 | ||
Long-term debt | 1,375,149 | ||
Asset retirement obligations | 42,360 | ||
Long-term derivatives | 35,631 | ||
Long-term deferred taxes | 871,912 | ||
Other long-term liabilities | 2,717 | ||
Amount attributable to liabilities assumed | 2,602,567 | ||
Less: fair value of assets acquired: | |||
Cash and cash equivalents | 51,850 | ||
Accrued production receivable | 124,494 | ||
Trade and other receivables | 43,643 | ||
Current derivatives | 29,737 | ||
Other current assets | 2,740 | ||
Oil and natural gas properties – proved | 3,340,141 | ||
Oil and natural gas properties – unevaluated | 1,279,000 | ||
Pipelines and plants | 7,254 | ||
Other property, plant and equipment | 11,475 | ||
Long-term derivatives | 35,207 | ||
Other long-term assets | 83,628 | ||
Amount attributable to assets acquired | 5,009,169 | ||
Goodwill | $ | 1,061,123 | |
(1) | 135.2 million Denbury common shares at $15.43 per share. | ||
(2) | Based on cash paid to holders of Encore issued and outstanding common stock who elected to receive all cash or who received a combination of cash and stock; also includes cash payment to stock option holders of $4.5 million. | ||
(3) | Represents fair value of the noncontrolling interest of ENP. As of March 9, 2010, there were 45.3 million ENP common units outstanding, and the closing price was $21.10 per common unit. As of March 9, 2010, Encore owned approximately 46% of ENP’s outstanding units. | ||
(4) | The sum of the consideration issued, the noncontrolling interest of ENP and the fair value of Encore’s long-term debt assumed totals approximately $4.8 billion, representing the aggregate purchase price. |
2010 Unaudited Pro Forma Acquisition Information. Had our acquisition of Encore occurred on January 1, 2010, our combined pro forma revenue and net income (loss) would have been as follows:
Year Ended December 31, | |||||||
In thousands | 2010 | 2009 | |||||
Pro forma total revenues and other income | $ | 2,098,241 | $ | 1,568,050 | |||
Pro forma net income (loss) attributable to Denbury stockholders | 286,891 | (137,227) | |||||
Pro forma net income (loss) per common share: | |||||||
Basic | 0.73 | (0.35) | |||||
Diluted | 0.72 | (0.35) |
|
The following table summarizes the changes in our asset retirement obligations for the years ended December 31, 2011 and 2010:
Year Ended December 31, | |||||||
In thousands | 2011 | 2010 | |||||
Beginning asset retirement obligation | $ | 85,744 | $ | 54,338 | |||
Liabilities incurred and assumed during period | 12,477 | 4,291 | |||||
Liabilities assumed in the Encore Merger | - | 43,783 | |||||
Revisions in estimated retirement obligations | 12,217 | 5,505 | |||||
Liabilities settled during period | (23,225) | (6,622) | |||||
Accretion expense | 6,287 | 6,443 | |||||
Sales of properties | (32) | (21,994) | |||||
Ending asset retirement obligation | 93,468 | 85,744 | |||||
Less: current asset retirement obligation(1) | (4,742) | (4,454) | |||||
Long-term asset retirement obligation | $ | 88,726 | $ | 81,290 | |||
(1) | Included in "Accounts payable and accrued liabilities" in our Consolidated Balance Sheets |
|
The following table presents a summary of our net property and equipment balances as of December 31, 2011 and 2010:
December 31, | ||||||||
In thousands | 2011 | 2010 | ||||||
Oil and natural gas properties | ||||||||
Proved properties | $ | 7,026,579 | $ | 6,042,442 | ||||
Unevaluated properties | 1,157,106 | 870,130 | ||||||
Total | 8,183,685 | 6,912,572 | ||||||
Accumulated depletion and depreciation | (2,407,520) | (2,045,091) | ||||||
Net oil and natural gas properties | 5,776,165 | 4,867,481 | ||||||
CO2 properties | ||||||||
CO2 properties | 596,003 | 522,091 | ||||||
Accumulated depletion and depreciation | (91,666) | (68,479) | ||||||
Net CO2 properties | 504,337 | 453,612 | ||||||
Pipelines and plants | ||||||||
CO2 pipelines in service | 1,277,326 | 1,240,710 | ||||||
CO2 pipelines under construction(1) | 155,320 | 53,922 | ||||||
Plants under construction(1) | 269,110 | 83,607 | ||||||
Total | 1,701,756 | 1,378,239 | ||||||
Accumulated depletion and depreciation | (65,392) | (31,866) | ||||||
Net plants and pipelines | 1,636,364 | 1,346,373 | ||||||
Other property and equipment | ||||||||
Other property and equipment | 157,674 | 121,973 | ||||||
Accumulated depletion and depreciation | (62,915) | (52,081) | ||||||
Net other property and equipment | 94,759 | 69,892 | ||||||
Net property and equipment | $ | 8,011,625 | $ | 6,737,358 | ||||
(1) | Amounts primarily include the Greencore pipeline in southwestern Wyoming, which is expected to be completed in late 2012, and the Riley Ridge gas plant, which is currently expected to be placed in service in the second quarter of 2012. Amounts are excluded from DD&A expense until placed into service. |
A summary of the unevaluated properties excluded from oil and natural gas properties being amortized at December 31, 2011, and the year in which they were incurred follows:
December 31, 2011 | ||||||||||||||||
Costs Incurred During: | ||||||||||||||||
In thousands | 2011 | 2010 | 2009 | 2008 and prior | Total | |||||||||||
Property acquisition costs | $ | 12,543 | $ | 560,314 | $ | 94,969 | $ | 49,566 | $ | 717,392 | ||||||
Exploration and development | 270,062 | 86,251 | 3,758 | 6,682 | 366,753 | |||||||||||
Capitalized interest | 44,853 | 20,958 | 3,228 | 3,922 | 72,961 | |||||||||||
Total | $ | 327,458 | $ | 667,523 | $ | 101,955 | $ | 60,170 | $ | 1,157,106 |
|
The following long-term debt and capital lease obligations were outstanding as of December 31, 2011 and 2010:
December 31, | |||||||
In thousands | 2011 | 2010 | |||||
Bank Credit Agreement | $ | 385,000 | $ | - | |||
7½% Senior Subordinated Notes due 2013, including discount of $437 | - | 224,563 | |||||
7½% Senior Subordinated Notes due 2015, including premium of $427 | - | 300,427 | |||||
9½% Senior Subordinated Notes due 2016, including premium of $11,854 and $14,589, respectively | 236,774 | 239,509 | |||||
9¾% Senior Subordinated Notes due 2016, including discount of $17,854 and $22,139, respectively | 408,496 | 404,211 | |||||
8¼% Senior Subordinated Notes due 2020 | 996,273 | 996,273 | |||||
6⅜% Senior Subordinated Notes due 2021 | 400,000 | - | |||||
Other Subordinated Notes, including premium of $33 and $41, respectively | 3,840 | 3,848 | |||||
NEJD financing | 163,677 | 167,331 | |||||
Free State financing | 79,597 | 81,188 | |||||
Capital lease obligations | 4,388 | 6,806 | |||||
Total | 2,678,045 | 2,424,156 | |||||
Less: current obligations | (8,316) | (7,948) | |||||
Long-term debt and capital lease obligations | $ | 2,669,729 | $ | 2,416,208 |
Indebtedness Repayment Schedule
At December 31, 2011, our indebtedness, including our capital and financing lease obligations but excluding the discount and premium on our senior subordinated debt, is payable over the next five years and thereafter as follows
In thousands | ||||
2012 | $ | 8,316 | ||
2013 | 10,148 | |||
2014 | 12,963 | |||
2015 | 10,603 | |||
2016 | 1,046,359 | |||
Thereafter | 1,595,623 | |||
Total indebtedness | $ | 2,684,012 |
|
Our income tax provision (benefit) is as follows:
Year Ended December 31, | ||||||||||||
In thousands | 2011 | 2010 | 2009 | |||||||||
Current income tax expense (benefit) | ||||||||||||
Federal | $ | (12,552) | $ | 15,683 | $ | 7,090 | ||||||
State | 20,801 | 17,511 | (2,479) | |||||||||
Total current income tax expense | 8,249 | 33,194 | 4,611 | |||||||||
Deferred income tax expense (benefit) | ||||||||||||
Federal | 329,715 | 143,381 | (50,457) | |||||||||
State | 12,748 | 16,968 | (1,187) | |||||||||
Total deferred income tax expense (benefit) | 342,463 | 160,349 | (51,644) | |||||||||
Total income tax expense (benefit) | $ | 350,712 | $ | 193,543 | $ | (47,033) |
Significant components of our deferred tax assets and liabilities as of December 31, 2011 and 2010 are as follows:
December 31, | |||||||||
In thousands | 2011 | 2010 | |||||||
Deferred tax assets: | |||||||||
Loss carryforwards — federal | $ | 13,970 | $ | - | |||||
Loss carryforwards — state | 41,960 | 44,595 | |||||||
Tax credit carryover | 34,829 | 34,476 | |||||||
Derivative contracts | 3,551 | 24,918 | |||||||
Enhanced oil recovery credit carryforwards | 53,381 | 39,810 | |||||||
Stock based compensation | 32,566 | 38,947 | |||||||
Other | 35,279 | 45,950 | |||||||
Total deferred tax assets | 215,536 | 228,696 | |||||||
Deferred tax liabilities: | |||||||||
Property and equipment | (2,078,143) | (1,738,269) | |||||||
Other | (5,813) | (10,965) | |||||||
Total deferred tax liabilities | (2,083,956) | (1,749,234) | |||||||
Total net deferred tax liability | $ | (1,868,420) | $ | (1,520,538) |
Our reconciliation of income tax expense (benefit) computed by applying the U.S. federal statutory rate and the reported effective tax rate on income (loss) from continuing operations is as follows:
Year Ended December 31, | |||||||||||
In thousands | 2011 | 2010 | 2009 | ||||||||
Income tax provision (benefit) calculated using the federal statutory income tax rate | $ | 323,416 | $ | 167,674 | $ | (42,765) | |||||
State income taxes, net of federal income tax benefit | 29,555 | 13,087 | (3,666) | ||||||||
Revaluation of deferred tax liabilities, net | (578) | 11,502 | - | ||||||||
Other | (1,681) | 1,280 | (602) | ||||||||
Total income tax expense (benefit) | $ | 350,712 | $ | 193,543 | $ | (47,033) |
|
Stock-based compensation costs for the years ended December 31, 2011, 2010 and 2009, respectively, are as follows:
Year Ended December 31, | |||||||||||
In thousands | 2011 | 2010 | 2009 | ||||||||
Stock-based compensation expensed: | |||||||||||
General and administrative expense | $ | 30,256 | $ | 28,169 | $ | 20,435 | |||||
Lease operating expense | 2,621 | 2,056 | 1,432 | ||||||||
Transaction and other costs related to the Encore Merger | 313 | 5,866 | - | ||||||||
Total stock-based compensation expensed | 33,190 | 36,091 | 21,867 | ||||||||
Stock-based compensation capitalized | 6,998 | 3,702 | 2,455 | ||||||||
Total cost of stock-based compensation arrangements | $ | 40,188 | $ | 39,793 | $ | 24,322 | |||||
Income tax benefit recognized for stock-based compensation arrangements | $ | 12,902 | $ | 14,359 | $ | 8,749 |
2011 | 2010 | 2009 | ||||||||
Weighted average fair value of SARs granted | $ | 9.68 | $ | 8.45 | $ | 6.40 | ||||
Risk-free interest rate | 1.74% | 2.19% | 1.58% | |||||||
Expected life | 4.0 to 5.0 years | 4.0 to 4.3 years | 3.9 to 4.7 years | |||||||
Expected volatility | 63.3% | 65.0% | 60.1% | |||||||
Dividend yield | - | - | - |
The following is a summary of our stock option and SAR activity:
Year Ended December 31, | |||||||||||||||
2011 | 2010 | 2009 | |||||||||||||
Weighted | Weighted | Weighted | |||||||||||||
Number | Average | Number | Average | Number | Average | ||||||||||
of Awards | Exercise Price | of Awards | Exercise Price | of Awards | Exercise Price | ||||||||||
Outstanding at beginning of period | 12,269,340 | $ | 12.28 | 10,763,955 | $ | 10.77 | 9,514,999 | $ | 9.32 | ||||||
Granted | 1,507,992 | 18.69 | 3,444,494 | 16.30 | 2,883,311 | 13.23 | |||||||||
Exercised | (1,448,358) | 6.97 | (1,119,853) | 6.21 | (1,315,535) | 4.33 | |||||||||
Forfeited or expired | (379,364) | 17.89 | (819,256) | 17.57 | (318,820) | 16.36 | |||||||||
Outstanding at end of period | 11,949,610 | 13.56 | 12,269,340 | 12.28 | 10,763,955 | 10.77 | |||||||||
Exercisable at end of period | 6,179,154 | $ | 10.18 | 6,214,546 | $ | 8.07 | 6,087,019 | $ | 6.48 |
A summary of the status of our non-vested stock options and SARs as of December 31, 2011, and the changes during the year ended December 31, 2011, is presented below:
Weighted | |||||
Average | |||||
Grant-Date | |||||
Awards | Fair Value | ||||
Non-vested at December 31, 2010 | 6,054,794 | $ | 8.02 | ||
Granted | 1,507,992 | 9.68 | |||
Vested | (1,452,626) | 7.85 | |||
Forfeited | (339,704) | 8.87 | |||
Non-vested at December 31, 2011 | 5,770,456 | 8.44 |
A summary of the status of our non-vested restricted stock grants and the changes during the year ended December 31, 2011, is presented below:
Weighted | |||||
Average | |||||
Grant-Date | |||||
Shares | Fair Value | ||||
Non-vested at December 31, 2010 | 2,948,834 | $ | 13.70 | ||
Granted | 1,134,627 | 18.83 | |||
Vested | (818,215) | 15.89 | |||
Forfeited | (133,811) | 17.74 | |||
Non-vested at December 31, 2011 | 3,131,435 | 14.82 |
A summary of the status of the non-vested restricted stock grants under the Encore Plan and the changes during the year ended December 31, 2011, is presented below:
Weighted | |||||
Average | |||||
Grant-Date | |||||
Shares | Fair Value | ||||
Non-vested at December 31, 2010 | 276,620 | $ | 15.42 | ||
Granted | - | - | |||
Vested | (149,577) | 15.43 | |||
Forfeited | (24,000) | 15.43 | |||
Non-vested at December 31, 2011 | 103,043 | 15.43 |
|
The following is a summary of “Derivatives expense (income)” included in our Consolidated Statements of Operations:
Year Ended December 31, | |||||||||||
In thousands | 2011 | 2010 | 2009 | ||||||||
Oil | |||||||||||
Payment (receipt) on settlements of derivative contracts | $ | 25,128 | $ | 93,417 | $ | (146,734) | |||||
Fair value adjustments to derivative contracts – expense (income) | (58,980) | (44,441) | 375,750 | ||||||||
Total derivative expense (income) – oil | (33,852) | 48,976 | 229,016 | ||||||||
Natural gas | |||||||||||
Payment (receipt) on settlements of derivative contracts | (27,505) | (61,805) | - | ||||||||
Fair value adjustments to derivative contracts – expense (income) | 8,860 | (8,585) | 7,210 | ||||||||
Total derivative expense (income) – natural gas | (18,645) | (70,390) | 7,210 | ||||||||
Ineffectiveness on interest rate swaps | - | (2,419) | - | ||||||||
Derivative expense (income) | $ | (52,497) | $ | (23,833) | $ | 236,226 |
Commodity Derivative Contracts Not Classified as Hedging Instruments | ||||||||||||||||||||
Contract Prices(1) | ||||||||||||||||||||
Type of | Weighted Average Price(2) | |||||||||||||||||||
Year | Months | Contract | Volume(1) | Range | Swap | Floor | Ceiling | |||||||||||||
Oil Contracts: | ||||||||||||||||||||
2012 | Jan – Mar | Swap | 625 | $ | 80.28 – 81.75 | $ | 81.04 | $ | - | $ | - | |||||||||
Collar | 52,000 | 70.00 – 139.60 | - | 70.00 | 106.86 | |||||||||||||||
Put | 625 | 65.00 – 65.00 | - | 65.00 | - | |||||||||||||||
Total Jan – Mar 2012 | 53,250 | |||||||||||||||||||
Apr – June | Swap | 625 | $ | 80.28 – 81.75 | $ | 81.04 | $ | - | $ | - | ||||||||||
Collar | 53,000 | 70.00 – 137.50 | - | 70.00 | 119.44 | |||||||||||||||
Put | 625 | 65.00 – 65.00 | - | 65.00 | - | |||||||||||||||
Total Apr – June 2012 | 54,250 | |||||||||||||||||||
July – Sept | Swap | 625 | $ | 80.28 – 81.75 | $ | 81.04 | $ | - | $ | - | ||||||||||
Collar | 53,000 | 80.00 – 140.65 | - | 80.00 | 128.57 | |||||||||||||||
Put | 625 | 65.00 – 65.00 | - | 65.00 | - | |||||||||||||||
Total July – Sept 2012 | 54,250 | |||||||||||||||||||
Oct – Dec | Swap | 625 | $ | 80.28 – 81.75 | $ | 81.04 | $ | - | $ | - | ||||||||||
Collar | 53,000 | 80.00 – 140.65 | - | 80.00 | 128.57 | |||||||||||||||
Put | 625 | 65.00 – 65.00 | - | 65.00 | - | |||||||||||||||
Total Oct – Dec 2012 | 54,250 | |||||||||||||||||||
2013 | Jan – Mar | Swap | - | $ | - | $ | - | $ | - | $ | - | |||||||||
Collar | 55,000 | 70.00 – 117.00 | - | 70.00 | 110.32 | |||||||||||||||
Put | - | - | - | - | - | |||||||||||||||
Total Jan – Mar 2013 | 55,000 | |||||||||||||||||||
Apr – June | Swap | - | $ | - | $ | - | $ | - | $ | - | ||||||||||
Collar | 42,000 | 75.00 – 118.00 | - | 75.00 | 115.91 | |||||||||||||||
Put | - | - | - | - | - | |||||||||||||||
Total Apr – June 2013 | 42,000 | |||||||||||||||||||
Natural Gas Contracts: | ||||||||||||||||||||
2012 | Jan – Dec | Swap | 20,000 | $ | 6.30 – 6.85 | $ | 6.53 | $ | - | $ | - | |||||||||
Collar | - | - | - | - | - | |||||||||||||||
Put | - | - | - | - | - | |||||||||||||||
Total Jan – Dec 2012 | 20,000 | |||||||||||||||||||
(1) | Contract volumes are stated in BBl/d and MMBtu/d for oil and natural gas contracts, respectively. | |||||||||||||||||||
(2) | Contract prices are stated in $/BBl and $/MMBtu for oil and natural gas contracts, respectively. |
At December 31, 2011 and 2010, we had derivative financial instruments recorded in our Consolidated Balance Sheets as follows:
Estimated Fair Value | |||||||||||
Asset (Liability) | |||||||||||
December 31, | |||||||||||
Type of Contract | Balance Sheet Location | 2011 | 2010 | ||||||||
In thousands | |||||||||||
Derivatives not designated as hedging instruments: | |||||||||||
Derivative Assets | |||||||||||
Crude oil contracts | Derivative assets – current | $ | 23,452 | $ | 3,050 | ||||||
Natural gas contracts | Derivative assets – current | 23,950 | 21,192 | ||||||||
Crude oil contracts | Derivative assets – long-term | 29 | 1,301 | ||||||||
Natural gas contracts | Derivative assets – long-term | - | 11,618 | ||||||||
Derivative Liabilities | |||||||||||
Crude oil contracts | Derivative liabilities – current | (22,610) | (55,256) | ||||||||
Natural gas contracts | Derivative liabilities – current | - | - | ||||||||
Deferred premiums(1) | Derivative liabilities – current | (3,913) | (22,928) | ||||||||
Crude oil contracts | Derivative liabilities – long-term | (18,702) | (25,906) | ||||||||
Natural gas contracts | Derivative liabilities – long-term | - | - | ||||||||
Deferred premiums(1) | Derivative liabilities – long-term | (170) | (3,781) | ||||||||
Total derivatives not designated as hedging instruments | $ | 2,036 | $ | (70,710) | |||||||
(1) | Deferred premiums payable relate to various oil and natural gas floor contracts and are payable on a monthly basis through December 2012. |
|
The following table sets forth by level within the fair value hierarchy our financial assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2011 and 2010:
Fair Value Measurements Using: | ||||||||||||||
Significant | ||||||||||||||
Quoted Prices | Other | Significant | ||||||||||||
in Active | Observable | Unobservable | ||||||||||||
Markets | Inputs | Inputs | ||||||||||||
In thousands | (Level 1) | (Level 2) | (Level 3) | Total | ||||||||||
December 31, 2011 | ||||||||||||||
Assets: | ||||||||||||||
Short-term investments | $ | 86,682 | $ | - | $ | - | $ | 86,682 | ||||||
Oil and natural gas derivative contracts | - | 23,481 | 23,950 | 47,431 | ||||||||||
Liabilities: | ||||||||||||||
Oil and natural gas derivative contracts | - | (41,312) | - | (41,312) | ||||||||||
Total | $ | 86,682 | $ | (17,831) | $ | 23,950 | $ | 92,801 | ||||||
December 31, 2010 | ||||||||||||||
Assets: | ||||||||||||||
Short-term investments | $ | 93,020 | $ | - | $ | - | $ | 93,020 | ||||||
Oil and natural gas derivative contracts | - | 20,683 | 16,478 | 37,161 | ||||||||||
Liabilities: | ||||||||||||||
Oil and natural gas derivative contracts | - | (81,162) | - | (81,162) | ||||||||||
Total | $ | 93,020 | $ | (60,479) | $ | 16,478 | $ | 49,019 |
The following table summarizes the changes in the fair value of our Level 3 assets and liabilities for the years ended December 31, 2011 and 2010:
Year Ended December 31, | ||||||||
In thousands | 2011 | 2010 | ||||||
Fair value of Level 3 instruments, beginning of year | $ | 16,478 | $ | - | ||||
Commodity derivative contracts acquired in Encore Merger | - | 38,093 | ||||||
Unrealized gains (losses) on commodity derivative contracts included in earnings | 13,384 | 21,240 | ||||||
Receipts on settlement of commodity derivative contracts | (5,912) | (42,855) | ||||||
Fair value of Level 3 instruments, end of year | $ | 23,950 | $ | 16,478 | ||||
The amount of total gains for the period included in earnings attributable to the change in | ||||||||
unrealized gains relating to assets still held at the reporting date | $ | 13,384 | $ | 21,240 |
|
The following table summarizes by year the remaining non-cancelable future payments under these operating leases as of December 31, 2011:
Pipeline | |||||||||||
Financing | Capital | Operating | |||||||||
In thousands | Leases | Leases | Leases | ||||||||
2012 | $ | 30,689 | $ | 2,206 | $ | 36,207 | |||||
2013 | 32,469 | 1,447 | 37,509 | ||||||||
2014 | 34,036 | 664 | 34,369 | ||||||||
2015 | 31,847 | 106 | 33,536 | ||||||||
2016 | 30,912 | 106 | 31,349 | ||||||||
Thereafter | 344,233 | 510 | 74,269 | ||||||||
Total minimum lease payments | 504,186 | 5,039 | $ | 247,239 | |||||||
Less: Amount representing interest | (260,912) | (651) | |||||||||
Present value of minimum lease payments | $ | 243,274 | $ | 4,388 |
|
December 31, | |||||||
In thousands | 2011 | 2010 | |||||
Accrued exploration and development costs | $ | 141,868 | $ | 101,758 | |||
Accounts payable | 99,444 | 47,660 | |||||
Accrued interest | 60,923 | 57,077 | |||||
Accrued compensation | 35,861 | 39,757 | |||||
Accrued lease operating expenses | 24,185 | 23,557 | |||||
Deferred Riley Ridge acquisition consideration | 15,000 | - | |||||
Taxes payable | 13,455 | 34,371 | |||||
Other | 38,600 | 45,888 | |||||
Total | $ | 429,336 | $ | 350,068 |
Year Ended December 31, | ||||||||||
In thousands, except shares | 2011 | 2010 | 2009 | |||||||
Supplemental cash flow information: | ||||||||||
Cash paid for interest, expensed | $ | 137,259 | $ | 151,831 | $ | 20,924 | ||||
Cash paid for interest, capitalized | 60,540 | 66,815 | 68,596 | |||||||
Cash paid for income taxes | 45,912 | 17,960 | 16,002 | |||||||
Cash received from income tax refunds | 24,677 | 15,107 | 15,761 | |||||||
Non-cash investing activities: | ||||||||||
Increase in asset retirement obligations | 24,694 | 53,579 | 11,268 | |||||||
Increase (decrease) in liabilities for capital expenditures | 74,697 | (237) | (76,605) | |||||||
Issuance of Denbury common stock in connection with the Encore Merger | - | 2,085,681 | - | |||||||
Vanguard common units received as consideration for sale of ENP | - | 93,020 | - | |||||||
Issuance of Denbury common stock pursuant to Conroe Field acquisition | - | - | 168,723 |
|
Costs incurred in oil and natural gas activities were as follows:
Year Ended December 31, | |||||||||||
In thousands | 2011 | 2010 | 2009 | ||||||||
Property acquisitions: | |||||||||||
Proved | $ | 86,465 | $ | 3,373,450 | $ | 585,637 | |||||
Unevaluated | 17,858 | 1,297,695 | 104,772 | ||||||||
Exploration | 31,483 | 8,728 | 4,635 | ||||||||
Development | 1,144,243 | 658,758 | 292,545 | ||||||||
Total costs incurred (1) | $ | 1,280,049 | $ | 5,338,631 | $ | 987,589 | |||||
(1) | Capitalized general and administrative costs that directly relate to exploration and development activities were $35.0 million, $20.1 million and $14.0 million for the years ended December 31, 2011, 2010 and 2009, respectively. |
Results of operations from oil and natural gas producing activities, excluding corporate overhead and interest costs, were as follows:
Year Ended December 31, | |||||||||||
In thousands, except per BOE data | 2011 | 2010 | 2009 | ||||||||
Oil, natural gas and related product sales | $ | 2,269,151 | $ | 1,793,292 | $ | 866,709 | |||||
Lease operating costs | 507,397 | 470,364 | 314,689 | ||||||||
Marketing expenses | 26,047 | 31,036 | 16,890 | ||||||||
Taxes other than income | 138,419 | 114,569 | 37,037 | ||||||||
Depletion, depreciation and amortization | 369,075 | 391,782 | 206,999 | ||||||||
CO2 depletion, depreciation and amortization (1) | 24,460 | 29,206 | 29,076 | ||||||||
Commodity derivative expense (income) | (52,497) | (21,414) | 236,226 | ||||||||
Net operating income | 1,256,250 | 777,749 | 25,792 | ||||||||
Income tax provision | 477,375 | 295,545 | 9,927 | ||||||||
Results of operations from oil and natural gas producing activities | $ | 778,875 | $ | 482,204 | $ | 15,865 | |||||
Depletion, depreciation and amortization per BOE | $ | 16.42 | $ | 15.82 | $ | 13.39 | |||||
(1) | Represents an allocation of the depletion, depreciation and amortization of our CO2 properties and pipelines associated with our tertiary oil producing activities. |
Year Ended December 31, | |||||||||||||||||||
2011 | 2010 | 2009 | |||||||||||||||||
Oil | Gas | Total | Oil | Gas | Total | Oil | Gas | Total | |||||||||||
(MBbl) | (MMcf) | (MBOE) | (MBbl) | (MMcf) | (MBOE) | (MBbl) | (MMcf) | (MBOE) | |||||||||||
Balance at beginning of year | 338,276 | 357,893 | 397,925 | 192,879 | 87,975 | 207,542 | 179,126 | 427,955 | 250,452 | ||||||||||
Revisions of previous estimates | (4,478) | (14,058) | (6,821) | 3,538 | 16,171 | 6,233 | (69) | (1,298) | (285) | ||||||||||
Revisions due to price changes | 2,558 | 485 | 2,639 | 2,780 | 811 | 2,915 | 4,557 | (2,079) | 4,211 | ||||||||||
Extensions and discoveries | 42,936 | 52,339 | 51,658 | 26,313 | 130,245 | 48,021 | 334 | 11,785 | 2,298 | ||||||||||
Improved recovery(1) | 264 | - | 264 | 30,173 | - | 30,173 | 13,875 | - | 13,875 | ||||||||||
Production | (22,169) | (10,783) | (23,966) | (21,870) | (28,491) | (26,619) | (13,495) | (24,764) | (17,622) | ||||||||||
Acquisition of minerals in place | 346 | 239,332 | 40,235 | 155,021 | 622,984 | 258,852 | 28,379 | 2,317 | 28,765 | ||||||||||
Sales of minerals in place | - | - | - | (50,558) | (471,802) | (129,192) | (19,828) | (325,941) | (74,152) | ||||||||||
Balance at end of year | 357,733 | 625,208 | 461,934 | 338,276 | 357,893 | 397,925 | 192,879 | 87,975 | 207,542 | ||||||||||
Proved Developed Reserves: | |||||||||||||||||||
Balance at beginning of year | 219,077 | 110,516 | 237,496 | 116,192 | 69,513 | 127,778 | 96,746 | 298,114 | 146,432 | ||||||||||
Balance at end of year | 239,741 | 125,970 | 260,736 | 219,077 | 110,516 | 237,496 | 116,192 | 69,513 | 127,778 | ||||||||||
(1) Improved recovery additions result from the application of secondary recovery methods such as water flooding, or tertiary recovery methods such as CO2 flooding. |
The following representative oil and natural gas prices were used in the Standardized Measure. These prices were adjusted by field to arrive at the appropriate corporate net price.
December 31, | |||||||||
2011 | 2010 | 2009 | |||||||
Oil (NYMEX) | $ | 96.19 | $ | 79.43 | $ | 61.18 | |||
Natural Gas (Henry Hub) | 4.16 | 4.40 | 3.87 |
December 31, | ||||||||||
In thousands | 2011 | 2010 | 2009 | |||||||
Future cash inflows | $ | 38,165,122 | $ | 26,698,819 | $ | 11,579,159 | ||||
Future production costs | (12,570,015) | (9,702,896) | (5,034,393) | |||||||
Future development costs | (3,026,898) | (1,912,457) | (836,455) | |||||||
Future income taxes | (7,379,972) | (4,700,023) | (1,257,844) | |||||||
Future net cash flows | 15,188,237 | 10,383,443 | 4,450,467 | |||||||
10% annual discount for estimated timing of cash flows | (8,180,632) | (5,465,516) | (1,993,082) | |||||||
Standardized measure of discounted future net cash flows | $ | 7,007,605 | $ | 4,917,927 | $ | 2,457,385 |
The following table sets forth an analysis of changes in the Standardized Measure of Discounted Future Net Cash Flows from proved oil and natural gas reserves:
Year Ended December 31, | |||||||||||
In thousands | 2011 | 2010 | 2009 | ||||||||
Beginning of year | $ | 4,917,927 | $ | 2,457,385 | $ | 1,415,498 | |||||
Sales of oil and natural gas produced, net of production costs | (1,597,288) | (1,177,322) | (498,093) | ||||||||
Net changes in sales prices | 4,646,086 | 2,062,181 | 1,263,346 | ||||||||
Extensions and discoveries, less applicable future development and production costs | 762,370 | 295,074 | 6,735 | ||||||||
Improved recovery(1) | 15,708 | 623,622 | 202,145 | ||||||||
Previously estimated development costs incurred | 354,228 | 193,947 | 98,659 | ||||||||
Revisions of previous estimates, including revised estimates of development costs, reserves and rates of production | (1,673,283) | (285,158) | (63,044) | ||||||||
Accretion of discount | 729,234 | 307,546 | 192,686 | ||||||||
Acquisition of minerals in place | 29,737 | 3,671,439 | 365,771 | ||||||||
Sales of minerals in place | - | (1,474,443) | (419,601) | ||||||||
Net change in income taxes | (1,177,114) | (1,756,344) | (106,717) | ||||||||
End of year | $ | 7,007,605 | $ | 4,917,927 | $ | 2,457,385 | |||||
(1) | Improved recovery additions result from the application of secondary recovery methods such as water flooding or tertiary recovery methods such as CO2 flooding. |
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Based on engineering reports prepared by DeGolyer and MacNaughton, proved CO2 and helium reserves were estimated as follows (in MMcf):
Year Ended December 31, | ||||||||
2011 | 2010 | 2009 | ||||||
CO2 Reserves | ||||||||
Gulf Coast region(1) | 6,685,412 | 7,085,131 | 6,302,836 | |||||
Rocky Mountain region(2) | 2,195,534 | 2,189,756 | - | |||||
Helium Reserves Associated with Denbury's Production Rights | ||||||||
Rocky Mountain region(3) | 12,004 | 7,159 | - | |||||
(1) | Proved CO2 reserves in the Gulf Coast region consist of reserves from our reservoirs at Jackson Dome and are presented on a gross working interest basis, of which Denbury’s net revenue interest was approximately 5.3 Tcf, 5.6 Tcf and 5.0 Tcf at December 31, 2011, 2010 and 2009, respectively, and include reserves dedicated to volumetric production payments of 84.7 Bcf, 100.2 Bcf and 127.1 Bcf at December 31, 2011, 2010 and 2009, respectively. | |||||||
(2) | Proved CO2 reserves in the Rocky Mountain region consist of our reserves at Riley Ridge and are presented on a gross working interest basis, of which Denbury’s net revenue interest was approximately 1.6 Tcf and 0.9 Tcf at December 31, 2011 and 2010, respectively. | |||||||
(3) | Reserves associated with helium production rights include helium reserves located in the acreage in the Rocky Mountain region for which we have the right to extract the helium. The U.S. government retains title to the helium reserves and we retain the right to extract and sell the helium on behalf of the government in exchange for a fee. The helium reserves are presented net of the fee we will remit to the U.S. government. |
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In thousands, except per share amounts | March 31 | June 30 | September 30 | December 31 | |||||||||
2011 | |||||||||||||
Revenues and other income | $ | 514,165 | $ | 601,397 | $ | 576,505 | $ | 617,257 | |||||
Expenses | 537,111 | 177,595 | 133,185 | 537,388 | |||||||||
Net income (loss) | (14,190) | 259,246 | 275,670 | 52,607 | |||||||||
Net income (loss) per share: | |||||||||||||
Basic | (0.04) | 0.65 | 0.69 | 0.14 | |||||||||
Diluted | (0.04) | 0.64 | 0.68 | 0.13 | |||||||||
Cash flow from operating activities | 124,832 | 398,521 | 315,739 | 365,722 | |||||||||
Cash flow used for investing activities | (285,043) | (347,797) | (525,412) | (447,706) | |||||||||
Cash flow provided by (used for) financing activities | (93,801) | (56,789) | 112,244 | 76,314 | |||||||||
2010 | |||||||||||||
Revenues and other income | $ | 438,821 | $ | 497,210 | $ | 466,703 | $ | 519,057 | |||||
Expenses | 261,676 | 265,518 | 415,170 | 500,357 | |||||||||
Net income | 96,888 | 135,367 | 29,104 | 10,364 | |||||||||
Net income per share: | |||||||||||||
Basic | 0.33 | 0.34 | 0.07 | 0.03 | |||||||||
Diluted | 0.32 | 0.34 | 0.07 | 0.03 | |||||||||
Cash flow from operating activities | 113,168 | 271,123 | 208,484 | 263,036 | |||||||||
Cash flow provided by (used for) investing activities | (764,327) | 505,713 | (261,539) | 165,373 | |||||||||
Cash flow provided by (used for) financing activities | 739,753 | (818,547) | 71,926 | (132,885) |
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