|• FORM 10-Q • EXHIBIT 4(A • EXHIBIT 10(A • EXHIBIT 10(B • EXHIBIT 10(C • EXHIBIT 31(A • EXHIBIT 31(B • EXHIBIT 32 • XBRL INSTANCE DOCUMENT • XBRL TAXONOMY EXTENSION SCHEMA • XBRL TAXONOMY EXTENSION CALCULATION LINKBASE • XBRL TAXONOMY EXTENSION DEFINITION LINKBASE • XBRL TAXONOMY EXTENSION LABELS LINKBASE • XBRL TAXONOMY EXTENSION PRESENTATION LINKBASE|
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
For the quarterly period ended March 31, 2012
For the transition period from _______ to ________
Commission file number: 001-12935
DENBURY RESOURCES INC.
(Exact name of registrant as specified in its charter)
(Former name, former address and former fiscal year, if changed since last report)
Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.Yes þ No o
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).Yes þ No o
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No þ
Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date.
Table of Contents
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Note 1. Basis of Presentation
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.
Interim Financial Statements
The accompanying unaudited condensed consolidated financial statements of Denbury Resources Inc. and its subsidiaries have been prepared in accordance with the rules and regulations of the Securities and Exchange Commission (“SEC”) and do not include all of the information and footnotes required by Accounting Principles Generally Accepted in the United States (“U.S. GAAP”) for complete financial statements. These financial statements and the notes thereto should be read in conjunction with our Annual Report on Form 10-K for the year ended December 31, 2011. Unless indicated otherwise or the context requires, the terms “we,” “our,” “us,” “Company,” or “Denbury,” refer to Denbury Resources Inc. and its subsidiaries.
Accounting measurements at interim dates inherently involve greater reliance on estimates than at year-end and the results of operations for the interim periods shown in this report are not necessarily indicative of results to be expected for the year. In management’s opinion, the accompanying unaudited condensed consolidated financial statements include all adjustments of a normal recurring nature necessary for a fair statement of our consolidated financial position as of March 31, 2012, our consolidated results of operations for the three months ended March 31, 2012 and 2011, and our consolidated cash flows for the three months ended March 31, 2012 and 2011. Certain prior period items have been reclassified to make the classification consistent with the classification in the most recent quarter. On the Unaudited Condensed Consolidated Statements of Operations for the three months ended March 31, 2011, “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,” 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 expenses.” Such reclassifications had no impact on our reported total expenses or net income.
Restricted cash consists of proceeds from the sale of oil and gas properties in February 2012 that are held by a qualified intermediary and are restricted for the pending acquisition of Thompson Field (see Note 8, Subsequent Events) to facilitate an anticipated like-kind exchange transaction.
Net Income Per Common Share
Basic net income per common share is computed by dividing 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”), nonvested restricted stock, and nonvested performance equity awards. For the three months ended March 31, 2012 and 2011, there were no adjustments to net income for purposes of calculating diluted net income per common share.
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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:
Basic weighted average common shares excludes 3.9 million and 3.7 million shares of nonvested restricted stock during the three months ended March 31, 2012 and 2011, 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 nonvested 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 excluded from the computation of diluted net income per share as their effect would have been antidilutive:
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, 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 Encore Energy Partners LP to a subsidiary of Vanguard on December 31, 2010. We received distributions of $1.8 million on the Vanguard common units we owned for the three months ended March 31, 2011, which are included in “Interest income and other income” on our Unaudited Condensed Consolidated Statements of Operations. During January 2012, the Company sold its investment in Vanguard for cash consideration of $83.5 million, net of related transaction fees. The Company recognized a pretax loss on the sale of $3.1 million, which is included in “Other expenses” on our Unaudited Condensed Consolidated Statements of Operations for the three months ended March 31, 2012.
Recently Adopted Accounting Pronouncements
Comprehensive Income. In June 2011, the Financial Accounting Standards Board (“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. ASU 2011-05 was effective for Denbury beginning January 1, 2012. Since ASU 2011-05 only amended presentation requirements, it did not 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 Financial Accounting Standards Board Codification (“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 was effective for Denbury beginning January 1, 2012. The adoption of ASU 2011-04 did not have a material effect on our consolidated financial statements, but did require additional disclosures. See Note 5, Fair Value Measurements.
Note 2. Acquisitions and Divestitures
August 2011 Acquisition of Reserves in Rocky Mountain Region at Riley Ridge
In August 2011, we acquired the remaining 57.5% working interest in the Riley Ridge Federal Unit (“Riley Ridge”), located in the LaBarge Field of southwestern Wyoming. Riley Ridge contains natural gas resources, as well as helium and CO2 resources. The purchase included a 57.5% interest in a gas plant which will separate the helium and natural gas from the commingled gas stream, and interests in certain surrounding properties. The purchase price was approximately $214.8 million after closing adjustments, including a $15.0 million deferred payment to be made at the time the Riley Ridge gas plant is operational and meets specific performance conditions. The gas plant is currently undergoing readiness testing, and we expect it to become operational during the fourth quarter of 2012.
The August 2011 acquisition of Riley Ridge meets the definition of a business under the FASC Business Combinations topic. The fair values assigned to assets acquired and liabilities assumed in the August 2011 acquisition have been finalized and no adjustments have been made to amounts previously disclosed in our Form 10-K for the period ended December 31, 2011. Because the Riley Ridge plant is not yet operational, 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.
On January 10, 2012, we entered into an agreement to sell certain non-core assets primarily located in central and southern Mississippi and in southern Louisiana for $155.0 million. We entered into the sales agreement with a privately held entity in which a member of our Board of Directors serves as chairman of the board, in a sale for which there was a competing bid contained in a multi-property purchase proposal. On February 29, 2012, we closed on the sale with net proceeds of $144.8 million, after preliminary closing adjustments. The sale had an effective date of December 1, 2011 and consequently, operating net revenues after the effective date, net of capital expenditures, along with any other purchase price adjustments, were adjustments to the selling price. We did not record a gain or loss on the sale of the properties in accordance with the full cost method of accounting.
Note 3. Long-Term Debt
The following table shows the components of our long-term debt:
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. Certain of DRI’s subsidiaries guarantee our debt, and each such subsidiary guarantor 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 obligations of the subsidiary guarantors.
Bank Credit Facility
In March 2010, we entered into a $1.6 billion revolving credit agreement with JPMorgan Chase Bank, N.A. as administrative agent, and other lenders party thereto (as amended 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 of each year and upon requested special redeterminations. The borrowing base is adjusted at the banks’ discretion and is based in part upon certain external factors over which we have no control. The weighted average interest rate on borrowings under the credit facility, evidenced by the Bank Credit Agreement (the “Bank Credit Facility”) was 2.0% for the three months ended March 31, 2012. We incur a commitment fee on the unused portion of the Bank Credit Facility of either 0.375% or 0.5%, based on the ratio of outstanding borrowings under the Bank Credit Facility to the borrowing base. The Bank Credit Agreement is scheduled to mature in May 2016.
In April 2012, we entered into the Seventh Amendment to the Bank Credit Agreement (the “Bank Amendment”). Under the Bank Amendment, we increased the amount of additional permitted subordinate debt (other than refinancing debt) from $300.0 million to $650.0 million. At the same time, the banks reaffirmed Denbury’s borrowing base of $1.6 billion under the Bank Credit Facility until the next redetermination, which is scheduled to occur on or around November 1, 2012.
6⅜% Senior Subordinated Notes due 2021
In February 2011, we issued $400.0 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 $393.0 million were used to repurchase a portion of our outstanding 2013 Notes and 2015 Notes (see Redemption of our 2013 and 2015 Notes below).
Redemption of our 2013 and 2015 Notes
On February 3, 2011, we commenced cash tender offers to purchase all $225.0 million principal amount of our 7½% Senior Subordinated Notes due 2013 (“2013 Notes”) and all $300.0 million principal amount of our 7½% Senior Subordinated Notes due 2015 (“2015 Notes”). Upon expiration of the tender offers on March 3, 2011, we accepted for purchase $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 Notes 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 $15.8 million loss during the three months ended March 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”.
Note 4. Derivative Instruments
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” in our Unaudited Condensed 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 18 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.
We manage and control market and counterparty credit risk through established internal control procedures that are reviewed on an ongoing basis. We attempt to minimize credit risk exposure to counterparties through formal credit policies, monitoring procedures, and diversification. We only enter into commodity derivative contracts with parties that are lenders under our Bank Credit Agreement.
The following is a summary of “Derivatives expense” included in the accompanying Unaudited Condensed Consolidated Statements of Operations for the periods indicated:
Commodity Derivative Contracts Not Classified as Hedging Instruments
The following tables present outstanding commodity derivative contracts with respect to future production as of March 31, 2012:
Additional Disclosures about Derivative Instruments
At March 31, 2012 and December 31, 2011, we had derivative financial instruments recorded in our Unaudited Condensed Consolidated Balance Sheets as follows:
Note 5. Fair Value Measurements
Fair value is 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 (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 the periods indicated:
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” in the accompanying Unaudited Condensed Consolidated Statements of Operations.
Level 3 Fair Value Measurements
Assets and Liabilities Measured at Fair Value on a Recurring Basis
The following table summarizes the changes in the fair value of our Level 3 assets for the three months ended March 31, 2012 and 2011:
We utilize an income approach to value our natural gas swap arrangements, generally the industry standard valuation technique for a commodity swap contract. We obtain and ensure the appropriateness of the natural gas forward pricing curve, the most significant input to the calculation, and the fair value estimate is prepared and reviewed on a quarterly basis.
The following table details fair value inputs related to our level 3 financial measurements:
Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis
As of December 31, 2011, we had invested a total of $13.8 million in the preferred stock of Faustina Hydrogen Products LLC, a company created to develop a proposed gasification plant from which CO2 would be produced as a byproduct and used by Denbury in its tertiary oil operations. The investment was recorded at cost, together with a $1.3 million receivable for accrued dividends receivable. The developer of the proposed plant was soliciting other potential investors for the project, and as of December 31, 2011, a third-party was actively engaged in due diligence. During 2012, a key investor and participant in the project announced its intent to abandon its investment in the proposed plant. As a result, due diligence by the potential third party investor ceased. Absent the key investor, we believe it is unlikely the plant will be constructed and therefore, it is also unlikely our investment will generate future cash flows. Accordingly, we recorded a $15.1 million impairment charge for this investment during the first quarter of 2012, which is classified as “Impairment of assets” in the Unaudited Condensed Consolidated Statements of Operations. The inputs used to determine fair value of the investment included the projected future cash flows of the plant and risk-adjusted rate of return that we estimated would be used by a market participant in valuing the asset. These inputs are unobservable within the marketplace and therefore considered level 3 within the fair value hierarchy. However, as there are currently no expected future cash flows associated with the plant, the fair value was determined to be $0.
Other Fair Value Measurements
The carrying value of our 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 senior subordinated notes as of March 31, 2012 and December 31, 2011 is $2,255.5 million and $2,253.2 million, respectively. The fair value hierarchy for long-term debt is primarily Level 1 (quoted prices for identical assets in active markets). 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.
Note 6. Commitments and Contingencies
We are involved in various lawsuits, claims and other 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, 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. We are also subject to audits for sales and use taxes and severance taxes in the various states in which we operate, and from time to time receive assessments for potential taxes that we may owe. Currently, we have no material assessments for potential taxes.
Note 7. Related Party
During the first quarter of 2012, we purchased and marketed $1.2 million of oil produced by a privately-held entity of which a member of our Board of Directors serves as chairman of the board. The oil purchased under this agreement is related to the non-core assets in central and southern Mississippi and in southern Louisiana (see further discussion in Note 2, Acquisitions and Divestitures) sold to this same entity. We are under no obligation to purchase oil under this agreement.
In addition, during the first quarter of 2012, we entered into a sublease of excess office space at our former corporate headquarters with the same privately-held entity. The sublease provides for payment of $2.4 million in lease rentals to us over the lease term, which expires on July 31, 2016. During the first quarter of 2012, we recorded $27 thousand in lease income related to the new sublease arrangement, which is classified as “Interest income and other income” in the Unaudited Condensed Consolidated Statements of Operations.
Note 8. Subsequent Events
Sale of Non-Core Assets
On April 11, 2012, we announced that we had entered into an agreement and closed on the sale of certain non-operated assets in the Paradox Basin of Utah for $75 million. The sale had an effective date of January 1, 2012 and proceeds received after consideration of preliminary closing adjustments totaled $72.4 million. Preliminary closing adjustments include operating net revenues after January 1, 2012, net of capital expenditures, along with other purchase price adjustments.
Amendment to Bank Credit Agreement
During April 2012, we entered into an amendment to our Bank Credit Agreement (see Note 3, Long-Term Debt).
Pending Acquisition of Thompson Field
In April 2012, we entered into an agreement to purchase a nearly 100% working interest and 84.7% net revenue interest in Thompson Field located in southeast Texas for approximately $360 million in cash. Under the agreement, the seller will hold approximately a 5% net revenue interest beginning when average monthly tertiary oil production exceeds 3,000 Bbls/d. Thompson Field is a significant potential tertiary oil flood located approximately 18 miles west of our Hastings Field, our most recent CO2 flood. The acquisition is expected to close in June 2012.
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Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
The following discussion and analysis should be read in conjunction with our consolidated financial statements and notes thereto contained herein and in our Annual Report on Form 10-K for the year ended December 31, 2011 (the “Form 10-K”), along with Management’s Discussion and Analysis of Financial Condition and Results of Operations contained in the Form 10-K. Any terms used but not defined herein have the same meaning given to them in the Form 10-K. Our discussion and analysis includes forward-looking information that involves risks and uncertainties and should be read in conjunction with Risk Factors under Item 1A of Part II of this report, along with Forward-Looking Information at the end of this Item 2 for information about the risks and uncertainties that could cause our actual results to be materially different than our forward-looking statements.
We are 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 CO2 reserves 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 acquired properties through a combination of exploitation, drilling and proven engineering extraction practices, with the most significant emphasis on our CO2 tertiary recovery operations.
We recognized net income of $113.5 million, or $0.29 per basic common share, during the first quarter of 2012 compared to a net loss of $14.2 million, or $0.04 per basic common share, during the first quarter of 2011. This increase in net income between the two periods is primarily attributable to:
During the first quarter of 2012, our oil and natural gas production, which was 93% oil, averaged 71,532 BOE/d compared to 63,604 BOE/d produced during the first quarter of 2011. This 12% increase in production is primarily attributable to increases in our Bakken and tertiary oil production, partially offset by normal declines in most of our other non-tertiary properties. After adjusting quarterly production in both periods to exclude production from non-core properties which were sold in 2012 (see Sale of Non-Core Assets below), continuing production in the first quarter of 2012 increased 14% over production in the comparable prior year quarter and 7% sequentially over levels in the fourth quarter of 2011. Our tertiary oil production averaged 33,257 Bbls/d during the first quarter of 2012, an increase of 8% over the 30,825 Bbls/d produced during the first quarter of 2011 and 7% over fourth quarter 2011 levels. Our Bakken oil production averaged 15,114 BOE/d during the first quarter of 2012, an increase of 164% over production of 5,728 BOE/d during the first quarter of 2011, and 29% over levels in the fourth quarter of 2011. See Results of Operations — CO2 Operations and Results of Operations — Operating Results — Production for more information.
Oil prices during the first quarter of 2012 were considerably higher than prices during the first quarter of 2011, with average NYMEX oil prices averaging $102.89 per Bbl in the first quarter of 2012, compared to average NYMEX prices of $94.26 per Bbl during the first quarter of 2011. Our average realized oil price received per barrel, excluding the impact of commodity derivative contracts, was $102.52 per Bbl during the first quarter of 2012, compared to $93.67 per Bbl during the first quarter of 2011, a 9% increase between the comparative periods. See Results of Operations – Operating Results – Oil and Natural Gas Revenues below for more information on our oil prices received and differentials to NYMEX prices.
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Sale of Investment in Vanguard Natural Resources LLC
On January 19, 2012, we sold our investment in Vanguard Natural Resources LLC (“Vanguard”) common units for cash consideration of $83.5 million, net of related transaction fees. The investment was originally acquired as partial consideration for the sale of our interests in Encore Energy Partners LP on December 31, 2010. In connection with the sale, during the first quarter of 2012 we recorded a pretax $3.1 million loss which is classified as “Other expenses” in the Unaudited Condensed Consolidated Statements of Operations. The $3.1 million loss represents the difference between the net proceeds received from the sale and the carrying amount of the investment at December 31, 2011.
Sale of Non-Core Assets
On January 10, 2012, we entered into an agreement to sell certain non-core assets primarily located in central and southern Mississippi and in southern Louisiana for $155 million. On February 29, 2012, we closed the sale for net proceeds of $144.8 million, after preliminary closing adjustments. The sale had an effective date of December 1, 2011 and consequently operating net revenues after December 1, 2011, net of capital expenditures, along with any other purchase price adjustments, reduced the selling price. We did not record a gain or loss on the sale in accordance with the full cost method of accounting.
On April 11, 2012, we announced that we had entered into an agreement and closed the sale of non-operated assets in the Greater Aneth Field in the Paradox Basin of Utah for $75 million. The sale had an effective date of January 1, 2012 and proceeds received after consideration of preliminary closing adjustments totaled $72.4 million.
Addition of Proved Oil and Natural Gas Reserves
During the first quarter of 2012, we added 18.3 MMBOE of estimated proved reserves, including 14.0 MMBOE at Oyster Bayou Field based on the field’s recent response to CO2 injections, and 4.3 MMBOE due to further development in the Bakken. These increases were partially offset by the disposition of 6.6 MMBOE of reserves associated with certain non-core Gulf Coast assets we sold in February 2012, as discussed above.
Pending Acquisition of Thompson Field
On April 24, 2012, we entered into an agreement to purchase a nearly 100% working interest and 84.7% net revenue interest in Thompson Field located in southeast Texas for approximately $360 million in cash. Under the agreement, the seller will hold approximately a 5% net revenue interest when average monthly tertiary oil production exceeds 3,000 Bbls/d. Thompson Field is a significant potential tertiary oil flood and is located approximately 18 miles west of our Hastings Field. Net to Denbury’s interest, Thompson Field is producing approximately 2,200 Bbls/d of oil, roughly equivalent to the daily production volumes of our non-core assets divested to date in 2012, as discussed above, all of which is non-tertiary production. The sale has an effective date of June 1, 2012 and is expected to close in June 2012.
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Capital Resources and Liquidity
We recently increased our projected 2012 capital budget from $1.35 billion to $1.5 billion based on higher than previously estimated cash flows as a result of better than expected commodity prices and production. We allocated $80 million of our capital budget to further develop the Bakken, $65 million to tertiary oilfield expenditures (primarily in the Hastings and Bell Creek fields) and the remainder to other capital spending projects. Our capital budget of $1.5 billion excludes estimated equipment leases ($75 million), acquisitions, capitalized interest and start-up costs associated with our new tertiary floods. Our current 2012 capital budget includes the following:
Based on oil and natural gas prices in early May 2012 and our current production forecasts, we estimate that our 2012 capital budget (including capitalized interest and tertiary start-up costs) will be approximately $100 to $200 million greater than our 2012 anticipated cash flow from operations. We plan to fund any shortfall between our cash flow from operations and our capital spending with our asset sales and borrowings under our Bank Credit Facility.
During the first three months of 2012, we incurred capital expenditures of approximately $319.8 million, net of equipment lease recoveries of $21.0 million. Additionally, we have capitalized interest and tertiary start-up costs which are not included in the above mentioned amounts. See additional detail on our expenditures in the table below.
During the first four months of 2012, we received net proceeds from non-core oil and natural gas asset divestitures of $217.2 million ($144.8 million at March 31, 2012 and $72.4 million during April 2012), $212.5 million of which are being held by a qualified intermediary to facilitate an anticipated like-kind exchange transaction. We plan to use these proceeds, together with borrowings under our Bank Credit Facility, to fund the $360 million acquisition of Thompson Field, which is expected to close in early June 2012. See Sale of Non-Core Assets and Pending Acquisition of Thompson Field discussed above. In structuring these transactions as a like-kind exchange for income tax purposes, we anticipate deferral of a majority of the taxable gain recognized on the sale of the non-core assets. Such amounts are classified as “Restricted cash” on the Unaudited Condensed Consolidated Balance Sheet.
In October 2011, we commenced a share repurchase program for up to $500 million of Denbury common stock. To date we have only repurchased $195.2 million (all during the fourth quarter of 2011). Any further share repurchases during 2012 will be determined based on various parameters; therefore, it is uncertain whether or not we will make additional share repurchases of Denbury common stock under this program in the remainder of 2012.
We continually monitor our capital spending and anticipated cash flows and believe that we can adjust our capital spending up or down depending on cash flows; however, any such reduction in capital spending could reduce our anticipated production levels in future years. For 2012 and certain future years, we have contracted for certain capital expenditures; therefore, we cannot eliminate all of our capital commitments without penalties (refer to Management’s Discussion and Analysis – Capital Resources and Liquidity – Off-Balance Sheet Arrangements — Commitments and Obligations in the Form 10-K). In addition to the potential flexibility in our capital spending plans, as of March 31, 2012, we had approximately $1.2 billion of unused liquidity under our Bank Credit Facility and have oil price floors in place through 2013 (see Note 4, Derivative Instruments, to the Unaudited Condensed Consolidated Financial Statements), which together should provide us with adequate liquidity and flexibility to meet our near-term capital spending plans if oil prices were to decrease significantly. Also, we currently believe we could significantly expand our borrowing base beyond the current $1.6 billion if we desired to do so.
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Capital Expenditure Summary
The following table of capital expenditures includes accrued capital for the three months ended March 31, 2012 and 2011:
Our capital expenditures for the first three months of 2012 were funded with $291.7 million of cash flow from operations and the remainder with borrowings under our Bank Credit Facility. Our capital expenditures for the first three months of 2011 were funded with $124.8 million of cash flow from operations and the remainder with cash on hand at the beginning of the period.
Off-Balance Sheet Arrangements
Our obligations that are not currently recorded on our balance sheet consist of our operating leases and various obligations for development and exploratory expenditures arising from purchase agreements, our capital expenditure program, or other transactions common to our industry. In addition, in order to recover our proved undeveloped reserves, we must also fund the associated future development costs as forecasted in our proved reserve reports. Our derivative contracts, which are recorded at fair value in our balance sheets, are discussed in Notes 4 and 5 to the Unaudited Condensed Consolidated Financial Statements.
Our commitments and obligations consist of those detailed as of December 31, 2011 in the Form 10-K under Management’s Discussion and Analysis of Financial Condition and Results of Operations – Off-Balance Sheet Arrangements – Commitments and Obligations.
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Results of Operations
Our focus on CO2operations is the primary strategy of our business and operations. We believe there are significant additional oil reserves and production that can be obtained through the use of CO2, and we have outlined certain of this estimated potential in our Form 10-K and other public disclosures. In addition to its long-term effect, our focus on these types of operations impacts certain trends in our current and near-term operating results. Please refer to Management’s Discussion and Analysis of Financial Condition and Results of Operations and the section entitled CO2 Operations contained in our Form 10-K for further information regarding these matters.
During the first quarter of 2012, our CO2 production at Jackson Dome averaged 1,047 MMcf/d, compared to an average of 1,021 MMcf/d produced during the first quarter of 2011 and 1,024 MMcf/d produced during the fourth quarter of 2011. We used 92% of this production, or 964 MMcf/d, in our tertiary operations during the first quarter of 2012, and sold the balance to our industrial customers or to Genesis Energy, L.P. pursuant to our volumetric production payments. Refer to Management’s Discussion and Analysis of Financial Condition and Results of Operations – Capital Resources and Liquidity – Off-Balance Sheet Arrangements – Commitments and Obligations in our Form 10-K for further discussion of our CO2 delivery obligations. We believe we have sufficient CO2reserves to develop our current Gulf Coast enhanced oil recovery program, and we continue to drill additional wells to increase our productive capability and to test the significant probable and possible reserves at Jackson Dome. At December 31, 2011, our proven CO2 reserves at Jackson Dome were approximately 6.7 Tcf.
We spent approximately $0.28 per Mcf in operating expenses to produce our CO2 during the first quarter of 2012, which costs averaged $0.25 per Mcf during the first quarter of 2011 and the fourth quarter of 2011. This increase in the rate from the prior year quarters is due primarily to increased CO2 royalty expense (which is tied to oil prices) and an increase in lease operating expense charges.
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The following table summarizes our tertiary oil production and tertiary lease operating expense per barrel for each quarter in 2011 and the first quarter of 2012: