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UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
For the quarterly period ended June 30, 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 June 30, 2012, our consolidated results of operations for the three and six months ended June 30, 2012 and 2011, and our consolidated cash flows for the six months ended June 30, 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 and six months ended June 30, 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.
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 and six months ended June 30, 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 3.5 million and 3.8 million shares for the three and six months ended June 30, 2012, respectively, and 3.4 million and 3.6 million shares for the three and six months ended June 30, 2011, respectively, of nonvested restricted stock. 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 $1.7 million and $3.5 million on the Vanguard common units we owned during the three and six months ended June 30, 2011, respectively, 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 six months ended June 30, 2012.
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The following table summarizes the changes in Denbury’s goodwill for the period indicated:
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
June 2012 Acquisition of Reserves in the Gulf Coast region at Thompson Field
In June 2012, we acquired a nearly 100% working interest and 84.7% net revenue interest in Thompson Field for $366.2 million after preliminary closing adjustments. The field is located approximately 18 miles west of Hastings Field, which is an enhanced oil recovery (“EOR”) field that Denbury is currently flooding with CO2, and is the current terminus of the Green Pipeline which transports CO2 from the Jackson Dome, located near Jackson, Mississippi. Thompson Field is similar to Hastings Field, producing oil from the Frio zone at similar depths, and is also expected to be an ideal candidate for a CO2 flood. Under the terms of the Thompson Field acquisition agreement, the seller will retain approximately a 5% gross revenue interest (less severance taxes) once average monthly oil production exceeds 3,000 Bbls/d after the initiation of CO2 injection.
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This acquisition meets the definition of a business under the FASC Business Combinations topic. As such, Denbury estimated the fair value of assets acquired and liabilities assumed as of June 1, 2012, the closing date of the acquisition. 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 assumptions should not impact the measurement of fair value unless those assumptions are consistent with market participant views.
In applying these accounting principles, Denbury estimated the fair value of the assets acquired less liabilities assumed on the acquisition date to be approximately $238.9 million. This measurement resulted in the recognition of goodwill of approximately $127.2 million, which represents the excess of the cash paid to acquire the field over the acquisition date estimated fair value. This resultant goodwill is due primarily to two factors. The first factor is the decrease in average NYMEX oil futures prices between the date of signing the purchase agreement on April 24, 2012 and closing the purchase on June 1, 2012. The second factor is the fair value assigned to the estimated oil reserves recoverable through a CO2 EOR project. By building an 18 mile extension of the Green Pipeline, Denbury has access to its CO2 reserves at Jackson Dome, one of the few known significant natural sources of CO2 in the United States, and the largest known source east of the Mississippi River, allowing Denbury to carry out CO2 EOR activities in this field at a lower cost than other market participants. However, the FASC Fair Value Measurements and Disclosures does not allow entity-specific assumptions in the measurement of fair value. Therefore, we estimated the fair value of the oil reserves recoverable through CO2 EOR using a higher estimated cost of CO2 to other market participants, which lowers the discounted net revenue stream used in making the fair value estimate related to this field.
The fair value of Thompson Field assets acquired and liabilities assumed was based on significant inputs not observable in the market, which FASC Fair Value Measurements and Disclosures topic defines as Level 3 inputs. Key assumptions include (1) NYMEX oil futures prices (this input is observable), (2) estimated quantities of oil reserves, (3) projections of future rates of production, (4) timing and amount of estimated future development and operating costs, (5) projected cost of CO2 to a market participant, (6) projected recovery factors, and (7) risk-adjusted discount rates. The fair value of the oil and natural gas properties was determined using a risk-adjusted after-tax discounted cash flow analysis. Denbury applies full cost accounting rules, and all of the goodwill is deductible for tax purposes as property cost.
The following table presents a summary of the preliminary fair value of the Thompson Field assets acquired and liabilities assumed.
Pro Forma Information
Had the Thompson Field acquisition occurred on January 1, 2011, our combined pro forma revenues and net income for the three and six months ended June 30, 2012 and 2011, would have been as follows:
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. We previously acquired the other 42.5% interest in Riley Ridge and the gas plant in October 2010. The purchase price for the August 2011 acquisition 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 in December 2012 or early 2013.
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 fair value 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 February 29, 2012, we completed the sale of certain non-core assets primarily located in central and southern Mississippi and in southern Louisiana for $155.0 million to 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. We realized net proceeds of $141.8 million, after final closing adjustments. The sale had an effective date of December 1, 2011 and consequently, operating revenues of $13.5 million after the effective date, net of capital and lease operating expenditures, along with any other purchase price adjustments, were adjustments to the selling price.
On April 9, 2012, we completed the sale of certain non-operated assets in the Paradox Basin of Utah for $75.0 million. The sale had an effective date of January 1, 2012 and proceeds received after consideration of closing adjustments totaled $68.5 million. Closing adjustments included operating net revenues after January 1, 2012, net of capital and lease operating expenditures, along with other purchase price adjustments.
We did not record a gain or loss on either of the above sales of properties in accordance with the full cost method of accounting.
Of the proceeds from these property sales before final closing adjustments, $212.5 million was paid directly to a qualified intermediary and later released to fund a portion of the acquisition cost of Thompson Field (see June 2012 Acquisition of Reserves in the Gulf Coast region at Thompson Field above). Since the $212.5 million in cash proceeds was never held by, or paid directly to, Denbury’s bank account, this amount is not reflected as a receipt of net proceeds from the sale of oil and natural gas properties and equipment, nor as a cash payment to purchase oil and natural gas properties in the investing activity in our Consolidated Statement of Cash Flows.
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; and the guarantees are full and unconditional and joint and several obligations of the subsidiary guarantors; any subsidiaries of DRI other than the subsidiary guarantors are minor subsidiaries.
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 is subject to 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 six months ended June 30, 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.
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In April 2012, we entered into the Seventh Amendment to the Bank Credit Agreement (the “Seventh Amendment”). Under the Seventh Amendment, we increased the amount of additional permitted subordinated 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.
In July 2012, we entered into the Eighth Amendment to the Bank Credit Agreement (the “Eighth Amendment”). The Bank Credit Agreement permits the Company to incur capital lease obligations in an aggregate amount outstanding at any time not to exceed $300 million. The Bank Credit Agreement permits the Company to incur up to $40 million of other unsecured debt, and prior to the effectiveness of the Eighth Amendment capital leases would have been captured in this permitted debt basket. The Bank Credit Agreement was amended concurrent with the Company’s change in classification of equipment leases from operating to capital in the second quarter of 2012 (see Capital Leases below), and the Eighth Amendment included the granting by the lenders of a waiver of any applicable violations of the provisions of the Bank Credit Agreement resulting from such correction and the Company’s recording of its equipment leases as debt.
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
Pursuant to cash tender offers, during March 2011, we repurchased $169.6 million in principal of our 7½% Senior Subordinated Notes due 2013 (“2013 Notes”) at 100.625% of par, and $220.9 million in principal of our 7½% Senior Subordinated Notes due 2015 (“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 $0.3 million and $16.1 million loss during the three and six months ended June 30, 2011, respectively, associated with the debt repurchases, which are included in our Unaudited Condensed Consolidated Statements of Operations under the caption “Loss on early extinguishment of debt.”
Capital Lease Obligations
During the second quarter of 2012, the Company corrected the accounting for its equipment leases from operating leases to capital leases to comply with ASC Topic 840, Leases as a result of the consideration of nonperformance-related default covenants included in its equipment lease agreements. The Company recorded a cumulative adjustment to establish the capital lease assets as “Other property and equipment” ($155.6 million) and the capital lease obligations as “Long-term debt” ($138.9 million) and “Current maturities of long-term debt” ($25.1 million) on the accompanying Unaudited Condensed Consolidated Balance Sheets. The Company also recognized the cumulative pre-tax impact of $8.4 million ($5.2 million after tax) as “Other expenses” on the accompanying Unaudited Condensed Consolidated Statements of Operations. Because the amounts involved were not material to the Company’s financial statements in any individual prior period, and the cumulative impact is not material to the estimated results of operations for the year ending December 31, 2012, the Company recorded the cumulative effect of correcting these items during the three months ended June 30, 2012.
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 income” in our Unaudited Condensed Consolidated Statements of Operations.
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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 income” included in the accompanying Unaudited Condensed Consolidated Statements of Operations for the periods indicated:
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Commodity Derivative Contracts Not Classified as Hedging Instruments
The following tables present outstanding commodity derivative contracts with respect to future production as of June 30, 2012:
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Additional Disclosures about Derivative Instruments
At June 30, 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:
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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 income” in the accompanying Unaudited Condensed Consolidated Statements of Operations.
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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 and six months ended June 30, 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 natural gas financial measurements: