Oil and natural gas operating expenses for the three months ended June 30, 2009 increased four percent to $9.6 million from $9.2 million for the same period in 2008, primarily as a result of increased transportation and other product costs of $1.2 million mainly attributable to increased production in the Barnett Shale area and higher lifting costs of $0.5 million primarily attributable to increased production and the increased number of producing wells. The increase was partially offset by decreased severance tax expense of $1.3 million associated with decreased revenues.
Depreciation, depletion and amortization (DD&A) expense for the three months ended June 30, 2009 decreased 12% to $12.2 million ($1.55 per Mcfe) from $13.9 million ($2.27 per Mcfe) for the same period in 2008. This decrease in DD&A was primarily due to a lower depletion rate resulting from impairment charges that reduced the depletable full-cost pool in the fourth quarter 2008 and the first quarter of 2009, partially offset by increased production.
General and administrative expense increased to $6.4 million for the three months ended June 30, 2009 from $5.6 million for the corresponding period in 2008. The increase was due primarily to an increase in non-cash, stock-based compensation of $1.2 million as a result of additional deferred compensation awards.
The following table summarizes production volumes, average sales prices (excluding the impact of derivatives) and operating revenues for the six months ended June 30, 2009 and 2008:
__________
| (1) | Includes gathering income and third party gas sales that is also included as third-party purchases in operating expense. |
Oil and natural gas operating expense was comparable at $17.6 million for both the six months ended June 30, 2009 and 2008, primarily as a result of decreased severance tax expense of $3.8 million associated with refunds from certain wells that qualified for a tight-gas sands tax credit for prior production periods and decreased revenues, offset by increased transportation and other product costs of $2.2 million mainly attributable to increased production in the Barnett Shale area and higher lifting costs of $1.6 million primarily attributable to increased production and the increased number of producing wells.
Depreciation, depletion and amortization (DD&A) expense for the six months ended June 30, 2009 decreased 2% to $27.5 million ($1.70 per Mcfe) from $28.0 million ($2.25 per Mcfe) for the same period in 2008. This decrease in DD&A was primarily due to impairment charges in the fourth quarter of 2008 and the first quarter of 2009 that reduced the depletable full-cost pool, partially offset by increased production.
The significant decline in oil and natural gas prices since December 31, 2008, indicated by average posted prices of $3.17 per Mcf for natural gas and $51.76 per Bbl for oil on May 6, 2009, caused the discounted present value (discounted at ten percent) of future net cash flows from our proved oil and gas reserves to fall below our net book basis in the proved oil and gas properties at March 31, 2009. This resulted in a non-cash, ceiling test write-down of $216.4 million ($140.6 million after tax).
General and administrative expense for the six months ended June 30, 2009 increased by $2.2 million to $14.3 million from $12.1 million for the corresponding period in 2008 primarily as a result of increased employee-related expenses due to the increase in staff. This increase was partially offset by decreased insurance costs and lower legal and professional fees.
The net gain on derivatives of $27.8 million in the first six months of 2009 was comprised of a $45.6 million realized gain on cash-settled oil and natural gas derivatives and a $17.8 million of net unrealized mark-to-market loss on derivatives. The net loss on derivatives of $78.0 million in the first six months of 2008 was comprised of $11.5 million of realized loss on net settled derivatives, $63.2 million of net unrealized mark-to-market loss on derivatives and $3.3 million of realized loss on interest rate derivatives associated with the early termination of the interest rate swaps.
In May 2008, we repaid our outstanding borrowings under the Second Lien Facility and terminated the facility. As a result, we recorded a $5.7 million loss associated with the early extinguishment of debt consisting of a $4.6 million non-cash write-off of deferred loan costs and $1.1 million in penalties paid for early retirement.
Interest expense and capitalized interest for the six months ended June 30, 2009 were $18.7 million and $10.1 million, respectively, as compared to $12.5 million and $8.2 million for the same period in 2008 primarily attributable to an increase of approximately $5.0 million in non-cash interest expense associated with the amortization of the debt discount on the Senior Convertible Notes as prescribed by APB 14-1 and higher debt levels on the Senior Credit Facility.
Liquidity and Capital Resources
2009 Capital Budget and Funding Strategy. For 2009, management estimates a capital and exploration expenditures plan ranging between $105 million and $120 million, including $90 million to $100 million for our drilling program, of which $85 million to $95 million is designated for Barnett Shale development and $4 million for our share of capital expenditures related to Marcellus Shale joint venture. We intend to finance our 2009 capital and exploration budget primarily from cash flows from operations, supplemented by available borrowings under the Senior Credit Facility and the possible selective sale or monetization of non-core assets. We may be required to reduce or defer part of our 2009 capital expenditures program if we are unable to obtain sufficient financing from these sources.
Sources and Uses of Cash. During the six months ended June 30, 2009, capital expenditures, net of proceeds from property sales, exceeded our net cash provided by operations. During 2009, we have funded our capital expenditures with cash generated from operations and net additional borrowings under the Senior Credit Facility. Potential primary sources of future liquidity include the following:
| · | Cash on hand and cash generated by operations. Cash flows from operations are highly dependent on commodity prices and market conditions for oil and gas field services. We hedge a portion of our production to reduce the downside risk of declining natural gas and oil prices. |
| · | Available borrowings under the Senior Credit Facility. At August 10, 2009, $81.4 million was available for borrowing under the Senior Credit Facility. The next borrowing base redetermination is currently scheduled for the fourth quarter of 2009. |
| · | Debt and equity offerings. As situations or conditions arise, we may need to issue debt, equity or other instruments to supplement our cash flows. However, we may not be able to obtain such financing on terms that are acceptable to us, or at all. |
| · | Asset sales. In order to fund our capital and exploration budget, we may consider the sale of certain properties or assets that are not part of our core business, can be monetized at a price we find acceptable, or are no longer deemed essential to our future growth. To this end, we have announced that we are pursuing the possible sale or monetization of certain of our gathering systems located in the Barnett Shale play. |
| · | Project financing in certain limited circumstances. |
| · | Lease option agreements and land banking arrangements, such as those we have entered into in the past regarding the Marcellus Shale, the Barnett Shale and other plays. |
| · | Joint ventures with third parties through which such third parties fund a portion of our exploration activities to earn an interest in our exploration acreage, such as our joint venture in the Marcellus Shale play. |
| · | We may consider sale/leaseback transactions of certain capital assets, such as pipelines and compressors, which are not part of our core oil and gas exploration and production business. |
Our primary use of cash is capital expenditures to fund our drilling and development programs and, to a lesser extent, our lease and seismic acquisition programs. Our current 2009 capital expenditures plan provides for approximately $90 million to $100 million for drilling, and approximately $15 million to $20 million for leasing, land costs, seismic acquisitions and other capital expenses. During the second quarter of 2009, our partner in the Marcellus Shale joint venture completed its initial contribution of cash related to the formation of the joint venture. At that point, we became obligated to fund our share of the Marcellus joint venture costs and expenses. We expect to pay approximately $7 million for our share of the remaining Marcellus 2009 joint venture capital expenditure program, primarily to drill wells in West Virginia.
Overview of Cash Flow Activities. Cash flows provided by operating activities were $80.9 million and $69.0 million for the six months ended June 30, 2009 and 2008, respectively. The increase was primarily due to the Company’s efforts to manage cash flows and control operational costs. Natural gas prices have fallen since the third quarter of 2008 and have continued to decline in 2009, having a negative impact on our cash flow from operations and on our 2009 drilling plans. Despite our increase in natural gas production, further decreases in natural gas prices could have a further negative impact on our cash flow from operations and on our 2009 drilling plans.
Cash flows used in investing activities were $117.9 million and $326.6 million for the six months ended June 30, 2009 and 2008 and related primarily to oil and gas property expenditures.
Net cash provided by financing activities for the six months ended June 30, 2009 was $36.6 million and related primarily to net borrowings under the Senior Credit Facility. Net cash provided by financing activities for the six months ended June 30, 2008 was $261.6 million and related primarily to net proceeds of $135.2 million from the issuance of common stock in February 2008, net proceeds of $365.3 million in additional borrowings under the Senior Convertible Notes and $142.0 million in additional borrowings under the Senior Credit Facility. The cash proceeds were partially offset by the payoff and termination of the Second Lien Credit Facility and partial paydown of the Senior Credit Facility.
Liquidity/Cash Flow Outlook.
We currently believe that cash generated from operations, supplemented by borrowings under the Senior Credit Facility and selected assets sales, will be sufficient to fund our immediate needs. Cash generated from operations is primarily driven by production and commodity prices. While we have steadily increased production over the last few years, oil and natural gas prices have declined since the third quarter of 2008. In an effort to mitigate declining prices, we hedge a portion of our production and, as of June 30, 2009, we had hedged approximately 12,512,000 MMBtus (70 MMcf per day for the full year 2009, or 85% of our estimated production from July through December 2009) of our 2009 natural gas production at a weighted average floor or swap price of $6.15 per MMBtu relative to WAHA and HSC prices. We believe the funds available to us under the Senior Credit Facility, $81.4 million at August 10, 2009, will be accessible to us.
If cash from operations and funds available under the Senior Credit Facility are insufficient to fund our 2009 capital and exploration budget, we may need to reduce our capital and exploration budget or seek other financing alternatives to fund it. We may not be able to obtain financing needed in the future on terms that would be acceptable to us, or at all. If we cannot obtain adequate financing, we may be required to limit or defer our planned 2009 natural gas and oil exploration and development program, thereby adversely
affecting the recoverability and ultimate value of our natural gas and oil properties. The recent worldwide financial and credit crisis has adversely affected our ability to access the capital markets.
Contractual Obligations
In 2009, we entered into a two-year and one-year term lease agreements for compressor rentals with an estimated obligation of approximately $2.4 million and $0.5 million, respectively.
Financing Arrangements
Senior Credit Facility
In April 2009, we amended the Senior Credit Facility to, among other things, (1) adjust the maximum ratio of total net debt to Consolidated EBITDAX to a maximum ratio of (a) 4.25 to 1.00 for the quarter ending June 30, 2009, (b) 4.50 to 1.00 for the quarter ending September 30, 2009, (c) 4.75 to 1.00 for each quarter ending on or after December 31, 2009 and on or before September 30, 2010, (d) 4.25 to 1.00 for the quarter ending December 31, 2010, and (e) 4.00 to 1.00 for each quarter ending on or after March 31, 2011; (2) modify the calculation of total net debt for purposes of determining the ratio of total net debt to Consolidated EBITDAX to exclude the following amounts, which represent a portion of the Convertible Senior Notes deemed to be an equity component under APB 14-1: $51,252,980 during 2009, $38,874,756 during 2010, $26,021,425 during 2011 and $12,674,753 during 2012 until the maturity date; (3) add a new senior leverage ratio, which requires that our ratio of senior debt (which excludes debt attributable to the Convertible Senior Notes) to Consolidated EBITDAX not exceed 2.25 to 1.00; (4) modify the interest rate margins applicable to Eurodollar loans to a range of between 2.25% and 3.25% (depending on the then-current level of borrowing base usage); (5) modify the interest rate margins applicable to base rate loans to a range of between 1.00% and 2.00% (depending on the then-current level of borrowing base usage); and (6) establish new procedures governing the modification of swap agreements.
In May 2009, we amended the Senior Credit Facility to, among other things, (1) replace Guaranty Bank with Wells Fargo Bank, N.A. as administrative agent, (2) provide that the aggregate notional volume of oil and natural gas subject to swap agreements may not exceed 80% of “forecasted production from proved producing reserves,” as that term is defined in the Senior Credit Facility, for any month, (3) remove a provision that limited the maximum duration of swap agreements permitted under the Senior Credit Facility to five years, and (4) provide that the aggregate notional amount under interest rate swap agreements may not exceed the amount of borrowings then outstanding under the Senior Credit Facility. Also in April 2009, the Company amended the Senior Credit Facility to increase the borrowing base to $290,000,000 and, in May 2009, the total commitment of the lenders was increased from $250,000,000 to $259,400,000. On June 5, 2009, the total commitment was increased by $25,000,000 to $284,400,000 with the addition of a new lender to the bank syndicate.
As of August 10, 2009, we had $201.0 million of borrowings outstanding and a borrowing base availability of $81.4 million.
Effects of Inflation and Changes in Price
Our results of operations and cash flows are affected by changing natural gas and oil prices. The dramatic drop in natural gas and oil prices since the third quarter of 2008 has resulted in a significant drop in revenue per unit of production. Although operating costs have also declined, the rate of decline in natural gas and oil prices has been substantially greater. Historically, inflation has had a minimal effect on us. However, with interest rates at historic lows and the government attempting to stimulate the economy through rapid expansion of the money supply in recent months, inflation could become a significant issue in the future.
Recently Adopted Accounting Pronouncements
On January 1, 2009, we adopted the Financial Accounting Standards Boards (“FASB”) Staff Position No. APB 14-1, “Accounting for Convertible Debt Instruments That May Be Settled in Cash Upon Conversion (Including Partial Cash Settlements)” (“APB 14-1”), which clarifies the accounting for convertible debt instruments that may be settled in cash (including partial cash settlement) upon conversion. APB 14-1 requires that issuers of convertible debt separately account for the liability and equity components in a manner that reflects the entity’s nonconvertible debt borrowing rate when interest cost is recognized in subsequent periods. Once adopted, ABP 14-1 requires retrospective application to the terms of instruments as they existed for periods presented. We applied this accounting pronouncement to the Convertible Senior Notes. We valued the conversion premium of the convertible debt at $64.2 million and accordingly restated our balance sheet as of December 31, 2008 for the carrying value of debt and equity and restated our results of operations for interest expense, capitalized interest, and income taxes for the year ended December 31, 2008. See Item 1,
Notes to Consolidated Financial Statements, Note 2 for a discussion of the restatement related to the adoption of this accounting pronouncement.
On January 1, 2009, we adopted and retroactively applied FASB Staff Position (“FSP”) Emerging Issues Task Force 03-6-1, “Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities” (“EITF 03-6-1”). This FSP provides that unvested share-based payment awards that contain non-forfeitable rights to dividends or dividend equivalents, whether paid or unpaid, are participating securities and shall be included in the computation of both basic and diluted earnings per share. This FSP requires retroactive application for all periods presented. We determined that our restricted shares of common stock are participating securities as defined in this FSP and applied this FSP retroactively to all periods presented. See Item 1, Notes to Consolidated Financial Statements, Note 2 for a discussion of the restatement related to the adoption of this accounting pronouncement.
In March 2008, the FASB issued SFAS No. 161, Disclosures about Derivative Instruments and Hedging Activities (“SFAS No. 161”). This standard is intended to improve financial reporting by requiring transparency about the location and amounts of derivative instruments in an entity’s financial statements, how derivative instruments and related hedged items are accounted for under SFAS No. 133, and how derivative instruments and related hedged items affect an entity’s financial position, financial performance and cash flows. The provisions of SFAS No. 161 are effective for financial statements issued for fiscal years and interim periods beginning after November 15, 2008. We adopted this pronouncement effective January 1, 2009 and it did not have a significant effect on our consolidated financial position, results of operations or cash flows.
In April 2009, the FASB issued FSP No. 157-4, “Determining Fair Value When the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions That Are Not Orderly” (“FSP FAS 157-4”), which provides additional guidance for estimating fair value in accordance with SFAS No. 157, “Fair Value Measurements” (“SFAS No. 157”). FSP FAS 157-4 is effective for the quarter ending June 30, 2009. We adopted this pronouncement effective June 30, 2009 and it had no material impact on our consolidated financial statements.
In April 2009, the FASB issued FSP No. FAS 115-2 and FAS 124-2, “Recognition and Presentation of Other-Than-Temporary Impairments” (FSP FAS 115-2”), which provides new guidance on the recognition of other-than-temporary impairments of investments in debt securities and provides new presentation and disclosure requirements for other-than-temporary impairments of investments in debt and equity securities. FSP FAS 115-2 is effective for the quarter ending June 30, 2009. We adopted the requirements of this pronouncement effective June 30, 2009 and it had no material impact on our consolidated financial statements.
In April 2009, the FASB issued FSP FAS No. 107-1 and APB Opinion No. 28-1, “Interim Disclosures About Fair Value of Financial Instruments,” which requires quarterly fair value disclosures for financial instruments that are not reflected on the Company’s Consolidated Balance Sheet at fair value in interim financial statements effective for interim periods ending after June 15, 2009. We adopted the requirements of this pronouncement effective June 30, 2009 and included additional disclosures in our Notes to Consolidated Financial Statement.
In May 2009, the FASB issued SFAS No. 165, “Subsequent Events,” which establishes general standards of accounting for and disclosure of events that occur after the balance sheet date but before financial statements are issued. In particular, SFAS No. 165 sets forth (1) the period after the balance sheet date during which management of a reporting entity should evaluate events or transactions that may occur for potential recognition or disclosure in the financial statements; (2) the circumstances under which an entity should recognize events or transactions occurring after the balance sheet date in its financial statements; and (3) the disclosures that an entity should make about events or transactions that occurred after the balance sheet date. We applied the requirement of this pronouncement effective June 30, 2009 and included additional disclosures in our Notes to Consolidated Financial Statements.
Recently Issued Accounting Pronouncements
On December 31, 2008, the SEC adopted major revisions to its rules governing oil and gas company reporting requirements. These new rules permit the use of new technologies to determine proved reserves and that allow companies to disclose their probable and possible reserves to investors. The current rules limit disclosure to only proved reserves. The new rules require companies to report the independence and qualification of the person primarily responsible for the preparation or audit of its reserve estimates, and to file reports when a third party is relied upon to prepare or audit its reserves estimates. The new rules also require that the net present value of oil and gas reserves reported and used in the full cost ceiling test calculation be based upon an average price for the prior 12-month period. The new oil and gas reporting requirements are effective for annual reports on Form 10-K for fiscal years ending on or after December 31, 2009, with early adoption not permitted. We are in the process of assessing the impact of these new requirements on our financial position, results of operations and financial disclosures.
In June 2009, the FASB issued SFAS No. 168, “The FASB Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles” (“SFAS No. 168”). SFAS No. 168 establishes the FASB Accounting Standards Codification (“Codification”), which became effective July 1, 2009, to become the single source of authoritative U.S. GAAP recognized by the FASB to be applied by nongovernmental entities. Rules and interpretive releases of the SEC under authority of federal securities laws are also sources of authoritative GAAP for SEC registrants. All other accounting literature excluded from the Codification will be considered nonauthoritative. The subsequent issuances of new standards will be in the form of Accounting Standards Updates that will be included in the Codification. Generally, the Codification is not expected to change U.S. GAAP. SFAS No. 168 is effective for financial statements issued for interim and annual periods ending after September 15, 2009. We are currently evaluating the effect of the standard on our financial statement disclosures, as all future references to authoritative accounting literature will be made in accordance with the Codification.
Critical Accounting Policies
The following summarizes our critical accounting policies:
Oil and Natural Gas Properties
We account for investments in natural gas and oil properties using the full-cost method of accounting. All costs directly associated with the acquisition, exploration and development of natural gas and oil properties are capitalized. These costs include lease acquisitions, seismic surveys, and drilling and completion equipment. We proportionally consolidate our interests in natural gas and oil properties. We capitalized compensation costs for employees working directly on exploration activities of $3.0 million and $3.4 million for the six months ended June 30, 2009 and 2008, respectively. We expense maintenance and repairs as they are incurred.
We amortize natural gas and oil properties based on the unit-of-production method using estimates of proved reserve quantities. Costs not subject to amortization includes costs of unevaluated leaseholds, seismic costs associated with specific unevaluated properties and wells in progress. These costs are periodically evaluated on a property-by-property basis for impairment. If the results of an assessment indicate that the properties are impaired, we add the amount of impairment to the proved natural gas and oil property costs to be amortized. The amortizable base includes estimated future development costs and, where significant, dismantlement, restoration and abandonment costs, net of estimated salvage values. The depletion rate per Mcfe for the three months ended June 30, 2009 and 2008 was $1.52 and $2.14, respectively.
We account for dispositions of natural gas and oil properties as adjustments to capitalized costs with no gain or loss recognized, unless such adjustments would significantly alter the relationship between capitalized costs and proved reserves. We have not had any transactions that significantly alter that relationship.
Net capitalized costs of proved oil and natural gas properties are limited to a “ceiling test” based on the estimated future net revenues, discounted at 10% per annum, from proved oil and natural gas reserves based on current economic and operating conditions (“Full Cost Ceiling”). If net capitalized costs exceed this limit, the excess is charged to earnings.
The Full Cost Ceiling test cushion at June 30, 2009 of $69.6 million was based upon average realized oil, natural gas liquids and natural gas prices of $65.35 per Bbl, $31.76 per Bbl and $3.52 per Mcf, respectively, or a volume weighted average price of $27.69 per BOE. This cushion, however, would have been zero at such date at an estimated volume weighted average price of $25.63 per BOE. A BOE means one barrel of oil equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of oil, condensate or natural gas liquids, which approximates the relative energy content of oil, condensate and natural gas liquids as compared to natural gas. In connection with our June 30, 2009 Full Cost Ceiling test computation, a price sensitivity study also indicated that a 10% increase in commodity prices at June 30, 2009 would have increased the Full Cost Ceiling test cushion by approximately $11.7 million and a 10% decrease in commodity prices would have resulted in a $24.1 million ceiling test impairment. The aforementioned price sensitivity is as of June 30, 2009 and, accordingly, does not include any potential changes in reserve values due to subsequent performance or events, such as commodity prices, reserve revisions and drilling results. Prices have historically been higher or substantially higher, more often for oil than natural gas on an energy equivalent basis, although there have been periods in which they have been lower or substantially lower.
Under the full cost method of accounting, the depletion rate is the current period production as a percentage of the total proved reserves. Total proved reserves include both proved developed and proved undeveloped reserves. The depletion rate is applied to the net book value of our oil and natural gas properties, excluding the costs not subject to amortization as discussed above, plus estimated
future development costs and salvage value, to calculate the depletion expense. Proved reserves materially impact depletion expense. If the proved reserves decline, then the depletion rate (the rate at which we record depletion expense) increases, reducing net income.
We have a significant amount of proved undeveloped reserves. We had 239.1 Bcfe of proved undeveloped reserves at December 31, 2008, representing 48% of our total proved reserves. As of December 31, 2008, a portion of these proved undeveloped reserves, or approximately 29.9 Bcfe, are attributable to our Camp Hill properties that we acquired in 1994. The estimated future development costs to develop our proved undeveloped reserves on our Camp Hill properties are relatively low, on a per Mcfe basis, when compared to the estimated future development costs to develop our proved undeveloped reserves on our other oil and natural gas properties. Furthermore, the average depletable life (the estimated time that it will take to produce all recoverable reserves) of our Camp Hill properties is considerably longer, or approximately 15 years, when compared to the depletable life of our remaining oil and natural gas properties of approximately 10 years. Accordingly, the combination of a relatively low ratio of future development costs and a relatively long depletable life on our Camp Hill properties has resulted in a relatively low overall historical depletion rate and DD&A expense. This has resulted in a capitalized cost basis associated with producing properties being depleted over a longer period than the associated production and revenue stream, causing the build-up of nondepleted capitalized costs associated with properties that have been completely depleted. This combination of factors, in turn, has had a favorable impact on our earnings, which have been higher than they would have been had the Camp Hill properties not resulted in a relatively low overall depletion rate and DD&A expense and longer depletion period. As a hypothetical illustration of this impact, the removal of our Camp Hill proved undeveloped reserves starting January 1, 2002 and through December 31, 2008 would have reduced our earnings by (a) an estimated $11.2 million in 2002 (comprised of after-tax charges for a $7.1 million full cost ceiling impairment and a $4.1 million depletion expense increase), (b) an estimated $5.9 million in 2003 (due to higher depletion expense), (c) an estimated $3.4 million in 2004 (due to higher depletion expense), (d) an estimated $6.9 million in 2005 (due to higher depletion expense), (e) an estimated $0.7 million in 2006 (due to higher depletion expense), (f) an estimated $2.0 million in 2007 (due to higher depletion expense), and (g) an estimated $9.2 million in 2008 (comprised of after tax charges for an $8.5 million full cost ceiling test impairment and a $0.7 million depletion expense increase).
We expect our relatively low historical depletion rate to continue until the high level of nonproducing reserves to total proved reserves is reduced and the life of our proved developed reserves is extended through development drilling and/or the significant addition of new proved producing reserves through acquisition or exploration. If our level of total proved reserves, finding costs and current prices were all to remain constant, this continued build-up of capitalized cost increases the probability of a ceiling test write-down in the future.
We depreciate other property and equipment using the straight-line method based on estimated useful lives ranging from five to ten years.
Income Taxes
Under Statement of Financial Accounting Standards No. 109 (“SFAS No. 109”), “Accounting for Income Taxes,” deferred income taxes are recognized at each year end for the future tax consequences of differences between the tax bases of assets and liabilities and their financial reporting amounts based on tax laws and statutory tax rates applicable to the periods in which the differences are expected to affect taxable income. We routinely assess the realizability of our deferred tax assets based upon our estimated production of proved reserves at estimated future pricing. We consider future taxable income in making such assessments. If we conclude that it is more likely than not that some portion or all of the deferred tax assets will not be realized under accounting standards, it is reduced by a valuation allowance. However, despite our attempt to make an accurate estimate, the ultimate utilization of our deferred tax assets is highly dependent upon our actual production and the realization of taxable income in future periods.
For information regarding our other critical accounting policies, see the 2008 Form 10-K/A.
Volatility of Oil and Natural Gas Prices
Our revenues, future rate of growth, results of operations, financial condition and ability to borrow funds or obtain additional capital, as well as the carrying value of our properties, are substantially dependent upon prevailing prices of oil and natural gas.
We periodically review the carrying value of our oil and natural gas properties under the full cost method of accounting rules. See “—Critical Accounting Policies—Oil and Natural Gas Properties.”
To mitigate some of our commodity price risk, we engage periodically in certain other limited derivative activities including price swaps, costless collars and, occasionally, put and call options, in order to establish some price floor protection.
The following table includes oil and natural gas positions settled during the three and six-month periods ended June 30, 2009 and 2008, and the unrealized gain/(loss) associated with the outstanding oil and natural gas derivatives at June 30, 2009 and 2008.
| | | Three Months Ended | | | Six Months Ended | |
| | | June 30, | | | June 30, | |
| | | 2009 | | | 2008 | | | 2009 | | | 2008 | |
| Oil positions settled (Bbls) | | | - | | | | 9,100 | | | | 5,900 | | | | 27,300 | |
| Natural gas positions settled (MMBtus) | | | 7,293,000 | | | | 3,458,000 | | | | 13,678,000 | | | | 7,590,000 | |
Realized gain/(loss) ($ millions) (1) | | $ | 23.0 | | | $ | (8.8 | ) | | $ | 45.6 | | | $ | (10.3 | ) |
Unrealized gain/(loss) ($ millions) (1) | | $ | (25.3 | ) | | $ | (40.1 | ) | | $ | (17.8 | ) | | $ | (66.0 | ) |
| | | | | | | | | | | | | | | | | |
__________
(1) Included in net gain (loss) on derivatives in the Consolidated Statements of Operations.
At June 30, 2009, we had the following outstanding natural gas derivative positions:
| | | Natural Gas | | | Natural Gas | | | Basis Differential | |
| | | Swaps | | | Collars | | | Swaps(3) | |
| | | | | | Average | | | | | | Average | | | Average | | | | | | | |
| Quarter | | MMBtus(1) | | | Fixed Price(2) | | | MMBtus(1) | | | Floor Price(2) | | | Ceiling Price(2) | | | MMbtu | | | Fixed Price | |
| Third Quarter 2009 | | | 3,680,000 | | | | 5.31 | | | | 2,576,000 | | | | 7.16 | | | | 8.88 | | | | 1,840,000 | | | | 0.27 | |
| Fourth Quarter 2009 | | | 3,680,000 | | | | 5.58 | | | | 2,576,000 | | | | 7.17 | | | | 8.90 | | | | - | | | | - | |
| First Quarter 2010 | | | 3,150,000 | | | | 5.45 | | | | 1,620,000 | | | | 7.92 | | | | 9.63 | | | | - | | | | - | |
| Second Quarter 2010 | | | 3,185,000 | | | | 5.50 | | | | 637,000 | | | | 5.84 | | | | 7.30 | | | | - | | | | - | |
| Third Quarter 2010 | | | 1,840,000 | | | | 5.57 | | | | 1,104,000 | | | | 6.07 | | | | 7.62 | | | | - | | | | - | |
| Fourth Quarter 2010 | | | 1,840,000 | | | | 5.57 | | | | 1,380,000 | | | | 6.49 | | | | 7.90 | | | | - | | | | - | |
| First Quarter 2011 | | | 1,800,000 | | | | 5.64 | | | | 450,000 | | | | 9.70 | | | | 11.70 | | | | - | | | | - | |
| Second Quarter 2011 | | | 1,820,000 | | | | 5.64 | | | | 455,000 | | | | 8.25 | | | | 10.25 | | | | - | | | | - | |
| Third Quarter 2011 | | | 1,840,000 | | | | 5.64 | | | | 460,000 | | | | 8.65 | | | | 10.65 | | | | - | | | | - | |
| Fourth Quarter 2011 | | | 1,840,000 | | | | 5.64 | | | | 460,000 | | | | 8.85 | | | | 10.85 | | | | - | | | | - | |
| First Quarter 2012 | | | 910,000 | | | | 5.88 | | | | 455,000 | | | | 9.55 | | | | 11.55 | | | | - | | | | - | |
| Second Quarter 2012 | | | 910,000 | | | | 5.88 | | | | 455,000 | | | | 8.35 | | | | 10.35 | | | | - | | | | - | |
| Third Quarter 2012 | | | 920,000 | | | | 5.88 | | | | - | | | | - | | | | - | | | | - | | | | - | |
| Fourth Quarter 2012 | | | 920,000 | | | | 5.88 | | | | - | | | | - | | | | - | | | | - | | | | - | |
| | | | 28,335,000 | | | | | | | | 12,628,000 | | | | | | | | | | | | 1,840,000 | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
__________
| (1) | During 2009, the Company entered into (1) a $5.35 put, a $6.20 long-call and an $8.00 short-call with respect to a portion of the Company’s production hedged with swaps (10,000 MMBtus per day) in 2011 and 2012 and (2) a $4.35 put, a $6.00 long-call and a $6.50 short-call with respect to a portion of the Company’s production hedged with swaps (20,000 MMBtus per day for April through October of 2010). The table below presents additional put positions the Company has entered into associated with a portion of hedged volumes presented above: |
| Quarter | | MMBtus | | | Put Price | |
| Third Quarter 2009 | | | 920,000 | | | $ | 3.00 | |
| Fourth Quarter 2009 | | | 920,000 | | | | 3.00 | |
| Second Quarter 2010 | | | 455,000 | | | | 3.74 | |
| Third Quarter 2010 | | | 920,000 | | | | 4.31 | |
| Fourth Quarter 2010 | | | 1,196,000 | | | | 4.61 | |
| First Quarter 2011 | | | 450,000 | | | | 6.80 | |
| Second Quarter 2011 | | | 455,000 | | | | 6.80 | |
| Third Quarter 2011 | | | 460,000 | | | | 6.80 | |
| Fourth Quarter 2011 | | | 460,000 | | | | 6.80 | |
| First Quarter 2012 | | | 455,000 | | | | 6.80 | |
| Second Quarter 2012 | | | 455,000 | | | | 6.80 | |
| | | | | | | | | |
| (2) | Based on Houston Ship Channel (“HSC”) and WAHA spot prices. |
| (3) | Basis differential swaps covering the price differential for natural gas between NYMEX and HSC. |
As of June 30, 2009, approximately 55% of our open natural gas hedged volumes were with Credit Suisse as the counterparty, and the remaining 45% were with Shell Energy North America (U.S.), L.P. as the counterparty.
While the use of hedging arrangements limits the downside risk of adverse price movements, it may also limit our ability to benefit from increases in the prices of natural gas and oil. We enter into the majority of our derivatives transactions with two counterparties and have a netting agreement in place with those counterparties. We do not obtain collateral to support the agreements but monitor the financial viability of counterparties and believe our credit risk is minimal on these transactions. Under these arrangements, payments are received or made based on the differential between a fixed and a variable commodity price. These agreements are settled in cash at expiration or exchanged for physical delivery contracts. In the event of nonperformance, we would be exposed again to price risk. We have additional risk of financial loss because the price received for the product at the actual physical delivery point may differ from the prevailing price at the delivery point required for settlement of the hedging transaction. Moreover, our derivatives arrangements generally do not apply to all of our production and thus provide only partial price protection against declines in commodity prices. We expect that the amount of our hedges will vary from time to time.
Our natural gas derivative transactions are generally settled based upon the average of the reported settlement prices on the HSC or WAHA indices for the last three trading days of a particular contract month. Our oil derivative transactions are generally settled based on the average reported settlement prices on the West Texas Intermediate index for each trading day of a particular calendar month.
Forward Looking Statements
The statements contained in all parts of this document, including, but not limited to, those relating to our schedule, targets, estimates or results of future drilling, including the number, timing and results of wells, budgeted wells, increases in wells, the timing and risk involved in drilling follow-up wells, expected working or net revenue interests, planned expenditures, prospects budgeted and other future capital expenditures, efforts to control capital costs, risk profile of oil and natural gas exploration, acquisition of 3-D seismic data (including number, timing and size of projects), planned evaluation of prospects, probability of prospects having oil and natural gas, expected production or reserves, increases in reserves, acreage, working capital requirements, hedging activities, credit risk of hedging counterparties, the ability of expected sources of liquidity to implement the Company’s business strategy, future exploration activity, production rates, 2009 drilling program, growth in production, development of new drilling programs, hedging of production and exploration and development expenditures, Camp Hill development, addition of new lenders under the Senior Credit Facility, fair value of the Company’s investment in Pinnacle and all and any other statements regarding future operations, financial results, business plans and cash needs, potential borrowing base increases and other statements that are not historical facts are forward looking statements. When used in this document, the words “anticipate,” “estimate,” “expect,” “may,” “project,” “believe” and similar expressions are intended to be among the statements that identify forward looking statements. Such statements involve risks and uncertainties, including, but not limited to, those relating to the Company's dependence on its exploratory drilling activities, the volatility of oil and natural gas prices, the need to replace reserves depleted by production, operating risks of oil and natural gas operations, the Company’s dependence on its key personnel, factors that affect the Company's ability to manage its growth and achieve its business strategy, technological changes, significant capital requirements of the Company, borrowing base determinations and availability under the Senior Credit Facility, evaluations of the Company by potential lenders under the Senior Credit Facility, results of operation of Pinnacle, the potential impact of government regulations, litigation, competition, the uncertainty of reserve information and future net revenue estimates, property acquisition risks, availability of equipment, weather, availability of financing, actions by lenders, ability to obtain permits, the results of audits and assessments, and other factors detailed in the “Risk Factors” and other sections of the Company’s Annual Report on Form 10-K/A for the year ended December 31, 2008 and in this and its other filings with the Securities and Exchange Commission. Should one or more of these risks or uncertainties materialize, or should underlying assumptions prove incorrect, actual outcomes may vary materially from those indicated. All subsequent written and oral forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by reference to these risks and uncertainties. You should not place undue reliance on forward-looking statements. Each forward-looking statement speaks only as of the date of the particular statement and the Company undertakes no obligation to update or revise any forward-looking statement.
