The net gain on derivatives of $3.0 million in the second quarter of 2006 was comprised of (1) $1.4 million of realized gain on net settled derivatives and (2) $1.6 million of net unrealized mark-to-market gain on the derivatives accounted for as nondesignated derivatives. The mark-to-market gain on derivatives of $1.2 million in the second quarter of 2005 was comprised of (1) $30,000 of realized loss on net settled derivatives and (2) $1.2 million of net unrealized mark-to-market gain on the derivatives accounted for as nondesignated derivatives.
In April 2006, our ownership interest in Pinnacle was reduced below 20 percent; consequently, we converted from accounting for our investment in Pinnacle using the equity method to the cost method.
Interest expense and capitalized interest for the three months ended June 30, 2006 were $4.6 million and ($2.4) million, respectively, as compared to $1.8 million and ($1.2) million for the same period in 2005. The increases in 2006 are attributable to borrowings under the Second Lien Credit Facility in July 2005, and the borrowings under the Senior Credit Facility in 2006.
Income taxes decreased to $1.5 million for the three months ended June 30, 2006 from $2.7 million for the same period in 2005 as a result of lower taxable income.
Oil and natural gas revenues for the six months ended June 30, 2006 increased 21% to $38.4 million from $31.6 million for the same period in 2005. Production volumes for natural gas increased from 3.9 Bcf for the six months ended June 30, 2005 to 4.5 Bcf in the same period of 2006. Average natural gas prices excluding the impact of the gain from our cash settled derivatives of $2.5 million and $0.2 million for the six months ended June 30, 2006 and 2005, respectively, increased 9% to $6.92 per Mcf in the first half of 2006 from $6.33 per Mcf in the same period in 2005. Average oil prices for the six months ended June 30, 2006 increased 20% to $63.72 from $52.89 per barrel in the same period in 2005. The increase in natural gas production volumes was principally due to the commencement of production from the Galloway #1, Mass #1 and new wells in the Barnett Shale area. These volume increases were partially offset or adversely affected by: (1) production declines from the Beach House #1 and other normal production declines, (2) an after-payout working interest reduction on the LL&E #1 Deepening and (3) mechanical failures with the Galloway #1 and the Delta Farms #1 during the second quarter of 2006.
The following table summarizes production volumes, average sales prices and operating revenues (excluding the impact of derivatives) for the six months ended June 30, 2005 and 2006:
| | | | | | | 2006 Period | |
| | | | | | | Compared to 2005 Period | |
| | | June 30, | | Increase | | % Increase | |
| | | 2005 | | 2006 | | (Decrease) | | (Decrease) | |
| | | (Restated) | | | | | | | |
| Production volumes | | | | | | | | | |
| Oil and condensate (MBbls) | | | 125 | | | 110 | | | (15 | ) | | (12 | %) |
| Natural gas (MMcf) | | | 3,949 | | | 4,533 | | | 584 | | | 15 | % |
| Average sales prices | | | | | | | | | | | | | |
| Oil and condensate (per Bbl) | | $ | 52.89 | | $ | 63.72 | | $ | 10.83 | | | 20 | % |
| Natural gas (per Mcf) | | | 6.33 | | | 6.92 | | | 0.59 | | | 9 | % |
| Operating revenues (In thousands) | | | | | | | | | | | | | |
| Oil and condensate | | $ | 6,617 | | $ | 7,018 | | $ | 401 | | | 6 | % |
| Natural gas | | | 24,983 | | | 31,376 | | | 6,393 | | | 26 | % |
| | | | | | | | | | | | | | |
| Total Operating Revenues | | $ | 31,600 | | $ | 38,394 | | $ | 6,794 | | | 21 | % |
Oil and natural gas operating expenses for the six months ended June 30, 2006 increased 47% to $7.1 million from $4.8 million for the same period in 2005 due principally to higher lifting costs of $2.4 million primarily attributable to the increased number of producing wells added after the first half of 2005, expenses related to workovers, higher market costs of oilfield services and higher ad valorem
taxes. Operating expenses per equivalent unit increased to $1.36 per Mcfe in the first half of 2006 compared to $1.03 per Mcfe in the same period in 2005.
Depreciation, depletion and amortization (DD&A) expense for the six months ended June 30, 2006 increased 45% to $14.0 million ($2.70 per Mcfe) from $9.7 million ($2.06 per Mcfe) for the same period in 2005. This increase was primarily due to (1) an increase in production volumes and (2) an increase in the DD&A rate attributable to the increased land, seismic and drilling costs added to the proved property cost base and increased future development costs largely related to the significant increase in the number of Barnett Shale wells.
General and administrative expense for the six months ended June 30, 2006 increased by $2.0 million to $7.3 million from $5.3 million for the same period in 2005 primarily as a result of (1) higher salary and incentive compensation costs of $0.7 million, attributable to an increased headcount and an overall increase in salaries and incentive bonuses, (2) higher contract service costs of $0.8 million largely due to costs to cover accounting staff vacancies and to support the continued phase-in of our integrated software system, (3) higher auditing fees of $0.2 million largely attributable to the financial restatement for mark-to-market accounting on derivatives and (4) higher stock compensation expense of $0.2 million associated with the issuance of restricted stock beginning in May of 2005 and expenses associated with the adoption of SFAS No. 123(R) effective January 1, 2006.
The net gain on derivatives of $8.4 million in the first half of 2006 was comprised of (1) $2.8 million of realized gain on net settled derivatives and (2) $5.6 million of net unrealized mark-to-market gain on the derivatives accounted for as nondesignated derivatives. The mark-to-market loss on derivatives of $0.5 million in the first half of 2005 was comprised of (1) $0.2 million of realized gain on net settled derivatives and (2) $0.7 million of net unrealized mark-to-market loss on the derivatives accounted for as nondesignated derivatives.
We recorded a $35,000 benefit on our equity interest in Pinnacle for the six months ended June 30, 2006. The increase in earnings was primarily due to the non-cash gains related to Pinnacle’s hedging activity. In April 2006, our ownership interest in Pinnacle was reduced below 20 percent; consequently, we converted from accounting for our investment in Pinnacle using the equity method to the cost method.
Loss on the early extinguishment of debt was $0.3 million in connection with the Company’s refinancing of its First Lien Credit Facility in May 2006. After the refinancing, the Company’s borrowing base was increased to $40.0 million from $22.5 million.
Interest expense and capitalized interest for the six months ended June 30, 2006 were $8.9 million and ($4.5) million, respectively, as compared to $3.4 million and ($2.2) million for the same period in 2005. The increases in 2006 are attributable to the borrowings under the Second Lien Credit Facilit in July 2005, and borrowings under the Senior Credit Facility in 2006.
Income taxes increased to $5.1 million for the six months ended June 30, 2006 from $3.6 million for the same period in 2005 as a result of higher taxable income.
Liquidity and Capital Resources
During the six months ended June 30, 2006, capital expenditures, net of $23.6 million in proceeds from property sales, exceeded our net cash flows provided by operating activities. For future capital expenditures in 2006, we expect to use cash on hand, proceeds from the 2006 Private Placement, cash generated by operating activities and available draws on the Senior Credit Facility to partially fund our planned drilling expenditures and fund leasehold costs and geological and geophysical costs on our exploration projects in 2006. We may need to seek other financing alternatives to fully fund our 2006 capital expenditures program, including possible debt or equity financings.
We may not be able to obtain financing as may be needed in the future on terms that would be acceptable to us. If we cannot obtain adequate financing, we anticipate that we may be required to limit or defer our planned oil and natural gas exploration and development program, thereby adversely affecting the recoverability and ultimate value of our oil and natural gas properties.
Our primary sources of liquidity have included funds generated by operations, proceeds from the issuance of various securities, including our common stock, preferred stock and warrants (including our public offering in 2004 and our private placement in 2005 of our common stock), and borrowings under our credit facilities. Our liquidity position has been enhanced by the availability of funds under the Senior Credit Facility, the borrowing base of which was increased to $50.0 million effective August 1, 2006. In addition, we received proceeds of $33.7 million from the 2006 Private Placement.
Cash flows provided by operating activities were $14.3 million and $31.7 million for the six months ended June 30, 2005 and 2006, respectively. The increase was primarily due to increased production and higher commodity prices.
We have planned capital expenditures in 2006 of approximately $140.0 million to $145.0 million, of which $117.5 million is expected to be used for drilling activities in our project areas and the balance is expected to be used to fund 3-D seismic surveys and land acquisitions. In 2006, we plan to drill approximately 26 gross wells (11.7 net) in the onshore Gulf Coast area and 49 gross wells (35.0 net) in our Barnett Shale area and 25 to 30 gross wells (25 to 30 net) in our East Texas areas, primarily in our Camp Hill oil field. The actual number of wells drilled and capital expended is dependent upon our available financing, cash flow, availability and cost of drilling rigs, land and partner issues and other factors.
We have continued to reinvest a substantial portion of our cash flows into our leasehold acreage and 3-D prospect portfolio, improving our 3-D seismic interpretation technology and funding our drilling program. Capital expenditures were $53.4 million (excluding $9.0 million of proceeds from an asset sale) and $91.8 million (excluding $23.6 million of proceeds from asset sales) for the six months ended June 30, 2005 and 2006, respectively.
Our drilling efforts in the Gulf Coast region resulted in apparent successes in drilling seven gross wells (1.7 net) during the six months ended June 30, 2006. In our Barnett Shale area, we had apparent successes in drilling 27 gross wells (19.3 net) during the first six months of 2006, and in our East Texas area, we had apparent successes in drilling six gross wells (5.9 net) during that period. We also drilled four gross (3.8 net) service wells. Of the 40 apparently successful wells, 26 have been completed and the remaining wells were in various stages of completion at June 30, 2006.
We have accelerated the development of our Camp Hill project. In August 2005, management proposed the acceleration of the Camp Hill development to our board of directors. Accordingly, a development plan was formally approved by the board for increased drilling activity in the Camp Hill field, beginning with an initial 60-well drilling program. In February 2006, our board of directors formally approved a multi-year plan to fully develop the entire Camp Hill field. In furtherance of this plan, we expect to drill between 25 and 30 gross wells (25 to 30 net) in this area at an estimated cost of $2.4 million during 2006. To fully develop the field, we expect to drill approximately 326 wells from 2006 through 2017, at a total cost of approximately $22.0 million and total operating costs including steam of approximately $175.0 million. The precise timing and amount of our expenditures on additional well drilling and increased steam injection to develop the proved undeveloped reserves in this project will depend on several factors including the relative prices of oil and natural gas.
In our Camp Hill field in the East Texas area, we drilled seven gross wells (7.0 net) during 2005, all of which are apparent successes. During 2006 and the first half of 2007, we expect to drill between 55 and 60 gross wells (55 to 60 net) in this area at an estimated cost of approximately $4.2 million.
Financing Arrangements
First Lien Credit Facility
On September 30, 2004, we entered into a Second Amended and Restated Credit Agreement with Hibernia National Bank and Union Bank of California, N.A. (the “First Lien Credit Facility”), which was to mature on September 30, 2007. The First Lien Credit Facility provided for (1) a revolving line of credit of up to the lesser of the Facility A Borrowing Base and $75.0 million and (2) a term loan facility of up to the lesser of the Facility B Borrowing Base and $25.0 million (subject to the limit of the borrowing base, which was $22.5 million as of March 31, 2006). It was secured by substantially all of our assets and was guaranteed by our subsidiary, CCBM, Inc. The First Lien Credit Facility was amended on July 21, 2005 in connection with the Second Lien Credit Facility and refinancing discussed in our 2005 Annual Report on Form 10-K/A. On May 25, 2006, we terminated this agreement upon entering into the Senior Credit Facility as described below.
Second Lien Credit Facility
On July 21, 2005, we entered into a second lien credit agreement with Credit Suisse, as administrative agent and collateral agent (the “Agent”) and the lenders party thereto (the “Second Lien Credit Facility”) that matures on July 21, 2010. The Second Lien Credit Facility provides for a term loan facility in an aggregate principal amount of $150.0 million. It is secured by substantially all of our assets and is guaranteed by our subsidiaries. The liens securing the Second Lien Credit Facility were second in priority to the liens securing the First Lien Credit Facility prior to its termination in May 2006, as discussed above, and are second in priority to the liens securing the Senior Credit Facility.
The interest rate on each base rate loan will be (1) the greater of the Agent’s prime rate and the federal funds effective rate plus 0.5%, plus (2) a margin of 5.0%. The interest rate on each eurodollar loan will be the adjusted LIBOR plus a margin of 6.0%. Interest on
eurodollar loans is payable on either the last day of each interest period or every three months, whichever is earlier. Interest on base rate loans is payable quarterly.
The Second Lien Credit Facility is subject to customary events of default. Subject to certain exceptions, if an event of default occurs and is continuing, the Agent may accelerate amounts due under the Second Lien Credit Facility (except for a bankruptcy event of default, in which case such amounts will automatically become due and payable). If an event of default occurs under the Second Lien Credit Facility as a result of an event of default under the Senior Credit Facility, the Agent may not accelerate the amounts due under the Second Lien Credit Facility until the earlier of 45 days after the occurrence of the event resulting in the default and acceleration of the loans under the Senior Credit Facility.
We are subject to certain covenants under the terms of the Second Lien Credit Facility. These covenants include, but are not limited to, the maintenance of the following financial ratios: (1) a minimum current ratio of 1.0 to 1.0 including availability under the borrowing base under the First Lien Credit Facility; (2) a minimum quarterly interest coverage ratio of 2.75 to 1.0 through June 30, 2006 and 3.0 to 1.0 thereafter; (3) a minimum quarterly proved reserve coverage ratio of 1.5 to 1.0 through September 30, 2006 and 2.0 to 1.0 thereafter; and (4) a maximum total net recourse debt to EBITDA (as defined in the Second Lien Credit Facility) ratio of not more than 3.5 to 1.0 through June 30, 2006 and 3.25 to 1.0 thereafter. The Second Lien Credit Facility also places restrictions on additional indebtedness, dividends to shareholders, liens, investments, mergers, acquisitions, asset dispositions, repurchase or redemption of our common stock, speculative commodity transactions, transactions with affiliates and other matters.
Senior Secured Revolving Credit Facility
On May 25, 2006, we entered into a Senior Secured Revolving Credit Facility (“Senior Credit Facility”) with JPMorgan Chase Bank, National Association, as administrative agent that matures May 25, 2010. The Senior Credit Facility provides for a revolving credit facility up to the lesser of the borrowing base and $200.0 million. It is secured by substantially all of our assets and is guaranteed by our subsidiaries. The liens securing the Senior Credit Facility are first in priority to the liens securing the Second Lien Credit Facility.
The borrowing base will be determined by the lenders at least semi-annually on each May 1 and November 1, beginning November 1, 2006. The initial borrowing base was $40.0 million. We may request one unscheduled borrowing base determination subsequent to each scheduled determination, and the lenders may request unscheduled determinations at any time. A one-time redetermination effective August 1, 2006 increased the borrowing base to $50.0 million. In addition, in the event the outstanding principal balance of indebtedness under the Second Lien Credit Facility exceeds $150.0 million, the borrowing base under the Senior Credit Facility will be reduced $1.00 for every $4.00 of such additional indebtedness under the Second Lien Credit Facility.
If the outstanding principal balance of the revolving loans under the Senior Credit Facility exceeds the borrowing base at any time, we have the option within 30 days to take any of the following actions, either individually or in combination: make a lump sum payment curing the deficiency, pledge additional collateral sufficient in the lenders' opinion to increase the borrowing base and cure the deficiency or begin making equal monthly principal payments that will cure the deficiency within the ensuing six-month period. Those payments would be in addition to any payments that may come due as a result of the quarterly borrowing base reductions. Otherwise, any unpaid principal or interest will be due at maturity.
The annual interest rate on each base rate borrowing will be (1) the greatest of the Agent’s Prime Rate, the Base CD Rate plus 1.0% and the Federal Funds Effective Rate plus 0.5%, plus (2) a margin between 0.25% and 1.75% (depending on the current level of borrowing base usage). The interest rate on each Eurodollar Loan will be the adjusted LIBOR Rate plus a margin between 1.5% to 3.0% (depending on the current level of borrowing base usage).
Following completion of the 2006 Private Placement, we repaid all amounts outstanding under the Senior Credit Facility. Effective August 1, 2006, $50.0 million was available for borrowing under the Senior Credit Facility, and we had no borrowings outstanding as of such date. The Company is subject to certain covenants under the terms of the Senior Credit Facility which include, but are not limited to, the maintenance of the following financial ratios: (1) a minimum current ratio of 1.0 to 1.0; and (2) a maximum total net debt to Consolidated EBITDAX (as defined in the Senior Credit Facility) of 3.50 to 1.0 through June 30, 2006 and 3.25 to 1.0 thereafter. The Senior Credit Facility also places restrictions on indebtedness, dividends to shareholders, liens, investments, mergers, acquisitions, asset dispositions, repurchase or redemption of the Company’s common stock, speculative commodity transactions, transactions with affiliates and other matters.
The Senior Credit Facility is subject to customary events of default, the occurrence and continuation of which could result in the acceleration of amounts due under the facility by the agent or the lenders.
Shelf Registration Statement
In the third quarter of 2005, we filed a registration statement on Form S-3 with the SEC for the proposed offering from time to time of up to $250.0 million of senior or subordinated debt securities, preferred stock, common stock and warrants to purchase debt securities, preferred stock, common stock or other securities. Due to the delay in our filing of our Annual Report on Form 10-K for the year ended December 31, 2005, we believe that we are not eligible to use a “short form” registration statement on Form S-3 at the present time. The Company has withdrawn the registration statement with the SEC.
Lease Option Arrangements
Due to the limited capital available in the first half of 2006 to fund all of the Company’s ongoing lease acquisition efforts in the Barnett Shale and other shale plays, the Company elected to enter into several lease option agreements with a number of third parties and with Steven A. Webster, the Company’s chairman (collectively, the “counterparties”). The terms and conditions of the leasing arrangement (agreement terms are described below) with Mr. Webster are consistent with the leasing arrangements the Company has entered into with the other third parties. These leasing arrangements provide the Company the option to purchase leases from the counterparties, over an option period, generally 90 days, for the counterparties’ original cost of the leases plus an option fee. Strategically, these leasing arrangements have allowed the Company to temporarily control important acreage positions during periods that the Company has lacked sufficient capital to directly acquire such oil and gas leases.
Since May 2006, the Company has acquired certain oil and gas leases through the aforementioned lease option arrangement with Mr. Webster. The acquisitions were made pursuant to a land option agreement between Mr. Webster and the Company dated January 25, 2006. The terms and conditions of this leasing arrangement with Mr. Webster are consistent with leasing arrangements the Company has entered into with the other third parties. Under the option agreement, Mr. Webster agreed to acquire oil and gas leases in areas where the Company is actively leasing or that it deems prospective. On or before the 90th day from the date that Mr. Webster acquires any lease in these areas, the Company has the option to acquire these leases from Mr. Webster for 110% of Mr. Webster’s purchase price or, on the 90th day, pay a non-refundable 10% option extension fee to add a second 90-day option period. On or before the end of this second 90-day option period, the Company has the option to pay Mr. Webster 110% of his original purchase price to acquire the lease. If, at the end of the second option period, the Company has not exercised its purchase option, Mr. Webster will retain ownership of the oil and gas leases. In addition to the cash payments described above, the Company will assign a one-half of one percent of 8/8ths overriding royalty interest (proportionally reduced to the actual net interest in any given lease acquired) on any lease it acquires from Mr. Webster in the first 90-day option period and a one percent of 8/8ths overriding royalty interest (also proportionally reduced) on any lease acquired from Mr. Webster in the second 90-day option period. As of June 30, 2006, Mr. Webster has acquired oil and gas leases for approximately $4.2 million, the Company has purchased approximately $2.6 million in leases from Mr. Webster and the Company has made option extension payments of approximately $48,000 to Mr. Webster. In the third quarter of 2006, the Company plans to acquire additional leases from Mr. Webster and the other third parties pursuant to the option agreements and longer term, the Company may continue to use these arrangements as a strategic alternative when available funding may be limited.
Effects of Inflation and Changes in Price
Our results of operations and cash flows are affected by changing oil and natural gas prices. If the price of oil and natural gas increases (decreases), there could be a corresponding increase (decrease) in the operating cost that we are required to bear for operations, as well as an increase (decrease) in revenues. Inflation has had a minimal effect on us.
Recently Adopted Accounting Pronouncements
On December 16, 2004, the FASB issued SFAS No. 123 (revised 2004), “Share-Based Payment” (“SFAS No. 123(R)”). SFAS No. 123(R) requires companies to measure all employee stock-based compensation awards using a fair value method and record such expense in their consolidated financial statements. In addition, the adoption of SFAS No. 123(R) requires additional accounting and disclosure related to the income tax and cash flow effects resulting from share-based payment arrangements. SFAS No. 123(R) was effective beginning as of the first annual reporting period after June 15, 2005. We adopted the provisions of SFAS No. 123(R) during the first quarter of 2006 using the modified prospective method for transition and have recognized approximately $0.3 million in compensation expense in the first half of 2006.
Critical Accounting Policies
The following summarizes several of our critical accounting policies:
Use of Estimates
The preparation of financial statements in conformity with U.S. generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting periods. Actual results could differ from these estimates. The use of these estimates significantly affects our natural gas and oil properties through depletion and the full cost ceiling test, as discussed in more detail below.
Significant estimates include volumes of oil and natural gas reserves used in calculating depletion of proved oil and natural gas properties, future net revenues and abandonment obligations, impairment of undeveloped properties, future income taxes and related assets/liabilities, bad debts, derivatives, stock-based compensation, contingencies and litigation. Oil and natural gas reserve estimates, which are the basis for unit-of-production depletion and the ceiling test, have numerous inherent uncertainties. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Results of drilling, testing and production subsequent to the date of the estimate may justify revision of such estimate. Accordingly, reserve estimates are often different from the quantities of oil and natural gas that are ultimately recovered. In addition, reserve estimates are vulnerable to changes in wellhead prices of crude oil and natural gas. Such prices have been volatile in the past and can be expected to be volatile in the future.
The significant estimates are based on current assumptions that may be materially effected by changes to future economic conditions such as the market prices received for sales of volumes of oil and natural gas, interest rates, the market value of our common stock and corresponding volatility and our ability to generate future taxable income. Future changes to these assumptions may affect these significant estimates materially in the near term.
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 $1.1 million and $1.8 million for the six months ended June 30, 2005 and 2006, 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. We do not amortize investments in unproved properties until proved reserves associated with the projects can be determined or until these investments are impaired. We periodically evaluate, on a property-by-property basis, unevaluated properties 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, 2005 and 2006 was $2.14 and $2.70, 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.
The net capitalized costs of proved oil and natural gas properties are subject to a “ceiling test” which limits such costs to the estimated present value, discounted at a 10% interest rate, of future net revenues from proved reserves, based on current economic and operating conditions (the “Full Cost Ceiling”). If net capitalized costs exceed this limit, the excess is charged to operations through depreciation, depletion and amortization.
In connection with our June 30, 2006 ceiling test computation, a price sensitivity study also indicated that a 10% increase in commodity prices at June 30, 2006 would have increased the ceiling test cushion by approximately $35 million. Conversely, a 10% decrease in commodity prices at June 30, 2006 would have reduced the ceiling test cushion by approximately $35 million. The aforementioned price sensitivity and NPV is as of June 30, 2006 and, accordingly, does not include any potential changes in reserves due to third quarter 2006 performance, such as commodity prices, reserve revisions and drilling results.
The Full Cost Ceiling cushion at the end of June 2006 of approximately $53 million was based upon average realized oil and natural gas prices of $68.85 per Bbl and $6.01 per Mcf, respectively, or a volume weighted average price of $46.31 per BOE. This cushion, however, would have been zero on such date at an estimated volume weighted average price of $39.31 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. 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 plus estimated future development costs 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, which are primarily oil reserves. We had 97.9 Bcfe and 91.1 Bcfe of proved undeveloped reserves at December 31, 2005 and June 30, 2006, respectively, representing 65% and 61% of our total proved reserves. As of December 31, 2005 and June 30, 2006, a large portion of these proved undeveloped reserves, or approximately 38.1 Bcfe and 38.0 Bcfe, respectively, 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 would have reduced our earnings by (1) 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), (2) an estimated $5.9 million in 2003 (due to higher depletion expense), (3) an estimated $3.4 million in 2004 (due to higher depletion expense) and (4) an estimated $6.9 million in 2005 (due to higher depletion expense).
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 cost and current prices were all to remain constant, this continued build-up of capitalized costs increases the probability of a ceiling test write-down.
We depreciate other property and equipment using the straight-line method based on estimated useful lives ranging from five to 10 years.
Oil and Natural Gas Reserve Estimates
The proved reserve data as of December 31, 2005 included in this document are estimates prepared by Ryder Scott Company, DeGolyer and MacNaughton and Fairchild & Wells, Inc., Independent Petroleum Engineers. We estimated the reserve data for all other dates using current market conditions. Reserve engineering is a subjective process of estimating underground accumulations of hydrocarbons that cannot be measured in an exact manner. The process relies on judgment and the interpretation of available geologic, geophysical, engineering and production data. The extent, quality and reliability of this data can vary. The process also requires certain economic assumptions regarding drilling and operating expense, capital expenditures, taxes and availability of funds. The SEC mandates some of these assumptions such as oil and natural gas prices and the present value discount rate.
Proved reserve estimates prepared by others may be substantially higher or lower than our estimates. Because these estimates depend on many assumptions, all of which may differ from actual results, reserve quantities actually recovered may be significantly different than estimated. Material revisions to reserve estimates may be made depending on the results of drilling, testing, and rates of production.
You should not assume that the present value of future net cash flows is the current market value of our estimated proved reserves. In accordance with SEC requirements, we based the estimated discounted future net cash flows from proved reserves on prices and costs on the date of the estimate.
Our rate of recording depreciation, depletion and amortization expense for proved properties depends on our estimate of proved reserves. If these reserve estimates decline, the rate at which we record these expenses will increase. A 10% increase or decrease in our proved reserves would have increased or decreased our depletion expense by 10% for the three months ended June 30, 2006.
As of December 31, 2005, approximately 81% of our proved reserves were proved undeveloped and proved nonproducing. Moreover, some of the producing wells included in our reserve reports as of December 31, 2005 had produced for a relatively short period of
time as of that date. Because most of our reserve estimates are calculated using volumetric analysis, those estimates are less reliable than estimates based on a lengthy production history. Volumetric analysis involves estimating the volume of a reservoir based on the net feet of pay of the structure and an estimation of the area covered by the structure based on seismic analysis. In addition, realization or recognition of our proved undeveloped reserves will depend on our development schedule and plans. Lack of certainty with respect to development plans for proved undeveloped reserves could cause the discontinuation of the classification of these reserves as proved. Although we have accelerated our development of the Camp Hill field in East Texas, we have in the past chosen to delay development of our proved undeveloped reserves in the Camp Hill field in East Texas in favor of pursuing shorter-term exploration projects with higher potential rates of return, adding to our lease position in this field and further evaluating additional economic enhancements for this field's development. The average life of the Camp Hill proved undeveloped reserves is approximately 15 years, with 50% of these reserves being booked over 8 years ago. Although we have recently accelerated the pace of the development of the Camp Hill project, there can be no assurance that the aforementioned discontinuance will not occur.
Derivative Instruments
We use derivatives to manage price and interest rate risk underlying our oil and gas production and the variable interest rate on the Second Lien Credit Facility. Given our limited internal resources, we have elected to account for all new derivative contracts as non-designated derivatives that will be marked-to-market. For a discussion of the impact of changes in the prices of oil and gas on our hedging transactions, see “Volatility of Oil and Natural Gas Prices” below.
We have initiated a program designed to manage our exposure to interest rate fluctuations by entering into financial derivative instruments. The primary objective of this program is to reduce the overall cost of borrowing. We have entered into interest rate swap agreements with respect to amounts borrowed under the Second Lien Credit Facility, which effectively exchange existing obligations to pay interest based on floating rates for obligations to pay interest based on fixed LIBOR rates.
Our Board of Directors sets all of our risk management policies and reviews volume limitations, types of instruments and counterparties, on a quarterly basis. These policies require that derivative instruments be executed only by either the President or Chief Financial Officer after consultation and concurrence by the President, Chief Financial Officer and Chairman of the Board. The master contracts with the approved counterparties identify the President and Chief Financial Officer as the only representatives authorized to execute trades. The Board of Directors also reviews the status and results of derivative activities quarterly.
During the third quarter of 2005, we entered into interest rate swap agreements with respect to amounts outstanding under the Second Lien Credit Facility. These arrangements are designed to manage our exposure to interest rate fluctuations during the period beginning January 1, 2006 through June 30, 2007 by effectively exchanging existing obligations to pay interest based on floating rates for obligations to pay interest based on fixed LIBOR rates. These derivatives will be marked-to-market at the end of each period and the realized and unrealized gain or loss will be reported as mark-to-market gain (loss) on derivatives, net within other income and expenses on our Statement of Income.
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. 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.
Contingencies
Liabilities and other contingencies are recognized upon determination of an exposure, which when analyzed indicates that it is both probable that an asset has been impaired or that a liability has been incurred and that the amount of such loss is reasonably estimable.
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 accounting rules of the Commission. See “—Critical Accounting Policies and Estimates—Oil and Natural Gas Properties.”
Total oil purchased and sold under swaps and collars during the three months ended June 30, 2005 and 2006 was 38,800 Bbls and 18,200 Bbls, respectively. Total natural gas purchased and sold under swaps and collars during the three months ended June 30, 2005 and 2006 was 1,032,000 MMBtu and 1,275,000 MMBtu, respectively. Total oil hedged under swaps and collars during the six months ended June 30, 2005 and 2006 were 71,700 Bbls and 36,200 Bbls, respectively. Total natural gas hedged under swaps and collars during the six months ended June 30, 2005 and 2006 were 1,960,000 MMBtu and 2,357,000 MMBtu, respectively. The net gain/(loss) realized by us under such hedging arrangements was $(30,000) and $1.2 million for the three months ended June 30, 2005 and 2006, respectively, and was $0.2 million and $2.5 million for the six months ended June 30, 2005 and 2006, respectively. These gains/(losses) are included in mark-to-market gain (loss) on derivatives, net.
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 options, in order to establish some price floor protection. We do not hold or issue derivative instruments for trading purposes.
For the quarter ended June 30, 2005 and 2006, the unrealized gain on oil and natural gas derivatives was $1.2 million and $1.3 million, respectively. For the six months ended June 30, 2005 and 2006, the unrealized mark-to-market gain (loss) on derivatives, net was ($0.7) million and $4.6 million, respectively. The gains (losses) are reported as mark-to-market gain (loss) on derivatives, net.
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 some 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 reporting settlement prices on the Houston Ship Channel index for the last three trading days of a particular contract month. Our oil derivative transactions are generally settled based on the average reporting settlement prices on the West Texas Intermediate index for each trading day of a particular calendar month. For the second quarter of 2006, a 10% change in the price per Mcf of gas sold would have changed revenue by $1.4 million. A 10% change in the price per barrel of oil would have changed revenue by $0.3 million.
The table below summarizes our total natural gas production volumes subject to derivative transactions during the six months ended June 30, 2006:
Natural Gas Collars | | | |
| Volumes (MMBtu) | | | 2,357,000 | |
| Average price ($/MMBtu) | | | | |
| Fixed | | $ | 7.30 | |
| Floor | | $ | 8.00 | |
| Ceiling | | $ | 9.21 | |
The table below summarizes our total crude oil production volumes subject to derivative transactions for the six months ended June 30, 2006:
Crude Oil Collars | | | |
| Volumes (Bbls) | | | 36,200 | |
| Average price ($/Bbls) | | | | |
| Floor | | $ | 56.01 | |
| Ceiling | | $ | 68.28 | |
At June 30, 2006 we had the following outstanding derivative positions:
| | | Contract Volumes | | | | | | | |
| | | | | | | Average | | Average | | Average | |
Quarter | | BBls | | MMbtu | | Fixed Price | | Floor Price | | Ceiling Price | |
| | | | | | | | | | | | |
| Third Quarter 2006 | | | | | | 1,043,000 | | $ | 7.22 | | $ | 7.06 | | $ | 10.04 | |
| Third Quarter 2006 | | | 27,600 | | | | | | | | | 59.00 | | | 70.22 | |
| Fourth Quarter 2006 | | | | | | 705,000 | | | 7.64 | | | 7.51 | | | 9.06 | |
| Fourth Quarter 2006 | | | 18,400 | | | | | | | | | 58.50 | | | 70.93 | |
| First Quarter 2007 | | | | | | 630,000 | | | | | | 7.95 | | | 9.81 | |
| Second Quarter 2007 | | | | | | 728,000 | | | | | | 7.31 | | | 8.87 | |
| Third Quarter 2007 | | | | | | 552,000 | | | | | | 7.53 | | | 9.10 | |
| Fourth Quarter 2007 | | | | | | 276,000 | | | | | | 6.92 | | | 8.32 | |
| First Quarter 2008 | | | | | | 182,000 | | | | | | 7.25 | | | 8.65 | |
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, 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, the ability of expected sources of liquidity to implement the Company’s business strategy, future exploration activity, production rates, exploration and development expenditures, the Company’s initiatives designed to eliminate material weaknesses in the Company’s internal control over financial reporting and the results of these initiatives and all and any other statements regarding future operations, financial results, business plans and cash needs 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, risks relating to limited operating history, technological changes, significant capital requirements of the Company, 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, the actual results of the initiatives designed to eliminate a material weakness in the Company’s internal control over financial reporting, completion of the implementation of the Company’s new accounting software system and the results of audits and assessments and other factors detailed in the Company's Annual Report on Form 10-K/A for the year ended December 31, 2005 and 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.
ITEM 3- QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
For information regarding our exposure to certain market risks, see “Quantitative and Qualitative Disclosures about Market Risk” in Item 7A of our Annual Report on Form 10-K/A for the year ended December 31, 2005, except for the Company’s hedging activity subsequent to December 31, 2005, which is described above in “Volatility of Oil and Natural Gas Prices.” There have been no material changes to the disclosure regarding our exposure to certain market risks made in the Annual Report on Form 10-K/A. For additional information regarding our long-term debt, see Note 2 of the Notes to Unaudited Consolidated Financial Statements in Item 1 of Part I of this Quarterly Report on Form 10-Q.
ITEM 4- CONTROLS AND PROCEDURES
Disclosure Controls and Procedures. We maintain disclosure controls and procedures that are designed to provide reasonable assurance that information required to be disclosed by us in the reports that we file or submit to the Securities and Exchange Commission under the Securities Exchange Act of 1934, as amended (the “Exchange Act”), is recorded, processed, summarized and reported within the time periods specified by the Commission’s rules and forms, and that information is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure.
In accordance with Exchange Act Rules 13a-15 and 15d-15, we carried out an evaluation, under the supervision and with the participation of management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report. As described in more detail in our Form 10-K/A filed on April 11, 2006 , we identified material weaknesses in the Company’s internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) in connection with the work related to Management’s Annual Report on Internal Control over Financial Reporting. As a result of these material weaknesses, our Chief Executive Officer and Chief Financial Officer concluded that, as of December 31, 2005, the Company’s disclosure controls and procedures were not effective. Additionally, as a result of such material weaknesses, the Company was not able to file its Annual Report on Form 10-K for the year ended December 31, 2005 with the Securities and Exchange Commission in the time required. Because the control deficiencies leading to such material weaknesses were still present as of June 30, 2006, our Chief Executive Officer and Chief Financial Officer have concluded that as of the end of the period covered by this report, the Company’s disclosure controls and procedures were not effective. The Company has outlined a number of initiatives, as discussed below, that it believes will remediate these material weaknesses in 2006.
Hedging
For a description of a material weakness related to the accounting for our derivatives and related matters, see Item 9A in our Annual Report on Form 10-K/A for the year ended December 31, 2005.
Year-end Close Process and Other Controls
In the fourth quarter of 2005, we hired a manager of financial reporting, filling the prior vacancy described in our Annual Report on Form 10-K for the year ended December 31, 2004. This manager of financial reporting subsequently left the Company late in the fourth quarter of 2005, creating a new vacancy. Our manager of accounting left the Company in November 2005. In February 2006, our controller and our director of financial planning and analysis also both left the Company. We attempted to fill these vacancies, but were not able to do so as quickly as we would have liked. We subsequently hired a new controller and manager of operations accounting in March 2006, near the end of our year-end closing process. During the second quarter of 2006, we hired a new manager of financial reporting, a manager of financial planning and analysis and a manager of general accounting.
The accounting and financial staff vacancies described above occurred during the year-end close process. While these vacancies were partially remedied by reliance upon independent financial reporting consultants for review of critical accounting areas and disclosures and material nonstandard transactions, these absences, combined with our complex manual, review intensive accounting system, placed greater burdens of detailed reviews on our remaining middle and upper-level accounting professionals, which in turn compromised the level of their qualitative review of the elements of the year end close, financial statements and disclosures. These review procedures are an important component of our controls surrounding the closing process and in financial reporting. As a result, we believe that these vacancies resulted in inadequate staffing, supervision and financial reporting expertise in our accounting and financial areas, which constituted a material weakness in our internal control over financial reporting as of December 31, 2005. These deficiencies ultimately affect the accuracy of our financial statement reporting and disclosures.
Accordingly, in connection with the audit of our 2005 financial statements, Pannell Kerr Forster of Texas, P.C. (“PKF”), our independent registered public accounting firm, detected a number of errors and/or omissions that were an indication that the aforementioned material weaknesses were present at December 31, 2005, increasing the likelihood to more than remote that a material misstatement of the Company’s annual or interim financial statements will not be prevented or detected. The most notable of these errors included (1) our accounting for our derivatives as cash flow hedges rather than on a mark-to-market basis, (2) corrections for certain computational errors in the fair value of our derivatives previously reported in other comprehensive income in 2004 and 2005, (3) errors related to our capital expenditures accrual, (4) errors in the evaluation of our unproved property pool and (5) errors related to the evaluation of our asset retirement obligation. These errors came to management's attention in connection with the preparation of
our consolidated financial statements for the year ended December 31, 2005. The controls in place related to items (3), (4) and (5) (“Other Controls”) were not properly designed and/or operating to provide reasonable assurance that amounts would be properly recorded in the Company’s consolidated financial statements. The failure of the Other Controls constituted a third material weakness in our internal controls as of December 31, 2005. Management determined that the restatement of our consolidated financial statements discussed in Note 3 to our consolidated financial statements included in Item 8 of our Annual Report on Form 10-K/A for the year ended December 31, 2005 was an additional effect of the year-end close process material weakness. All correcting adjustments were recorded by the Company prior to the finalization of its 2005 financial statements. The Company has implemented procedures to prevent these specific errors from occurring in the future. However, the additional initiatives (outlined below) are needed to remediate the material weaknesses in our internal controls, and thus lower the risk level to remote of other potential material errors or omissions.
As a result of these three material weaknesses, our management concluded in our Annual Report on Form 10-K/A for the year ended December 31, 2005 that our internal control over financial reporting was not effective as of December 31, 2005.
While there can be no assurance in this regard, we expect that the following initiatives will eliminate the material weaknesses relating to our year-end close process and Other Controls in 2006: (1) increasing the level of our professional accounting staff, including the successful placement of a new manager of financial reporting, new controller, new manager of operations accounting, new manager of general accounting and new director of financial planning and analysis (including the placement in the first quarter of 2006 of a new manager of financial reporting, new controller and new manager of operations accounting and the placement in the second quarter of 2006 of a manager of financial planning and analysis and a manager of general accounting), and (2) completing our transition to a new fully-integrated accounting software system (phase one was completed in the fourth quarter of 2005) to automate processes and improve qualitative reviews. Until these initiatives are fully implemented, we will continue to rely on manual processes and require additional commitment of resources to the closing process to produce our financial records and reports. Given our limited internal resources, we have elected to account for all new derivative contracts as non-designated derivatives. Our project team has made significant progress towards completing the transition to a new fully-integrated accounting software system described in the second initiative. We have discussed these material weaknesses and our remediation steps with our Audit Committee.
Changes in Internal Control over Financial Reporting. Except as described above, there have not been any changes in the Company's internal control over financial reporting during the fiscal quarter ended June 30, 2006 that have materially affected, or are reasonably likely to materially affect, the Company's internal control over financial reporting. As described above, the Company identified material weaknesses in the Company's internal control over financial reporting and has described a number of planned changes to its internal control over financial reporting during 2006 designed to remediate these weaknesses. Some of these changes were effected in the first and second quarters of 2006, including some changes in staffing and changes in hedge accounting. This Item 4 should be read in conjunction with Item 9A included in our Annual Report on Form 10-K/A for the year ended December 31, 2005.
