* Includes negative fair value adjustments of $0.6 million as of September 30, 2004, and $0.7 million as of December 31, 2003, related to interest rate swap designated as a fair value hedge .
8
In accordance with SFAS No. 132 (revised 2003), Employers' Disclosures about Pensions and Other Postretirement Benefits, following are disclosures regarding the net periodic benefit costs recognized and the total amount of employer contributions.
The following table provides the components of net periodic benefit costs for the respective plans for the three months and nine months ended September 30, 2004 and 2003 (in thousands):
| Pension | | | Post-retirement Healthcare | |
| Three Months Ended
September 30, | | Nine Months Ended September 30, | | | Three Months Ended September 30, | | Nine Months Ended
September 30, | |
| 2004 | | 2003 | | 2004 | | 2003 | | | 2004 | | 2003 | | 2004 | | 2003 | |
| | | | | | | | | | | | | | |
Service cost | $ - | | $ - | | $ - | | $ - | $ 7 | | $ 7 | | $ 19 | | $ 21 |
Interest cost | 37 | | 39 | | 111 | | 117 | 65 | | 84 | | 207 | | 252 |
Amortization of prior
service cost | 1 | | 2 | | 3 | | 6 | 22 | | 26 | | 66 | | 78 |
Amortization of transitional
obligation | 1 | | 1 | | 3 | | 3 | - | | - | | - | | - |
Recognized actuarial (gain)
loss | 5 | | 4 | | 15 | | 12 | 8 | | 14 | | 30 | | 42 |
Net periodic benefit cost | | | | | | | $ 138 | $ 102 | | $ 131 | | $ 322 | | $ 393 |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Contributions paid to the pension and post-retirement healthcare plans during the three months and nine months ended September 30, 2004, were $0.1 and $0.5 million, respectively. We expect to contribute a total of approximately $0.7 million to our pension and other postretirement benefit plans during 2004.
The Financial Accounting Standards Board (FASB) issued FASB Staff Position ("FSP") SFAS 106-2, Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003, in May 2004, effective for the first interim or annual period beginning after June 15, 2004. The FSP requires employers that qualify for a prescription-drug subsidy under Medicare legislation enacted in December 2003 to recognize the reduction in costs as employees provide services in future years. We adopted FSP SFAS 106-2 in the third quarter of 2004, and it did not have a significant impact on our financial statements. As a result of the Medicare Prescription Drug, Improvement and Modernization Act of 2003, our accumulated postretirement benefit obligation as of January 1, 2004, decreased by $0.4 million.
9
8. EARNINGS PER SHARE
The following is a reconciliation of the numerators and denominators used in the calculation of basic and diluted earnings per share for the three months and nine months ended September 30, 2004 and 2003 (in thousands, except per share data).
| Three Months | | Nine Months |
| Ended September 30, | | Ended September 30, |
| 2004 | | 2003 | | 2004 | | 2003 |
Income before cumulative effect of change in accounting | | | | | | | |
principle | $ 6,434 | | $ 5,443 | | $ 28,656 | | $ 20,928 |
Cumulative effect of change in accounting principle | - | | | | - | | 1,363 |
Net income | $ 6,434 | | $ 5,443 | | $ 28,656 | | $ 22,291 |
| | | | | | | |
Weighted average shares, basic | 18,357 | | 17,992 | | 18,268 | | 17,948 |
Effect of dilutive securities: | | | | | | | |
Stock options | 217 | | 146 | | 184 | | 116 |
Weighted average shares, diluted | 18,574 | | 18,138 | | 18,452 | | 18,064 |
| | | | | | | |
Income before cumulative effect of change in accounting | | | | | | | |
principle, basic | $ 0.35 | | $ 0.30 | | $ 1.57 | | $ 1.17 |
Cumulative effect of change in accounting principle, basic | - | | - | | - | | 0.08 |
Net income per share, basic | $ 0.35 | | $ 0.30 | | $ 1.57 | | $ 1.25 |
| | | | | | | |
Income before cumulative effect of change in accounting | | | | | | | |
principle, diluted | $ 0.35 | | $ 0.30 | | $ 1.55 | | $ 1.16 |
Cumulative effect of change in accounting principle, diluted | - | | - | | - | | 0.08 |
Net income per share, diluted | $ 0.35 | | $ 0.30 | | $ 1.55 | | $ 1.24 |
9. STOCK SPLIT AND CHANGE IN PAR VALUE
On May 4, 2004, the Board of Directors approved a two-for-one split of the Company's common stock in the form of a 100 percent stock dividend payable on June 10, 2004 to shareholders of record on June 3, 2004. Shareholders received one additional share of common stock for each share held on the record date. All common shares and per share data have been retroactively adjusted to reflect the stock split. Also effective June 10, 2004, the Company changed the par value of its common stock from $6.25 to $0.01 per share.
10. COMPREHENSIVE INCOME
Comprehensive income represents changes in equity during the reporting period, including net income and charges directly to equity which are excluded from net income. For the three months and nine months ended September 30, 2004 and 2003, the components of comprehensive income were as follows (in thousands):
| Three Months | | Nine Months |
| Ended September 30, | | Ended September 30, |
| 2004 | | 2003 | | 2004 | | 2003 |
| | | | | | | |
Net income | $ 6,434 | | $ 5,443 | | $ 28,656 | | $ 22,291 |
Unrealized holding losses on hedging activities, net of | | | | | | | |
tax | (1,611) | | (1,876) | | (4,660) | | (3,752) |
Reclassification adjustment for hedging activities, net | | | | | | | |
of tax | 787 | | 470 | | 2,399 | | 4,040 |
Comprehensive income | | | | | | | |
11. SEGMENT INFORMATION
Segment information has been prepared in accordance with SFAS No. 131, Disclosure about Segments of an Enterprise and Related Information. Under SFAS No. 131, operating segments are defined as components of an enterprise about which separate financial information is available and is evaluated regularly by the chief operating decision maker, or decision-making group, in assessing performance. Our chief operating decision-making group consists of the Chief Executive Officer and other senior officials. This group routinely reviews and makes operating and resource allocation decisions among our oil and gas operations and PVR's coal royalty and land management operations. Accordingly, our reportable segments are as follows:
10
Oil and Gas - crude oil and natural gas exploration, development and production.
Coal Royalty and Land Management - the leasing of mineral interests and subsequent collection of royalties, the providing of fee-based coal handling, transportation and processing
infrastructure facilities, and the development and harvesting of timber.
Corporate and Other - primarily represents corporate functions.
The following is a summary of certain financial information relating to our segments:
| | | | Coal Royalty | | |
| | | | and Land | Corporate | |
| | | Oil and Gas | Management | and Other | Consolidated |
| | | (in thousands) |
For the three months ended September 30, 2004: | | | | |
Revenues | | | $ 33,015 | $ 19,397 | $ 329 | $ 52,741 |
Operating costs and expenses | | 15,276 | 4,093 | 2,700 | 22,069 |
Depreciation, depletion and amortization | 8,307 | 4,764 | 108 | 13,179 |
Operating income (loss) | | $ 9,432 | $ 10,540 | $ (2,479) | $ 17,493 |
Interest expense | | | | | | (1,719) |
Interest income and other | | | | | | 274 |
Income before minority interest and taxes | | | | | $ 16,048 |
Total assets | | $ 462,541 | $ 283,946 | $ 11,101 | $ 757,588 |
| | | | | |
For the three months ended September 30, 2003: | | | | |
Revenues | | | $ 29,035 | $ 12,812 | $ 174 | $ 42,021 |
Operating costs and expenses | | 11,411 | 2,803 | 2,786 | 17,000 |
Depreciation, depletion and amortization | 8,572 | 3,659 | 34 | 12,265 |
Operating income (loss) | | $ 9,052 | $ 6,350 | $ (2,646) | 12,756 |
Interest expense | | | | | | (1,380) |
Interest income | | | | | | 301 |
Income before minority interest and taxes | | | | | $ 11,677 |
Total assets | | $ 400,773 | $ 260,197 | $ 3,905 | $ 664,875 |
| | | | | | | |
11
| | | | Coal Royalty | | |
| | | | and Land | Corporate | |
| | | Oil and Gas | Management | and Other | Consolidated |
| | | (in thousands) |
For the nine months ended September 30, 2004: | | | | |
Revenues | | | $ 106,014 | $ 56,092 | $ 830 | $ 162,936 |
Operating costs and expenses | | 37,463 | 12,363 | 6,876 | 56,702 |
Depreciation, depletion and amortization | 26,015 | 14,385 | 322 | 40,722 |
Operating income (loss) | | $ 42,536 | $ 29,344 | $ (6,368) | $ 65,512 |
Interest expense | | | | | | (4,573) |
Interest income and other | | | | | | 806 |
Income before minority interest and taxes | | | | | $ 61,745 |
Total assets | | $ 462,541 | $ 283,946 | $ 11,101 | $ 757,588 |
| | | | | | |
For the nine months ended September 30, 2003: | | | | |
Revenues | | | $ 93,791 | $ 39,334 | $ 615 | $ 133,740 |
Operating costs and expenses | | 33,812 | 8,665 | 8,264 | 50,741 |
Depreciation, depletion and amortization | 24,493 | 12,027 | 103 | 36,623 |
Operating income (loss) | | $ 35,486 | $ 18,642 | $ (7,752) | 46,376 |
Interest expense | | | | | | (3,837) |
Interest income | | | | | | 951 |
Income before minority interest and taxes | | | | | $ 43,490 |
Total assets | | $ 400,773 | $ 260,197 | $ 3,905 | $ 664,875 |
12. RECENT ACCOUNTING PRONOUNCEMENTS
As previously disclosed in our 2003 Form 10-K, a reporting issue existed regarding the application of certain provisions of SFAS No. 141, Business Combinations and SFAS No. 142, Goodwill and Other Intangible Assets, to companies in the extractive industries, including oil and gas and coal industry companies. The issue is whether SFAS No. 142 requires registrants to classify the costs of mineral rights as intangible assets in the balance sheet, apart from other capitalized oil and gas property and coal property costs, and provide specific footnote disclosures. In April 2004, the FASB issued an FSP that clarifies certain sections of SFAS No. 141 and No. 142 relating to the characterization of coal mineral rights. The FSP is effective for the first reporting period beginning after April 29, 2004. As allowed by the FSP, the Partnership early adopted the FSP in April 2004 and, accordingly, reclassified its leased coal mineral rights back to tangible property. The Partnership discontinued straight-line amortization upon adoption and will deplete its coal mineral rights using the units-of-production method on a prospective basis. The amount capitalized related to a mineral right represents its fair value at the time such right was acquired, less accumulated amortization. Pursuant to the FSP, for comparative presentation purposes, $4.9 million was reclassified from other noncurrent assets to net property and equipment as of December 31, 2003, on the accompanying consolidated balance sheet.
In September 2004, the FASB issued another FSP to clarify that the scope exception in paragraph 8(b) of SFAS No. 142 includes the balance sheet classification and disclosures for drilling and mineral rights of oil and gas producing companies. Therefore, our historical practice of including the costs of mineral rights associated with extracting oil and gas as a component of oil and gas properties under SFAS No. 19, Financial Accounting and Reporting by Oil and Gas Producing Companies, has been affirmed by the new FSP.
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13. COAL HANDLING JOINT VENTURE
Effective July 1, 2004, the Partnership acquired from affiliates of Massey Energy Company a 50 percent interest in a joint venture formed to own and operate end-user coal handling facilities. The purchase price was $28.4 million and was funded through the Partnership's credit facility. The Partnership accounts for its investment in the joint venture under the equity method. Equity earnings of $0.2 million from the joint venture were included in other income on the consolidated statements of income for the three and nine months ended September 30, 2004.
14. SUBSEQUENT EVENTS
Dividend Declared. In October 2004, the Company declared a quarterly dividend of $0.1125 per share payable November 24, 2004, to shareholders of record on November 10, 2004.
Sales Plan Approved. In October 2004, the board of directors approved a plan to sell certain oil and gas properties in West Texas with a net book value of $18.4 million as of September 30, 2004. We have not yet entered into a sales agreement. The sale of these properties is anticipated to be completed within one year.
Legal Proceedings. In August 2004, one of PVR's lessees dislodged a boulder while repairing a surface mine access road. The boulder rolled down a hillside, damaging a residence and causing a fatality. On October 29, 2004, A&G Coal Corp., PVR's lessee, Penn Virginia Operating Co., LLC, PVR's wholly owned subsidiary, and PVR were named along with several other defendants in a lawsuit brought by the family of the deceased in the Circuit Court of Wise County, Virginia. The lawsuit is seeking $26.5 million in punitive and compensatory damages. While the ultimate result of the lawsuit cannot be predicted with certainty, based on the facts currently available to us, management believes that the case will not have a material adverse effect on our financial position, results of operations or cash flows.
Item 2. Management's Discussion and Analysis of Financial Conditions and Results of Operations
The following analysis of financial condition and results of operations of Penn Virginia Corporation and subsidiaries should be read in conjunction with the Consolidated Financial Statements and Notes thereto.
Overview
Penn Virginia Corporation ("Penn Virginia", "PVA", the "Company", "we" or "our") is an independent energy company that is engaged in two primary business segments. Our oil and gas segment explores for, develops, produces and sells crude oil, condensate and natural gas primarily in the eastern and Gulf Coast onshore areas of the United States. Our coal royalty and land management segment operates through our ownership in Penn Virginia Resource Partners, L.P. (the "Partnership" or "PVR"). Penn Virginia and PVR are both publicly traded on the New York Stock Exchange under the symbols PVA and PVR, respectively. Due to our control of the general partner of PVR, the financial results of the Partnership are included in our consolidated financial statements. However, PVR functions with a capital structure that is independent of the Company, consisting of its own debt instruments and publicly traded common units. The following diagram depicts our ownership of PVR:
Diagram 13
As a result of our ownership in the Partnership, we receive cash payments from PVR in the form of quarterly cash distributions. We received approximately $4.4 million and $12.9 million of cash distributions during the three months and nine months ended September 30, 2004, respectively. We received approximately $4.2 million and $12.6 million in the three months and nine months ended September 30, 2003, respectively. As part of our ownership of PVR's general partner, we also own the rights, referred to as incentive distribution rights, to receive an increasing percentage of quarterly distributions of available cash from operating surplus after certain levels of cash distributions have been achieved. As of September 30, 2004, these levels had not yet been achieved.
We are committed to increasing value to our shareholders by conducting a balanced program of investment in our two business segments. In the oil and gas segment, we expect to execute a program combining relatively low risk, moderate return development drilling in the Appalachian region of Virginia and West Virginia with higher risk, higher return exploration and development drilling in the onshore Gulf Coast, supplemented periodically with acquisitions. In addition to our continuing conventional development program, we are expanding our eastern presence by developing coalbed methane ("CBM") gas reserves in Appalachia. By employing horizontal drilling techniques, we expect to increase the value of the CBM reserves we own.
In the coal royalty and land management segment, PVR regularly evaluates acquisition opportunities that are accretive to cash available for distribution to PVR unitholders, of which we are the largest single unitholder. These opportunities include, but are not limited to, acquiring additional coal properties and reserves, acquiring or constructing assets for coal services which would provide a fee-based revenue stream, and acquiring mid-stream hydrocarbon-related transportation assets or other operating assets that would strategically fit within the Partnership.
Oil and gas segment capital expenditures for 2004 are expected to be between $125 million and $130 million. The increase in anticipated 2004 capital expenditures from our original capital expenditures budget of $98 million is primarily due to pipeline construction expenditures to support our increasing horizontal CBM production in Appalachia and increased expenditures to expand the Company's Cotton Valley program in east Texas and north Louisiana. Borrowings under our credit facility were $73 million out of $150 million available as of September 30, 2004, and we expect to fund our 2004 capital expenditures with a combination of internal cash flow and credit facility borrowings.
Coal-related capital expenditures in 2004 are expected to be less than $1.0 million on existing properties excluding the joint venture acquisition discussed in Note 13 to the Consolidated Financial Statements. As of September 30, 2004, PVR had borrowed $117.9 million under its debt facilities. We expect to fund the 2004 capital expenditures for PVR through a combination of internal cash flow and credit facility borrowings.
Critical Accounting Policies and Estimates
The process of preparing financial statements in accordance with accounting principles generally accepted in the United States of America requires the management of the Company to make estimates and judgments regarding certain items and transactions. It is possible that materially different amounts could be recorded if the actual results differ from these estimates and judgments. We consider the following to be the most critical accounting policies which involve the judgment of our management.
Reserves. The estimates of oil and gas reserves are the single most critical estimate included in our financial statements. There are many uncertainties inherent in estimating crude oil and natural gas reserve quantities including projecting the total quantities in place, future production rates and the timing of future development. In addition, reserve estimates of new discoveries are less precise than those of producing properties due to the lack of a production history. Accordingly, these estimates are subject to change as additional information becomes available.
Proved reserves are the estimated quantities of crude oil, condensate and natural gas that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed reserves are those reserves expected to be recovered through existing equipment and operating methods. Proved undeveloped reserves are those quantities that require additional capital investment through drilling or well recompletion techniques.
Reserve estimates become the basis for determining depletive write-off rates, recoverability of historical cost investments and the fair value of properties subject to potential impairments.
There are several factors which could change our estimates of oil and gas reserves, including a change in economic limits resulting from a significant change in product prices or production costs and the change in reservoir production rates from those assumed when the reserves were initially recorded. Estimates of future production and development costs are also subject to change due to factors such as energy costs and the inflation or deflation of oil field service costs. Additionally, we perform impairment tests pursuant to Statement of Financial Accounting Standards ("SFAS") No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets, when significant events occur, such as a market move to a lower price environment or a material revision to our reserve estimates.
14
Depreciation and depletion of oil and gas producing properties is determined by the units-of-production method and could change with revisions to estimated proved recoverable reserves.
Coal properties are depleted on an area-by-area basis at a rate based on the cost of the mineral properties and the number of tons of estimated proven and probable coal reserves contained therein. The Partnership's estimates of coal reserves are updated periodically and may result in adjustments to coal reserves and depletion rates that are recognized prospectively.
Oil and Gas Revenues. Oil and gas sales revenues are recognized when crude oil and natural gas volumes are produced and sold for our account. As a result of the numerous requirements necessary to gather information from purchasers or various measurement locations, calculate volumes produced, perform field and wellhead allocations and distribute and disburse funds to various working interest partners and royalty owners, the collection of revenues from oil and gas production may take up to 60 days following the month of production. Therefore, accruals for revenues and accounts receivable are made based on estimates of our share of production. Since the settlement process may take 30 to 60 days following the month of actual production, our financial results include estimates of production and revenues for the related time period. Any differences between the actual amounts ultimately received and the original estimates are recorded in the period they become finalized.
Coal Royalties. Coal royalty revenues are recognized on the basis of tons of coal sold by the Partnership's lessees and the corresponding revenues from those sales. Since PVR is not the mine operator, it does not have access to actual production and revenues information until approximately 30 days following the month of production. Therefore, the financial results of the Partnership include estimated revenues and accounts receivable for this 30-day period. Any differences between the actual amounts ultimately received and the original estimates are recorded in the period they become finalized.
Oil and Gas Properties. We use the successful efforts method to account for our oil and gas properties. Under this method, costs of acquiring and holding properties, costs of drilling successful exploration wells and development costs are capitalized. Annual lease rentals, exploration costs, geological, geophysical and seismic costs and exploratory dry-hole costs are expensed as incurred.
A portion of the carrying value of the Company's oil and gas properties is attributable to unproved properties. At September 30, 2004, the costs attributable to unproved properties were approximately $57.6 million. These costs are not currently being depreciated or depleted. As exploration work progresses and the reserves on these properties are proven, capitalized costs of the properties will be written off through depletion expense. If the exploration work is unsuccessful, the capitalized costs of the properties related to the unsuccessful work will be expensed. The timing of any write downs of these unproven properties, if warranted, depends upon the nature, timing and extent of future exploration and development activities and their results.
Asset Retirement Obligations. In accordance with SFAS No. 143, Accounting for Asset Retirement Obligations, we make estimates of the timing and future costs of plugging and abandoning wells. Estimated abandonment dates will be revised in the future based on changes to related economic lives, which vary with product prices and production costs. Estimated plugging costs may also be adjusted to reflect changing industry conditions. Our cash flows would not be affected until costs to plug and abandon were actually incurred.
15
Results of Operations
Selected Financial Data - Consolidated
| Three Months Ended September 30, | Nine Months Ended September 30, |
| 2004 | | 2003 | 2004 | | 2003 |
| (in thousands, except share data) | (in thousands, except share data) |
| | | | | | |
Revenues | $ 52,741 | | $ 42,021 | $ 162,936 | | $ 133,740 |
Expenses | $ 35,248 | | $ 29,265 | $ 97,424 | | $ 87,364 |
Operating income | $ 17,493 | | $ 12,756 | $ 65,512 | | $ 46,376 |
Net income | $ 6,434 | | $ 5,443 | $ 28,656 | | $ 22,291 |
Earnings per share, basic | $ 0.35 | | $ 0.30 | $ 1.57 | | $ 1.25 |
Earnings per share, diluted | $ 0.35 | | $ 0.30 | $ 1.55 | | $ 1.24 |
Cash flow provided by operating activities | $ 41,595 | | $ 22,935 | $ 100,194 | | $ 70,904 |
Included in net income for the nine months ended September 30, 2003, was $1.4 million, or $0.08 per diluted share, related to the adoption of SFAS No. 143.
Oil and Gas Segment
In our oil and gas segment, we explore for, develop and produce and sell crude oil, condensate and natural gas primarily in the Appalachian and Gulf Coast onshore areas of the United States. Our revenues, profitability and future rate of growth are highly dependent on the prevailing prices for oil and natural gas, which are affected by numerous factors that are generally beyond the Company's control. Crude oil prices are generally determined by global supply and demand. Natural gas prices are influenced by national and regional supply and demand. A substantial or extended decline in the prices of oil or natural gas could have a material adverse effect on our revenues, profitability and cash flow and could, under certain circumstances, result in an impairment of our oil and natural gas properties. Our future profitability and growth is also highly dependent on the results of our exploratory and development drilling programs.
16
Operations and Financial Summary - Oil and Gas Segment
The following table sets forth the oil and gas segment's revenues, operating expenses and operating statistics for the three months ended September 30, 2004, compared with the same period in 2003 (in thousands, except per unit amounts).
| | | | Three Months Ended September 30, |
| | | 2004 | | 2003 |
Production | | | Amount | | $ Per Unit * | | Amount | | $ Per Unit* |
Natural gas (MMcf) | | | 5,052 | | | | 4,728 | | |
Oil and condensate (MBbls) | | 97 | | | | 216 | | |
Total equivalent production (MMcfe) | 5,634 | | | | 6,024 | | |
| | | | |
Revenues | | | | | | | | | |
Natural gas | | | | | | | | |
Revenue received for production | $ 30,027 | | $ 5.95 | | $ 23,919 | | $ 5.06 |
Effect of hedging activities | (497) | | (0.10) | | (626) | | (0.13) |
| Net revenue realized | | | | | | | | |
Crude oil and condensate | | | | | | | | |
Revenue received for production | 4,066 | | 41.92 | | 5,470 | | 25.32 |
Effect of hedging activities | (715) | | (7.37) | | (98) | | (0.45) |
Net revenue realized | 3,351 | | 34.55 | | 5,372 | | 24.87 |
Other income | | | 134 | | | | 370 | | |
Total revenues | 33,015 | | 5.86 | | 29,035 | | 4.82 |
| | | | | | | | | | |
Expenses | | | | | | | | |
Lease operating expenses | | 3,309 | | 0.59 | | 3,195 | | 0.53 |
Exploration expenses | | 7,508 | | 1.33 | | 3,747 | | 0.62 |
Taxes other than income | | 2,349 | | 0.42 | | 2,364 | | 0.39 |
General and administrative | | 2,110 | | 0.37 | | 2,105 | | 0.35 |
Depreciation and depletion | | 8,307 | | 1.47 | | 8,572 | | 1.42 |
Total expenses | | 23,583 | | 4.18 | | 19,983 | | 3.31 |
| | | | | | | |
Income before income taxes | $ 9,432 | | $ 1.68 | | $ 9,052 | | $ 1.51 |
| | | | | | | | | | | | | | | | | | | | |
*Natural gas revenues are shown per Mcf, oil and condensate revenues are shown per Bbl, and all other amounts are shown per Mcfe.
Production. During the third quarter of 2004, oil and gas production was 5.6 billion cubic feet equivalent (Bcfe), a seven percent decrease from 6.0 Bcfe produced in the third quarter of 2003. The decrease was primarily due to pipeline curtailments by two of the Company's natural gas transporters in the Appalachian production areas and delays in the Gulf Coast drilling program. Average daily oil and gas production decreased slightly to 61.2 million cubic feet equivalent (MMcfe) in the third quarter of 2004 compared to 65.5 MMcfe in the third quarter of 2003.
Revenues. Oil and gas total revenues increased $4.0 million to $33.0 million in the third quarter of 2004 from $29.0 million in the third quarter of 2003.
Increased crude oil and natural gas realized prices accounted for most of the $4.0 million increase in total oil and gas revenues from the third quarter of 2003 to the third quarter of 2004. As stated previously, crude oil and natural gas production decreased by seven percent due to pipeline curtailments and delays in the Gulf Coast drilling program.
Approximately 90 percent of our third quarter 2004 production was natural gas, for which the average realized price received was $5.85 per million cubic feet (Mcf) compared with $4.93 per Mcf in the third quarter of 2003, a 19 percent increase. The average realized oil price received was $34.55 per barrel for the third quarter of 2004, up 39 percent from $24.87 per barrel in the third quarter of 2003.
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Gains and losses from hedging activities are included in revenues when the hedged production occurs. For the three months ended September 30, 2004, approximately 38 percent of our natural gas production was hedged, primarily using costless collars, at an average floor price of $4.08 per MMbtu and ceiling price of $6.02 per MMbtu.
Since actual cash market prices exceeded the average ceiling price of the costless collars, our price on the hedged natural gas production was limited to the ceiling price of the costless collar, and we recognized a loss on settled natural gas hedges of $0.5 million in the third quarter of 2004 compared to a loss of $0.6 million in the same quarter of 2003.
Approximately 46 percent of our third quarter 2004 crude oil production was hedged using fixed price swaps with an average price of $30.36 per barrel. Crude oil cash market prices were significantly higher than the swap price, resulting in a loss on settled crude oil hedges of $0.7 million in the third quarter of 2004 compared to a loss of less than $0.1 million in the same quarter of 2003.
See Note 4, "Hedging Activities," in the Notes to the Consolidated Financial Statements for details of costless collars and fixed price swaps.
Operating expenses. The oil and gas segment's aggregate operating costs and expenses for the third quarter of 2004 were $23.6 million, compared with $20.0 million for the same period in 2003, an increase of $3.6 million, or 18 percent. The increase in operating costs and expenses primarily related to higher exploration expenses, partially offset by increased depreciation, depletion and amortization.
Exploration expenses for the three months ended September 30, 2004 and 2003, consisted of the following (in thousands):
| Three Months Ended September 30, |
|
| 2004 | | 2003 |
| | |
Unproved leasehold write-offs | $ 1,795 | | $ - |
Seismic | 552 | | 1,066 |
Dry hole costs | 4,881 | | 2,490 |
Other | 280 | | 191 |
Total | $ 7,508 | | $ 3,747 |
Exploration expenses increased to $7.5 million in the third quarter of 2004 from $3.7 million in the third quarter of 2003, primarily due to higher dry hole costs resulting from the drilling of three unsuccessful exploratory wells in the Gulf Coast region and the related write-off of unproved property. These increased costs were partially offset by lower seismic data costs.
Oil and gas depreciation, depletion and amortization ("DD&A") decreased from $8.6 million in the third quarter of 2003 to $8.3 million in the third quarter of 2004, primarily due to lower production volumes, partially offset by higher average depletion rates. The average DD&A rate increased to $1.47 per Mcfe produced in third quarter 2004 from $1.42 per Mcfe produced in 2003's third quarter due to a greater percentage of production coming from relatively higher cost horizontal CBM and Gulf Coast wells.
18
The following table sets forth the oil and gas segment's revenues, operating expenses and operating statistics for the nine months ended September 30, 2004, compared with the same period in 2003 (in thousands, except per unit amounts).
| | | Nine Months Ended September 30, | |
| | | 2004 | | 2003 | |
Production | | | Amount | | $ Per Unit * | | Amount | | $ Per Unit* | |
Natural gas (MMcf) | | | 16,105 | | | | 14,516 | | | |
Oil and condensate (MBbls) | | 307 | | | | 526 | | | |
Total equivalent production (MMcfe) | 17,947 | | | | 17,672 | | | |
| | | | | |
Revenues | | | | | | | | | | |
Natural gas | | | | | | | | |
Revenue received for production | $ 98,198 | | $ 6.10 | | $ 84,940 | | $ 5.86 |
Effect of hedging activities | (2,260) | | (0.14) | | (5,743) | | (0.40) |
Net revenue realized | 95,938 | | 5.96 | | 79,197 | | 5.46 |
Crude oil and condensate | | | | | | | | |
Revenue received for production | 11,301 | | 36.81 | | 14,472 | | 27.51 |
| Effect of hedging activities | (1,432) | | (4.66) | | (473) | | (0.90) |
Net revenue realized | 9,869 | | 32.15 | | 13,999 | | 26.61 |
Other income | | | | | | | 595 | | | |
Total revenues | 106,014 | | 5.91 | | | | 5.31 | |
| | | | | | | | | | | |
Expenses | | | | | | | | | |
Lease operating expenses | | 9,525 | | 0.53 | | 9,094 | | 0.51 | |
Exploration expenses | | 14,903 | | 0.83 | | 11,648 | | 0.66 | |
Taxes other than income | | 7,308 | | 0.41 | | 7,446 | | 0.42 | |
General and administrative | | 5,727 | | 0.32 | | 5,624 | | 0.32 | |
Depreciation and depletion | | 26,015 | | 1.45 | | 24,493 | | 1.39 | |
Total expenses | | 63,478 | | 3.54 | | 58,305 | | 3.30 | |
| | | | | | | | |
Income before income taxes | | | $ 2.37 | | $ 35,486 | | $ 2.01 | |
| | | | | | | | | | | | | | | | | | | | | | |
*Natural gas revenues are shown per Mcf, oil and condensate revenues are shown per Bbl, and all other amounts are shown per Mcfe.
Production. In the first three quarters of 2004, oil and gas production was 17.9 Bcfe, an increase of one percent over the 17.7 Bcfe reported for the same period in 2003. The increase in year-to-date production was primarily due to new drilling in the Company's Selma Chalk fields in Mississippi and its horizontal CBM drilling project in Appalachia. Considering the impact of Gulf Coast drilling program delays and the drilling of three unsuccessful exploratory wells in the Gulf Coast region, the Company now expects full-year 2004 production to range from 24.5 Bcfe to 25.2 Bcfe.
Revenues. Oil and gas total revenues increased $12.2 million to $106.0 million for the nine months ended September 30, 2004, from $93.8 million in the same period of 2003. The higher revenues resulted from increased prices realized for natural gas and crude oil along with increased natural gas production.
Approximately 90 percent of our production for the nine months ended September 30, 2004, was natural gas, for which the average realized price received was $5.96 per Mcf compared with $5.46 per Mcf in the same period of 2003, a nine percent increase. The average realized oil price received was $32.15 per barrel for the nine months ended September 30, 2004, up 21 percent from $26.61 per barrel in the same period of 2003.
19
Gains and losses from hedging activities are included in revenues when the hedged production occurs. For the nine months ended September 30, 2004, approximately 38 percent of our natural gas was hedged, primarily using costless collars, at an average floor price of $3.86 per MMbtu and ceiling price of $5.86 per MMbtu. During the same period of 2004, we hedged approximately 44 percent of our crude oil production using fixed price swaps with an average price of $29.56 per barrel. We recognized a loss on settled hedging activities of $3.7 million for the nine months ended September 30, 2004, compared with a loss of $6.2 million in the same period of 2003.
See Note 4, "Hedging Activities," in the Notes to the Consolidated Financial Statements for details of costless collars and fixed price swaps.
Operating expenses. The oil and gas segment's aggregate operating costs and expenses for the nine months ended September 30, 2004, were $63.5 million, compared with $58.3 million for the same period in 2003, an increase of $5.2 million, or nine percent. The increase in operating costs and expenses primarily related to higher lease operating expenses, exploration expenses and DD&A.
Lease operating expenses increased by $0.4 million, or four percent, to $9.5 million for the first nine months of 2004 from $9.1 million for the first nine months of 2003 primarily due to higher compressor rental costs and higher costs associated with non-operated joint ventures. These increases were partially offset by a decrease in well workover costs.
Exploration expenses for the nine months ended September 30, 2004 and 2003, consisted of the following (in thousands):
| Nine Months Ended September 30, |
| 2004 | | 2003 |
| | |
Unproved leasehold write-offs | $ 4,002 | | $ 92 |
Seismic | 5,128 | | 6,962 |
Dry hole costs | 5,320 | | 4,007 |
Other | 453 | | 587 |
Total | $ 14,903 | | $ 11,648 |
Exploration expenses for the first nine months of 2004 increased to $14.9 million from $11.6 million in the same period of 2003 primarily due to increased unproved leasehold write-offs related to expiring lease options in south Texas and increased dry hole costs. We recognized dry hole expense on six wells for the nine months ended September 30, 2004, compared to four wells for the nine months ended September 30, 2003. These increases were partially offset by lower seismic data costs.
Oil and gas DD&A increased from $24.5 million for the nine months ended September 30, 2003, to $26.0 million in the same period of 2004, primarily due to higher production as discussed previously, and an increase in the weighted average DD&A rate from $1.39 per Mcfe for the nine months ended September 30, 2003, to $1.45 per Mcfe in the same period of 2004. The increase in the weighted average DD&A rate was the result of a greater percentage of production coming from relatively higher cost horizontal CBM and Gulf Coast wells.
Coal Royalty and Land Management Segment (PVR)
The coal royalty and land management segment includes PVR's coal reserves, timber assets and other land assets. The assets, liabilities and earnings of PVR are fully consolidated in our financial statements, with the public unitholders' interest reflected as a minority interest.
The Partnership enters into leases with various third-party operators giving them the right to mine coal reserves on the Partnership's properties in exchange for royalty payments. Approximately 78 percent of the Partnership's coal royalty revenues for the first three quarters of 2004 and 69 percent of its coal royalty revenues for the first three quarters of 2003 were based on the higher of a percentage of the gross sales price or a fixed price per ton of coal sold, with pre-established minimum monthly or annual payments. The balance of the Partnership's coal royalty revenues for the respective periods was based on fixed royalty rates which escalate annually, also with pre-established monthly minimums. In addition to coal royalty revenues, the Partnership generates coal service revenues from fees charged to lessees for the use of coal preparation and transportation facilities. The Partnership also generates revenues from the sale of timber on its properties.
20
The coal royalty stream is impacted by several factors, which PVR generally cannot control. The number of tons mined annually is determined by an operator's mining efficiency, labor availability, geologic conditions, access to capital, ability to market coal and ability to arrange reliable transportation to the end-user. The possibility exists that new legislation or regulations may be adopted which may have a significant impact on the mining operations of the Partnership's lessees or their customers' ability to use coal and may require PVR, its lessees or its lessees' customers to change operations significantly or incur substantial costs.
Operations and Financial Summary - Coal Royalty and Land Management Segment
The following table sets forth PVR's revenues, operating expenses and operating statistics for the three months ended September 30, 2004, compared with the same period in 2003.
| Three Months
Ended September 30, |
| 2004 | 2003 |
| (in thousands, except prices) |
Revenues | | |
Coal royalties | $ 18,018 | $ 11,960 |
Coal services | 888 | 484 |
Timber | 204 | 80 |
| Other | 287 | 288 |
Total revenues | 19,397 | 12,812 |
Operating costs and expenses | | |
Operating | 1,777 | 753 |
Taxes other than income | 239 | 389 |
General and administrative | 2,077 | 1,661 |
Depreciation, depletion and amortization | 4,764 | 3,659 |
Total operating costs and expenses | 8,857 | 6,462 |
| | | |
Operating income | 10,540 | 6,350 |
| Interest expense | (1,658) | (1,380) |
| Interest income | 265 | |
| | | |
Income before income taxes and minority interest | 9,147 | 5,269 |
| Minority interest | 5,073 | 2,936 |
| Income before income taxes | $ 4,074 | $ 2,333 |
| | | |
Operating Statistics | | |
Royalty coal tons produced by lessees (tons in thousands) | 7,971 | 6,229 |
Average royalty per ton | $ 2.26 | $ 1.92 |
| | | |
Revenues. PVR's revenues in the third quarter of 2004 were $19.4 million compared with $12.8 million for the same period in 2003, an increase of $6.6 million, or 52 percent. The increase in revenues primarily related to increased coal royalties received from PVR's lessees.
Coal royalty revenues for the three months ended September 30, 2004, were $18.0 million compared with $12.0 million for the same period in 2003, an increase of $6.0 million, or 50 percent. Production by PVR's lessees increased by 1.8 million tons, or 29 percent, to 8.0 million tons in the third quarter of 2004 from 6.2 million tons in the third quarter of 2003. A significant part of this increase was attributed to increased production from a longwall mining operation located on PVR's Coal River property. Average royalties per ton increased to $2.26 in the third quarter of 2004 from $1.92 in the comparable 2003 period, primarily due to stronger market conditions for coal and the resulting higher coal prices.
Coal services revenues increased 80 percent to $0.9 million in the third quarter of 2004 from $0.5 million in the third quarter of 2003. The increase was primarily the result of start-up operations at two of PVR's coal loading facilities in July 2003 and February 2004.
21
Other revenues includes $0.2 million of equity earnings in the third quarter of 2004 from the coal handling joint venture acquired as of July 1, 2004, as discussed in Note 13 to the Consolidated Financial Statements. Minimum rentals of $0.2 million are included in other revenues for the third quarter of 2003. Less than $0.1 million in minimum rental income was recognized in the third quarter of 2004 as all lessees met or exceeded their minimum obligations during the period.
Operating Costs and Expenses. The Partnership's aggregate operating costs and expenses for the third quarter of 2004 were $8.9 million, compared with $6.5 million for the same period in 2003, an increase of $2.4 million, or 37 percent. The increase in operating costs and expenses primarily related to increases in operating expenses and DD&A.
Operating expenses, which include royalty expenses paid on leased coal properties and other operating expenses, increased to $1.8 million in the third quarter of 2004 from $0.8 million in the third quarter of 2003. This increase was primarily due to higher royalty expense, which increased by $1.0 million to $1.5 million in the third quarter of 2004 from $0.5 million in the third quarter of 2003. This increase was the result of higher production by lessees on subleased properties, which increased to 1.0 million tons in the third quarter of 2004 from 0.3 million tons in the third quarter of 2003.
DD&A for the three months ended September 30, 2004, was $4.8 million compared with $3.7 million for the same period of 2003, an increase of $1.1 million, or 30 percent. This increase was the result of increased production by several of PVR's lessees over the comparable periods and depreciation on a coal loading facility which began start-up operations in February 2004.
Interest Expense. Interest expense was $1.7 million for the three months ended September 30, 2004, compared with $1.4 million for the same period in 2003, an increase of $0.3 million, or 21 percent. The increase was primarily due to additional borrowings of $28.5 million on PVR's revolving credit facility in the third quarter of 2004 for its investment in a coal handling joint venture.
Minority Interest. Minority interest was $5.1 million for the three months ended September 30, 2004, compared with $2.9 million for the same period in 2003, an increase of $2.2 million, or 76 percent. The increase was due to the increase in the Partnership's net income for the third quarter of 2004 compared with the third quarter of 2003.
22
The following table sets forth PVR's revenues, operating expenses and operating statistics for the nine months ended September 30, 2004, compared with the same period in 2003.
| Nine Months
Ended September 30, |
| 2004 | 2003 |
| (in thousands, except prices) |
Revenues | | |
Coal royalties | $ 52,395 | $ 35,658 |
Coal services | 2,614 | 1,523 |
Timber | 499 | 829 |
Other | 584 | 1,324 |
Total revenues | 56,092 | 39,334 |
| | |
Operating costs and expenses | | |
Operating | 5,574 | 2,488 |
Taxes other than income | 753 | 978 |
General and administrative | 6,036 | 5,199 |
Depreciation, depletion and amortization | 14,385 | 12,027 |
Total operating costs and expenses | 26,748 | 20,692 |
| | | |
| Operating income | 29,344 | 18,642 |
| | | |
| Interest expense | (4,390) | (3,536) |
| Interest income | 789 | 943 |
| | | |
Income before minority interest, income taxes and
cumulative effect of change in accounting principle | 25,743 | 16,049 |
Minority interest | 14,271 | 8,778 |
Cumulative effect of change in accounting principle | - | 107 |
Income before income taxes | $ 11,472 | $ 7,164 |
Operating Statistics | | |
Royalty coal tons produced by lessees (tons in thousands) | 23,865 | 19,252 |
Average royalty per ton | $ 2.20 | $ 1.85 |
Revenues. PVR's revenues in the first three quarters of 2004 were $56.1 million compared with $39.3 million for the same period in 2003, an increase of $16.8 million, or 43 percent. The increase in revenues primarily related to increased coal royalties received from lessees.
Coal royalty revenues for the nine months ended September 30, 2004, were $52.4 million compared with $35.7 million for the same period in 2003, an increase of $16.7 million, or 47 percent. Production by PVR's lessees increased by 4.6 million tons, or 24 percent, to 23.9 million tons in the first three quarters of 2004 from 19.3 million tons in the first three quarters of 2003. A significant part of this increase was attributable to increased production from a longwall mining operation located on PVR's Coal River property. Average royalties per ton increased to $2.20 in the first three quarters of 2004 from $1.85 in the comparable 2003 period. The increase in the average royalties per ton was primarily due to stronger market conditions for coal and the resulting higher coal prices.
Coal services revenues increased 73 percent to $2.6 million in the first three quarters of 2004 from $1.5 million in the first three quarters of 2003, due primarily to the start-up of two of PVR's coal loading facilities in July 2003 and February 2004.
Other revenues decreased to $0.6 million in the first nine months of 2004 from $1.3 million in the same period of 2003, primarily due to a decrease in minimum rental revenues. Almost all of PVR's lessees met their minimum production obligations during the first nine months of 2004, resulting in less than $0.1 million in minimum rentals being recorded during the first nine months of 2004, compared to $1.0 million being recognized in the first nine months of 2003. The decrease in minimum rental revenues is partially offset by $0.2 million of equity earnings in the third quarter of 2004 from the coal handling joint venture acquired as of July 1, 2004, as discussed in Note 13 to the Consolidated Financial Statements.
23
Operating Costs and Expenses. The Partnership's aggregate operating costs and expenses for the first three quarters of 2004 were $26.7 million, compared with $20.7 million for the same period in 2003, an increase of $6.0 million, or 29 percent. The increase in operating costs and expenses primarily related to increases in operating expenses, general and administrative expenses and DD&A.
Operating expenses, which include royalty expenses paid on leased coal properties and other operating expenses, more than doubled to $5.6 million in the first three quarters of 2004 from $2.5 million in the same period of 2003. This increase was primarily due to an increase in royalty expenses, offset in part by a decrease in other operating expenses.
Royalty expenses were $4.9 million for the nine months ended September 30, 2004, compared with $1.3 million for the nine months ended September 30, 2003, an increase of $3.6 million. This increase was the result of an increase in production by lessees on two subleased properties. Production on these subleased properties increased 2.6 million tons to 3.4 million tons in the first three quarters of 2004 from 0.8 million tons in the first three quarters of 2003.
Other operating expenses decreased 42 percent to $0.7 million in the first three quarters of 2004 compared with $1.2 million in the same period of 2003. The decrease was due to the assumption by a new lessee of costs incurred after May 2003 to maintain idled mines on its West Coal River property, which is part of the Coal River property. PVR paid these costs through May 2003.
General and administrative expenses increased $0.8 million, or 15 percent, to $6.0 million in the first three quarters of 2004, from $5.2 million in the same period of 2003. Approximately $0.2 million was attributable to costs related to a secondary public offering for the sale of common units held by an affiliate of Peabody Energy Corporation. The remainder is primarily attributable to increased consulting fees used to evaluate acquisition opportunities and increased payroll costs allocated to the Partnership by the general partner.
DD&A for the nine months ended September 30, 2004, was $14.4 million compared with $12.0 million for the same period of 2003, an increase of $2.4 million or 20 percent. This increase was a result of increased production by several of PVR's lessees over the comparable periods and depreciation on its two coal loading facilities which began start-up operations in July 2003 and February 2004.
Interest Expense. Interest expense was $4.4 million for the nine months ended September 30, 2004, compared with $3.5 million for the same period in 2003, an increase of $0.9 million, or 26 percent. The increase was primarily due to the closing in March 2003 of a private placement of $90 million ten-year senior unsecured notes (the "Notes"), which bear interest at a fixed rate of 5.77 percent. Prior to the private placement, the $90 million was included on PVR's revolving credit facility, which bears interest at a relatively lower Eurodollar rate plus an applicable margin which ranges from 1.25 to 2.25 percent. Also, PVR borrowed an additional $28.5 million on its revolving credit facility in the third quarter of 2004 for its investment in a coal handling joint venture.
Minority Interest. Minority interest was $14.3 million for the nine months ended September 30, 2004, compared with $8.8 million for the same period in 2003, an increase of $5.5 million, or 63 percent. The increase was due to the increase in the Partnership's net income for the first three quarters of 2004 compared with the first three quarters of 2003.
Corporate and Other Segment
The corporate and other segment primarily consists of oversight and administrative functions.
24
Operations and Financial Summary - Corporate and Other Segment
The following table sets forth the corporate and other segment's revenues, operating expenses and operating statistics for the three months ended September 30, 2004, compared with the same period in 2003.
| | Three Months Ended September 30, |
| 2004 | | 2003 |
| (in thousands) |
Revenues | | | |
Other | $ 329 | | $ 174 |
Total revenues | 329 | | 174 |
| | | |
Expenses | | | |
Lease operating | 150 | | 149 |
Taxes other than income | 94 | | 101 |
General and administrative | 2,456 | | 2,536 |
Depreciation, depletion and amortization | 108 | | 34 |
Total expenses | 2,808 | | 2,820 |
| | | |
Operating loss | (2,479) | | (2,646) |
| | | |
Interest expense | (61) | | - |
Interest income and other | 9 | | 2 |
| | | |
Loss before income taxes | $ (2,531) | | $ (2,644) |
| | | | | |
Other revenues increased to $0.3 million in the third quarter of 2004 from $0.2 million in the third quarter of 2003 due to increased rail rental income.
General and administrative (G&A) expenses of $2.5 million in third quarter 2004 were consistent with the third quarter of 2003. A general increase in staffing levels and higher insurance premiums were offset by the absence in 2004 of consulting and advisory fees incurred in 2003 related to the consideration of various shareholder proposals.
All direct credit facility interest costs were capitalized during the third quarters of 2004 and 2003 because the borrowings funded the preparation of unproved properties for their intended use. We capitalized interest costs amounting to $0.5 million in each of the third quarters of 2004 and 2003. Interest costs which were expensed in the corporate and other segment related to the amortization of debt issuance costs.
25
The following table sets forth the corporate and other segment's revenues, operating expenses and operating statistics for the nine months ended September 30, 2004, compared with the same period in 2003.
| | Nine Months Ended September 30, | |
| 2004 | | 2003 |
| (in thousands) |
Revenues | | | |
Other | $ 830 | | $ 615 |
Total revenues | 830 | | 615 |
| | | |
Expenses | | | |
Lease operating | 450 | | 449 |
Taxes other than income | 115 | | 498 |
General and administrative | 6,311 | | 7,317 |
Depreciation, depletion and amortization | 322 | | 103 |
Total expenses | 7,198 | | 8,367 | |
| | | |
Operating loss | (6,368) | | (7,752) |
| | | |
Interest expense | (183) | | (301) |
Interest income and other | | | |
Loss before income taxes | | | |
| | | | | | |
Other revenues increased to $0.8 million in the first three quarters of 2004, from $0.6 million in the first three quarters of 2003, due to increased rail rental income.
Taxes other than income decreased by $0.4 million to $0.1 million for the nine months ended September 30, 2004, from $0.5 million for the nine months ended September 30, 2003, due to a decrease in franchise taxes.
G&A expenses decreased from $7.3 million for the nine months ended September 30, 2003, to $6.3 million in the same period of 2004. This $1.0 million decrease was primarily attributable to the absence in 2004 of consulting and advisory fees incurred in 2003 related to the consideration of various shareholder proposals, offset in part by a general increase in staffing levels and higher insurance premiums.
All direct credit facility interest costs were capitalized during the nine months ended September 30, 2004 and 2003, because the borrowings funded the preparation of unproved properties for their intended use. We capitalized interest costs amounting to $1.4 million in the nine months ended September 30, 2004 and 2003, respectively. Interest costs which were expensed in the corporate and other segment related to the amortization of debt issuance costs.
Capital Resources and Liquidity
The Company and PVR have separate credit facilities, and neither entity guarantees the debt of the other. Since PVR's initial public offering in October 2001, with the exception of cash distributions received by the Company from PVR, the cash needs of each entity have been met independently with a combination of operating cash flows, credit facility borrowings and, in the case of PVR's December 2002 acquisition of coal reserves from affiliates of Peabody Energy Corporation ("Peabody"), issuance of new partnership units. We expect that our cash needs and the cash needs of PVR will continue to be met independently of each other with a combination of these funding sources. Following are summarized cash flow statements for 2004 and 2003 consolidating the oil and gas (and corporate) and the coal royalty and land management (PVR) segments.
26
For the nine months ended September 30, 2004 | | Oil and Gas, Corporate and Other Segments | | Coal Royalty and Land Mgmt
(PVR) | | |
(amounts in thousands) | | | | |
| | | | Consolidated |
Cash flows from operating activities | | | | | | |
Net income | | $ 2,913 | | $ 25,743 | | $ 28,656 |
Adjustments to reconcile net income to net cash | | | | | | |
provided by operating activities (summarized) | | 65,447 | | 14,561 | | 80,008 |
Net change in operating assets and liabilities | | (6,889) | | (1,581) | | (8,470) |
Net cash provided by operating activities | | 61,471 | | 38,723 | | 100,194 |
| | | | | | |
Cash flows from investing activities | | | | | | |
Additions to property and equipment | | (86,992) | | (939) | | (87,931) |
Equity investments | | - | | (28,442) | | (28,442) |
Other | | 838 | | 585 | | 1,423 |
Net cash used in investing activities | | (86,154) | | (28,796) | | (114,950) |
| | | | | | |
Cash flows from financing activities | | | | | | |
PVA dividends paid | | (6,176) | | - | | (6,176) |
PVR distributions received (paid) | | 12,894 | | (29,229) | | (16,335) |
PVA debt proceeds | | 25,000 | | - | | 25,000 |
PVA debt repayments | | (16,000) | | - | | (16,000) |
PVR debt proceeds | | - | | 28,500 | | 28,500 |
PVR debt repayments | | - | | (2,500) | | (2,500) |
Issuance of stock and other | | 3,843 | | - | | 3,843 |
Net cash provided by (used in) financing activities | | 19,561 | | (3,229) | | 16,332 |
| | | | | | |
Net increase (decrease) in cash and cash equivalents | | (5,122) | | 6,698 | | 1,576 |
Cash and cash equivalents - beginning of period | | | | | | |
Cash and cash equivalents - end of period | | | | | | |
| | | | | | |
For the nine months ended September 30, 2003 | | Oil and Gas,
Corporate and Other Segments | | Coal Royalty and Land Mgmt
(PVR) | | |
(amounts in thousands) | | | | |
| | | | Consolidated |
Cash flows from operating activities | | | | | | |
Net income | | $ 6,349 | | $ 15,942 | | $ 22,291 |
Adjustments to reconcile net income to net cash | | | | | | |
provided by operating activities (summarized) | | 47,470 | | 12,524 | | 59,994 |
Net change in operating assets and liabilities | | (11,004) | | (377) | | (11,381) |
Net cash provided by operating activities | | 42,815 | | 28,089 | | 70,904 |
| | | | | | |
Cash flows from investing activities | | | | | | |
Additions to property and equipment | | (94,646) | | (3,437) | | (98,083) |
Other | | 116 | | 431 | | 547 |
Net cash used in investing activities | | (94,530) | | (3,006) | | (97,536) |
| | | | | | |
Cash flows from financing activities | | | | | | |
PVA dividends paid | | (6,061) | | - | | (6,061) |
PVR distributions received/(paid) | | 12,579 | | (27,145) | | (14,566) |
PVA debt proceeds | | 44,399 | | - | | 44,399 |
PVA debt repayments | | (2,451) | | - | | (2,451) |
PVR debt proceeds | | - | | 90,000 | | 90,000 |
PVR debt repayments | | - | | (88,387) | | (88,387) |
Issuance of stock and other | | 1,362 | | (1,118) | | 244 |
Net cash provided by (used in) financing activities | | 49,828 | | (26,650) | | 23,178 |
| | | | | | |
Net decrease in cash and cash equivalents | | (1,887) | | (1,567) | | (3,454) |
| Cash and cash equivalents - beginning of period | | 3,721 | | 9,620 | | 13,341 |
| Cash and cash equivalents - end of period | | $ 1,834 | | $ 8,053 | | $ 9,887 |
| | | | | | |
27
Except where noted, the following discussion of cash flows and contractual obligations relates to consolidated results of the Company.
Cash Flows from Operating Activities
Consolidated net cash provided from operating activities was $100.2 million for the nine months ended September 30, 2004, compared with $70.9 million for the same period in 2003. The oil and gas and corporate segment's net cash provided by operations was $61.5 million for the nine months ended September 30, 2004, compared with $42.8 million for the same period in 2003. This increase was primarily driven by an increase in natural gas revenues as a result of higher prices and increased production from new drilling. Cash in excess of working capital needs was used to help fund oil and gas capital expenditures in 2004. Cash provided by operations of the coal royalty and land management segment was $38.7 million for the nine months ended September 30, 2004, compared with $28.1 million in the same period in 2003. The increase was due to both increased production and higher average royalty rates realized.
Cash Flows from Investing Activities
Consolidated net cash used in investing activities was $115.0 million for the nine months ended September 30, 2004, compared with $97.5 million during the same period in 2003. During these periods, we used cash primarily for capital expenditures for oil and gas development and exploration activities and acquisitions of oil and gas properties. PVR acquired an interest in a coal handling joint venture as of July 1, 2004 for $28.4 million.
Capital expenditures totaled $123.6 million for the nine months ended September 30, 2004, compared with $110.9 million during the same period in 2003. The following table sets forth capital expenditures by segment, made during the periods indicated.
| |
| Nine Months Ended September 30, |
| 2004 | | 2003 |
| (in thousands) |
Oil and gas | | | |
Development drilling | $ 55,893 | | $ 45,347 |
Exploratory drilling | 11,995 | | 8,871 |
Lease acquisitions * | 8,293 | | 41,739 |
Field projects | 12,347 | | 3,433 |
Seismic and other | 5,552 | | 7,505 |
Total | 94,080 | | 106,895 |
| | | |
Coal royalty and land management (PVR) | | | |
Acquisition of coal handling joint venture | 28,442 | | - |
Lease acquisitions ** | 105 | | 1,361 |
Support equipment and facilities | 834 | | 2,076 |
Total | 29,381 | | 3,437 |
| | | |
Other | 105 | | 552 |
| Total capital expenditures | | | $ 110,884 |
* Includes $33.5 million to acquire proved oil and gas properties in south Texas in the first quarter of 2003.
** Excludes noncash expenditure of $1.1 million to acquire additional reserves on PVR's northern Appalachia properties in exchange for 51,000 units,
which had been held in escrow since December 2002 and were released to affiliates of Peabody Energy Corporation in the first quarter of 2004.
We are committed to expanding our oil and natural gas operations over the next several years through a combination of exploration, development and acquisition of new properties. We have a portfolio of assets which balances relatively low risk, moderate return development projects in Appalachia and Mississippi with relatively moderate risk, potentially higher return development projects and exploration prospects in south and east Texas and south Louisiana.
Oil and gas segment capital expenditures for 2004 are expected to be between $125 million and $130 million. The increase in anticipated 2004 capital expenditures from our original capital expenditures budget of $98 million is primarily due to pipeline construction expenditures to support our increasing horizontal CBM production in Appalachia and increased expenditures to expand the Company's Cotton Valley program in east Texas and north Louisiana. We continually review drilling and other capital expenditure plans and may continue to change these amounts based on industry conditions and the availability of capital. We believe our cash flow from operations and sources of debt financing are sufficient to fund our 2004 planned capital expenditures program as revised.
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Cash Flows from Financing Activities
Consolidated net cash provided by financing activities was $16.3 million for the nine months ended September 30, 2004, compared with $23.2 million for the same period in 2003. During the nine months ended September 30, 2004, we borrowed $9.0 million on our credit facility, net of repayments. Credit facility borrowings, net of repayments, provided approximately $41.9 million of cash in the nine months ended September 30, 2003, and were used primarily to fund a south Texas acquisition. In the nine months ended September 30, 2004 and 2003, we received $12.9 million and $12.6 million of cash distributions, respectively, from PVR. These distributions were primarily used for capital expenditure needs.
In October 2004, PVR announced a $0.54 per unit quarterly distribution payable November 3, 2004, to unitholders of record on November 12, 2004.
As of September 30, 2004, we had outstanding borrowings of $73 million under our revolving credit facility which has an initial commitment of $150 million and which can be expanded at our option to our current approved borrowing base of $200 million.
We have a five million dollar line of credit, which had no borrowings against it as of September 30, 2004. The line of credit is effective through June 2005 and is renewable annually. The agreement was renewed in June 2004.
The financial covenants in our credit agreements require us to maintain certain levels of debt-to-earnings and dividend limitation restrictions. We are currently in compliance with all of our covenants.
As of September 30, 2004, PVR had outstanding borrowings of $117.9 million, consisting of $30.0 million borrowed under its revolving credit facility and $88.5 million of the Notes, partially offset by $0.6 million fair value of the interest rate swap described below. The current portion of the Notes as of September 30, 2004, was $4.8 million.
In connection with the Notes, PVR entered into an interest rate swap agreement with a notional amount of $29.5 million, to effectively convert the interest rate on one-third of the Notes from a fixed rate to a floating rate. This swap is designated as a fair value hedge and has been reflected as a decrease in long-term debt of $0.6 million as of September 30, 2004, with a corresponding increase in long-term hedging liabilities. Under the terms of the interest rate swap agreement, the counterparty pays the Partnership a fixed annual rate of 5.77 percent on a total notional amount of $29.5 million, and the Partnership pays the counterparty a variable rate equal to the floating interest rate which is determined semi-annually and is based on the six month London Interbank Offering Rate ("LIBOR") plus 2.36 percent.
Future Capital Needs and Commitments. For the remainder of 2004, we anticipate making total capital expenditures, excluding future acquisitions, of approximately $31 million to $36 million. These expenditures are expected to be made primarily in our oil and gas segment and are expected to be funded primarily by operating cash flow. Additional funding will be provided as needed from our credit facility, under which we had $77 million of borrowing capacity as of September 30, 2004. The credit facility can be expanded at our option to provide an additional $50 million of borrowing capacity.
See Note 6, "Commitments and Contingencies," in the Notes to Consolidated Financial Statements for a discussion of our data licensing agreement and firm transportation agreements.
In our coal royalty and land management segment, PVR anticipates making total capital expenditures, excluding acquisitions, of up to approximately $0.4 million for coal services related projects for the remainder of 2004. Part of PVR's strategy is to make acquisitions which increase cash available for distribution to its unitholders. PVR's ability to make these acquisitions in the future will depend in part on the availability of debt financing and on its ability to periodically use equity financing through the issuance of new units. Since completing a large acquisition in late 2002 and the coal handling joint venture in July 2004, PVR's ability to incur additional debt has been restricted due to limitations in its debt instruments. At September 30, 2004, PVR has approximately $32 million of borrowing capacity. This limitation may necessitate the issuance of new units by PVR, as opposed to using debt, to fund acquisitions in the future.
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Environmental Matters
Our businesses are subject to various environmental hazards. Several federal, state and local laws, regulations and rules govern the environmental aspects of our businesses. Noncompliance with these laws, regulations and rules can result in substantial penalties or other liabilities. We do not believe our environmental risks are materially different from those of comparable companies nor that cost of compliance will have a material adverse effect on our profitability, capital expenditures, cash flows or competitive position. However, there is no assurance that future changes in or additions to laws, regulations or rules regarding the protection of the environment will not have such an impact. We believe we are in material compliance with environmental laws, regulations and rules.
In connection with the Partnership's leasing of property to coal operators, environmental and reclamation liabilities are generally the responsibilities of the Partnership's lessees. Lessees post performance bonds pursuant to federal and state mining laws and regulations for the estimated costs of reclamation and mine closing, including the cost of treating mine water discharge when necessary.
Recent Accounting Pronouncements
See Notes 7 and 12 in the Notes to Consolidated Financial Statements for a description of recent accounting pronouncements.
Item 3. Quantitative and Qualitative Disclosures about Market Risk
Interest Rate Risk. At September 30, 2004, we had $73.0 million of long-term debt borrowed under our credit facility. The credit facility matures in December 2007 and is governed by a borrowing base calculation that is re-determined semi-annually. We have the option to elect interest at (i) LIBOR plus a Eurodollar margin ranging from 1.25 to 2.00 percent, based on the percentage of the borrowing base outstanding or (ii) the greater of the prime rate or federal funds rate plus a margin ranging from 0.30 to 0.50 percent. As a result, our 2004 interest costs will fluctuate based on short-term interest rates relating to the PVA credit facility.
As of September 30, 2004, $88.5 million of PVR's borrowings were financed with debt which has a fixed interest rate throughout its term. In connection with this financing, PVR executed an interest rate derivative transaction to effectively convert the interest rate on one-third of the amount financed from a fixed rate of 5.77 percent to a floating rate of LIBOR plus 2.36 percent. The interest rate swap has been accounted for as a fair value hedge in compliance with SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended by SFAS No. 137 and SFAS No. 138.
Price Risk Management. Our price risk management program permits the utilization of derivative financial instruments (such as futures, forwards, option contracts and swaps) to mitigate the price risks associated with fluctuations in natural gas and crude oil prices as they relate to our anticipated production. These financial instruments are designated as cash flow hedges and accounted for in accordance with SFAS No. 133, as amended by SFAS No. 137, SFAS No. 138 and SFAS No. 139. The derivative financial instruments are placed with major financial institutions that we believe are of minimum credit risk. The fair value of our price risk management assets are significantly affected by energy price fluctuations. See the discussion and table in Note 4, "Hedging Activities," to our consolidated financial statements for a description of our hedging program and a listing of open hedging contracts and their fair value as of September 30, 2004.
Forward-Looking Statements
Statements included in this report which are not historical facts (including any statements concerning plans and objectives of management for future operations or economic performance, or assumptions related thereto) are forward-looking statements. In addition, we and our representatives may from time to time make other oral or written statements that are also forward-looking statements.
Such forward-looking statements may include, among other things, statements regarding development activities, capital expenditures, acquisitions and dispositions, drilling and exploration programs, expected commencement dates and projected quantities of oil, gas, or coal production, costs and expenditures as well as projected demand or supply for coal, coal handling joint venture operations, crude oil and natural gas, all of which may affect sales levels, prices, royalties and distributions realized by us and PVR.
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These forward-looking statements are made based upon management's current plans, expectations, estimates, assumptions and beliefs concerning future events impacting us and PVR and, therefore, involve a number of risks and uncertainties. We caution that forward-looking statements are not guarantees and that actual results could differ materially from those expressed or implied in the forward-looking statements.
Important factors that could cause the actual results of our operations or financial condition to differ materially from those expressed or implied in the forward-looking statements include, but are not necessarily limited to:
* the cost of finding and successfully developing oil and gas reserves and the cost to PVR of finding new coal reserves;
* our ability to acquire new oil and gas reserves and PVR's ability to acquire new coal reserves on satisfactory terms;
* our ability to discover and economically produce proved oil and gas reserves on our unproved leasehold acreage;
* the price for which such reserves can be sold;
* the volatility of commodity prices for oil and gas and coal;
* the projected demand for oil and gas and coal;
* the projected supply of oil and gas and coal;
* our ability to obtain adequate pipeline transportation capacity for our oil and gas production;
* the operating ability and financial stability of our oil and gas joint ventures partners;
* PVR's ability to lease new and existing coal reserves;
* the ability of PVR's lessees to produce sufficient quantities of coal on an economic basis from PVR's reserves;
* the ability of lessees to obtain favorable contracts for coal produced from PVR's reserves;
* competition among producers in the oil and gas and coal industries generally;
* the extent to which the amount and quality of actual production differs from estimated recoverable proved oil and gas reserves and coal reserves;
* unanticipated geological problems;
* availability of required drilling rigs, materials and equipment;
* the occurrence of unusual weather or operating conditions including force majeure events;
* the failure of equipment or processes to operate in accordance with specifications or expectations;
* delays in anticipated start-up dates of our oil and natural gas production and PVR's lessees' mining operations and related coal infrastructure projects;
* environmental risks affecting the drilling and producing of oil and gas wells or the mining of coal reserves;
* the timing of receipt of necessary governmental permits by us and by PVR's lessees;
* the risks associated with having or not having price risk management programs;
* labor relations and costs;
* accidents;
* changes in governmental regulation or enforcement practices, especially with respect to environmental, health and safety matters, including with respect to emissions levels applicable to coal-burning
power generators;
* uncertainties relating to the outcome of litigation regarding permitting of the disposal of coal overburden;
* risks and uncertainties relating to general domestic and international economic (including inflation and interest rates) and political conditions;
* the experience and financial condition of lessees of PVR's coal reserves, including their ability to satisfy their royalty, environmental, reclamation and other obligations to PVR and others;
* coal handling joint venture operations;
* the Partnership's ability to make cash distributions;
* changes in financial market conditions; and
* other risk factors detailed in our SEC filings on Annual Report on Form 10-K.
Many of such factors are beyond our ability to control or accurately predict. Readers are cautioned not to put undue reliance on forward-looking statements.
While we periodically reassess material trends and uncertainties affecting our results of operations and financial condition in connection with the preparation of Management's Discussion and Analysis of Results of Operations and Financial Condition and certain other sections contained in our quarterly, annual and other reports filed with the SEC, we do not undertake any obligation to review or update any particular forward-looking statement, whether as a result of new information, future events or otherwise.
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Item 4. Controls and Procedures
(a) Evaluation of Disclosure Controls and Procedures.
The Company, under the supervision and with the participation of its management, including its principal executive officer and principal financial officer, performed an evaluation of the design and operation of the Company's disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) as of the end of the period covered by this report. Based on that evaluation, the Company's principal executive officer and principal financial officer concluded that such disclosure controls and procedures are effective to ensure that material information relating to the Company, including its consolidated subsidiaries, is accumulated and communicated to the Company's management and made known to the principal executive officer and principal financial officer, particularly during the period for which this periodic report was being prepared.
(b) Changes in Internal Controls Over Financial Reporting.
No changes were made in the Company's internal control over financial reporting that occurred during the quarter ended September 30, 2004, that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
However, in connection with our ongoing evaluation of the effectiveness of our internal control over financial reporting, we discovered a material weakness in the user access controls related to our accounting system. Although we are unaware of any misstatement of financial position, results of operations or cash flows resulting from this control deficiency, management has determined that there is more than a remote likelihood that a material misstatement could occur as a result of such control deficiency. We have updated our software and implemented stricter user access controls which took effect during the fourth quarter.
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PART II. Other Information
Items 2, 3, 4 and 5 are not applicable and have been omitted.
Item 1. Legal Proceedings
In August 2004, one of PVR's lessees dislodged a boulder while repairing a surface mine access road. The boulder rolled down a hillside, damaging a residence and causing a fatality. On October 29, 2004, A&G Coal Corp., PVR's lessee, Penn Virginia Operating Co., LLC, PVR's wholly owned subsidiary, and PVR were named along with several other defendants in a lawsuit brought by the family of the deceased in the Circuit Court of Wise County, Virginia. The lawsuit is seeking $26.5 million in punitive and compensatory damages. While the ultimate result of the lawsuit cannot be predicted with certainty, based on the facts currently available to us, management believes that the case will not have a material adverse effect on our financial position, results of operations or cash flows.
Item 6. Exhibits and Reports on Form 8-K
(a) Exhibits
12 Statement of Computation of Ratio of Earnings to Fixed Charges Calculation.
31.1 Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 302 of the Sarbanes-
Oxley Act of 2002.
31.2 Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 302 of the Sarbanes-
Oxley Act of 2002.
32.1 Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-
Oxley Act of 2002.
32.2 Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
(b) Reports on Form 8-K
The Company furnished a Form 8-K on August 4, 2004 announcing that it issued a press release regarding its financial results for the three and six months ended June 30, 2004.
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SIGNATURES | | | | | | | | |
| | | | | | | | | |
Pursuant to the requirements of the Securities Exchange Act of 1934, as amended, the Registrant |
has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. |
| | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
PENN VIRGINIA CORPORATION | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
Date: | November 4, 2004 | | | By: | /s/ Frank A. Pici | |
| | | | | | Frank A. Pici | | |
| | | | | | Executive Vice President and | |
| | | | | | Chief Financial Officer | | |
| | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
Date: | November 4, 2004 | | | By: | /s/ Dana G Wright | |
| | | | | | Dana G Wright
Vice President and | |
| | | | | | Principal Accounting Officer | |
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