Three Months				Nine Months
	Ended September 30,				Ended September 30,
	2002		2001		2002		2001
Cash flow from operating activities:
Net Income	$      3,208		$      4,247		$    9,741		$    57,975
Adjustments to reconcile net income to net
cash provided by operating activities:
Depreciation, depletion, and amortization	8,146		5,401		21,758		12,162
Impairment of oil and gas properties	501		-		501		-
Minority interest in Penn Virginia Resource Partners, L.P.	3,379		-		9,321		-
Discontinued operations gain on sale of properties and depletion	-		-		(312)		-
Loss (Gain) on sale of properties	11		(313)		7		(1,147)
Gain on sale of securities	-		-		-		(54,688)
Deferred income taxes	4,221		1,929		6,101		4,952
Dry hole and leasehold amortization	5		2,846		149		4,300
Tax benefit from stock option exercises	4		-		224		2,716
Other	399		78		1,250		162
	19,874		14,188		48,740		26,432
Changes in operating assets and liabilities:
Current assets	(1,577)		1,101		(1,187)		(1,237)
Current liabilities	(330)		(15,117)		(7,648)		1,027
Other assets	(64)		(336)		(736)		(372)
Other liabilities	693		1,894		2,079		2,080
Net cash flows provided by operating activities	18,596		1,730		41,248		27,930
Cash flows from investing activities:
Proceeds from sale of U.S. Treasury Notes	12,000		-		12,000		-
Payments received on long-term notes receivable	110		245		445		736
Proceeds from sale of properties	14		37		1,314		1,283
Proceeds from sale of securities	-		-		-		57,525
Additions to property and equipment	(24,477)		(125,267)		(45,739)		(180,238)
Net cash flows used in investing activities	(12,353)		(124,985)		(31,980)		(120,694)
Cash flows from financing activities
Dividends paid	(2,012)		(1,996)		(6,027)		(5,928)
Distributions paid to minority interest holders of subsidiary	(3,746)		-		(10,041)		-
Proceeds from (repayments of) borrowings	(3,051)		124,546		6,280		88,824
Purchase of units of Penn Virginia Resource Partners, L.P.	-		-		(1,067)		-
Purchase of treasury stock	-		-		(557)		-
Issuance of stock	144		108		1,900		9,133
Net Cash provided by (used in) financing activities	(8,665)		122,658		(9,512)		92,029
Net decrease in cash and cash equivalents	(2,422)		(597)		(244)		(735)
Cash and cash equivalents-beginning of period	11,799		597		9,621		735
Cash and cash equivalents-end of period	$      9,377		$              -		$      9,377		$              -
Supplemental disclosures of cash flow information:
Cash paid during the periods for:
Interest	$          478		$          598		$      1,300		$      1,569
Income taxes	$            10		$     18,000		$         113		$    26,000
Noncash financing activities:
Restricted subsidiary partnership units granted as unearned compensation	$               -		$               -		$      1,067		$             -
Deferred tax liabilities related to acquisition	$               -		$     43,807		$              -		$   43,807

 

The accompanying notes are an integral part of these condensed consolidated financial statements.

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PENN VIRGINIA CORPORATION

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2002

1.  INTRODUCTION

      The accompanying unaudited condensed consolidated financial statements include the accounts of Penn Virginia Corporation ("Penn Virginia" or the "Company"), all wholly-owned subsidiaries, and Penn Virginia Resource Partners, L.P. (the "Partnership" or "PVR") in which we have an approximate 52 percent ownership interest.  Penn Virginia Resource GP, LLC, a wholly-owned subsidiary of Penn Virginia, serves as the Partnership's sole general partner.  The financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America for interim financial reporting and SEC regulations. These statements involve the use of estimates and judgments where appropriate. In the opinion of management, all adjustments, consisting of normal recurring accruals, considered necessary for a fair presentation have been included. These financial statements should be read in conjunction with the Company's consolidated financial statements and footnotes included in the Company's Annual Report on Form 10-K for the year ended December 31, 2001. Operating results for the nine months ended September 30, 2002 are not necessarily indicative of the results that may be expected for the year ended December 31, 2002.  Certain reclassifications have been made to conform to the current period's presentation.

 

2.  ACQUISITIONS

     On July 23, 2001, the Company acquired all of the outstanding stock of Synergy Oil and Gas, Inc., a Texas Corporation.  Cash consideration for the stock was $112 million (subject to certain post closing adjustments) and was funded by long-term debt.  As of July 23, 2001, Synergy Oil and Gas, Inc. had net proved oil and gas reserves of approximately 58 Bcfe. The operations have been included in the Company's statement of income as of the closing date. The following unaudited pro forma results of operations have been prepared to give effect to (1) the sale of 3,307,200 shares of Norfolk Southern Corporation common stock on April 26, 2001 and (2) the acquisition of Synergy Oil & Gas, Inc. on July 23, 2001 had such transactions been completed on January 1, 2001. The unaudited pro forma results of operations consist of the following (in thousands, except share data):

	Three Months Ended		Nine Months Ended
	September 30, 2001		September 30, 2001
Revenues	$  23,718		$  92,534
Net income	$    3,680		$  66,377
Net income per share, diluted	$      0.41		$      7.47

 

 

 

 

The summarized pro forma information has been prepared for comparative purposes only.

 

3.  PRICE RISK MANAGEMENT ACTIVITIES

      From time to time, we enter into derivative financial instruments to mitigate our exposure to natural gas and crude oil price volatility.  The derivative financial instruments, which are placed with major financial institutions that we believe are minimum credit risks, take the form of costless collars and swaps.  All derivative financial instruments are recognized in the financial statements at fair value in accordance with Statement of Financial Accounting Standards ("SFAS") No. 133, Accounting for Derivative Instruments and Certain Hedging Activities, as amended by SFAS No. 137 and SFAS No. 138, Accounting for Certain Derivative Instruments and Certain Hedging Activities, and Amendment of FASB Statement No. 133.

      All derivative instruments are recorded on the balance sheet at fair value.  If the derivative does not qualify as a hedge or is not designated as a hedge, the gain or loss on the derivative is recognized currently in earnings.  To qualify for hedge accounting, the derivative must qualify either as a fair value hedge, cash flow hedge or foreign currency hedge.  Currently, we are utilizing only cash flow hedges and the remaining discussion will relate exclusively to this type of derivative instrument. All hedge transactions are subject to our risk management policy, which has been reviewed and approved by the Board of Directors.

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      We formally document all relationships between hedging instruments and hedged items, as well as its risk-management objective and strategy for undertaking various hedge transactions. This process includes linking all derivatives that are designated as cash flow hedges to forecasted transactions. We also formally assess, both at  inception of the hedge and on an ongoing basis, whether the derivatives that are used in hedging transactions are highly effective in offsetting changes in cash flows of hedged transactions. We measure hedge effectiveness on a period basis. When it is determined that a derivative is not highly effective as a hedge, or that it has ceased to be a highly effective hedge, we discontinue hedge accounting prospectively.

      When hedge accounting is discontinued because it is probable that a forecasted transaction will not occur, the derivative will continue to be carried on the balance sheet at its fair value, and gains and losses that were accumulated in other comprehensive income will be recognized in earnings immediately. In all other situations in which hedge accounting is discontinued, the derivative will be carried at its fair value on the balance sheet, with changes in its fair value recognized in earnings prospectively.

      Gains and losses on hedging instruments when settled are included in natural gas or crude oil production revenues in the period that the related production is delivered.

      The fair value of our hedging instruments is determined based on third party forward price quotes for NYMEX Henry Hub and West Texas Intermediate closing price's as of September 30, 2002.  The following table sets forth our positions as of September 30, 2002:

	Notional	Fixed Price or
Time Period	Quantities	Effective Floor/Ceiling Price	Fair Value
			(in thousands)
Natural Gas	(MMbtu per Day)
Costless collars
October 1 - December 31, 2002	2,301	$4.00 / $5.70	$                 56
October 1 - December 31, 2002	1,315	$4.00 / $6.25	34
November 1 - December 31, 2002	8,000	$2.96 / $5.05	(74)
January 1 - March 31, 2003	10,000	$2.96 / $5.05	(253)
January 1 - September 30, 2003	5,000	$3.47 / $5.20	(84)
April 1- October 31, 2003	5,000	$2.92 / $4.42	(325)
Crude Oil	(Bbls per Day)
Costless collars
October 1 - December 31, 2002	263	$20.00 / $24.50	(177)
October 1 - December 31, 2002	197	$22.00 / $26.60	(85)
October 1 - December 31, 2002	303	$22.00 / $26.20	(89)
January 1 - September 30, 2003	500	$23.00 / $28.75	(60)
Total			$         (1,057)

  

 

 

 

 

 

 

 

 

 

 

 

 

    Based upon our assessment of our derivative contracts at September 30, 2002, we reported (i) an approximate liability of $1.2 million and an asset of $0.1 million and (ii) a loss in accumulated other comprehensive income of $0.8 million, net of related income taxes of $0.4 million.  In connection with monthly settlements, we recognized net hedging losses in natural gas and oil revenues of $0.4 million for the nine months ended September 30, 2002.  Based upon future oil and natural gas prices as of September 30, 2002, $1.1 million of hedging losses are expected to be realized within the next 13 months.  The amounts ultimately realized will vary due to changes in the fair value of the open derivative contracts prior to settlement.

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4. LONG-TERM DEBT

      At September 30, 2002 and December 31, 2002, long-term debt consists of the following (in thousands):

	September 30,		December 31,
	2002		2001
	(Unaudited)
Penn Virginia revolving credit facility	$   11,000		$     3,500
PVR unsecured term loan	12,000		-
	$   23,000		$     3,500
PVR term loan secured by U.S. Treasury Notes	$   31,387		$   43,387

 

 

 

 

 

 

5. CONTINGENT LIABILITIES

    We are involved in various legal proceedings arising in the ordinary course of business. While the ultimate results of these proceedings cannot be predicted with certainty, we believe these claims will not have a material effect on our financial position, liquidity or operations.

    On March 25, 2002, we entered into an agreement with an investment banking firm to provide financial advisory services in connection with our receipt and consideration of various shareholder proposals.  The fees payable under this agreement  cannot be calculated with certainty until the time of actual payment which will occur on or before November 30, 2003.  As of September 30, 2002, based on a range of probable payment amounts, we have recognized expenses of approximately $0.8 million for services rendered in connection with this agreement.  We will continue to accrue additional expenses under this agreement in accordance with our best estimate of the amount due for such services.

 

6.  EARNINGS PER SHARE

    The following is a reconciliation of the amounts used in the calculation of basic and diluted earnings per share for income from continuing operations and net income at September 30, 2002 and 2001 (in thousands, except share data).

 

	Three Months				Nine Months
	Ended September 30,				Ended September 30,
	2002		2001		2002		2001
Income from continuing operations	$    3,208		$    4,247		$   9,520		$  57,975
Income from discontinued operations	-		-		221		-
Net income	$    3,208		$    4,247		$   9,741		$  57,975
Weighted average shares, basic	8,944		8,869		8,926		8,736
Dilutive securities:
Stock options	48		138		49		144
Weighted average shares, diluted	8,992		9,007		8,975		8,880
Income from continuing operations per share, basic	$      0.36		$      0.48		$      1.07		$      6.64
Income from discontinued operations per share, basic	-		-		0.02		-
Net income per share, basic	$      0.36		$      0.48		$      1.09		$      6.64
Income from continuing operations per share, diluted	$      0.36		$      0.47		$      1.07		$      6.53
Income from discontinued operations per share, diluted	-		-		0.02		-
Net income per share, diluted	$      0.36		$      0.47		$      1.09		$      6.53

 

 

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7. COMPREHENSIVE INCOME

    Comprehensive income represents changes in retained earnings during the reporting period, including net income and charges made directly to retained earnings. For the three- and nine-month periods ended September 30, 2002 and 2001, the components of comprehensive income are as follows (in thousands):

 

	Three Months				Nine Months
	Ended September 30,				Ended September 30,
	2002		2001		2002		2001
Net income	$    3,208		$    4,247		$    9,741		$  57,975
Holding gains on available-for-sale securities
during period, net of tax	-		-		-		8,741
Unrealized gains (losses) on price risk
management, net of tax	(332)		1,122		(3,034)		1,896
Reclassification adjustment for available-for-sale
securities, net of tax	-		-		-		(35,547)
Reclassification adjustment for price risk management,
net of tax	427		(1,101)		234		(1,226)
Total comprehensive income	$    3,303		$    4,268		$     6,941		$  31,839

 

 

 

 

 

 

 

 

 

 

8.  LONG-TERM INCENTIVE PLAN

    In January 2002, pursuant to the PVR long-term incentive plan described in its Annual Report on Form 10-K for the year ended December 31, 2001, we purchased and awarded PVR common units to certain directors and employees of the general partner of PVR as restricted units.  The units are restricted for a five-year period, with 25 percent vested by the end of 2004, another 25 percent vested by the end of 2005, and the remaining 50 percent vested during 2006.  Amounts related to this transaction are reported in the Unearned Compensation balance in the Shareholder's Equity section of the Balance Sheet.  Compensation expense related to these awards is amortized into earnings ratably over the vesting period. PVR reimburses the Company for the cost it incurred to purchase and award the PVR common units.

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9.  SEGMENT INFORMATION

Penn Virginia's operations are classified into two operating segments:

    Oil and Gas - crude oil and natural gas exploration, development and production.

    Coal Royalty and Land Management - the management of coal properties resulting in collection of coal royalties and service fees and the harvesting and sale of timber.  The activities related to this segment are conducted through Penn Virginia's ownership interest in Penn Virginia Resource Partners, L.P.

      All Other - primarily represents corporate assets and related expenses.

			Coal Royalty
			and Land		All
	Oil and Gas		Management		Other		Consolidated
	(in thousands)
For the three months ended September 30, 2002:
Revenues	$        18,182		$         10,404		$              168		$         28,754
Operating costs and expenses	7,823		2,370		2,126		12,319
Depreciation, depletion and amortization	7,098		995		53		8,146
Impairment of oil and gas properties	501		-		-		501
Operating income (loss)	$          2,760		$           7,039		$          (2,011)		7,788
Interest expense							(707)
Interest and other income							508
Income from continuing operations
before minority interest and taxes							$           7,589
Additions to property and equipment	$       12,329		$        12,106		$               42		$         24,477
For the three months ended September 30, 2001:
Revenues	$         13,691		$          9,974		$              366		$         24,031
Operating costs and expenses	8,169		2,185		1,435		11,789
Depreciation, depletion and amortization	4,537		845		19		5,401
Operating income (loss)	$             985		$          6,944		$         (1,088)		6,841
Interest expense							(721)
Interest and other income							371
Income before taxes							$           6,491
Additions to property and equipment	$      125,046		$             162		$                59		$       125,267

 

 

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			Coal Royalty
			and Land		All
	Oil and Gas		Management		Other		Consolidated
	(in thousands)
For the nine months ended September 30, 2002:
Revenues	$        49,176		$         28,950		$              659		$        78,785
Operating costs and expenses	20,086		7,207		5,430		32,723
Depreciation, depletion and amortization	19,041		2,558		159		21,758
Impairment of oil and gas properties	501		-		-		501
Operating income (loss)	$          9,548		$         19,185		$         (4,930)		23,803
Interest expense							(1,988)
Interest and other income							1,583
Income from continuing operations
before minority interest and taxes							$        23,398
Additions to property and equipment	$        32,542		$         12,887		$              310		$        45,739
For the nine months ended September 30, 2001:
Revenues	$         46,329		$         28,418		$           1,146		$         75,893
Operating costs and expenses	16,620		6,362		3,489		26,471
Depreciation, depletion and amortization	9,987		2,116		59		12,162
Operating income (loss)	$         19,722		$         19,940		$         (2,402)		$         37,260
Interest expense							(1,939)
Interest and other income							1,215
Gain on sale of securities							54,688
Income before taxes							$         91,224
Additions to property and equipment	$       146,419		$        33,719		$             100		$       180,238

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

10. DISCONTINUED OPERATIONS

       During the second quarter of 2002, we sold certain marginal oil and gas properties that were considered a component of the Company under SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets. The properties sold included various interests in South Texas properties acquired in the third quarter of last year, the operations of which were insignificant in 2001. The net carrying amount of properties sold was $0.5 million. We adopted the provisions ofSFAS No. 144effective January 1, 2002. Accordingly, the components of discontinued operations were as follows for the nine-months ended September 30, 2002 (in thousands).

Revenues
Natural gas	$         48
Oil and condensate	332
Total revenues	380
Expenses
Operating expenses	352
Depreciation, depletion and amortization	25
Total expenses	377
Income from discontinued operations	3
Gain on sale of properties	337
	340
Income taxes	(119)
Net income from discontinued operations	$        221

 

 

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11.  IMPAIRMENT OF OIL AND GAS PROPERTIES

     In accordance with SFAS No. 144, Accounting for the Impairment of Disposal or Long-Lived Assets, we review oil and gas properties for impairment when events and circumstances indicate a decline in the recoverability of the carrying value of such properties. Due to a downward revision of the reserve estimates of one Texas oil and gas field, we estimated the future cash flows expected in connection with the property and compared such future cash flows to the carrying amount of the property to determine if the carrying amount was recoverable.  We found that the carrying amount of the property exceeded the estimated undiscounted future cash flows. Therefore, we adjusted the carrying amount of the property to its fair value as determined by discounting its estimated future cash flows, and we recognized a pretax charge of $0.5 million related to the impairment of such property.  The factors used to determine fair value included, but were not limited to, estimates of proved reserves, future commodity prices, timing of future production, future capital expenditures and a discount rate reflective of the current market for oil and gas properties.  

 

12.  NEW ACCOUNTING STANDARDS

      In June 2001, the Financial Accounting Standards Board ("FASB") issued SFAS No. 143, Accounting for Asset Retirement Obligations. This statement requires companies to record a liability relating to the future retirement and removal of assets used in their business. The liability is discounted to its present value, and the related asset value is increased by the amount of the resulting liability. Over the life of the asset, the liability will be accreted to its future value and eventually extinguished when the asset is taken out of service. The provisions of this statement are effective for fiscal years beginning after June 15, 2002.  We are currently evaluating the future financial reporting effect of adopting SFAS No. 143 and will complete such assessment during the fourth quarter of 2002.  We will adopt the standard effective January 1, 2003.

      In April 2002, the FASB issued SFAS No. 145, Rescission of FASB Statements No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical Corrections. This statement rescinds SFAS No. 4, Reporting Gains and Losses from Extinguishment of Debt, which required all gains and losses from extinguishment of debt to be aggregated and, if material, classified as an extraordinary item of debt to be aggregated and, if material, classified as an extraordinary item, net of income taxes.  As a result, the criteria in Accounting Principles Board Opinion (APB) Opinion No. 30 will now be used to classify those gains and losses. Any gain or loss on the extinguishment of debt that was classified as an extraordinary item in prior periods presented that does not meet the criteria in APB Opinion No. 30 for classification as an extraordinary item shall be reclassified. The provisions of this statement are effective for fiscal years beginning after January 1, 2003. Under present conditions, management does not expect the initial adoption of SFAS No. 145 to have a material effect on the financial position, results of operations or liquidity of the Company.

      In June 2002, the FASB issued SFAS No. 146, Accounting for Costs Associated with Exit or Disposal Activities. This statement requires the recognition of costs associated with exit or disposal activities when they are incurred rather than at the date of a commitment to an exit or disposal plan. The provisions of this statement are effective for exit or disposal activities initiated after December 31, 2002. Under present conditions, management does not expect the initial adoption of SFAS No. 146 to have a material effect on the financial position, results of operations or liquidity of the Company.

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Item 2.  Management's Discussion and Analysis of Financial Condition and Results of Operations

    We operate in two business segments: oil and gas and coal royalty and land management. The oil and gas segment includes the exploration for, development and production of crude oil, condensate and natural gas in the eastern and southern portions of the United States, and our ownership of mineral rights to oil and gas reserves. The coal royalty and land management segment includes coal reserves, timber and other land assets owned by Penn Virginia Resource Partners, L.P. (the "Partnership" or "PVR"). The assets, liabilities and earnings of PVR are included in our consolidated financial statements, with the public unitholders' 48 percent interest in PVR reflected as a minority interest.  Selected operating and financial data by segment is presented below.

      The Company's Annual Report on Form 10-K for the year ended December 31, 2001 describes the accounting policies that we believe are critical to the reporting of our financial position and operating results and that require management's judgments.  Estimates include, but are not limited to, remaining proved oil and gas reserves, timing of our future drilling activities, and future costs to develop and abandon our oil and gas properties. 

 

Results of Operations - Three Months Ended September 30, 2002 Compared to Three Months Ended  September 30, 2001

    The Company reported net income of $3.2 million, or $0.36 per share (diluted), for the three months ended September 30, 2002, compared with $4.2 million, or $0.47 per share (diluted), for the three months ended September 30, 2001.  Revenues increased $4.7 million, primarily as a result of increased natural gas and crude oil production, offset in part by a decrease in coal tons produced and a decrease in natural gas and crude oil prices received.  Operating expenses were $3.8 million higher during the three months ended September 30, 2002 than the 2001 comparable period primarily due to expense increases related to our acquisition of certain South Texas oil and gas properties in July 2001 and increased expenses related to the consideration of various shareholder proposals, offset in part by decreased exploration expenses.

Variances in revenues and operating expenses are explained in more detail in the segment discussions following.

Interest expense.  Interest expense was $0.7 million for the three months ended September 30, 2002, compared with $0.7 million for the three months ended September 30, 2001.  The 2002 interest expense primarily related to the PVR term loan secured by U.S. Treasury Notes.

Interest income.  Interest income was $0.5 million for the three months ended September 30, 2002, compared with $0.4 million for the three months ended September 30, 2001.  The 2002 interest income was earned on the U.S Treasury Notes and a note receivable related to the sale of coal properties in 1986.

Minority interest.  Minority interest for the three months ended September 30, 2002 was $3.4 million, representing the public unitholders' 48 percent interest in PVR's net income of $7.0 million for the same period.  PVR was created in October 2001; therefore, no comparable amount exists for the same period in 2001.

Income tax expense.  Income tax expense for the three months ended September 30, 2002 was $1.0 million compared with $2.2 million for the three months ended September 31, 2001.  The 2002 tax provision was reduced by the expected benefit of Section 29 tax credits available to the Company.

Results of Operations - Nine Months Ended September 30, 2002 Compared to Nine Months Ended September 30, 2002

    The Company reported net income of $9.7 million, or $1.09 per share (diluted), for the nine months ended September 30, 2002, compared with $58.0 million, or $6.53 per share (diluted), for the nine months ended September 30, 2001. Net income for the nine months ended September 30, 2001 included a gain on sale of securities of $54.7 million ($35.5 million net of taxes). Revenues increased $2.9 million, primarily as a result of increased natural gas and crude oil production, offset in part by a decrease in coal tons produced and a decrease in natural gas and crude oil prices received.  Operating expenses were $16.3 million higher during the nine months ended September 30, 2002 than the 2001 comparable period primarily due to the additional operational and administrative expenses related to our acquisition of certain South Texas oil and gas properties in the third quarter of 2001 and increased expenses related to the consideration of various shareholder proposals, offset in part by decreased exploration expense.

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Variances in revenues and operating expenses are explained in more detail in the segment discussions following.

Interest expense. Interest expense was $2.0 million for the nine months ended September 30, 2002, compared with $1.9 million for the nine months ended September 30, 2001. The 2002 interest expense primarily related to the PVR term loan secured by U.S. Treasury Notes, while the 2001 amount related to higher credit facility borrowings outstanding in that period.

Interest income: Interest income was $1.6 million for the nine months ended September 30, 2002, compared with $1.2 million for the nine months ended September 30, 2001. The increase was due to the U.S. Treasury Notes purchased by PVR to secure its term loan in late 2001.

Minority interest.  Minority interest for the three months ended September 30, 2002 was $9.3 million, representing the public unitholders' 48 percent interest in PVR's net income for that period of $19.5 million.  PVR was created in October 2001; therefore, no comparable amount exists for the same period in 2001.

Income tax expense.  Income tax expense for the nine months ended September 30, 2002 was $4.6 million compared with $33.2 million for the nine months ended September 31, 2001.  The decrease was due to lower income levels as explained in this section and the expected benefit of Section 29 tax credits available to the Company.

Selected operating and financial data by segment is presented below.

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Oil and Gas Segment

Three Months Ended September 30, 2002 Compared to Three Months Ended September 30, 2001

    The following table sets forth operational and financial data for the Company's oil and gas segment for the three months ended September 30, 2002 and 2001:

Operations and Financial Summary

	Three Months
	Ended September 30,
Production	2002				2001
Natural gas (MMcf)	5,008				3,482
Oil and condensate (Mbbls)	91				73
Equivalent production (MMcfe)	5,554				3,920
	(in thousands, except unit cost)
Revenues:
Natural gas (including $/Mcf)	$     16,012		$         3.20		$     11,627		$         3.34
Oil and condensate (including $Bbl)	2,085		22.91		1,687		23.11
Other income	85				377
Total revenues (including $/Mcfe)	18,182		3.27		13,691		3.49
Expenses (including $/Mcfe):
Lease operating	2,712		0.49		1,917		0.48
Exploration	1,614		0.29		3,627		0.93
Taxes other than income	1,355		0.24		1,083		0.28
General and administrative	2,142		0.39		1,542		0.39
Impairment of oil and gas properties	501		0.09		-		-
Depreciation and depletion	7,098		1.28		4,537		1.16
Total expenses	15,422		2.78		12,706		3.24
Operating Income (including $/Mcfe)	$       2,760		$         0.49		$       985		$         0.25

 

    

 

 

 

 

 

 

 

 

 

 

 

 

 

    For the three months ended September 30, 2002, approximately 53 percent of our natural gas and crude oil production was sold at market prices.  The remainder was sold subject to cash flow hedges at an average floor price of $2.98 per MMbtu and ceiling price of $3.38 per MMbtu for natural gas, and an average floor price of $21.29 per barrel and ceiling price of $25.70 per barrel for crude oil. The effects of these hedges were to decrease the average natural gas prices received by $0.10 per Mcf and the average crude oil prices received by $1.97 per barrel.

    See "Note 2. Price Risk Management Activities" in the Notes to the Condensed Consolidated Financial Statements for details of costless collars and a fixed price swap for the period October 2002 through October 2003.  We will continue, when circumstances warrant, hedging the price received for market-sensitive production through the use of similar type transactions.

Natural gas.  Natural gas sales increased $4.4 million, or 38 percent, to $16.0 million in the three months ended 
September 30, 2002,compared with $11.6 million in the three months ended September 30, 2001.  The average natural gas price realized of $3.20 per Mcf was 4 percent lower in the third quarter of 2002, compared with $3.34 per Mcf in the same quarter of the prior year.  More than offsetting the price decrease was a production increase of 1,526 MMcf, or 44 percent, to 5,008 MMcf in the third quarter of 2002 compared with 3,482 MMcf in the same period in 2001.  The production increase was due to added production from the acquisition of certain South Texas oil and gas properties in late July of 2001 and to increased production from the 2002 drilling program.

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Oil and condensate.  Oil sales increased $0.4 million, or 24 percent, to $2.1 million in the three months ended September 30, 2002, compared with  $1.7 million in the three months ended September 30, 2001.  The increase was a direct result of added production, to 91 Mbbls in the three months ended September 30, 2002 from 73 Mbbls in the same period of 2001, primarily related to the acquisition of certain South Texas oil and gas properties in late July of 2001.

Lease operating.  Lease operating expenses for the three months ended September 30, 2002 increased $0.8 million, or 41 percent, to $2.7 million, compared with $1.9 million for the three months ended September 30, 2001. The increase was primarily attributable to the acquisition of certain South Texas oil and gas properties in late July of 2001 and the related higher operating costs of properties in that region.

Exploration.  Exploration expenses for the three months ended September 30, 2002 decreased $2.0 million, or 56 percent, to $1.6 million from $3.6 million for the three months ended September 30, 2001.  This variance was a result of the timing and makeup of exploration activities between the two periods.

Taxes other than income.  Taxes other than income increased $0.3 million, or 25 percent, to $1.4 million for the three months ended September 30, 2002 from $1.1 million for the three months ended September 30, 2001. The increase was primarily due to higher production. However, on a unit of production basis, severance and ad valorem taxes decreased due to the lower prices received for natural gas.

General and administrative.  General and administrative expenses increased $0.6 million, or 39 percent, to $2.1 million for the three months ended September 30, 2002 from $1.5 million for the three months ended September 30, 2001. The increase was attributable to the acquisition of certain South Texas oil and gas properties in late July of 2001 and personnel expenses related to our expansion in Gulf Coast region activity.

Impairment of oil and gas properties.  Due to a downward revision of the reserve estimates of one Texas oil and gas field, we reviewed certain oil and gas properties for impairment.  The carrying amount of the property exceeded the estimated undiscounted future cash flows and, consequently, we adjusted the carrying amount of this property to its fair value as determined by discounting its estimated future cash flows.  As a result, we recognized a pretax charge of $0.5 million related to the impairment of oil and gas property for the three months ended September 30, 2002.

Depreciation and depletion.  Depreciation and depletion increased $2.6 million, or 56 percent, to $7.1 million for the three months ended September 30, 2002 from $4.5 million for the three months ended September 30, 2001.  The increase was a result of higher production and the late July 2001 acquisition of certain South Texas oil and gas properties, which have a higher cost basis than our other properties.

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Nine Months Ended September 30, 2002 Compared to Nine Months Ended September 30, 2001

    The following table sets forth operational and financial data for the Company's oil and gas segment for the nine months ended September 30, 2002 and 2001:

Operations and Financial Summary

	Nine Months
	Ended September 30,
Production	2002				2001
Natural gas (MMcf)	13,916 *				9,177
Oil and condensate (Mbbls)	259 *				80
Equivalent production  (MMcfe)	15,470 *				9,657
	(in thousands, except unit cost)
Revenues:
Natural gas (including $/Mcf)	$     43,032		$         3.09		$     43,174		$         4.70
Oil and condensate (including $Bbl)	5,954		22.99		1,846		23.08
Other income	190				1,309
Total revenues (including $/Mcfe)	49,176		3.18		46,329		4.80
Expenses (including $/Mcfe):
Lease operating	6,475		0.42		3,787		0.39
Exploration	3,663		0.24		6,104		0.64
Taxes other than income	3,922		0.25		3,156		0.33
General and administrative	6,026		0.39		3,573		0.37
Impairment of oil and gas properties	501		0.03		-		-
Depreciation and depletion	19,041		1.23		9,987		1.03
Total expenses	39,628		2.56		26,607		2.76
Operating Income (including $/Mcfe)	$     9,548		$         0.62		$     19,722		$         2.04

  

 

 

 

 

 

 

 

 

 

 

 

 

 

 

* Excludes 18 MMcf natural gas and 16 Mbbls oil and condensate production related to discontinued operations.

  For the nine months ended September 30, 2002, approximately 48 percent of our natural gas and crude oil production was sold at market prices.  The remainder was sold subject to cash flow hedges at an average floor price of $2.95 per MMbtu and ceiling price of $3.38 per MMbtu for natural gas, and an average floor price of $21.33 per barrel and ceiling price of $25.73 per barrel for crude oil. The effects of these hedges were to decrease the average price received for natural gas by $0.02 per Mcf and the average crude oil price received by $0.42 per barrel.

    See "Note 2. Price Risk Management Activities" in the Notes to the Condensed Consolidated Financial Statements for details of costless collars and a fixed price swap for the period October 2002 through October 2003.  We will continue, when circumstances warrant, hedging the price received for market-sensitive production through the use of similar type transactions.

Natural gas. Natural gas sales decreased less than one percent, to $43.0 million, for the nine months ended September 30, 2002,compared with $43.2 million for the nine months ended September 30, 2001. The average natural gas price realized of $3.09 per Mcf was 34 percent lower in 2002, compared with $4.70 per Mcf in the same period of the prior year.  Offsetting the price decrease was a production increase of 4,739 MMcf, or 52 percent, to 13,916 MMcf in 2002 compared with 9,177 MMcf in the same period in 2001.  The production increase was due to added production from the acquisition of certain South Texas oil and gas properties in the third quarter of 2001 and to increased production from the 2002 drilling program.

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Oil and condensate. Oil sales increased $4.1 million, or 222 percent, to $6.0 million for the nine months ended September 30, 2002, compared with  $1.8 million for the nine months ended September 30, 2001.  The increase in sales was a direct result of added production, which increased to 259 Mbbls for the three months ended September 30, 2002 from 80 Mbbls for the same period of 2001, primarily related to the acquisition of certain South Texas oil and gas properties in the third quarter of 2001.

Lease operating. Lease operating expenses for the nine months ended September 30, 2002 increased $2.7 million, or 71 percent, to $6.5 million, compared with $3.8 million for the nine months ended September 30, 2001. The increase was primarily attributable to the acquisition of certain South Texas oil and gas properties in the third quarter of 2001 and the related higher operating costs of properties in that region.

Exploration. Exploration expenses for the nine months ended September 30, 2002 decreased $2.4 million, or 40 percent, to $3.7 million from $6.1 million for the nine months ended September 30, 2001. This variance is a result of the timing and makeup of exploration activities between the two periods.

Taxes other than income. Taxes other than income increased $0,8 million, or 24 percent, to $3.9 million for the nine months ended September 30, 2002 from $3.2 million for the nine months ended September 30, 2001. The increase was primarily due to higher production. However, on a unit of production basis, severance and ad valorem taxes decreased due to the lower prices received for natural gas.

General and administrative. General and administrative expenses increased $2.4 million, or 69 percent, to $6.0 million for the nine months ended September 30, 2002 from $3.6 million for the nine months ended September 30, 2001. The increase was attributable to the acquisition of certain South Texas oil and gas properties in the third quarter of 2001 and personnel expenses related to our expansion in Gulf Coast region activity.

Impairment of oil and gas properties.  Due to a downward revision of the reserve estimates of one Texas oil and gas field, we reviewed certain oil and gas properties for impairment.  The carrying amount of the property exceeded the estimated undiscounted future cash flows and, consequently, we adjusted the carrying amount of this property to its fair value as determined by discounting its estimated future cash flows.  As a result, we recognized a pretax charge of $0.5 million related to the impairment of oil and gas property for the nine months ended September 30, 2002.

Depreciation and depletion.  Depreciation and depletion increased $9.0 million, or 91 percent, to $19.0 million for the nine months ended September 30, 2002 from $10.0 million for the nine months ended September 30, 2001.  The increase was a result of higher production and the third quarter 2001 acquisition of certain South Texas oil and gas properties, which have a higher cost basis than our other properties.

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Coal Royalty and Land Management

    The coal royalty and land management segment includes PVR's mineral rights to coal reserves, its timber assets and its land assets. The assets, liabilities and earnings of PVR are included in our consolidated financial statements, with the public unitholders' 48 percent interest in PVR reflected as a minority interest.

Three Months Ended September 30, 2002 Compared to Three Months Ended September 30, 2001

    The following table sets forth operational and financial data for the Company's coal segment for the three months ended September 30, 2002 and 2001:

Operations and Financial Summary

		Three Months
		Ended September 30				Percent
		2002		2001		Change
		(in thousands)
Coal tons		3,716		4,131		(10%)
Average royalty per ton		$            2.22		$             2.22		-
Revenues:
Coal royalties		$          8,253		$           9,154		(10%)
Timber sales		360		358		1%
Other income		1,791		462		288%
Total revenues		10,404		9,974		4%
Expenses
Operating		555		716		(22%)
Taxes other than income		241		131		84%
General and administrative		1,574		1,338		18%
Depreciation and depletion		995		845		18%
Total expenses		3,365		3,030		11%
Operating Income		$         7,039		$          6,944		1%

 

 

 

 

 

 

 

 

 

 

 

 

 

Coal royalties. Coal royalty revenue for the three months ended September 30, 2002 was $8.3 million compared to $9.2 million for the same period in 2001, a decrease of $0.9 million, or 10 percent.  While the average royalty per ton remained stable over the respective periods, the production by PVR lessees decreased 0.4 million tons, or 10 percent, primarily due to the bankruptcy of one of PVR's lessees in the first quarter of 2002. 

Timber sales. Timber revenue remained constant at $0.4 million for the three months ended September 30, 2002 and September 30, 2001.  Volume sold declined 215 thousand board feet (Mbf), or 11 percent, to 1,690 Mbf in the third quarter of  2002, compared with 1,905 Mbf for the same period in 2001. This decrease was mitigated by an increase in the average price received, which totaled $204 per Mbf in the third quarter of 2002 compared with $154 per Mbf in the comparable period of 2001.  The decrease in volume sold was due to the timing of parcel sales and the increase in the average price received primarily resulted from higher quality hardwoods being sold.

Other income. Minimum rentals revenue, a component of other income, increased to $1.1 million for the three months ended September 30, 2002 from zero in the comparable period of 2001.  The increase was primarily due to a lessee rejecting a PVR lease in bankruptcy on August 31, 2002; consequently, all deferred revenue from this lessee ($0.8 million) was recognized as income.  Also, coal services revenue increased $0.1 million, or 36 percent, to $0.5 million in the third quarter of 2002, compared with $0.4 million in the same period of 2001. The increase was attributable to a small preparation plant being added by one of PVR's lessees and a slight increase in throughput fees from tonnage going through PVR's loadout facility.  Additionally, for the periods compared, there was a $0.1 million increase due to the timing of rebates received for the use of a specific portion of railroad by one of PVR's lessees.

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Operating. Operating expenses decreased by $0.1 million, or 22 percent, to $0.6 million for the three months ended September 30, 2002, compared with $0.7 million in the same period of 2001.  The decrease was primarily due to less preventative maintenance necessary on certain properties.

Taxes other than income. Taxes other than income increased $0.1 million, or 84 percent, to $0.2 million for the three months ended September 30, 2002, compared with $0.1 million in the same period of 2001. The variance was attributable to an increase in West Virginia franchise taxes, which was caused by a change from a corporation to a partnership structure in the last half of 2001 for the coal royalty and land management segment of the business.

General and administrative. General and administrative expenses increased $0.2 million, or 18 percent, to $1.6 million for the three months ended September 30, 2002, compared with $1.3 million for the same period of 2001. The increase was primarily attributable to recurring fees and expenses associated with being a public entity, such as director's fees, tax reporting for the partners and fees for professional services.

Depreciation and depletion. Depreciation and depletion for the three months ended September 30, 2002 was $1.0 million compared with $0.8 million for the same period of 2001, an increase of 18 percent.  The increase in depreciation and depletion primarily resulted from an increase in the depletion rate per ton caused by a downward revision of coal reserves in 2001 and additional depreciation related to coal services capital projects.

 

Nine Months Ended September 30, 2002 Compared to Nine Months Ended June 30, 2001

    The following table sets forth operational and financial data for the Company's coal segment for the nine months ended September 30, 2002 and 2001:

Operations and Financial Summary

		Nine Months
		Ended September 30				Percent
		2002		2001		Change
		(in thousands)
Coal tons		10,614		11,682		(9%)
Average royalty per ton		$            2.21		$          2.09		6%
Revenues:
Coal royalties		$        23,437		$      24,415		(4%)
Timber sales		1,441		1,116		29%
Other income		4,072		2,887		41%
Total revenues		28,950		28,418		2%
Expenses
Operating		1,886		2,213		(15%)
Taxes other than income		663		478		39%
General and administrative		4,658		3,671		27%
Depreciation and depletion		2,558		2,116		21%
Total expenses		9,765		8,478		15%
Operating Income		$        19,185		$     19,940		(4%)

 

 

 

 

 

 

 

 

 

 

 

 

 

Coal royalties. Coal royalty revenue for the nine months ended September 30, 2002 was $23.4 million, compared with $24.4 million for the same period in 2001, a decrease of $1.0 million, or 4 percent.  The average royalty per ton increased by 6 percent over the respective periods because many of PVR's lessees entered into higher priced long-term contracts in the last half of 2001. However, production from PVR's lessees decreased 1.1 million tons, or 9 percent for the respective periods due to four mines being idled and a reduction in general market demand for coal.

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Timber sales. Timber revenue increased to $1.4 million for the nine months ended September 30, 2002 from $1.1 million for the same period in 2001, an increase of $0.3 million, or 29 percent.  Volume sold increased 1,613 Mbf, or 27 percent, to 7,492 Mbf in the first nine months of 2002 from 5,879 Mbf for the same period in 2001. The increase in volume sold was due to the timing of parcel sales.  In addition, an increase of 17 percent in the average price received primarily resulted from higher quality hardwoods being sold during the 2002 period.

Other income. Minimum rentals revenue, a component of other income, increased to $2.0 million for the nine months ended September 30, 2002 from $0.9 in the comparable period of 2001.  The increase was primarily due to a lessee rejecting PVR's lease in bankruptcy on August 31, 2002; consequently, all deferred revenue from this lessee ($0.8 million) was recognized as income.  Additionally, for the periods compared there was a $0.1 million increase due to the timing of rebates received for the use of a specific portion of railroad by one of PVR's lessees.

Operating. Operating expenses decreased by $0.3 million, or 15 percent, to $1.9 million for the nine months ended September 30, 2002, compared with $2.2 million in the same period of 2001.  The decrease was due to fewer tons mined by lessees on PVR subleased properties and less preventative maintenance necessary on certain properties.

Taxes other than income. Taxes other than income increased $0.2 million, or 39 percent, to $0.7 million for the nine months ended September 30, 2002, compared with $0.5 million in the same period of 2001. The variance was attributable to an increase in West Virginia franchise taxes, which was caused by a change from a corporate structure to a partnership structure in the third quarter of 2001 for the coal royalty and land management segment of the business.

General and administrative. General and administrative expenses increased to $4.7 million for the nine months ended September 30, 2002 from $3.7 million for the same period in 2001, an increase of $1.0 million, or 27 percent. The increase was primarily attributable to recurring fees and expenses associated with being a public entity, such as director's fees, tax reporting for the partners and fees for professional services.

Depreciation and depletion.  Depreciation and depletion for the nine months ended September 30, 2002 was $2.6 million compared with $2.1 million for the same period of 2001, an increase of 21 percent.  The increase in depreciation and depletion resulted from an increase in the depletion rate per ton caused by a downward revision of coal reserves in 2001 and additional depreciation related to coal services capital projects.

 

Corporate and Other

Revenues and expenses not directly related to either the oil and gas or coal royalty and land management segments are classified as corporate and other (or "All Other" in footnote 9. Segment Information in the accompanying unaudited financial statements).

For the three months ended September 30, 2002, net operating expenses related to corporate and other activities amounted to $2.0 million compared with $1.1 million for the same period of 2001, for an expense increase of $0.9 million, or 85 percent, primarily due to increased expenses related to the consideration of various shareholder proposals.

For the nine months ended September 30, 2002, net operating expenses related to corporate and other activities amounted to $4.9 million compared with $2.4 million for the same period of 2001, for an expense increase of $2.5 million, or 105 percent, primarily due to increased expenses related to the consideration of various shareholder proposals.

 

Liquidity and Capital Resources

    Funding for our activities has historically been provided by operating cash flows and bank borrowings.  Net cash provided by operating activities was $41.2 million for the nine months ended September 30, 2002, compared with $27.9 million for the nine months ended September 30, 2001. Excluding a pre-tax gain of $54.7 million on the sale of 3.3 million shares of Norfolk Southern Corporation common stock in April 2001, cash flows from operating activities decreased primarily due to the added expenses related the acquisition of certain South Texas oil and gas properties in the third quarter of 2001. 

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    For the nine months ended September 30, 2002, we used $32.0 million in investing activities, compared with $120.7 million for the nine months ended September 30, 2001. Additions to property and equipment totaled $45.7 million for the nine months ended September 30, 2002, compared with $180.2 million in the same period in 2001. The 2001 additions included the effects of the acquisition of certain South Texas oil and gas properties in the third quarter of 2001. The following table sets forth additions to property and equipment made during the periods indicated.

	Nine Months
	Ended September 30,
	2002		2001
	(in thousands)
Oil and gas
Development drilling	$    25,271		$     25,762
Exploratory drilling	1,056		6,677
Lease acquisitions	4,718		113,442
Field projects	1,497		538
Seismic and other *	3,578		1,759
Oil and gas capital expenditures	36,120		148,178
Coal royalty and land management (PVR)
Lease acquisitions	12,129		33,320
Support equipment and facilities	758		399
Coal royalty and land management capital expenditures	12,887		33,719
Other	310		100
Total capital expenditures	49,317		181,997
Less: Seismic and other  *	(3,578)		(1,759)
Additions to property and equipment	$45,739		$   180,238

 

 

 

 

 

 

 

 

 

 

 

 

 

* Included in exploration expense on the consolidated statements of income.

      We drilled 74 gross (53.2 net) wells for the nine months ended September 30, 2002, compared to 128 gross (100.3 net) wells in the same period in 2001.  All wells drilled in 2002 were development wells, including 71 gross successful wells and three gross wells that were unsuccessful for a success rate of 96 percent.  Capital expenditures for the remainder of year are expected to be $28.5 to $32.0 million, predominantly for the drilling of exploration and development wells in the oil and gas segment ($17.5 to $20.0 million), lease acquisitions and support equipment ($4.1 to $4.3 million), acquisition and evaluation of seismic data ($2.2 to $2.5 million), and the purchase of mining-related infrastructure in PVR ($4.8 to $5.0 million).  We continually review drilling expenditures and may increase, decrease or reallocate amounts based on industry conditions.  We believe our cash flow from operations and sources of debt financing are sufficient to fund our total 2002 planned capital expenditure program.

    As of September 30, 2002, we had approximately $63 million of unproved leasehold costs included in oil and gas properties on our consolidated balance sheet. We expect to complete our evaluation of our unproved leaseholds over the next two to three years. We assess our unproved leasehold costs on a property by property basis and a loss is recognized to the extent, if any, the cost of unproved leasehold has been impaired. Unproved leasehold costs for projects that are determined to be productive are transferred to proved leaseholds in the oil and gas properties section of our consolidated balance sheet.

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    Net cash used in financing activities totaled $9.5 million for the nine months ended September 30, 2002, compared to $92.0 million net cash provided by financing activities in the same period in 2001.  In addition to cash flow from operating activities, for the nine months ended September 30, 2002, we received $6.3 million in proceeds from borrowing, which was used to finance capital expenditures. Proceeds from borrowings in 2001 were used to finance the third quarter 2001 acquisition of certain South Texas oil and gas properties.

   Penn Virginia has a $150 million secured revolving credit facility (the "Revolver") with a final maturity of October 2004.  The Revolver currently has a borrowing base of $140 million and we had borrowed $11.0 million against it as of September 30, 2002.  We have the option to elect interest at (i) LIBOR plus a Eurodollar margin ranging from 1.375 to 1.875 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 0.375 to 0.875 percent.  The Revolver contains financial covenants requiring the Company to maintain certain levels of net worth and to comply with certain debt-to-capitalization and dividend limitation restrictions, among other requirements.  We are currently in compliance with all of the covenants in the Revolver.  We also currently have a $5.0 million line of credit and we had borrowed $15 thousand against it as of September 30, 2002.  The line of credit is due in March 2003, renewable annually. 

      The Partnership has a credit facility expiring in October 2004 comprised of a $50 million unsecured revolving credit loan (the "Partnership Revolver"), which was undrawn as of September 30, 2002, and a $43.4 million term loan (the "Term Loan"), $31.4 million of the $43.4 million outstanding under the term loan at September 30, 2002 was secured by United States treasury securities.  The Partnership Revolver provides for the option to elect interest at (i) LIBOR plus a Euro-rate margin ranging from 1.25 percent to 1.75 percent, based on certain financial data or (ii) the greater of the prime rate or federal funds rate plus 0.5 percent.  The Partnership has the option to elect interest on the secured portion of the Term Loan at (i) LIBOR plus a Euro-rate margin of 0.5 percent, based on certain financial data or (ii) the greater of the prime rate or federal funds rate plus 0.5 percent.  The unsecured portion of the Term Loan has the same interest rate election options as the Partnership Revolver.  The financial covenants of the Partnership's credit facility include, but are not limited to, maintaining: (i) a ratio of not more than 2.5:1.0 of total debt to consolidated EBITDA (as defined by the credit facility) and (ii) a ratio of not less than 4.00:1.00 of consolidated EBITDA to fixed charges. The Partnership is currently in compliance with all of its covenants.

    In January and February 2002, two of PVR's lessees filed for bankruptcy protection under Chapter 11 of the U.S. Bankruptcy Code.  One of the lessees, Horizon Resources (formerly AEI Resources, Inc.), has reorganized, is no longer in bankruptcy and has made all payments to PVR as required by its lease.  The other lessee, Pen Holdings, Inc., remains in bankruptcy and idled operations on PVR's property in March 2002.  Pen Holdings paid all required $200 thousand per month post-petition minimum rental payments through August 31, 2002, the date on which PVR recovered its lease from Pen Holdings.  Pen Holdings made an additional payment of $200 thousand to PVR in October 2002 in connection with PVR entering into an agreement whereunder PVR agreed to purchase certain infrastructure-related equipment and other assets integral to mining at Fork Creek for approximately $4.8 million plus approximately $0.6 million of stream mitigation obligations and the assumption of reclamation permits associated with the property, which PVR intends to assign to the next lessee of the property. The United States Bankruptcy Court for the Middle District of Tennessee issued an order approving Pen Holdings' sale of the Fork Creek assets to PVR on October 23, 2002.  Unless the order is appealed or amended, it will become final in early November 2002, and PVR expects to close the transaction promptly thereafter.  The purchase would be funded from the sale of U.S. Treasury notes held by PVR. PVR is currently seeking to find a lessee to replace Pen Holdings and is optimistic that a lessee will be found in the near future.  However, PVR may not be able to find a replacement lessee and, if PVR does find a replacement lessee, it may not be able to enter into a new lease on favorable terms within a reasonable period of time.  If PVR enters into a new lease, the replacement operator might not achieve the same levels of production or sell coal at the same price as did Pen Holdings at the inception of the Pen Holdings lease.

    Management believes its sources of funding are sufficient to meet short and long-term liquidity needs of the Company.

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Legal and Environmental

        Mountaintop Removal Litigation.  On May 8, 2002, the United States District Court for the Southern District of West Virginia issued an order, which it thereafter clarified in response to defendants' motion to do so, enjoining the Huntington, West Virginia office of the U.S. Army Corps of Engineers from issuing permits under Section 404 of the Clean Water Act for the construction of valley fills for the disposal of overburden from mining operations.  These valleys typically contain streams that, under the Clean Water Act, are considered navigable waters of the United States.  The court held that the filling of these waters with overburden solely for waste disposal is a violation of the Clean Water Act.  If the injunction is not overturned by an appellate court or subsequent legislation, PVR's lessees may not be able to obtain permits in many cases to use these common fill activities, which could render their mining operations uneconomical.  Any consequent reduction or cessation of their operations would reduce mining on PVR's properties and PVR's coal royalty revenue.

     Legislation of Weight.  During its 2002 session, the West Virginia House of Representatives considered legislation that, if passed, would have significantly increased the scope of powers available to enforce the current weight restrictions on trucks carrying coal.  Past sessions of the legislature have considered, but not adopted, similar legislation.  The legislature and the governor appointed a task force to study the issue, and the task force issued a report recommending legislation that would raise the weight limits on the trucks, but also would increase the number of required safety inspections and the amounts of registration fees and fines imposed for violations.  The legislature has not yet acted on this recommendation.  If there is increased enforcement of existing weight restrictions, the costs of transporting coal in the state would increase.  An increase in transportation costs could have an adverse effect on PVR's lessees' ability to increase or to maintain production on PVR's properties and a similar adverse effect on PVR's coal royalty revenue.

 

Recent Accounting Pronouncements

     In June 2001, the Financial Accounting Standards Board ("FASB") issued SFAS No. 143, Accounting for Asset Retirement Obligations. This statement requires companies to record a liability relating to the future retirement and removal of assets used in their business. The liability is discounted to its present value, and the related asset value is increased by the amount of the resulting liability. Over the life of the asset, the liability will be accreted to its future value and eventually extinguished when the asset is taken out of service. The provisions of this statement are effective for fiscal years beginning after June 15, 2002.  We are currently evaluating the future financial reporting effect of adopting SFAS No. 143 and will complete such assessment during the fourth quarter of 2002.  We will adopt the standard effective January 1, 2003.

      In April 2002, the FASB issued SFAS No. 145, Rescission of FASB Statements No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical Corrections. This statement rescinds SFAS No. 4, Reporting Gains and Losses from Extinguishment of Debt, which required all gains and losses from extinguishment of debt to be aggregated and, if material, classified as an extraordinary item of debt to be aggregated and, if material, classified as an extraordinary item, net of income taxes.  As a result, the criteria in Accounting Principles Board Opinion (APB) Opinion No. 30 will now be used to classify those gains and losses. Any gain or loss on the extinguishment of debt that was classified as an extraordinary item in prior periods presented that does not meet the criteria in APB Opinion No. 30 for classification as an extraordinary item shall be reclassified. The provisions of this statement are effective for fiscal years beginning after January 1, 2003. Under present conditions, management does not expect the initial adoption of SFAS No. 145 to have a material effect on the financial position, results of operations or liquidity of the Company.

      In June 2002, the FASB issued SFAS No. 146, Accounting for Costs Associated with Exit or Disposal Activities. This statement requires the recognition of costs associated with exit or disposal activities when they are incurred rather than at the date of a commitment to an exit or disposal plan. The provisions of this statement are effective for exit or disposal activities initiated after December 31, 2002. Under present conditions, management does not expect the initial adoption of SFAS No. 146 to have a material effect on the financial position, results of operations or liquidity of the Company.

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Quantitative and Qualitative Disclosures about Market Risk 

    Our price risk management program permits the utilization of fixed-price contracts and financial instruments (such as futures, forward and 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 contracts and financial instruments are designed as cash flow hedges and accounted for in accordance with SFAS No. 133, as amended by SFAS No. 137 and SFAS No. 138. 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 and liabilities are significantly affected by energy price fluctuations. The following table sets forth our positions as of September 30, 2002:

	Notional	Fixed Price or
Time Period	Quantities	Effective Floor/Ceiling Price	Fair Value
			(in thousands)
Natural Gas	(MMbtu per Day)
Costless collars
October 1 - December 31, 2002	2,301	$4.00 / $5.70	$                 56
October 1 - December 31, 2002	1,315	$4.00 / $6.25	34
November 1 - December 31, 2002	8,000	$2.96 / $5.05	(74)
January 1 - March 31, 2003	10,000	$2.96 / $5.05	(253)
January 1 - September 30, 2003	5,000	$3.47 / $5.20	(84)
April 1- October 31, 2003	5,000	$2.92 / $4.42	(325)
Crude Oil	(Bbls per Day)
Costless collars
October 1 - December 31, 2002	263	$20.00 / $24.50	(177)
October 1 - December 31, 2002	197	$22.00 / $26.60	(85)
October 1 - December 31, 2002	303	$22.00 / $26.20	(89)
January 1 - September 30, 2003	500	$23.00 / $28.75	(60)
Total			$          (1,057)

     

   

 

 

 

 

 

 

 

 

 

 

    Based upon our assessment of our derivative contracts at September 30, 2002, we reported (i) an approximate liability of $1.2 million and an asset of $0.1 million and (ii) a loss in accumulated other comprehensive income of $0.8 million, net of related income taxes of $0.4 million.  In connection with monthly settlements, we recognized net hedging losses in natural gas and oil revenues of $0.4 million for the nine months ended September 30, 2002.  Based upon future oil and natural gas prices as of September 30, 2002, $1.1 million of hedging losses are expected to be realized within the next 13 months.  The amounts ultimately realized will vary due to changes in the fair value of the open derivative contracts prior to settlement.    Market risk is the risk of loss arising from adverse changes in market rates and prices. The principal market risks to which PVR is exposed are interest rate risk and coal price risks. PVR's current term loan debt is partially secured by U.S. Treasury notes and has limited interest risk exposure. However, debt incurred in the future under the current PVA and PVR credit facilities will bear variable interest at either the applicable base rate or a rate based on LIBOR.

      From a PVR perspective, we are also exposed to credit risk if lessees do not manage their operations and finances well or if there is a significant decline in coal prices.  Lessees may not be able to pay their debts as they become due or coal royalty revenues could decrease due to decreased production volumes.  See Item 2. "Liquidity and Capital Resources" for a discussion of recent occurrences related to credit risk.

 

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 within the meaning of Section 21E of the Securities Exchange Act of 1934, as amended, and Section 27A of the Securities Act of 1933, as amended. In addition, we and our representatives may from time to time make other oral or written statements that are also forward-looking statements.

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    Such forward-looking statements include, among other things, statements regarding development activities, capital expenditures, acquisitions and dispositions, drilling and exploration programs, expected commencement dates and projected quantities of future oil and natural gas production by Penn Virginia, expected commencement dates and projected quantities of future coal production by lessees producing coal from reserves leased from PVR and costs and expenditures, as well as projected demand, or supply, for coal and oil and natural gas, all of which may affect sales levels, prices and royalties realized by Penn Virginia and PVR.

    These forward-looking statements are made based upon management's current plans, expectations, estimates, assumptions and beliefs concerning future events impacting Penn Virginia and PVR and, therefore, involve a number of risks and uncertainties.  Penn Virginia cautions 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 operations or financial condition of Penn Virginia to differ materially from those expressed or implied in the forward-looking statements include, but are not limited to: the cost of finding and successfully developing oil and natural gas reserves; the cost to PVR of finding new coal reserves; the ability of Penn Virginia to acquire new oil and natural gas reserves and of PVR to acquire new coal reserves on satisfactory terms; the price for which such reserves can be sold; the volatility of commodity prices for oil and natural gas and coal; the risks associated with having or not having price risk management programs; 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; Penn Virginia's ability to obtain adequate pipeline transportation capacity for its oil and natural gas production; competition among producers in oil and natural gas industries generally and in the coal industry generally and in Appalachia in particular; the extent to which the amount and quality of actual production differs from estimated recoverable and proved oil and natural gas reserves and coal reserves; unanticipated geological problems; availability of required 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 Penn Virginia's oil and natural gas production and PVR's lessees' mining operations; environmental risks affecting the drilling and producing of oil and natural gas wells or the mining of coal reserves; the timing of receipt of necessary governmental permits by Penn Virginia and PVR's lessees; 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 mountaintop removal litigation and issues regarding coal truck weight restriction enforcement and legislation; risks and uncertainties relating to general domestic and international economic (including inflation and interest rates) and political conditions; and the experience and financial condition of the lessees of PVR's coal reserves, including their ability to satisfy their royalty, environmental, reclamation and other obligations to PVR and others.  Many of such factors are beyond Penn Virginia's ability to control or predict.  Readers are cautioned not to put undue reliance on forward-looking statements.

    While Penn Virginia periodically reassesses material trends and uncertainties affecting Penn Virginia's 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 Penn Virginia's quarterly, annual or other reports filed with the Securities and Exchange Commission, Penn Virginia does 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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PART II  Other Information

Items 1, 2, 3 and 5 are not applicable and have been omitted.

Item 4.  Controls and Procedures

(a)  Evaluation of Disclosure Controls and Procedures:

     Within the 90 day period prior to the filing date of this Quarterly Report on Form 10-Q, 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 Securities and Exchange Act Rule 13a-14(c)). 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

     No significant changes were made in the Company's internal controls or in other factors that could significantly affect these controls subsequent to the evaluation described in Item 4(a).

 

Item 6.  Exhibits and Reports on Form 8-K

(a)           Exhibits

99.1              Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-

                     Oxley Act of 2002

 

99.2              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

                      None.

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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 1, 2002				By:	/s/ Frank A. Pici
						Frank A. Pici
						Executive Vice President and
						Chief Financial Officer
Date:	November 1, 2002				By:	/s/ Dana G. Wright
						Dana G. Wright, Vice President and
						Principal Accounting Officer

 

 

 

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CERTIFICATIONS

 

I, A. James Dearlove, President and Chief Executive Officer of Penn Virginia    Corporation (the "Registrant"), certify that:

 

1.        I have reviewed this quarterly report on Form 10-Q of the Registrant;

 

2.        Based on my knowledge, this quarterly report does not contain any untrue statement of a material fact or omit to state 

           a material fact necessary to make the statements made, in light of the circumstances under which such statements were

           made, not misleading with respect to the period covered by this quarterly report;

 

3.        Based on my knowledge, the financial statements, and other financial information included in this quarterly report, fairly

           present in all material respects the financial condition, results of operations and cash flows of the Registrant as of, and

           for, the periods presented in this quarterly report;

 

4.        The Registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and

            procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the Registrant and we have:

 

a)       designed such disclosure controls and procedures to ensure that material information relating to the

          Registrant, including its consolidated subsidiaries, is made known to us by others within those entities,

          particularly during the period in which this quarterly report is being prepared;

 

b)       evaluated the effectiveness of the Registrant's disclosure controls and procedures as of a date within 90

          days prior to the filing date of this quarterly report (the "Evaluation Date"); and

 

c)       presented in this quarterly report our conclusions about the effectiveness of the disclosure controls and

          procedures based on our evaluation as of the Evaluation Date;

5.        The Registrant's other certifying officer and I have disclosed, based on our most recent evaluation, to the Registrant's

           auditors and the audit committee of Registrant's board of directors:

 

a)       all significant deficiencies in the design or operation of internal controls which could adversely affect the

          Registrant's ability to record, process, summarize and report financial data and have identified for the

          Registrant's auditors any material weaknesses in internal controls; and

 

b)       any fraud, whether or not material, that involves management or other employees who have a significant

          role in the Registrant's internal controls; and

 

6.        The Registrant's other certifying officer and I have indicated in this quarterly report whether or not there were significant

           changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of

           our most recent evaluation, including any corrective actions with regard to significant deficiencies and material

           weaknesses.

 

Date:             November 1, 2002                            

 

     /s/ A. James Dearlove                                                      

                                                                              A.  James Dearlove

                                                                              President and Chief Executive Officer

 

 

 

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I, Frank A. Pici, Executive Vice President and Chief Financial Officer of Penn Virginia   Corporation (the "Registrant"), certify

      that:

 

1.        I have reviewed this quarterly report on Form 10-Q of the Registrant;

 

2.       Based on my knowledge, this quarterly report does not contain any untrue statement of a material fact or omit to state

          a material fact necessary to make the statements made, in light of the circumstances under which such statements were

          made, not misleading with respect to the period covered by this quarterly report;

 

3.       Based on my knowledge, the financial statements, and other financial information included in this quarterly report, fairly

          present in all material respects the financial condition, results of operations and cash flows of the Registrant as of, and

          for, the periods presented in this quarterly report;

 

4.       The Registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and

          procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the Registrant and we have:

 

a)      designed such disclosure controls and procedures to ensure that material information relating to the

         Registrant, including its consolidated subsidiaries, is made known to us by others within those entities, 

         particularly during the period in which this quarterly report is being prepared;

 

b)     evaluated the effectiveness of the Registrant's disclosure controls and procedures as of a date within 90

        days prior to the filing date of this quarterly report (the "Evaluation Date"); and

 

c)     presented in this quarterly report our conclusions about the effectiveness of the disclosure controls and procedures based

        on our evaluation as of the Evaluation Date;

 

5.        The Registrant's other certifying officer and I have disclosed, based on our most recent evaluation, to the Registrant's auditors and the

           audit committee of Registrant's board of directors:

 

a)       all significant deficiencies in the design or operation of internal controls which could adversely affect the Registrant's 

          ability to record, process, summarize and report financial data and have identified for the Registrant's auditors any

           material weaknesses in internal controls; and

 

b)       any fraud, whether or not material, that involves management or other employees who have a significant role in the

           Registrant's internal controls; and

 

6.        The Registrant's other certifying officer and I have indicated in this quarterly report whether or not there were significant changes in

            internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent

           evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.

 

Date:             November 1, 2002                            

 

 

 /s/ Frank A. Pici                                                          

                                                                                  Frank A. Pici

  Executive Vice President and Chief Financial Officer

 

 

 

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