PENN VIRGINIA CORP - 10-Q Quarterly Report

PART I. Financial Information	PAGE

Item 1. Financial Statements

Consolidated Statements of Income for the Three and Nine Months Ended September 30, 2004 and 2003	3

Consolidated Balance Sheets as of September 30, 2004, and December 31, 2003	4

Consolidated Statements of Cash Flows for the Three and Nine Months Ended September 30, 2004 and 2003	5

Notes to Consolidated Financial Statements	6

Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations	13

Item 3. Quantitative and Qualitative Disclosures about Market Risk	30

Item 4. Controls and Procedures	32

PART II. Other Information

Item 6. Exhibits and Reports on Form 8-K	33

PART I.
Financial Information

Item 1. Financial Statements

PENN VIRGINIA CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME - Unaudited

(in thousands, except per share data)

	Three Months		Nine Months
	Ended September 30,		Ended September 30,
	2004	2003	2004	2003
Revenues
Natural gas	$ 29,530	$ 23,293	$ 95,938	$ 79,197
Oil and condensate	3,351	5,372	9,869	13,999
Coal royalties	18,018	11,960	52,395	35,658
Coal services	888	484	2,614	1,523
Timber	204	80	499	829
Other	750	832	1,621	2,534
Total revenues	52,741	42,021	162,936	133,740

Expenses
Lease operating	5,236	4,092	15,549	11,965
Exploration	7,508	3,752	14,903	11,714
Taxes other than income	2,682	2,854	8,176	8,922
General and administrative	6,643	6,302	18,074	18,140
Depreciation, depletion and amortization	13,179	12,265	40,722	36,623
Total expenses	35,248	29,265	97,424	87,364

Operating income	17,493	12,756	65,512	46,376

Other income (expense)
Interest expense	(1,719)	(1,380)	(4,573)	(3,837)
Interest and other income	274	301	806	951
Income before minority interest, income taxes and
cumulative effect of change in accounting principle	16,048	11,677	61,745	43,490
Minority interest	5,073	2,936	14,271	8,778
Income tax expense	4,541	3,298	18,818	13,784
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

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

Weighted average shares outstanding, basic	18,357	17,992	18,268	17,948
Weighted average shares outstanding, diluted	18,574	18,138	18,452	18,064

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

PENN VIRGINIA CORPORATION AND
SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(in thousands, except share data)

	September 30, 2004		December 31, 2003

	(Unaudited)
ASSETS
Current assets
Cash and cash equivalents	$ 19,584		$ 18,008
Accounts receivable	30,068		31,789
Inventory	1,111		246
Prepaid expenses	4,930		1,018
Other	1,104		844
Total current assets	56,797		51,905
Property and equipment
Oil and gas properties (successful efforts method)	583,015		503,290
Other property and equipment	274,504		272,447
Less: Accumulated depreciation, depletion and amortization	(190,403)		(149,934)
Net property and equipment	667,116		625,803
Equity investments	28,607		-
Other assets	5,068		6,025
Total assets	$ 757,588		$ 683,733

LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities
Current maturities of long-term debt	$ 4,800	$ 1,500
Accounts payable	4,968	9,911
Accrued liabilities	19,420	19,153
Hedging liabilities	6,409	2,678
Total current liabilities	35,597	33,242

Other liabilities	18,296	15,188
Hedging liabilities	691	998
Deferred income taxes	89,959	77,863
Long-term debt of the Company	73,000	64,000
Long-term debt of PVR	113,093	90,286
Minority interest in PVR	189,700	190,508

Shareholders' equity
Preferred stock of $100 par value -100,000 authorized shares; none issued	-	-
Common stock of $0.01 par value at September 30, 2004, and $6.25 at December 31, 2003 - 32,000,000 shares authorized; 18,358,148 and 18,104,832 shares issued and outstanding at September 30, 2004, and December 31, 2003, respectively (9,052,416 pre-split shares issued and outstanding at December 31, 2003)	184	56,576
Paid-in capital	76,474	14,497
Retained earnings	166,098	143,619
Accumulated other comprehensive income	(4,511)	(2,250)
	238,245	212,442
Less: Unearned compensation and ESOP	(993)	(794)
Total shareholders' equity	237,252	211,648
Total liabilities and shareholders' equity	$ 757,588	$ 683,733

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

PENN VIRGINIA CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS - Unaudited

(in thousands)

	Three Months		Nine Months
	Ended September 30		Ended September 30,
	2004	2003	2004	2003

Cash flows from operating activities
Net income	$ 6,434	$ 5,443	$ 28,656	$ 22,291
Adjustments to reconcile net income to net
cash provided by operating activities:
Depreciation, depletion and amortization	13,179	12,265	40,722	36,623
Minority interest	5,073	2,936	14,271	8,778
Deferred income taxes	6,350	4,360	13,314	10,495
Dry hole and unproved leasehold expense	6,676	2,490	9,322	4,098
Cumulative effect of change in accounting principle	-	-	-	(1,363)
Other	243	408	2,379	1,363
Changes in operating assets and liabilities:
Accounts receivable	2,611	(582)	1,721	(12,261)
Other current assets	1,243	512	(5,158)	267
Accounts payable and accrued expenses	933	(6,334)	(7,730)	(1,333)
Other assets and liabilities	(1,147)	1,437	2,697	1,946
Net cash provided by operating activities	41,595	22,935	100,194	70,904

Cash flows from investing activities
Additions to property and equipment	(38,302)	(22,976)	(87,931)	(98,083)
Equity investments	(28,442)	-	(28,442)	-
Other	800	236	1,423	547
Net cash used in investing activities	(65,944)	(22,740)	(114,950)	(97,536)

Cash flows from financing activities
Dividends paid	(2,065)	(2,023)	(6,176)	(6,061)
Distributions paid to minority interest holders of PVR	(5,556)	(5,313)	(16,335)	(14,566)
Proceeds from borrowings of the Company	15,000	5,000	25,000	44,399
Repayments of borrowings of the Company	(5,000)	(367)	(16,000)	(2,451)
Proceeds from borrowings of PVR	28,500	-	28,500	90,000
Repayments of borrowings of PVR	(1,500)	-	(2,500)	(88,387)
Payments for debt issuance costs	-	-	-	(1,419)
Issuance of stock and other	40	479	3,843	1,663
Net cash provided by (used in) financing activities	29,419	(2,224)	16,332	23,178

Net increase (decrease) in cash and cash equivalents	5,070	(2,029)	1,576	(3,454)
Cash and cash equivalents - beginning of period	14,514	11,916	18,008	13,341
Cash and cash equivalents - end of period	$ 19,584	$ 9,887	$ 19,584	$ 9,887

Supplemental disclosures
Cash paid during the periods for:
Interest (net of amounts capitalized)	$ 2,772	$ 2,698	$ 5,788	$ 3,668
Income taxes	$ 494	$ 268	$ 4,103	$ 6,348
Noncash investing and financing activities
Issuance of PVR units for acquisition	$ -	$ -	$ 1,060	$ 4,969

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

PENN VIRGINIA CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Unaudited

September 30, 2004

1.
BASIS OF PRESENTATION

The accompanying unaudited consolidated
financial statements include the accounts of Penn Virginia Corporation
("Penn Virginia", "PVA", the "Company",
"we" or "our"), all wholly-owned subsidiaries of the
Company, and Penn Virginia Resource Partners, L.P. (the "Partnership"
or "PVR") of which we indirectly own the sole two percent general
partner interest and an approximately 42.5 percent limited partner interest.
The financial statements have been prepared in accordance with accounting
principles generally accepted in the United States of America for interim
financial reporting and Securities and Exchange Commission ("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 our
consolidated financial statements and footnotes included in our Annual Report
on Form 10-K for the year ended December 31, 2003. Our accounting policies are
consistent with those described in our Annual Report on Form 10-K for the year
ended December 31, 2003. Please refer
to such Form 10-K for further discussion of those policies. Operating results for the nine months ended
September 30, 2004, are not necessarily indicative of the results that may be
expected for the year ended December 31, 2004.
Certain reclassifications have been made to conform to the current
period's presentation.

2. STOCK-BASED COMPENSATION

We have stock compensation plans that
allow, among other grants, incentive and nonqualified stock options to be
granted to key employees and officers and nonqualified stock options to be
granted to directors. We account for
those plans under the recognition and measurement principles of Accounting
Principles Board ("APB") Opinion No. 25, Accounting for Stock
Issued to Employees, and related Interpretations. No stock-based employee compensation cost
related to stock options is reflected in net income, as all options granted
under those plans had an exercise price equal to the market value of the
underlying common stock on the date of grant.
The following table illustrates the effect on net income and earnings
per share as if we had applied the fair value recognition provision of
Statement of Financial Accounting Standards ("SFAS") No. 123, Accounting
for Stock-Based Compensation, to stock-based employee options (in
thousands, except per share data).

	Three Months		Nine Months
	Ended September 30,		Ended September 30,
	2004	2003	2004	2003
Net income, as reported	$ 6,434	$ 5,443	$ 28,656	$ 22,291
Add: Stock-based employee compensation expense included in reported net income related to restricted units and director compensation, net of related tax effects	124	52	341	276
Less: Total stock-based employee compensation expense determined under fair value based method for all awards, net of related tax effects	(257)	(244)	(797)	(877)
Pro forma net income	$ 6,301	$ 5,251	$ 28,200	$ 21,690
Earnings per share
Basic - as reported	$ 0.35	$ 0.30	$ 1.57	$ 1.25
Basic - pro forma	$ 0.34	$ 0.29	$ 1.54	$ 1.21
Diluted - as reported	$ 0.35	$ 0.30	$ 1.55	$ 1.24
Diluted - pro forma	$ 0.34	$ 0.29	$ 1.53	$ 1.20

3. ASSET RETIREMENT OBLIGATIONS

Effective January 1, 2003, we adopted
SFAS No. 143, Accounting for Asset Retirement Obligations, which
addresses financial accounting and reporting for obligations associated with
the retirement of tangible long-lived assets and the associated asset
retirement costs. The Standard applies
to legal obligations associated with the retirement of long-lived assets that
result from the acquisition, construction, development or normal use of such
assets.

The fair
value of a liability for an asset retirement obligation is recognized in the
period in which it is incurred if a reasonable estimate of fair value can be
made. The fair value of the liability
is also added to the carrying amount of the associated asset and is depreciated
over the life of the asset. The
liability is accreted through a charge to accretion expense, which is recorded
as additional depreciation, depletion and amortization. If the obligation is settled for other than
the carrying amount of the liability, we will recognize a gain or loss on
settlement.

Below is a
reconciliation of the beginning and ending aggregate carrying amount of our
asset retirement obligations as of September 30, 2004 (in thousands).

Balance, January 1, 2004	$ 3,389
Liabilities incurred in the current period	268
Liabilities settled in the current period	(108)
Accretion expense	165
Balance, September 30, 2004	$ 3,714

4. HEDGING ACTIVITIES

Commodity Cash
Flow Hedges

The fair values of our hedging
instruments are determined based on third party forward price quotes for NYMEX
Henry Hub gas and West Texas Intermediate crude oil closing prices as of September
30, 2004. The following table sets forth our positions as of September 30,
2004:

	Average	Weighted Average Price			Estimated
	Volume	Swaps	Collars		Fair Value
	Per Day		Floor	Ceiling	(in thousands)

Natural gas hedging positions	(in MMbtus)	(per MMbtu)
Fourth Quarter 2004
Costless Collars	19,837		$ 4.13	$ 6.54	$ (1,139)
Swaps	1,234	$ 4.70			(226)
First Quarter 2005
Costless Collars	21,656		4.60	7.12	(2,585)
Swaps (January only)	1,100	4.70			(114)
Second Quarter 2005
Costless Collars	18,330		4.87	7.04	(573)
Third Quarter 2005
Costless Collars	18,000		5.06	7.12	(506)
Fourth Quarter 2005
Costless Collars	17,000		5.29	8.96	44
First Quarter 2006
Costless Collars	9,133		5.55	8.68	(92)
Second Quarter 2006 (April only)
Costless Collars	5,000		6.00	8.19	94

Crude oil hedging positions	(in Bbls)	(per Bbl)
Fourth Quarter 2004
Swaps	482	30.41			(1,048)
First Quarter 2005 (January only)
Swaps	400	30.13			(218)

Total					$ (6,363)

Based upon our assessment of
our derivative contracts designated as cash flow hedges at September 30, 2004,
we reported (i) a net hedging liability of approximately $6.4 million and (ii)
a loss in accumulated other comprehensive income of $4.1 million, net of a
related income tax benefit of $2.3 million. In connection with monthly
settlements, we recognized net hedging losses in natural gas and oil revenues
of $1.2 million and $3.7 million for the three months and nine months ended
September 30, 2004, respectively. Based upon future oil and natural gas prices
as of September 30, 2004, $6.4 million of hedging losses are expected to be
realized within the next 12 months. The amounts that we ultimately realize will
vary due to changes in the fair value of the open derivative contracts prior to
settlement. We recognized net hedging losses of $0.7 million and $6.2 million
for the three months and nine months ended September 30, 2003, respectively.

Interest Rate Swap

In connection
with its senior unsecured notes, PVR entered into an interest rate swap
agreement with a notional amount of $29.5 million to hedge a portion of the
fair value of those notes which mature over a ten-year period. This swap was
designated as a fair value hedge and has been reflected as a decrease of
long-term debt of approximately $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 PVR a fixed annual rate of
5.77 percent on a total notional amount of $29.5 million, and PVR pays the
counterparty a variable rate equal to the floating interest rate which is based
on the six month London Interbank Offering Rate plus 2.36 percent.

5. LONG-TERM DEBT

At September 30, 2004, and
December 31, 2003, long-term debt consisted of the following (in thousands):

	September 30, 2004	December 31, 2003
	September 30, 2004	December 31, 2003
	(Unaudited)

Penn Virginia revolving credit facility	$ 73,000	$ 64,000
PVR senior unsecured notes*	87,893	89,286
PVR revolving credit facility	30,000	2,500
	190,893	155,786
Less: Current maturities	(4,800)	(1,500)
	$ 186,093	$ 154,286

* 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 .

6. COMMITMENTS AND CONTINGENCIES

Legal

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.

Data Licensing
Agreement

In November
2003, we purchased from a provider of seismic data a license to access 5,000
square miles of 3-D seismic data over the next two years. We paid $5.0 million in the first quarter of
2004. As of September 30, 2004, $3.4 million, representing prepaid license
fees, was recorded in other current assets. Such amounts are expensed as data
is received. We have a remaining
commitment of $4.0 million to be paid in the first quarter of 2005.

Firm
Transportation Agreements

In July 2004,
we entered into a contract which provides firm transportation capacity rights for
15,000 MMbtu per day on a pipeline system for ten years beginning November 1,
2004. The contract requires us to pay transportation demand charges regardless
of the amount of pipeline capacity we use.
In October 2004, we entered into another firm transportation contract
for 7,000 MMbtu per day with a term of
three years beginning November 1, 2004. Total minimum payments over the terms
of both contracts will be approximately $13.8 million. All transportation costs, including demand
charges, are expensed as they are incurred.

7. PENSION PLANS AND OTHER POSTRETIREMENT
BENEFITS

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):

width=3 colspan=2>

width=5>

	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	$ 44	$ 46		$ 132	$ 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.

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	$ 5,610	$ 4,037	$ 26,395	$ 22,579

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:

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

		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.

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.

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.

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.

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		29,530			5.85		23,293			4.93
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.

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,
	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.

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).

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	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	207					595
Total revenues	106,014			5.91		93,791			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	$ 42,536			$ 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.

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.

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		299

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.

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.

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.

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.

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.

width=1>

	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.

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.

width=1>

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	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	17	8
Loss before income taxes	$ (6,534)	$ (8,045)

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.

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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	8,942	9,066	18,008
Cash and cash equivalents - end of period	$ 3,820	$ 15,764	$ 19,584

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

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	$ 123,566	$ 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.

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.

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.

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.

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.

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.

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

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 10-Q
(Mark One)

[ X ] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended September 30, 2004

Or

[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from	to


Commission File Number 1-13283

PENN VIRGINIA CORPORATION
(Exact Name of Registrant as Specified in Its Charter)

Virginia	23-1184320
(State or Other Jurisdiction of	(I.R.S. Employer
Incorporation or Organization)	Identification No.)

THREE RADNOR CORPORATE CENTER, SUITE 230
100 MATSONFORD ROAD
RADNOR, PA 19087
(Address of Principal Executive Office)	(Zip Code)

(610) 687-8900
(Registrant's Telephone Number, Including Area Code)


(Former Name, Former Address and Former Fiscal Year, if Changed Since Last Report)

Indicate by check mark whether the Registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of
the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the Registrant
was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.
	Yes	X	No
Indicate by check mark whether the Registrant is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act).
	Yes	X	No
As of November 1, 2004, 18,368,602 shares of common stock of the Registrant were issued and outstanding.

Operating income

Income before income taxes and minority interest

Income before minority interest, income taxes and cumulative effect of change in accounting principle

Minority interest

Cumulative effect of change in accounting principle

Income before income taxes

Three Months Ended September 30,

Nine Months Ended September 30,

Income before income taxes and
minority interest

Income
before minority interest, income taxes and

cumulative effect of change in accounting principle

Income
before income taxes