UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
XANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
For the Fiscal Year Ended December 31,
2000 or TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 19342002Commission File Number 0-753
PENN VIRGINIA CORPORATION
One Radnor Corporate Center, Suite 200
100 Matsonford Road
Radnor, PA 19087
Registrant'sRegistrant’s telephone number, including area code: (610) 687-8900
Incorporated in I.R.S Employer Identification Number VIRGINIA 23-1184320
Incorporated in | I.R.S. Employer Identification Number | |
VIRGINIA | 23-1184320 |
Securities registered pursuant to section 12(b) of the Act: None
Securities Registered pursuant to Section 12(g) of the Act:
Title of Each Class
Title of Each Class | Name of | |
Common Stock, $6.25 Par Value | New York Stock Exchange |
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 Xx No ¨
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant'sregistrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. The¨
Indicate by check mark whether registrant is an accelerated filer (as defined in Rule 12b-2 of the Act). Yes x No ¨
State the aggregate market value of the voting stockand non-voting common equity held by non-
affiliatesnon-affiliates computed by reference to the price at which the common equity was last sold, or the average bid and asked price of such common equity, as of the Corporation at February 14, 2001 was
$280,018,348, based onlast business day of the closing price of $32.90 per share. registrant’s most recently completed second fiscal quarter. $348,612,796.
As of that date, 8,511,196February 27, 2003, 8,947,418 shares of common stock of the registrant were issued and outstanding. The number of shareholders of record of the
registrant was 778 as of February 14, 2001.
DOCUMENTS INCORPORATED BY REFERENCE:
Part Into
Which Incorporated
(1) Proxy Statement for Stockholder Meeting on May 1, 2001 PartIII
Part Into Which Incorporated | ||
(1) Proxy Statement for Annual Shareholders Meeting on May 6, 2003 | Part III. |
Penn Virginia Corporation and Subsidiaries
Part I
1.Business
2.Properties
3.Legal Proceedings
4.Submission of Matters to a Vote of Security Holders
Part II
5.Market for the Company's Common Stock and Related Stockholder Matters
6.Selected Financial Data
7.Management's Discussion and Analysis of Financial Condition and Results
of Operations
8.Financial Statements and Supplementary Data
9.Changes In and Disagreements with Accountants on Accounting and
Financial Disclosure
Part III
10. Directors and Executive Officers of the Registrant
11. Executive Compensation
12. Security Ownership of Certain Beneficial Owners and Management
13. Certain Relationships and Related Transactions
Part IV
14. Exhibits, Financial Statement Schedules and Reports on Form 8-K
Part I | ||||
1. | 3 | |||
2. | 14 | |||
3. | 18 | |||
4. | 18 | |||
Part II | ||||
5. | Market for the Registrant’s Common Stock and Related Shareholder Matters | 19 | ||
6. | 20 | |||
7. | Management’s Discussion and Analysis of Financial Condition and Results of Operations | 21 | ||
8. | 41 | |||
9. | Changes In and Disagreements with Accountants on Accounting and Financial Disclosure | 73 | ||
Part III | ||||
10. | 73 | |||
11. | 73 | |||
12. | Security Ownership of Certain Beneficial Owners and Management | 73 | ||
13. | 73 | |||
14. | 73 | |||
Part IV | ||||
15. | Exhibits, Financial Statement Schedules, and Reports on Form 8-K | 74 |
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Part 1
General
Penn Virginia Corporation ("(“Penn Virginia"Virginia” or the "Company"“Company”) is a Virginia corporation founded in 1882. The Company isWe are engaged in the exploration, development and production of oil and natural gas primarily in the eastern and Gulf Coast onshore areas of the collection ofUnited States. We also collect royalties and overriding royalty
interests on various oil and gas properties as well as the
leasing of coalin which we own a mineral rights and the collection of related
royalties.
Penn Virginia explores for, develops and produces crude oil,
condensate and natural gas in the eastern and southern portions
of the United States. The Companyfee interest. At December 31, 2002, we had proved reserves of 71,000approximately 5.4 million barrels of oil and condensate and 174241 billion cubic feet (Bcf) of natural gas, or 273 billion cubic feet equivalent (“Bcfe”).
Until October 30, 2001, we also engaged directly in the leasing and management of coal properties in the Central Appalachian region of the United States. In September 2001, we transferred our coal properties and related assets and liabilities to Penn Virginia Resource Partners, L.P. (the “Partnership” or “PVR”), a newly formed Delaware limited partnership. On October 30, 2001, the Partnership completed its initial public offering (“IPO”) of approximately 7.5 million common units at $21.00 per unit, which are traded on the New York Stock Exchange under the symbol PVR. At December 31, 2002, the Partnership owned approximately 615 million tons of proven and probable coal reserves, including approximately 120 million tons of such reserves that were acquired in December 2002 related to a strategic alliance with Peabody Energy Corporation (“Peabody”). The Partnership’s coal reserves are located on 241,000 acres in Virginia, West Virginia, New Mexico and eastern Kentucky. The Partnership does not operate any mines, but has leased its reserves under 51 leases to 28 different operators who mine coal at 61 mines in exchange for royalty payments to PVR. Lessees other than those which are affiliates of Peabody (the “Peabody Lessees”) are generally required to make royalty payments to the Partnership based on the amount of coal they produce from the Partnership’s properties and the price at which they sell the coal, subject to fixed minimum royalty rates per ton. The Peabody Lessees are required to make payments based on fixed royalty rates which escalate annually. In managing its properties, PVR actively works with its lessees to develop efficient methods to exploit reserves and to maximize production from properties. Additionally, the Partnership provides fee-based coal preparation and transportation facilities to some of its lessees to generate coal service revenues. The Partnership also generates timber sales from timber owned. The Partnership owned approximately 168 million board feet (“MMbf”) of timber at December 31, 2000.
The Company2002.
Our wholly owned mineral rights to 480 million tonssubsidiary, Penn Virginia Resource GP, LLC, a Delaware limited liability company, serves as general partner of mineable and merchantable coal reserves located in central
Appalachia atthe Partnership. As of December 31, 2000. Its coal reserves include both
surface2002, we owned approximately 45 percent of the Partnership, consisting of a two percent general partner interest, 42 percent subordinated units, and underground mineable seams. The reserves are
generally high quality, low-sulfur bituminous coalone percent common units. 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 distribution of available cash from operating surplus after certain levels of cash distributions have been achieved. See Item 1 – Business – Corporate and are leased
to various operators.
Other, for more information on Incentive Distribution Rights.
Financial Information
The Company operates
We operate in two primary business segments: (1)segments. We are in the oil and natural gas exploration and (2)production business and, through our interests in PVR, we are in the coal royalty and land management. Financial
information concerningmanagement business. For financial statement purposes, the Company's business segments can be
foundassets, liabilities and earnings of PVR are included in our consolidated financial statements, with the public unitholders’ ownership interest reflected as a minority interest. See Note 1519 (Segment Information) of the Notes to the Consolidated Financial Statements, of Penn Virginia Corporation
which is included in this report.
for financial information concerning our business segments.
Oil and Gas Overview
Penn Virginia'sOperations
General
Our oil and gas properties are located primarily in the eastern and southern portionsGulf Coast onshore areas of the United States. At December 31, 2000, the Company2002, we had 175273 Bcfe of proved reserves (174 Bcf of(88 percent natural gas) including 132226 Bcfe ofheld through various working interests and 4347 Bcfe ofheld by royalty interests. Oil and Gas Production
During 2000, 31,0002002, 349 thousand barrels of oil and condensate and 11,645
MMcf18.7 Bcf of natural gas, net to the Company'sour interest, were produced from continuing operations compared with 32,000164 thousand barrels and 8,679 MMcf13.1 Bcf in 1999. Average2001. In addition, there were approximately 18 thousand barrels of oil and condensate and 16 million cubic feet (“MMcf”) of natural gas produced from properties which were sold in 2002 and reflected as discontinued operations. We received average prices received by the Company were $26.84of $23.63 and $14.47$22.94 per barrel and $3.95$3.35 and $2.46$4.06 per Mcfthousand cubic feet (“Mcf”) for crude oil and natural gas sales in 20002002 and 1999,2001, respectively. Exploration and Development
The CompanyWe also drilled 109 96
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gross (79.1(65.5 net) wells in 20002002, of which 10090 gross (76.2(60.9 net) were development and nine6 gross (2.9(4.6 net) were exploratory. A total of five3 gross (1.3(1.6 net) exploratory wells were non-productivenot successful.
Transportation
The majority of our natural gas production is transported to market primarily on three major transmission systems. Duke Energy, Inc., Nisource, Inc. and three gross (1.4 net) wells are
under evaluation.Dominion Energy, Inc. transported 39 percent, 24 percent and 20 percent, respectively, of our 2002 natural gas production. The Companyremainder was divided among several pipeline companies in Texas, Louisiana and West Virginia. In almost all cases, our natural gas is still evaluatingsold at the unproved
propertiesinterconnects with the transmission pipelines. For additional information, see Item 1 – Risks Associated with Business Activities – Oil and Gas – Transportation.
Marketing and Hedging
We generally sell our natural gas using the spot market and short-term fixed price physical contracts. From time to time, we enter into commodity derivative contracts or fixed price physical contracts to mitigate the risk associated with the December 1999 purchasevolatility of natural gas prices. Recently, we have utilized swaps and costless collars in connection with our hedging activities. Gains and losses from hedging activities are included in revenues when the hedged production is sold. We recognized a 20loss of $1.0 million on settled hedging activities in 2002, a gain of $1.9 million in 2001, and no gain or loss in 2000. In 2002, we hedged approximately 44 percent of our natural gas base production at an average NYMEX Henry Hub floor price of $2.98 per MMbtu and a ceiling price of $3.53 per MMbtu. For crude oil, we hedged approximately 76 percent of our 2002 crude oil production at an average floor price or $21.31 per barrel and a ceiling price of $25.72 per barrel. See Item 7 – Management’s Discussion and Analysis of Financial Condition and Results of Operations – Quantitative and Qualitative Disclosures about Market Risk, for information about our price risk management positions for 2003, 2004 and the first quarter of 2005.
Coalbed Methane Drilling Venture
In August 2002, we entered into an agreement with CDX Gas, LLC (“CDX”), a private owner of proprietary horizontal drilling technology, to explore for and develop coalbed methane (“CBM”) in 16,000 square miles of property located in Central Appalachia as well as in the Devonian Shale formation. Our agreement with CDX is generally for five years and provides that we and CDX will have a 60 percent and 40 percent working interest, respectively, in future CBM projects conducted on property owned by us and subject to the agreement. On future projects conducted on property not owned by us, we and CDX will generally each have a Texas onshore gulf coast
exploration project.50 percent working interest.
Coal Royalty and Land Management Operations
Overview
At December 31, 2002, the Partnership owned and leased approximately 241,000 acres in Virginia, West Virginia, New Mexico and eastern Kentucky containing approximately 615 million tons of coal reserves. The project covers 35,000Partnership earns coal royalty revenue, based on long-term lease agreements, from 28 coal-mining operators actively mining under 51 separate leases at 61 mines. Coal royalty revenues under non-Peabody leases are based on the higher of a percentage of the gross sales price or a fixed price per ton of coal, with pre-established minimum monthly or annual payments. Under the Peabody leases, coal royalty revenues are based on fixed royalty rates which escalate annually, also with pre-established monthly minimums. The Partnership does not operate coal mines. The Partnership provides fee-based coal preparation and transportation facilities to some of its lessees to enhance their production levels and generate additional coal service revenues.
The Partnership’s timber assets consist of various hardwoods, primarily red oak, white oak, yellow poplar and black cherry. The Partnership owned approximately 168 million board feet of standing saw timber at December 31, 2002. The Partnership’s timber inventory only includes timber that can be harvested and is greater than 12 inches in diameter.
In December 2002, the Partnership announced the formation of an important strategic alliance with Peabody Energy Corporation, the largest private sector coal company in the world. Central to the transaction was the purchase from and leaseback to Peabody of approximately 120 million tons of coal reserves located in New Mexico (80 million tons) and northern West Virginia (40 million tons) (the “Peabody Acquisition”). As a result of the Peabody Acquisition, the Partnership’s total reserves increased by approximately 25 percent to 615 million tons. The Peabody Acquisition was funded with $72.5 million in cash and the issuance by the Partnership to
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Peabody of 1,522,325 common units and 1,240,833 Class B common units. Of the Class B common units issued, 293,700 are currently being held in escrow pending certain approvals from the State of New Mexico and Peabody’s acquisition and transfer to PVR of certain reserves. As a result of the escrow arrangement, approximately five million tons of coal reserves were excluded from reserve totals and 293,700 Class B common units were excluded from units issued in the Partnership’s financial statements for the year ended December 31, 2002.
The alliance with Peabody accomplishes several strategically important goals. It provides geographic diversity by exposing the Partnership to new markets in the western United States and northern Appalachia. The inclusion of affiliates of Peabody as a significant part of the Partnership’s lessee mix adds additional strength and stability to its lessee group. Peabody is incentivized to source additional assets to the Partnership in the future. This incentive is derived not only from Peabody’s ownership of approximately 15 percent of the Partnership’s common units, but also from its right to share in the general partner’s incentive distribution rights if Peabody sells additional coal assets to the Partnership in the future. See Item 1 – Corporate and Other – Partnership Distributions, Incentive Distribution Rights for more information.
In addition to the Peabody Acquisition, in August 2002, the Partnership purchased approximately 16 million tons of coal reserves in northern Appalachia for $12 million. This acquisition was the Partnership’s first outside of central Appalachia. The properties, which include approximately 18,000 mineral acres, contain predominately high sulfur, high BTU coal reserves.
In June 2001, the Partnership acquired the Fork Creek property in West Virginia, purchasing approximately 53 million tons of coal reserves for $33.1 million. In early 2002, the operator at Fork Creek filed for bankruptcy protection under Chapter 11 of the U.S. Bankruptcy Code and evidences Penn Virginia's strategyoperations at the mine were idled on March 4, 2002. The operator continued to expandpay minimum royalties until the Partnership recovered its lease on August 31, 2002. In November 2002, the Partnership purchased various infrastructure at Fork Creek for $5.1 million plus the assumption of certain reclamation liabilities and diversifystream mitigation obligations. With control of the reserves, permits and the critical infrastructure, PVR’s management is working diligently to put a new, financially stable operator in place at Fork Creek. As is customary in the Partnership’s operations, PVR intends to assign all related reclamation liabilities to the new operator.
Coal Royalties
The Partnership’s lessees mined approximately 14.3 million tons of coal in 2002 from PVR’s properties and paid an average royalty of $2.20 per ton, compared with approximately 15.3 million tons mined in 2001 at an average royalty of $2.11 per ton.
Timber Sales
Timber is harvested in advance of lessee mining to prevent loss of the resource. Timber is sold as individual parcels in competitive bid sales or on a contract basis, where PVR pays independent contractors to harvest timber while PVR directly markets the product. The Partnership sold approximately 8.3 MMbf in 2002 at an average price of $187 per thousand board feet (“Mbf”), compared with 8.7 MMbf at an average price of $168 per Mbf in 2001.
Coal Services
The Partnership generates coal service revenues from fees charged to lessees for the use of the Partnership’s coal preparation and transportation facilities. The majority of these fees have been generated by the Partnership’s unit train loadout facility, which was completed in April 1999 at a cost of $5.2 million. This facility accommodates 108-car unit trains, which can be loaded in approximately four hours. Lessees utilize the unit train loadout facility to reduce delivery costs incurred by their customers. The Partnership recognized $1.7 million in coal service revenues in 2002 and 2001. Such amounts are reported in other revenues in the Consolidated Statements of Income included herein.
Corporate and Other
Partnership Distributions
We are entitled, through our wholly owned subsidiaries, to receive certain cash distributions payable with respect to the subordinated and common units of PVR held by such subsidiaries as well as certain cash distributions payable with respect to general partner incentive distribution rights held by our general partner subsidiary.
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Cash Distributions. The Partnership made its first cash distribution of $0.34 per common and subordinated unit in February 2002 for the period October 30, 2001 through December 31, 2001. For 2002, the Partnership made quarterly cash distributions of $0.50 per common unit and subordinated unit. The Partnership intends to increase quarterly cash distributions to $0.52 per common unit and subordinated unit beginning with the distribution payable in May 2003 with respect to the first quarter of 2003.
Incentive Distribution Rights. Our wholly owned subsidiary is the general partner of PVR and, as such, holds certain incentive distribution rights which represent the right to receive an increasing percentage of quarterly distributions of available cash from operating surplus after the Partnership has paid minimum quarterly distributions and certain target distribution levels have been achieved. The minimum quarterly distribution is $0.50 per unit ($2.00 per unit on an annual basis). The incentive distributions rights are payable as follows:
If for any quarter:
then, PVR will distribute any additional available cash from operating surplus for that quarter among the unitholders and our general partner subsidiary in the following manner:
In each case, the amount of the target distribution set forth above is exclusive of any distributions to common unitholders to eliminate any cumulative arrearages in payment of the minimum quarterly distribution on the common units. In conjunction with the Peabody Acquisition, our general partner subsidiary has issued a special membership interest which entitles Peabody to receive increased percentages, starting at zero and increasing up to 40 percent, of payments PVR makes to our general partner subsidiary with respect to incentive distribution rights if PVR purchases additional assets from Peabody in the future.
Investments
During 2001, we sold 3,307,200 shares of Norfolk Southern Corporation (NYSE: NSC) common stock. The shares were sold in open market transactions on the New York Stock Exchange at an average price of $17.39 per share. Our 3,307,200 common shares of Norfolk Southern Corporation generated dividends of $0.2 million in 2001 and $2.6 million in 2000. We received a quarterly dividend of $0.06 per share in 2001, which was a reduction from the $0.20 per share realized in 2000. We had no available-for-sale securities at December 31, 2002 and 2001. See Note 5 (Investments and Dividend Income) of the Notes to the Consolidated Financial Statements for additional information.
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Risks Associated with Business Activities
Oil and Gas
Competition
The oil and natural gas industry is very competitive. Competition is particularly intense in the acquisition of prospective oil and natural gas properties and oil and gas reserves. Our competitive position depends on our geological, geophysical and engineering expertise, our financial resources, our ability to develop properties and our ability to select, acquire and develop proved reserves. We compete with a substantial number of other companies having larger technical staffs and greater financial and operational resources. Many such companies not only engage in the acquisition, exploration, development and production of oil and natural gas reserves, but also carry on refining operations, electricity generation and the marketing of refined products. We also compete with major and independent oil and gas companies in the marketing and sale of oil and natural gas, and the oil and natural gas industry in general competes with other industries supplying energy and fuel to industrial, commercial and individual consumers. We compete with other oil and natural gas companies in attempting to secure drilling rigs and other equipment necessary for drilling and completion of wells. Such equipment may be in short supply from time to time.
Price Volatility
Historically, natural gas and crude oil prices have been volatile. These prices rise and fall based on changes in market demand and changes in the political, regulatory and economic climate and other factors that affect commodities markets that are generally outside of our control. Some of our projections and estimates are based on assumptions as to the eastern United States
through strategic acquisitions,future prices of natural gas and crude oil. These price assumptions are used for planning purposes. We expect our assumptions will change over time and that actual prices in the future may differ from our estimates. Any substantial or extended decline in the actual prices of natural gas and/or crude oil could have a material adverse effect on the Company’s financial position and results of operations (including reduced cash flow and borrowing capacity), the quantities of natural gas and crude oil reserves that we can economically produce, the quantity of estimated proved reserves that may be attributed to our properties and our ability to fund our capital program.
Drilling and Operating Risks
Our drilling operations are subject to various risks common in the industry, including cratering, explosions, fires and exploration.
Gathering
Penn Virginia transports itsuncontrollable flows of oil, gas or well fluids. Our drilling operations are also subject to the risk that no commercially productive natural gas or oil reserves will be encountered. The cost of drilling, completing and operating wells is often uncertain, and drilling operations may be curtailed, delayed or canceled as a result of a variety of factors, including drilling conditions, pressure or irregularities in formations, equipment failures or accidents and adverse weather conditions.
Transportation
We transport our natural gas to market on various gathering and transmission pipeline systems owned primarily by third parties. Gathering fees are primarily paid by the purchaser of the natural gas. The Company'smajority of natural gas was gathered
principally by Dominion Energy, Inc. "Dominion" (formerly
Consolidated Natural Gas)sales contracts are one year or less in duration and Columbia Natural Resources "CNR".
These two primary providers gathered 35 percent and 38 percent of
the Company's natural gas for 2000 and 1999, respectively.contain relevant monthly index pricing provisions. Interruptible gathering rates have increased over the years as pipelines have implemented the mandatory unbundling of gathering services (Federal Energy Regulatory Commission Order 636) from other transportation services. Dominion's interruptible
gathering rates were 19.4 cents per MMbtu for 2000In 2002, Duke Energy, Inc. gathered and effective
January 1, 2001, were changed to a 9.3transported approximately 39 percent volumetric
retainage. CNR's interruptible gathering rate was 32 cents per
MMbtu in 2000; however, the Company does not expect to incur any
gathering expense from CNR in 2001 as a result of the divestiture
of non-strategic oil and gas properties in December 2000.
Transportation
The majority of Penn Virginia'sour natural gas, production is
transported to market primarily on three major transmission
systems.Nisource, Inc. (formerly Columbia Gas Transmission, Dominion and Duke
transported 45 percent, 30Transmission) approximately 24 percent, and 19Dominion Energy, Inc. approximately 20 percent, respectively,
ofwith the Company's 2000 natural gas production. The volume
transported by Columbia Gas Transmission is expected to decreaseremainder divided among several pipeline companies in 2001 due to the divestiture of non-strategic oilTexas, West Virginia and gas
properties in December 2000.Louisiana. Production could be adversely affected by shutdowns of the pipelines for maintenance or replacement as pipeline flexibility istransportation options are limited.
Marketing
Penn Virginia generally sells its
Regulation
State Regulatory Matters. Various aspects of our oil and natural gas usingoperations are regulated by administrative agencies under statutory provisions of the spot
marketstates where such operations are conducted. All of the jurisdictions in which we own or operate producing crude oil and short-term fixed price physical contracts. From timenatural gas properties have statutory provisions regulating the exploration for and production of crude oil and natural gas. These provisions include the permitting for the drilling of wells, maintaining bonding requirements in order to time,drill or operate wells, provisions relating to the Company enters into commodity derivative contractslocation of wells, the method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled, and the plugging and abandoning of wells. Our operations are also subject to various conservation laws and regulations. These include the regulation of the size of drilling and spacing units or fixed price physical contracts to mitigateproration units, the risk associated
withnumber of wells that may be
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drilled in an area, and the volatilityunitization or pooling of crude oil and natural gas properties. In addition, state conservation laws establish maximum rates of production from crude oil and natural gas wells, generally prohibit the venting or flaring of natural gas, prices.and impose certain requirements regarding the ratability or fair apportionment of production from fields and individual wells. The effect of these regulations is to limit the amounts of crude oil and natural gas we can produce from our wells, and to limit the number of wells or the locations at which we can drill.
Federal Energy Regulatory Commission. The Federal Energy Regulatory Commission (“FERC”) regulates the transportation and sale for resale of natural gas in interstate commerce under the Natural Gas Act of 1938 (“NGA”) and the Natural Gas Policy Act of 1978 (“NGPA”). In the past, the Federal government has regulated the prices at which oil and gas pricing was extremely volatilecould be sold. The Natural Gas Wellhead Decontrol Act of 1989 (the “Decontrol Act”) removed all NGA and NGPA price and nonprice controls affecting producers’ wellhead sales of natural gas effective January 1, 1993. While sales by producers of natural gas, and all sales of crude oil, condensate and natural gas liquids can currently be made at market prices, Congress could reenact price controls in 2000. Inthe future.
Commencing in April 1992, the FERC issued Order Nos. 636, 636-A, 636-B and May636-C (“Order No. 636”), which require interstate pipelines to provide transportation separate, or “unbundled,” from the pipelines’ sales of 2000, the Company entered into several physical
contracts that totaled 9,289 MMcf per day for the remainder of
2000. The volumes under contract accounted for 20 percent of
Penn Virginia's 2000 production at a price of $3.39 per Mcf. The
Company has one contract remaining that expires in March 2001
covering 18 percent of anticipated first quarter production at
$3.12 per Mcf.
In January 2001, the Company hedged 13 percent of its
anticipated production for the second and third quarters of 2001
throughgas. Also, Order No. 636 requires pipelines to provide open-access transportation on a basis hedgethat is equal for all gas supplies. Although Order No. 636 does not directly regulate gas producers like Penn Virginia Corporation, the FERC has stated that it intends for Order No. 636 to foster increased competition within all phases of the natural gas industry. The courts have largely affirmed the significant features of Order No. 636 and numerous related orders pertaining to the individual pipelines, although certain appeals remain pending and the FERC continues to review and modify its open access regulations. In particular, the FERC has issued Order No. 637, which, among other things, (i) permits pipelines to charge different maximum cost-based rates for peak and off-peak times, (ii) encourages auctions for pipeline capacity, (iii) requires pipelines to implement imbalance management services, and (iv) restricts the ability of pipelines to impose penalties for imbalances, overruns, and non-compliance with operational flow orders. In addition, the FERC has implemented regulations governing the procedure for obtaining authorization to construct new pipeline facilities and has issued a costless collarpolicy statement, which it largely affirmed in a recent order on rehearing, establishing a presumption in favor of requiring owners of new pipeline facilities to charge rates based solely on the costs associated with a floor of $4.95
per Mcf and a ceiling of $7.16 per Mcf. Additionally, basis
hedges covering ansuch new pipeline facilities.
While any additional 11 percent of anticipated
production for the same periods were executed. Gains and losses
from hedging activitiesFERC action on these matters would affect us only indirectly, these changes are includedintended to further enhance competition in natural gas revenues whenmarkets. We cannot predict what further action the hedged production occurs. The Company recognized a lossFERC will take on these matters, nor can we predict whether the FERC’s actions will achieve its stated goal of $0.4 millionincreasing competition in 1999natural gas markets. However, we do not believe that we will be treated materially differently than other natural gas producers and $0.7 million in 1998 on hedging
activitiesmarkets with no gain or loss recognized in 2000. Effective
January 1, 2001, the Company will account for its derivative
activities in accordance with Statement of Financial Accounting
Standards ("SFAS") No. 133, as amended by SFAS 137 and SFAS 138.
See Note 2 (New Accounting Standards) in the financial
statements.
Coal Royalty and Land Management Operations
Overview
Penn Virginia owned 163,000 acres of coal- and timber-bearing
land in central Appalachia at December 31, 2000. The Company
earns coal royalty revenue, based on long-term lease agreements,
from 19 coal mining operators. Coal royalty revenue is based on a
minimum annual payment, a minimum dollar royalty per ton and/or a
percentage of the coal's selling price. The Company does not
operate coal mines.
The Company's timber assets consist of various hardwoods,
primarily red oak, white oak, yellow poplar and black cherry.
Penn Virginia owns an estimated 177 million board feet of
standing saw timber. The Company's timber inventory only
includes timber that can be harvested and is greater than 12
inches in diameter.
Coal Production
Lessees mined 12.5 million tons of coal from Penn Virginia's
properties in 2000 and paid an average royalty of $1.94 per ton,
compared with 8.6 million tons mined in 1999 at an average
royalty of $2.07 per ton.
At December 31, 2000, the Company's mineable and merchantable
coal reserves in central Appalachia were estimated at 480 million
tons. At December 31, 2000, the Company's central Appalachia
properties had 19 operators actively mining a total of 31
separate lease locations.
Timber Production
The Company sold 8.5 MMbf in 2000 for an average price of $257
per Mbf, compared with 9.0 MMbf at an average price of $206 per
Mbf in 1999. Timber is harvested in advance of lessee mining to
prevent loss of the resource. Timber is sold in competitive bid
sales involving individual parcels and also on a contract basis,
whereby Penn Virginia pays independent contractors to harvest
timber while the Company directly markets the product.
Corporate and Other
Investments
The Company holds available-for-sale securities, primarily in
Norfolk Southern Corporation. The Company's 3,307,200 common
shares of Norfolk Southern Corporation (NYSE symbol: NSC)
generated dividends of $2.6 million in 2000, 1999 and 1998. Penn
Virginia received a quarterly dividend of $0.20 per share in
2000, 1999 and 1998; however, in January 2001, Norfolk Southern
Corporation reduced its quarterly dividend to $0.06 per share.
The fair value of the Company's equity portfolio at December 31,
2000 was $44.1 million compared with $67.8 million at December
31, 1999. See Note 4 (Investments and Dividend Income) of the
Notes to the Consolidated Financial Statements for additional
information.
Risks Associated with Business Activities
General
Government Regulations
Each of Penn Virginia's businesses is subject to extensive
rules and regulations promulgated by variouswhich we compete.
Environmental Matters. Extensive federal, state and local government agencies. Failurelaws govern oil and natural gas operations, regulate the discharge of materials into the environment or otherwise relate to the protection of the environment. Numerous governmental departments issue rules and regulations to implement and enforce such laws that are often difficult and costly to comply with suchand which carry substantial administrative, civil and even criminal penalties for failure to comply. Some laws, rules and regulations can resultrelating to protection of the environment may, in substantial penalties.certain circumstances, impose “strict liability” for environmental contamination, rendering a person liable for environmental and natural resource damages and cleanup costs without regard to negligence or fault on the part of such person. Other laws, rules and regulations may restrict the rate of oil and natural gas production below the rate that would otherwise exist or even prohibit exploration or production activities in sensitive areas. In addition, state laws often require some form of remedial action to prevent pollution from former operations, such as closure of inactive pits and plugging of abandoned wells. The regulatory burden on the oil and natural gas industry increases the Company'sits cost of doing business and consequently affects its profitability. These laws, rules and regulations affect our operations, as well as the oil and gas exploration and production industry in general. We believe that we are in substantial compliance with current applicable environmental laws, rules and regulations and that continued compliance with existing requirements will not have a material adverse impact on us. Nevertheless, changes in existing environmental laws or the adoption of new environmental laws have the potential to adversely affect our operations.
Page 8
Coal Royalty and Land Management
Although the Company believesPartnership intends to make quarterly cash distributions of $0.52 per common unit, it can only do so to the extent it has sufficient cash from operations after payment of fees and expenses. In addition, quarterly distributions are payable on our subordinated units only after each common unit has received a distribution of $0.52 plus any arrearages due from prior quarters. Incentive distributions are payable to our general partner subsidiary after cash distributions per unit exceed $0.55 in any quarter. The Partnership’s revenues and its ability to make quarterly and incentive distributions are subject to several risks, including those described below.
Competition
The coal industry is intensely competitive primarily as a result of the existence of numerous producers. The Partnership’s lessees compete with coal producers in materialvarious regions of the U.S. for domestic sales. The industry has undergone significant consolidation that has led to some of the competitors of the Partnership’s lessees located in Appalachia to have significantly larger financial and operating resources than the Partnership’s lessees do. The Partnership’s lessees primarily compete with both large and small producers in Appalachia as well as the western United States. They compete on the basis of coal price at the mine, coal quality (including sulfur content), transportation cost from the mine to the customer and the reliability of supply. Continued demand for the Partnership’s coal and the prices that the Partnership’s lessees obtain are also affected by demand for electricity, environmental and government regulations, technological developments and the availability and price of alternative fuel supplies, including nuclear, natural gas, oil and hydroelectric power. Demand for the Partnership’s low sulfur coal and the prices the Partnership’s lessees will be able to obtain for it will also be affected by the price and availability of high sulfur coal, which can be marketed in tandem with emissions allowances in order to meet federal Clean Air Act requirements.
Operating Risks
General Regulation. The Partnership’s lessees are obligated to conduct mining operations in compliance with all rules,applicable federal, state and local laws and regulations. These laws and regulations include matters involving the discharge of materials into the environment, employee health and safety, mine permits and other licensing requirements, reclamation and restoration of mining properties after mining is completed, management of materials generated by mining operations, surface subsidence from underground mining, water pollution, legislatively mandated benefits for current and retired coal miners, air quality standards, protection of wetlands, plant and wildlife protection, limitations on land use, storage of petroleum products and substances which are regarded as hazardous under applicable laws, thereand management of electrical equipment containing polychlorinated biphenyls, or PCBs. Because of extensive and comprehensive regulatory requirements, violations during mining operations are not unusual in the industry and, notwithstanding compliance efforts, we do not believe violations by the Partnership’s lessees can be no assurance that new interpretations of existing rules,
regulations and laws will not adversely affect the Company's
business and operations.
Competition
The energy industry is highly competitive. Manyeliminated completely. However, none of the Company's competitors are large, well-established companies with
substantially larger operating staffs, greater capital resources
and established long-term strategic positions.
Oil and Gas
Prices
Penn Virginia's revenues, profitability andviolations to date, or the monetary penalties assessed, have been material to us, to the Partnership or, to our knowledge, to the Partnership’s lessees. We do not currently expect that future rate of
growth are highly dependent on the prevailing prices for oil and
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 gas couldcompliance will have a material adverse effect on us or the Company's revenues,
profitabilityPartnership.
While it is not possible to quantify the costs of compliance by the Partnership’s lessees with all applicable federal and cash flowstate laws, those costs have been and could, under certain
circumstances, result in an impairment of the Company's oilare expected to continue to be significant. The lessees post performance bonds pursuant to federal and gas properties.
In Aprilstate mining laws and May of 2000, the Company entered into several
physical contracts that totaled 9,289 MMcf per dayregulations for the remainderestimated costs of 2000.reclamation and mine closing, including the cost of treating mine water discharge when necessary. The volumes under contract accountedPartnership does not accrue for 20
percentsuch costs because its lessees are contractually liable for all costs relating to their mining operations, including the costs of Penn Virginia's 2000 production at a price of $3.39
per Mcf. The Company has one contract remaining that expires in
March 2001 covering 18 percent of anticipated first quarter
production at $3.12 per Mcf.
In January 2001,reclamation and mine closure. However, the Company hedged 13 percent of its
anticipated productionPartnership does require some smaller lessees to deposit certain funds into escrow for reclamation and mine closure costs or post performance bonds for these costs. Although the second and third quarters of 2001
through a basis swap and a costless collar with a floor of $4.95
per Mcf and a ceiling of $7.16 per Mcf. Additionally, basis
swaps covering an additional 11 percent of anticipated productionlessees typically accrue adequate amounts for the same periods were executed. Gains and losses from
hedging activities are included in natural gas revenues when the
hedged production occurs. The Company recognized a loss of $0.4
million in 1999 and $0.7 million in 1998 on hedging activities
with no gain or loss recognized in 2000. Effective January 1,
2001, the Company will account for its derivative activities in
accordance with Statement of Financial Accounting Standards
("SFAS") No. 133, as amended by SFAS 137 and SFAS 138. See Note
2 (New Accounting Standards) in the financial statements.
Exploratory Drilling
Both development and exploratory drilling involve risks.
However, exploratory drilling involves greater risks of dry holes
or failure to find commercial quantities of hydrocarbons than
does development drilling. The Company anticipates the number of
exploratory prospects drilled in the short and long-term may
increase, compared with historical amounts. Consequently, it is
likely that the Company will experience increased levels of
exploration expense in 2001 and beyond.
Transportation
The majority of Penn Virginia's natural gas production is
transported to market primarily on three major transmission
systems. Columbia Gas Transmission, Dominion and Duke
transported 45 percent, 30 percent and 19 percent, respectively,
of the Company's 2000 natural gas production. The volume
transported by Columbia Gas Transmission is expected to decrease
in 2001 due to the divestiture of non-strategic oil and gas
properties in December 2000. Production couldthese costs, their future operating results would be adversely affected by shutdownsif they later determined these accruals to be insufficient. Compliance with these laws has substantially increased the cost of coal mining for all domestic coal producers.
In addition, the utility industry, which is the most significant end-user of coal, is subject to extensive regulation regarding the environmental impact of its power generation activities which could affect demand for the Partnership’s lessees’ coal. The possibility exists that new legislation or regulations may be adopted which may have a significant impact on the mining operations of the pipelinesPartnership’s lessees or their customers’ ability to use coal and may require the Partnership, its lessees or their customers to change operations significantly or incur substantial costs.
Page 9
Regulation
Clean Air Act. The Clean Air Act affects the end-users of coal and could significantly affect the demand for maintenance or
replacement as pipeline flexibility is limited.
Coal Royaltythe Partnership’s coal and Land Management
Operating Risks
Penn Virginia'sreduce the Partnership’s coal royalty stream is impactedrevenues. The Clean Air Act and corresponding state and local laws extensively regulate the amount of sulfur dioxide, particulate matter, nitrogen oxides and other compounds emitted from industrial boilers and power plants, including those that use the Partnership’s coal. These regulations together constitute a significant burden on coal customers and stricter regulation could further adversely impact the demand for and price of the Partnership’s coal, resulting in lower coal royalty revenues.
In July 1997, the U.S. Environmental Protection Agency adopted more stringent ambient air quality standards for particulate matter and ozone. Particulate matter includes small particles that are emitted during the combustion process. In a February 2001 decision, the U.S. Supreme Court largely upheld the EPA’s position, although it remanded the EPA’s ozone implementation policy for further consideration. Details regarding the new particulate standard itself are still subject to judicial challenge. These ozone restrictions will require electric power generators to further reduce nitrogen oxide emissions. Nitrogen oxides are naturally occurring byproducts of coal combustion that lead to the formation of ozone. Further reduction in the amount of particulate matter that may be emitted by several
factors, whichpower plants could also result in reduced coal consumption by electric power generators. Future regulations regarding ozone, particulate matter and other ambient air standards could restrict the Company 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 for coal and abilitythe development of new mines by the Partnership’s lessees. This in turn may result in decreased production by the Partnership’s lessees and a corresponding decrease in the Partnership’s coal royalty revenues. These decreases could adversely effect the distributions we receive from the Partnership.
The Clean Air Act also imposes standards on sources of hazardous air pollutants. These standards have not yet been extended to arrange reliable
transportationcoal mining operations or by-products of coal combustion, but consideration is now being given to regulating certain hazardous air pollutant components that are found in coal combustion exhaust, including mercury. Like other environmental regulations, these standards and future standards could result in a decreased demand for coal.
Surface Mining Control and Reclamation Act of 1977. The Surface Mining Control and Reclamation Act of 1977 (“SMCRA”) and similar state statutes impose on mine operators the responsibility of restoring the land to its original state or compensating the landowner for types of damages occurring as a result of mining operations, and require mine operators to post performance bonds to ensure compliance with any reclamation obligations. Regulatory authorities may attempt to assign the liabilities of the Partnership’s lessees to the end-user. Coal emissionsPartnership if any of the lessees are regulatednot financially capable of fulfilling those obligations. In conjunction with mining the property, the Partnership’s lessees are contractually obligated under the terms of their leases to comply with all laws, including SMCRA and equivalent state and local laws, which obligations include reclaiming and restoring the mined areas by variousgrading, shaping and reseeding the soil. Upon completion of the mining, reclamation generally is completed by seeding with grasses or planting trees for use as pasture or timberland, as specified in the approved reclamation plan.
CERCLA. The Partnership could become liable under federal and state agencies which affectSuperfund and waste management statutes if its lessees are unable to pay environmental cleanup costs. The Comprehensive Environmental Response, Compensation and Liability Act, known as CERCLA or “Superfund,” and similar state laws create liabilities for the qualityinvestigation and remediation of releases and threatened releases of hazardous substances to the environment and damages to natural resources. As a landowner, the Partnership is potentially subject to liability for these investigation and remediation obligations.
Mountaintop Removal Litigation. On January 29, 2003, the United States Fourth Circuit Court of Appeals (the “Circuit Court”) vacated an injunction issued in May 2002 by the United States District Court for the Southern District of West Virginia (the “District Court”). This injunction had prohibited the Huntington, West Virginia office of the U.S. Army Corps of Engineers (the “Corps”) from issuing permits under Section 404 of the Clean Water Act for the construction of valley fills for the disposal of coal mining overburden. These valleys typically contain steams that, can be burned within compliance guidelines.
Corporate and Other
Investments
The valueunder the Clean Water Act, are considered navigable waters of the Company's investment portfolioUnited States. The District Court had found that the Corp’s permitting of overburden valley fills under Section 404 was a violation of the Clean Water Act since Section 404 allows only the permitting of fill material deposited for a beneficial purpose and not for mere waste disposal such as the disposal of coal overburden. The Circuit Court reversed this finding, concluding, instead, that overburden valley fills may be permitted under Section 404 and remanded the case back to the District Court for further proceedings not inconsistent with the Circuit Court’s opinion.
Mine Health and Safety Laws.Stringent safety and health standards have been imposed by federal legislation since the adoption of the Mine Health and Safety Act of 1969. The Mine Health and Safety Act of 1969 resulted in increased operating costs and reduced productivity. The Mine Safety and Health Act of 1977, which significantly expanded the enforcement of health and safety standards of the Mine Health and Safety Act of 1969, imposes comprehensive safety and health standards on all mining operations. In addition, as part of the Mine Health and Safety Acts of 1969 and 1977, the Black Lung Acts require payments of benefits by all businesses conducting current mining operations to coal miners with black lung and to some survivors of a miner who dies from this disease.
Page 10
Mining Permits and Approvals.Numerous governmental permits or approvals are required for mining operations. In connection with obtaining these permits and approvals, the Partnership’s lessees may be required to prepare and present to federal, state or local authorities data pertaining to the effect or impact that any proposed production of coal may have upon the environment. The requirements imposed by any of these authorities may be costly and time consuming and may delay commencement or continuation of mining operations.
In order to obtain mining permits and approvals from state regulatory authorities, mine operators, including the Partnership’s lessees, must submit a reclamation plan for restoring, upon the completion of mining operations, the mined property to its prior condition, productive use or other permitted condition. Typically lessees submit the necessary permit applications between 12 and 18 months before they plan to begin mining a new area. In the Partnership’s experience, permits generally are approved within 12 months after a completed application is submitted. In the past, lessees have generally obtained their mining permits without significant delay. The Partnership’s lessees have obtained or applied for permits to mine a majority of the reserves that are currently planned to be mined by lessees over the next five years. The Partnership’s lessees are in the planning phase for obtaining permits for the remaining reserves planned to be mined over the next five years. However, they cannot make any assurances that they will not experience difficulty in obtaining mining permits in the future.
Timber Regulations.The Partnership’s timber operations are subject to market price fluctuations.
federal, state and local laws and regulations, including those related to the environment, protection of endangered species, foresting activities and health and safety. The Partnership believes it is managing its timberlands in substantial compliance with applicable federal and state regulations.
Employees
Penn Virginia
We had 68104 employees at December 31, 2000. The
Company considers2002, including 30 employees who directly provide services for PVR through its general partner. We consider our relations with itsour employees to be good.
Available Information
The Company’s Internet address is www.pennvirginia.com. We make available free of charge on or through our Internet website our annual report on Form 10-K, quarterly reports on Form 10-Q and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 as soon as reasonably practicable after we electronically file such material with, or furnish it to, the Securities and Exchange Commission. To date, we have inadvertently not made so available on our website any current reports on Form 8-K. We will provide, free of charge upon request, electronic or paper copies of all current reports on Form 8-K which were filed from November 15, 2002 to February 15, 2003. We will make available, free of charge, on or through our internet website, all reports on Form 8-K and amendments to those reports filed after February 15, 2003 as soon as reasonably practicable after we electronically file such reports with, or furnish them to, the Securities and Exchange Commission.
Page 11
Executive Officers of the Company
Below is a list of
The following table sets forth information concerning our executive officers of the Company
including their ages and positions held.officers. Each officer is elected annually by the Board of Directors and serves at the pleasure of the Board of Directors.
Name | Age | Position with the Company | ||
A. James Dearlove | 55 | President and Chief Executive Officer | ||
Frank A. Pici | 47 | Executive Vice President and Chief Financial Officer | ||
Keith D. Horton | 49 | Executive Vice President | ||
H. Baird Whitehead | 52 | Executive Vice President | ||
Nancy M. Snyder | 49 | Senior Vice President, General Counsel and Secretary | ||
Dana G. Wright | 50 | Vice President and |
A. James Dearlove -– Mr. Dearlove is the President and Chief
Executive Officer. He has served in various capacities with the Company since 1977, including Viceas President and Chief Executive Officer and a Director of the Company since May 1996, President and Chief Operating Officer of the Company from 1994 to May 1996, Senior Vice President of the Company form 1992 to 1994 and most recently,Vice President since 1994. Mr. Dearlove
was electedof the Company from 1986 to the Company's Board of Directors effective
February 6, 1996.1992. He was appointedis also Chief Executive Officer in May
1996.and Chairman of the Board of Penn Virginia Resource GP, LLC, the general partner of Penn Virginia Resource Partners, L.P. He also serves as director of the Powell River Project and the National Council of Coal Lessors.
James O. Idiaquez -
Frank A. Pici – Mr. IdiaquezPici is anthe Executive Vice President and Chief Financial Officer. He was appointed to these positions
in December 2000. He previously served as Vice President-
Corporate Development forOfficer of the Company, from October 1998which he joined in September 2001. Mr. Pici is also the Vice President and Chief Financial Officer and a Director of Penn Virginia Resource, GP LLC. From 1996 to December 2000. From 1978August 2001, Mr. Pici was Vice President of Finance and Chief Financial Officer of Mariner Energy, Inc., an oil and gas exploration and production company. Prior to 1998, Mr. Idiaquez1996, he served in various capacities with Cabot Oil & Gas Corporation, including Corporate Controller from 1994 to 1996, Director, Internal Audit from 1992 to 1994, and regional accounting manager from 1989 to 1992. From 1982 to 1989, he held financial management capacities, including corporate planningpositions with companies in the oil and acquisitionsgas and divestitures, with The Louisiana Land &
Exploration Company and Burlington Resources, Inc.
coal industries.
Keith D. Horton -– Mr. Horton serves as President of the
Company's coal and land management subsidiary and has served as
an executive officer for the Company since 1996. He was
appointed Executive Vice President in December 2000. He has served in various capacities with the Company since 1981, including Executive Vice President and was
electeda Director of the Company since December 2000, Vice President – Eastern Operations of the Company from May 1996 to May 1997, President of Penn Virginia Coal Company from April 1996 to October 2001, Vice President of Penn Virginia Coal Company from March 1994 to February 1996, Vice President from January 1990 to December 1998, and Manager, Coal Operations from July 1982 to December 1989, of Penn Virginia Resources Corporation. He is also the Company's BoardPresident and Chief Operating Officer and a Director of Directors on December 6, 2000.Penn Virginia Resource, GP LLC. Additionally, Mr. Horton is Chairman of the Central Appalachian Section of the Society of Mining Engineers. He also serves as a director of the Virginia Mining Association, Powell River Project and Virginia Coal Council and the
Central Appalachian Section of the Society of Mining Engineers.
Council.
H. Baird Whitehead -– Mr. Whitehead is an Executive Vice President. He joinedPresident of the Company, which he joined in January 2001. He serves as
President of the Company's oil and gas subsidiary. Previously he
was employed for the past 20 years atPrior to joining Penn Virginia, Mr. Whitehead served in various positions with Cabot Oil & Gas Corporation
in various management positions, most recentlyCorporation. From 1998 to 2001, he served as Senior Vice President.
President during which time he oversaw Cabot’s drilling, production, and exploration activity in the Appalachia, Rocky Mountains, Mid-Continent and the Texas and Louisiana Gulf Coast areas. From 1992 to 1998, he was Vice President and Regional Manager of Cabot’s Appalachian business unit and from 1989 to 1992, he was Vice President and Regional Manager of Cabot’s Anadarko business unit. From 1987 to 1989, he served as Vice President of Engineering for Cabot. From 1972 to 1987, he held various engineering and supervisory positions with Texaco, Columbia Gas Transmission, and Cabot.
Nancy M. Snyder -– Ms. Snyder has served as Corporate Secretary
and General Counsel since joining the Company in 1997. She was
appointed as aSenior Vice President of the Company insince February 2003, as Vice President since December 2000.
Previously, Ms. Snyder was in private2000 and firm practices in the
areas of general corporateas General Counsel and securities law.
Ann N. Horton - Mrs. Horton has served as Principal Accounting
Officer and ControllerCorporate Secretary of the Company since 1995. She was
appointed as a1997. Ms. Snyder is also the Vice President, General Counsel and a Director of Penn Virginia Resource GP, LLC. From 1993 to 1997, Ms. Snyder was a solo practitioner representing clients generally in connection with mergers and acquisitions and general corporate matters. From 1990 to 1993, Ms. Snyder served as general counsel to Nan Duskin, Inc. and its affiliated companies, which were in the businesses of womens’ retail fashion and real estate. From 1983 to 1989, Ms. Snyder was an associate at the law firm of Duane Morris, where she practiced securities, banking and general corporate law.
Dana G. Wright – Mr. Wright joined the Company in December 2000.
She has served in various capacitiesJuly 2002 and serves as Vice President and Controller. Prior to joining Penn Virginia, he was employed for 26 years with theAtlantic Richfield Company, and most recently with its subsidiaries since 1981.
Page 12
The following terms have the meanings indicated below when used in this report.
Bbl - means a standard barrel of 42 U.S. gallons liquid volume
Bcf - means one billion cubic feet
Bcfe - means one billion cubic feet equivalent with one barrel
of oil or condensate converted to six thousand cubic feet
of natural gas based on the estimated relative energy content
Gross - acre or well means an acre or well in which a working
interest is owned
Mbbl - means one thousand barrels
Mbf - means one thousand board feet
Mcf - means one thousand cubic feet
MMbf - means one million board feet
MMbtu - means one million British thermal units
MMcf - means one million cubic feet
Net - acres or wells is determined by multiplying the gross acres
or wells by the owned working interest in those gross acres
or wells.
Proved
Reserves - means those 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 oil and gas reservoirs under
existing economic and operating conditions
Bbl– | means a standard barrel of 42 U.S. gallons liquid volume | |
Bcf– | means one billion cubic feet | |
Bcfe– | means one billion cubic feet equivalent with one barrel of oil or condensate converted to six thousand cubic feet of natural gas based on the estimated relative energy content | |
Gross– | acre or well means an acre or well in which a working interest is owned | |
Mbbl– | means one thousand barrels | |
Mbf– | means one thousand board feet | |
Mcf– | means one thousand cubic feet | |
MMbf– | means one million board feet | |
Mmbtu– | means one million British thermal units | |
MMcf– | means one million cubic feet | |
Net– | acres or wells is determined by multiplying the gross acres or wells by the owned working interest in those gross acres or wells | |
NYMEX– | New York Mercantile Exchange | |
Present value of proved reserves– | means the present value (discounted at 10%) of estimated future cash flows from proved oil and natural gas reserves, as estimated by our independent engineers, reduced by additional estimated future operating expenses, development expenditures and abandonment costs (net of salvage value) associated therewith (before income taxes) | |
Probable Coal Reserves– | means those reserves for which quantity and grade and/or quality are computed from information similar to that used for proven reserves, but the sites for inspection, sampling and measurement are farther apart or are otherwise less adequately spaced. The degree of assurance, although lower than that for proven reserves, is high enough to assume continuity between points of observation. | |
Proved Reserves– | means those 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 oil and gas reservoirs under existing economic and operating conditions | |
Proven Coal Reserves– | means those reserves for which: (a) quantity is computed from dimensions revealed in outcrops, trenches, workings or drill holes; grade and/or quality are computed from the results of detailed sampling; and (b) the sites for inspection, sampling and measurement are spaced so closely, and the geologic character is so well defined, that the size, shape, depth and mineral content of reserves are well-established. | |
Standardized Measure– | means present value of proved reserves further reduced by the present value (discounted at 10%) of estimated future income taxes on cash flows | |
Working Interest– | means a cost-bearing interest under an oil and gas lease that gives the holder the right to develop and produce the minerals under the lease |
Page 13
ITEM 2 - PROPERTIES
–PROPERTIES
Facilities
Penn Virginia Corporation is
We are headquartered in Radnor, Pennsylvania with additional offices in Duffield, Virginia;Kingsport, Tennessee, Houston, Texas and Charleston, West Virginia; and Houston, Texas. The Company
believes its leasedVirginia. We believe that our properties are adequate for our current needs.
Title to Properties
Penn Virginia believes it has
We believe that we have satisfactory title to all of itsour properties in accordance with standards generally accepted in the oil and natural gas and coal royalty and land management industries.
As is customary in the oil and gas industry, the Company makeswe make only a cursory review of title to farmout acreage and to undeveloped oil and gas leases upon execution of any contracts. Prior to the commencement of drilling operations, a thorough title examination is conducted and curative work is performed with respect to significant defects. To the extent title opinions or other investigations reflect defects, Penn Virginia
cureswe cure such title defects. If the Company waswe were unable to remedy or cure any title defect of a nature such that it would not be prudent to commence drilling operations on a property, the
Companywe could suffer a loss of itsour investment in the property. Prior to completing an acquisition of producing oil and gas leases, the Company obtainsassets, we obtain title opinions on all material leases. Penn Virginia'sOur oil and gas properties are subject to customary royalty interests, liens for current taxes and other burdens that the Company believeswe believe do not materially interfere with the use or affect the value of such properties.
Of the 163,000615 million tons of proven and probable coal reserves to which the Partnership has rights as of December 31, 2002, PVR owned the mineral rights and the majority of related surface rights to 572 million tons, or 93 percent, and leased the remaining 43 million tons, or 7 percent, from unaffiliated third parties. In addition to the revenues the Partnership receives from its coal business, it also earns revenues from the sale of timber. At December 31, 2002, the Partnership owned 114,500 surface acres of coal and timber bearing land, Penn
Virginia owns 70 percent in fee and 30 percent in mineral.
Additionally, the Company leases over 25,000 acrestimberland containing 168 million board feet of coal andtimber
bearing land from third parties.
inventory.
Page 14
Oil and Gas
Production and Pricing
The following table sets forth production, sales prices and production costs with respect to the Company'sour properties for the years ended December 31, 2000, 19992002, 2001 and 1998.
2002 | 2001 | 2000 | ||||||||
Production | ||||||||||
Oil and condensate (Mbbls)* |
| 349 |
|
| 164 |
| 31 | |||
Natural gas (MMcf)* |
| 18,697 |
|
| 13,130 |
| 11,645 | |||
Total production (MMcfe)* |
| 20,791 |
|
| 14,114 |
| 11,831 | |||
Average sales price | ||||||||||
Oil and condensate ($/Bbl) | $ | 23.63 |
| $ | 22.94 | $ | 26.84 | |||
Natural gas ($/Mcf) | $ | 3.35 |
|
| 4.06 |
| 3.95 | |||
Production cost ($/Mcfe) | ||||||||||
Lease operating expense | $ | 0.45 |
| $ | 0.40 | $ | 0.38 | |||
Taxes other than income |
| 0.27 |
|
| 0.31 |
| 0.24 | |||
General and Administrative Expense |
| 0.40 |
|
| 0.38 |
| 0.22 | |||
Total production cost | $ | 1.12 |
| $ | 1.09 | $ | 0.84 | |||
Hedging Summary | ||||||||||
Natural gas prices ($/Mcf): | ||||||||||
Actual price received for production | $ | 3.39 |
| $ | 3.92 | $ | 3.95 | |||
Effect of derivative hedging activities |
| (0.04 | ) |
| 0.14 |
| — | |||
Average realized price | $ | 3.35 |
| $ | 4.06 | $ | 3.95 | |||
Crude oil prices ($/Bbl): | ||||||||||
Actual price received for production | $ | 24.39 |
| $ | 22.45 | $ | 26.84 | |||
Effect of derivative hedging activities |
| (0.76 | ) |
| 0.49 |
| — | |||
Average realized price | $ | 23.63 |
| $ | 22.94 | $ | 26.84 | |||
*Production for 2002 does not include approximately 16 Mbbls of oil condensate and 18 MMcf of natural gas production, or 114 MMcfe, related to discontinued operations. 2001 production volumes for properties sold were insignificant.
Page 15
Proved Reserves
We had proved reserves of 71,000241 Bcf of natural gas and 5.4 million barrels of crude oil and condensate and 174 Bcf of natural gas at December 31, 2000.2002. The present value of the estimated future cash flows discounted at 10 percent (Pre-tax(pre-tax SEC PV10 Value) at December 31, 20002002, was $644$481 million. At December 31, 2000, the Company2002, we had 150195 gross (74(128.3 net) proved undeveloped drilling locations.
Oil and Condensate (MMbbls) | Natural Gas (Bcf) | Natural Gas Equivalents (Bcfe) | Pre-tax SEC PV10Value ($MM) | Year-end Weighted Average Prices Used | |||||||||||
$ / Bbl | $ / Mmbtu | ||||||||||||||
2002 | |||||||||||||||
Developed | 2.9 | 199 | 216 | $ | 404 | ||||||||||
Undeveloped | 2.5 | 42 | 57 |
| 77 | ||||||||||
Total | 5.4 | 241 | 273 | $ | 481 | $ | 31.13 | $ | 4.74 | ||||||
2001 | |||||||||||||||
Developed | 2.2 | 183 | 196 | $ | 202 | ||||||||||
Undeveloped | 1.7 | 46 | 56 |
| 40 | ||||||||||
Total | 3.9 | 229 | 252 | $ | 242 | $ | 20.40 | $ | 2.65 | ||||||
2000 | |||||||||||||||
Developed | 0.1 | 146 | 147 | $ | 540 | ||||||||||
Undeveloped | — | 28 | 28 |
| 104 | ||||||||||
Total | 0.1 | 174 | 175 | $ | 644 | $ | 23.31 | $ | 9.91 | ||||||
The standardized measure of discounted future net cash flows, which represents the present value of future net revenues after income taxes discounted at ten percent, was $467$355 million, $119$189 million and $76$467 million at December 31, 2002, 2001 and 2000, 1999 and 1998,
respectively. The year-end weighted average prices used to
determine proved reserves at December 31, 2000, 1999 and 1998
were ($/Bbl) $23.31, $21.78 and $9.70, respectively, for oil and
condensate and ($/Mcf) $9.91, $2.69 and $2.14, respectively, for
natural gas. Natural gas prices have declined significantly
since December 31, 2000. If the average price received for 2000
($26.84 per Bbl and $3.95 per Mcf) had been used to calculate the
standardized measure at December 31, 2000, the pre-tax discounted
future net cash flows would have been $235 million. For information on the changes in standardized measure of discounted future net cash flows, see "Note 17. Supplementaryflows. See Note 22 (Supplementary Information on Oil and Gas Producing Activities (Unaudited)" in "Item 8. -) of the Notes to the Consolidated Financial Statements, and Supplementary Data."
for more information.
In accordance with the Securities and Exchange Commission'sCommission’s guidelines, the engineers'engineers’ estimates of future net revenues from the Company'sour properties and the pre-tax SEC PV10 value thereof are made using oil and natural gas sales prices in effect at the
dateas of such estimates.December 31, 2002. The prices are held constant throughout the life of the properties except where such guidelines permit alternate treatment, including the use of fixed and determinable contractual price escalations. Net proved oil and gas reserves for the three years ended December 31, 20002002 were estimated by Wright and Company, Inc. Prices for oil and gas are subject to substantial seasonal fluctuations and prices for each are subject to substantial fluctuations as a result of numerous other factors. See "ItemItem 7 - Management's– Management’s Discussion and Analysis of Financial Condition and Results of Operations."
Proved reserves are the estimated quantities of natural gas, crude oil and condensate 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 proved reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting future rates of production and timing of development expenditures, including many factors beyond the
control of the Company.our control. Reserve engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact manner, and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgement.judgment. The quantities of crude oil and natural gas that are ultimately recovered, production and operating costs, the amount ofand timing of future development expenditures, and future crude oil and natural gas sales prices may all differ from those assumed in these estimates. Therefore, the pre-tax SEC PV10 value amounts shown above should not be construed as the current market value of the estimated oil and natural gas reserves attributable to the
Company'sour properties. The information set forth in the foregoing tables includes revisions of certain volumetric reserve estimates attributable to proved properties included in the preceding year'syear’s estimates. Such revisions are the result of additional information from subsequent completions and production history from the
Page 16
properties involved or the result of a decrease (or increase) in the projected economic life of such properties resulting from changes in production prices.
Acreage
The following table sets forth the Company'sour developed and undeveloped acreage at December 31, 2000.2002. The Company's acreage is located in the eastern and southern portions of the United States.
Gross Acreage | Net Acreage | |||
(in thousands) | ||||
Developed | 611 | 487 | ||
Undeveloped | 246 | 131 | ||
Total | 857 | 618 | ||
Wells Drilled
The following table sets forth the gross and net number of exploratory and development wells drilled during the last three years. The number of wells drilled meansrefers to the number of wells spud at any time during the respective year. Net wells equal the number of gross wells multiplied by Penn Virginia'sour working interest in each of the gross wells. Productive wells represent either wells which were producing or which were capable of commercial production.
2002 | 2001 | 2000 | ||||||||||
Gross | Net | Gross | Net | Gross | Net | |||||||
Development | ||||||||||||
Productive | 87 | 58.4 | 125 | 96.1 | 99 | 75.3 | ||||||
Non-productive | 3 | 2.5 | 5 | 5.0 | 1 | 0.9 | ||||||
90 | 60.9 | 130 | 101.1 | 100 | 76.2 | |||||||
Exploratory | ||||||||||||
Productive | 3 | 3.0 | 19 | 14.5 | 1 | 0.2 | ||||||
Non-productive | 3 | 1.6 | 5 | 3.5 | 5 | 1.3 | ||||||
Under evaluation | — | — | — | — | 3 | 1.4 | ||||||
6 | 4.6 | 24 | 18.0 | 9 | 2.9 | |||||||
Total | 96 | 65.5 | 154 | 119.1 | 109 | 79.1 | ||||||
Productive Wells
The number of productive oil and gas wells in which Penn
Virginiawe had a working interest at December 31, 20002002 is set forth below. Productive wells are producing wells or wells capable of commercial production.
Operated Wells | Non-Operated Wells | Total | ||||||||
Gross | Net | Gross | Net | Gross | Net | |||||
692 | 668 | 430 | 63 | 1,122 | 731 | |||||
In addition to the above working interest wells, Penn Virginia owns royalty interests in 1,7832,346 gross wells.
Page 17
Coal Royalty and Land Management
Penn Virginia's
The Partnership’s coal reserves and timber assets at December 31, 20002002 covered 188,000241,000 acres, including fee and leased acreage,in central
Appalachia.Virginia, West Virginia, New Mexico and eastern Kentucky. The coal reserves are in various surface and underground seams.
Penn Virginia's mineable
The Partnership’s proven and merchantableprobable coal reserves are estimated at 480615 million tons as of December 31, 2000. Mineable2002. Reserves are coal tons that can be economically extracted or produced at the time of determination considering legal, economic and merchantabletechnical limitations. Proven coal reserves meansare reserves for which (a) the quantity is computed from dimensions revealed in outcrops, trenches, working or drill holes; grade and/or quality are computed from the results of detailed sampling; and (b) the sites for inspection, sampling and measurement are spaced so closely, and the geologic character is so well defined, that the size, shape, and depth and mineral content of reserves are well-established. Probable coal reserves are reserves for which quantity and grade and/or quality are computed from information similar to that used for proven reserves, but the sites for inspection, sampling and measurement are farther apart or are otherwise less adequately spaced. The degree of assurance, although lower than that for proven reserves, is economically
mineable using existing equipmenthigh enough to assume continuity between points of observation.
In areas where geologic conditions indicate potential inconsistencies related to coal reserves, the Partnership performs additional drilling to ensure the continuity and methods under federal and
state laws nowmineablility of coal reserves. Consequently, sampling in effect. those areas involves drill holes that are spaced closer together than those distances cited above.
Reserve estimates are adjusted annually for production, unmineable areas, acquisitions and sales of coal in place. The majority of the Company'sPVR’s reserves are high in energy content, low in sulfur and suitable for either the steam or metallurgical markets.
The amount of coal a lessee can profitably mine at any given time is subject to several factors and may be substantially different from "mineable“proven and merchantableprobable reserves."” Included among the factors that influence profitability are the existing market price, coal quality and operating costs.
The Company'sPartnership’s timber assets consist of various hardwoods, primarily red oak, white oak, yellow poplar and black cherry. At December 31, 2000,2002, the CompanyPartnership owned an estimated 177 million
board feet168 MMbf of standing saw timber.
Coal Reserves
The following table sets forth the coal reserves that are owned
and leased by the Company. The reserves are estimated internally
by the Company's engineers.
ITEM 3 - LEGAL–LEGAL PROCEEDINGS
The Company is
We are involved in various legal proceedings arising in the ordinary course of business. While the ultimate results of these cannot be predicted with certainty, Company management believes these claims will not have a material effect on the
Company'sour financial position, liquidity or operations.
ITEM 4 - SUBMISSION–SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
There were no matters submitted to a vote of security holders during the fourth quarter of 2000.
2002.
Page 18
PART II
ITEM 5 - MARKET–MARKET FOR THE COMPANY'SCOMPANY’S COMMON STOCK AND RELATED STOCKHOLDER MATTERS
Common Stock Market Prices And Dividends
High and low closing stock prices and dividends for the last two years were:
2002 | 2001 | |||||||||||||||||
Sales Price | Cash Dividends Paid | Sales Price | Cash Dividends Paid | |||||||||||||||
High | Low | High | Low | |||||||||||||||
Quarter Ended: | ||||||||||||||||||
March 31 | $ | 40.15 | $ | 26.84 | $ | 0.225 | $ | 37.39 | $ | 30.00 | $ | 0.225 | ||||||
June 30 | $ | 41.87 | $ | 32.58 | $ | 0.225 | $ | 45.10 | $ | 31.10 | $ | 0.225 | ||||||
September 30 | $ | 38.98 | $ | 30.30 | $ | 0.225 | $ | 38.41 | $ | 27.15 | $ | 0.225 | ||||||
December 31 | $ | 36.90 | $ | 30.35 | $ | 0.225 | $ | 38.50 | $ | 27.90 | $ | 0.225 | ||||||
The Company'sCompany’s common stock is traded on the New York Stock Exchange under the symbol PVA.
Page 19
ITEM 6 - SELECTED–SELECTED FINANCIAL DATA
Five Year Selected Financial Data
Year Ended December 31, | 2002 | 2001 | 2000 | 1999 | 1998 | ||||||||||
(in thousands except share data) | |||||||||||||||
Revenues | $ | 110,957 | $ | 96,571 | $ | 105,998 | $ | 47,697 | $ | 38,324 | |||||
Operating income (a,b) | $ | 30,791 | $ | 1,563 | $ | 65,684 | $ | 20,715 | $ | 10,273 | |||||
Net income (c) | $ | 12,104 | $ | 34,337 | $ | 39,265 | $ | 14,504 | $ | 9,591 | |||||
Per common share: | |||||||||||||||
Net income, basic | $ | 1.35 | $ | 3.92 | $ | 4.76 | $ | 1.73 | $ | 1.15 | |||||
Net income, diluted | $ | 1.34 | $ | 3.86 | $ | 4.69 | $ | 1.71 | $ | 1.13 | |||||
Dividends paid | $ | 0.90 | $ | 0.90 | $ | 0.90 | $ | 0.90 | $ | 0.90 | |||||
Weighted average shares outstanding, basic |
| 8,930 |
| 8,770 |
| 8,241 |
| 8,406 |
| 8,310 | |||||
Weighted average shares outstanding, diluted |
| 8,974 |
| 8,896 |
| 8,371 |
| 8,480 |
| 8,463 | |||||
Total assets (d) | $ | 586,292 | $ | 457,102 | $ | 268,766 | $ | 274,011 | $ | 256,931 | |||||
Long-term debt(e) | $ | 106,887 | $ | 46,887 | $ | 47,500 | $ | 78,475 | $ | 37,967 | |||||
Minority interest in PVR | $ | 192,770 | $ | 144,039 | $ | — | $ | — | $ | — | |||||
Shareholders’ equity | $ | 187,956 | $ | 185,454 | $ | 171,162 | $ | 154,343 | $ | 170,259 | |||||
| (a) | Certain reclassifications have been made to conform to the current year presentation. |
| (b) | Operating income in 2002 includes a $0.8 million impairment on oil and gas properties. Operating income in 2001 included a $33.6 million impairment on oil and gas properties. Operating income in 2000 |
| (c) | Net income |
| (d) | Total assets |
| (e) | Long-term debt |
Page 20
ITEM 7 - MANAGEMENT'S–MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Management's Discussion and Analysis of Financial Condition and Results
of Operations
The following review of operations and financial condition of Penn Virginia Corporation and subsidiaries should be read in conjunction with the Consolidated Financial Statements and Notes thereto.
Overview
Penn Virginia's net incomeVirginia Corporation (“Penn Virginia” or the “Company”) is an independent energy company that is engaged in two primary business segments. Our oil and gas segment explores for, 2000 was $39.3 million or $4.69
per share (diluted) with operating income of $40.8 milliondevelops and revenues of $81.2 million. The comparable 1999 results were net
income of $14.5 million or $1.71 per share (diluted), operating
income of $20.4 millionproduces crude oil, condensate and revenues of $47.4 million. The
results for 2000 reflected the sale of non-strategic natural gas properties located primarily in Kentuckythe eastern and West Virginia.
ExcludingGulf Coast onshore areas of the $23.9 million ($14.2 million after tax) gain onUnited States. Our coal royalty and land management segment operates through our ownership in Penn Virginia Resource Partners, L.P. (the “Partnership” or “PVR”), a Delaware limited partnership, see Note 2 (Penn Virginia Resource Partners, L.P.) of the sale, net income would have been $25.1 million for 2000,Notes to the Consolidated Financial Statements.
We are committed to increasing value to our shareholders by conducting a 73balanced program of investment in our two business segments. In the oil and gas segment, we intend to execute a program combining relatively low risk, moderate return development drilling in the east with higher risk, higher return exploration and development drilling in the onshore Gulf Coast, supplemented periodically with acquisitions. In addition to our continuing development program, we are expanding our eastern presence by developing coalbed methane gas reserves in Appalachia. By employing horizontal drilling techniques, we expect to increase production rates from coalbed methane reserves we own. We are also committed to expanding our onshore Gulf Coast reserves and production internally through our drilling program and by acquiring reserves with favorable return potential.
In 2002, these efforts resulted in a 47 percent increase over 1999. The 2000 increases were a direct
result ofin oil and gas production from 2001, and we expect an increase in price the Company received for its
natural2003 oil and gas production and anof at least 30 percent, with a corresponding increase in production attributableoperating cash flow. In January 2003, we completed an acquisition of approximately 31.8 Bcfe of proved reserves in the South Texas area of the onshore Gulf Coast region for $32.5 million, which will provide a significant part of the expected growth in 2003 production.
Our oil and gas capital expenditures for 2003, including the January 2003 South Texas acquisition, are expected to be $110 to $120 million. Borrowings against our $140 million credit facility were $16 million as of December 31, 2002, and we expect to fund our 2003 capital expenditures with a combination of internal cash flow and credit facility borrowings.
During 2002, PVR completed its first two coal reserve acquisitions since its initial public offering in October 2001. In December 2002, PVR announced the formation of a strategic alliance with Peabody, resulting from the purchase from and leaseback to Peabody of approximately 120 million tons of coal reserves in New Mexico and northern West Virginia for $72.5 million in cash and a total of 2.76 million common units and Class B common units. The Peabody Acquisition significantly expanded PVR’s geographic diversity and included incentives for Peabody to source additional assets to the acquisitionPartnership in the future. In August 2002, PVR also purchased approximately 16 million tons of certain naturalcoal reserves in northern West Virginia for $12.0 million. The two acquisitions are expected to contribute 12.3 million to 12.9 million tons of production and $16.5 million to $17.5 million of cash flow from operations to PVR in 2003.
Coal-related capital expenditures in 2003 are expected to be $3.0 to $3.3 million for the construction of new coal service-related projects for which PVR will collect a fee. As of December 31, 2002, PVR had borrowed $90.9 million against its credit facility, and it is currently attempting to refinance those borrowings with a more permanent form of debt. The Partnership expects to complete the refinancing during the first quarter of 2003. Cash flow from operations, supplemented with credit facility borrowings, are expected to be adequate for PVR to fund 2003 capital expenditures and distributions to unitholders.
Critical Accounting Policies and Estimates
Oil and Gas Properties.We use the successful efforts method of accounting for our oil and gas operations. Under this method of accounting, costs to acquire mineral interests in oil and gas properties and to drill and equip development wells (including development dry holes) are capitalized and amortized on a unit-of-production basis over the remaining life of proved developed reserves and proved reserves, respectively. Costs of drilling exploratory wells are initially capitalized, and later charged to expense upon determination that the well does not justify commercial development. Other exploratory costs, including annual delay rentals and geological and geophysical costs, are charged to expense when incurred.
Page 21
The costs of unproved leaseholds are capitalized pending the results of exploration efforts. Unproved leasehold costs are assessed periodically, on a property-by-property basis, and a loss is recognized to the extent, if any, the cost of the property has been impaired. As unproved leaseholds are determined to be productive, the related costs are transferred to proved leaseholds. As of December 31, 2002, we had approximately $57.6 million of unproved leasehold costs included in Mississippi, West Virginiaoil and Kentucky as well as higher levelsgas properties on our consolidated balance sheet. We expect to complete an evaluation of coal royalties.
Management is committed to expanding its natural gas operationsour unproved leaseholds over the next several years through a combination of exploitationtwo to three years.
Other Property and explorationEquipment.Other property and equipment is carried at cost and includes expenditures for additions and improvements, which substantially increase the productive lives of existing assets. Maintenance and repair costs are expensed as incurred. Depreciation of property and equipment is generally computed using the straight-line method over their estimated useful lives, varying from 3 years to 20 years. Coal properties are depleted on an area-by-area basis at a rate based upon the cost of the mineral properties and acquisitionsestimated proven and probable tonnage therein. When an asset is retired or sold, its cost and related accumulated depreciation are removed from the accounts. The difference between undepreciated cost and proceeds from disposition is recorded as a gain or loss.
Impairment of new
properties. During 2000, the Company acquired naturalLong-Lived Assets.We review our long-lived assets to be held and used, including proved oil and gas properties in West Virginia and eastern Kentucky at a costthe Partnership’s coal properties, whenever events or circumstances indicate that the carrying value of $34.7 million. At December 31, 2000,those assets may not be recoverable. An impairment loss must be recognized when the properties hadcarrying amount of an asset exceeds the sum of the undiscounted estimated future cash flows. In this circumstance, we would recognize an impairment loss equal to the difference between the carrying value and the fair value of the asset. Fair value is estimated to be the expected present value of future net cash flows from proved reserves, of approximately 33 billion cubic feet (Bcf) in addition
to significant drilling potential. The Company continued to
develop the property it acquired in July 1999 in Mississippi for
$13.7 million by drilling 41 gross wells (37.7 net) in 2000. The
acquisition, which was 99 percent natural gas, added 23.3 Bcfe in
proved reserves and provided numerous future drilling locations.
The Company drilled seven gross (1.4 net) exploratory wells indiscounted utilizing a Texas onshore gulf coast exploration project, of which one gross
(0.2 net) well was successful, four gross (0.8 net) wells were
non-productive and two gross (0.4 net) wells are under
evaluation. The Company is still evaluating the unproved
properties associatedrisk-free interest rate commensurate with the 20 percent working interest inremaining lives for the project.
Historically, Penn Virginia has focused most of its operations
in the eastern United Statesrespective oil and particularly in Appalachia.
However, the Company believes continued growth opportunities,
especially ingas properties.
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. Each working interest owner in a well generally has the right to a specific percentage of production, and often actual production sold for any particular owner will be enhanceddiffer from such owner’s ownership percentage. When, under contract terms, these differences are settled in cash, revenues are adjusted accordingly.
Coal Royalties. Coal royalty revenues are recognized on the basis of tons of coal sold by a presence
outside the Appalachian Basin.
The Company continued its ambitious drilling program in 2000 by
drilling 109 gross (79.1 net) wells. In 2000, Penn Virginia
produced a record 11.8 Bcfe of oilPartnership’s lessees and natural gas, which was a
33 percent increase over 1999.
Penn Virginia participates in the coal industry exclusively
through its royalty ownership. The Companycorresponding revenue from those sales. Coal leases the rights to
mine its coal reserves to various operators who pay aother than those with Peabody affiliates are based on minimum monthly or annual payment,payments, a minimum dollar royalty per ton and/or a percentage of the gross sales price. SincePeabody leases are leased on fixed royalties which escalate annually and also provide for minimum monthly payments.
Coal Services.Coal services revenues are recognized when lessees use the CompanyPartnership’s facilities for the processing and transportation of coal. Coal services revenues consist of fees collected from the Partnership’s lessees for the use of the Partnership’s loadout facility, coal preparation plant, dock loading facility.
Timber.Timber revenues are recognized as timber is sold on a contract basis where independent contractors harvest and sell the timber and, from time to time, in a competitive bid process involving sales of standing timber on individual parcels. Title and risk of loss pass to the independent contractors upon the execution of the contract. In addition, if the contractors do not harvest the timber within the specified time period, the title of the timber reverts back to the Partnership with no refund of original payment.
Minimum Rentals. Most of the Partnership’s lessees must make minimum monthly or annual payments that are generally recoupable over certain time periods. These minimum payments are recorded as deferred income. If the lessee recoups a minimum payment through production, the deferred income attributable to the minimum payment is recognized as coal royalty revenues. If a lessee fails to meet its minimum production for certain pre-determined time periods (the recoupment period), the deferred income attributable to the minimum payment is recognized as minimum rental revenues. Revenues associated with minimum rentals are included in other revenues.
Price Risk Management Activities.From time to time, we enter into derivative financial instruments to mitigate our exposure to natural gas and crude oil price volatility. The derivative financial instruments, which are placed with major financial institutions that we believe are minimum credit risks, take the form of costless collars and swaps. All derivative instruments are recorded on the balance sheet at fair value. If the derivative does not minequalify as a hedge or is not designated as a hedge, the coal,gain or loss on the coal royaltyderivative is recognized currently in earnings. To qualify for hedge accounting, the derivative must qualify either as a fair value hedge, cash flow hedge or foreign currency hedge. Currently, we are utilizing only cash flow hedges and landthe remaining discussion will relate exclusively to this type of derivative instrument. All hedge transactions are subject to our risk management segmentpolicy, which has relatively high margins. Coal royaltybeen reviewed and land management
segmentapproved by the Board of Directors. We formally document all relationships between hedging instruments and hedged items, as well as its risk-management objective and strategy for undertaking various hedge transactions. This process includes linking
Page 22
all derivatives that are designated as cash flow hedges to forecasted transactions. We also formally assess, both at inception of the hedge and on an ongoing basis, whether the derivatives that are used in hedging transactions are highly effective in offsetting changes in cash flows of hedged transactions. We measure hedge effectiveness on a period basis. When it is determined that a derivative is not highly effective as a hedge, or that it has ceased to be a highly effective hedge, we discontinue hedge accounting prospectively. When hedge accounting is discontinued because it is probable that a forecasted transaction will not occur, the derivative will continue to be carried on the balance sheet at its fair value, and gains and losses that were accumulated in other comprehensive income will be recognized in earnings immediately. In all other situations in which hedge accounting is discontinued, the derivative will be carried at its fair value on the balance sheet, with changes in its fair value recognized in earnings prospectively. Gains and losses on hedging instruments when settled are included in natural gas or crude oil production revenues increased $9.8in the period that the related production is delivered. The fair values of our hedging instruments are determined based on third party forward price quotes for NYMEX Henry Hub and West Texas Intermediate closing prices.
Reserves.There are many uncertainties inherent in estimating crude oil and natural gas reserve quantities, projecting future production rates and projecting the timing of future development expenditures. In addition, reserve estimates of new discoveries are more imprecise than those of properties with 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 at the end of the respective years. Proved developed reserves are those reserves expected to be recovered through existing equipment and operating methods.
Results of Operations
Selected Financial Data – Consolidated
2002 | 2001 | 2000 | |||||||
(in millions, except share data) | |||||||||
Revenues | $ | 111.0 | $ | 96.6 | $ | 106.0 | |||
Operating costs and expenses |
| 80.2 |
| 95.0 |
| 40.3 | |||
Operating income |
| 30.8 |
| 1.6 |
| 65.7 | |||
Net income |
| 12.1 |
| 34.3 |
| 39.3 | |||
Net income per share, basic |
| 1.35 |
| 3.92 |
| 4.76 | |||
Net income per share, diluted |
| 1.34 |
| 3.86 |
| 4.69 | |||
Cash flows provided by operating activities |
| 65.8 |
| 44.2 |
| 41.7 | |||
Consolidated Net Income
Our 2002 net income was $12.1 million, or 45 percent, to an all-
time high of $31.9compared with $34.3 million in 2001 and $39.3 million in 2000. The increase was
attributable to acquisitions, enhanced production from lessees
due to the completion of the unit train loadout facility and
start-up operations from other lessees. The Company continues to
diversify its coal customer base by adding additional lessees and
by searchingRevenues for additional coal reserve acquisition
opportunities.
The Company had its first full year of usage for the $5.2
million state-of-the-art coal loadout facility in Virginia
completed in April 1999. The facility accommodates 100 rail car
unit trains which can be loaded in approximately four hours, thus
generating substantial savings for the Company's lessees. The
loadout is primarily utilized by the Company's lessees and
provides them a competitive advantage by reducing delivery costs
to their principal customers. The loadout facility transshipped
2.5 million tons in 2000, generating $1.9 million in fees.
Additionally, the loadout facility has accelerated the cash flow
received by the Company, primarily due to increased production
from lessees. Other infrastructure projects are underway or
being evaluated.
In September 1999, Penn Virginia completed a $30 million
acquisition which included over 90 million tons of high quality
coal reserves, as well as oil and gas leases, timber assets, a
short line railroad and a coal loading dock on the Kanawha River.
The acquisition covers over 24,000 acres and complements the
existing asset base of the Company's Coal River Properties in
West Virginia.
At December 31, 2000, the Company owned 3,307,200 shares of
Norfolk Southern common stock, which decreased in price from
$20.50 per share at December 31, 1999 to $13.31 per share,
reducing the value of the investment by $23.7 million, or $15.4
million after tax. Penn Virginia received a quarterly dividend
of $0.20 per share in 2000, 1999 and 1998; however, in January
2001, Norfolk Southern Corporation reduced its quarterly dividend
to $0.06 per share.
Results of Operations
Consolidated Net Income
Penn Virginia's 2000 net income was $39.32002 were $111.0 million, compared with $14.5$96.6 million and $106.0 million in 19992001 and $9.6 million in 1998. Revenues for
2000, were $81.2 million,respectively.
The 2001 results included a 71 percent increase over 1999 and a
112 percent increase over 1998. Significant factors for the
increase in 2000 include (a) increased natural gas production
resulting from an acquisition in May 2000, (b) a substantial
increase the average price received for natural gas and (c)
higher levels of coal royalties and fees received in connection
with the coal loading facility. In addition, apre-tax gain of $23.9
million ($14.2 million after tax) was recognized in December 2000
foron the sale of mature oil and gas properties located primarilysecurities of approximately $54.7 million ($35.5 million after tax). Also included in Kentucky and West Virginia. The increase in net income for
1999the 2001 results was a direct result of increased production of natural gas
and higher levels of coal royalties. Net income for 1998
included a non-cash charge relating to impairmentsthe impairment of certain oil and gas properties, of $4.6for which we recorded a $33.6 million ($3.721.8 million after tax) impairment charge. In addition to the gain on sale of securities, net of the impairment charge noted above, the decrease in 2002 net income from 2001 was primarily due to a decline in commoditylower natural gas prices and the minority interest resulting from the ownership change of our coal reserves in connection with the initial public offering of the Partnership’s common units in the fourth quarter of 2001.
In 2000, we recorded a restructuring charge of $0.6 million ($0.4 million after tax).
Net income includes apre-tax gain of approximately $23.9 million ($14.215.5 million after tax) on the sale of non-strategic oil andnatural gas properties located in December 2000.
Corporate and Other
Dividends. In April 2001, we sold 3.3 million shares of common stock of Norfolk Southern Corporation at an average selling price of $17.39 per share. Proceeds, net of commissions, totaled approximately $57.4 million. As a result, dividend income decreased from $2.6 million in 2000 to the
current year presentation.
Page 23
Oil and Gas Segment
The
In our oil and gas segment, exploreswe explore for, developsdevelop and producesproduce crude oil and natural gas in the eastern and southern portionsGulf Coast onshore regions of the United States. The Company also owns mineral rights to
We use the successful efforts method of accounting for our oil and gas reserves.
The costs of unproved leaseholds are capitalized pending the results of exploration efforts. Unproved leasehold costs are assessed periodically, on a property-by-property basis, and a loss is recognized to the extent, if any, the cost of the property has been impaired. As unproved leaseholds are determined to be productive, the related costs are transferred to proved leaseholds.
Oil and natural gas revenues are generally recorded using the entitlement method in which we recognize our ownership interest in the production as revenue. Each working interest owner in a well generally has the right to a specific percentage of production, although actual production sold may differ from an ownership percentage. Using entitlement accounting, a receivable is recorded when sales are less than our entitlement and deferred revenue is recognized when sales are greater than our entitlement.
We review our long-lived assets, including proved oil and natural gas properties, for possible impairment whenever events or circumstances indicate that the carrying value of those assets may not be recoverable. An impairment loss must be recognized when the carrying amount of an asset exceeds the sum of the undiscounted estimated future cash flows. In this circumstance, we would recognize an impairment loss equal to the difference between the carrying value and the fair value of the asset. Fair value is estimated using the expected present value of future net cash flows from proved reserves, utilizing a risk-free interest rate.
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.
Page 24
Selected Financial and Operating Data – Oil and Gas
2002 | 2001 | 2000 | |||||||||
(in thousands, except as noted) | |||||||||||
Revenues | |||||||||||
Oil and condensate | $ | 8,246 |
| $ | 3,762 |
| $ | 832 | |||
Natural gas | $ | 62,552 |
|
| 53,263 |
|
| 46,019 | |||
Other |
| 714 |
|
| 753 |
|
| 24,554 | |||
Total Revenues | $ | 71,512 |
| $ | 57,778 |
| $ | 71,405 | |||
Expenses | |||||||||||
Lease operating |
| 9,253 |
|
| 5,631 |
|
| 4,562 | |||
Exploration |
| 7,549 |
|
| 11,514 |
|
| 5,080 | |||
Taxes other than income |
| 5,618 |
|
| 4,439 |
|
| 2,809 | |||
General and administrative |
| 8,381 |
|
| 5,330 |
|
| 2,656 | |||
Operating expenses before non-cash charges |
| 30,801 |
|
| 26,914 |
|
| 15,107 | |||
Depreciation, depletion and amortization |
| 26,336 |
|
| 16,418 |
|
| 9,883 | |||
Impairment of properties |
| 796 |
|
| 33,583 |
|
| — | |||
Total Operating Expenses |
| 57,933 |
|
| 76,915 |
|
| 24,990 | |||
Operating Income (Loss) | $ | 13,579 |
| $ | (19,137 | ) | $ | 46,415 | |||
Production | |||||||||||
Oil and condensate (Mbbls) * |
| 349 |
|
| 164 |
|
| 31 | |||
Natural gas (MMcf) * |
| 18,697 |
|
| 13,130 |
|
| 11,645 | |||
Total production (MMcfe) * |
| 20,791 |
|
| 14,114 |
|
| 11,831 | |||
Realized prices | |||||||||||
Oil and condensate ($/Bbl) | $ | 23.63 |
| $ | 22.94 |
| $ | 26.84 | |||
Natural gas ($/Mcf) |
| 3.35 |
|
| 4.06 |
|
| 3.95 | |||
Production cost ($/Mcfe) | |||||||||||
Lease operating expense | $ | 0.45 |
| $ | 0.40 |
| $ | 0.38 | |||
Taxes other than income |
| 0.27 |
|
| 0.31 |
|
| 0.24 | |||
General and administrative expense |
| 0.40 |
|
| 0.38 |
|
| 0.22 | |||
Total production cost | $ | 1.12 |
| $ | 1.09 |
| $ | 0.84 | |||
Hedging Summary | |||||||||||
Natural gas prices ($/Mcf): | |||||||||||
Actual price received for production | $ | 3.39 |
| $ | 3.92 |
|
| 3.95 | |||
Effect of hedging activities |
| (0.04 | ) |
| 0.14 |
|
| — | |||
Average realized price | $ | 3.35 |
| $ | 4.06 |
| $ | 3.95 | |||
Crude oil prices ($/Bbl): | |||||||||||
Actual price received for production | $ | 24.39 |
| $ | 22.45 |
| $ | 26.84 | |||
Effect of hedging activities |
| (0.76 | ) |
| 0.49 |
|
| — | |||
Average realized price | $ | 23.63 |
| $ | 22.94 |
| $ | 26.84 | |||
* Production for 2002 does not include 16 Mbbls of oil and condensate and 18 MMcf of natural gas production, or 114 MMcfe, related to discontinued operations. 2001 production volumes for properties sold were insignificant.
Page 25
Year Ended December 31, 20002002 Compared to Year Ended December 31,1999
31, 2001
Revenues.Oil and gas revenues increased $24.6$13.7 million to $47.5$71.5 million in 20002002 from 19992001 primarily due to a $24.6 millionan increase in natural gas sales.
Natural gas sales increased 115 percent to a record $46.0
million due to a 34 percent increase in production coupled with a
61 percent increase in the average price received per Mcf. The
Company's $34.7 million acquisition of mineral interests in May
2000 represents 1,111 MMcf of the 2,966 MMcf increase incrude oil and natural gas production.
Crude oil and natural gas production increased to 20.8 Bcfe in 2002, a 47 percent increase over 2001. The developmentincrease was primarily due to the inclusion of Penn Virginia's $13.7 million
acquisitiona full year of production from the Gulf Coast oil and gas properties acquired in July 1999 accounted for 1,511 of the increase with
the remainder attributable to2001 and development drilling success in Appalachia.
Naturalconnection with our Gulf Coast, Mississippi and Appalachian assets. Approximately 90 percent of our 2002 production was natural gas.
The average natural gas price received during 2002 was $3.35 per Mcf compared with $4.06 per Mcf in 2001, a 17 percent decrease. The average oil price received was $23.63 per barrel for 2002, up three percent from $22.94 per barrel in 2001.
Due to the volatility of crude oil and natural gas prices, were extremely volatile in 2000. In April
and May of 2000, the Company entered into several physical
contracts that totaled 9,289 MMcf per day for the remainder of
2000. The volumes under contract accounted for 20 percent of
Penn Virginia's 2000 production at a price of $3.39 per Mcf. The
Company had one contract remaining that expires in March 2001
covering 18 percent of anticipated first quarter production at
$3.12 per Mcf.
The Company, from time to time, hedgeswe sometimes hedge the price received for market-sensitive productionsales volumes through the use of swaps with
purchased options.and costless collars. Gains and losses from hedging activities are included in natural gas revenues when the hedged production occurs. The CompanyWe recognized a loss on settled hedging activities of $0.4$1.0 million in 19992002 and $0.7a gain of $1.9 million in 19982001.
Operating expenses. Production costs increased from $5.6 million in 2001 to $9.3 million in 2002. The increase was primarily attributable to the full year impact of operating costs related to our acquisition of certain Gulf Coast oil and gas properties in late July of 2001.
Exploration expenses decreased from $11.5 million in 2001 to $7.5 million in 2002 due to lower exploratory dry hole costs incurred this year. Seismic expenditures were $4.7 million in 2002, up from $2.2 million in 2001. The impact of these higher costs was offset by reduced write-offs of unproved property in 2002.
Taxes other than income taxes increased by $1.2 million to $5.6 million in 2002. The increased taxes were a result of the higher production and revenue levels in 2002.
General and administrative (“G&A”) expenses increased to $8.4 million in 2002 from $5.3 million in 2001. The increase was primarily attributable to our acquisition of the Gulf Coast oil and gas properties in July 2001 and related personnel expenses.
Oil and gas depreciation, depletion and amortization (“DD&A”) increased to $26.3 million in 2002 from $16.4 million in 2001. This increase was primarily due to increased production related to the Gulf Coast assets acquired in July 2001, as well as increased DD&A rates due to changes in reserve estimates and capital additions.
Year Ended December 31, 2001 Compared to Year Ended December 31, 2000
Revenues.Oil and gas revenues increased $10.2 million to $57.0 million in 2001 from 2000 primarily due to an increase in crude oil and natural gas production.
Crude oil and natural gas sales combined increased 22 percent to $57.0 million due to a 19 percent increase in production. The increase was primarily due to production related to our acquisition of certain Gulf Coast oil and gas properties in July 2001 and to increased production from the Gwinville Field, offset in part by production lost from properties disposed of in the fourth quarter of 2000. Approximately 93 percent of our 2001 production was natural gas. The average natural gas price received during 2001 was $4.06 per Mcf compared with $3.95 per Mcf in 2000, a three percent increase. The average oil price received was $22.94 per barrel for 2001, down 15 percent from $26.84 per barrel in 2000. We recognized a gain of $1.9 million in 2001 on hedging activities with no gain or loss recognized in 2000. Effective January 1, 2001, the Company
will account for its derivative activities in accordance with
Statement of Financial Accounting Standards ("SFAS") No. 133, as
amended by SFAS No. 137 and SFAS No. 138. See Note 2 (New
Accounting Standards) in the financial statements.
Operating expenses. Production costs, consisting of lease operating expense and taxes other than income, increased from $6.3 million in 1999 to $7.4 million in 2000.2000 to $10.0 million in 2001. Production costs decreasedincreased from $0.62 per Mcfe in 2000 to $0.71 per Mcfe in 1999 to $0.62 per Mcfe in 2000.
A decrease, on a Mcfe basis, of $0.06 resulted from the Company's
May 2000 acquisition of royalty interest for $34.7 million.2001. The remainder of the decrease isincrease was primarily attributable to the low operating
costs associated with the increased production from the Company's
1999 acquiredacquisition of certain Gulf Coast oil and gas properties in Mississippi. These decreases, on a
Mcfe basis, were offset by an increase in severance taxes related
to increased average prices received in 2000.
July 2001.
Exploration expenses increased from $1.7 million in 1999 to
$5.1 million in 2000. The $5.1 million in 2000 consiststo $11.5 million in 2001. The $11.5 million in 2001 consisted of $1.7$2.4 million in seismic expenditures, charges relating to five gross (1.3(3.5 net) nonproductive exploratory wells and the impairment of unproved leasehold costs. Penn Virginia'sOur increased seismic expenditures for the year, compared with $0.31.7 million in 1999, represents2000, represented a continued effort to establish the Company'sa balanced exploratory program.
General and administrative ("
Page 26
G&A")&A expenses increased to $5.3 million in 2001 from $2.7 million in 2000 from $2.1 million in 1999; however, G&A expenses
decreased to $0.22 per Mcfe in 2000 from $0.24 Mcfe in 1999.2000. The decrease of $0.02 per Mcfe isincrease was attributable to increased
production from acquisitions and an accelerated drilling program,
offset by additional staffing necessary to accomplish those
objectives.
Oil and gas depreciation, depletion and amortization increased
to $9.9 million, or $0.84 per Mcfe, in 2000 from $7.0 million, or
$0.78 per Mcfe, in 1999. The increase is primarily to the Company's acquisitions in July 1999 and May 2000.
Other non-operating income. Gain on the saleacquisition of properties
includes $23.9 million ($14.2 million after tax) related to the
sale of mature oil and gas properties located primarily in
Kentucky and West Virginia. Proceeds from the December 2000 sale
totaled $54.3 million, after closing adjustments.
Year Ended December 31, 1999 Compared to Year Ended December 31,
1998
Revenues. Oil and gas revenues increased $1.9 million, or nine
percent, from 1998 to 1999 primarily due to a $0.8 million
increase in natural gas sales and a $0.8 million increase in
other income. Natural gas production increased eight percent,
offset by a three percent decrease in average price per Mcf. The
production increase is a result of an acquisition in Mississippi
and the Company's 1999 drilling program. Other operating income
increased $0.8 million primarily due to $0.4 million received for
the final settlement of a 1995 contract dispute and $0.2 million
for reimbursement of lost production caused by third party
pipeline damages.
Operating expenses. Production costs, consisting of lease
operating expense and taxes other than income, increased from
$6.1 million in 1998 to $6.3 million in 1999. On a Mcfe basis,
production costs decreased from $0.74 per Mcfe in 1998 to $0.71
per Mcfe in 1999. The decrease on a Mcfe basis resulted from
less tax being paid due to the relocation of the offices of the
oil and gas segment.
Exploration expenses increased from $0.5 million in 1998 to
$1.7 million in 1999. The increase is attributable to charges
relating to seven gross (3.5 net) nonproductive, exploratory
wells and preliminary field costs incurred in 1999.
Additionally, the Company's exploration program included $0.3
million in seismic expenditures.
General and administrative expenses decreased from $3.2 million
in 1998 to $2.1 million in 1999. The decrease primarily relates
to the Company's 1998 plan to reduce administrative and
operational overhead costs in its oil and gas subsidiary. In
connection with the plan, the Company recorded a pre-tax charge
to general and administrative expense totaling $0.6 million in
1998 related to severance costs for six employees and a lease
cancellation penalty. The Company completed its restructuring
plan in August 1999. There were no adjustments to the liability
recorded in 1998 that resulted in an adjustment to net income in
1999.
Oil and gas depreciation, depletion and amortization increased
to $7.0 million in 1999 but remained relatively constant on a
unit basis at $0.79 per Mcfe in 1999, compared with $6.4 million,
or $0.78 per Mcfe, in 1998.
Impairment of oil and gas properties. In accordance with SFAS
No. 121, the Company reviews its oil and gas properties for
impairment whenever events and circumstances indicate a decline
in the recoverability of their carrying value. In the fourth
quarter of 1998, the Company estimated the expected future cash
flows of its oil and gas properties and compared such future cash
flows to the carrying amount of the oil and gas properties to
determine if the carrying amount was recoverable. For those oil
and gas properties which the carrying amount exceeded the
estimated undiscounted future cash flows, an impairment was
determined to exist; thus, the Company adjusted the carrying
amount of the respective oil and gas properties to their fair
value as determined by discounting their estimated future cash
flows. The factors used to determine fair value included, but
were not limited to, estimates of proved reserves, future
commodity pricing, future production estimates, anticipated
capital expenditures and a discount rate commensurate with a risk-
adjusted rate of return. As a result, the Company recognized a
noncash pre-tax charge of $4.6 million ($3.7 million after tax)
related to itscertain Gulf Coast oil and gas properties in late July of 2001 and related personnel expenses.
Oil and gas DD&A increased to $16.4 million in 2000 from $9.9 million in 2000. This increase was primarily due to increased production and a higher cost basis in the producing assets. The acquisition of certain Gulf Coast oil and gas properties in July 2001 was completed when crude oil and natural gas future prices were higher than forecasted prices at year-end 2001. As a result of low commodity prices in the fourth quarter 2001, we subjected all properties to impairment testing and recognized a pretax impairment charge related primarily to our Texas properties of 1998.
Coal Royalty and Land Management Segment
The coal royalty and land management segment includes Penn Virginia'sPVR’s mineral rights to coal reserves, its timber assets and its other land assets.
The Partnership enters into leases with various third-party operators for the right to conformmine coal reserves on the Partnership’s properties in exchange for royalty payments. Coal royalty revenues under non-Peabody leases are 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. Under the Peabody leases, coal royalty revenues are 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 current year
presentation.
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 lessee’s customers to change operations significantly or incur substantial costs.
Page 27
Selected Financial and Operating Data – Coal Royalty and Land Management
2002 | 2001 | 2000 | |||||||
(in thousands, except as noted) | |||||||||
Revenues | |||||||||
Coal royalties | $ | 31,358 | $ | 32,365 | $ | 24,308 | |||
Timber |
| 1,640 |
| 1,732 |
| 2,388 | |||
Coal services |
| 1,704 |
| 1,660 |
| 1,385 | |||
Other |
| 3,906 |
| 1,756 |
| 2,108 | |||
Total Revenues |
| 38,608 |
| 37,513 |
| 30,189 | |||
Expenses | |||||||||
Operating |
| 3,807 |
| 3,812 |
| 3,480 | |||
General and administrative |
| 6,419 |
| 5,459 |
| 4,847 | |||
Operating expenses before non-cash charges |
| 10,226 |
| 9,271 |
| 8,327 | |||
Depreciation, depletion and amortization |
| 3,955 |
| 3,084 |
| 2,047 | |||
Total Operating Expenses |
| 14,181 |
| 12,355 |
| 10,374 | |||
Operating Income | $ | 24,427 | $ | 25,158 | $ | 19,815 | |||
Production | |||||||||
Royalty coal tons produced by lessees (thousands) |
| 14,281 |
| 15,306 |
| 12,536 | |||
Timber sales (Mbf) |
| 8,345 |
| 8,741 |
| 8,545 | |||
Prices | |||||||||
Royalty per ton | $ | 2.20 | $ | 2.11 | $ | 1.94 | |||
Timber sales price per Mbf | $ | 187 | $ | 168 | $ | 257 | |||
Year Ended December 31, 20002002 Compared to Year Ended December 31, 1999
Revenues.2001
Revenues. Coal royalty and land management segment revenues for the year ended December 31, 2002 were $38.6 million compared to $37.5 million for the year ended December 31, 2001, an increase of $1.1 million, or three percent.
Coal royalty revenues for the year ended December 31, 2002 were $31.4 million compared to $32.4 million for the year ended December 31, 2001, a decrease of $1.0 million, or three percent. Over these same periods, production decreased by 1.0 million tons, or seven percent, from 15.3 million tons to 14.3 millions tons. These decreases were primarily due to weaker coal demand in 2002 in general, and more specifically, the idling of production at the Fork Creek property caused by the lessee’s bankruptcy.
Timber revenues decreased to $1.6 million for the year ended December 31, 2002 from $1.7 million for the year ended December 31, 2001, a decrease of $0.1 million, or five percent. Volume sold declined 396 thousand board feet (Mbf), or five percent, to 8,345 Mbf in 2002, compared to 8,741 Mbf for 2001.
Coal services revenues remained constant at $1.7 million for the years ended December 31, 2002 and 2001. Slight increases in revenues generated from PVR’s modular preparation plants and dock loadout facility were offset by a minor reduction in revenues from its unit-train loadout facility.
Other revenues were $3.9 million for the year ended December 31, 2002 compared to $1.8 million for the year ended December 31, 2001, an increase of $2.1 million, or 122 percent. The increase was primarily due to the recognition of minimum rental payments received from the Partnership’s lessees which are no longer recoupable by the lessee. Two of PVR’s lessees, Horizon Resources, Inc. (formerly AEI Resources, Inc.) and Pen Holdings, Inc., both of which filed Chapter 11 bankruptcies during 2002, accounted for $1.9 million of minimum rental income in 2002.
Page 28
Operating expenses.Operating expenses, which include both lease operating expenses and taxes other than income, were $3.8 million for the years ended December 31, 2002 and 2001. Lease operating expenses were $2.9 million for the year ended December 31, 2002 compared to $3.2 million for the year ended December 31, 2001, a decrease of $0.3 million, or nine percent. This decrease is primarily due to a decrease in production by lessees on the Partnership’s subleased properties, offset by temporary mine maintenance costs on its Coal River property. Aggregate production from subleased properties decreased to 1.8 million tons for the year ended December 31, 2002 from 2.3 million tons for the year ended December 31, 2001. Taxes other than income for the year ended December 31, 2002 was $0.9 million compared to $0.6 million for the year ended December 31, 2001, an increase of $0.3 million, or 45 percent. The increase was primarily due to an increase in state franchise taxes resulting from the Partnership’s change from a corporate to a partnership structure in late 2001. Prior to the initial formation of the Partnership, franchise taxes were calculated based on filing as a corporation.
G&A expenses increased to $6.4 million for the year ended December 31, 2002 compared to $5.5 million for the year ended December 31, 2001, representing an 18 percent increase. The increase was primarily attributable to a full year of fees and expenses associated with the Partnership being a publicly traded entity.
Depreciation and depletion expense for the year ended December 31, 2002 was $4.0 million compared to $3.1 million for the year ended December 31, 2001, an increase of $0.9 million, or 28 percent. The increase in depreciation, depletion and amortization resulted from an increase in the depletive write-off rate per ton caused by a downward revision of coal reserves in the late 2001, higher cost coal properties being added to the depletable base as a result of recent acquisitions, and additional depreciation related to coal services capital projects.
Year Ended December 31, 2001 Compared to Year Ended December 31, 2000
Revenues. Coal royalty and land management segment revenues were $31.1$37.5 million in 2001 and $30.2 million in 2000, and $21.8 million in 1999,
representing a 4224 percent increase.
Coal royaltiesroyalty revenues increased $6.5$8.1 million from $24.3 million in 2000 primarily due to a $30$32.4 million acquisition in September 1999 and increased
production from additional lessees. Coal royalties from2001. Production increases were the acquisition were $1.5 million higher in 2000 because the Company
included a full year of operations in 2000 versus three months in
1999. The remainder ofprimary factor related to the increase was attributable to a full
year of operation for the Company's unit train loadout,
infrastructure additions by two lessees, four additional mines
added by lessees andin revenues. Royalty tons increased production2.8 million from numerous lessees
due to improved conditions in the coal industry.
Timber revenues increased $440,000, or 23 percent, to $2.4
million in 2000; however, timber harvested decreased from 9,020
Mbf in 1999 to 8,545 in 2000. The average price received by the
Company increased from $206 per Mbf in 1999 to $257 per Mbf in
2000. These variances are justified by the harvesting of Penn
Virginia's higher quality hardwoods in 2000.
Other operating income increased to $4.412.5 million in 2000 compared with $2.0to 15.3 million in 1999. Rail car rental, dock rental
and various land rentals related to the acquisition in September
1999 accounted for $1.2 million of the increase. Additionally,
$603,000 of the increase was attributable to Penn Virginia's unit
train loadout facility which had a full year of operation in 2000
versus nine months in 1999. The remainder of the increase is
primarily due to $589,000 of additional lease forfeitures
received in 2000. Lease forfeitures are recognized as revenue by
the Company when lessees fail to meet their minimum required coal2001, or 22 percent. These production for a specified time period; consequently, their non-
recoupable minimums would be forfeited and recognized as income
by the Company.
Expenses. Total operating expenses for the coal royalty and
land management segment increased 69 percent to $9.2 million from
$5.5 million in 1999.
Operating expenses increased from $784,000 in 1999 to $3.1
million in 2000. The September 1999 coal royalty acquisition
accounted for $2.2 million of the 2000 increase due to (a) $1.4
million in additional lease expense relating to newly acquired
coal reserves, (b) increased expense of $573,000increases were attributable to the leasingstart up of rail cars,five new mines, the June 2001 acquisition of new properties and (c) continuing environmental
maintenancethe completion of $213,000 to comply with governmental agency
requirements.
Exploration expenses increased $126,000 due to additional core
drilling and evaluation of samples primarily relating to Penn
Virginia's 1999 acquired coal properties.
Taxes other than income increased $157,000, or 31 percent, to
$663,000 for 2000 due to property taxes associated with the
September 1999 acquisition.
General and administrative expenses,a capital project on a per ton basis,another lease.
Timber revenues decreased to $0.24 in$1.7 million for the year ended December 31, 2001 from $2.4 million for the year ended December 31, 2000, versus $0.30 in 1999.a decrease of $0.7 million, or 27 percent. The decrease is primarily attributable to a decrease in the average price received for the timber from $257 per Mbf for the year ended December 31, 2000 to $168 per Mbf for the year ended December 31, 2001. The decrease reflects overall market conditions as well as the sale of lower priced species and lower quality timber.
Coal services revenues increased productionto $1.7 million for the year ended December 31, 2001 from $1.4 million in 2000, an increase of $0.3 million, or 20 percent. The increase is a direct result of the addition of a small preparation plant put into service during 2001 and additional usage of the Partnership’s existing coal service facilities.
Other revenues were $1.8 million for the year ended December 31, 2001 compared with $2.1 million for the year ended December 31, 2000, a decrease of $0.3 million, or 17 percent. The decrease was primarily due to gains from the sale of property and equipment in 2000, offset by additional staffing needsthe recognition of minimum rental payments received from lessees which are no longer recoupable.
Operating expenses.Operating expenses were $3.8 million for the year ended December 31, 2001 compared with $3.5 million for the year ended December 31, 2000, an increase of $0.3 million, or 10 percent. This variance is primarily due to an increase in production by lessees on PVR’s subleased properties resulting in royalty expense incurred. Production from the September 1999 coal
royalty acquisition.
Depreciation, depletion and amortizationsubleased properties increased from $1.32.1 million tons for the year ended December 31, 2000 to 2.3 million tons for the year ended December 31, 2001, an increase of 0.2 million tons, or 10 percent.
G&A expenses increased to $5.5 million for the year ended December 31, 2001 compared to $4.8 million for the year ended December 31, 2000. This increase is primarily attributable to fees associated with tax preparation and public reporting by the Partnership.
Page 29
Depreciation and depletion expense for the year ended December 31, 2001 was $3.1 million compared with $2.0 million for the year ended December 31, 2000, an increase of $1.1 million, or $0.1551 percent. This increase primarily resulted from coal production increases of 22 percent. Depreciation and depletion expense increased, on a per ton in 1999basis, to $2.0 million, or $0.16$0.20 per ton infor the year ended December 31, 2001 from $0.16 for the year ended December 31, 2000. The slight$0.04 increase on a per ton basis is due to
the Company's September 1999 acquisition of coal reserves in West
Virginia.
Other non-operating income. Gain on the sale of property was
$897,000 in 2000 primarily due to the sale of a small block of
coal reserves in eastern Kentucky.
Year Ended December 31, 1999 Compared to Year Ended December 31, 1998
Revenues. Coal royalty and land management segment revenuesresults from increased 51 percent to $21.8 million in 1999 compared with $14.5
million in 1998. The $7.5 million increase in 1999 was
attributable to enhanced production from existing lessees due to
the completion of the unit train loadout, start-up operations for
some lessees and acquisitions.
Operating expenses. The coal royalty and land management
segment's operating expenses increased $1.5 million, or 37
percent, to $5.5 million, compared with $4.0 million in 1998.
Operating expenses increased $0.5 million primarily due to
additional lease expense relating to the September 1999 coal
royalty acquisition. Exploration expenses decreased $0.3 million
to $0.2 million in 1999 primarily due to increased 1998 costs
incurred to maintainCoal River property, which has a mine on a terminated lease. General and
administrative expenses increased $0.4 million in 1999 due to
legal fees incurred by the Company to pursue the potential
recovery of coal reserves and the addition of three additional
employees in the Charleston, West Virginia office relating to the
Company's September 1999 acquisition. Depreciation, depletion
and amortization increased from $0.6 million to $1.3 million.
The increase is attributable to an increase in coal royalty tons
produced by existing lessees, the Company's September 1999
acquisition of coal reserves in West Virginia and the unit train
loadout's first year of operation.
Corporate and Other
Dividends. Dividend income of $2.6 million in 2000 remained
constant, compared with $2.6 million in 1999 and 1998. However,
in January 2001, Norfolk Southern Corporation reduced its
quarterly dividend from $0.20 per share to $0.06 per share. Penn
Virginia's holdings primarily consist of 3,307,200 shares of
Norfolk Southern Corporation.
significantly higher cost basis.
Reserves
Oil and Gas Reserves
Penn Virginia's
Our total proved reserves at year-end 2000December 31, 2002 were 174.6273.4 Bcfe, compared with 187.4252.8 Bcfe at 1999 year- end. The
decrease is attributable to the sale of mature oil and gas
properties, partially offset by acquisitions and extensions,
discoveries and other additions. Proved developed reserves
increased 6.1 Bcfe, or four percent, to 146.4 Bcfe.December 31, 2001. At year-end
2000,December 31, 2002, proved developed reserves comprised 8479 percent of the
Company'sour total proved reserves, compared with 7578 percent at year-
end 1999. The Company has 74December 31, 2001. We have 128 net proved undeveloped drilling locations at year-end 2000,December 31, 2002, compared with 13993 locations at year-
end 1999. The Company acquired 35.9 Bcfe of proved oil and gas
reserves, primarily consisting of royalty interest, during 2000
for $36.0 million. In December 2000, the Company received $54.3
million, after closing adjustments, for the sale of mature oil
and gas properties in Kentucky and West Virginia, which contained
66.6 Bcfe of proved oil and gas reserves.
Penn Virginia's comparative reserve replacement measures are as
follows:
2002 | 2001 | 2000 | ||||||||||
Proved reserves | ||||||||||||
Crude oil (Mbbls) |
| 5,361 |
|
| 3,920 |
|
| 71 |
| |||
Natural gas (MMcf) |
| 241,255 |
|
| 229,253 |
|
| 174,247 |
| |||
Proved developed reserves | ||||||||||||
Crude oil (Mbbls) |
| 2,943 |
|
| 2,212 |
|
| 71 |
| |||
Natural gas (MMcf) |
| 198,733 |
|
| 183,134 |
|
| 145,930 |
| |||
Finding and development cost (a), ($/Mcfe) | ||||||||||||
Current year | $ | 1.34 |
| $ | 3.26 |
| $ | 0.82 |
| |||
Three year weighted average |
| 1.81 |
|
| 2.66 |
|
| 1.56 |
| |||
Reserve replacement cost (b), ($/Mcfe) | ||||||||||||
Current year | $ | 1.32 |
| $ | 2.22 |
| $ | 0.92 |
| |||
Three year weighted average |
| 1.60 |
|
| 1.70 |
|
| 1.08 |
| |||
Reserve replacement percentage (c), ($/Mcfe) | ||||||||||||
Current year |
| 206 | % |
| 660 | % |
| 556 | % | |||
Three year weighted average |
| 432 | % |
| 544 | % |
| 332 | % | |||
Finding and development cost, reserve replacement cost and reserve replacement percentage are not measures presented in accordance with generally accepted accounting principles ("GAAP"(“GAAP”) and are not intended to be used in lieu of GAAP presentation. These measures are commonly used by financial statement userswithin the industry as a measurement to determine the performance of a Company'scompany’s oil and gas activities.
(a)
| (a) | Finding and development cost is calculated by dividing 1) costs incurred in certain oil and gas activities less proved property acquisitions, by 2) reserve extensions, discoveries and other additions and revisions. The 2001 finding and development costs used in this calculation included $62.2 million for unproved property acquisition costs (including the impact of deferred income taxes) related to the purchase of certain Gulf Coast oil and gas properties in the third quarter of 2001. No proved reserves were recorded relative to these unproved property acquisition costs, for which future exploration and development activities will be conducted. Had the unproved property acquisition costs been excluded from the 2001 finding and development cost calculations, 2001 and three year weighted average cost per Mcfe would have been $1.41 and $1.24, respectively. |
| (b) | Reserve replacement cost is calculated by dividing 1) costs incurred in certain oil and gas activities, including acquisitions, by 2) reserve purchases, extensions, discoveries and other additions and revisions. The 2001 reserve replacement costs used in this calculation included $62.2 million for unproved property acquisition costs described in footnote (a) above and $27.2 million of deferred income taxes on proved property acquisition costs related to the purchase of certain Gulf Coast oil and gas properties in the third quarter of 2001. Had the unproved property acquisition costs and the deferred income taxes on the proved property acquisition costs been excluded from the 2001 reserve replacement cost calculations, 2001 and three year weighted average cost per Mcfe would have been $1.26 and $1.09, respectively. |
Page 30
| (c) | Reserve replacement percentage is calculated by dividing 1) reserve purchases, revisions, extensions, discoveries and other additions, by 2) oil and gas production. |
Proven and development cost is calculated by dividing
1) costs incurred in certain oilProbable Coal Reserves
The Partnership’s proven and gas activities less proved
property acquisitions, by 2) reserve extensions, discoveries and
other additions and revisions.
(b) Reserve replacement cost is calculated by dividing 1) costs
incurred in certain oil and gas activities, including
acquisitions, by 2) reserve purchases, extensions, discoveries
and other additions and revisions.
(c) Reserve replacement percentage is calculated by dividing 1)
reserve purchases, revisions, extensions, discoveries and other
additions, by 2) oil and gas production.
Mineable and Merchantable Coal Reserves
Penn Virginia's mineable and merchantableprobable coal reserves were 480615 million tons at December 31, 2000,2002 compared with 488493 million tons in 1999. The Company collected royalties for 12.5 million
tons in 2000. Mineable and merchantable coal reserves means coal
that is economically mineable using existing equipment and
methods under federal and state laws now in effect.
Market Risk
Marketable Equity Securities. At December 31, 2000, the
Company's marketable equity securities, consisting primarily of
Norfolk Southern Corporation common stock, were recorded at their
fair value of $44.1 million, including net unrealized gains of
$41.2 million. The closing stock price for Norfolk Southern
Corporation was $13.31 and $20.50 per share at December 31, 2000
and 1999, respectively. At February 1, 2000, the closing price2001. Royalties were collected for Norfolk Southern Corporation was $16.55. The fair value of
the Company's marketable equity securities is significantly
affected by market price fluctuations. See Note 4 of the Notes
to Consolidated Financial Statements.
Interest Rate Risk. The carrying value of Penn Virginia's debt
approximates fair value. At December 31, 2000, the Company had
$47.514.3 million of long-term debt represented by an unsecured
revolving credit facility (the "Revolver"). The Revolver matures
in June 2003 and is governed by a borrowing base calculation that
is redetermined semi-annually. The Company has the option to
elect interest at (i) Libor plus a Eurodollar margin ranging from
100 to 150 basis points, basedtons mined on the percentage of the borrowing
base outstanding or (ii) the greater of the prime rate or federal
funds rate plus 50 basis points. As a result, the Company's 2001
interest costs will fluctuate based on short-term interest rates
relatingPartnership’s properties in 2002.
Capital Resources and Liquidity
Prior to the Revolver.
Price Risk Management. Penn Virginia's price risk program
permits the utilization of fixed-price contracts and financial
instruments (such as futures, forward and option contracts and
swaps) to mitigate the price risks associated with fluctuations
in natural gas prices as they relate to the Company's anticipated
production. These contracts and/or financial instruments are
designated as hedges and accounted for on the accrual basis with
gains and losses being recognized based on the type of contract
and exposure being hedged. Realized gains and losses on natural
gas financial instruments designated as hedges of anticipated
transactions are treated as deferred charges or credits, as
applicable, on the balance sheet until recognized. Through
December 31, 2000, net gains and losses on such financial
instruments, including accrued gains or losses upon maturity or
termination of the contract, are recognized in operating income
concurrently with the hedged transaction. Effective January 1, 2001, the Company accountssatisfied its working capital requirements and funded its capital expenditure and dividend payments with cash generated from operations and credit facility borrowings. In 2001, the acquisition of Gulf Coast properties was funded with credit facility borrowings that were subsequently repaid with proceeds from PVR’s initial public offering. Although results are consolidated for its derivative activitiesfinancial reporting, the resultant change in accordanceownership structure of PVR caused the Company and PVR to operate with Statementindependent capital structures. The Company and PVR have separate credit facilities, for which neither entity guarantees the debt of Financial Accounting Standards
("SFAS") No. 133, as amended by SFAS No. 137the other. Since PVR’s public offering, the cash needs of each entity have been met independently with a combination of operating cash flows, credit facility borrowings and, SFAS No. 138.
See Note 2 (New Accounting Standards) in the financial
statements.
SFAS No. 133, as amended by SFAS No. 137 and SFAS No. 138,
alterscase of PVR’s Peabody Acquisition, issuance of new partnership units. We expect that the reporting by companies that use derivative
instruments. The new rule, which went into effect January 1,
2001, requires companies to recognize derivatives as assets or
liabilities in their balance sheets and to measure them at "fair
value." Penn Virginia, from time to time, hedges in the form of
"costless collars." The options establish a price "collar"
around the gas. The hedging strategy is costless because the
purchasecash needs of the "put" optionsCompany and PVR will continue to sell gas atbe met with a combination of these funding sources.
Except where noted, the floor price was
offset by the salefollowing discussion of cash flows and contractual obligations relates to consolidated results of the "call" option on Penn Virginia gas at
the ceiling price. If the price of gas falls, Penn Virginia's
expected revenue stream from producing properties also declines;
however, the value of the "put" option increases. In accounting
for cash flow hedges under SFAS No. 133, part of the change in
option value would be reported as an operating gain or loss in
Penn Virginia's quarterly income statement (the gain or loss will
be reversed in future quarters as the true value of the option
diminishes to zero at the expiration date.) Consequently, if the
price of gas (and Penn Virginia's expected revenue stream) rises,
the cost to unwind the call option increases, creating an
operating loss. As a result, the Company's earnings could
experience increased volatility over the term of the costless
collar.
Natural gas pricing was extremely volatile in 2000. In AprilCompany and May of 2000, the Company entered into several physical
contracts that totaling 9,289 MMcf per day for the remainder of
2000. The volumes under contract accounted for 20 percent of
Penn Virginia's 2000 production at a price of $3.39 per Mcf. The
Company had one contract remaining that expires in March 2001
covering 18 percent of anticipated first quarter production at
$3.12 per Mcf. This physical contract is not considered to be a
derivative instrument under SFAS No. 133, as amended, as such
contracts qualify for the normal purchase and sale exception.
In January 2001, the Company hedged 13 percent of its
anticipated production for the second and third quarters of 2001
through a basis swap and a costless collar with a floor of $4.95
per Mcf and a ceiling of $7.16 per Mcf. Additionally, basis
swaps covering an additional 11 percent of anticipated production
for the same periods were executed.
Capital Resources and Liquidity
PVR.
Cash flows from Operating Activities
Funding for the Company's activities has historically been
provided by operating cash flows and bank borrowings.
Net cash provided from operating activities was $65.8 million in 2002, compared with $44.2 million in 2001 and $41.7 million in 2000,
compared with $25.1 million in 1999 and $19.4 million in 1998.
The Company's2000. Our consolidated cash balance remained constant atincreased to $13.3 million in 2002 compared with $9.6 million in 2001 and $0.7 million in 2000, respectively. As a result of PVR’s public offering, approximately $9.6 million and 1999.
$8.3 million of the consolidated cash balance as of December 31, 2002 and 2001, respectively, was held by PVR primarily for working capital requirements.
Cash flows from Investing Activities
The Company
Cash used in investing activities was $99.5 million in 2002, compared with $179.4 million in 2001 and $3.3 million in investing activities in 2000,
compared with $58.7 million in 1999 and $18.3 million in 1998.
Capital2000. Cash was used during these periods primarily for capital expenditures including acquisitions and noncash items,
totaled $59.4 million, compared with $60.7 million in 1999 and
$23.6 million in 1998. Capital expenditures in 2000 were
partially offset from the sale of certainfor oil and gas development and exploration activities and acquisitions of oil and gas and coal properties, totaling $55.2offset in part by proceeds from sales of securities and non-strategic oil and gas properties.
Page 31
Capital expenditures totaled $204.8 million after closing adjustments.in 2002, compared with $241.7 million in 2001 and $61.4 million in 2000. The following table sets forth capital expenditures, including acquisitions and
noncash items, made by the Company during the periods indicated.
Year ended December 31, | |||||||||
2002 | 2001 | 2000 | |||||||
(in thousands) | |||||||||
Oil and gas | |||||||||
Development Drilling | $ | 39,014 | $ | 30,123 | $ | 18,317 | |||
Exploration Drilling |
| 2,485 |
| 11,253 |
| 3,200 | |||
Seismic and other |
| 5,358 |
| 2,561 |
| 1,925 | |||
Lease Acquisitions |
| 7,346 |
| 161,631 |
| 36,916 | |||
Field Projects |
| 2,736 |
| 1,422 |
| 244 | |||
Total |
| 56,939 |
| 206,990 |
| 60,602 | |||
Coal royalty and land management | |||||||||
Lease acquisitions |
| 138,450 |
| 32,992 |
| — | |||
Support equipment and facilities |
| 9,085 |
| 677 |
| 485 | |||
Total |
| 147,535 |
| 33,669 |
| 485 | |||
Other |
| 343 |
| 1,074 |
| 281 | |||
Total capital expenditures | $ | 204,817 | $ | 241,733 | $ | 61,368 | |||
The Company drilled 75.3 net successful development wells, 0.2
net successful exploratory wellscapital expenditures noted above include noncash items related to equity issued in the form of PVR common units in connection with PVR’s Peabody Acquisition in 2002 and 2.6 net non-productive wellsdeferred taxes related to the Company’s acquisition of Gulf Coast properties in 2000, compared with 38.1 net successful development wells, 9.2
net successful exploratory wells and 2.0 net non-productive wells
in 1999.
2001.
Management is committed to expanding its oil and natural gas operations over the next several years through a combination of exploitation, exploration and acquisition of new properties. During 2000, the Company acquired proved naturalWe have a portfolio of assets which balance relatively low risk, moderate return development projects in Appalachia, Mississippi and west Texas with relatively moderate risk, potentially higher return development projects and exploration prospects in south Texas and south Louisiana.
Oil and gas segment capital expenditures for 2003, including our January 2003 acquisition of properties in Appalachia at a costSouth Texas for $32.5 million, are estimated to be $110 to $120 million. Approximately $53 to $57 million of $36.0 million, including a $34.7
million acquisition of royalty interests in West Virginiathe planned oil and eastern Kentucky. The properties had proved reserves of 35.9 Bcfe
at December 31, 2000 in addition to significant drilling
potential. The Company continued to develop the property it
acquired in July 1999 in Mississippi by drilling 41 gross wells
(37.7 net) in 2000. The acquisition, which was 99 percent
natural gas added 23.3 Bcfe in proved reserves and provided
numerous future drilling locations. The Company drilled seven
gross (1.4 net) exploratory wells in a Texas onshore gulf coast
exploration project, of which one gross (0.2 net) well was
successful, four gross (0.8 net) wells were non-productive and
two gross (0.4 net) wells are under evaluation. The Company is
still evaluating the unproved properties associated with the 20
percent working interest in the project.
Capitalcapital expenditures for 2001, before lease and proved property
acquisitions, are expected to be $43for development drilling projects, including horizontal coalbed methane drilling in Appalachia, development of the South Texas properties acquired in January 2003 and continued drilling in our Mississippi and west Texas fields. Exploration drilling is expected to $50be approximately $11 to $13 million including $41of the planned expenditures, concentrated primarily in south Louisiana and south Texas. Expenditures to $47build our library of 3-D seismic data for drilling prospect generation is expected to be approximately $6 to $7 million, and lease acquisition and field project expenditures are expected to be $8 to $10 million. Capital expenditures for the oil and gas segment and $2 to $3 million
for2003 in the coal royalty and land management segment. In addition,
Penn Virginia planssegment are expected to invest an additional $2be up to $3 million in
seismic. The Companyfor the construction of fee-based infrastructure facilities. We continually review drilling and other capital expenditure plans to drill approximately 180 to 200
gross (120 to 140 net) wells. Management continually reviews the
Company's drilling expenditures and may increase, decrease or
reallocatechange these amounts based on industry conditions. Management
believes itsconditions and the availability of capital. We believe our cash flow from operations portfolio of investments and sources of debt financing are sufficient to fund its 2001our 2003 planned capital expenditure program.
In September 1999, the Company completed an acquisition which
included over 90 million tons of high quality coal reserves as
well as oil and gas leases, timber assets, a short line railroad
and a coal loading dock on the Kanawha River in West Virginia.
The $30 million acquisition complements the Company's existing
Coal River Properties located on the inland river system in West
Virginia. The Company continues to diversify its coal customer
base by adding additional lessees and by searching for additional
coal reserve acquisition opportunities.
Cash flows from Financing Activities
Net cash provided (used) by (used in) financing activities was $(38.4)$37.4 million in 2000,2002, compared with $34.0$144.1 million in 19992001 and $(1.7)($38.4) million in 1998.
Penn Virginia2000. Credit facility borrowings provided approximately $58.8 million of cash from financing activities during 2002, offset in part by $8.0 million of dividend payments and distributions to PVR’s minority unitholders of $13.8 million. In 2001, proceeds to the Company of $142.4 million from PVR’s initial public offering allowed the Company to repay borrowings made for acquisitions after $7.9 million of dividend payments. In 2000, operating cash flows allowed the Company to repay debt of $30.3 million and to fund dividends of $7.4 million.
Page 32
The Company has a $150 million unsecuredsecured revolving credit facility (the "Revolver"“Revolver”) led by J.P. Morgan Chase Bank with a final maturity of June 2003.October 2004. The credit facility has a borrowing base of $140 million and the Company had borrowings of $16.0 million and $3.5 million against the facility as of December 31, 2002 and 2001, respectively. The Revolver contains financial covenants requiring the Company to maintain certain levels of net worth, debt-to-capitalization and dividend limitation restrictions, among other requirements. We currently have a $5 million line of credit with a financial institution due in March 2003, renewable annually. We have the option to elect either a fixed rate LIBOR loan or floating rate LIBOR loan.
In connection with the closing of its initial public offering in 2001, PVR entered into a three-year credit agreement with a syndicate of financial institutions led by PNC Bank, National Association. The outstanding balance oncredit agreement consists of two facilities, a revolving credit facility of $50.0 million (the “PVR Revolver”) and a term loan facility of up to $43.4 million (the “PVR Term Loan”). Both credit facilities mature in October 2004. The PVR Revolver is available for general partnership purposes, including working capital, capital expenditures, and acquisitions, and includes a $5.0 million distribution sublimit that is available for working capital needs and distributions and a $5.0 million sublimit for the issuance of letters of credit. In connection with the closing of its initial public offering, PVR borrowed $43.4 million under the PVR Term Loan and purchased and pledged $43.4 million of U.S. Treasury notes, which secured the term loan facility. In 2002, the U.S. Treasury Notes were liquidated for the purpose of funding acquisitions, and as of December 31, 2002, the obligations under the PVR Term Loan facility were unsecured. Total borrowings of as of December 31, 2002 against the PVR Revolver wasand PVR Term Loan were $47.5 million and $77.7$43.4 million, respectively. The PVR credit agreement contains financial covenants requiring the Partnership to certain levels of net worth and of debt to EBITDA (as defined by the credit agreement). The Partnership has the option to elect interest at Decemberi) LIBOR plus a Euro-rate margin of 0.5 percent, based on certain financial data, or (ii) the greater of the prime rate or federal funds rate plus .05 percent.
PVR is currently attempting to refinance up to $90 million of borrowings against its credit agreement with more permanent debt. This refinancing is expected to be completed by March 31, 20002003, with proceeds used to repay and 1999, respectively.
retire the PVR Term Loan and to repay most of the borrowings on the PVR Revolver. If the refinancing is not completed by March 31, 2003, PVR will be required to provide security to the syndicate of financial institutions in its credit agreement for all borrowings against its credit agreement.
Management believes its portfolio of investments and sources of funding are sufficient to meet short and long-term liquidity needs not funded by cash flows from operations.
Other
In June 1998, the Financial Accounting Standards Board ("FASB")
issued Statement
Page 33
Contractual Obligations
Our contractual obligations as of Financial Accounting Standards ("SFAS") No.
133, "Accounting for Derivative Instruments and Hedging
Activities." SFAS No. 133,December 31, 2002, are as amended by SFAS No. 137 and SFAS
No. 138, establishes accounting and reporting standards for
derivative instruments, including certain derivative instruments
embedded in other contracts, (collectively referred to as
derivatives) and for hedging activities. It requires an entity
to recognize all derivatives as either assets or liabilities in
the statement of financial position and measure those instruments
at fair value. If certain conditions are met, a derivative may
be specifically designated as (a) a hedge of the exposure to
changes in the fair value of a recognized asset or liability or
an unrecognized firm commitment, (b) a hedge of the exposure to
changes in the fair value of the exposure to variable cash flows
of a forecasted transaction, or (c) a hedge of the foreign
currency exposure of a net investment in a foreign operation, an
unrecognized firm commitment, an available-for-sale security, or
a foreign currency denominated forecasted transaction. Special
accounting for qualifying hedges allows a derivative's gains and
losses to offset related results on the hedged item in the
Company's statement of income. The adoption of SFAS No. 133 on
January 1, 2001 did not have a material impact on the Company's
financial position or results of operations.
In December 1999, the Securities and Exchange Commission
("SEC") issued Staff Accounting Bulletin No. 101, "Revenue
Recognition in Financial Statements' ("SAB No. 101"). SAB No.
101, as amended, summarizes the SEC's views in applying generally
accepted accounting principles to revenue recognition in
financial statements. The adoption of SAB No. 101 on October 1,
2000 did not have a material effect on the Company's financial
position or results of operations.
follows:
Total | Payments Due by Period | Thereafter | |||||||||||||
Less Than 1 Year | 1-3 Years | 4-5 Years | |||||||||||||
(in thousands) | |||||||||||||||
Penn Virginia revolver | $ | 16,000 | $ | — | $ | 16,000 | $ | — | $ | — | |||||
PVR revolver |
| 47,500 |
| — |
| 47,500 |
| — |
| — | |||||
PVR term loan |
| 43,387 |
| — |
| 43,387 |
| — |
| — | |||||
Line of credit |
| 52 |
| 52 |
| — |
| — |
| — | |||||
Rental commitments (1) |
| 8,081 |
| 2,855 |
| 3,237 |
| 1,989 |
| — | |||||
Total contractual cash obligations | $ | 115,020 | $ | 2,907 | $ | 110,124 | $ | 1,989 | $ | — | |||||
| (1) | Rental commitments primarily relate to equipment, car and building leases. Also included are the Partnership’s rental commitments, which primarily relate to reserve-based properties which are, or are intended to be, subleased by the Partnership to third parties. The obligation expires when the property has been mined to exhaustion or the lease has been canceled. The timing of mining by third party operators is difficult to estimate due to numerous factors. We believe the obligation after five years cannot be reasonably estimated; however, based on current knowledge, we believe the Partnership will incur approximately $0.4 million in rental commitments in perpetuity until the reserves have been exhausted. |
Environmental Matters
Penn Virginia's operating segments
Our businesses are subject to various environmental hazards. Several federal, state and local laws, regulations and rules govern the environmental aspects of the
Company's business.our businesses. Noncompliance with these laws, regulations and rules can result in substantial penalties or other liabilities. The Company doesWe do not believe itsour environmental risks are materially different from those of comparable companies ornor that cost of compliance will have a material adverse effect on our profitability, capital expenditures, cash flows or competitive position. ThereHowever, 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. The Company believes
it isWe believe we are materially in compliance with environmental laws, regulations and rules.
In conjunction with the Partnership’s leasing of property to coal operators, all environmental and reclamation liabilities are generally the responsibilityresponsibilities 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
In June 2001, the Financial Accounting Standards Board (“FASB”) issued 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 Company evaluatesStandard applies to legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development or normal use of the asset.
SFAS No. 143 requires that the fair value of a liability for an asset retirement obligation be 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 this additional carrying amount is depreciated over the life of the asset. The liability is accreted at the end of each period through charges to operating expense. If the obligation is settled for other than the carrying amount of the liability, we will recognize a gain or loss on settlement.
We will adopt the provisions of SFAS No. 143 effective January 1, 2003. We identified all required asset retirement obligations and determined the fair value of these obligations on the date of adoption. The determination of fair value was based upon regional market and specific well or mine type information. In conjunction with the initial application of SFAS No. 143, it is expected we will record a cumulative-effect of change in accounting principle, net of taxes, of approximately $0.5 to $1.5 million as an increase to
Page 34
income, which will be reflected in the Company’s results of operations for 2003. In addition, it is expected we will record an asset retirement obligation of approximately $2.3 to $3.3 million.
In April 2002, the FASB issued SFAS No. 145,Rescission of FASB Statements No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical Corrections.This Statement rescinds SFAS No. 4,Reporting Gains and Losses from Extinguishment of Debt,which required all gains and losses from extinguishment of debt to be aggregated and, if material, classified as an extraordinary item of debt to be aggregated and, if material, classified as an extraordinary item, net of income taxes. As a result, the criteria in Accounting Principles Board Opinion (APB) Opinion No. 30 will now be used to classify those gains and losses. Any gain or loss on the extinguishment of debt that was classified as an extraordinary item in prior periods presented that does not meet the criteria in APB Opinion No. 30 for classification as an extraordinary item shall be reclassified. The provisions of this Statement are effective for fiscal years beginning after January 1, 2003. The initial adoption of SFAS No. 145 did not have a material effect on the financial capabilityposition, results of each lessee prioroperations or liquidity of the Company.
In June 2002, the FASB issued SFAS No. 146,Accounting for Costs Associated with Exit or Disposal Activities. This statement requires the recognition of costs associated with exit or disposal activities when they are incurred rather than at the date of a commitment to an exit or disposal plan. The provisions of this statement are effective for exit or disposal activities initiated after December 31, 2002.
In November 2002, the FASB issued Interpretation No. 45 ( FIN 45),Guarantor’s Accounting and Disclosure Requirements forGuarantees, Including Indirect Guarantees of the Indebtedness of Others, which clarifies the requirements of SFAS No. 5,Accounting for Contingencies, relating to a guarantor’s accounting for and disclosures of certain guarantees issued. FIN 45 requires enhanced disclosures for certain guarantees. It also will require certain guarantees that are issued or modified after December 31, 2002, including certain third-party guarantees, to be initially recorded on the balance sheet at fair value. For guarantees issued on or before December 31, 2002, liabilities are recorded when and if payments become probable and estimable. The financial statement recognition provisions are effective prospectively, and the Company cannot reasonably estimate the impact of adopting FIN 45 until guarantees are issued or modified in future periods, at which time their results will be initially reported in the financial statements.
Quantitative and Qualitative Disclosures about Market Risk
Interest Rate Risk. The carrying value of our debt approximates fair value. At December 31, 2002, we had $16.0 million of long-term debt represented by a secured revolving credit facility (the “PVA Revolver”). The PVA Revolver matures in October 2004 and is governed by a borrowing base calculation that is redetermined semi-annually. We have the option to elect interest at (i) LIBOR plus a Eurodollar margin ranging from 1.375 to 1.875 percent, based on the percentage of the borrowing base outstanding or (ii) the greater of the prime rate or federal funds rate plus a margin ranging from 0.375 to 0.875 percent. As a result, our 2003 interest costs will fluctuate based on short-term interest rates relating to the leasingPVA Revolver.
Additionally, PVR had outstanding borrowings of property.
$90.9 million, consisting of $47.5 million borrowed against its $50 million revolving credit facility (the “PVR Revolver”) and $43.4 million of a fully-drawn term loan (the “PVR Term Loan”). Both the PVR Revolver and PVR Term Loan mature in October 2004. Regarding the unsecured PVR Revolver, PVR has the option to elect interest at (i) LIBOR plus a Euro-rate margin ranging from 1.25 to 1.75 percent, based upon certain financial data, or (ii) the greater of the prime rate or federal funds rate plus 0.5 percent. Regarding the PVR Term Loan, PVR has the option to elect interest at (i) LIBOR plus a Euro-rate margin of 0.5 percent, based upon certain financial data or (ii) the greater of the prime rate or federal funds rate plus 0.5 percent. As a result of both instruments, PVR’s interest costs will fluctuate based on short-term interest rates.
Page 35
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 contracts and/or financial instruments are designated as cash flow hedges and accounted for in accordance with Statement of Financial Accounting Standards (“SFAS”) No. 133, as amended by SFAS No. 137 and SFAS No. 138. See Note 9 (Price Risk Management Activities) of the Notes to the Consolidated Financial Statements, for more information. 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. As of February 14, 2003, our open commodity price risk management positions on average daily volumes were as follows:
Natural gas hedging positions | Costless Collars | Swaps | |||||||||||
MMBtu Per Day | Price / MMBtu (a) | MMBtu Per Day | Price /MMBtu | ||||||||||
Floor | Ceiling | ||||||||||||
First Quarter 2003 | 15,000 | $ | 3.15 | $ | 5.05 | 3,164 | $ | 4.70 | |||||
Second Quarter 2003 | 21,500 | $ | 3.39 | $ | 5.36 | 3,399 | $ | 4.70 | |||||
Third Quarter 2003 | 21,500 | $ | 3.39 | $ | 5.36 | 2,570 | $ | 4.70 | |||||
Fourth Quarter 2003 | 19,500 | $ | 3.49 | $ | 5.46 | 2,034 | $ | 4.70 | |||||
First Quarter 2004 | 19,500 | $ | 3.54 | $ | 5.51 | 1,800 | $ | 4.70 | |||||
Second Quarter 2004 | 14,137 | $ | 3.56 | $ | 5.70 | 1,533 | $ | 4.70 | |||||
Third Quarter 2004 | 1,348 | $ | 3.72 | $ | 6.97 | 1,367 | $ | 4.70 | |||||
Fourth Quarter 2004 | — | $ | — | $ | — | 1,234 | $ | 4.70 | |||||
First Quarter 2005 (January) | — | $ | — | $ | — | 1,100 | $ | 4.70 | |||||
| (a) | The costless collar natural gas prices per MMBtu per quarter include the effects of basis differentials, if any, that may be hedged. |
Crude oil hedging positions | Costless Collars | Swaps | |||||||||||
Barrels Per Day | Price / Barrel | Barrels Per Day | Price /Barrel | ||||||||||
Floor | Ceiling | ||||||||||||
First Quarter 2003 | 500 | $ | 23.00 | $ | 28.75 | 150 | $ | 26.93 | |||||
Second Quarter 2003 | 500 | $ | 23.00 | $ | 28.75 | 170 | $ | 26.93 | |||||
Third Quarter 2003 | — | $ | — | $ | — | 250 | $ | 26.76 | |||||
Fourth Quarter 2003 | — | $ | — | $ | — | 220 | $ | 26.74 | |||||
First Quarter 2004 | — | $ | — | $ | — | 207 | $ | 26.73 | |||||
Second Quarter 2004 | — | $ | — | $ | — | 193 | $ | 26.71 | |||||
Third Quarter 2004 | — | $ | — | $ | — | 63 | $ | 26.93 | |||||
Fourth Quarter 2004 | — | $ | — | $ | — | 57 | $ | 26.93 | |||||
First Quarter 2005 (January) | — | $ | — | $ | — | 50 | $ | 26.93 | |||||
Page 36
Forward-Looking Statements
Statements included in this report which are not historical facts (including any statements concerning plans and objectives of management for future operations or economic performance, or assumptions related thereto) are forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934, as amended, and Section 27A of the Securities Act of 1933, as amended. In addition, Penn Virginiawe and itsour representatives may from time to time make other oral or written statements whichthat 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 of coal mining
or oil and gas production, projected quantities of future oil, and
gas, production by Penn Virginia, projected quantities of futureor coal production, by the Company's lessees producing coal from
reserves leased from Penn Virginia, costs and expenditures as well as projected demand or supply for, coal and oil and natural gas, all of which willmay affect sales levels, prices and royalties realized by Penn Virginia.
Virginia and PVR.
These forward-looking statements are made based upon management'smanagement’s current plans, expectations, estimates, assumptions and beliefs concerning future events impacting Penn Virginia and PVR and, therefore, involve a number of risks and uncertainties. Penn Virginia cautions that forward-looking statements are not guarantees and that actual results could differ materially from those expressed or implied in the forward-looking statements.
Important factors that could cause the actual results of operations or financial condition of Penn Virginia to differ materially from those expressed or implied in the forward-looking statements include, but are not necessarily limited to: the cost of finding and successfully developing oil and gas reserves; the cost to PVR of finding new coal reserves; the ability of Penn Virginia to acquire new oil and gas reserves and of PVR to acquire new coal reserves on satisfactory terms; the price for which such reserves can be sold; the volatility of commodity prices for oil and gas and coal; the risks associated with having or not having price risk management programs; Penn Virginia'sPVR’s ability to lease new and existing coal reserves; the ability of Penn Virginia'sPVR’s lessees to produce sufficient quantities of coal on an economic basis from Penn Virginia'sPVR’s reserves; the ability of lessees to obtain favorable contracts for coal produced from Penn VirginiaPVR’s reserves; Penn Virginia'sVirginia’s ability to obtain adequate pipeline transportation capacity for its oil and gas production; competition among producers in the coal and oil and gas and coal industries generally and in the Appalachian Basin in particular;generally; the extent to which the amount and quality of actual production differs from estimated mineable and merchantable coal reserves
andrecoverable proved oil and gas reserves and coal reserves; unanticipated geological problems; availability of required materials and equipment; the occurrence of unusual weather or operating conditions including force majeure or events; the failure of equipment or processes to operate in accordance with specifications or expectations; delays in anticipated start-up dates;date of Penn Virginia’s oil and natural gas production and PVR’s lessees’ mining operations; environmental risks affecting the drilling and producing of oil and gas wells or the mining of coal reserves; the timing of receipt of necessary governmental permits;permits by Penn Virginia and by PVR’s lessees; labor relations and costs; accidents; changes in governmental regulation or enforcement practices, especially with respect to environmental, health and safety matters, including with respect to emissions levels applicable to coal-burning power generators; uncertainties relating to the outcome of mountaintop removal litigation and issues regarding coal truck weight restriction enforcement and legislation; risks and uncertainties relating to general domestic and international economic (including inflation and interest rates) and political conditions; and the experience and financial condition of lessees of PVR’s coal reserves joint venture partners and
purchasers of reserves in transactions financed by Penn Virginia, including their ability to satisfy their royalty, environmental, reclamation and other obligations to Penn VirginiaPVR and others;
changes in financial market conditions; changes in the market
prices or value of the marketable securities owned by Penn
Virginia, including the price of Norfolk Southern common stock
and other risk factors detailed in Penn Virginia's Securities and
Exchange commission filings.others. Many of such factors are beyond Penn Virginia'sVirginia’s ability to control or predict. Readers are cautioned not to put undue reliance on forward-looking statements.
While Penn Virginia periodically reassesses material trends and uncertainties affecting Penn Virginia'sVirginia’s results of operations and financial condition in connection with the preparation of Management'sManagement’s Discussion and Analysis of Results of Operations and Financial Condition and certain other sections contained in Penn Virginia'sVirginia’s quarterly, annual or other reports filed with the Securities and Exchange Commission, Penn Virginia does not intendundertake any obligation to review or update any particular forward-looking statement, whether as a result of new information, future events or otherwise.
Page 37
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
PENN VIRGINIA CORPORATION
February 14, 2001 By: /s/ James O. Idiaquez
(James O. Idiaquez, Vice President
and Chief Financial Officer)
February 14, 2001 By: /s/ Ann N. Horton
(Ann N. Horton, Vice President
and Principal Accounting Officer)
PENN VIRGINIA CORPORATION | ||||||
March 7, 2003 | By: | /s/ Frank A. Pici | ||||
(Frank A. Pici, Executive Vice President and Chief Financial Officer) | ||||||
March 7, 2003 | By: | /s/ Dana G. Wright | ||||
(Dana G. Wright, Vice President and Principal Accounting Officer) | ||||||
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
/s/ Robert Garrett (Robert Garrett) | Chairman of the Board | March 7, 2003 | ||
/s/ Edward B Cloues, II (Edward B. Cloues, II) | Director | March 7, 2003 | ||
/s/ A. James Dearlove (A. James Dearlove) | Director and | March 7, 2003 | ||
/s/ H. Jarrell Gibbs (H. Jarrell Gibbs) | Director | March 7, 2003 | ||
/s/ Keith D. Horton (Keith D. Horton) | Director and | March 7, 2003 | ||
/s/ Marsha R. Perelman (Marsha R. Perelman) | Director | March 7, 2003 | ||
/s/ Joe T. Rye (Joe T. Rye) | Director | March 7, 2003 | ||
/s/ Gary K. Wright (Gary K. Wright) | Director | March 7, 2003 |
Page 38
CERTIFICATIONS
I, A. James Dearlove, President and Chief Executive Officer of Penn Virginia Corporation (the “Registrant”), certify that:
| 1. | I have reviewed this annual report on Form 10-K of the Registrant; |
| 2. | Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report; |
| 3. | Based on my knowledge, the financial statements, and |
| 4. | The Registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the Registrant and we have: |
| a) | designed such disclosure controls and procedures to ensure that material information relating to the Registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared; |
| b) | evaluated the effectiveness of the Registrant’s disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the “Evaluation Date”); and |
| c) | presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date; |
| 5. | The Registrant’s other certifying officer and I have disclosed, based on our most recent evaluation, to the Registrant’s auditors and the audit committee of Registrant’s board of directors: |
| a) | all significant deficiencies in the design or operation of internal controls which could adversely affect the Registrant’s ability to record, process, summarize and report financial data and have identified for the Registrant’s auditors any material weaknesses in internal controls; and |
| b) | any fraud, whether or not material, that involves management or other employees who have a significant role in the Registrant’s internal controls; and |
| 6. | The Registrant’s other certifying officer and I have indicated in this annual report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses. |
Date: | March 11, 2003 |
/s/ A. James Dearlove |
A. James Dearlove President and Chief Executive Officer |
Page 39
I, Frank A. Pici, Executive Vice President and Chief Financial Officer of Penn Virginia Corporation (the “Registrant”), certify that:
| 1. | I have reviewed this annual report on Form 10-K of the Registrant; |
| 2. | Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report; |
| 3. | Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of |
| 4. | The Registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the Registrant and we have: |
| a) | designed such disclosure controls and procedures to ensure that material information relating to the Registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared; |
| b) | evaluated the effectiveness of the Registrant’s disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the “Evaluation Date”); and |
| c) | presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date; |
| 5. | The Registrant’s other certifying officer and I have disclosed, based on our most recent evaluation, to the Registrant’s auditors and the audit committee of Registrant’s board of directors: |
| a) | all significant deficiencies in the |
| b) | any fraud, whether or not material, that involves management or other employees who have a significant role in the |
| 6. | The Registrant’s other certifying officer and |
Date: | March 11, 2003 |
/s/ Frank A. Pici |
Frank A. Pici Executive Vice President and Chief Financial Officer |
Page 40
ITEM 8 –FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Penn Virginia Corporation and Subsidiaries
Index to Financial Section
Management’s Report on Financial Information | 42 | |
Reports of | 43 | |
Financial Statements and | 45 |
Page 41
Management’s Report on Financial Information
Management of Penn Virginia Corporation (the “Company”) is responsible for the preparation and integrity of the financial information included in this annual report. The financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America, which involve the use of estimates and judgments where appropriate.
The Company has a system of internal accounting controls designed to provide reasonable assurance that assets are safeguarded against loss or unauthorized use and to produce the records necessary for the preparation of financial information. The system of internal control is supported by the selection and training of qualified personnel, the delegation of management authority and responsibility, and dissemination of policies and procedures. There are limits inherent in all systems of internal control based on the recognition that the costs of such systems should be related to the benefits to be derived. We believe the Company’s systems provide this appropriate balance.
The Company’s independent public accountants, KPMG LLP, have developed an understanding of our accounting and financial controls and have conducted such tests as they consider necessary to support their opinion on the 2002 financial statements. Their report contains an independent, informed judgment as to the corporation’s reported results of operations and financial position for 2002.
The Board of Directors pursues its oversight role for the financial statements through the Audit Committee, which consists solely of outside directors. The Audit Committee meets regularly with management, the internal auditor and KPMG LLP, jointly and separately, to review management’s process of implementation and maintenance of internal controls, and auditing and financial reporting matters. The independent and internal auditors have unrestricted access to the Audit Committee.
A. James Dearlove President and Chief Executive Officer | Frank A. Pici Executive Vice President and Chief Financial Officer |
Page 42
INDEPENDENT AUDITORS’ REPORT
To the Shareholders of Penn Virginia Corporation:
We have audited the accompanying consolidated balance sheet of Penn Virginia Corporation (a Virginia corporation) and subsidiaries as of December 31, 2002, and the related consolidated statements of income, shareholders’ equity and cash flows for the year then ended. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audit. The 2001 and 2000 consolidated financial statements of Penn Virginia Corporation and subsidiaries were audited by other auditors who have ceased operations. Those auditors expressed an unqualified opinion on those financial statements in their report dated February 18, 2002.
We conducted our audit in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Penn Virginia Corporation and subsidiaries as of December 31, 2002, and the results of their operations and their cash flows for the year then ended in conformity with accounting principles generally accepted in the United States of America.
KPMG LLP
Houston, Texas
February 14, 2003
Page 43
THIS REPORT IS A COPY OF A REPORT PREVIOUSLY ISSUED BY ARTHUR ANDERSEN LLP. THE REPORT HAS NOT BEEN REISSUED BY ARTHER ANDERSEN LLP, NOR HAS ARTHUR ANDERSEN LLP PROVIDED A CONSENT TO THE INCLUSION OF ITS REPORT IN THIS FORM 10-K.
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Shareholders of Penn Virginia Corporation:
We have audited the accompanying consolidated balance sheets of Penn Virginia Corporation (a Virginia corporation) and subsidiaries as of December 31, 2001 and 2000, and the related consolidated statements of income, shareholders’ equity and cash flows for each of the three years in the period ended December 31, 2001. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with auditing standards generally accepted in the United States. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Penn Virginia Corporation and subsidiaries as of December 31, 2001 and 2000, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2001, in conformity with accounting principles generally accepted in the United States.
Arthur Andersen LLP
Houston, Texas
February 18, 2002
Page 44
PENN VIRGINIA CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(in thousands, except share data)
Year Ended December 31, | ||||||||||||
2002 | 2001 | 2000 | ||||||||||
Revenues | ||||||||||||
Oil and condensate | $ | 8,246 |
| $ | 3,762 |
| $ | 832 |
| |||
Natural gas |
| 62,552 |
|
| 53,263 |
|
| 46,019 |
| |||
Coal royalties |
| 31,358 |
|
| 32,365 |
|
| 24,308 |
| |||
Timber |
| 1,640 |
|
| 1,732 |
|
| 2,388 |
| |||
Dividends |
| — |
|
| 198 |
|
| 2,646 |
| |||
Gain (loss) on the sale of properties |
| (5 | ) |
| 492 |
|
| 24,795 |
| |||
Other |
| 7,166 |
|
| 4,759 |
|
| 5,010 |
| |||
| 110,957 |
|
| 96,571 |
|
| 105,998 |
| ||||
Expenses | ||||||||||||
Lease operating |
| 12,754 |
|
| 9,284 |
|
| 7,629 |
| |||
Exploration |
| 7,733 |
|
| 11,832 |
|
| 5,660 |
| |||
Taxes other than income |
| 6,804 |
|
| 5,433 |
|
| 3,648 |
| |||
General and administrative |
| 21,440 |
|
| 15,297 |
|
| 11,350 |
| |||
Impairment of oil and gas properties |
| 796 |
|
| 33,583 |
|
| — |
| |||
Depreciation, depletion and amortization |
| 30,639 |
|
| 19,579 |
|
| 12,027 |
| |||
| 80,166 |
|
| 95,008 |
|
| 40,314 |
| ||||
Operating Income |
| 30,791 |
|
| 1,563 |
|
| 65,684 |
| |||
Other income (expense) | ||||||||||||
Interest expense |
| (2,116 | ) |
| (2,453 | ) |
| (7,926 | ) | |||
Interest income |
| 2,038 |
|
| 1,602 |
|
| 1,458 |
| |||
Gain on the sale of securities |
| — |
|
| 54,688 |
|
| — |
| |||
Other |
| 1 |
|
| 14 |
|
| 14 |
| |||
Income from continuing operations before minority interest and income taxes and discontinued operations |
| 30,714 |
|
| 55,414 |
|
| 59,230 |
| |||
Minority interest |
| 11,896 |
|
| 1,763 |
|
| — |
| |||
Income tax expense |
| 6,935 |
|
| 19,314 |
|
| 19,965 |
| |||
Income from continuing operations |
| 11,883 |
|
| 34,337 |
|
| 39,265 |
| |||
Income from discontinued operations (including gain on sale and net of taxes) |
| 221 |
|
| — |
|
| — |
| |||
Net Income | $ | 12,104 |
| $ | 34,337 |
| $ | 39,265 |
| |||
Income from continuing operations per share, basic | $ | 1.33 |
| $ | 3.92 |
| $ | 4.76 |
| |||
Income from discontinued operations per share, basic |
| 0.02 |
|
| — |
|
| — |
| |||
Net income per share, basic | $ | 1.35 |
| $ | 3.92 |
| $ | 4.76 |
| |||
Income from continuing operation per share, diluted | $ | 1.32 |
| $ | 3.86 |
| $ | 4.69 |
| |||
Income from discontinued operations per share, diluted |
| 0.02 |
|
| — |
|
| — |
| |||
Net income per share, diluted | $ | 1.34 |
| $ | 3.86 |
| $ | 4.69 |
| |||
Weighted average shares outstanding, basic |
| 8,930 |
|
| 8,770 |
|
| 8,241 |
| |||
Weighted average shares outstanding, diluted |
| 8,974 |
|
| 8,896 |
|
| 8,371 |
| |||
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)
December 31,
2000 1999
Assets
Current assets
Cash and cash equivalents $ 735 $ 657
Accounts receivable 12,926 6,880
Current portion of long-term notes
receivable 981 816
Current deferred income taxes - 155
Other 652 813
Total current assets 15,294 9,321
Investments 44,080 67,816
Long-term notes receivable 2,427 3,518
Property and Equipment
Oil and gas properties
(successful efforts method) 174,504 185,048
Other property and equipment 83,534 82,772
258,038 267,820
Less: Accumulated depreciation,
depletion and amortization 52,922 76,553
Net property and equipment 205,116 191,267
Other assets 1,849 2,089
Total assets $ 268,766 $274,011
Liabilities and Shareholders' Equity
Current liabilities
Current maturities of long-term debt $ 740 $ 34
Accounts payable 2,609 1,570
Accrued liabilities 7,154 5,470
Current deferred income taxes 136 -
Taxes on income 7,296 -
Total current liabilities 17,935 7,074
Other liabilities 5,486 5,854
Deferred income taxes 26,683 28,265
Long-term debt 47,500 78,475
Commitments and contingencies (Note 16)
Shareholders' equity
Preferred stock of $100 par value-
Authorized 100,000 shares; none issued - -
Common stock of $6.25 par value -
16,000,000 shares authorized;
8,921,866 shares issued 55,762 55,762
Paid-in capital 8,100 8,096
Retained earnings 92,718 60,860
Accumulated other comprehensive income 26,606 42,017
183,186 166,735
Less: 524,108 shares in 2000 and
498,238 in 1999 of common
stock held in treasury, at cost 10,974 11,142
Unearned compensation - ESOP 1,050 1,250
Total shareholders' equity 171,162 154,343
Total liabilities and
shareholders' equity $268,766 $ 274,011
PENN VIRGINIA CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(in thousands, except share data)
December 31, | |||||||
2002 | 2001 | ||||||
Assets | |||||||
Current assets | |||||||
Cash and cash equivalents | $ | 13,341 |
| $ | 9,621 | ||
Accounts receivable |
| 20,366 |
|
| 12,334 | ||
Current portion of long-term notes receivable |
| 527 |
|
| 599 | ||
Price risk management assets |
| — |
|
| 3,674 | ||
Other |
| 1,503 |
|
| 1,105 | ||
Total current assets |
| 35,737 |
|
| 27,333 | ||
Property and equipment | |||||||
Oil and gas properties (successful efforts method) |
| 383,360 |
|
| 335,494 | ||
Other property and equipment |
| 265,180 |
|
| 117,789 | ||
| 648,540 |
|
| 453,283 | |||
Less: Accumulated depreciation, depletion and amortization |
| 102,588 |
|
| 72,095 | ||
Net property and equipment |
| 545,952 |
|
| 381,188 | ||
Restricted U.S. Treasury Notes |
| — |
|
| 43,387 | ||
Other assets |
| 4,603 |
|
| 5,194 | ||
Total assets | $ | 586,292 |
| $ | 457,102 | ||
Liabilities and Shareholders’ Equity | |||||||
Current liabilities | |||||||
Current maturities of long-term debt | $ | 52 |
| $ | 1,235 | ||
Accounts payable |
| 5,670 |
|
| 3,987 | ||
Accrued liabilities |
| 16,508 |
|
| 10,762 | ||
Price risk management liabilities |
| 1,621 |
|
| — | ||
Total current liabilities |
| 23,851 |
|
| 15,984 | ||
Other liabilities |
| 12,674 |
|
| 8,877 | ||
Deferred income taxes |
| 62,154 |
|
| 55,861 | ||
Long-term debt |
| 106,887 |
|
| 46,887 | ||
Minority interest |
| 192,770 |
|
| 144,039 | ||
Commitments and contingencies (Note 20) | |||||||
Shareholders’ equity | |||||||
Preferred stock of $100 par value – authorized 100,000 shares; none issued |
| — |
|
| — | ||
Common stock of $6.25 par value – 16,000,000 shares authorized; 8,946,651 | |||||||
and 8,921,866 shares issued at December 31, 2002 and 2001 respectively |
| 55,915 |
|
| 55,762 | ||
Paid-in capital |
| 11,436 |
|
| 9,869 | ||
Retained earnings |
| 123,189 |
|
| 119,125 | ||
Accumulated other comprehensive income |
| (1,661 | ) |
| 1,756 | ||
| 188,879 |
|
| 186,512 | |||
Less: 23,765 shares of common stock held in treasury, at cost on December 31, 2001 |
| — |
|
| 599 | ||
Unearned compensation and ESOP |
| 923 |
|
| 459 | ||
Total shareholders’ equity |
| 187,956 |
|
| 185,454 | ||
Total liabilities and shareholders’ equity | $ | 586,292 |
| $ | 457,102 | ||
The accompanying notes are an integral part of these consolidated financial statements.
PENN VIRGINIA CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY
(in thousands, except share data)
Accumulated
Other
Shares Common Paid-in Retained Comprehensive
Outstanding Stock Capital Earnings Income
Balance at 12/31/97 8,274,326 $ 55,634 $8,431 $51,813 $63,500
Dividends paid
($0.90 per share) - - - (7,480) -
Stock issued as
compensation 5,357 - 26 - -
Exercise of stock
options 87,133 128 (114) - -
Allocation of ESOP shares - - 98 - -
Net income - - - 9,591 -
Other comprehensive income,
net of tax - - - - 2,485
Balance at 12/31/98 8,366,816 55,762 8,441 53,924 65,985
Dividends paid
($0.90 per share) - - - (7,568) -
Stock issued as
compensation 7,878 - (13) - -
Exercise of stock options 48,934 - (365) - -
Allocation of ESOP shares - - 33 - -
Net income - - - 14,504 -
Other comprehensive loss,
net of tax - - - - (23,968)
Balance at 12/31/99 8,423,628 55,762 8,096 60,860 42,017
Dividends paid
($0.90 per share) - - - (7,407) -
Purchase of treasury
stock (363,430) - - - -
Stock issued as
compensation 11,163 - - - -
Exercise of stock
options 326,397 - (63) - -
Allocation of ESOP shares - - 67 - -
Net income - - - 39,265 -
Other comprehensive loss,
net of tax - - - - (15,411)
Balance at 12/31/2000 8,397,758 $55,762 $8,100 $92,718 $26,606
Continued from above table
Unearned Total
Treasury Compensation Stockholders' Comprehensive
Stock ESOP Equity Income (Loss)
Balance at 12/31/97 $(14,024) $(1,650) $163,704 $19,077
Dividends paid ($0.90/share) - - (7,480)
Stock issued as compensation 120 - 146
Exercise of stock options 1,501 - 1,515
Allocation of ESOP shares - 200 298
Net income - - 9,591 $ 9,951
Other comprehensive income,
net of tax _ _ 2,485 2,485
Balance at 12/31/98 (12,403) (1,450) 170,259 12,076
Dividends paid ($0.90/share) - - (7,568)
Stock issued as compensation 176 - 163
Exercise of stock options 1,085 - 720
Allocation of ESOP shares - 200 233
Net income - - 14,504 $14,504
Other comprehensive loss,
net of tax - - (23,968) (23,968)
Balance at 12/31/99 (11,142) (1,250) 154,343 $ (9,464)
Dividends paid ($0.90/share) - - (7,407)
Purchase of treasury stock (6,761) - (6,761)
Stock issued as compensation 226 - 226
Exercise of stock options 6,703 - 6,640
Allocation of ESOP shares _ 200 267
Net income - - 39,265 $ 39,265
Other comprehensive loss,
net of tax - - (15,411) (15,411)
Balance at 12/31/2000 $(10,974) $ (1,050) $171,162 $ 23,854
Page 46
PENN VIRGINIA CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY
(in thousands, except share data)
Accumulated | Total | |||||||||||||||||||||||||||||||||
Other | Unearned | Stockholders’ | ||||||||||||||||||||||||||||||||
Shares | Common | Paid-in | Retained | Comprehensive | Treasury | Compensation | Comprehensive | Comprehensive | ||||||||||||||||||||||||||
Outstanding | Stock | Capital | Earnings | Income | Stock | And ESOP | Equity | Income (Loss) | ||||||||||||||||||||||||||
Balance at December 31, 1999 | 8,423,628 |
| $ | 55,762 | $ | 8,096 |
| $ | 60,860 |
| $ | 42,017 |
| $ | (11,142 | ) | $ | (1,250 | ) | $ | 154,343 |
| $ | (9,464 | ) | |||||||||
Dividends paid ($0.90 per share) | — |
|
| — |
| — |
|
| (7,407 | ) |
| — |
|
| — |
|
| — |
|
| (7,407 | ) | ||||||||||||
Purchase of treasury stock | (363,430 | ) |
| — |
| — |
|
| — |
|
| — |
|
| (6,761 | ) |
| — |
|
| (6,761 | ) | ||||||||||||
Stock issued as compensation | 11,163 |
|
| — |
| — |
|
| — |
|
| — |
|
| 226 |
|
| — |
|
| 226 |
| ||||||||||||
Exercise of stock options | 326,397 |
|
| — |
| (63 | ) |
| — |
|
| — |
|
| 6,703 |
|
| — |
|
| 6,640 |
| ||||||||||||
Allocation of ESOP shares | — |
|
| — |
| 67 |
|
| — |
|
| — |
|
| — |
|
| 200 |
|
| 267 |
| ||||||||||||
Net income | — |
|
| — |
| — |
|
| 39,265 |
|
| — |
|
| — |
|
| — |
|
| 39,265 |
|
| 39,265 |
| |||||||||
Other comprehensive loss, net of tax | — |
|
| — |
| — |
|
| — |
|
| (15,411 | ) |
| — |
|
| — |
|
| (15,411 | ) |
| (15,411 | ) | |||||||||
Balance at December 31, 2000 | 8,397,758 |
|
| 55,762 |
| 8,100 |
|
| 92,718 |
|
| 26,606 |
|
| (10,974 | ) |
| (1,050 | ) |
| 171,162 |
|
| 23,854 |
| |||||||||
Dividends paid ($0.90 per share) | — |
|
| — |
| — |
|
| (7,930 | ) |
| — |
|
| — |
|
| — |
|
| (7,930 | ) | ||||||||||||
Purchase of treasury stock | (33,991 | ) |
| — |
| — |
|
| — |
|
| (638 | ) |
| — |
|
| (638 | ) | |||||||||||||||
Stock issued as compensation | 8,281 |
|
| — |
| 142 |
|
| — |
|
| — |
|
| 188 |
|
| — |
|
| 330 |
| ||||||||||||
Exercise of stock options | 526,053 |
|
| — |
| 1,417 |
|
| — |
|
| — |
|
| 11,216 |
|
| — |
|
| 12,633 |
| ||||||||||||
Allocation of ESOP shares | — |
|
| — |
| 210 |
|
| — |
|
| — |
|
| (391 | ) |
| 591 |
|
| 410 |
| ||||||||||||
Net income | — |
|
| — |
| — |
|
| 34,337 |
|
| — |
|
| — |
|
| — |
|
| 34,337 |
|
| 34,337 |
| |||||||||
Other comprehensive loss, net of tax | — |
|
| — |
| — |
|
| — |
|
| (24,850 | ) |
| — |
|
| — |
|
| (24,850 | ) |
| (24,850 | ) | |||||||||
Balance at December 31, 2001 | 8,898,101 |
|
| 55,762 |
| 9,869 |
|
| 119,125 |
|
| 1,756 |
|
| (599 | ) |
| (459 | ) |
| 185,454 |
|
| 9,487 |
| |||||||||
Dividends paid ($0.90 per share) | — |
|
| — |
| — |
|
| (8,040 | ) |
| — |
|
| — |
|
| — |
|
| (8,040 | ) | ||||||||||||
Purchase of treasury stock | (15,202 | ) |
| — |
| — |
|
| — |
|
| — |
|
| (557 | ) |
| — |
|
| (557 | ) | ||||||||||||
Stock issued as compensation | 6,752 |
|
| 8 |
| 84 |
|
| — |
|
| — |
|
| 157 |
|
| — |
|
| 249 |
| ||||||||||||
Penn Virginia Resource Partners, L.P. units issued as compensation, net | — |
|
| — |
| 806 |
|
| — |
|
| — |
|
| — |
|
| (664 | ) |
| 142 |
| ||||||||||||
Exercise of stock options | 57,000 |
|
| 145 |
| 470 |
|
| — |
|
| — |
|
| 999 |
|
| — |
|
| 1,614 |
| ||||||||||||
Allocation of ESOP shares | — |
|
| — |
| 207 |
|
| — |
|
| — |
|
| — |
|
| 200 |
|
| 407 |
| ||||||||||||
Net income | — |
|
| — |
| — |
|
| 12,104 |
|
| — |
|
| — |
|
| — |
|
| 12,104 |
|
| 12,104 |
| |||||||||
Other comprehensive loss, net of tax | — |
|
| — |
| — |
|
| — |
|
| (3,417 | ) |
| — |
|
| — |
|
| (3,417 | ) |
| (3,417 | ) | |||||||||
Balance at December 31, 2002 | 8,946,651 |
| $ | 55,915 | $ | 11,436 |
| $ | 123,189 |
| $ | (1,661 | ) | $ | — |
| $ | (923 | ) | $ | 187,956 |
| $ | 8,687 |
| |||||||||
The accompanying notes are an integral part of these consolidated financial statements
PENN VIRGINIA CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands)
Year ended December 31,
2000 1999 1998
Cash flows from operating activities:
Net income $39,265 $14,504 $9,591
Adjustments to reconcile net income to net
cash provided (used) by operating activities:
Depreciation, depletion and amortization 12,027 8,393 7,162
Impairment of oil and gas properties - - 4,641
Gain on the sale of property and equipment (24,795) (280) (65)
Deferred income taxes 7,006 2,805 923
Tax benefit from stock option exercises 1,049 86 170
Dry hole and unproved leasehold expense 3,154 1,115 58
Other 140 (1,284) (2,753)
37,846 25,339 19,727
Changes in operating assets and liabilities:
Accounts receivable (6,046) (1,198) 1,721
Other current assets 161 (133) (136)
Accounts payable and accrued liabilities 2,723 604 (1,277)
Taxes on income 7,296 (576) 432
Other assets and liabilities (240) 1,105 (1,060)
Net cash flows provided by operating
activities 41,740 25,141 19,407
Cash flows from investing activities:
Proceeds from the sale of securities - - 17
Proceeds from the sale of property & equipment 55,208 299 79
Payments received on long-term notes receivable 926 1,670 2,253
Proved properties acquired (35,999) (13,921) (3,351)
Lease acquisitions (788) (32,793) (3,512)
Capital expenditures (22,656) (13,937 (13,806)
Net cash flows used in investing activities (3,309) (58,682) (18,320)
Cash flows from financing activities:
Dividends paid (7,407) (7,568) (7,480)
Proceeds from borrowings 33,240 44,500 9,100
Repayment of borrowings (63,509) (3,990) (5,100)
Purchases of treasury stock (6,761) - -
Issuance of stock 6,084 1,031 1,787
Net cash flows provided by (used in)
financing activities (38,353) 33,973 (1,693)
Net increase (decrease) in cash and
cash equivalents 78 432 (606)
Cash and cash equivalents-beginning of year 657 225 831
Cash and cash equivalents - end of year $ 735 $657 $ 225
Supplemental disclosures:
Cash paid during the year for:
Interest $8,304 $2,980 $2,065
Income taxes $4,614 $2,100 $1,100
Noncash investing activities:
Note receivable for sale of property
and equipment $ - $ 1,255 $ - Note
receivable exchanged for:
Other property and equipment $ - $ - $2,954
Other liabilities $ - $ - $1,296
The accompanying notes are an integral part of these consolidated financial
statements.
Page 47
PENN VIRGINIA CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands)
Year ended December 31, | ||||||||||||
2002 | 2001 | 2000 | ||||||||||
Cash flows from operating activities: | ||||||||||||
Net income | $ | 12,104 |
| $ | 34,337 |
| $ | 39,265 |
| |||
Adjustments to reconcile net income to net cash provided (used) by operating activities: | ||||||||||||
Depreciation, depletion and amortization |
| 30,639 |
|
| 19,579 |
|
| 12,027 |
| |||
Impairment of oil and gas properties |
| 796 |
|
| 33,583 |
|
| — |
| |||
Loss (gain) on the sale of property and equipment |
| 5 |
|
| (492 | ) |
| (24,795 | ) | |||
Gain on sale of securities |
| — |
|
| (54,688 | ) |
| — |
| |||
Deferred income taxes |
| 8,133 |
|
| (1,888 | ) |
| 7,006 |
| |||
Tax benefit from stock option exercises |
| 230 |
|
| 2,933 |
|
| 1,049 |
| |||
Dry hole and unproved leasehold expense |
| 2,255 |
|
| 8,953 |
|
| 3,154 |
| |||
Minority interest |
| 11,896 |
|
| 1,763 |
|
| — |
| |||
Noncash interest expense |
| 666 |
|
| 285 |
|
| 112 |
| |||
Other |
| 1,074 |
|
| 194 |
|
| 28 |
| |||
| 67,798 |
|
| 44,559 |
|
| 37,846 |
| ||||
Changes in operating assets and liabilities: | ||||||||||||
Accounts receivable |
| (5,695 | ) |
| 592 |
|
| (6,046 | ) | |||
Other current assets |
| (646 | ) |
| (2,041 | ) |
| 161 |
| |||
Accounts payable and accrued liabilities |
| 6,849 |
|
| 4,986 |
|
| 2,723 |
| |||
Taxes on income |
| — |
|
| (7,296 | ) |
| 7,296 |
| |||
Other assets and liabilities |
| (2,518 | ) |
| 3,391 |
|
| (240 | ) | |||
Net cash flows provided by operating activities |
| 65,788 |
|
| 44,191 |
|
| 41,740 |
| |||
Cash flows from investing activities: | ||||||||||||
Proceeds from the sale of securities |
| — |
|
| 57,525 |
|
| — |
| |||
Proceeds from the sale of property and equipment |
| 1,319 |
|
| 1,416 |
|
| 55,208 |
| |||
Payments received on long-term notes receivable |
| 555 |
|
| 1,052 |
|
| 926 |
| |||
Sale of restricted U. S. Treasury Notes |
| 43,387 |
|
| — |
|
| — |
| |||
Purchase of restricted U.S. Treasury Notes |
| — |
|
| (43,387 | ) |
| — |
| |||
Additions to property and equipment |
| (144,741 | ) |
| (196,038 | ) |
| (59,443 | ) | |||
Net cash flows used in investing activities |
| (99,480 | ) |
| (179,432 | ) |
| (3,309 | ) | |||
Cash flows from financing activities: | ||||||||||||
Dividends paid |
| (8,040 | ) |
| (7,930 | ) |
| (7,407 | ) | |||
Distributions paid to minority interest holders of subsidiary |
| (13,787 | ) |
| — |
|
| — |
| |||
Proceeds from borrowings |
| 22,046 |
|
| 147,895 |
|
| 33,240 |
| |||
Repayment of borrowings |
| (10,729 | ) |
| (191,400 | ) |
| (63,509 | ) | |||
Proceeds from Penn Virginia Resource Partners, L.P. revolver |
| 47,500 |
|
| — |
|
| — |
| |||
Proceeds from Penn Virginia Resource Partners, L.P. term loan |
| — |
|
| 43,387 |
|
| — |
| |||
Proceeds from initial public offering, net |
| — |
|
| 142,373 |
|
| — |
| |||
Purchases of treasury stock |
| (557 | ) |
| (638 | ) |
| (6,761 | ) | |||
Purchase of units of Penn Virginia Resource Partners, L.P. |
| (1,067 | ) |
| — |
|
| — |
| |||
Issuance of stock |
| 2,046 |
|
| 10,440 |
|
| 6,084 |
| |||
Net cash flows provided by (used in) financing activities |
| 37,412 |
|
| 144,127 |
|
| (38,353 | ) | |||
Net increase in cash and cash equivalents |
| 3,720 |
|
| 8,886 |
|
| 78 |
| |||
Cash and cash equivalents – beginning of year |
| 9,621 |
|
| 735 |
|
| 657 |
| |||
Cash and cash equivalents – end of year | $ | 13,341 |
| $ | 9,621 |
| $ | 735 |
| |||
Supplemental disclosures: | ||||||||||||
Cash paid during the year for: | ||||||||||||
Interest (net of amount capitalized) | $ | 1,213 |
| $ | 3,131 |
| $ | 8,304 |
| |||
Income taxes | $ | 125 |
| $ | 28,772 |
| $ | 4,614 |
| |||
Noncash additions to property and equipment: | ||||||||||||
Issuance of Penn Virginia Resource Partners, L.P. units for acquisitions | $ | 50,920 |
| $ | — |
| $ | — |
| |||
Working capital and assumed liabilities for acquisitions, net | $ | 3,805 |
| $ | — |
| $ | — |
| |||
Deferred tax liabilities related to acquisition, net | $ | — |
| $ | 43,137 |
| $ | — |
| |||
The accompanying notes are an integral part of these consolidated financial statements.
Page 48
PENN VIRGINIA CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. Nature of Operations
Penn Virginia Corporation ("(“Penn Virginia"Virginia” or the "Company"“Company”) exploresis an independent energy company that is engaged in two primary lines of business. We explore for, developsdevelop and producesproduce crude oil, condensate and natural gas in the eastern and southern portions of the United States. In addition, we conduct our coal operations through our ownership in Penn Virginia Resource Partners, L.P. (the “Partnership” or “PVR”); a Delaware limited partnership. See Note 2 (Penn Virginia Resource Partners, L.P.).
The Company owns land and mineral rightsPartnership enters into leases with various third-party operators for the right to mineable and
merchantablemine coal reserves and timber locatedon the Partnership’s property in central
Appalachia. The coal reservesexchange for royalty payments. Coal royalty revenues under non-Peabody Leases are leased to various operators
who mine and market the coal. Penn Virginia collects royalties based on the lessee'shigher 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. Under the Peabody leases, coal royalty revenues are based on fixed royalty rates which escalate annually, also with pre-established monthly minimums. The Partnership also sells timber growing on its land and provides fee-based infrastructure facilities to certain lessees to enhance coal production and to generate additional coal services revenues.
2. Penn Virginia Resource Partners, L.P.
Penn Virginia Resource Partners, L.P. was formed in July 2001 to own and operate the coal land management business of Penn Virginia.
The Partnership completed its initial public offering of 7,475,000 common units at a price of $21.00 per unit on October 30, 2001. Total proceeds for the 7,475,000 units were $157.0 million before offering costs and underwriters’ commissions. Effective with the closing of the initial public offering, Penn Virginia, through its wholly owned subsidiaries, received 174,880 common units, 7,649,880 subordinated units and a 2 percent partnership interest in the ownership of the Partnership. In addition, concurrent with the closing of the initial public offering, the Partnership borrowed $43.4 million under its term loan credit facility with PNC Bank, National Association and other lenders.
In conjunction with the formation of the Partnership, Penn Virginia contributed to the Partnership net assets totaling $39.1 million. Concurrent with the initial public offering, the Partnership paid $141.5 million to Penn Virginia for repayment of debt and the purchase of 975,000 common units held by Penn Virginia. The Partnership’s note receivable from Penn Virginia was forgiven as well as the remaining portion of the Partnership’s note payable to Penn Virginia.
The common units have preferences over the subordinated units with respect to cash distributions, accordingly, we accounted for the sale of reserves. Timberthe Partnership units as a sale of a minority interest. At the time our subordinated units convert to common units, we will recognize any gain or loss computed at that time, as paid-in capital. Our subordinated units automatically convert to common units on September 30, 2006, but a portion of the subordinated units may convert after September 30, 2004 if the Partnership meets certain financial tests, namely operating surpluses that exceed the minimum quarterly distributions.
In December 2002, the Partnership acquired approximately 120 million tons of coal reserves from subsidiaries of Peabody Energy Corporation (“Peabody”). In conjunction with the acquisition, the Partnership issued 1,522,325 common units and 1,240,833 Class B common units, of which 293,700 Class B common units are held in escrow pending certain title transfers. All Class B common units share in income and distributions on the same basis as the common units, but they are not listed on the New York Stock Exchange. Subject to the approval of our common unitholders, the Class B common units will automatically convert into an equal number of common units; however, if the conversion is solddenied, Peabody, as holder of the Class B units, would have the right to receive 115 percent of the amount of distributions paid on the common units. Adoption of the proposed conversion requires the affirmative vote of a majority of the votes cast at a special meeting of unitholders to be held in competitive bid sales involving individual parcels and
also on a contract basis, where2003, provided that the total votes cast represent over 50 percent in interest of all common units entitled to vote.
The general partner of the Partnership is Penn Virginia pays independent
contractors to harvest timber while the Company directly markets
the product.
2.Resource GP, LLC (the “general partner”), a wholly owned subsidiary of Penn Virginia.
3. Summary of Significant Accounting Policies
Principles of Consolidation
The consolidated financial statements include the accounts of Penn Virginia, Corporation and all wholly-owned subsidiaries. The
Company ownssubsidiaries, and operates itsthe Partnership in which we have an approximate 45 percent ownership interest as of December 31, 2002. Penn Virginia Resource GP, LLC, a wholly-owned subsidiary of Penn Virginia, serves as the Partnership’s sole general partner and controls the Partnership. We own and operate
Page 49
our undivided oil and gas properties
and manages its coal reserves through itsour wholly-owned subsidiaries. The Company accountsWe account for itsour undivided interest in oil and gas properties using the proportionate consolidation method, whereby the Company'sour share of assets, liabilities, revenues and expenses is included in the appropriate classification in the financial statements. Intercompany balances and transactions have been eliminated in consolidation. In the opinion of management, all adjustments have been reflected that are necessary for a fair presentation of the consolidated financial statements. Certain amounts have been reclassified to conform to the current year'syear’s presentation.
New Accounting Standards
In June 1998, the Financial Accounting Standards Board ("FASB")
issued Statement of Financial Accounting Standards ("SFAS") No.
133, "Accounting for Derivative Instruments and Hedging
Activities." SFAS No. 133, as amended by SFAS No. 137 and SFAS
No. 138, establishes accounting and reporting standards for
derivative instruments, including certain derivative instruments
embedded in other contracts, (collectively referred to as
derivatives) and for hedging activities. It requires an entity
to recognize all derivatives as either assets or liabilities in
the statement of financial position and measure those instruments
at fair value. If certain conditions are met, a derivative may
be specifically designated as (a) a hedge of the exposure to
changes in the fair value of a recognized asset or liability or
an unrecognized firm commitment, (b) a hedge of the exposure to
changes in the fair value of the exposure to variable cash flows
of a forecasted transaction, or (c) a hedge of the foreign
currency exposure of a net investment in a foreign operation, an
unrecognized firm commitment, an available-for-sale security, or
a foreign currency denominated forecasted transaction. Special
accounting for qualifying hedges allows a derivative's gains and
losses to offset related results on the hedged item in the
Company's statement of income. The adoption of SFAS No. 133 on
January 1, 2001 did not have a material impact on the Company's
financial position or results of operations.
In December 1999, the Securities and Exchange Commission
("SEC") issued Staff Accounting Bulletin No. 101, "Revenue
Recognition in Financial Statements' ("SAB No. 101"). SAB No.
101, as amended, summarizes the SEC's views in applying generally
accepted accounting principles to revenue recognition in
financial statements. The adoption of SAB No. 101 on October 1,
2000 did not have a material effect on the Company's financial
position or results of operations.
Use of Estimates
Preparation of the accompanying consolidated financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities in the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
Cash and Cash equivalents
The Company considersequivalents/Restricted U.S. Treasury Notes
We consider all highly liquid investments purchased with an original maturity of three months or less to be cash equivalents. As of December 31, 2001, the Partnership had restricted cash in the form of U.S. Treasury Notes, which were used to secure the Partnership’s term loan facility. See Note 11 (Long-Term Debt). In 2002, the Partnership sold the U.S. Treasury Notes and used the proceeds to purchase property and equipment.
Investments
Investments consist
During 2001 and 2000, we held investments that consisted of publicly traded equity securities. The
Company classifies itsWe classify our equity securities as available-for-sale. Available-for-sale securities are recorded at fair value based upon market quotations. Unrealized holding gains and losses, net of the related tax effect, on available-for-salethese securities are excluded from earnings and are reported as a separate component of stockholders' equity until realized.stockholders’ equity. See Note 18 (Accumulated Other Comprehensive Income). A decline in the market value of any available-for-sale security below cost that is deemed other than temporary, is charged to earnings in the period it occurs resulting in the establishment of a new cost basis for the security. Dividend income is recognized when earned.received. Realized gains and losses for securities classified as available-
for-saleavailable-for-sale are included in earnings and are derived using the specific identification method for determining the cost of securities sold. NotesSee Note 5 (Investments and Dividend Income).
Note Receivable
Notes
The note receivable areis recorded at cost and adjusted for amortization of discounts. Discounts are amortized over the life of the notesnote receivable using the effective interest rate method.
Oil and Gas Properties
The Company uses
We use the successful efforts method of accounting for itsour oil and gas operations. Under this method of accounting, costs to acquire mineral interests in oil and gas properties and to drill and equip development wells including(including development dry holes,holes) are capitalized and to drillamortized on a unit-of-production basis over the remaining life of proved developed reserves and equipproved reserves, respectively. Cost of drilling exploratory wells are initially capitalized, and later charged to expense upon determination that find proved
reservesthe well does not justify commercial development. Other exploratory costs, including annual delay rentals and geological and geophysical costs, are capitalized. Capitalized costs of producing oil and
gas fields are amortized using the unit-of-production method
based on estimates of proved oil and gas reserves on a field-by-
field basis. Oil and gas reserve quantities represent estimates
only and there are numerous uncertainties inherent in the
estimation process. Actual future production may be materially
different from amounts estimated and such differences could
materially affect future amortization of proved properties.
Estimated costs (net of salvage value) of plugging and abandoning
oil and gas wells are reported as additional depreciation and
depletioncharged to expense using the units-of-production method.
when incurred.
The costs of unproved leaseholds, incuding capitalized interest, are capitalized pending the results of exploration efforts. During 2002 and 2001, interest costs associated with non-producing leases were capitalized for the period activities were in progress to bring projects to their intended use. We capitalized $1.0 million and $1.1 million of interest costs in 2002 and 2001, respectively. No interest costs were capitalized in 2000. Unproved leasehold costs are assessed periodically, on a property-by-property basis, and a loss is recognized to the extent, if any, the cost of the property has been impaired. As unproved leaseholds are determined to be productive, the related costs are transferred to proved leaseholds. Exploratory costs including exploratory dry holes,
annual delay rental and geological and geophysical costs are
charged to expense when incurred.
Other Property and Equipment
Other property and equipment is carried at cost and includes expenditures for additions and improvements, which substantially increase the productive lives of existing assets. Maintenance and repair costs are expensed as incurred. Depreciation of property and equipment is generally computed using the straight-
linestraight-line method over their estimated useful lives, varying from 3 years to 20 years. Coal in place isproperties are depleted on an area-by-area basis at a rate based upon the cost of the mineral properties and estimated mineableproven and merchantableprobable tonnage therein. When an asset is retired or sold, its cost and related accumulated depreciation are removed from the accounts. The difference between undepreciated cost and proceeds from disposition is recorded as a gain or loss.
Impairment of Long-Lived Assets
The Company reviews its
We review our long-lived assets to be held and used, including proved oil and gas properties accounted for usingand the successful efforts method of accounting,Partnership’s coal properties, whenever events or circumstances indicate that the carrying value of those assets may not be recoverable. An impairment loss must be recognized when the carrying amount of an asset exceeds the sum of the undiscounted estimated future cash flows. In this circumstance, the Companywe would recognize an impairment loss equal to the difference between the carrying value and the fair value of the asset.
Page 50
Fair value is estimated to be the expected present value of
expected future net cash flows from proved reserves, discounted utilizing a risk-adjustedrisk-free interest rate of return.
commensurate with the remaining lives for the respective oil and gas properties.
Concentration of Credit Risk
Substantially all of the Company'sour accounts receivable at December 31, 20002002 result from oil and gas sales and joint interest billings to third party companies in the oil and gas industry. This concentration of customers and joint interest owners may impact the Company'sour overall credit risk, either positively or negatively, in that these entities may be similarly affected by changes in economic or other conditions. In determining whether or not to require collateral from a customer or joint interest owner, we analyze the Companyentity’s net worth, cash flows, earnings and credit ratings. Receivables are generally not collateralized. Historical credit losses incurred on receivables have not been significant.
Substantially all of the Partnership’s accounts receivable at December 31, 2002, result from billings to third party companies in the coal industry. This concentration of customers may impact the Partnership’s overall credit risk, either positively or negatively, in that these entities may be similarly affected by changes in economic or other conditions. In determining whether or not to require collateral from a lessee, the Partnership analyzes the entity'sentity’s net worth, cash flows, earnings and credit ratings. Receivables are generally not collateralized. Historical credit losses incurred by the CompanyPartnership on receivables have not been significant.
Risk Factors
Our revenues, profitability, cash flow and future growth rates are substantially dependent upon the price of and demand for natural gas and crude oil and to a lesser extent coal. Prices for natural gas and crude oil are subject to wide fluctuations in response to relatively minor changes in the supply of and demand for natural gas and crude oil, market uncertainty and a variety of additional factors that are beyond our control. We are also dependent upon the continued success of our exploratory drilling program. Other factors that could affect revenues, profitability, cash flow and future growth rates include the inherent uncertainties in crude oil, natural gas and coal reserves, hedging of our crude oil and natural gas production with derivative instruments, the ability to replace crude oil, natural gas and coal reserves, and finance future capital spending requirements.
Fair Value of Financial Instruments
The Company's
Our financial instruments consist of cash and cash equivalents, marketable securities, accounts receivable, notes receivables, U.S. Treasury Notes, accounts payable and long-term debt. The carrying values of cash, marketable securities, accounts receivables, andU.S. Treasury Notes, accounts payables, and long-term debt approximate fair value. See Note 5
for a discussion of notes receivable.
Price Risk Management Activities
The Company, from time to time, enters into derivative financial
instruments to mitigate its exposure to natural gas price
volatility. The derivative financial instruments, which are
placed with a major financial institution the Company believes is
a minimum credit risk, take the form of swaps with purchased
options. Through December 31, 2000, the derivative financial
instruments were designated as hedges and realized gains and
losses from the Company's price risk management activities were
recognized in natural gas revenues when the associated production
occurs. Effective January 1, 2001, any derivative financial
instruments will be accounted for in accordance with SFAS 133, as
amended by SFAS 137 and SFAS 138.
The fair value of open derivative financial instruments is
determined by comparing the New York Mercantile Exchange forward
prices at year-end with the appropriate location differential
adjustment to the contractual prices designated in the derivative
financial instruments. The Company had no outstanding derivative
financial instrumentsnotes receivable at December 31, 2000 or 1999. The fair
value of the Company's open derivative contracts at December 31,
19982002 and 2001 was $0.1 million.
$3.4 million and $4.6 million, respectively.
Revenues
Oil and Gas
NaturalGas.Oil and gas sales revenues generally are recorded using the
entitlement method in which the Company recognizes its ownership
interest inrecognized when crude oil and natural gas production as revenue.volumes are produced and sold for our account. Each working interest owner in a well generally has the right to a specific percentage of production, althoughand often actual production sold mayfor any particular owner will differ from antheir ownership percentage. Using entitlement
accounting, a receivable is recorded when under-production occurs
and deferred revenue is recognized when over-production occurs.
When, under contract terms, these differences are settled in cash, revenues are adjusted accordingly.
Coal RoyaltiesRoyalties. Coal royalty income isrevenues are recognized on the basis of tons of coal sold by the Company'sPartnership’s lessees and the corresponding revenue from those sales. AllMost coal leases are based on minimum monthly or annual payment,payments, a minimum dollar royalty per ton and/or a percentage of the gross sales price.
Coal Services.Coal services revenues are recognized when lessees use the Partnership’s facilities for the processing and transportation of coal. Coal services revenues consist of fees collected from the Partnership’s lessees for the use of the Partnership’s loadout facility, coal preparation plant, dock loading facility. Revenues associated with coal services for the years ended December 31, 2002 and 2001 were approximately $1.7 million for both years, and are included in other revenues.
Timber.Timber Timberrevenues are recognized as timber is sold in competitive bid sales involving individual
parcels and also on a contract basis whereby Penn Virginia payswhere independent contractors harvest and sell the timber and, from time to time, in a competitive bid process involving sales of standing timber on individual parcels. Title and risk of loss pass to the independent contractors upon the execution of the contract. In addition, if the contractors do not harvest the timber whilewithin the Company
directly marketsspecified time period, the product. Timbertitle of the timber reverts back to the Partnership with no refund of original payment.
Minimum Rentals. Most of the Partnership’s lessees must make minimum monthly or annual payments that are generally recoupable over certain time periods. These minimum payments are recorded as deferred income. If the lessee recoups a minimum payment through production, the deferred income attributable to the minimum payment is recognized whenas coal royalty revenues. If a lessee fails to meet its minimum production for certain pre-determined time periods (the recoupment period), the timber has been sold.
deferred income attributable to the minimum payment is recognized as minimum rental revenues. Revenues associated with minimum rentals are included in other revenues.
Page 51
Income Tax
The Company accounts
We account for income taxes in accordance with the provisions of SFAS No. 109, "AccountingAccounting for Income Taxes."Taxes. This statementStatement requires a company to recognize deferred tax liabilities and assets for the expected future tax consequences of events that have been recognized in a company'scompany’s financial statements or tax returns. Using this method, deferred tax liabilities and assets are determined based on the difference between the financial statement carrying amounts and tax bases of assets and liabilities using enacted tax rates.
3.
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. See Note 17 (Stock Compensation and Stock Ownership Plans). We account for those plans under the recognition and measurement principles of 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 if we had applied the fair value recognition provision of SFAS No. 123,Accounting for Stock-Based Compensation, to stock-based employee options.
Year ended December 31, | ||||||||||||
2002 | 2001 | 2000 | ||||||||||
Net income, as reported | $ | 12,104 |
| $ | 34,337 |
| $ | 39,265 |
| |||
Add: Stock-based employee compensation expense included in reported net income related to restricted units and director compensation, net of related tax effects |
| 424 |
|
| 215 |
|
| 147 |
| |||
Less: Total stock-based employee compensation expense determined under fair value based method for all awards, net of related tax effects |
| (1,268 | ) |
| (900 | ) |
| (320 | ) | |||
Pro forma net income | $ | 11,260 |
| $ | 33,652 |
| $ | 39,092 |
| |||
Net income per share | ||||||||||||
Basic – as reported | $ | 1.35 |
| $ | 3.92 |
| $ | 4.76 |
| |||
Basic – pro forma | $ | 1.26 |
| $ | 3.84 |
| $ | 4.74 |
| |||
Diluted – as reported | $ | 1.34 |
| $ | 3.86 |
| $ | 4.69 |
| |||
Diluted – pro forma | $ | 1.25 |
| $ | 3.78 |
| $ | 4.67 |
| |||
New Accounting Standards
In June 2001, the Financial Accounting Standards Board (“FASB”) issued 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 the asset.
SFAS No. 143 requires that the fair value of a liability for an asset retirement obligation be 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 this additional carrying amount is depreciated over the life of the asset. The liability is accreted at the end of each period through charges to operating expense. If the obligation is settled for other than the carrying amount of the liability, we will recognize a gain or loss on settlement.
We will adopt the provisions of SFAS No. 143 effective January 1, 2003. We identified all required asset retirement obligations and determined the fair value of these obligations on the date of adoption. The determination of fair value was based upon regional market and specific well or mine type information. In conjunction with the initial application of SFAS No. 143, it is expected we will record a cumulative-effect of change in accounting principle, net of taxes, of approximately $0.5 to $1.5 million as an increase to income, which will be reflected in the Company’s results of operations for 2003. In addition, it is expected we will record an asset retirement obligation of approximately $2.3 to $3.3 million.
Effective January 1, 2002 we adopted SFAS No. 144,Accounting for the Impairment or Disposal of Long-Lived Assets. This Statement supersedes SFAS No. 121,Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of, and the accounting and reporting provisions of APB No. 30,Reporting the Results of Operations – Reporting the Effects of Disposal of a Segment of a Business, and Extraordinary, Unusual and Infrequently Occurring Events and Transactions, for the
Page 52
disposal of a segment of a business. SFAS No. 144 addresses financial accounting and reporting for the impairment or disposal of long-lived assets. See Note 15 (Discontinued Operations) for current year disclosures related to our adoption.
In April 2002, the FASB issued SFAS No. 145,Rescission of FASB Statements No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical Corrections. This Statement rescinds SFAS No. 4,Reporting Gains and Losses from Extinguishment of Debt, which required all gains and losses from extinguishment of debt to be aggregated and, if material, classified as an extraordinary item of debt to be aggregated and, if material, classified as an extraordinary item, net of income taxes. As a result, the criteria in Accounting Principles Board Opinion (APB) Opinion No. 30 will now be used to classify those gains and losses. Any gain or loss on the extinguishment of debt that was classified as an extraordinary item in prior periods presented that does not meet the criteria in APB Opinion No. 30 for classification as an extraordinary item shall be reclassified. The provisions of this Statement are effective for fiscal years beginning after January 1, 2003. The initial adoption of SFAS No. 145 did not have a material effect on the financial position, results of operations or liquidity of the Company.
In June 2002, the FASB issued SFAS No. 146,Accounting for Costs Associated with Exit or Disposal Activities. This Statement requires the recognition of costs associated with exit or disposal activities when they are incurred rather than at the date of a commitment to an exit or disposal plan. The provisions of this Statement are effective for exit or disposal activities initiated after December 31, 2002.
In November 2002, the FASB issued Interpretation No. 45 ( FIN 45),Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of the Indebtedness of Others, which clarifies the requirements of SFAS No. 5,Accounting for Contingencies, relating to a guarantor’s accounting for and disclosures of certain guarantees issued. FIN 45 requires enhanced disclosures for certain guarantees. It also will require certain guarantees that are issued or modified after December 31, 2002, including certain third-party guarantees, to be initially recorded on the balance sheet at fair value. For guarantees issued on or before December 31, 2002, liabilities are recorded when and if payments become probable and estimable. The financial statement recognition provisions are effective prospectively, and the Company cannot reasonably estimate the impact of adopting FIN 45 until guarantees are issued or modified in future periods, at which time their results will be initially reported in the financial statements
4. Acquisitions
Oil and Dispositions
In May 2000, Penn Virginia successfully completedgas
On January 22, 2003, we acquired a 25 percent non-operated working interest in properties located in a producing field in south Texas. Proved reserves of 31.8 billion cubic feet equivalent of (unaudited) were acquired in a cash transaction with a private investor group for $32.5 million. The acquisition, which was effective January 1, 2003, was financed with the purchaseCompany’s existing credit facility. Nine wells are currently producing and comprise approximately one-third of the total proved reserves acquired. As of January 22, 2003, daily production net to the Company was approximately 11.4 million cubic feet (MMcf) of natural gas reservesand 570 barrels of oil, or 14.8 MMcf equivalents (unaudited). Additional wells are expected to be drilled over the next two to three years to fully develop the field.
On July 23, 2001, we acquired all of the outstanding stock of Synergy Oil & Gas, Inc., a Texas corporation. Synergy was a privately owned independent exploration and production company with operations primarily in the Texas onshore Gulf Coast and West Virginia and KentuckyTexas areas. Cash consideration for $34.7the stock was approximately $112 million, after closing adjustments. Additionally, in
September 1999, the Company completed the purchase of fee mineral
and lease rights for coal reserves and related assets in West
Virginia for $30 million. Both acquisitions werewhich was funded by borrowings from the Company'sadvances under our revolving credit facility (the
"Revolver") and accounted for at fair value.available cash on hand. The operations have
been includedtotal purchase price was allocated to the assets purchased and the liabilities assumed in the Company's statementSynergy transaction based upon the fair values on the date of incomeacquisition, as of the
closing date. follows (in thousands):
Value of oil and gas properties acquired | $ | 157,120 |
| |
Net assets acquired, excluding oil and gas properties |
| 351 |
| |
Deferred income tax liability |
| (45,271 | ) | |
Cash paid, net of cash acquired | $ | 112,200 |
| |
Page 53
The following unaudited pro formaPro Forma results of operations have been prepared as though the acquisitionsacquisition had been completed on January 1, 1999.2000. The unaudited pro formaPro Forma results of operations for the years ended December 31, 20002001 and 19992000 are as follows (in thousands, except share data):
2001 | 2000 | |||||
Revenues | $ | 114,629 | $ | 128,127 | ||
Net income | $ | 40,026 | $ | 33,773 | ||
Net income per share, diluted | $ | 4.50 | $ | 4.03 | ||
Coal Royalty and Land Management
In December 2000,2002, the Company sold oilPartnership acquired two properties containing approximately 120 million tons of coal reserves from Peabody for 1,522,325 million common units, 1,240,833 million Class B common units (a combined common unit value of $57.0 million) and gas properties$72.5 million in cash. The acquisition includes approximately $6.1 million, or 293,700 Class B units, which are currently held in escrow pending certain title transfers. As a result of the units held in escrow, approximately five million tons of coal reserves and 293,700 Class B common units were not included in property, plant and equipment or partners’ capital, respectively, at December 31, 2002. The Class B common units will be converted to common units upon approval by the common unitholders. Approximately two-thirds of the reserves are located in KentuckyNew Mexico, which Peabody will continue to operate as a surface mining operation. Approximately one third of the acquired reserves are in northern West Virginia, which Peabody will also continue to operate. Each set of reserves is being leased back to Peabody for royalty rates which escalate annually over the life of the property’s production. As part of the transaction, Peabody will receive the right to share in cash distributed with respect to the general partner’s incentive distribution rights, if any, in exchange for additional properties Peabody may source to the Partnership in the future. The cash portion of the transaction was funded with long-term debt and West Virginia. Proceeds$26.4 million in proceeds from the sale totaled $54.3of U.S. Treasury notes. The acquired coal reserves had existing productive operations that have been included in the Partnership’s statements of income since the closing date.
In November 2002, the Partnership completed the acquisition of certain infrastructure-related equipment and other assets integral to mining on its Fork Creek property in West Virginia. The purchased assets included a 900-ton per hour coal preparation plant, a unit-train loading facility and a railroad-granted rebate on coal loaded through the facility. The Partnership acquired the assets from Pen Holdings, Inc. and its lessors for $5.1 million afterin cash, which was funded with the proceeds from the sale of U.S. Treasury notes, plus the assumption of approximately $2.4 million in reclamation liabilities and approximately $0.6 million of stream mitigation obligations. The Partnership is actively seeking a new lessee and, as is customary in its operations, intends to assign all reclamation liabilities to such lessee. These assets did not have existing productive operations.
In August 2002, the Partnership acquired the mineral rights to approximately 16 million tons of coal reserves (unaudited) located in West Virginia for $12.3 million. The acquisition, which was purchased from an independent private entity, was funded with the proceeds from the sale of U.S. Treasury notes. The acquired mineral rights had existing productive operations that have been included in the Partnership’s statements of income since the closing adjustments,date.
In June 2001, the Partnership completed a $33.1 million acquisition from Pen Holdings, Inc., an unrelated third party. The acquisition contained 53 million tons of coal reserves in West Virginia (unaudited). Theproperty had existing productive operations that have been included in the Partnership’s statements of income since the closing date.
The factors used by the Partnership to determine the fair market value of acquisitions include, but are not limited to, discounted future net cash flows on a risked-adjusted basis, geographic location, quality of resources, potential marketability and financial condition of the Company
recognized a gain of $23.9 million ($14.2 million after tax.)
4.lessees.
5. Investments and Dividend Income
The cost, gross unrealized holding gains and fair value
In April 2001, we sold 3.3 million shares of available-for-sale securities were as follows (in thousands):
Dividend income from the
Company'sour investment in Norfolk Southern Corporation was $0.2 million for the year ended December 31, 2001 and $2.6 million for each of the three yearsyear ended December 31, 2000, 1999
and 1998. The closing stock price for Norfolk Southern
Corporation was $13.31 and $20.50 per share at2000.
Page 54
6. Notes Receivable
At December 31, 20002002, we had one note receivable outstanding, which relates to the sale of coal properties located in Virginia in 1986. The note has a stated interest rate of 6.0 percent per annum and had an original principal amount of $15.0 million pursuant to which we receive quarterly payments through July 1, 2005. In addition, we own a 50 percent residual interest in any royalty income generated from the coal properties sold which are mined after July 1, 2005.
At December 31, 2001, we had an additional note relating to the sale of property and equipment in 1999 respectively.
5. Notes Receivable
The Company's notesfor which we received a $1.3 million note for a portion of the proceeds. This note was repaid in full in 2002.
Our note receivable areis collateralized by property and equipment. During 1999, the Company received a $1.3 million
note receivable for a portion of the proceeds relating to a
property and equipment sale. Maturities of notes receivable are as follows (in thousands):
December 31, | ||||||
2002 | 2001 | |||||
Current | $ | 527 | $ | 599 | ||
Due after one year through five years |
| 1,274 |
| 1,757 | ||
Total | $ | 1,801 | $ | 2,356 | ||
7. Property and Equipment
Property and equipment includes (in thousands):
December 31, | ||||||||
2002 | 2001 | |||||||
Oil and gas properties | ||||||||
Unproved | $ | 57,575 |
| $ | 57,813 |
| ||
Proved |
| 325,785 |
|
| 277,681 |
| ||
Total oil and gas properties |
| 383,360 |
|
| 335,494 |
| ||
Other property and equipment: | ||||||||
Land and timber |
| 1,979 |
|
| 1,961 |
| ||
Coal properties |
| 244,702 |
|
| 106,270 |
| ||
Other equipment |
| 18,499 |
|
| 9,558 |
| ||
Total property and equipment |
| 648,540 |
|
| 453,283 |
| ||
Less: Accumulated depreciation, depletion and amortization |
| (102,588 | ) |
| (72,095 | ) | ||
Net property and equipment | $ | 545,952 |
| $ | 381,188 |
| ||
8. Impairment of Oil and Gas Properties
In accordance with SFAS No. 121,144,Accounting for the Company reviews its provedImpairment of Disposal or Long-Lived Assets,we review oil and gas properties and other long-lived assets for impairment wheneverwhen events and circumstances indicate a decline in the recoverability of theirthe carrying value. Invalue of such properties, such as a downward revision of the fourth quarter of
1998,reserve estimates. We estimate the Company estimated the expected future cash flows of its
oil and gasexpected in connection with the properties and comparedcompare such future cash flows to the carrying amount of the oil and gas properties to determine if the carrying amount wasis recoverable. For certain oil and gas
properties,When we find that the carrying amount exceededamounts of the properties exceed their estimated undiscounted future cash flows; thus, the Company adjustedflows, we adjust the carrying amount of the respective oil and gas properties to their fair value as determined by discounting theirits estimated future cash flows. For the twelve months ended December 31, 2002, we recognized a pretax charge of $0.8 million ($0.5 million after tax) related to the impairment of such properties. The factors used to determine fair value included, but were not limited to, estimates of proved reserves, future commodity pricing,prices, and timing of future production, estimates, anticipatedfuture capital expenditures and a discount rate commensurate with the Company's internalrisk-free interest rate reflective of return on itsthe lives remaining for the respective oil and gas properties.
As
Due to a result,low commodity price environment at the Companyend of 2001, we recognized a noncashnon-cash pre-tax charge of $4.6$33.6 million ($3.721.8 million after tax) related to itsthe impairment of oil and gas properties in the fourth quarter of 1998.2001. There were no impairments of oil and gas properties in 2000.
Page 55
9. Price Risk Management Activities
From time to time, we enter into derivative financial instruments to mitigate our exposure to natural gas and crude oil price volatility. The derivative financial instruments, which are placed with major financial institutions that we believe are minimum credit risks, take the form of costless collars and swaps. All derivative financial instruments are recognized in the financial statements at fair value in accordance with SFAS No. 133, as amended by SFAS No. 137 and SFAS No. 138.
All derivative instruments are recorded on the balance sheet at fair value. If the derivative does not qualify as a hedge or is not designated as a hedge, the gain or loss on the derivative is recognized currently in earnings. To qualify for hedge accounting, the derivative must qualify either as a fair value hedge, cash flow hedge or foreign currency hedge. Currently, we are utilizing only cash flow hedges and the remaining discussion will relate exclusively to this type of derivative instrument. All hedge transactions are subject to our risk management policy, which has been reviewed and approved by the Board of Directors.
We formally document all relationships between hedging instruments and hedged items, as well as its risk-management objective and strategy for undertaking various hedge transactions. This process includes linking all derivatives that are designated as cash flow hedges to forecasted transactions. We also formally assess, both at inception of the hedge and on an ongoing basis, whether the derivatives that are used in hedging transactions are highly effective in offsetting changes in cash flows of hedged transactions. We measure hedge effectiveness on a period basis. When it is determined that a derivative is not highly effective as a hedge, or that it has ceased to be a highly effective hedge, we discontinue hedge accounting prospectively.
When hedge accounting is discontinued because it is probable that a forecasted transaction will not occur, the derivative will continue to be carried on the balance sheet at its fair value, and gains and losses that were accumulated in other long-lived assetscomprehensive income will be recognized in 2000earnings immediately. In all other situations in which hedge accounting is discontinued, the derivative will be carried at its fair value on the balance sheet, with changes in its fair value recognized in earnings prospectively.
Gains and losses on hedging instruments when settled are included in natural gas or 1999.
7.crude oil production revenues in the period that the related production is delivered.
The fair values of our hedging instruments are determined based on third party forward price quotes for NYMEX Henry Hub and West Texas Intermediate closing prices as of December 31, 2002. The following table sets forth our positions as of December 31, 2002:
Notional | |||||||||||
Time Period | Quantities | Effective Floor/Ceiling Price | Fair Value | ||||||||
(in thousands) | |||||||||||
Natural Gas | (MMbtu per Day | ) |
| (Per Mmbtu | ) | ||||||
Costless collars | |||||||||||
January 1 – March 31, 2003 | 10,000 |
| $ | 3.01 / $5.01 |
| $ | (168 | ) | |||
January 1 – September 30, 2003 | 5,000 |
| $ | 3.37 / $5.05 |
|
| (240 | ) | |||
April 1 – October 31, 2003 | 5,000 |
| $ | 2.92 / $4.42 |
|
| (535 | ) | |||
October 2003 | 3,000 |
| $ | 3.50 / $5.00 |
|
| (32 | ) | |||
November 1, 2003 – April 30, 2004 | 8,000 |
| $ | 3.50 / $5.00 |
|
| (501 | ) | |||
April 1 2003 – June 30, 2004 | 7,500 |
| $ | 3.50 / $5.28 |
|
| (445 | ) | |||
Crude Oil | (Bbls per Day | ) | |||||||||
Costless collars | |||||||||||
January 1 – June 30, 2003 | 500 |
| $ | 23.00 /$28.75 |
|
| (144 | ) | |||
Total | $ | (2,065 | ) | ||||||||
Based upon our assessment of our derivative contracts at December 31, 2002, we reported (i) an approximate liability of $2.1 million and (ii) a loss in accumulated other comprehensive income of $1.3 million, net of related income taxes of $0.8 million. In connection with monthly settlements, we recognized net hedging losses in natural gas and oil revenues of $1.0 million for the year ended December 31, 2002. Based upon future oil and natural gas prices as of December 31, 2002, $1.6 million of hedging losses are expected to be realized within the next 12 months. The amounts ultimately realized will vary due to changes in the fair value of the open derivative contracts prior to settlement. We recognized net hedging gains of $1.9 million for the year ended December 31, 2001. We had no outstanding derivative financial instruments at December 31, 2000.
Page 56
As of February 14, 2003 our open commodity price risk management positions on average daily volumes were as follows:
Natural gas hedging positions | Costless Collars | Swaps | |||||||||||
MMBtu | Price / MMBtu (a) | MMBtu | Price | ||||||||||
Per Day | Floor | Ceiling | Per Day | /MMBtu | |||||||||
First Quarter 2003 | 15,000 | $ | 3.15 | $ | 5.05 | 3,164 | $ | 4.70 | |||||
Second Quarter 2003 | 21,500 | $ | 3.39 | $ | 5.36 | 3,399 | $ | 4.70 | |||||
Third Quarter 2003 | 21,500 | $ | 3.39 | $ | 5.36 | 2,570 | $ | 4.70 | |||||
Fourth Quarter 2003 | 19,500 | $ | 3.49 | $ | 5.46 | 2,034 | $ | 4.70 | |||||
First Quarter 2004 | 19,500 | $ | 3.54 | $ | 5.51 | 1,800 | $ | 4.70 | |||||
Second Quarter 2004 | 14,137 | $ | 3.56 | $ | 5.70 | 1,533 | $ | 4.70 | |||||
Third Quarter 2004 | 1,348 | $ | 3.72 | $ | 6.97 | 1,367 | $ | 4.70 | |||||
Fourth Quarter 2004 | — | $ | — | $ | — | 1,234 | $ | 4.70 | |||||
First Quarter 2005 (January) | — | $ | — | $ | — | 1,100 | $ | 4.70 | |||||
| (a) | The costless collar natural gas prices per MMBtu per quarter include the effects of basis differentials, if any, that may be hedged. |
Crude oil hedging positions | Costless Collars | Swaps | |||||||||||
Barrels | Price /Barrel | Barrels | Price | ||||||||||
Per Day | Floor | Ceiling | Per Day | /Barrel | |||||||||
First Quarter 2003 | 500 | $ | 23.00 | $ | 28.75 | 150 | $ | 26.93 | |||||
Second Quarter 2003 | 500 | $ | 23.00 | $ | 28.75 | 170 | $ | 26.93 | |||||
Third Quarter 2003 | — | $ | — | $ | — | 250 | $ | 26.76 | |||||
Fourth Quarter 2003 | — | $ | — | $ | — | 220 | $ | 26.74 | |||||
First Quarter 2004 | — | $ | — | $ | — | 207 | $ | 26.73 | |||||
Second Quarter 2004 | — | $ | — | $ | — | 193 | $ | 26.71 | |||||
Third Quarter 2004 | — | $ | — | $ | — | 63 | $ | 26.93 | |||||
Fourth Quarter 2004 | — | $ | — | $ | — | 57 | $ | 26.93 | |||||
First Quarter 2005 (January) | — | $ | — | $ | — | 50 | $ | 26.93 | |||||
10. Accrued Liabilities
Accrued expenses are summarized as follows (in thousands):
December 31, | ||||||
2002 | 2001 | |||||
Deferred income | $ | 2,829 | $ | — | ||
Taxes other than income |
| 2,809 |
| 2,700 | ||
Accrued oil and gas royalties |
| 2,513 |
| 2,042 | ||
Compensation |
| 2,286 |
| 1,949 | ||
Accrued drilling costs |
| 1,481 |
| 1,641 | ||
Accrued professional services |
| 2,328 |
| 53 | ||
Post-retirement healthcare |
| 160 |
| 160 | ||
Pension |
| 140 |
| 140 | ||
Other |
| 1,962 |
| 2,077 | ||
Total | $ | 16,508 | $ | 10,762 | ||
Page 57
11. Long-Term Debt
Long-term debt consistsas of December 31, 2002 and 2001 consisted of the following (in thousands):
December 31, | ||||||||
2002 | 2001 | |||||||
Penn Virginia revolving credit facility, variable rate of 2.8% at December 31, 2002, due in 2004 | $ | 16,000 |
| $ | 3,500 |
| ||
PVR revolving credit facility, variable rate of 3.2% at December 31, 2002, due in 2004 |
| 47,500 |
|
| — |
| ||
PVR Term loan, variable rates of 1.9% to 2.7% at December 31, 2002, due in 2004 |
| 43,387 |
|
| 43,387 |
| ||
Line of credit |
| 52 |
|
| 1,235 |
| ||
| 106,939 |
|
| 48,122 |
| |||
Less: current maturities |
| (52 | ) |
| (1,235 | ) | ||
Total long-term debt | $ | 106,887 |
| $ | 46,887 |
| ||
The aggregate maturities applicable to outstanding debt at December 31, 20002002 are $0.7$52 thousand in 2003 and $106.9 million in 2001 and $47.5 million in
2003.2004.
Penn Virginia Revolving Credit Facility
The Company has an unsecured
We have a $150.0 million secured revolving credit facility (the "Revolver"“Revolver”) with a group of major U.S. banks. In 2000, the
Revolver was increased from $120banks, and a borrowing base of $140 million, to $150 million. which expires in October 2004.
The Revolver is governed by a borrowing base calculation and will be redetermined semi-annually. The Company hasWe have the option to elect interest at (i) LiborLIBOR plus a Eurodollar margin ranging from 1001.375 to 150 basis points,1.875 percent, based on the percentage of the borrowing base outstanding or (ii) the greater of the prime rate or federal funds rate plus 50 basis points.a margin ranging from 0.375 to 0.875 percent. The weighted average interest rate on borrowings incurred during the year ended December 31, 2002 was approximately 3.0 percent. The Revolver allows for issuance of letters of credit whichthat are limited to no more than $10 million. At December 31, 2002, letters of credit issued were $0.3 million. The financial covenants require the Companyus to maintain levels of net worth, debt-to-capitalizationdebt-to-earnings and dividend limitation restrictions. We are currently in compliance with all of our covenants.
PVR Revolving Credit Facility
The CompanyPartnership has a $50.0 million unsecured revolving credit facility (the “Partnership Revolver”) with a group of major banks, which expires in October 2004. The Partnership has the option to elect interest at (i) LIBOR plus a Euro-rate margin ranging from 1.25 percent to 1.75 percent, based on certain financial data or (ii) the greater of the prime rate or federal funds rate plus 0.5 percent. The Partnership Revolver allows for working capital draws of no more than $5.0 million and issuance of letters of credit, which are limited to $2 million. At December 31, 2002, letters of credit issued were $1.6 million. The financial covenants of the Partnership Revolver include, but are not limited to, maintaining: (i) a ratio of not more than 2.5:1.0 of total debt to consolidated EBITDA (as defined by the credit agreement) and (ii) a ratio of not less than 4.00:1.00 of consolidated EBITDA to interest. The Partnership is currently in compliance with all of its covenants.
PVR Term Loan
In conjunction with the PVR Revolver, the Partnership borrowed an additional $43.4 million in the form of a term loan. The term loan expires in October 2004. The Partnership has the option to elect interest at (i) LIBOR plus a Euro-rate margin 0.5 percent, based on certain financial data or (ii) the greater of the prime rate or federal funds rate plus 0.5 percent. The term loan was originally secured with U.S. Treasuries, but is currently unsecured, after the Treasuries were used to fund the Peabody Acquisition. The term loan is subject to the same covenants as the Revolver. The Partnership is currently in compliance with all of its covenants.
Line of Credit
The Company has
We have a $5 million line of credit with a financial institution due in December 2001,March 2003, renewable annually. The
Company hasWe have an option to elect either a fixed rate LIBOR loan, floating rate LIBOR loan or base rate (as determined by the financial institution) loan.
8. Accrued Liabilities
Accrued expenses are summarized as follows (in thousands):
Anticipated PVR Refinancing
The Partnership is currently attempting to refinance up to $90 million of its credit facility borrowings with more permanent debt. This refinancing is expected to be completed by March 31, 2003. If the refinancing is not completed by March 31, 2002, PVR will be required to provide security for all borrowings against its credit facility and term loan.
Page 58
12. Income Taxes
The provision for income taxes from continuing operations is comprised of the following (in thousands):
Year ended December 31, | |||||||||||
| 2002 |
|
| 2001 |
|
| 2000 | ||||
Current income taxes | |||||||||||
Federal | $ | (320 | ) | $ | 21,160 |
| $ | 10,463 | |||
State |
| (878 | ) |
| 42 |
|
| 2,496 | |||
Total current |
| (1,198 | ) |
| 21,202 |
|
| 12,959 | |||
Deferred income taxes | |||||||||||
Federal |
| 5,236 |
|
| (3,167 | ) |
| 6,951 | |||
State |
| 2,897 |
|
| 1,279 |
|
| 55 | |||
Total deferred |
| 8,133 |
|
| (1,888 | ) |
| 7,006 | |||
Total income tax expense | $ | 6,935 |
| $ | 19,314 |
| $ | 19,965 | |||
The difference between the taxes computed by applying the statutory tax rate to income from operations before income taxes and the Company'sour reported income tax expense is as follows (in thousands):
Year ended December 31, | |||||||||||||||||||||
2002 | 2001 | 2000 | |||||||||||||||||||
Computed at federal statutory tax rate | $ | 6,586 |
| 35.0 | % | $ | 18,777 |
| 35.0 | % | $ | 20,731 |
| 35.0 | % | ||||||
State income taxes, net of federal income tax benefit |
| 1,312 |
| 7.0 | % |
| 859 |
| 1.6 | % |
| 1,658 |
| 2.8 | % | ||||||
Dividends received deduction |
| — |
| — |
|
| (49 | ) | (0.1 | %) |
| (648 | ) | (1.1 | %) | ||||||
Non-conventional fuel source credit |
| (926 | ) | (4.9 | %) |
| (721 | ) | (1.3 | %) |
| (1,570 | ) | (2.7 | %) | ||||||
Other, net |
| (37 | ) | (0.2 | %) |
| 448 |
| 0.8 | % |
| (206 | ) | (0.3 | %) | ||||||
Total Income tax expense | $ | 6,935 |
| 36.9 | % | $ | 19,314 |
| 36.0 | % | $ | 19,965 |
| 33.7 | % | ||||||
The principal components of the Company'sour net deferred income tax liability isare as follows (in thousands):
December 31, | ||||||||
2002 | 2001 | |||||||
Deferred tax assets: | ||||||||
Pension and post-retirement benefits | $ | 1,826 |
| $ | 1,513 |
| ||
Deferred income – coal properties |
| 965 |
|
| 1,294 |
| ||
Alternative minimum tax credits |
| — |
|
| 439 |
| ||
Net operating loss carryforwards |
| 1,392 |
|
| 1,154 |
| ||
Other |
| 1,058 |
|
| 74 |
| ||
Total deferred tax assets |
| 5,241 |
|
| 4,474 |
| ||
Deferred tax liabilities: | ||||||||
Notes receivable |
| (668 | ) |
| (747 | ) | ||
Investments |
| — |
|
| — |
| ||
Oil and gas properties |
| (66,092 | ) |
| (56,675 | ) | ||
Other property and equipment |
| (635 | ) |
| (2,108 | ) | ||
Other |
| — |
|
| (805 | ) | ||
Total deferred tax liabilities |
| (67,395 | ) |
| (60,335 | ) | ||
Net deferred tax liability | $ | (62,154 | ) | $ | (55,861 | ) | ||
As of December 31, 2000, the Company had available2002, we have various net operating loss carryforwards for federal
incomestate tax purposes alternative minimum tax credits of approximately $2.3 million which can be carried forward
indefinitely as a credit. The Company has various state tax loss
carryforwards of $11.5$27.7 million which, if unused, will expire from 2009 to 2020.
10.Pension2022.
Page 59
13. Pension Plans and Other Post-retirement Benefits
The Company
We provide early retirement programs for eligible employees. Benefits are recorded based on the employee’s average annual compensation and its wholly-owned subsidiariesyearly services. We provided a noncontributory, defined benefit pension plan, which was frozen in 1996 and early retirement programs (the "Plans") for eligible
employees. Benefits were based on the employee's average annual
compensation and years of service.
The Company sponsorsterminated in 2001.
We also sponsor a defined benefit post-retirement plan that covers employees hired prior to January 1, 1991 who retire from active service. The plan provides medical benefits for the retirees and dependents and life insurance for the retirees. The medical coverage is noncontributory for retirees who retired prior to January 1, 1991 and may be contributory for retirees who retireretired after December 31, 1990.
A reconciliation of the changes in the benefit obligations and fair value of assets for the two years ended December 31, 20002002 and 19992001 and a statement of the funded status at December 31, 20002002 and 19992001 is as follows (in thousands):
Pension | Post-retirement Healthcare | |||||||||||||||
2002 | 2001 | 2002 | 2001 | |||||||||||||
Reconciliation of benefit obligation: | ||||||||||||||||
Obligation – beginning of year | $ | 2,375 |
| $ | 10,467 |
| $ | 3,468 |
| $ | 2,853 |
| ||||
Service cost |
| — |
|
| 43 |
|
| 10 |
|
| 11 |
| ||||
Interest cost |
| 164 |
|
| 744 |
|
| 311 |
|
| 251 |
| ||||
Benefits paid |
| (260 | ) |
| (1,754 | ) |
| (618 | ) |
| (577 | ) | ||||
Change in benefit assumption |
| — |
|
| — |
|
| 1,039 |
|
| — |
| ||||
Settlements |
| — |
|
| (7,879 | ) |
| — |
|
| — |
| ||||
Actuarial (gain) loss |
| 98 |
|
| 797 |
|
| 750 |
|
| 930 |
| ||||
Other |
| — |
|
| (43 | ) |
| — |
|
| — |
| ||||
Obligation – end of year |
| 2,377 |
|
| 2,375 |
|
| 4,960 |
|
| 3,468 |
| ||||
Reconciliation of fair value of plan assets: | ||||||||||||||||
Fair value – beginning of year |
| — |
|
| 9,941 |
|
| 518 |
|
| 975 |
| ||||
Actual return on plan assets |
| — |
|
| 368 |
|
| 5 |
|
| 138 |
| ||||
Settlements |
| (7,879 | ) |
| — |
|
| — |
| |||||||
Employer contributions |
| 260 |
|
| 259 |
|
| 96 |
|
| 10 |
| ||||
Participant contributions |
| — |
|
| 11 |
|
| 11 |
| |||||||
Benefit payments |
| (260 | ) |
| (1,754 | ) |
| (609 | ) |
| (588 | ) | ||||
Administrative expenses |
| — |
|
| (190 | ) |
| (21 | ) |
| (28 | ) | ||||
Transfer to 401 K |
| — |
|
| (186 | ) |
| — |
|
| — |
| ||||
Reversion to Penn Virginia |
| — |
|
| (559 | ) |
| — |
|
| — |
| ||||
Fair value – end of year |
| — |
|
| — |
|
| — |
|
| 518 |
| ||||
Funded status: | ||||||||||||||||
Funded status – end of year |
| (2,377 | ) |
| (2,375 | ) |
| (4,960 | ) |
| (2,950 | ) | ||||
Unrecognized transition obligation |
| 16 |
|
| 20 |
|
| — |
|
| — |
| ||||
Unrecognized prior service cost |
| 36 |
|
| 42 |
|
| 1,112 |
|
| 79 |
| ||||
Unrecognized (gain) loss |
| 491 |
|
| 405 |
|
| 1,559 |
|
| 930 |
| ||||
Net amount recognized | $ | (1,834 | ) | $ | (1,908 | ) | $ | (2,289 | ) | $ | (1,941 | ) | ||||
Page 60
The following table provides the amounts recognized in the statements of financial position at December 31, 20002002 and 19992001 (in thousands):
Pension | Post-retirement Healthcare | |||||||||||||||
2002 | 2001 | 2002 | 2001 | |||||||||||||
Accrued benefit liability | $ | (2,377 | ) | $ | (2,375 | ) | $ | (2,289 | ) | $ | (1,941 | ) | ||||
Other long-term assets |
| 52 |
|
| 62 |
|
| — |
|
| — |
| ||||
Accumulated other comprehensive income |
| 491 |
|
| 405 |
|
| — |
|
| — |
| ||||
Obligation – end of year | $ | (1,834 | ) | $ | (1,908 | ) | $ | (2,289 | ) | $ | (1,941 | ) | ||||
The following table provides the components of net periodic benefit cost for the plans for the two years ended December 31, 20002002 and 19992001 (in thousands):
Pension | Post-retirement Healthcare | ||||||||||||||
2002 | 2001 | 2002 | 2001 | ||||||||||||
Service cost | $ | — | $ | 43 |
| $ | 10 |
| $ | 11 |
| ||||
Interest cost |
| 164 |
| 745 |
|
| 311 |
|
| 251 |
| ||||
Expected return on plan assets |
| — |
| (901 | ) |
| (8 | ) |
| (23 | ) | ||||
Amortization of prior service cost |
| 6 |
| 6 |
|
| 119 |
|
| 6 |
| ||||
Amortization of transitional obligation |
| 3 |
| 3 |
|
| — |
|
| — |
| ||||
Recognized actuarial (gain) loss |
| 12 |
| 8 |
|
| — |
|
| 32 |
| ||||
Net periodic benefit cost | $ | 185 | $ | (96 | ) | $ | 432 |
| $ | 277 |
| ||||
The assumptions used in the measurement of the Company'sour benefit obligation were as follows:
Pension | Post-retirement Healthcare | |||||||||||
2002 | 2001 | 2002 | 2001 | |||||||||
Discount rate | 6.75 | % | 7.25 | % | 6.75 | % | 7.25 | % | ||||
Expected return on plan assets | — |
| 9.50 |
| — |
| 3.00 |
| ||||
For measurement purposes, a 7.59.5 percent annual rate increase in the per capita cost of covered health care benefits was assumed for 2000.2002. The rate is assumed to decrease gradually to 5.55.0 percent for 20042011 and remain at that level thereafter.
Assumed health care cost trend rates have a significant effect on the amounts reported for post-retirement benefits. A one percent change in assumed health care cost trend rates would have the following effects for 20002002 (in thousands):
One percent Increase | One percent Decrease | ||||||
Effect on total of service and interest cost components | $ | 14 | $ | (12 | ) | ||
Effect on post-retirement benefit obligation |
| 157 |
| (144 | ) | ||
Page 61
14. Other Liabilities
Other liabilities are summarized in the following table (in thousands):
December 31, | ||||||
2002 | 2001 | |||||
Reclamation/environmental liabilities | $ | 5,349 | $ | 1,154 | ||
Post-retirement health care |
| 2,129 |
| 1,781 | ||
Deferred income |
| 2,488 |
| 3,658 | ||
Pension |
| 2,237 |
| 2,234 | ||
Other |
| 471 |
| 50 | ||
Total | $ | 12,674 | $ | 8,877 | ||
15. Discontinued Operations
During the second quarter of 2002, we sold certain oil and gas properties, which included various interests in south Texas properties acquired in the third quarter of 2001. The operations of these properties were insignificant in 2001. The net carrying amount of properties sold was approximately $0.5 million. Accordingly, under the provisions of SFAS No. 144 the components of discontinued operations were as follows for the year ended December 31, 2002 (in thousands)
Production | ||||
Oil and condensate (Mbbls) |
| 16 |
| |
Natural gas (MMcf) |
| 18 |
| |
Total production (MMcfe) |
| 114 |
| |
Revenues | ||||
Natural gas | $ | 48 |
| |
Oil and condensate |
| 332 |
| |
Total revenues |
| 380 |
| |
Expenses | ||||
Operating expenses |
| 352 |
| |
Depreciation, depletion and amortization |
| 25 |
| |
Total expenses |
| 377 |
| |
Income from discontinued operations |
| 3 |
| |
Gain on sale of properties |
| 337 |
| |
| 340 |
| ||
Income taxes |
| (119 | ) | |
Net income from discontinued operations | $ | 221 |
| |
Page 62
16. Earnings Per Share
The following is a reconciliation of the numerators and denominators used in the calculation of basic and diluted earnings per share ("EPS"(“EPS”) for net income for the three years ended December 31, 20002002 (in thousands, except per share data.)
2002 | 2001 | 2000 | |||||||
Income from continuing operations | $ | 11,883 | $ | 34,337 | $ | 39,265 | |||
Income from discontinued operations |
| 221 |
| — |
| — | |||
Net income | $ | 12,104 | $ | 34,337 | $ | 39,265 | |||
Weighted average shares, basic |
| 8,930 |
| 8,770 |
| 8,241 | |||
Effect of dilutive securities: | |||||||||
Stock options |
| 44 |
| 126 |
| 130 | |||
Weighted average shares, diluted |
| 8,974 |
| 8,896 |
| 8,371 | |||
Income from continuing operations per share, basic | $ | 1.33 | $ | 3.92 | $ | 4.76 | |||
Income from discontinued operations per share, basic |
| 0.02 |
| — |
| — | |||
Net income per share, basic | $ | 1.35 | $ | 3.92 | $ | 4.76 | |||
Income from continuing operations per share, diluted | $ | 1.32 | $ | 3.86 | $ | 4.69 | |||
Income from discontinued operations per share, diluted |
| 0.02 |
| — |
| — | |||
Net income per share, diluted | $ | 1.34 | $ | 3.86 | $ | 4.69 | |||
Page 63
17. Stock Compensation and Stock Ownership Plans
Plans`
Stock OptionCompensation Plans
The Company has
We have several stock optioncompensation plans (collectively known as the "Stock Option Plans"“Stock Compensation Plans”) whichthat allow, among other grants, incentive and nonqualified stock options to be granted to key employees and officers of the Company and nonqualified stock options to be granted to directors of the Company.directors. Options granted under the Stock OptionCompensation Plans may be exercised at any time after one year and prior to ten years following the grant, subject to special rules that apply in the event of death, retirement and/or termination of the employment of an optionee. The exercise price of all options granted under the Stock OptionCompensation Plans is at the fair market value of the Company'sCompany’s stock on the date of the grant. At December 31, 2002 there were approximately 134,000 and 416,000 shares available for issuance to directors and employees, respectively, pursuant to the Stock Compensation Plans.
The following table summarizes information with respect to the common stock options awarded under the Stock Option Plans and grants described above.
2002 | 2001 | 2000 | |||||||||||||
Shares Under Options | Weighted Avg. Exercise Price | Shares Under Options | Weighted Avg Exercise Price | Shares Under Options | Weighted Avg Exercise Price | ||||||||||
Outstanding at beginning of year | 359,450 | $ | 25.97 | 725,403 | $ | 19.38 | 1,014,500 | $ | 18.74 | ||||||
Granted | 113,400 | $ | 36.91 | 160,100 | $ | 32.02 | 46,300 | $ | 16.65 | ||||||
Exercised | 57,000 | $ | 24.45 | 526,053 | $ | 23.35 | 326,397 | $ | 17.13 | ||||||
Cancelled | 12,000 | $ | 21.38 | — |
| — | 9,000 | $ | 18.99 | ||||||
Outstanding at end of year | 403,850 | $ | 29.39 | 359,450 | $ | 25.97 | 725,403 | $ | 19.38 | ||||||
Weighted average of fair value of options granted during the year | $ | 10.17 | $ | 10.55 | $ | 5.02 | |||||||||
The following table summarizes certain information regarding
stockfair value of the options outstanding at December 31, 2000:
The fair value method pursuantof the options granted during 2001 is estimated on the date of grant using the Black-Scholes option-pricing model with the following assumptions: a) dividend yield of 2.71 percent to SFAS No. 123
"Accounting for Stock-Based Compensation", the Company's pro
forma net income2.92 percent, b) expected volatility of 32.3 percent, c) risk-free interest rate of 5.1 percent and earnings per share would have been as
follows:
The fair value of the options granted during 2000 is estimated on the date of grant using the Black-Scholes option-pricing model with the following assumptions: a) dividend yield of 5.2 percent to 5.4 percent, b) expected volatility of 37.0 percent, c) risk-
freerisk-free interest rate of 6.9 percent to 7.0 percent and d) expected life of eight years.
The fair value of thefollowing table summarizes certain information regarding stock options granted during 1999 is estimated
on the date of grant using the Black-Scholes option-pricing model
with the following assumptions: a) dividend yield of 4.4 percent
to 4.6 percent, b) expected volatility of 38.6 percent, c) risk-
free interest rate of 4.8 percent to 4.9 percent and d) expected
life of eight years.
The fair value of the options granted during 1998 is estimated
on the date of grant using the Black-Scholes option-pricing model
with the following assumptions: a) dividend yield of 3.4 percent
to 4.2 percent, b) expected volatility of 37.7 percent to 38.8
percent, c) risk-free interest rate of 4.7 percent to 5.7 percent
and d) expected life of eight years.
The effects of applying SFAS No. 123 in this pro forma
disclosure are not indicative of future amounts.
Employees'outstanding at December 31, 2002:
Options Outstanding | Options Exercisable | |||||||||
Range of Exercise Price | Number Outstanding at 12/31/02 | Weighted Avg. Remaining Contractual Life | Weighted Avg. Exercise Price | Number Exercisable at 12/31/02 | Weighted Avg. Exercise Price | |||||
$15 to $19 | 44,800 | 5.9 | $17.76 | 44,800 | $17.76 | |||||
$20 to $24 | 88,500 | 4.9 | $21.87 | 88,500 | $21.87 | |||||
$25 to $29 | 23,050 | 6.0 | $27.09 | 23,050 | $27.09 | |||||
$30 to $34 | 145,300 | 8.8 | $32.43 | 134,100 | $32.27 | |||||
$35 to $39 | 102,200 | 9.4 | $37.19 | — | $ — | |||||
Page 64
Employees’ Stock Ownership Plan
In 1996, the Board of Directors extended the Employees'Employees’ Stock Ownership Plan ("ESOP"(“ESOP”). All employees with one year of service are participants. The ESOP is designed to enable employees of the
Company to accumulate stock ownership. While there are no employee contributions, participants receive an allocation of stock which has been contributed by the Company. Compensation costs are reported when such shares are released to employees. The ESOP borrowed $2.0 million from the Company in 1996 and used the proceeds to purchase treasury stock. Under the terms of the ESOP, the Companywe will make annual contributions over a 10-year period. At December 31, 2000,2002, the unearned portion of the ESOP of approximately ($1.10.3 million) was recordedis reported as a contra-equity
accountcomponent of Shareholders’ Equity entitled "Unearned“Unearned Compensation-ESOP."
”
Shareholder Rights Plan
In February 1998, the Board of Directors adopted a Shareholder Rights Plan (the “Plan”) designed to prevent an acquirer from gaining control of the Company without offering a fair price to all shareholders. The Plan was amended in March 2002. Each Rightright entitles the holder to purchase from the Company one one-thousandth of a share of Series A Junior Participating Preferred Stock, $100 par value, at a price of $100 subject to adjustment. The Rightsrights are not exercisable or transferable apart from the common stock until ten days after a person or affiliated group has acquired or obtained the right to acquire fifteen percent or more or makes a tender
offer for fifteen(or ten percent or more if such person or group has been deemed to an “adverse person” as defined in the Plan), of the Company'sour common stock. Each Rightright will entitle the holder, under certain circumstances,
(such as a merger, acquisition of fifteen percent or more of
common stock of the Company by the acquiring person or sale of
fifty percent or more of the Company's assets or earning power), to acquire at half the value, either common stock of the Company, a combination of cash, other property, or common stock or other securities of the Company, or common stock of thean acquiring person. Any such event would also result in any Rightsrights owned beneficially by the acquiring person or its affiliates becoming null and void. The Rightsrights expire in February 2008 and are redeemable at any time until ten days following the time an
acquiring person acquires fifteen percent or moreunder certain circumstances.
Restricted Units
The general partner granted 37,500 restricted units to directors and officers of the Company'sgeneral partner in 2002. A restricted unit entitles the grantee to receive a common stockunit upon the vesting of the restricted unit. Restricted units vest upon terms established by the Partnership Compensation Committee, but in no case earlier than the conversion to common units of the Partnership’s outstanding subordinated units. In addition, the restricted units will vest upon a change of control of the general partner or the Company. If a grantee’s employment with or membership on the Partnership’s Board of Directors of the general partner terminates for any reason, the grantee’s restricted units will be automatically forfeited unless, and to the extent, the compensation committee provides otherwise. Common units to be delivered upon the vesting of restricted units may be common units acquired by the general partner in the open market, common units already owned by the general partner, common units acquired by the general partner directly from the Partnership or any other person or any combination of the foregoing. The general partner will be entitled to reimbursement by the Partnership for the cost incurred in acquiring such common units. Distributions payable with respect to restricted units may, at $0.001 per Right.
14.the Partnership’s Compensation Committee’s request, be paid directly to the grantee or held by the Partnership and made subject to a risk of forfeiture during the applicable restriction period.
The following table summarizes information with respect to restricted units awarded by the general partner.
2002 | |||||
Restricted Units | Fair Value | ||||
Outstanding at beginning of year | — | $ | — | ||
Granted | 37,500 | $ | 24.50 | ||
Vested | 4,000 | $ | 24.50 | ||
Forfeited | — |
| — | ||
Outstanding at end of year | 33,500 | $ | 24.50 | ||
Page 65
18. Accumulated Other Comprehensive Income
Comprehensive income represents certain changes in equity during the reporting period, including net income and other comprehensive income, which includes, but is not limited to, unrealized gains from marketable securities, price risk management assets and minimum pension liability adjustments. Reclassification adjustments represent gains or losses from investments realized in net income for each respective year. For the three years ended December 31, 2000,2002, the components of accumulated other comprehensive income are as follows (in thousands):
Net unrealized holding gain – Investments | Price risk management assets | Minimum pension liability | Accumulated other comprehensive income | |||||||||||||
Balance at December 31, 1999 | $ | 42,235 |
| $ | — |
| $ | (218 | ) | $ | 42,017 |
| ||||
Unrealized holding loss, net of tax of $8,308 |
| (15,429 | ) |
| — |
|
| — |
|
| (15,429 | ) | ||||
Pension plan adjustment, net of tax of $10 |
| — |
|
| — |
|
| 18 |
|
| 18 |
| ||||
Balance at December 31, 2000 |
| 26,806 |
|
| — |
|
| (200 | ) |
| 26,606 |
| ||||
Investment holding gain, net of tax of $1,383 |
| 8,741 |
|
| — |
|
| — |
|
| 8,741 |
| ||||
Investment reclassification adjustment, net of tax of $19,140 |
| (35,547 | ) |
| — |
|
| — |
|
| (35,547 | ) | ||||
Price risk management unrealized gain, net of tax of $1,940 |
| — |
|
| 3,603 |
|
| — |
|
| 3,603 |
| ||||
Price risk management reclassification adjustment, net of tax of $853 |
| — |
|
| (1,584 | ) |
| — |
|
| (1,584 | ) | ||||
Pension plan adjustment, net of tax of $34 |
| — |
|
| — |
|
| (63 | ) |
| (63 | ) | ||||
Balance at December 31, 2001 |
| — |
|
| 2,019 |
|
| (263 | ) |
| 1,756 |
| ||||
Price risk management unrealized loss, net of tax of $2,160 |
| — |
|
| (4,012 | ) |
| — |
|
| (4,012 | ) | ||||
Price risk management reclassification adjustment, net of tax of $350 |
| — |
|
| 651 |
|
| — |
|
| 651 |
| ||||
Pension plan adjustment, net of tax of $30 |
| — |
|
| — |
|
| (56 | ) |
| (56 | ) | ||||
Balance at December 31, 2002 | $ | — |
| $ | (1,342 | ) | $ | (319 | ) | $ | (1,661 | ) | ||||
Page 66
19. Segment Information
Penn Virginia's
Segment information has been prepared in accordance with SFAS No. 131Disclosure 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 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 its coal royalty and land management operations. Accordingly, our reportable segments are classified into two operating segments:
as follows:
Oil and Gas -– crude oil and natural gas exploration,development and production.
Coal Royalty and Land Management -– the leasing of mineral rights and subsequent collection of royalties and the development and harvesting of timber.
All Other – primarily represents corporate functions.
Oil and Gas | Coal Royalty and Land Management | All Other | Consolidated | ||||||||||||
(in thousands) | |||||||||||||||
December 31, 2002 | |||||||||||||||
Revenues | $ | 71,512 |
| $ | 38,608 | $ | 837 |
| $ | 110,957 |
| ||||
Operating costs and expenses |
| 30,801 |
|
| 10,226 |
| 7,704 |
|
| 48,731 |
| ||||
Depreciation, depletion and amortization |
| 26,336 |
|
| 3,955 |
| 348 |
|
| 30,639 |
| ||||
Impairment of oil and gas properties |
| 796 |
|
| — |
| — |
|
| 796 |
| ||||
Operating income (loss) | $ | 13,579 |
| $ | 24,427 | $ | (7,215 | ) |
| 30,791 |
| ||||
Interest expense |
| (2,116 | ) | ||||||||||||
Interest income |
| 2,038 |
| ||||||||||||
Other |
| 1 |
| ||||||||||||
Income before minority interest and taxes | $ | 30,714 |
| ||||||||||||
Total assets | $ | 314,284 |
| $ | 266,576 | $ | 5,432 |
| $ | 586,292 |
| ||||
Capital expenditures | $ | 51,581 |
| $ | 92,817 | $ | 343 |
| $ | 144,741 |
| ||||
December 31, 2001 | |||||||||||||||
Revenues | $ | 57,778 |
| $ | 37,513 | $ | 1,280 |
| $ | 96,571 |
| ||||
Operating costs and expenses |
| 26,914 |
|
| 9,271 |
| 5,661 |
|
| 41,846 |
| ||||
Depreciation, depletion and amortization |
| 16,418 |
|
| 3,084 |
| 77 |
|
| 19,579 |
| ||||
Impairment of oil and gas properties |
| 33,583 |
|
| — |
| — |
|
| 33,583 |
| ||||
Operating income (loss) | $ | (19,137 | ) | $ | 25,158 | $ | (4,458 | ) |
| 1,563 |
| ||||
Gain on sale of securities |
| 54,688 |
| ||||||||||||
Interest expense |
| (2,453 | ) | ||||||||||||
Interest income |
| 1,602 |
| ||||||||||||
Other |
| 14 |
| ||||||||||||
Income before minority interest and taxes | $ | 55,414 |
| ||||||||||||
Total assets | $ | 289,379 |
| $ | 162,638 | $ | 5,085 |
| $ | 457,102 |
| ||||
Capital expenditures | $ | 161,295 |
| $ | 33,669 | $ | 1,074 |
| $ | 196,038 |
| ||||
December 31, 2000 | |||||||||||||||
Revenues | $ | 71,405 |
| $ | 30,189 | $ | 4,404 |
| $ | 105,998 |
| ||||
Operating costs and expenses |
| 15,107 |
|
| 8,327 |
| 4,853 |
|
| 28,287 |
| ||||
Depreciation, depletion and amortization |
| 9,883 |
|
| 2,047 |
| 97 |
|
| 12,027 |
| ||||
Operating income (loss) | $ | 46,415 |
| $ | 19,815 | $ | (546 | ) |
| 65,684 |
| ||||
Interest expense |
| (7,926 | ) | ||||||||||||
Interest income |
| 1,458 |
| ||||||||||||
Other |
| 14 |
| ||||||||||||
Income before taxes | $ | 59,230 |
| ||||||||||||
Total assets | $ | 142,613 |
| $ | 79,803 | $ | 46,350 |
| $ | 268,766 |
| ||||
Capital expenditures | $ | 58,677 |
| $ | 485 | $ | 281 |
| $ | 59,443 |
| ||||
Page 67
Operating loss for the oil and gasOil Gas segment in 2001 includes a $33.6 million impairment on properties see Note 9 (Impairment of Oil and Gas Properties). Operating income for 2000 includeincludes a $23.9 million gain on asale of property sale.
of $23.9 million.
Operating income is total revenue less operating expenses. Operating income does not include certain other income items, gain (loss) on sale of securities, unallocated general corporate
expenses, interest expense, minority interest and income taxes. Identifiable assets
are those assets used in the Company's operations in each
segment. Corporate assets are principally cash and marketable
securities.
For the year ended December 31, 2000,2002, two customers of the oil and gas segment accounted for $13.6$29.4 million, or 1326 percent, and $10.5$17.7 million, or 1016 percent, respectively, of the Company'sour consolidated net revenues. For the year ended December 31, 1999,2001, two customers of the oil and gas segment accounted for $9.6$20.8 million, or 2022 percent, and $6.9$11.4 million, or 1312 percent, respectively, of the Company'sour consolidated net revenues.
16.
20. Commitments and Contingencies
Rental Commitments
Minimum rental commitments under all non-cancelable operating leases, primarily real estate, in effect at December 31, 20002002 were as follows (in thousands):
Year ending December 31,
2001 $ 454
2002 420
2003 346
2004 246
2005 77
Total minimum payments $ 1,543
Year ending December 31, | |||
2003 | $ | 2,855 | |
2004 |
| 1,729 | |
2005 |
| 1,508 | |
2006 |
| 1,388 | |
2007 |
| 601 | |
Total minimum payments | $ | 8,081 | |
Legal
The Company is
We are involved, from time to time, in various legal proceedings arising in the ordinary course of business. While the ultimate results of these proceedings cannot be predicted with certainty, Company management believes these claims will not have a material effect on the Company's financial position, liquidity or operations.
17.
Environmental Compliance
Extensive federal, state and local laws govern oil and natural gas operations, regulate the discharge of materials into the environment or otherwise relate to the protection of the environment. Numerous governmental departments issue rules and regulations to implement and enforce such laws that are often difficult and costly to comply with and which carry substantial administrative, civil and even criminal penalties for failure to comply. Some laws, rules and regulations relating to protection of the environment may, in certain circumstances, impose “strict liability” for environmental contamination, rendering a person liable for environmental and natural resource damages and cleanup costs without regard to negligence or fault on the part of such person. Other laws, rules and regulations may restrict the rate of oil and natural gas production below the rate that would otherwise exist or even prohibit exploration or production activities in sensitive areas. In addition, state laws often require some form of remedial action to prevent pollution from former operations, such as closure of inactive pits and plugging of abandoned wells. The regulatory burden on the oil and natural gas industry increases its cost of doing business and consequently affects its profitability. These laws, rules and regulations affect our
Page 68
operations, as well as the oil and gas exploration and production industry in general. We believe that we are in substantial compliance with current applicable environmental laws, rules and regulations and that continued compliance with existing requirements will not have a material adverse impact on us. Nevertheless, changes in existing environmental laws or the adoption of new environmental laws have the potential to adversely affect our operations.
The operations of the Partnership’s lessees are subject to environmental laws and regulations adopted by various governmental authorities in the jurisdictions in which these operations are conducted. The terms of the Partnership’s coal property leases impose liability for all environmental and reclamation liabilities arising under those laws and regulations on the relevant lessees. The lessees are bonded and have indemnified the Partnership against any and all future environmental liabilities. The Partnership regularly visits the coal property leases to monitor its lessee’s compliance with environmental laws and regulations, as well as to review mining activities. Management believes that the Partnership’s lessees will be able to comply with existing regulations and does not expect any material impact on its financial condition or results of operations as a result of environmental regulations.
With respect to its unleased and inactive properties, the Partnership has some reclamation bonding requirements. In conjunction with the November 2002 purchase of equipment at the Fork Creek property, the Partnership assumed reclamation and mitigation liabilities of approximately $3.0 million. The Partnership is currently pursuing a potential lessee for this property and, as is customary in its operations, the Partnership intends to assign all reclamation liabilities to such lessee. As of December 31, 2002 and 2001, the Partnership’s environmental liabilities totaled $4.6 million and zero, respectively.
21. Quarterly Financial Information (Unaudited)
Summarized Quarterly Financial Data:
2002 Quarters Ended | 2001 Quarters Ended | ||||||||||||||||||||||||
Mar. 31 | June 30 | Sept. 30 | Dec. 31 | Mar. 31 | June 30(a) | Sept. 30 | Dec. 31(b) | ||||||||||||||||||
(in thousands, except share data) | |||||||||||||||||||||||||
Revenues | $ | 24,383 | $ | 25,648 | $ | 28,754 | $ | 32,172 | $ | 27,121 | $ | 24,741 | $ | 24,031 | $ | 20,678 |
| ||||||||
Operating | |||||||||||||||||||||||||
Income (loss) (c) | $ | 8,778 | $ | 7,076 | $ | 7,949 | $ | 6,988 | $ | 16,958 | $ | 13,461 | $ | 6,841 | $ | (35,697 | ) | ||||||||
Net income | $ | 3,370 | $ | 3,163 | $ | 3,208 | $ | 2,363 | $ | 10,710 | $ | 43,018 | $ | 4,247 | $ | (23,638 | ) | ||||||||
Net income from continuing operations per share (d) | |||||||||||||||||||||||||
Basic | $ | 0.38 | $ | 0.33 | $ | 0.36 | $ | 0.26 | $ | 1.25 | $ | 4.88 | $ | 0.48 | $ | (2.66 | ) | ||||||||
Diluted | $ | 0.37 | $ | 0.33 | $ | 0.36 | $ | 0.26 | $ | 1.22 | $ | 4.79 | $ | 0.47 | $ | (2.63 | ) | ||||||||
Net income from per share (d) | |||||||||||||||||||||||||
Basic | $ | 0.38 | $ | 0.35 | $ | 0.36 | $ | 0.26 | $ | 1.25 | $ | 4.88 | $ | 0.48 | $ | (2.66 | ) | ||||||||
Diluted | $ | 0.37 | $ | 0.35 | $ | 0.36 | $ | 0.26 | $ | 1.22 | $ | 4.79 | $ | 0.47 | $ | (2.63 | ) | ||||||||
Weighted average shares outstanding: | |||||||||||||||||||||||||
Basic |
| 8,909 |
| 8,927 |
| 8,944 |
| 8,945 |
| 8,549 |
| 8,820 |
| 8,869 |
| 8,890 |
| ||||||||
Diluted |
| 9,007 |
| 8,984 |
| 8,982 |
| 8,984 |
| 8,755 |
| 8,982 |
| 9,007 |
| 8,989 |
| ||||||||
| (a) | Net income for the second quarter of 2001 included a $54.7 million ($35.6 million after tax) gain on the sale of Norfolk Southern Corporation Common Stock. |
| (b) | Operating loss for the fourth quarter of 2001 included a $33.6 million impairment on oil and gas properties. |
| (c) | Certain reclassifications have been made to conform to the current year presentation. |
| (d) | The sum of the quarters may not equal the total of the respective year’s net income per share due to changes in the weighted average shares outstanding throughout the year. |
Page 69
22. Supplementary Information on Oil and Gas Producing Activities (Unaudited)
The following supplementary information regarding the oil and gas producing activities of Penn Virginia is presented in accordance with the requirements of the Securities and Exchange Commission (SEC) and SFAS No. 69 "Disclosures“Disclosures about Oil and Gas Producing Activities"Activities”. The amounts shown include Penn Virginia'sour net working and royalty interestsinterest in all of itsour oil and gas operations.
Capitalized Costs Relating to Oil and Gas Producing Activities Year Ended December 31,
2000 1999 1998
(in thousands)
Proved properties $64,107 $41,084 $35,842
Unproved properties 2,425 3,959 1,408
Wells, equipment and facilities 105,283 137,176 117,688
Support equipment 2,689 2,829 2,620
174,504 185,048 157,558
Accumulated depreciation and depletion (43,720) (69,495) (62,545)
Net capitalized costs $ 130,784 $ 115,553 $ 95,013
Year Ended December 31, | ||||||||||||
2002 | 2001 | 2000 | ||||||||||
(in thousands) | ||||||||||||
Proved properties | $ | 73,606 |
| $ | 75,152 |
| $ | 64,107 |
| |||
Unproved properties |
| 57,575 |
|
| 57,813 |
|
| 2,425 |
| |||
Wells, equipment and facilities |
| 248,746 |
|
| 199,670 |
|
| 105,283 |
| |||
Support equipment |
| 3,433 |
|
| 2,859 |
|
| 2,689 |
| |||
| 383,360 |
|
| 335,494 |
|
| 174,504 |
| ||||
Accumulated depreciation and depletion |
| (86,586 | ) |
| (60,073 | ) |
| (43,720 | ) | |||
Net capitalized costs | $ | 296,774 |
| $ | 275,421 |
| $ | 130,784 |
| |||
Costs Incurred in Certain Oil and Gas Activities
Year Ended December 31,
2000 1999 1998
(in thousands)
Proved property acquisition costs $35,999 $14,069 $3,351
Unproved property acquisition costs 917 2,551 206
Exploration costs 5,125 3,171 2,022
Development costs and other 18,561 9,398 8,698
Total costs incurred $ 60,602 $29,189 $14,277
Year Ended December 31, | |||||||||
2002 | 2001 | 2000 | |||||||
(in thousands) | |||||||||
Proved property acquisition costs | $ | 517 | $ | 97,143 | $ | 35,999 | |||
Unproved property acquisition costs |
| 6,829 |
| 64,488 |
| 917 | |||
Exploration costs |
| 7,843 |
| 13,814 |
| 5,125 | |||
Development costs and other |
| 41,750 |
| 31,545 |
| 18,561 | |||
Total costs incurred | $ | 56,939 | $ | 206,990 | $ | 60,602 | |||
Costs for the year ended December 31, 2001, include deferred income taxes of $45.3 million provided for the book versus tax basis difference related to the acquired Synergy Oil and Gas properties, $27.2 million of which is included in proved property acquisition costs and $18.1 million is included in unproved property acquisition costs.
Results of Operations for Oil and Gas Producing Activities
The following schedule includes results solely from the production and sale of oil and gas and a noncashnon-cash charge for property impairments. It excludes corporate related general and administrative expenses and gains or losses on property dispositions. The income tax expense is calculated by applying the statutory tax rates to the revenues after deducting costs, which include depletion allowances and giving effect to oil and gas related permanent differences and tax credits.
Year Ended December 31, | ||||||||||
2002 | 2001 | 2000 | ||||||||
(in thousands) | ||||||||||
Revenues | $ | 71,178 | $ | 57,024 |
| $ | 46,851 | |||
Production expenses |
| 15,390 |
| 10,069 |
|
| 7,226 | |||
Exploration expenses |
| 7,614 |
| 11,514 |
|
| 5,080 | |||
Depreciation and depletion expense |
| 26,361 |
| 16,418 |
|
| 9,883 | |||
Impairment of oil and gas properties |
| 796 |
| 33,583 |
|
| — | |||
| 21,017 |
| (14,560 | ) |
| 24,662 | ||||
Income tax expense (benefit) |
| 6,566 |
| (5,817 | ) |
| 8,309 | |||
Results of operations | $ | 14,451 | $ | (8,743 | ) | $ | 16,353 | |||
Page 70
Oil and Gas Reserves
The following schedule presents the estimated oil and gas reserves owned by Penn Virginia.us. This information includes Penn
Virginia'sour royalty and net working interest share of the reserves in oil and gas properties. Net proved oil and gas reserves for the three years ended December 31, 20002002, were estimated by Wright and Company, Inc. All reserves are located in the United States.
There are many uncertainties inherent in estimating proved reserve quantities, and projecting future production rates and the timing of future development expenditures. In addition, reserve estimates of new discoveries are more imprecise than those of properties with a production history. Accordingly, these estimates are subject to change as additional information becomes available. Proved oil and gas 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 at the end of the respective years. Proved developed oil and gas reserves are those reserves expected to be recovered through existing equipment and operating methods.
Net quantities of proved reserves and proved developed reserves during the periods indicated are set forth in the tables below:
Proved Developed and Undeveloped Reserves
Oil and Condensate (MBbls) | Natural Gas (MMcf) | MMcfe | |||||||
December 31, 1999 | 359 |
| 185,198 |
| 187,352 |
| |||
Revisions of previous estimates | 107 |
| (1,893 | ) | (1,251 | ) | |||
Extensions, discoveries and other additions | 19 |
| 30,987 |
| 31,101 |
| |||
Production | (31 | ) | (11,645 | ) | (11,831 | ) | |||
Purchase of reserves | 11 |
| 35,879 |
| 35,945 |
| |||
Sale of reserves in place | (394 | ) | (64,279 | ) | (66,643 | ) | |||
December 31, 2000 | 71 |
| 174,247 |
| �� | 174,673 |
| ||
Revisions of previous estimates | (438 | ) | (5,697 | ) | (8,325 | ) | |||
Extensions, discoveries and other additions | 90 |
| 41,395 |
| 41,935 |
| |||
Production | (164 | ) | (13,130 | ) | (14,114 | ) | |||
Purchase of reserves | 4,361 |
| 33,402 |
| 59,568 |
| |||
Sale of reserves in place | — |
| (964 | ) | (964 | ) | |||
December 31, 2001 | 3,920 |
| 229,253 |
| 252,773 |
| |||
Revisions of previous estimates | — |
| (3,339 | ) | (3,339 | ) | |||
Extensions, discoveries and other additions | 1,944 |
| 33,197 |
| 44,861 |
| |||
Production | (364 | ) | (18,715 | ) | (20,899 | ) | |||
Purchase of reserves | 29 |
| 1,071 |
| 1,245 |
| |||
Sale of reserves in place | (168 | ) | (212 | ) | (1,220 | ) | |||
December 31, 2002 | 5,361 |
| 241,255 |
| 273,421 |
| |||
Proved Developed Reserves: | |||||||||
December 31, 2000 | 71 |
| 145,930 |
| 146,356 |
| |||
December 31, 2001 | 2,212 |
| 183,134 |
| 196,406 |
| |||
December 31, 2002 | 2,943 |
| 198,733 |
| 216,391 |
| |||
The following table sets forth the standardized measure of the discounted future net cash flows attributable to the Company'sour proved oil and gas reserves. Future cash inflows were computed by applying year-end prices of oil and gas to the estimated future production of proved oil and gas reserves. Natural gas prices were escalated only where existing contracts contained fixed and determinable escalation clauses. Contractually provided natural gas prices in excess of estimated market clearing prices were used in computing the future cash inflows only if the Company
expectswe expect to continue to receive higher prices under legally enforceable contract terms. Future prices actually received may materially differ from current prices or the prices used in the standardized measure.
Future production and development costs represent the estimated future expenditures (based on current costs) to be incurred in developing and producing the proved reserves, assuming continuation of existing economic conditions. Future income tax expenses were computed by applying statutory income tax rates to the difference between pre-tax net cash flows relating to the
Company'sour proved oil and gas reserves and the tax basis of proved oil and gas properties. In addition, the effects of statutory depletion in excess of tax basis,
Page 71
available net operating loss carryforwards and alternative minimum tax credits were used in computing future income tax expense. The resulting annual net cash inflows were then discounted using a 10 percent annual rate.
Year Ended December 31, | |||||||||
2002 | 2001 | 2000 | |||||||
(in thousands) | |||||||||
Future cash inflows | $ | 1,372,935 | $ | 722,203 | $ | 1,727,923 | |||
Future production costs |
| 263,705 |
| 178,533 |
| 205,385 | |||
Future development costs |
| 51,151 |
| 39,145 |
| 19,981 | |||
Future net cash flows before income tax |
| 1,058,079 |
| 504,525 |
| 1,502,557 | |||
Future income tax expense |
| 285,633 |
| 127,277 |
| 422,485 | |||
Future net cash flows |
| 772,446 |
| 377,248 |
| 1,080,072 | |||
10% annual discount for estimated timing of cash flows |
| 417,523 |
| 188,305 |
| 612,679 | |||
Standardized measure of discounted future net cash flows | $ | 354,923 | $ | 188,943 | $ | 467,393 | |||
Changes in Standardized Measure of Discounted Future Net Cash Flows
Year Ended December 31,
2000 1999 1998
(in thousands)
Sales of oil and gas,
net of production costs $(39,754) $(16,755) $(16,071)
Net changes in prices and production costs 313,355 32,111 (57,646)
Extensions, discoveries & other additions 123,223 4,090 4,906
Development costs incurred during the period 16,001 5,330 5,289
Revisions of previous quantity estimates (4,604) 1,709 (6,735)
Purchase of minerals-in-place 121,979 20,438 2,896
Sale of minerals-in-place (41,456) - (26)
Accretion of discount 13,628 8,116 14,059
Net change in income taxes (159,220) (11,526) 12,006
Other changes 4,978 86 (2,109)
Net increase (decrease) 348,130 43,599 (43,431)
Beginning of year 119,263 75,664 119,095
End of year $ 467,393 $ 119,263 75,664
Year Ended December 31, | ||||||||||||
2002 | 2001 | 2000 | ||||||||||
(in thousands) | ||||||||||||
Sales of oil and gas, net of production costs | $ | (55,788 | ) | $ | (47,191 | ) | $ | (39,754 | ) | |||
Net changes in prices and production costs |
| 203,588 |
|
| (483,009 | ) |
| 313,355 |
| |||
Extensions, discoveries and other additions |
| 82,808 |
|
| 37,907 |
|
| 123,223 |
| |||
Development costs incurred during the period |
| 16,393 |
|
| 13,771 |
|
| 16,001 |
| |||
Revisions of previous quantity estimates |
| (6,513 | ) |
| (7,710 | ) |
| (4,604 | ) | |||
Purchase of minerals-in-place |
| 2,901 |
|
| 70,294 |
|
| 121,979 |
| |||
Sale of minerals-in-place |
| (328 | ) |
| (906 | ) |
| (41,456 | ) | |||
Accretion of discount |
| 24,254 |
|
| 64,363 |
|
| 13,628 |
| |||
Net change in income taxes |
| (72,614 | ) |
| 122,636 |
|
| (159,220 | ) | |||
Other changes |
| (28,721 | ) |
| (48,605 | ) |
| 4,978 |
| |||
Net increase (decrease) |
| 165,980 |
|
| (278,450 | ) |
| 348,130 |
| |||
Beginning of year |
| 188,943 |
|
| 467,393 |
|
| 119,263 |
| |||
End of year | $ | 354,923 |
| $ | 188,943 |
| $ | 467,393 |
| |||
As required by SFAS No. 69, "Disclosures“Disclosures about Oil and Gas Producing Activities,"” changes in standardized measure relating to sales of reserves are calculated using prices in effect as of the beginning of the period and changes in standardized measure relating to purchases of reserves are calculated using prices in effect at the end of the period. Accordingly, the changes in standardized measure for purchases and sales of reserves reflected above do not necessarily represent the economic reality of such transactions. See the disclosure of "Costs“Costs incurred in Certain Oil and Gas Activities"Activities” and the statements of cash flows in the financial statements.
Natural gas prices have declined significantly since December
31, 2000; consequently, the discounted future net cash flows
would be significantly reduced if the standardized measure was
calculated in the first quarter of 2001.
Page 72
ITEM 9 - CHANGES–CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
PART III
Effective May 3, 2002, the Audit Committee of the Board of Directors of our Company dismissed Arthur Andersen LLP (“Andersen”) as the Company’s independent public accountants and engaged KPMG to serve as the Company’s independent public accountants for 2002.
None of Andersen’s reports on the Company’s consolidated financial statements for either of the past two fiscal years contained an adverse opinion or disclaimer of opinion or were qualified or modified as to uncertainty, audit scope or accounting principles.
During the Company’s two most recent fiscal years, there were no disagreements with Andersen on any matter of accounting principles or practices, financial statement disclosure or auditing scope or procedure, which disagreements, if not resolved to the satisfaction of Andersen, would have caused Andersen to make reference to the subject matter of the disagreements in connection with Andersen’s report; and during such period there were no “reportable events” of the kind listed in Item 304(a)(1)(v) of Regulation S-K.
The Company disclosed the foregoing information on a Current Report on Form 8-K dated May 3, 2002 (the “Form 8-K”). The Company provided Andersen with a copy of the foregoing disclosure and requested Andersen to furnish the Company with a letter addressed to the Securities and Exchange Commission stating whether Andersen agreed with the statements by the Company in the foregoing disclosure and, if not, stating the respects in which it did not agree. Andersen’s letter stated that it had read the pertinent paragraphs of the Form 8-K and was in agreement with the statements contained therein. Andersen’s letter is incorporated herein by reference to Exhibit 16.1 of the Form 8-K.
During the Company’s two most recent fiscal years and through the date of this Annual Report on Form 10-K, the Company did not consult KPMG with respect to the application of accounting principles to a specified transaction, either completed or proposed, or the type of audit opinion that might be rendered on the Company’s consolidated financial statements, or any other matters or reportable events listed in Items 304(a)(2)(i) and (ii) of Regulation S-K.
| PART | III |
ITEMS 10, 11, 12 AND 13 - DIRECTORS–DIRECTORS AND EXECUTIVE OFFICERS OF THE COMPANY, EXECUTIVE OFFICERS OF THE COMPANY, EXECUTIVE COMPENSATION,SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS ANDCERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
Except for information concerning executive officers of the Company included as an unnumbered item in Part 1,I hereof, in accordance with General Instruction G(3), reference is hereby made to the Company'sCompany’s definitive proxy statement to be filed within 120 days after the end of the fiscal year covered by this report.
PART IV
ITEM 14 - EXHIBITS,–CONTROLS AND PROCEDURES
(a) Evaluation of Disclosure Controls and Procedures:
Within the 90 day period prior to the filing date of this Annual Report on Form 10-K, the Company, under the supervision, and with the participation, of its management, including its principal executive officer and principal financial officer, performed an evaluation of the design and operation of the Company’s disclosure controls and procedures (as defined in Securities and Exchange Act Rule 13a-14(c)). Based on that evaluation, the Company’s principal executive officer and principal financial officer concluded that such disclosure controls and procedures are effective to ensure that material information relating to the Company, including its consolidated subsidiaries, is accumulated and communicated to the Company’s management and made known to the principal executive officer and principal financial officer, particularly during the period for which this periodic report was being prepared.
(b) Changes in Internal Controls
No significant changes were made in the Company’s internal controls or in other factors that could significantly affect these controls subsequent to the date of the evaluation described in Item 14 (a).
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PART IV
ITEM 15 –EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K
(a) Financial Statements
1. Financial Statements - The financial statements
filed herewith are listed in the Index to Financial
Statements on page 30 of this report.
2. All schedules are omitted because they are not required,
inapplicable or the information is included in the consolidated
financial statements or the notes thereto.
3. Exhibits
(3.1)
(a) | Financial Statements | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
1. | Financial Statements – The financial statements filed herewith are listed in the Index to Financial Statements on page 36 of this report. | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
2. | All schedules are omitted because they are not required, inapplicable or the information is included in the consolidated financial statements or the notes thereto. | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
3. | Exhibits | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
(3.1 | ) | Articles of Incorporation of (3.2 ) Articles of Amendment of Articles of Incorporation of Penn Virginia (3.3 ) Amended bylaws of Registrant (incorporated by reference to Exhibit 3.1 to Registrant’s Report on Form 8-K filed on March 28, 2002). (4.1 ) Rights Agreement dated as of February 11, 1998 between Penn Virginia (4.2 ) Amendment No. 1 to Rights Agreement dated March 27, 2002 by and between Penn Virginia (10.1 ) Credit Agreement dated as of October 30, 2001 among Penn Virginia (10.2 ) Penn Virginia Corporation and Affiliated Companies Employees’ Stock Ownership Plan, as amended (incorporated by reference to Exhibit 10.2 of Registrant’s Annual Report on Form 10-K for the year ended December 31, 2001). (10.3 ) Penn Virginia Corporation and Affiliated Companies’ Employees’ 401(k) Plan, as amended (incorporated by reference to Exhibit 10.3 of Registrant’s Annual Report on Form 10-K for the year ended December 31, 2001). (10.6 ) Penn Virginia Corporation 1995 Third Amended and Restated Directors’ Stock Compensation Plan. (10.7 ) Penn Virginia Corporation Amended 1999 Employee Stock Incentive Plan. (10.8 ) Omnibus Agreement (“Omnibus Agreement”) dated October 30, 2001 among Penn Virginia Corporation, Penn Virginia Resource GP, LLC, Penn Virginia Operating Co. (10.9 ) Amendment No.1 to Omnibus Agreement (10.10 ) Penn Virginia (10.11 ) Change of Control Severance Agreement dated May 7, 2002 between Penn Virginia (10.12 ) Change of Control Severance Agreement dated May 7, 2002 between Penn Virginia Corporation and Frank A. Pici (incorporated by reference to Exhibit 10.2 of Registrant’s Report on Form 10-Q for the period ended March 31, 2002). (10.13 ) Change of Control Severance Agreement dated May 7, 2002 between Penn Virginia Corporation and Nancy M. Snyder (incorporated by reference to Exhibit 10.3 of Registrant’s Report on Form 10-Q for the period ended March 31, 2002). (10.14 ) Change of Control Severance Agreement dated May 7, 2002 between Penn Virginia Corporation and H. Baird Whitehead (incorporated by reference to Exhibit 10.4 of Registrant’s Report on Form 10-Q for the period ended March 31, 2002). (10.15 ) Change of Control Severance Agreement dated May 7, 2002 between Penn Virginia Corporation and Keith D. Horton (incorporated by reference to Exhibit 10.5 of Registrant’s Report on Form 10-Q for the period ended March 31, 2002). (21 ) Subsidiaries of Registrant. (23.1 ) Consent of KPMG LLP. (99.1 ) Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. (99.2 ) Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. Page 74
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