ITEM 1. BUSINESS.
General
PDC 2001-C Limited Partnership ("the Partnership") is a limited partnership formed on November 9, 2001 pursuant to the West Virginia Uniform Limited Partnership Act. Petroleum Development Corporation ("PDC") serves as Managing General Partner of the Partnership.
Since the commencement of operations on November 9, 2001, the Partnership has been engaged in onshore, domestic oil and natural gas exploration exclusively in the Rocky Mountain Region. A total of 9 limited partners contributed initial capital of $430,000; a total of 586 additional general partners contributed initial capital of $10,197,234; and PDC (Managing General Partner) contributed $2,311,423 in capital as a participant in accordance with contribution provisions of the Limited Partnership Agreement (the Agreement). During 2002 in accordance with the Partnership Agreement, all Additional General Partners were converted to Limited Partners.
Under the terms of the Agreement, the allocation of revenues is as follows:
Allocation
of Revenues
Additional General and Limited Partners
80%
Managing General Partner
20%
Operating and direct costs are allocated and charged to the additional general and limited partners and the Managing General Partner in the same percentages as revenues are allocated. Leasehold, drilling and completion costs, and equipment costs are borne 80% by the Additional General and Limited Partners and 20% by the Managing General Partner. See Footnote 4 of financial statements for a complete description of the allocation of Partnership revenue and costs.
Employees
The Partnership has no employees; however, PDC has approximately 120 employees, including 17 in finance and data processing, 8 in administration, 12 in exploration and development, 78 in production and 5 in natural gas marketing.
Plan of Operations
The Partnership participated in the drilling of eighteen gross (15.53 net) wells (all of which are productive) and will continue to operate and produce its nineteen productive wells. The Partnership does not have unexpended initial capital and no additional drilling activity is planned.
See Item 2
ITEM 2. PROPERTIES.
Drilling Activity
The following table sets forth the results of the Partnership's drilling activity from November 9, 2001 (date of inception) to December 31, 2004. All of the Partnership's wells drilled and producing are located in Colorado.
The Partnership has not participated in any exploratory wells. No additional drilling activity is planned.
Production
See "Management's Discussion and Analysis" on page 5 for Partnership production.
Reserves
See "Footnote 8" to the Partnership's financial statements for information related to the Partnership's oil and gas reserves.
Productive Wells
As outlined in the above table, the Partnership has a total of 18 gross productive wells (15.53 net wells) all of which are located in Colorado.
A "productive well" is a well producing, or capable of producing, oil and gas in commercial quantities. For purposes of the above table, a "gross well" is one in which the Partnership has a working interest and a "net well" is a gross well multiplied by the Partnership's working interest to which it is entitled under its drilling agreement.
Title to Properties
The Partnership's interests in producing acreage are in the form of assigned direct interests in leases. Such properties are subject to customary royalty interests generally contracted for in connection with the acquisition of properties, and could be subject to liens incident to operating agreements, liens for current taxes and other burdens. The Partnership believes that none of these burdens materially interfere with the use of such properties in the operation of the Partnership's business.
As is customary in the oil and gas industry, little or no investigation of title is made at the time of acquisition of undeveloped properties (other than a preliminary review of local mineral records). Investigations are generally made, including in most cases receiving a title opinion of legal counsel, before commencement of drilling operations. A thorough examination of title has been made with respect to all of the Partnership's producing properties and the Partnership believes that it has generally satisfactory title to such properties.
ITEM 3.
ITEM 3. LEGAL PROCEEDINGS.
The Managing General Partner as driller/operator is not party to any legal action that it believes would have a materially adverse affect on the Managing General Partner's or Partnership's business, financial condition, results of operations or liquidity.
ITEM 4.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.
NONE
PART II
ITEM 5.
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS.
At December 31, 2001, PDC 2001-C Limited Partnership had one Managing General Partner, 9 Limited Partners who fully paid for 21.5 units at $20,000 per unit of limited partnership interests and a total of 586 Additional General
Partners who fully paid for 509.8617 units at $20,000 per unit of additional general partnership interests. During 2002 in
accordance with the Partnership Agreement, all Additional General Partners were converted to Limited Partners. At December 31, 2003, the Partnership had one Managing General Partner and 595 limited partners who paid for 531.3617 units at $20,000 per unit. No established public trading market exists for the interests.
Limited and additional general partnership interests are transferable, however no assignee of an interest in the Partnership can become a substituted partner without the written consent of the transferor and the Managing General Partner.
ITEM 6.
ITEM 6. SELECTED FINANCIAL DATA.
The selected financial data presented below has been derived from audited financial statements of the Partnership appearing elsewhere herein.
Year Ended
December 31, 2004
Year Ended
December 31, 2003
Year Ended
December 31, 2002
Oil and Gas Sales
$1,366,254
$2,104,889
$1,741,435
Costs and Expenses
1,141,585
1,468,291
1,591,433
Cumulative Effect of change in accounting principle
-
(829)
-
Net Income
225,255
636,762
150,668
Allocation of Net Income:
Managing General Partner
45,051
127,352
30,134
Limited and Additional General Partners
180,204
509,410
120,534
Per Limited and Additional General Partner Unit
Total Assets
9,204,457
9,865,494
10,849,189
Cash Distributions
Managing General Partner
180,307
325,021
213,837
Limited and Additional General Partners
721,232
1,300,092
855,354
ITEM 7.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.
Liquidity and Capital Resources
The Partnership was funded on November 9, 2001 with initial Limited and Additional General Partner contributions of $10,627,234 and the Managing General Partner's cash contribution of $2,311,423 in accordance with the Agreement. After payment of syndication costs of $1,115,860 and a one-time management fee to the managing general partner of $265,681 the Partnership had available cash of $11,557,116 for Partnership activities. During 2002 the Managing General Partner made an additional capital contribution in the amount of $199,371 which was expended for the development of oil and gas properties.
The Partnership had working capital at December 31, 2004 of $243,024.
Operations are expected to be conducted with available funds and revenues generated from oil and gas activities. No bank borrowings are anticipated.
Results of Operations
2004 Results Compared to 2003
Oil and gas sales for the year ended December 31, 2004 were $1,366,254 compared to $2,104,889 for the year ended December 31, 2003. For the year ended December 31, 2004, the Partnership sold 143,798 Mcf of gas and 16,374 barrels of oil at average sales prices of $5.22 and $37.57, respectively. This compared with 395,773 Mcf of gas and 21,635 barrels of oil sold at average sales prices of $3.66 and $30.40, respectively for the year ended December 31, 2003. Lifting cost per Mcfe in 2004 amounted to $1.89 as compared to $1.00 for 2003. This increase is partially attributed to the increase in severance and property taxes on the significantly higher oil & gas prices along with additional well workovers. The fixed costs of operations and well maintenance are allocated to lower production volumes, therefore increasing the lifting cost per Mcfe. Depreciation, depletion and amortization decreased from $926,200 for the year ended December 31, 2003 to $675,235 for the year ended December 31, 2004 as a result of lower volumes of natural gas and oil sold. Cash distributions to the partners amounted to $901,539 in 2004.
2003 Results Compared to 2002
Oil and gas sales for the year ended December 31, 2003 were $2,104,889 compared to $1,741,435 for the year ended December 31, 2002. For the year ended December 31, 2003, the Partnership sold 395,773 Mcf of gas and 21,635 barrels of oil at average sales prices of $3.66 and $30.40, respectively. This compared with 442,568 Mcf of gas and 33,875 barrels of oil sold at average sales prices of $2.01 and $25.09, respectively for the year ended December 31, 2002. Lifting cost per Mcfe in 2003 amounted to $1.00 as compared to $0.52 for 2002. This increase is partially attributed to the increase in severance and property taxes. The fixed costs of operations and well maintenance are allocated to lower production volumes, therefore increasing the lifting cost per Mcfe. Depreciation, depletion and amortization decreased from $1,242,841 for the year ended December 31, 2002 to $926,200 for the year ended December 31, 2003 as a result of lower volumes of natural gas and oil sold. Cash distributions to the partners amounted to $1,625,113 in 2003.
The Partnership's revenues from oil and natural gas sales will be affected by changes in prices. As a result of changes in federal regulations, gas prices are highly dependent on the balance between supply and demand. The Partnership's gas sales prices are subject to increase and decrease based on various market sensitive indices.
Critical Accounting Policies and Estimates
Certain accounting policies are very important to the portrayal of the Partnership's financial condition and results of operations and require management's most subjective or complex judgments. In applying those policies, our management uses its judgment to determine the appropriate assumptions to be used in the determination of certain estimates. Those estimates are based on our historical experience, our observance of trends in the industry, and information available from other outside sources, as appropriate. For a more detailed discussion on the application of these and other accounting policies, see "Note 1 - Summary of significant account policies" in our financial statements and related notes. The Partnership's critical accounting policies and estimates are as follows:
Revenue Recognition
Sales of natural gas are recognized when natural gas has been delivered to a custody transfer point, persuasive evidence of a sales arrangement exists, the rights and responsibility of ownership pass to the purchaser upon delivery, collection of revenue from the sale is reasonably assured and the sales price is fixed or determinable. Natural gas is sold by the Managing General Partner under contracts with terms ranging from one month to three years. Virtually all of the Managing General Partner's contracts pricing provisions are tied to a market index, with certain adjustments based on, among other factors, whether a well delivers to a gathering or transmission line, quality of natural gas and prevailing supply and demand conditions, so that the price of the natural gas fluctuates to remain competitive with other available natural gas supplies. As a result, the Partnership's revenues from the sale of natural gas will suffer if market prices decline and benefit if they increase. The Partnership believes that the pricing provisions of its natural gas contracts are customary in the industry.
The Managing General Partner currently uses the "Net-Back" method of accounting for transportation arrangements of natural gas sales. The Managing General Partner sells gas at the wellhead and collects a price and recognizes revenues based on the wellhead sales price since transportation costs downstream of the wellhead are incurred by the Managing General Partner's customers and reflected in the wellhead price.
Sales of oil are recognized when persuasive evidence of a sales arrangement exists, the oil is verified as produced and is delivered in a stock tank, collection of revenue from the sale is reasonably assured and the sales price is determinable. The Partnership is currently able to sell all the oil that it can produce under existing sales contracts with petroleum refiners and marketers. The Partnership does not refine any of its oil production. The Partnership's crude oil production is sold to purchasers at or near the Partnership's wells under short-term purchase contracts at prices and in accordance with arrangements that are customary in the oil industry.
Accounting for Derivative Contracts at Fair Value
The Partnership uses derivative instruments to manage its commodity and financial market risks. Accounting requirements for derivatives and hedging activities are complex; interpretation of these requirements by standard-setting bodies is ongoing.
Derivatives are reported on the Balance Sheets at fair value. Changes in fair value of derivatives that are not designated as accounting hedges are recorded in earnings.
The measurement of fair value is based on actively quoted market prices, if available. Otherwise, the Partnership seeks indicative price information from external sources, including broker quotes and industry publications. If pricing information from external sources is not available, measurement involves judgment and estimates. These estimates are based on valuation methodologies considered appropriate by the Partnership's management.
For individual contracts, the use of different assumptions could have a material effect on the contract's estimated fair value. In addition, for hedges of forecasted transactions, the Partnership must estimate the expected future cash flows of the forecasted transactions, as well as evaluate the probability of the occurrence and timing of such transactions. Changes in conditions or the occurrence of unforeseen events could affect the timing of recognition in earnings for changes in fair value of certain hedging derivatives.
Use of Estimates in Long-Lived Asset Impairment Testing
Impairment testing for long-lived assets and intangible assets with definite lives is required when circumstances indicate those assets may be impaired. In performing the impairment test, the Partnership would estimate the future cash flows associated with individual assets or groups of assets. Impairment must be recognized when the undiscounted estimated future cash flows are less than the related asset's carrying amount. In those circumstances, the asset must be written down to its fair value, which, in the absence of market price information, may be estimated as the present value of its expected future net cash flows, using an appropriate discount rate. Although cash flow estimates used by the Partnership are based on the relevant information available at the time the estimates are made, estimates of future cash flows are, by nature, highly uncertain and may vary significantly from actual results.
Oil and Gas Properties
Exploration and development costs are accounted for by the successful efforts method.
The Partnership assesses impairment of capitalized costs of proved oil and gas properties by comparing net capitalized costs to estimated undiscounted future net cash flows on a field-by-field basis using expected prices. Prices utilized in each year's calculation for measurement purposes and expected costs are held constant throughout the estimated life of the properties. If net capitalized costs exceed undiscounted future net cash flows, the measurement of impairment is based on estimated fair value which would consider future discounted cash flows.
Property acquisition costs are capitalized when incurred. Geological and geophysical costs and delay rentals are expensed as incurred. The costs of drilling exploratory wells are capitalized pending determination of whether the wells have discovered economically producible reserves. If reserves are not discovered, such costs are expensed as dry holes. Development costs, including equipment and intangible drilling costs related to both producing wells and developmental dry holes are capitalized.
Unproved properties or leases are written-off to expense when it is determined that they will expire or be abandoned.
Costs of proved properties, including leasehold acquisition, exploration and development costs and equipment, are depreciated and depleted by the unit-of-production method based on estimated proved developed oil and gas reserves.
Upon sale or retirement of complete fields of depreciable or depletable property, the book value thereof, less proceeds or salvage value, is credited or charged to income. Upon sale of a partial unit of property, the proceeds are credited to accumulated depreciation and depletion.
New Accounting Standards
In June 2001, the Financial Accounting Standard Board issued FASB No. 143, "Accounting for Asset Retirement
Obligations" that requires entities to record the fair value of a liability for an asset retirement obligation in the period in which it is incurred and a corresponding increase in the carrying amount of the related long-lived asset. This statement is effective for fiscal years beginning after June 15, 2002. The Partnership adopted FASB No. 143 on January 1, 2003 and recorded a net asset of $7,169 and a related liability of $7,998 (using a 6% discount rate) and a cumulative effect of change in accounting principle on prior years of $829.
Item 7A.
Item 7A. Quantitative and Qualitative Disclosure About Market Risk.
Market-Sensitive Instruments and Risk Management
The Partnership's primary market risk exposure is commodity price risk. This exposure is discussed in detail below:
Commodity Price Risk
The Managing General Partner utilizes commodity-based derivative instruments as hedges to manage a portion of its exposure to price risk from its oil and natural gas sales. These instruments consist of CIG-based contracts traded by JP Morgan for Colorado production. These hedging arrangements have the effect of locking in for specified periods (at predetermined prices or ranges of prices) the prices the Partnership will receive for the volume to which the hedge relates. As a result, while these hedging arrangements are structured to reduce the Partnership's exposure to changes in price associated with the hedged commodity, they also limit the benefit the Partnership might otherwise have received from price changes associated with the hedged commodity. The Partnership's policy prohibits the use of natural gas future and option contracts for speculative purposes.
The following tables summarize the open futures and options contracts for the Partnership as of December 31, 2004 and 2003.
Commodity
Type
Quantity
Gas-Mmbtu
Oil-Barrels
Weighted
Average
Price
Total
Contract
Amount
Fair
Market
Value
Total Contracts as of December 31, 2004
Natural Gas
Floors
26,828
4.36
-
7,657
Natural Gas
Ceilings
13,414
5.56
-
(6,956)
Oil
Floors
8,178
32.30
264,155
6,967
Oil
Ceilings
4,089
40.00
163,564
(22,118)
Contracts maturing in 12 months following December 31 , 2004
Natural Gas
Floors
26,828
4.36
-
7,657
Natural Gas
Ceilings
13,414
5.56
-
(6,956)
Oil
Floors
8,178
32.30
264,155
6,967
Oil
Ceilings
4,089
40.00
163,564
(22,118)
Prior Year Total Contracts as of December 31, 2003
Natural Gas
Floors
16,754
3.28
-
-
Natural Gas
Ceilings
16,754
4.84
-
(255)
The maximum term over which the Partnership is hedging exposure to the variability of cash flows for commodity price risk is 12 months.
The average CIG closing price for natural gas for the years 2004, 2003 and 2002 was $5.17 per Mmbtu, $4.04 per Mmbtu and $1.97 per Mmbtu. Future near-term gas prices will be affected by various supply and demand factors such as weather, government and environmental regulations and new drilling activities within the industry.
Disclosure of Limitations
As the information above incorporates only those exposures that exist at December 31, 2004, it does not consider those exposures or positions which could arise after that date. As a result, the Partnership's ultimate realized gain or loss with respect to commodity price fluctuations will depend on the exposures that arise during the period, the Partnership's hedging strategies at the time and commodity prices at the time.
PART III
ITEM 8.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA:
The response to this Item is set forth herein in a separate section of this Report, beginning on Page.
ITEM 9.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE.
NONE.
ITEM 9A.
ITEM 9A. CONTROLS AND PROCEDURES
Under the supervision and with the participation of the Managing General Partner's management, including the Managing General Partner's Chief Executive Officer and Chief Financial Officer, the Managing General Partner has evaluated the effectiveness of the design and operation of its disclosure controls and procedures (as defined in Exchange Act Rule 13a-14(c)) as of the end of the period covered by this annual report on Form 10-K, and, based on their evaluation, the Chief Executive Officer and Chief Financial Officer have concluded that these disclosure controls and procedures are effective in all material respects, including those to ensure that information required to be disclosed in reports filed or submitted under the Securities Exchange Act is recorded, processed, summarized, and reported, within the time periods specified in the Commission's rules and forms, and is accumulated and communicated to management, including the Managing General Partner's Chief Executive Officer and Chief Financial Officer, as appropriate to allow for timely disclosure. There have been no significant changes in our internal controls or in other factors that could significantly affect these controls in the fourth quarter and subsequent to the date of their evaluation.
ITEM 9B.
ITEM 9B. OTHER INFORMATION
NONE
ITEM 10.
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT.
The Partnership has no directors or executive officers. The partnership is managed by Petroleum Development Corporation (the Managing General Partner). Petroleum Development Corporation's common stock is traded in the NASDAQ National Market and Form 10-K for 2004 has been filed with the Securities and Exchange Commission.
Although the Partnership has no Code of Ethics, Petroleum Development Corporation, the Managing General Partner of the Partnership, has a Code of Ethics that applies to its senior executive officers. The Code of Ethics is posted on the website of Petroleum Development Corporation at www.petd.com.
ITEM 11.
ITEM 11. EXECUTIVE COMPENSATION.
NON-APPLICABLE.
ITEM 12.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS, MANAGEMENT AND RELATED STOCKHOLDER MATTERS.
NON-APPLICABLE.
ITEM 13.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.
Pursuant to the authorization contained in the Limited Partnership Agreement, PDC receives fees for services rendered and reimbursement of certain expenses from the Partnership. The following table presents compensation or reimbursements by the Partnership to PDC or other related parties during the years ended December 31, 2004, 2003 and 2002.
December 31,
Drilling and completion costs
$ -
-
199,371
Lifting costs
456,281
527,952
335,536
Tax return preparation
5,473
6,927
4,175
Direct administrative cost
3,606
2,840
ITEM 14.
ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES
For the years ended December 31, 2004 and 2003, the Partnership paid KPMG LLP $3,220 and $3,126, respectively, for professional services for the audit of the Partnership's financial statements in its Form 10-K and review of financial statements included in the Partnership's Form 10-Qs.
Pre-Approval Policies and Procedures
The Sarbanes-Oxley Act of 2002 requires that all services provided to the Partnership by its independent accountants be subject to pre-approval by the Audit Committee or authorized members of the Committee. Since the Partnership does not have an Audit Committee, the Managing General Partner's Audit Committee also serves for the Partnership. The Audit Committee has adopted policies and procedures for pre-approval of all audit services and non-audit services to be provided by the Partnership's independent accountants. Services necessary to conduct the annual audit must be pre-approved by the Audit Committee or by the authorized Audit Committee member.
ITEM 15.
ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES.
(1) Financial Statements
See Index to Financial Statements on
(2) Financial Statement Schedules
See Index to Financial Statements on page. All financial statement schedules are omitted because they are not required, inapplicable, or the information is included in the Financial Statements or Notes thereto.
(3) Exhibits
4.1
Form of Limited Partnership Agreement (incorporated by reference to Appendix A to Form S-1, SEC File No. 333-47622, and Rule 424 final prospectus, dated May 25, 2001, of PDC 2003 Drilling Program, filed with the SEC on May 30, 2001).
Code of Ethics of Petroleum Development Corporation (incorporated by reference to the posted code on the web site of Petroleum Development Corporation at www.petd.com).
31.1
Rule 13a-14(a)/15d-14(c) Certification of Chief Executive Officer of Petroleum Development Corporation, the managing general partner of the Limited Partnership.
31.2
Rule 13a-14(a)/15d-14(c) Certification of Chief Financial Officer of Petroleum Development Corporation, the managing general partner of the Limited Partnership.
32.1
Title 18 U.S.C. Section 1350 (Section 906 of Sarbanes-Oxley Act of 2002) Certifications by Chief Executive Officer and Chief Financial Officer of Petroleum Development Corporation, the managing general partner of the Limited Partnership.
CONFORMED COPY
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.
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated:
Signature
Title
Date
/s/ Steven R. Williams
Steven R. Williams
Chairman, Chief Executive Officer and
Director
April 14, 2005
/s/ Darwin L. Stump
Darwin L. Stump
Chief Financial Officer and Treasurer
(principal financial and accounting officer)
April 14, 2005
/s/ Thomas E. Riley
Thomas E. Riley
President and Director
April 14, 2005
/s/ Donald B. Nestor
Donald B. Nestor
Director
April 14, 2005
/s/ Vincent F. D'Annunzio
Vincent F. D'Annunzio
Director
April 14, 2005
PDC 2001-C LIMITED PARTNERSHIP
(A West Virginia Limited Partnership)
Financial Statements for Annual Report
on Form 10-K to Securities and Exchange
Commission
Years Ended December 31, 2004, 2003 and
(With Independent Registered Public Accounting Firm's Report Thereon)
PDC 2001-C LIMITED PARTNERSHIP
(A West Virginia Limited Partnership)
Report of Independent Registered Public Accounting Firm
Balance Sheets - December 31, 2004 and 2003
Statements of Operations - Years Ended December 31, 2004, 2003 and 2002
Statements of Partners' Equity and Comprehensive Income (Loss) -
Years Ended December 31, 2004, 2003, and 2002
Statements of Cash Flows -Years Ended December 31, 2004, 2003 and 2002
Notes to Financial Statements
All financial statement schedules have been omitted because they are not applicable or not required or the required information is shown in the financial statements or notes thereto.
Report of Independent Registered Public Accounting Firm
To the Partners
PDC 2001-C Limited Partnership:
We have audited the accompanying balance sheets of PDC 2001-C Limited Partnership (a West Virginia limited partnership) as of December 31, 2004 and 2003, and the related statements of operations, partners' equity and comprehensive income (loss), and cash flows for each of the years in the three-year period ended December 31, 2004. These financial statements are the responsibility of the Partnership's management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (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 PDC 2001-C Limited Partnership as of December 31, 2004 and 2003, and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2004, in conformity with U.S. generally accepted accounting principles.
As discussed in note 1 to the financial statements, the Partnership adopted the provisions of Statement of Financial Accounting Standards No. 143, "Accounting for Asset Retirement Obligations", in 2003.
KPMG LLP
Pittsburgh, Pennsylvania
April 15, 2005
PDC 2001-C LIMITED PARTNERSHIP
(A West Virginia Limited Partnership)
Balance Sheets
December 31, 2004 and 2003
Assets
Current assets:
Cash
$ 2,413
1,967
Account receivable - oil and gas revenues
282,664
268,912
Total current assets
285,077
270,879
Oil and gas properties, successful efforts method
(notes 3 and 6):
11,764,033
11,764,033
Less accumulated depreciation,
depletion and amortization
2,844,653
2,169,418
8,919,380
9,594,615
$9,204,457
9,865,494
Liabilities and Partners' Equity
Current liabilities:
Accrued expenses
$42,053
13,120
Total current liabilities
42,053
13,120
Asset retirement obligation
8,987
8,478
Partners' equity
9,153,417
9,843,896
$9,204,457
9,865,494
See accompanying notes to financial statements.
PDC 2001-C LIMITED PARTNERSHIP
(A West Virginia Limited Partnership)
Statements of Operations
Years Ended December 31, 2004, 2003 and 2002
See accompanying notes to financial statements.
PDC 2001-C LIMITED PARTNERSHIP
(A West Virginia Limited Partnership)
Statements of Partners' Equity
And Comprehensive Income (Loss)
Years Ended December 31, 2004, 2003 and 2002
Limited and
additional
general
partners
Managing
general
Partner
Accumulated
Other
Comprehensive
Income
Total
Balance December 31, 2001
$9,241,323
2,310,331
11,551,654
Capital contribution
199,371
199,371
Distribution to partners
(855,354)
(213,837)
(1,069,191)
Comprehensive income:
Net income
120,534
30,134
150,668
Change in fair value of outstanding
hedging positions
2,391
Reclassification adjustment for settled
contracts included in net income
Other comprehensive income
2,391
2,391
Comprehensive income
153,059
Balance December 31, 2002
8,506,503
2,325,999
2,391
10,834,893
Distribution to partners
(1,300,092)
(325,021)
(1,625,113)
Comprehensive income:
Net income:
509,410
127,352
636,762
Change in fair value of outstanding
hedging positions
(1,448)
Reclassification adjustment for settled
contracts included in net income
(1,198)
Other comprehensive loss
(2,646)
(2,646)
Comprehensive income
634,116
Balance December 31, 2003
7,715,821
2,128,330
(255)
9,843,896
Distribution to partners
(721,232)
(180,307)
(901,539)
Comprehensive income:
Net income:
180,204
45,051
225,255
Change in fair value of outstanding
hedging positions
(22,024)
Reclassification adjustment for settled
contracts included in net income
7,829
Other comprehensive loss
(14,195)
(14,195)
Comprehensive income
211,060
Balance December 31, 2004
$7,174,793
1,993,074
(14,450)
9,153,417
See accompanying notes to financial statements.
PDC 2001-C LIMITED PARTNERSHIP
(A West Virginia Limited Partnership)
Statements of Cash Flows
Years Ended December 31, 2004, 2003 and 2002
Cash flows from operating activities:
Net income
$ 225,255
636,762
150,668
Adjustments to reconcile net income
to net cash used by operating activities:
Depreciation, depletion and
amortization
675,235
926,200
1,242,841
Cumulative effect of change in accounting principle
-
-
Accretion of asset retirement obligation
-
Changes in operating assets and liabilities:
Decrease (increase) in accounts receivable -
oil and gas revenues
63,169
(332,082)
Decrease in due to Managing General Partner
-
-
(109)
Increase (decrease) increase in accrued expenses
(1,430)
2,155
Net cash provided from
operating activities
901,985
1,626,010
1,063,473
Cash flows from investing activities:
Expenditures for oil and gas properties
-
-
(199,371)
Net cash used by
investing activities
-
-
(199,371)
Cash flows from financing activities:
Managing General Partner contribution
-
-
199,371
Distributions to partners
(901,539)
(1,625,113)
(1,069,191)
Net cash used by
financing activities
(901,539)
(1,625,113)
(869,820)
Net increase (decrease) in cash
(5,718)
Cash at beginning of period
1,967
1,070
6,788
Cash at end of period
$ 2,413
1,967
1,070
See accompanying notes to financial statements.
PDC 2001-C LIMITED PARTNERSHIP
(A West Virginia Limited Partnership)
Notes to Financial Statements
December 31, 2004, 2003 and 2002
(1) Summary of Significant Accounting Policies
Partnership Financial Statement Presentation Basis
The financial statements include only those assets, liabilities and results of operations of the partners which relate to the business of PDC 2001-C Limited Partnership (the Partnership). The statements do not include any assets, liabilities, revenues or expenses attributable to any of the partners' other activities. Petroleum Development Corporation ("PDC") serves as Managing General Partner of the Partnership.
Oil and Gas Properties
The Partnership follows the successful efforts method of accounting for the cost of exploring for and developing oil and gas reserves. Under this method, costs of development wells, including equipment and intangible drilling costs related to both producing wells and developmental dry holes, and successful exploratory wells are capitalized and amortized on an annual basis to operations by the units-of-production method using estimated proved developed reserves determined at December 31, 2004 and 2003 by the Managing General Partner's petroleum engineers and at December 31, 2002 by an independent petroleum engineer, Wright & Company, Inc. If a determination is made that an exploratory well has not discovered economically producible reserves, then its costs are expensed as dry hole costs.
The Partnership assesses impairment of capitalized costs of proved oil and gas properties by comparing net capitalized costs to undiscounted future net cash flows on a field-by-field basis using expected prices. Prices utilized in each year's calculation for measurement purposes and expected costs are held constant throughout the estimated life of the properties. If net capitalized costs exceed undiscounted future net cash flow, the measurement of impairment is based on estimated fair value which would consider future discounted cash flows.
Revenue Recognition
Sales of natural gas are recognized when natural gas has been delivered to a custody transfer point, persuasive evidence of a sales arrangement exists, the rights and responsibility of ownership pass to the purchaser upon delivery, collection of revenue from the sale is reasonably assured and the sales price is fixed or determinable. Natural gas is sold by the Managing General Partner under contracts with terms ranging from one month to three years. Virtually all of the Managing General Partner's contracts pricing provisions are tied to a market index, with certain adjustments based on, among other factors, whether a well delivers to a gathering or transmission line, quality of natural gas and prevailing supply and demand conditions, so that the price of the natural gas fluctuates to remain competitive with other available natural gas supplies. As a result, the Partnership's revenues from the sale of natural gas will suffer if market prices decline and benefit if they increase. The Partnership believes that the pricing provisions of its natural gas contracts are customary in the industry.
The Managing General Partner currently uses the "Net-Back" method of accounting for transportation arrangements of natural gas sales. The Managing General Partner sells gas at the wellhead and collects a price and recognizes revenues based on the wellhead sales price since transportation costs downstream of the wellhead are incurred by the Managing General Partner's customers and reflected in the wellhead price.
Sales of oil are recognized when persuasive evidence of a sales arrangement exists, the oil is verified as produced and is delivered in a stock tank, collection of revenue from the sale is reasonably assured and the sales price is determinable. The Partnership is currently able to sell all the oil that it can produce under existing sales contracts with petroleum refiners and marketers. The Partnership does not refine any of its oil production. The Partnership's crude oil production is sold to purchasers at or near the Partnership's wells under short-term purchase contracts at prices and in accordance with arrangements that are customary in the oil industry.
PDC 2001-C LIMITED PARTNERSHIP
(A West Virginia Limited Partnership)
Notes to Financial Statements
Income Taxes
Since the taxable income or loss of the Partnership is reported in the separate tax returns of the partners, no provision has been made for income taxes on the Partnership's books.
Under federal income tax laws, regulations and administrative rulings, certain types of transactions may be accorded varying interpretations. Accordingly, the Partnership's tax return and, consequently, individual tax returns of the partners may be changed to conform to the tax treatment resulting from a review by the Internal Revenue Service.
Derivative Financial Instruments
The Managing General Partner utilizes commodity based derivative instruments as hedges to manage a portion of the Partnership's exposure to price volatility stemming from natural gas production. These instruments consist of costless collars and option contracts traded on the New York Mercantile Exchange. The costless collars and option contracts hedge committed and anticipated natural gas sales generally forecasted to occur within a 12 month period. The Partnership does not hold or issue derivatives for trading or speculative purposes.
All derivatives are recognized on the Partnership balance sheet at their fair value. On the date the derivative contract is entered into, the Managing General Partner designates the derivative as either a hedge of a forecasted transaction or the variability of cash flows to be received or paid related to a recognized asset or liability ("cash flow" hedge), or a non-hedging derivative. The Managing General Partner formally documents 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 specific firm commitments or forecasted transactions. The Managing General Partner also formally assesses, both at the hedge's inception 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 items. 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, the Partnership discontinues hedge accounting prospectively. No hedging activities were discontinued during 2004 or 2003.
Changes in fair value of a derivative that is highly effective and that is designated and qualifies as a cash-flow hedge are recorded in accumulated other comprehensive income, until earnings are affected by the variability in cash flows of the designated hedged item. Changes in the fair value of non-hedging derivatives are reported in current-period earnings. The Partnership discontinues hedge accounting prospectively when it is determined that the derivative is no longer effective in offsetting changes in the cash flows of the hedged item, the derivative expires or is sold, terminated, or exercised. Additionally, if the derivative is dedesignated as a hedging instrument, because it is probable that a forecasted transaction will not occur, a hedged firm commitment no longer meets the definition of a firm commitment, or the Partnership determines that designation of the derivative as a hedging instrument is no longer appropriate, hedge accounting will be discontinued.
By using derivative financial instruments to hedge exposures to changes in commodity prices, the Managing General Partner exposes the Partnership to credit risk and market risk. Credit risk is the failure of the counterparty to perform under the terms of the derivative contract. When the fair value of a derivative contract is positive, the counterparty owes the Partnership, which creates credit/repayment risk. The Managing General Partner minimizes the credit/repayment risk in derivative instruments by entering into transactions with high-quality counterparties.
PDC 2001-C LIMITED PARTNERSHIP
(A West Virginia Limited Partnership)
Notes to Financial Statements
Use of Estimates
The Partnership has made a number of estimates and assumptions relating to the reporting of assets and liabilities and revenues and expenses and the disclosure of contingent assets and liabilities to prepare these financial statements in conformity with generally accepted accounting principles. Actual results could differ from those estimates. Estimates which are particularly significant to the financial statements include estimates of oil and gas reserves and future cash flows from oil and gas properties which are used in assessing the impairment of long-lived assets.
New Accounting Standards
In June 2001, the Financial Accounting Standard Board issued FASB No. 143, "Accounting for Asset Retirement Obligations" that requires entities to record the fair value of a liability for an asset retirement obligation in the period in which it is incurred and a corresponding increase in the carrying amount of the related long-lived asset. This statement is effective for fiscal years beginning after June 15, 2002. The Partnership adopted FASB No. 143 on January 1, 2003 and recorded a net asset of $7,169 and a related liability of $7,998 (using a 6% discount rate) and a cumulative effect of change in accounting principle on prior years of $829.
(2) Organization
The Partnership was organized as a limited partnership on November 9, 2001, in accordance with the laws of the State of West Virginia for the purpose of engaging in the drilling, completion and operation of oil and gas development and exploratory wells in the Rocky Mountain Region.
Purchasers of partnership units subscribed to and fully paid for 21.5 units of limited partner interests and 509.8617 units of additional general partner interests at $20,000 per unit (Investor Partners). Petroleum Development Corporation has been designated the Managing General Partner of the Partnership. Although costs, revenues and cash distributions allocable to the limited and additional general partners are shared pro rata based upon the amount of their subscriptions, including the Managing General Partner to the extent of its capital contributions, there are significant differences in the federal income tax effects and liability associated with these different types of units in the Partnership.
Upon completion of the drilling phase of the Partnership's wells, all additional general partners units are converted into units of limited partner interests and thereafter become limited partners of the Partnership. Limited partners do not have any rights to convert their units into units of additional general partner interests in the Partnership.
In accordance with the terms of the Limited Partnership Agreement (the Agreement), the Managing General Partner manages all activities of the Partnership and acts as the intermediary for substantially all Partnership transactions.
(Continued)
PDC 2001-C LIMITED PARTNERSHIP
(A West Virginia Limited Partnership)
Notes to Financial Statements
(3) Transactions with Managing General Partner and Affiliates
Pursuant to the authorization contained in the Agreement, PDC receives fees for services rendered and reimbursement of certain expenses from the Partnership. See respective drilling prospectus for further information regarding the Agreement. The following table presents compensation or reimbursements by the Partnership to PDC or other related parties for years ended December 31, 2004, 2003 and 2002.
Year Ended
December 31, 2004
Year Ended
December 31, 2003
Year Ended
December 31, 2002
Drilling and completion costs
$ -
-
199,371
Lifting costs
456,281
527,952
335,536
Tax return preparation
5,473
6,927
4,175
Direct administrative cost
3,606
2,840
(4) Allocation
The table below summarizes the participation of the Managing General Partner and the Investor Partners, taking account of the Managing General Partner's capital contribution equal to a minimum of 20% of the Initial Operating Capital, in the costs and revenues of the Partnership.
Partnership Costs
Investor
Partners(5)(6)
Managing
General
Partner (5)(6)
Broker-dealer Commissions and
Expenses(1)
100%
0%
Management Fee(2)
100%
0%
Lease Costs
0%
100%
Tangible Well Costs
0%
100%
Total Drilling and Completion Costs
80%
20%
Operating Costs(3)
80%
20%
Direct Costs(4)
80%
20%
Administrative Costs
0%
100%
Partnership Revenues
Sale of Oil and Gas Production
80%
20%
Sale of Productive Properties
80%
20%
Sale of Equipment
0%
100%
Sale of Undeveloped Leases.
80%
20%
Interest Income
80%
20%
____________________
(1) Organization and offering costs, net of the dealer manager commissions, discounts, due diligence expenses, and wholesaling fees of the Partnership were paid by the Managing General Partner and not from Partnership funds. In addition, organization and offering costs in excess of 10-1/2% of Subscriptions, if any, were paid by the Managing General Partner, without recourse to the Partnership.
PDC 2001-C LIMITED PARTNERSHIP
(A West Virginia Limited Partnership)
Notes to Financial Statements
(2) Represents a one-time fee paid to the Managing General Partner on the day the Partnership is funded equal to 2-1/2% of total investor subscriptions.
(3) Represents Operating costs incurred after the completion of productive wells, including monthly per-well charges paid to the Managing General Partner.
(4) The Managing General Partner receives monthly reimbursement from the Partnership for direct costs incurred by the Managing General Partner on behalf of the Partnership.
(5) To the extent that Investor Partners receive preferred cash distributions, the allocations for Investor Partners will be increased accordingly and the allocation for the Managing General Partner will likewise be decreased.
(6) The allocation of profits, losses and cash distributions of the Managing General Partner might be increased, and the allocation of profits, losses, and cash distributions of the Investor Partners might be decreased in the event that the Managing General Partner were to invest more than the Managing General Partner's minimum required Capital Contribution to cover tangible equipment and lease costs. The Managing General Partner will pay for the Partnership's share of all Leases and tangible well equipment. The entire Capital Contribution of the Investor Partners, after payment of brokerage commissions, due diligence reimbursement, and the Management Fee, will be utilized to pay for intangible drilling costs. In the event that the Intangible Drilling Costs exceed the funds of the Investor Partners available for payment of Intangible Drilling Costs (herein "excess IDC"), a portion of the Capital Contribution of the Managing General Partner may be used to pay such excess IDC. If the cost of Leases and tangible well equipment were to exceed the Managing General Partner's Capital Contribution of 21-3/4% of the aggregate Capital Contribution of the Investor Partners, then the Managing General Partner will increase its Capital Contribution to fund such additional capital requirements and the Managing General Partner's allocation of profits, losses, and cash distributions will be increased to equal the percentage arrived at by dividing the Capital Contribution made by the Managing General Partner by the Capital Available for Investment; the allocation of the Investor Partners will be decreased accordingly.
(7) In accordance with the repurchase provision of the partnership prospectus, PDC may repurchase units from the investor partners, which is entirely voluntary on the part of the partners. During 2004 and 2003 there were no units purchased by PDC.
(5) Derivative Financial Instruments
The Managing General Partner utilizes commodity-based derivative instruments as hedges to manage a portion of its exposure to price risk from its oil and natural gas sales. These instruments consist of CIG-based contracts traded by JP Morgan for Colorado production. These hedging arrangements have the effect of locking in for specified periods (at predetermined prices or ranges of prices) the prices the Partnership will receive for the volume to which the hedge relates. As a result, while these hedging arrangements are structured to reduce the Partnership's exposure to changes in price associated with the hedged commodity, they also limit the benefit the Partnership might otherwise have received from price changes associated with the hedged commodity. The Partnership's policy prohibits the use of natural gas future and option contracts for speculative purposes.
PDC 2001-C LIMITED PARTNERSHIP
(A West Virginia Limited Partnership)
Notes to Financial Statements
The following tables summarize the open futures and options contracts for the Partnership as of December 31, 2004 and 2003.
Commodity
Type
Quantity
Gas-Mmbtu
Oil-Barrels
Weighted
Average
Price
Total
Contract
Amount
Fair
Market
Value
Total Contracts as of December 31, 2004
Natural Gas
Floors
26,828
4.36
-
7,657
Natural Gas
Ceilings
13,414
5.56
-
(6,956)
Oil
Floors
8,178
32.30
264,155
6,967
Oil
Ceilings
4,089
40.00
163,564
(22,118)
Contracts maturing in 12 months following December 31, 2004
Natural Gas
Floors
26,828
4.36
-
7,657
Natural Gas
Ceilings
13,414
5.56
-
(6,956)
Oil
Floors
8,178
32.30
264,155
6,967
Oil
Ceilings
4,089
40.00
163,564
(22,118)
Prior Year Total Contracts as of December 31, 2003
Natural Gas
Floors
16,754
3.28
-
-
Natural Gas
Ceilings
16,754
4.84
-
(255)
The maximum term over which the Partnership is hedging exposure to the variability of cash flows for commodity price risk is 12 months.
(6) Costs Relating to Oil and Gas Activities
The Partnership is engaged solely in oil and gas activities, all of which are located in the continental United States. Information regarding aggregate capitalized costs and results of operations for these activities is located in the basic financial statements. Costs capitalized for these activities are as follows:
The following costs were incurred for the Partnership's oil and gas activities:
PDC 2001-C LIMITED PARTNERSHIP
(A West Virginia Limited Partnership)
Notes to Financial Statements
(7) Income Taxes
As a result of the differences in the treatment of certain items for income tax purposes as opposed to financial reporting purposes, primarily depreciation, depletion and amortization of oil and gas properties and the recognition of intangible drilling costs as an expense or capital item, the income tax basis of oil and gas properties differs from the basis used for financial reporting purposes. At December 31, 2004 and 2003, the income tax basis of the partnership's oil and gas properties was $1,003,983 and $1,269,891 respectively.
(8) Supplemental Reserve Information (Unaudited)
Proved oil and gas reserves of the Partnership have been estimated at December 31, 2004 and 2003 by the Managing General Partner's petroleum engineers and at December 31, 2002 by an independent petroleum engineer, Wright & Company, Inc. These reserves have been prepared in compliance with the Securities and Exchange Commission rules based on year-end prices. A copy of the reserve report has been made available to all partners. All of the partnership's reserves are proved developed. An analysis of the change in estimated quantities of proved developed oil and gas reserves is shown below:
(9) Standardized Measure of Discounted Future Net Cash Flows and Changes Therein Relating to Proved Oil
and Gas Reserves (Unaudited)
Summarized in the following table is information for the Partnership with respect to the standardized measure of discounted future net cash flows relating to proved oil and gas reserves. Future cash inflows are computed by applying year-end prices of oil and gas relating to the Partnership proved reserves to the year-end quantities of those reserves. Future production, development, site restoration and abandonment costs are derived based on current costs assuming continuation of existing economic conditions.
PDC 2001-C LIMITED PARTNERSHIP
(A West Virginia Limited Partnership)
Notes to Financial Statements
The following table summarizes the principal sources of change in the standardized measure of discounted future estimated net cash flows:
Years Ended December 31,
Sales of oil and gas production, net of production costs
$(884,000)
(1,577,000)
(1,406,000)
Net changes in prices and production costs
4,587,000
6,584,000
6,035,000
Extensions, discoveries, and improved recovery,
less related cost
-
-
-
Revisions of previous quantity estimates
(9,722,000)
1,231,000
3,096,000
Accretion of discount
3,350,000
(3,663,000)
(3,870,000)
$(2,669,000)
2,575,000
3,855,000
It is necessary to emphasize that the data presented should not be viewed as representing the expected cash flows from, or current value of, existing proved reserves since the computations are based on a large number of estimates and arbitrary assumptions. Reserve quantities cannot be measured with precision and their estimation requires many judgmental determinations and frequent revisions. The required projection of production and related expenditures over time requires further estimates with respect to pipeline availability, rates of demand and governmental control. Actual future prices and costs are likely to be substantially different from the current prices and costs utilized in the computation of reported amounts. Any analysis or evaluation of the reported amounts should give specific recognition to the computational methods utilized and the limitations inherent therein.