PETROLEUM DEVELOPMENT CORP - 10-Q Quarterly Report

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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

[X] Quarterly Report Pursuant to Section 13 or 15(d) of

the Securities Exchange Act of 1934

For the period ended September 30, 2003

[ ] Transition Report Pursuant to Section 13 of 15(d) of

the Securities Exchange Act of 1934

For the transition period from to

Commission file number 0-7246

I.R.S. Employer Identification Number 95-2636730

PETROLEUM DEVELOPMENT CORPORATION

(A Nevada Corporation)

103 East Main Street

Bridgeport, WV 26330

Telephone: (304) 842-6256

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 the number of shares outstanding of each of the issuers classes of common stock, as of the latest practicable date: 15,628,433 shares of the Company's Common Stock ($.01 par value) were outstanding as of September 30, 2003.

Indicate by check mark whether the registrant is an accelerated filer (as definition in Rule 12b-2 of the Exchange Act). Yes XX No

PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES

INDEX


PART I - FINANCIAL INFORMATION
		Page No.

Item 1. Financial Statements

	Independent Auditors' Review Report	1

	Condensed Consolidated Balance Sheets - September 30, 2003 and December 31, 2002	2


	Condensed Consolidated Statements of Income - Three Months and Nine Months Ended September 30, 2003 and 2002	4


	Condensed Consolidated Statements of Cash Flows-Nine Months Ended September 30, 2003 and 2002	5


	Notes to Condensed Consolidated Financial Statements	6

Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations	10


Item 3.	Quantitative and Qualitative Disclosure About Market Risk	17

Item 4.	Controls and Procedures	18

PART II	OTHER INFORMATION	18

Item 1.	Legal Proceedings	18

Item 6.	Exhibits and Reports on Form 8-K	19

PART I - FINANCIAL INFORMATION

Independent Auditors' Review Report

The Board of Directors

Petroleum Development Corporation:

We have reviewed the accompanying condensed consolidated balance sheet of Petroleum Development Corporation and subsidiaries as of September 30, 2003, the related condensed consolidated statements of income for the three-month and nine-month periods ended September 30, 2003 and 2002, and the related condensed consolidated statements of cash flows for the nine-month periods ended September 30, 2003 and 2002. These condensed consolidated financial statements are the responsibility of the Company's management.

We conducted our review in accordance with standards established by the American Institute of Certified Public Accountants. A review of interim financial information consists principally of applying analytical review procedures and making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with generally accepted auditing standards, the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion.

Based on our review, we are not aware of any material modifications that should be made to the condensed consolidated financial statements referred to above for them to be in conformity with accounting principles generally accepted in the United States of America.

KPMG LLP

Pittsburgh, Pennsylvania

October 30, 2003

PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES

Condensed Consolidated Balance Sheets

September 30, 2003 and December 31, 2002


ASSETS
	2003	2002
	(Unaudited)

Current assets:
Cash and cash equivalents	$ 40,537,500	$ 51,023,500
Accounts and notes receivable	21,659,500	15,336,500
Inventories	2,111,600	1,174,100
Prepaid expenses	3,958,000	4,125,300

Total current assets	68,266,600	71,659,400



Properties and equipment	241,248,100	195,258,800
Less accumulated depreciation, depletion, and amortization	67,567,300	57,143,700
	173,680,800	138,115,100

Other assets	314,600	2,477,100

	$242,262,000	$212,251,600

(Continued)

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PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES

Condensed Consolidated Balance Sheets, Continued

September 30, 2003 and December 31, 2002

LIABILITIES AND
STOCKHOLDERS' EQUITY
	2003	2002
	(Unaudited)

Current liabilities:
Accounts payable and accrued expenses	$ 31,629,400	$ 28,687,200
Advances for future drilling contracts	17,686,400	37,283,800
Funds held for future distribution	10,550,600	3,917,900

Total current liabilities	59,866,400	69,888,900


Long-term debt	46,000,000	25,000,000
Other liabilities	2,512,000	4,137,200
Deferred income taxes	17,370,000	12,103,300
Asset retirement obligation	698,500	-


Stockholders' equity:
Common stock	156,300	157,300
Additional paid-in capital	28,573,200	29,316,800
Retained earnings	88,059,700	73,430,100
Accumulated other comprehensive income, net	(974,100)	(1,782,000)

Total stockholders' equity	115,815,100	101,122,200


	$242,262,000	$212,251,600

See accompanying notes to unaudited condensed consolidated financial statements.

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PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES

Condensed Consolidated Statements of Income

Three Months and Nine Months ended September 30, 2003 and 2002

(Unaudited)

	Three Months Ended September 30,		Nine Months Ended September 30,
	2003	2002	2003	2002
Revenues:
Oil and gas well drilling operations	$14,080,100	$ 9,409,800	$47,444,000	$43,834,900
Gas sales from marketing activities	17,686,100	11,672,800	56,644,400	32,116,900
Oil and gas sales	13,088,200	5,140,500	32,866,200	16,012,000
Well operations and pipeline income	1,865,200	1,474,500	5,282,100	4,405,800
Other income	488,300	451,000	1,158,100	1,333,800

	47,207,900	28,148,600	143,394,800	97,703,400

Costs and expenses:
Cost of oil and gas well drilling operations	11,955,700	8,541,300	39,751,500	37,110,600
Cost of gas marketing activities	17,463,500	11,734,100	55,923,100	32,164,800
Oil and gas production costs	3,986,200	2,158,500	10,303,600	6,433,900
General and administrative expenses	1,377,300	1,069,900	3,741,600	3,073,000
Depreciation, depletion, and amortization	4,243,200	3,123,600	10,632,400	9,083,300
Interest	415,000	399,800	911,000	995,000

	39,440,900	27,027,200	121,263,200	88,860,600

Income before income taxes and cumulative effect of change in accounting principle	7,767,000	1,121,400	22,131,600	8,842,800

Income taxes	2,563,100	232,400	7,303,400	2,602,900

Net income before cumulative effect of change in accounting principle	5,203,900	889,000	14,828,200	6,239,900

Cumulative effect of change in accounting principle (net of taxes of $121,700)	-	-	(198,600)	-

Net income	$5,203,900	$ 889,000	$14,629,600	$ 6,239,900

Basic earnings per common share before accounting change	$0.33	$0.06	$0.94	$0.39

Cumulative effect of change in accounting principle	$ -	$ -	$(0.01)	$ -

Basic earnings per common share	$0.33	$0.06	$0.93	$0.39

Diluted earnings per share before accounting change	$0.31	$0.05	$0.91	$0.38

Cumulative effect of change in accounting principle	$ -	$ -	$(0.01)	-

Diluted earnings per share	$0.31	$0.05	$0.90	$0.38

See accompanying notes to unaudited condensed consolidated financial statements.

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PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES

Condensed Consolidated Statements of Cash Flows

Nine Months Ended September 30, 2003 and 2002

(Unaudited)

	2003	2002
Cash flows from operating activities:
Net income	$14,629,600	$ 6,239,900
Adjustments to net income to reconcile to cash used in operating activities:
Deferred federal income taxes	4,893,200	2,119,400
Depreciation, depletion & amortization	10,632,400	9,083,300
Cumulative effect of change in accounting principle	198,600	-
Accretion of asset retirement obligation	27,000	-
Gain from sale of assets	(144,200)	(10,400)
Leasehold acreage expired or surrendered	1,364,300	595,900
Amortization of stock award	4,100	4,000
Increase in current assets	(7,066,100)	(2,119,700)
Decrease (increase) in other assets	2,087,300	(217,700)
Decrease in current liabilities	(8,746,600)	(26,505,200)
(Decrease) increase in other liabilities	(1,625,200)	445,600

Total adjustments	1,624,800	(16,604,800)

Net provided by (cash used) in operating activities	16,254,400	(10,364,900)

Cash flows from investing activities:
Capital expenditures	(48,194,500)	(9,293,000)
Proceeds from sale of leases	1,040,800	818,700
Proceeds from sale of fixed assets	162,000	10,400

Net cash used in investing activities	(46,991,700)	(8,463,900)

Cash flows from financing activities:
Net proceeds from/(retirement of) long-term debt	21,000,000	(1,800,000)
Repurchase and cancellation of treasury stock	(748,700)	(3,616,300)

Net cash provided by (used in) financing activities	20,251,300	(5,416,300)

Net decrease in cash and cash equivalents	(10,486,000)	(24,245,100)

Cash and cash equivalents, beginning of period	51,023,500	48,175,600

Cash and cash equivalents, end of period	$ 40,537,500	$ 23,930,500

See accompanying notes to unaudited condensed consolidated financial statements.

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PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

September 30, 2003

(Unaudited)

1. Accounting Policies

Reference is hereby made to the Company's Annual Report on Form 10-K for 2002, which contains a summary of significant accounting policies followed by the Company in the preparation of its consolidated financial statements. These policies were also followed in preparing the quarterly report included herein.

2. Stock Compensation

The Company has adopted SFAS No. 123, "Accounting for Stock-Based Compensation," which permits entities to recognize as expense over the vesting period the fair value of all stock-based awards on the date of grant. Alternatively, SFAS 123 allows entities to continue to measure compensation cost for stock-based awards using the intrinsic value based method of accounting prescribed by APB Opinion No. 25, "Accounting for Stock Issued to Employees," and to provide pro forma net income and pro forma earnings per share disclosures as if the fair value based method defined in SFAS 123 had been applied. The Company has elected to continue to apply the provisions of APB 25 and provide the pro forma disclosure provisions of SFAS 123. For stock options granted, the option price was not less than the market value of shares on the grant date, therefore, no compensation cost has been recognized. Had compensation cost been determined under the provisions of SFAS 123, the Company's net income and earnin gs per share would have been the following on a pro forma basis:

Three Months Ended September 30,

Nine Months Ended September 30,

2003

2002

2003

2002

Net income, as reported

$5,203,900

$  889,000

$14,629,600

$6,239,900

Deduct total stock-based employee

  compensation expense determined

  under fair-value-based method

  for all rewards, net of tax

        -

        -

        -

        -

Pro forma net income

$5,203,900

$  889,000

$14,629,600

$6,239,900

Pro forma basic earnings per share

$0.33

$0.06

$0.93

$0.39

Pro forma diluted earnings per share

$0.31

$0.05

$0.90

$0.38

3. Basis of Presentation

The Management of the Company believes that all adjustments (consisting of only normal recurring accruals) necessary to a fair statement of the results of such periods have been made. The results of operations for the nine months ended September 30, 2003 are not necessarily indicative of the results to be expected for the full year.

4. Oil and Gas Properties

Oil and Gas Properties are reported on the successful efforts method.

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5. Earnings Per Share

Computation of earnings per common and common equivalent share are as follows for the three months and nine months ended September 30:

	Three Months Ended September 30,		Nine Months Ended September 30,
	2003	2002	2003	2002

Weighted average common shares outstanding	15,636,787	15,734,767	15,670,092	15,910,711

Weighted average common and
common equivalent shares outstanding	16,294,616	15,942,015	16,186,849	16,209,376

Net income before cumulative effect of change in accounting principle	$ 5,203,900	$ 889,000	$14,828,200	$6,239,900

Cumulative effect of change in accounting principle (net of taxes of $121,700)	-	-	(198,600)	-

Net income	$5,203,900	$ 889,000	$14,629,600	$6,239,900


Basic earnings per common share before accounting change	$0.33	$0.06	$ 0.94	$0.39

Cumulative effect of change in accounting principle	$ -	$ -	$(0.01)	$ -

Basic earnings per common share	$0.33	$0.06	$ 0.93	$0.39

Diluted earnings per share before accounting change	$0.31	$0.05	$ 0.91	$0.38

Cumulative effect of change in accounting principle	$ -	$ -	$(0.01)	$ -

Diluted earnings per share	$0.31	$0.05	$ 0.90	$0.38

6. Business Segments (Thousands)

PDC's operating activities can be divided into three major segments: drilling and development, natural gas and oil sales, and well operations. The Company drills natural gas and oil wells for Company-sponsored drilling partnerships and purchases an interest in each partnership. The Company also engages in oil and gas sales to utilities, marketing companies, commercial and industrial end-users. The Company charges Company-sponsored partnerships and other third parties competitive industry rates for well operations and gas gathering. Segment information for the three and nine months ended September 30, 2003 and 2002 is as follows:

Three Months Ended

  September 30,

Nine Months Ended

   September 30,

2003

2002

2003

2002

REVENUES

  Drilling and Development

$14,080

$ 9,410

$47,444

$43,835

  Natural Gas and Oil Sales

30,774

16,813

89,511

48,129

  Well Operations

1,865

1,475

5,282

4,406

  Unallocated amounts (1)

   489

   451

1,158

1,333

     Total

$47,208

$28,149

$143,395

$97,703

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	Three Months Ended September 30,		Nine Months Ended September 30,
	2003	2002	2003	2002
SEGMENT INCOME BEFORE INCOME TAXES
Drilling and Development	$ 2,124	$ 868	$7,692	$6,724
Natural Gas and Oil Sales	6,305	702	15,999	3,444
Well Operations	721	527	2,172	1,565
Unallocated amounts (2)
General and Administrative expenses	(1,378)	(1,070)	(3,742)	(3,073)
Interest expense	(415)	(400)	(911)	(995)
Other (1)	410	494	922	1,178
Total	$ 7,767	$ 1,121	$ 22,132	$ 8,843

	September 30, 2003	December 31, 2002
SEGMENT ASSETS
Drilling and Development	$ 30,099	$ 31,279
Natural Gas Sales	192,738	162,232
Well Operations	10,838	10,706
Unallocated amounts
Cash	519	1,736
Other	8,068	6,299
Total	$242,262	$212,252

(1) Includes interest on investments and partnership management fees which are not

allocated in assessing segment performance.

(2) Items which are not allocated in assessing segment performance.

7. Comprehensive Income

Comprehensive income includes net income and certain items recorded directly to shareholders' equity and classified as Other Comprehensive Income. The following table illustrates the calculation of comprehensive income for the nine months ended September 30, 2003 and 2002.

2003

2002

Net Income before cumulative effect

of change in accounting principle

$ 14,828,200

$6,239,900

Cumulative effect on prior years of SFAS 143 -

"Accounting for Asset Retirement Obligations"

(net of taxes of $121,700)

   (198,600)

      -

Net income

14,629,600

6,239,900

Other Comprehensive Income (loss) (net of tax):

  Reclassification adjustment for settled

  contracts included in net income (net of tax

  of $603,200 and $49,500, respectively)

984,100

(80,800)

  Change in fair value of outstanding hedging

    positions (net of tax of $108,000 and

    $230,000, respectively)

(176,200)

   (375,300)

Other Comprehensive Income (loss)

  807,900

  (456,100)

Comprehensive Income

$15,437,500

$5,783,800

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8. Commitments and Contingencies

The nature of the independent oil and gas industry involves a dependence on outside investor drilling capital and involves a concentration of gas sales to a few customers. The Company sells natural gas to various public utilities, natural gas marketers, industrial and commercial customers.

The Company would be exposed to natural gas price fluctuations on underlying purchase and sale contracts should the counterparties to the Company's hedging instruments or the counterparties to the Company's gas marketing contracts not perform. Such nonperformance is not anticipated. There were no counterparty default losses in 2003 or 2002.

Substantially all of the Company's drilling programs contain a repurchase provision where Investors may request the Company to repurchase their partnership units at any time beginning with the third anniversary of the first cash distribution. The provision provides that the Company is obligated to purchase an aggregate of 10% of the initial subscriptions per calendar year (at a minimum price of four times the most recent 12 months' cash distributions), only if investors request the Company to repurchase such units, subject to the Company's financial ability to do so. The maximum annual 10% repurchase obligation, if requested by investors, is currently approximately $4.2 million. The Company has adequate liquidity to meet this obligation.

The Company is not party to any legal action that would materially affect the Company's results of operations or financial condition.

9. Common Stock Repurchase

On March 13, 2003 the Company publicly announced the authorization by its Board of Directors to repurchase up to 5% of the Company's common stock (785,000 shares) at fair market value at the date of purchase. Under the program, the Board has discretion as to the dates of purchase and amounts of stock to be purchased and whether or not to make purchases. This program is scheduled to expire on December 31, 2004. The following activity has occurred since inception of the plan on March 13, 2003 until September 30, 2003.

Month of Purchase	March, 2003	April, 2003	September, 2003

Average Price paid per share	$6.08	$6.48	$11.15

Broker/Dealer	McDonald Investments	McDonald Investments	McDonald Investments

Number of Shares Purchased	46,500	49,900	12,800

Remaining Number of Shares to Purchase	738,500	688,600	675,800

10. Change in Accounting Principle

In June 2001, the Financial Accounting Standard Board issued SFAS 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 Company adopted SFAS No. 143 on January 1, 2003 and recorded a net asset of $271,800 and a related liability of $592,100 (using a 6% discount rate) and a cumulative effect on change in accounting principle on prior years of $198,600 (net of taxes of $121,700).

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11. Acquisition of Oil and Gas Properties

During the second quarter of 2003 the Company completed the purchase of natural gas properties in the Denver-Julesburg Basin in northeastern Colorado for $28 million from Williams Production RMT Company, a subsidiary of The Williams Companies, Inc. of Tulsa, OK. The effective date of the purchase was April 1, 2003. Funding for the acquisition was provided from the Company's bank credit facility with Bank One N.A. and BNP Paribas.

The Company estimates the acquisition included approximately 22.6 billion cubic feet (Bcf) of proved developed producing (PDP) and 3.4 Bcf of proved developed non-producing reserves (PDNP) from 166 wells. All of the reserves are natural gas. The acquired property may also include up to 150 additional locations, subject to approval of revised spacing from the State of Colorado. The estimated PDNP reserves are expected to be available through the use of additional equipment to remove produced water from wells, a technique that the Company has already proven successful in a number of the wells purchased.

12. Subsequent Event - Commitments and Contingencies

On October 3, 2003 the Company's Executive Vice President and Chief Financial Officer, Dale G. Rettinger, passed away. The Company had a stock redemption agreement with Mr. Rettinger which required the Company to maintain a life insurance policy on Mr. Rettinger in the amount of $1 million. At the election of his estate made within one year of his death, the Company must utilize the proceeds from the insurance policy to purchase from his estate all or a portion of his shares of the Company's Common Stock owned by him, including shares subject to outstanding stock options owned by him at the time of his death, up to an aggregate purchase price of $1 million. The purchase price for such shares of Common Stock will be based upon the average closing "Ask" price for the Company's Common Stock as quoted by Nasdaq during the preceeding 90 calendar day period. As of this date no purchase request has been made by Mr. Rettinger's estate and no shares or options have been purchased by the Company. In addition, u nder the terms of Mr. Rettinger's employment contract, the Company is obligated to pay Mr. Rettinger's estate a death benefit of approximately $850,000.

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

Results of Operations

Three Months Ended September 30, 2003 Compared with September 30, 2002

Revenues. Total revenues for the three months ended September 30, 2003 were $47.2 million compared to $28.1 million for the three months ended September 30, 2002, an increase of approximately $19.1 million, or 68.0 percent. Such increase was a result of increased drilling revenues, sales from gas marketing activities, oil and gas sales and well operations and pipeline income. Drilling revenues for the three months ended September 30, 2003 were $14.1 million compared to $9.4 million for the three months ended September 30, 2002, an increase of approximately $4.7 million or 50.0 percent. Such increase was due to the drilling backlog at June 30, 2003 along with the early closing of the fully subscribed PDC 2003-B Partnership. Natural gas sales from the marketing activities of Riley Natural Gas (RNG), the Company's marketing subsidiary for the three months ended September 30, 2003 were $17.7 million compared to $11.7 million for the three months ended September 30, 2002, an increas e of approximately $6.0 million or 51.3 percent. Such increase was due to natural gas sold at higher average sales prices offset in part by lower volumes sold. Oil and gas sales from the Company's producing properties for the three months ended September 30, 2003 were $13.1 million compared to $5.1 million for the three months ended September 30, 2002, an increase of $8.0 million or 156.9 percent. The increase was due to significantly increased volumes sold at substantially higher average sales prices of oil and natural gas. The volume of natural gas sold for the three months ended September 30, 2003 was 2.4 million Mcf at an average sales price of $4.55 per Mcf compared to 1.6 million Mcf at an average sales price of $2.35 per Mcf for the three months ended September 30, 2002. Oil sales were 80,000 barrels at an average sales price of $28.42 per barrel for the three months ended September 30, 2003 compared to 51,000 barrels at an average sales price of $26.39 per barrel for the three months ended September 30, 2002. The increase in natural gas volumes was the result of the Company's increased investment in oil and gas properties, primarily the Williams property acquisition, effective April 1, 2003, recompletions of existing wells and the Company's additional investment in wells drilled along with the PDC

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2003-A Partnership. Financial results depend upon many factors, particularly the price of natural gas and our ability to market our production on economically attractive terms. Price volatility in the natural gas market has remained prevalent in the last few years. Natural gas prices declined dramatically at the end of 2001 and during the entire first quarter of 2002. However, in the second quarter of 2002, the Company saw a significant strengthening of natural gas prices in its Appalachian and Michigan producing areas. Natural gas prices in Colorado remained low for most of 2002. In the fourth quarter of 2002 and continuing in 2003, Colorado prices began to increase, although they continue to trail prices in other areas. The Company believes the lower prices in the Rocky Mountain Region, including Colorado, resulted from increasing local supplies that exceeded the local demand and pipeline capacity available to move gas from the region. On May 1st of 2003, the Kern River pipeline expansio n was completed and placed into service. The Kern River Pipeline Company has announced that the additional facilities added about 900 million cubic feet per day of capacity for deliveries to Arizona, Nevada and southern California. This represents almost 30% of the prior pipeline capacity from the region to the West Coast and other markets outside the region. The Company believes that the completion and start-up of the pipeline eliminated or reduced the local supply surplus, leading to improved natural gas prices in the region. Since the startup of the new Kern River pipeline the Colorado Interstate Gas price index has improved to a range of from 83% to over 90% of the NYMEX price, levels consistent with historical price relationships before the recent local demand/pipeline capacity problem. The Company has commodity price hedging contracts for production from October 2003 through December 2004 to protect against possible short-term price weaknesses.

Well operations and pipeline income for the three months ended September 30, 2003 was $1.9 million compared to $1.5 million for the three months ended September 30, 2002, an increase of approximately $400,000 or 26.7 percent. Such increase was due to an increase in the number of wells and pipelines operated by the Company. Other income for the three months ended September 30, 2003 was $488,000 compared to $451,000 for the three months ended September 30, 2002.

Production by area of operations:

	Three Months Ended September 30, 2003			Three Months Ended September 30, 2002
	Oil (Bbl)	Natural Gas (Mcf)	Natural Gas Equivalents (Mcfe)	Oil (Bbl)	Natural Gas (Mcf)	Natural Gas Equivalents (Mcfe)
Appalachian Basin	1,121	485,968	492,694	1,145	525,531	532,401
Michigan Basin	1,616	449,457	459,153	1,887	528,906	540,228
Rocky Mountains	77,367	1,442,556	1,906,758	47,518	566,510	851,618
Total	80,104	2,377,981	2,858,605	50,550	1,620,947	1,924,247

Average Price	$28.42	$4.55	$4.58	$26.39	$2.35	$2.67

Costs and expenses. Costs and expenses for the three months ended September 30, 2003 were $39.4 million compared to $27.0 million for the three months ended September 30, 2002, an increase of approximately $12.4 million or 45.9 percent. Such increase was primarily the result of increased cost of oil and gas well drilling operations, gas purchased for gas marketing activities, and oil and gas production costs. Oil and gas well drilling operations costs for the three months ended September 30, 2003 were $12.0 million compared to $8.5 million for the three months ended September 30, 2002, an increase of approximately $3.5 million or 41.1 percent. Such increase was due to the higher levels of drilling referred to above. The cost of gas marketing activities for the three months ended September 30, 2003 were $17.5 million compared to $11.7 million for the three months ended September 30, 2002, an increase of $5.8 million or 49.6 percent. The increase was due to the significantly higher average prices of natural gas purchased and offset in part by slightly lower volumes. Based on the nature of the Company's gas marketing activities, hedging did not have a significant impact on the Company's net margins from marketing activities during either period. Oil and gas production costs from the Company's producing properties for the three months ended September 30, 2003 were $4.0 million compared to $2.2 million for the three months ended September 30, 2002, an increase of approximately $1.8 million or 81.8% percent. Such increase was due to the increased production costs and severance and property taxes on the increased volumes and higher sales prices of natural gas and oil sold, along with the increased number of wells and pipelines operated by the Company. General and administrative expenses for the three months ended September 30, 2003 increased to $1.4 million compared with $1.1 million for the three months ended September 30, 2002.

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Depreciation, depletion, and amortization costs for the three months ended September 30, 2003 increased to $4.2 million from approximately $3.1 million for the three months ended September 30, 2002. The increase was due to the significantly increased production and investment in oil and gas properties by the Company as referred to above. Interest costs for the three months ended September 30, 2003 were $415,000 compared to $400,000 for the three months ended September 30, 2002.

Net income. Net income for the three months ended September 30, 2003 was $5.2 million compared to a net income of $900,000 for the three months ended September 30, 2002, an increase of approximately $4.3 million.

Nine Months Ended September 30, 2003 Compared with September 30, 2002

Revenues. Total revenues for the nine months ended September 30, 2003 were $143.4 million compared to $97.7 million for the nine months ended September 30, 2002, an increase of approximately $45.7 million, or 46.8 percent. Such increase was a result of increased drilling revenues, sales from gas marketing activities, oil and gas sales and well operations and pipeline income. Drilling revenues for the nine months ended September 30, 2003 were $47.4 million compared to $43.8 million for the nine months ended September 30, 2002, an increase of approximately $3.6 million or 8.2 percent. Such increase was due to increased volume of drilling activity by the Company's drilling programs. Natural gas sales from the marketing activities of Riley Natural Gas (RNG), the Company's marketing subsidiary for the nine months ended September 30, 2003 were $56.6 million compared to $32.1 million for the nine months ended September 30, 2002, an increase of approximately $24.5 million or 76.3 perce nt. Such increase was due to natural gas sold at significantly higher average sales prices offset in part by lower volumes sold. Oil and gas sales from the Company's producing properties for the nine months ended September 30, 2003 were $32.9 million compared to $16.0 million for the nine months ended September 30, 2002, an increase of $16.9 million or 105.6 percent. The increase was due to significantly increased volumes sold at substantially higher average sales prices of oil and natural gas. The volume of natural gas sold for the nine months ended September 30, 2003 was 6.1 million Mcf at an average sales price of $4.46 per Mcf compared to 4.8 million Mcf at an average sales price of $2.49 per Mcf for the nine months ended September 30, 2002. Oil sales were 195,000 barrels at an average sales price of $28.05 per barrel for the nine months ended September 30, 2002 compared to 175,000 barrels at an average sales price of $22.89 per barrel for the nine months ended September 30, 2002. The increase in natural gas volumes was the result of the Company's increased investment in oil and gas properties, primarily the Williams property acquisition, effective April 1, 2003, recompletions of existing wells and the Company's additional investment in wells drilled along with the PDC 2003-A Partnership. Financial results depend upon many factors, particularly the price of natural gas and our ability to market our production on economically attractive terms. Price volatility in the natural gas market has remained prevalent in the last few years. Natural gas prices declined dramatically at the end of 2001 and during the entire first quarter of 2002. However, in the second quarter of 2002, the Company saw a significant strengthening of natural gas prices in its Appalachian and Michigan producing areas. Natural gas prices in Colorado remained low for most of 2002. In the fourth quarter of 2002 and continuing in 2003, Colorado prices began to increase, although they continue to trail prices in other areas. The Company believes the lower prices in the Rocky Mountain Region, including Colorado, resulted from increasing local supplies that exceeded the local demand and pipeline capacity available to move gas from the region. On May 1st of 2003, the Kern River pipeline expansion was completed and placed into service. The Kern River Pipeline Company has announced that the additional facilities added about 900 million cubic feet per day of capacity for deliveries to Arizona, Nevada and southern California. This represents almost 30% of the prior pipeline capacity from the region to the West Coast and other markets outside the region. The Company believes that the completion and start-up of the pipeline eliminated or reduced the local supply surplus, leading to improved natural gas prices in the region. Since startup of the new Kern River pipeline the Colorado Interstate Gas price index has improved to a range of from 83% to over 90% of the NYMEX price, levels consistent with historical price relationships before the recent local demand /pipeline capacity problem. The Company has commodity price hedging contracts for production from October 2003 through December 2004 to protect against possible short-term price weaknesses.

Well operations and pipeline income for the nine months ended September 30, 2003 was $5.3 million compared to $4.4 million for the nine months ended September 30, 2002, an increase of approximately $900,000 or 20.5 percent. Such increase was due to an increase in the number of wells and pipelines operated by the Company. Other income for the nine months ended September 30, 2003 was $1.2 million compared to $1.3 million for the nine months ended September 30, 2002.

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Production by area of operations:

	Nine Months Ended September 30, 2003			Nine Months Ended September 30, 2002
	Oil (Bbl)	Natural Gas (Mcf)	Natural Gas Equivalents (Mcfe)	Oil (Bbl)	Natural Gas (Mcf)	Natural Gas Equivalents (Mcfe)
Appalachian Basin	3,135	1,459,414	1,478,224	3,873	1,573,698	1,596,936
Michigan Basin	4,910	1,382,532	1,411,992	6,492	1,638,702	1,677,654
Rocky Mountains	187,194	3,297,830	4,420,994	164,405	1,604,875	2,591,305
Total	195,239	6,139,776	7,311,210	174,770	4,817,275	5,865,895

Average Price	$28.05	$4.46	$4.50	$22.89	$2.49	$2.73

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Costs and expenses. Costs and expenses for the nine months ended September 30, 2003 were $121.3 million compared to $88.9 million for the nine months ended September 30, 2002, an increase of approximately $32.4 million or 36.4 percent. Such increase was primarily the result of increased cost of oil and gas well drilling operations, gas purchased for gas marketing activities and oil and gas production costs. Oil and gas well drilling operations costs for the nine months ended September 30, 2003 were $39.8 million compared to $37.1 million for the nine months ended September 30, 2002, an increase of approximately $2.7 million or 7.3 percent. Such increase was due to the higher levels of drilling volumes referred to above. The cost of gas marketing activities for the nine months ended September 30, 2003 were $55.9 million compared to $32.2 million for the nine months ended September 30, 2002, an increase of $23.7 million or 73.6 percent. The increase was due to the significantly h igher average purchase prices of natural gas purchased and marketed offset in part by slightly lower volumes purchased for resale. Based on the nature of the Company's gas marketing activities, hedging did not have a significant impact on the Company's net margins from marketing activities during either period. Oil and gas production costs from the Company's producing properties for the nine months ended September 30, 2003 were $10.3 million compared to $6.4 million for the nine months ended September 30, 2002, an increase of approximately $3.9 million or 60.9 percent. Such increase was due to the increased production costs and severance and property taxes on the significantly increased volumes and higher average sales prices of natural gas and oil sold along with the increased number of wells and pipelines operated by the Company. General and administrative expenses for the nine months ended September 30, 2003 increased to $3.7 million compared with $3.1 million for the nine months ended September 30, 2002 an increase of approximately $600,000 or 19.4 percent. Depreciation, depletion, and amortization costs for the nine months ended September 30, 2003 increased to $10.6 million from approximately $9.1 million for the nine months ended September 30, 2002 an increase of approximately $1.5 million or 16.5 percent. . The increase was due to the significantly increased production and investment in oil and gas properties by the Company as referred to above. Interest costs for the nine months ended September 30, 2003 were $911,000 compared to $995,000 for the nine months ended September 30, 2002.

Change in Accounting Principle. The Company adopted SFAS No. 143 "Accounting for Asset Retirement Obligations" on January 1, 2003 and booked the cumulative effect on prior years of $198,600 (net of taxes of $121,700).

Net income. Net income for the nine months ended September 30, 2003 was $14.6 million compared to a net income of $6.2 million for the nine months ended September 30, 2002, an increase of approximately $8.4 million or 135.5 percent.

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Liquidity and Capital Resources

The Company funds its operations through a combination of cash flow from operations, capital raised through drilling partnerships, and use of the Company's credit facility. Operational cash flow is generated by sales of natural gas from the Company's well interests, well drilling and operating activities for the Company's investor partners, natural gas gathering and transportation, and natural gas marketing. Cash payments from Company-sponsored partnerships are used to drill and complete wells for the partnerships, with operating cash flow accruing to the Company to the extent payments exceed drilling costs. The Company utilizes its revolving credit arrangement to meet the cash flow requirements of its operating and investment activities.

Natural gas and oil prices have been unusually volatile for the past few years, and the Company anticipates continued volatility in the future. Currently, the NYMEX futures reflect a market expectation of gas prices at Henry Hub close to or above record prices per million Btu's (Mmbtu). These prices look strong for the remainder of the year although natural gas storage levels are near normal levels following a period when storage levels had been at a five-year low. The Company believes this situation creates the possibility of both periods of low prices and continued high prices.

In 2001, 2002 and earlier this year Colorado gas prices were adversely affected by an increase in the negative "basis" between NYMEX and Colorado prices. In the past, natural gas produced by the Company in Colorado has sold for 10-20% less than the Company's prices received in the Michigan and Appalachian basins, but the Company's Colorado development costs have been less than the costs per Mcfe of development in the Michigan and Appalachian basins. Pipeline capacity from the area to major markets in California and the Midwest was not adequate to move the new supplies developed over the past several years by oil and gas companies when local demand was at low summer levels. The result was lower prices and some limited curtailment of production during the summer months. Higher winter demand by local Rocky Mountain markets improved gas prices during the first three quarters of 2003, and the recent start-up of the Ker