SECURITIES AND EXCHANGE COMMISSION

FORM 10-K

þ Annual Report Pursuant to Section 13 or 15 (d)
of the Securities Exchange Act of 1934

For the fiscal year ended December 31, 2004

o 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 – 13305

PARALLEL PETROLEUM CORPORATION

Registrant’s Telephone Number, Including Area Code: (432) 684-3727

Securities Registered Pursuant to Section 12(b) of the Act: None

Securities Registered Pursuant to Section 12(g) of the Act:

Common Stock, $.01 par value
Common Stock Purchase Warrants
Rights to Purchase Series A Preferred Stock
(Title of Class)

     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 þ                           No o

     Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. þ

     Indicate by check mark whether the registrant is an accelerated filer (as defined in Exchange Act Rule 12b-2).

Yes þ                           No o

     The aggregate market value of voting and non-voting common equity held by non-affiliates of the Registrant as of June 30, 2004 was approximately $116,087,075, based on the closing price of the common stock on the same date.

     At March 1, 2005 there were 31,189,292 shares of common stock outstanding.

FORM 10-K

PARALLEL PETROLEUM CORPORATION

TABLE OF CONTENTS

(i)

Cautionary Statement Regarding Forward Looking Statements

     Some statements contained in this Annual Report on Form 10-K are “forward-looking statements”. These forward looking statements relate to, among others, the following:

	•	our future financial and operating performance and results;
	•	our business strategy;
	•	market prices;
	•	sources of funds necessary to conduct operations and complete acquisitions;
	•	development costs;
	•	number and location of planned wells;
	•	our future commodity price risk management activities; and
	•	our plans and forecasts.

We have based these forward-looking statements on our current assumptions, expectations and projections about future events.

     We use the words “may,” “will,” “expect,” “anticipate,” “estimate,” “believe,” “continue,” “intend,” “plan,” “budget,” “present value,” “future” or “reserves” and other similar words to identify forward-looking statements. These statements also involve risks and uncertainties that could cause our actual results or financial condition to materially differ from our expectations. We believe the assumptions and expectations reflected in these forward-looking statements are reasonable. However, we cannot give any assurance that our expectations will prove to be correct or that we will be able to take any actions that are presently planned. All of these statements involve assumptions of future events and risks and uncertainties. Risks and uncertainties associated with forward-looking statements include, but are not limited to:

	•	fluctuations in prices of oil and gas;
	•	demand for oil and natural gas;
	•	losses due to potential or future litigation;
	•	future capital requirements and availability of financing;
	•	geological concentration of our reserves;
	•	risks associated with drilling and operating wells;
	•	competition;
	•	general economic conditions;

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•

governmental regulations;

	•	receipt of amounts owed to us by purchasers of our production and counterparties to our hedging contracts;
	•	hedging decisions, including whether or not to hedge;
	•	events similar to 911;
	•	actions of third party co-owners of interests in properties in which we also own an interest; and
	•	fluctuations in interest rates and availability of capital.

     For these and other reasons, actual results may differ materially from those projected or implied. We believe it is important to communicate our expectations of future performance to our investors. However, events may occur in the future that we are unable to accurately predict, or over which we have not control. We caution you against putting undue reliance on forward-looking statements or projecting any future results based on such statements.

     Before you invest in our common stock, you should be aware that there are various risks associated with an investment. We have described some of these risks in other sections of this Annual Report on Form 10-K and under “Risks Related to Our Business” beginning on page 20.

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PART I

About Our Company

     Parallel Petroleum Corporation and its subsidiaries are engaged in the acquisition, development and exploitation of long life oil and natural gas reserves and, to a lesser extent, the exploration for new oil and natural gas reserves. Our current producing properties are in the:

	•	Permian Basin of west Texas and New Mexico;
	•	Liberty County in east Texas; and
	•	the onshore Gulf Coast area of south Texas.

     In addition, we are actively evaluating, leasing, drilling and preparing to drill on new projects located in the Abo gas trend of New Mexico, the Barnett Shale gas trend of the Fort Worth Basin, the Cotton Valley Reef trend of east Texas and the Uinta Basin of Utah.

     In 2004, we spent approximately $67.9 million on oil and gas related capital expenditures, an increase of approximately 348% over that expended in 2003 (See Note 3 to the consolidated financial statements). This amount includes approximately $37.4 million of acquisition costs for properties we acquired during the period from September, 2004 to December, 2004. In September and October 2004, we acquired additional non-operated working interests in properties located in Andrews County, Texas for a total of $20.9 million. In October and December 2004, we acquired properties in Andrews and Gaines counties, Texas for approximately $16.5 million. In January 2005 we acquired additional interests in the Andrews and Gaines properties we acquired in October and December 2004. The net purchase price for these additional interests was approximately $1.5 million.

     Throughout this report, we refer to some terms that are commonly used and understood in the oil and gas industry. These terms are:

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     Parallel was incorporated in Texas on November 26, 1979, and reincorporated in the State of Delaware on December 18, 1984.

     Our executive offices are located at 1004 N. Big Spring, Suite 400, Midland, Texas 79701. Our telephone number is (432) 684-3727.

Available Information

     You may read and copy any materials we file with, or furnish to, the Securities and Exchange Commission at the SEC’s Public Reference Room at 450 Fifth Street, NW, Washington, DC 20549. You may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. The SEC maintains an Internet site (http://www.sec.gov) that contains reports, proxy and information statements, and other information regarding issuers, including Parallel, that file electronically with the SEC.

     Our website address is http://www.plll.com. Information on our website or any other website is not incorporated by reference into this Annual Report on Form 10-K and does not constitute a part of this Annual Report on Form 10-K.

     We make available free of charge on our Internet website our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 as soon as reasonably practicable after we electronically file such material with, or furnish it to, the SEC.

     We will provide electronic or paper copies of our SEC filings free of charge upon request made to: Cindy Thomason, Manager of Investor Relations, cindyt@plll.com, 1-800-299-3727.

Recent Developments

     From September 2004 through January 18, 2005, we effected a series of oil and gas property acquisitions in Andrews and Gaines counties, Texas for an aggregate net purchase price of approximately $38.9 million. Cawley Gillespie & Associates, Inc., our independent petroleum engineers, estimated that the recently acquired properties (excluding the properties acquired after December 31, 2004) contain aggregate proved reserves of approximately 5.19 MMBoe with estimated future net cash flows, discounted at an annual rate of 10%, of approximately $60.9 million at December 31, 2004.

     Our 2005 capital investment budget for properties we owned at March 1, 2005 is estimated to be approximately $43.7 million, which includes $7.0 million for the purchase of

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leasehold and seismic in our areas of activity. The budget will be funded from our estimated operating cash flows, which is based on anticipated commodity prices and forecasted production volumes, bank borrowings and equity proceeds. The amount and timing of expenditures are subject to change based upon market conditions, results of expenditures, new opportunities and other factors.

     On February 9, 2005, we sold 5,750,000 shares of common stock, $.01 par value per share, in a public offering at a price of $5.27 per share. Gross proceeds were $30.3 million, and net proceeds were approximately $28.0 million. The common shares were issued under our $100.0 million universal shelf registration statement on Form S-3 which became effective in November 2004.

Proved Reserves as of December 31, 2004

     Cawley Gillespie & Associates, Inc. estimated the total proved reserves attributable to all of our oil and gas properties to be 18.9 million Bbls of oil and 16.8 Bcf of natural gas as of December 31, 2004. Based on oil and gas prices at December 31, 2004 and current operating and development costs, the present value of our pretax future net revenues from these properties, discounted at 10%, was estimated to be approximately $266.2 million as of December 31, 2004.

     Approximately 87% of our proved reserves are oil and approximately 86% are categorized as proved developed reserves.

About Our Strategy and Business

     From 1993 until mid 2002, our activities were concentrated in the onshore gulf coast area of south Texas. In June, 2002 we reexamined and revised our business strategy. We shifted the balance of our investments from properties having high rates of production in early years to properties with more consistent production over a longer term. We now emphasize reducing drilling risks by dedicating a smaller portion of our capital to high risk projects, while reserving the majority of our available capital for exploitation, enhancement and development drilling opportunities. Obtaining positions in long-lived oil and gas reserves is given priority over properties that might provide more cash flow in the early years of production, but which have shorter reserve lives. Our risk reduction efforts also include emphasizing acquisition possibilities over high risk exploration projects.

     Since the latter part of 2002, we have reduced the emphasis on high risk exploration efforts and we now focus on established geologic trends where we can utilize the engineering, operational, financial and technical expertise of our entire staff. Although we will continue to participate in exploratory drilling activities from time to time, reducing financial, reservoir, drilling and geological risks and diversifying our property portfolio are the principal criteria in the execution of our business plan.

     In summary, our current business plan:

	•	focuses on projects having less geological risk;
	•	emphasizes exploitation and enhancement activities;

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	•	focuses on acquiring producing properties; and
	•	expands the scope of our operations by diversifying our exploratory and development efforts, both in and outside of our current areas of operation.

     An integral part of our business strategy includes exploitation and enhancement activities. Exploitation and enhancement activities include:

	•	operational enhancements, such as surface facility reconfiguration, and the installation of new or additional compression equipment;
	•	workovers;
	•	well recompletions;
	•	behind-pipe recompletions;
	•	refracing (restimulating a producing formation within an existing wellbore to enhance production and add reserves);
	•	installation of injection wells and related facilities;
	•	development well drilling (infill drilling);
	•	cost reduction programs; and
	•	secondary recovery operations, including waterfloods.

     When we initiate exploitation and enhancement activities on our existing producing properties, we first establish and maintain an ongoing program of oil and gas well reviews with the objective of maximizing the output of existing wells. Oil and gas wells usually generate their highest volumes during the earlier stages of production after which production begins to decline. Enhancement and remedial work can be undertaken to restore varying amounts of the lost production or reduce the rate of production decline.

     Our approach to producing property acquisitions, and the size and timing of any acquisition, is dependent upon market conditions in the domestic oil and gas industry. Generally, during periods of moderate to high prices for oil and gas, we believe that oil and gas acquisition opportunities are not as favorable to a prospective purchaser as they are when market conditions are depressed.

     Producing properties that we identify and attempt to acquire will include properties that have proved undeveloped and behind-pipe reserves, operational enhancement potential, long-lived reserves, multiple pay-zone exploitation and development drilling opportunities, and the potential for operating control. Selecting and acquiring producing properties having these characteristics will diversify and improve the quality of our property portfolio.

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     Although purchases of producing properties involve less risk than drilling, there is a risk that estimates of future prices or costs, reserves, production rates or other criteria upon which we have based our investment decision may prove to be inaccurate.

     In addition to acquisitions of producing properties, our business strategy also includes seeking opportunities to negotiate and enter into work to earn, joint venture and similar agreements with third parties for development operations on producing properties.

     Our sources for possible acquisitions of leases and prospects include independent landmen, independent oil and gas operators, geologists and engineers. We also evaluate properties that become available for purchase. If our review of an undeveloped lease or prospect or a producing property indicates that it may have geological characteristics favorable for 3-D seismic analysis, we may decide to acquire a working interest in the property or an option to acquire a working interest. In the case of producing properties, we also seek properties that we believe are underperforming relative to their potential. To reduce our financial exposure in any one prospect, we may enter into co-ownership arrangements with third parties. These arrangements are common in the industry and enable us to participate in more prospects and share the drilling and related costs and dry-hole risks with other participants. From time to time, we sell prospects to third parties or farm-out prospects and retain an interest in revenues from these prospects.

     As we have in the past, we will continue to:

     (1)  Use Advanced Technologies. We believe the use of 3-D seismic surveys and other advanced technologies provides us with a risk management tool. We believe that our use of these technologies in exploring for and developing oil and gas properties can:

	•	reduce drilling risks;
	•	lower finding costs;
	•	provide for more efficient production of oil and natural gas from our properties; and
	•	increase the probability of locating reserves that might not otherwise be discovered.

     Generally, 3-D seismic surveys provide more accurate and comprehensive information to evaluate drilling prospects than conventional 2-D seismic technology. We evaluate substantially all of our exploratory prospects using 3-D seismic technology. On some exploratory prospects, we also use amplitude versus offset, or AVO analysis. AVO analysis shows the high contrast between sands and shales and assists in determining the presence of natural gas in potential reservoir sands.

     We believe that using 3-D seismic, AVO and other technologies gives us a competitive advantage because of the increased likelihood of successful drilling. When we evaluate exploratory prospects in geographical areas where the use of 3-D seismic and other advanced technologies are not likely to provide any advantages, we use traditional evaluation methods, such as 2-D seismic technology.

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     (2)  Serve as Geophysical Operator. We prefer to serve as the geophysical operator on projects located in areas where we have experience using 3-D seismic technology. By doing so, we control the design, acquisition, processing and interpretation of 3-D surveys and, in most cases, determine drilling locations and well depths. The integrity of 3-D seismic analysis in our projects is enhanced by emphasizing quality controls throughout the data acquisition, processing and interpretation phases.

     We retain experienced outside consultants and participate with knowledgeable joint working interest owners when we acquire, process and interpret 3-D seismic surveys. When possible, we also attempt to correlate or model the interpretations of 3-D seismic surveys with wells previously drilled on or near the prospect being evaluated.

     (3) Conduct Exploratory Activities. Although we do not intend to emphasize exploratory drilling to the extent we have in the past, when we do undertake exploratory projects, we will continue to focus on prospects:

	•	having known geological and reservoir characteristics;
	•	being in close proximity to existing wells so data from the existing wells can be correlated with seismic data on or near the prospect being evaluated; and
	•	having a potentially meaningful impact on our reserves.

     When economic conditions are favorable and when we have sufficient capital resources, we believe we can maximize the value of our properties by accelerating drilling activities. This provides us an opportunity to replace reserves at a more rapid pace than existing reserves are produced.

Drilling Activities in 2004

     The following table shows our drilling activities, by geographic area, during 2004.

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     From 1993 until mid 2002, we concentrated our activities in the Yegua/Frio/Wilcox gas trends in the onshore Gulf Coast area of south Texas in Dewitt, Jackson, Lavaca, Victoria and Wharton Counties. Substantially all of our drilling success in south Texas has been in the Yegua/Frio gas trend and we intend to continue drilling additional lower risk 3-D seismic development wells in this trend. Although the successful wells we drilled in the Yegua/Frio trend provided quick payouts of our drilling and completion costs, the reserve lives of the properties in this area have proven to be very short as compared to our properties in the Permian Basin.

     As we announced in October 2003, consistent with our strategy of reducing geologic risk, we began to diversify our exploration efforts into other oil and gas trends. However, and as planned, the majority of our drilling in 2004 was in south and east Texas.

     We believe we can more fully develop our existing producing properties in the Permian Basin of west Texas, which have been proven by previous drilling. Collectively, our Permian Basin properties include approximately 39,000 gross (27,000 net) developed acres, which will provide significant exploitation and development opportunities for both oil and gas. Additionally, our Permian Basin properties have longer reserve lives than our South Texas properties. Our exploitation and enhancement efforts are conducted primarily on our properties in the Permian Basin of west Texas. We own working interests in these properties ranging from 6.25% to 100%.

     During 2004, our Permian Basin activities included:

	•	producing property acquisitions;
	•	recompleting existing wellbores;
	•	restimulating producing reservoirs;
	•	identifying potential infill drilling locations;
	•	making mechanical improvements to surface facilities and downhole equipment; and
	•	reviewing the feasibility of applying new drilling and production technologies that could either improve recovery potential or result in the discovery of a new reservoir.

     As part of our remedial and enhancement operations in the Permian Basin, we routinely review the performance and economics of our oil and gas properties and, from time to time, we may also renegotiate gas purchase contracts or reconfigure gathering lines. When necessary, we take corrective action, such as:

	•	shutting in temporarily uneconomic properties;
	•	plugging wells we believe to be permanently impaired or depleted;
	•	terminating oil and gas leases that are uneconomic under existing operating conditions; and/or

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•

selling properties to third parties.

Drilling and Acquisition Costs

     The table below shows our oil and gas property acquisition, exploration and development costs for the periods indicated.

Capital Investments for 2005

     Our 2005 capital investment budget for properties we owned at March 1, 2005 is estimated to be approximately $43.7 million, which includes $9.6 million for the purchase of leasehold, seismic and other in our areas of activity. The budget will be funded from our estimated operating cash flows, which is based on anticipated commodity prices and forecasted production volumes, bank borrowings and equity proceeds. The amount and timing of expenditures are subject to change based upon market conditions, results of expenditures, new opportunities and other factors.

     On a geographic basis, approximately 72.8% of our projected 2005 capital investment program will be directed toward oil and gas reserves in the Permian Basin, 6.6% to gas reserves in east Texas and in the onshore Gulf Coast area of south Texas, 17.4% for north Texas Barnett Shale gas project, and 3.2% to other projects.

Permian Basin of West Texas

     The Permian Basin of west Texas generated approximately 69% of our 2004 production and represents approximately 90% of our reserve value as of December 31, 2004. Our significant producing properties in the Permian Basin are described below.

Fullerton San Andres Field, Andrews County, Texas – This property generates approximately 44% of our current daily production and represents approximately 48% of our total proved reserve value as of December 31, 2004.

This non-operated property was acquired in December 2002 for approximately $46.1

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million. During the fourth quarter of 2004, we acquired additional interests in the property for approximately $20.9 million. Development since the initial acquisition in 2002 has primarily consisted of the re-stimulation of approximately 80 existing producing wells and the drilling of six new producing wells.

We have budgeted approximately $3.7 million to fund the drilling and completion of 13 new infill wells in the field in 2005. Our average working interest in the Fullerton properties is approximately 82%.

Carm-Ann San Andres Field / N. Means Queen Unit, Andrews & Gaines Counties, Texas – These properties generate approximately 5% of our current daily production and represent approximately 11% of our total proved reserve value as of December 31, 2004.

In the fourth quarter 2004 and in 2005, we acquired producing properties in the Carm-Ann Andres and North Queen Unit located in Andrews and Gaines Counties, Texas. The combined aggregate net purchase price was approximately $18.7 million. The properties include 25 leases covering 5,360 gross contiguous acres, with 67 gross producing oil and natural gas wells. This acquisition established a new core operating area that is located within 50 miles of our Midland, Texas, headquarters.

We have budgeted approximately $4.1 million for the Carm-Ann / N. Means Queen properties in 2005 for 22 workovers and 13 new infill wells. Our average working interest in these properties is approximately 77%.

Diamond M Shallow Leases, Scurry County, Texas – This property generates approximately 4% of our current daily production and represents approximately 13% of our total proved reserve value as of December 31, 2004.

Development activity on this project during 2004 consisted primarily of the drilling of 12 new producing wells and 18 new injection wells.

We have budgeted a total of $5.0 million in 2005 to fund 16 workovers and well conversions in this project throughout the year and for a 15-well development drilling program during the fourth quarter of 2005, pending satisfactory waterflood response. Our average working interest in these properties is approximately 66%.

Diamond M Canyon Reef Unit, Scurry County, Texas – This property generates approximately 4% of our current daily production and represents approximately 9% of our total proved reserve value as of December 31, 2004.

We assumed operations of this project in March 2003. Field activity has primarily consisted of facility upgrades, geophysical testing, and the reactivation (workover) of two existing wells during the fourth quarter of 2004.

A total of $9.4 million has been budgeted in 2005 to fund the workover of 24 wells, the drilling of 3 new wells, the acquisition of a new 3-D seismic survey and associated equipment upgrades. Our average working interest in these properties is approximately 66%.

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New Mexico Abo Gas Project – This project generates less than 1% of our current daily production and represents less than 1% of our total proved reserve value as of December 31, 2004.

This project consists of two areas in which the primary target is the Abo formation at a depth of approximately 5,000 feet. The Abo formation is a known natural gas-producing reservoir but historically has been marginally economic due to low per-well producing rates and low natural gas prices. We believe this project’s reservoir can be more efficiently exploited through the application of new horizontal drilling and hydraulic fracture stimulation technologies.

We have budgeted approximately $7.6 million for the New Mexico properties in 2005 for 3 re-entries, 6 new wells, and additional leasehold acquisitions.

Area 1 of our Abo Gas Project consists of approximately 60,000 gross (4,800 net) acres. Our base working interest in this area is approximately 8.5%. Since December 2003, we have participated in the drilling of six non-operated Abo horizontal gas wells. Three wells are currently producing to sales. One well, which went to sales in June 2004, is producing approximately 1,000 gross Mcf of gas per day, and the other two wells are each producing approximately 100 gross Mcf of gas per day. The other three wells are currently testing. We believe the two lesser producing wells are performing in a manner similar to historical vertical wells rather than efficiently completed horizontal wells. Refinement of the completion process is ongoing.

We also have, within Area 1, an approximate 20% working interest in one non-operated well. The well has been drilled, fracture-stimulated and is currently producing.

Area 2 of our Abo Gas Project consists of undeveloped leasehold interests in approximately 61,000 gross (25,500 net) acres, is contiguous to Area 1, and will be operated by Parallel. We expect the commencement of drilling operations in Area 2 to begin in early 2005 and will utilize well completion information gained from experience in Area 1. We own an 85.0% working interest in this area.

The estimated cost to drill and complete a horizontal well is approximately $1.6 million. Based upon the results of the initial wells drilled, we believe this project has the potential to become a multi-well, long-life gas project that will be developed over the next three to five years.

Other Permian Basin Projects – Other Permian Basin projects generate approximately 12% of our current daily production and represent approximately 9% of our total proved reserve value as of December 31, 2004.

We have budgeted approximately $2.0 million for other Permian Basin properties in 2005, primarily for lease and well equipment and capitalized overhead.

Onshore Gulf Coast of South Texas

Yegua/Frio Gas Project, Jackson and Wharton Counties, Texas – This project

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generates approximately 23% of our current daily production and represents approximately 9% of our total proved reserve value as of December 31, 2004.

We have budgeted approximately $0.9 million for the Yegua/Frio gas project in 2005, for the drilling and completion of 3 wells.

Cook Mountain Gas Project, Liberty County, Texas – This project generates approximately 8% of our current daily production and represents approximately 1% of our total proved reserve value as of December 31, 2004.

We have budgeted approximately $0.9 million for the Cook Mountain gas project in 2005 for the drilling and completion of 3 wells.

North Texas

Barnett Shale Gas Project, Tarrant County, Texas – Our development of this project is expected to begin in the first quarter of 2005. This project does not yet contribute to our current daily production or reserve value.

Our Barnett Shale gas project is located east of downtown Ft. Worth, in Tarrant County, Texas, between the Newark East Barnett Shale gas field to the north in Tarrant County and the Cleburne Barnett Shale gas field to the south in Johnson County. Our current leasehold position in the project is approximately 5,000 gross (1,400 net) acres.

Having assembled pipeline right-of-way and permits necessary to complete a gas gathering infrastructure, Parallel and a Dallas based operator spudded, on March 9, 2005, a horizontal well, the Brentwood No. 1. Our working interest in this well is 40%.

We are currently participating in the Parrot #1 horizontal well, which is operated by a Ft. Worth based operator. This well is located on leasehold contiguous to our 5,000 gross-acre leasehold position. The well is currently shut-in waiting on pipeline. Our working interest in this well is 20%.

The estimated cost to drill and complete a horizontal well is approximately $2.0 million. Based upon the results of the initial wells drilled we believe this project has the potential to become a multi-well, long-life gas project that will be developed over the next three to five years.

We have budgeted approximately $7.6 million for the Barnett Shale gas project in 2005 for the drilling and completion of 7 new wells, pipeline construction and leasehold acquisition.

Other Projects

Utah/Colorado CBM (Coal Bed Methane) Gas/Conventional Oil and Gas Projects – Our development of this project is expected to begin in the first half of 2005. This project does not yet contribute to our current daily production or reserve value.

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We have increased our leasehold acreage position in this project to approximately 138,000 gross acres. It is a multiple zone project consisting of both oil and gas targets at a depth of less than 6,000 feet. Seismic and geological data evaluation on this project continues. We expect to drill a test well during the first half of 2005.

We have budgeted approximately $1.4 million for the Utah/Colorado CBM gas project in 2005 for the drilling and completion of 1 well, seismic and leasehold acquisition, and multiple core test holes for coal-bed methane potential. We own and operate 100% of this project.

East Texas Cotton Valley Reef Gas Project – This project does not yet contribute to our current daily production or reserve value.

This 3-D seismic gas project is a higher risk profile than our other projects. The objective is the Cotton Valley barrier reef facies found between depths of 16,000 and 18,000 feet. The project consists of approximately 5,000 gross (650 net) acres.

In 2004, the first well was drilled to a total depth of 18,100 feet, finding a non-porous Cotton Valley Reef interval. The operator is currently attempting completion in shallower zones. The operator is also re-evaluating seismic to help determine other drilling locations with optimal porosity potential.

We have budgeted approximately $1.1 million for the Cotton Valley Reef gas project in 2005 for the drilling of 1 well and additional leasehold acquisition. We own an approximate 13.125% working interest in this project.

Oil and Natural Gas Prices

     Our revenues, profitability and cash flows are highly dependent on the prices we receive for our oil and natural gas. Generally, oil and natural gas prices improved and stabilized during the period from mid-2000 to the third quarter of 2001, when prices began to decline. During the first quarter of 2002, prices began to increase again and this upward trend in price has continued.

     The average prices we received for the oil and natural gas we produced in 2004, 2003, and 2002 are shown in the table below.

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     The average price we received for our oil sales at March 1, 2005 was approximately $40.69 per Bbl, excluding our hedging activities. At the same date, the average price we were receiving for our natural gas was approximately $6.60 per Mcf, excluding our hedging activities.

     There is substantial uncertainty regarding future oil and gas prices and we can provide no assurance that prices will remain at current levels. We have entered into hedge contracts in an attempt to reduce the risk of fluctuating oil and gas prices and interest rates.

     In 2004, approximately 62% of our production was oil and 38% was natural gas. The majority of the oil production is from our Permian Basin long life oil assets. The majority of the gas production is from our Gulf coast short life assets.

Employees

     In 2004, we added five new employees. At March 1, 2005, we had twenty-eight full time employees. Mr. Cambridge serves in the capacity of a consultant and not as a full-time employee. Parallel also retains independent land, geological, geophysical and engineering consultants and expects to continue to do so in the future. Additionally, Parallel retains five contract pumpers on a month-to-month basis.

     We consider our employee relations to be satisfactory. None of our employees are represented by a union and we have not experienced work stoppages or strikes.

Wells Drilled

     The following table shows certain information concerning the number of gross and net wells we drilled during the three-year period ended December 31, 2004.

     All of our drilling is performed on a contract basis by third-party drilling contractors. We do not own any drilling equipment.

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     At March 1, 2005, we were participating in the completion of 7 gross (.89 net) gas wells in Hemphill, Jackson, Leon, Liberty and Tarrant Counties, Texas and Eddy County, New Mexico.

Volumes, Prices and Lifting Costs

     The following table shows certain information about our oil and natural gas production, average sales prices per Mcf of gas and Bbl of oil and the average lifting cost per BOE for the three-year period ended December 31, 2004.

     The following summarizes our revenue for each of the three years ended December 31 by product sold.

     Our oil sales in 2004 represented approximately 64% of our combined oil and gas sales for the year ended December 31, 2004, as compared to 50% in 2003.

Markets and Customers

     Our oil and natural gas production is sold at the well site on an as produced basis at market- related prices in the areas where the producing properties are located. We do not refine or process any of the oil or natural gas we produce and all of our production is sold to unaffiliated purchasers on a month-to-month basis.

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     In the table below, we show the purchasers that accounted for 10% or more of our revenues during the specified years.

     We do not believe the loss of any one of our purchasers would materially affect our ability to sell the oil and natural gas we produce. Other purchasers are available in our areas of operations.

     Our future ability to market our oil and natural gas production depends upon the availability and capacity of gas gathering systems and pipelines and other transportation facilities. We do not currently own or operate our own pipelines or transportation facilities. We are dependent on third parties to transport our products.

     We are not obligated to provide a fixed and determinable quantity of oil or natural gas under any existing arrangements or contracts.

     Our business does not require us to maintain a backlog of products, customer orders or inventory.

Office Facilities

     Our principal executive offices are located in Midland, Texas, where we lease approximately 21,640 square feet of office space at 1004 North Big Spring, Suite 400, Midland, Texas 79701. Our current rental rate is $13,074 per month. The lease expires August 31, 2006.

     We have two field offices and storage facilities. These two offices are located in Andrews and Snyder, Texas. The current monthly rental rate is $750 for the Andrews office and $1,200 for the Snyder office. The Andrews office lease expires December 1, 2007. The Snyder office lease expires upon the termination of our trade agreement with the prior operator. We are unable to predict when this agreement will terminate, but we anticipate that it will remain in effect for the life of the properties covered by the agreement.

Competition

     The oil and natural gas industry is highly competitive, particularly in the areas of acquiring exploration and development prospects and producing properties. The principal means of competing for the acquisition of oil and natural gas properties are the amount and terms of the consideration offered. Our competitors include major oil companies, independent oil and gas

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firms and individual producers and operators. Many of our competitors have financial resources, staffs and facilities much larger than ours.

     We are also affected by competition for drilling rigs and the availability of related equipment. With relatively high oil and natural gas prices, the oil and gas industry typically experiences shortages of drilling rigs, equipment, pipe and qualified field personnel. We are unable to predict when or to what extent our exploration and development activities will be affected by rig, equipment or personnel shortages.

     Intense competition among independent oil and natural gas producers requires us to react quickly to available exploration and acquisition opportunities. We try to position for these opportunities by maintaining:

	•	adequate capital resources for projects in our primary areas of operations;
	•	the technological capabilities to conduct a thorough evaluation of a particular project; and
	•	a small staff that can respond quickly to exploration and acquisition opportunities.

     The principal resources we need for acquiring, exploring, developing, producing and selling oil and natural gas are:

	•	leasehold prospects under which oil and natural gas reserves may be discovered;
	•	drilling rigs and related equipment to explore for such reserves; and
	•	knowledgeable and experienced personnel to conduct all phases of oil and natural gas operations.

Oil and Gas Regulations

     Our operations are regulated by certain federal and state agencies. Oil and natural gas production and related operations are or have been subject to:

	•	price controls;
	•	taxes; and
	•	environmental and other laws relating to the oil and gas industry.

     We cannot predict how existing laws and regulations may be interpreted by enforcement agencies or court rulings, whether additional laws and regulations will be adopted, or the effect such interpretations or new laws and regulations may have on our business, financial condition or results of operations.

     Our oil and natural gas exploration, production and related operations are subject to extensive rules and regulations that are enforced by federal, state and local agencies. Failure to

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comply with these rules and regulations can result in substantial penalties. The regulatory burden on the oil and natural gas industry increases our cost of doing business and affects our profitability. Because these rules and regulations are frequently amended or reinterpreted, we are not able to predict the future cost or impact of compliance with these laws.

     Texas and many other states require drilling permits, bonds and operating reports. Other requirements relating to the exploration and production of oil and natural gas are also imposed. These states also have statutes or regulations addressing conservation matters, including provisions for:

	•	the unitization or pooling of oil and gas properties;
	•	the establishment of maximum rates of production from oil and gas wells; and
	•	the regulation of spacing, plugging and abandonment of wells.

     Sales of natural gas we produce are not regulated and are made at market prices. However, the Federal Energy Regulatory Commission regulates interstate and certain intrastate gas transportation rates and services conditions, which affect the marketing of our natural gas, as well as the revenues we receive for sales of our production. Since the mid-1980s, FERC has issued a series of orders, culminating in Order Nos. 636, 636-A, 636-B and 636-C. These orders, commonly known as Order 636, have significantly altered the marketing and transportation service, including the unbundling by interstate pipelines of the sales, transportation, storage and other components of the city-gate sales services these pipelines previously performed.

     One of FERC’s purposes in issuing the orders was to increase competition in all phases of the gas industry. Order 636 and subsequent FERC orders issued in individual pipeline restructuring proceedings has been the subject of appeals, the results of which have generally been supportive of the FERC’s open-access policy. In 1996, the United States Court of Appeals for the District of Columbia Circuit largely upheld Order No. 636. Because further review of certain of these orders is still possible, and other appeals remain pending, it is difficult to predict the ultimate impact of the orders on Parallel and our gas marketing efforts. Generally, Order 636 has eliminated or substantially reduced the interstate pipelines’ traditional role as wholesalers of gas, and has substantially increased competition and volatility in gas markets. While significant regulatory uncertainty remains, Order 636 may ultimately enhance our ability to market and transport our gas, although it may also subject us to greater competition.

     Sales of oil we produce are not regulated and are made at market prices. The price we receive from the sale of oil is affected by the cost of transporting the product to market. Effective January 1, 1995, FERC implemented regulations establishing an indexing system for transportation rates for interstate common carrier oil pipelines, which, generally, would index such rates to inflation, subject to certain conditions and limitations. These regulations could increase the cost of transporting oil by interstate pipelines, although the most recent adjustment generally decreased rates. These regulations have generally been approved on judicial review. We are unable to predict with certainty what effect, if any, these regulations will have on us. The regulations may, over time, tend to increase transportation costs or reduce wellhead prices for oil.

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     We are required to comply with various federal and state regulations regarding plugging and abandonment of oil and gas wells.

Environmental Regulations

     Various federal, state and local laws and regulations governing the discharge of materials into the environment, or otherwise relating to the protection of the environment, health and safety, affect our operations and costs. These laws and regulations sometimes:

	•	require prior governmental authorization for certain activities;
	•	limit or prohibit activities because of protected areas or species;
	•	impose substantial liabilities for pollution related to our operations or properties; and
	•	provide significant penalties for noncompliance.

     In particular, our exploration and production operations, our activities in connection with storing and transporting oil and other liquid hydrocarbons, and our use of facilities for treating, processing or otherwise handling hydrocarbons and related exploration and production wastes are subject to stringent environmental regulations. As with the industry generally, compliance with existing and anticipated regulations increases our overall cost of business. While these regulations affect our capital expenditures and earnings, we believe that they do not affect our competitive position in the industry because our competitors are also affected by environmental regulatory programs. Since environmental regulations have historically been subject to frequent change, we cannot predict with certainty the future costs or other future impacts of environmental regulations on our future operations. A discharge of hydrocarbons or hazardous substances into the environment could subject us to substantial expense, including the cost to comply with applicable regulations that require a response to the discharge, such as claims by neighboring landowners, regulatory agencies or other third parties for costs of:

	•	containment or cleanup;
	•	personal injury;
	•	property damage; and
	•	penalties assessed or other claims sought for natural resource damages.

     The following are examples of some environmental laws that potentially impact our operations.

•

Water. The Oil Pollution Act, or OPA, was enacted in 1990 and amends provisions of the Federal Water Pollution Control Act of 1972 and other statutes as they pertain to prevention of and response to major oil spills. The OPA subjects owners of facilities to strict, joint and potentially unlimited liability for removal costs and certain other consequences of an oil spill, where such spill is into navigable waters, or along shorelines. In the event of an oil spill into such waters, substantial liabilities

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		could be imposed upon Parallel. States in which Parallel operates have also enacted similar laws. Regulations are currently being developed under the OPA and similar state laws that may also impose additional regulatory burdens on Parallel.
		The FWPCA imposes restrictions and strict controls regarding the discharge of produced waters, other oil and gas wastes, any form of pollutant, and, in some instances, storm water runoff, into waters of the United States. The FWPCA provides for civil, criminal and administrative penalties for any unauthorized discharges and, along with the OPA, imposes substantial potential liability for the costs of removal, remediation or damages resulting from an unauthorized discharge and, along with the OPA, imposes substantial potential liability for the costs of removal, remediation or damages resulting from an unauthorized discharge. State laws for the control of water pollution also provide civil, criminal and administrative penalties and liabilities in the case of an unauthorized discharge into state waters. The cost of compliance with the OPA and the FWPCA have not historically been material to our operations, but there can be no assurance that changes in federal, state or local water pollution control programs will not materially adversely affect us in the future. Although no assurances can be given, we believe that compliance with existing permits and compliance with foreseeable new permit requirements will not have a material adverse effect on our financial condition or results of operations.
	•	Solid Waste. Parallel generates non-hazardous solid wastes that fall under the requirements of the Federal Resource Conservation and Recovery Act and comparable state statutes. The EPA and the states in which we operate are considering the adoption of stricter disposal standards for the type of non-hazardous waste we generate. The Resource Conservation and Recovery Act also govern the generation, management, and disposal of hazardous wastes. At present, we are not required to comply with a substantial portion of the Resource Conservation and Recovery Act requirements because our operations generate minimal quantities of hazardous wastes. However, it is anticipated that additional wastes, which could include wastes currently generated during operations, could in the future be designated as hazardous wastes. Hazardous wastes are subject to more rigorous and costly disposal and management requirements than are non-hazardous wastes. Such changes in the regulations may result in Parallel incurring additional capital expenditures or operating expenses.
	•	Superfund. The Comprehensive Environmental Response, Compensation, and Liability Act, sometimes called CERCLA or Superfund, imposes liability, without regard to fault or the legality of the original act, on certain classes of persons in connection with the release of a hazardous substance into the environment. These persons include the current owner or operator of any site where a release historically occurred and companies that disposed or arranged for the disposal of the hazardous substances found at the site. CERCLA also authorizes the EPA and, in some instances, third parties to act in response to threats to the public health or the environment and to seek to recover from the responsible classes of persons the costs they incur. In the course of our ordinary operations, we may have managed substances that may fall within CERCLA’s definition of a hazardous substance. We may be jointly and severally liable under CERCLA for all or part of the costs required

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cleaning up sites where we disposed of or arranged for the disposal of these substances. This potential liability extends to properties that we owned or operated, as well as to properties owned and operated by others at which disposal of Parallel’s hazardous substances occurred.

     Parallel may also fall into the category of a current owner or operator. We currently own or lease numerous properties that for many years have been used for exploring and producing oil and gas. Although we believe we use operating and disposal practices standard in the industry, hydrocarbons or other wastes may have been disposed of or released by us on or under properties that we have owned or leased. In addition, many of these properties have been previously owned or operated by third parties who may have disposed of or released hydrocarbons or other wastes at these properties. Under CERCLA, and analogous state laws, we could be required to remove or remediate previously disposed wastes, including wastes disposed of or released by prior owners or operators, to clean up contaminated property, including contaminated groundwater, or to perform remedial plugging operations to prevent future contamination.

Risks Related to Our Business

The volatility of the oil and natural gas industry may have an adverse impact on our operations.

     Our revenues, cash flows and profitability are substantially dependent upon prevailing prices for oil and natural gas. In recent years, oil and natural gas prices and, therefore, the level of drilling, exploration, development and production, have been extremely volatile. Any significant or extended decline in oil or natural gas prices will have a material adverse effect on our business, financial condition and results of operations and could impair access to future sources of capital. Volatility in the oil and natural gas industry results from numerous factors over which we have no control, including;

	•	the level of oil and natural gas prices, expectations about future oil and natural gas prices and the ability of international cartels to set and maintain production levels and prices;
	•	the cost of exploring for, producing and transporting oil and natural gas;
	•	the level and price of foreign oil and natural gas transportation;
	•	available pipeline and other oil and natural gas transportation capacity;
	•	weather conditions;
	•	international political, military, regulatory and economic conditions;
	•	the level of consumer demand;
	•	the price and the availability of alternative fuels;
	•	the effect of worldwide energy conservation measures; and

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•

the ability of oil and natural gas companies to raise capital.

     Significant declines in oil and natural gas prices for an extended period may:

	•	impair our financial condition, liquidity, ability to finance planned capital expenditures and results of operations;
	•	reduce the amount of oil and natural gas that we can produce economically;
	•	cause us to delay or postpone some of our capital projects;
	•	reduce our revenues, operating income and cash flow; and
	•	reduce the carrying value of our oil and natural gas properties.

     No assurance can be given that current levels of oil and natural gas prices will continue. We expect oil and natural gas prices, as well as the oil and natural gas industry generally, to continue to be volatile.

We must replace oil and natural gas reserves that we produce. Failure to replace reserves may negatively affect our business.

     Our future performance depends in part upon our ability to find, develop and acquire additional oil and natural gas reserves that are economically recoverable. Our proved reserves decline as they are depleted and we must locate and develop or acquire new oil and natural gas reserves to replace reserves being depleted by production. No assurance can be given that we will be able to find and develop or acquire additional reserves on an economical basis. If we cannot economically replace our reserves, our results of operations may be materially adversely affected.

We are subject to uncertainties in reserve estimates and future net cash flows.

     There is substantial uncertainty in estimating quantities of proved reserves and projecting future production rates and the timing of development expenditures. No one can measure underground accumulations of oil and natural gas in an exact way. Accordingly, oil and natural gas reserve engineering requires subjective estimations of those accumulations. Estimates of other engineers might differ widely from those of our independent petroleum engineers, and our independent petroleum engineers may make material changes to reserve estimates based on the results of actual drilling, testing, and production. As a result, our reserve estimates often differ from the quantities of oil and natural gas we ultimately recover. Also, we make certain assumptions regarding future oil and natural gas prices, production levels, and operating and development costs that may prove incorrect. Any significant variance from these assumptions could greatly affect our estimates of reserves, the economically recoverable quantities of oil and natural gas attributable to any particular group of properties, the classifications of reserves based on risk of recovery, and estimates of the future net cash flows. Some of our reserve estimates are made without the benefit of a lengthy production history and are calculated using volumetric analysis. Those estimates are less reliable than estimates based on a lengthy production history.

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Volumetric analysis involves estimating the volume of a reservoir based on the net feet of pay and an estimation of the productive area.

     The present value of future net cash flows from our proved reserves is not necessarily the same as the current market value of our estimated oil and natural gas reserves. We base the estimated discounted future net cash flows from our proved reserves on prices and costs in effect on the day of estimate. However, actual future net cash flows from our oil and natural gas properties also will be affected by factors such as:

	•	actual prices we receive for oil and natural gas;
	•	the amount and timing of actual production;
	•	supply and demand of oil and natural gas;
	•	limits of increases in consumption by natural gas purchasers; and
	•	changes in governmental regulations or taxation.

     The timing of both our production and our incurrence of expenses in connection with the development and production of oil and natural gas properties will affect the timing of actual future net cash flows from proved reserves, and thus their actual present value. In addition, the 10% discount factor we use when calculating discounted future net cash flows may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the oil and natural gas industry in general.

Competition in the oil and natural gas industry is intense, and many of our competitors have greater financial, technological and other resources than we do.

     We operate in the highly competitive areas of oil and natural gas acquisition, development, exploitation, exploration and production. The oil and natural gas industry is characterized by rapid and significant technological advancements and introductions of new products and services using new technologies. We face intense competition from independent, technology-driven companies as well as from both major and other independent oil and natural gas companies in each of the following areas:

	•	seeking to acquire desirable producing properties or new leases for future exploration;
	•	marketing our oil and natural gas production;
	•	integrating new technologies; and
	•	seeking to acquire the equipment and expertise necessary to develop and operate our properties.

     Many of our competitors have financial, technological and other resources substantially greater than ours, and some of them are fully integrated oil and natural gas companies. These companies may be able to pay more for development prospects and productive oil and natural

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gas properties and may be able to define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit. Further, these companies may enjoy technological advantages and may be able to implement new technologies more rapidly than we can. Our ability to develop and exploit our oil and natural gas properties and to acquire additional properties in the future will depend upon our ability to successfully conduct operations, implement advanced technologies, evaluate and select suitable properties and consummate transactions in this highly competitive environment.

We do not control all of our operations and development projects.

     Substantially all of our business activities are conducted through joint operating agreements under which we own partial interests in oil and natural gas wells.

     At December 31, 2004, we owned interests in 218 gross (162.91 net) producing oil and natural gas wells for which we were the operator and 451 gross (152.02 net) producing oil and natural gas wells where we were not the operator.

     If we do not operate wells in which we own an interest, we do not have control over normal operating procedures, expenditures or future development of underlying properties. The failure of an operator of our wells to adequately perform operations, or an operator’s breach of the applicable agreements, could reduce our production and revenues. The success and timing of our drilling and development activities on properties operated by others therefore depends upon a number of factors outside of our control, including the operator’s:

	•	timing and amount of capital expenditures;
	•	expertise and financial resources;
	•	inclusion of other participants in drilling wells; and
	•	use of technology.

     Since we do not have a majority interest in most wells we do not operate, we may not be in a position to remove the operator in the event of poor performance.

Our business involves many operating risks, which may result in substantial losses, and insurance may be unavailable or inadequate to protect us against these risks.

     Our operations are subject to hazards and risks inherent in drilling for, producing and transporting oil and natural gas, such as:

	•	fires;
	•	natural disasters;
	•	explosions;

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	•	pressure forcing oil or natural gas out of the wellbore at a dangerous velocity coupled with the potential for fire or explosion;
	•	weather;
	•	failure of oilfield drilling and service tools;
	•	changes in underground pressure in a formation that causes the surface to collapse or crater;
	•	pipeline ruptures or cement failures;
	•	environmental hazards such as natural gas leaks, oil spills and discharges of toxic gases; and
	•	availability of needed equipment at acceptable prices, including steel tubular products.

     Any of these risks can cause substantial losses resulting from:

	•	injury or loss of life;
	•	damage to and destruction of property, natural resources and equipment;
	•	pollution and other environmental damage;
	•	regulatory investigations and penalties;
	•	suspension of our operations; and
	•	repair and remediation costs.

     We do not insure against the loss of oil or natural gas reserves as a result of operating hazards or insure against business interruption. Losses could occur for uninsurable or uninsured risks, or in amounts in excess of existing insurance coverage. The occurrence of an event that is not fully covered by insurance could harm our financial condition and results of operations.

The oil and natural gas industry is capital intensive.

     The oil and natural gas industry is capital intensive. We make substantial capital expenditures for the acquisition, exploration for and development of oil and natural gas reserves.

     Historically, we have financed capital expenditures primarily with cash generated by operations, proceeds from bank borrowings and sales of our equity securities. In addition, we may consider selling non-core assets to raise additional operating capital. From time to time, we

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may also reduce our ownership interests in 3-D seismic and other projects in order to reduce our capital expenditure requirements, depending on our working capital needs.

     Our cash flow from operations and access to capital is subject to a number of variables, including:

	•	our proved reserves;
	•	the level of oil and natural gas we are able to produce from existing wells;
	•	the prices at which oil and natural gas are sold; and
	•	our ability to acquire, locate and produce new reserves.

     Any one of these variables can materially affect our ability to borrow under our revolving credit facility.

     If our revenues or the borrowing base under our revolving credit facility decreases as a result of lower oil and natural gas prices, operating difficulties, declines in reserves or for any other reason, we may have limited ability to obtain the capital necessary to undertake or complete future drilling projects. We may, from time to time, seek additional financing, either in the form of increased bank borrowings, sales of debt or equity securities or other forms of financing and there can be no assurance as to the availability or terms of any additional financing upon terms acceptable to us.

There are risks in acquiring producing properties, including difficulties in integrating acquired properties into our business, additional liabilities and expenses associated with acquired properties, diversion of management attention, increasing the scope, geographic diversity and complexity of our operations and incurrence of additional debt.

     Our business strategy includes growing our reserve base through acquisitions. Our failure to integrate acquired businesses successfully into our existing business, or the expense incurred in consummating future acquisitions, could result in unanticipated expenses and losses. In addition, we may assume cleanup or reclamation obligations or other unanticipated liabilities in connection with these acquisitions. The scope and cost of these obligations may ultimately be materially greater than estimated at the time of the acquisition.

     We are continually investigating opportunities for acquisitions. In connection with future acquisitions, the process of integrating acquired operations into our existing operations may result in unforeseen operating difficulties and may require significant management attention and financial resources that would otherwise be available for the ongoing development or expansion of existing operations. Our ability to make future acquisitions may be constrained by our ability to obtain additional financing.

     Possible future acquisitions could result in our incurring additional debt, contingent liabilities and expense, all of which could have a material adverse effect on our financial condition and operating results.

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The marketability of our natural gas production depends on facilities that we typically do not own or control.

     The marketability of our natural gas production depends in part upon the availability, proximity and capacity of natural gas gathering systems, pipelines and processing facilities. We generally deliver natural gas through natural gas gathering systems and natural gas pipelines that we do not own. Our ability to produce and market natural gas on a commercial basis could be harmed by any significant change in the cost or availability of such systems and pipelines.

We are subject to many restrictions under our revolving credit facility.

     We may depend on our revolving credit facility for future capital needs. As required by our revolving credit facility with our bank lenders, we have pledged substantially all of our oil and natural gas properties as collateral to secure the payment of our indebtedness. The revolving credit facility restricts our ability to obtain additional financing, make investments, lease equipment, sell assets and engage in business combinations. We are also required to comply with certain financial covenants and ratios. The revolving credit facility prohibits us from declaring or paying dividends on our common stock, but we are permitted to pay dividends on our outstanding shares of 6% convertible preferred stock if we are not in default under the revolving credit facility. Although we are currently in compliance with these covenants, in the past we have had to request waivers from our banks because of our non-compliance with certain financial covenants and ratios. Our ability to comply with these restrictions and covenants in the future is uncertain and will be affected by the levels of cash flow from our operations and events or circumstances beyond our control. Our failure to comply with any of the restrictions and covenants under the revolving credit facility could result in a default under the revolving credit facility, which could cause all of our existing indebtedness to be immediately due and payable.

     The revolving credit facility limits the amounts we can borrow to a borrowing base amount, determined by the lenders, based upon projected revenues from the oil and natural gas properties securing our loan. The lenders can adjust the borrowing base and the borrowings permitted to be outstanding under the revolving credit facility. Any increase in the borrowing base requires the consent of all lenders. If all lenders do not agree on an increase, then the borrowing base will be the lowest borrowing base determined by each lender. Outstanding borrowings in excess of the borrowing base must be repaid immediately, or we must pledge other oil and natural gas properties as additional collateral. We do not currently have any substantial unpledged properties and no assurance can be given that we would be able to make any mandatory principal prepayments required under the revolving credit facility.

If we default under our revolving credit facility, the lenders could foreclose on, and acquire control of, substantially all of our assets.

     The lenders under our revolving credit facility have liens on substantially all of our assets. As a result of the liens held by our revolving credit facility lenders, if we fail to meet our payment or other obligations under the revolving credit facility, those lenders would be entitled to foreclose on substantially all of our assets and liquidate those assets.

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Our producing properties are geographically concentrated.

     A substantial portion of our proved oil and natural gas reserves are located in the Permian Basin of west Texas and eastern New Mexico. Specifically, at December 31, 2004, approximately 90% of the discounted present value of our proved reserves were located in the Permian Basin. As a result, we may be disproportionately exposed to the impact of delays or interruptions of production from these wells due to mechanical problems, damages to the current producing reservoirs, significant governmental regulation, including any curtailment of production, or interruption of transportation of oil or natural gas produced from the wells.

Hedging activities create a risk of financial loss.

     In order to manage our exposure to price risks in the marketing of our oil and natural gas, we have in the past and expect to continue to enter into oil and natural gas price risk management arrangements with respect to a portion of our expected production. We use swap, floor, and collar hedging arrangements that generally result in a fixed price or a range of minimum and maximum price limits over a specified time period. Hedging contracts limit the benefits we will realize if actual prices rise above the contract price. Our hedging arrangements may expose us to the risk of financial loss in certain circumstances. In a typical hedge transaction, the hedging party will have the right to receive from the counterparty to the hedge, the excess of the fixed price specified in the hedge over a floating price based on a market index, multiplied by the quantity hedged. If the floating price exceeds the fixed price, the hedging party is required to pay the counterparty this difference multiplied by the quantity hedged. In this case, if we are the hedging party we would be required to pay the difference regardless of whether we had sufficient production to cover the quantities specified in the hedge. Significant reductions in production at times when the floating price exceeds the fixed price could require us to make payments under the hedge agreements even though the payments are not offset by sales of production. Hedging will also prevent us from receiving the full advantage of increases in oil or natural gas prices above the fixed amount specified in the hedge. In addition, these transactions may expose us to the risk of financial loss in certain circumstances, including instances in which:

	•	production is less than expected;
	•	there is a widening of price differentials between delivery points for our production and the delivery point assumed in the arrangement which might result in hedge ineffectiveness;
	•	the counterparties to our future contracts fail to perform under the contract; or
	•	a sudden, unexpected event materially impacts oil or natural gas prices.

     In the past, some of our hedging contracts required us to deliver cash collateral or other assurances of performance to the counterparties in the event that our payment obligations exceeded certain levels. Future collateral requirements are uncertain but will depend on arrangements with our counterparties and highly volatile natural gas and oil prices.

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We are subject to complex federal, state and local laws and regulations that could adversely affect our business.

     Extensive federal, state and local regulation of the oil and natural gas industry significantly affects our operations. In particular, our oil and natural gas exploration, development and production, are subject to stringent environmental regulations. These regulations have increased the costs of planning, designing, drilling, installing, operating and abandoning our oil and natural gas wells and other related facilities. These regulations may become more demanding in the future. Matters subject to regulation include:

	•	discharge permits for drilling operations;
	•	drilling bonds;
	•	spacing of wells;
	•	unitization and pooling of properties;
	•	environmental protection;
	•	reports concerning operations; and
	•	taxation.

Under these laws and regulations, we could be liable for:

	•	personal injuries;
	•	property damage;
	•	oil spills;
	•	discharge of hazardous materials;
	•	reclamation costs;
	•	remediation and clean-up costs; and
	•	other environmental damages.

     Failure to comply with these laws and regulations also may result in the suspension or termination of our operations and subject us to administrative, civil and criminal penalties. Further, these laws and regulations could change in ways that substantially increase our costs. Any of these liabilities, penalties, suspensions, terminations or regulatory changes could make it more expensive for us to conduct our business or cause us to limit or curtail some of our operations.

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Declining oil and natural gas prices may cause us to record ceiling test write-downs.

     We use the full cost method of accounting to account for our oil and natural gas operations. This means that we capitalize the costs to acquire, explore for and develop oil and natural gas properties. Under full cost accounting rules, the capitalized costs of oil and natural gas properties may not exceed a ceiling limit, which is based on the present value of estimated future net revenues, net of income tax effects, from proved reserves, discounted at 10%, plus the lower of cost or fair market value of unproved properties. These rules generally require pricing future oil and natural gas production at unescalated oil and natural gas prices in effect at the end of each fiscal quarter, with effect given to cash flow hedge positions. If capitalized costs of oil and natural gas properties, as adjusted for asset retirement obligations, exceed the ceiling limit, we must charge the amount of the excess against earnings. This is called a ceiling test write-down. This non-cash impairment charge does not affect cash flow from operating activities, but it does reduce stockholders’ equity. Impairment charges cannot be restored by subsequent increases in the prices of oil and natural gas.

     The risk that we will be required to write down the carrying value of our oil and natural gas properties increases when oil and natural gas prices decline. In addition, write-downs may occur if we experience substantial downward adjustments to our estimated proved reserves.

     We did not recognize impairment in 2004. We cannot assure you that we will not experience ceiling test write-downs in the future.

Terrorist activities may adversely affect our business.

     Terrorist activities, including events similar to those of September 11, 2001, or armed conflict involving the United States may adversely affect our business activities and financial condition. If events of this nature occur and persist, the resulting political and social instability could adversely affect prevailing oil and natural gas prices and cause a reduction in our revenues. In addition, oil and natural gas production facilities, transportation systems and storage facilities could be direct targets of terrorist attacks, and our operations could be adversely impacted if infrastructure integral to our operations is destroyed or damaged. Costs associated with insurance and other security measure may increase as a result of these threats, and some insurance coverage may become more difficult to obtain, if available at all.

We are highly dependent upon key personnel.

     Our success is highly dependent upon the services, efforts and abilities of key members of our management team. Our operations could be materially and adversely affected if one or more of these individuals become unavailable for any reason.

     We do not have employment agreements or long term contractual arrangements with any of our officers or other key employees. In periods of improving market conditions, our ability to obtain and retain qualified consultants on a timely basis may be adversely affected.

     Our future growth and profitability will also be dependent upon our ability to attract and retain other qualified management personnel and to effectively manage our growth. There can be no assurance that we will be successful in doing so.

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Part of our business is seasonal in nature.

     Weather conditions affect the demand for and price of oil and natural gas and can also delay drilling activities, temporarily disrupting our overall business plans. Demand for oil and natural gas is typically higher during winter months than summer months. However, warm winters can also lead to downward price trends. As a result, our results of operations may be adversely affected by seasonal conditions.

Our Oil and Natural gas Operations Are Subject to Many Inherent Risks

     Oil and natural gas drilling activities and production operations are highly speculative and involve a high degree of risk. These operations are marked by unprofitable efforts because of dry holes and wells that do not produce oil or natural gas in sufficient quantities to return a profit. The success of our operations depends, in part, upon the ability of our management and technical personnel. The cost of drilling, completing and operating wells is often uncertain. There is no assurance that our oil and natural gas drilling or acquisition activities will be successful, that any production will be obtained, or that any such production, if obtained, will be profitable.

     Our operations are subject to all of the operating hazards and risks normally incident to drilling for and producing oil and natural gas. These hazards and risks include, but are not limited to:

	•	encountering unusual or unexpected formations and pressures;
	•	explosions, blowouts and fires;
	•	pipe and tubular failures and casing collapses;
	•	environmental pollution; and
	•	personal injuries.

     Any one of these potential hazards could result in accidents, environmental damage, personal injury, property damage and other harm that could result in substantial liabilities to us.

     As is customary in the industry, we maintain insurance against some, but not all, of these hazards. We maintain general liability insurance and obtain Operator’s Extra Expense insurance on a well-by-well basis. We carry insurance against certain pollution hazards, subject to our insurance policy’s terms, conditions and exclusions. If we sustain an uninsured loss or liability, our ability to operate could be materially adversely affected.

     Our oil and natural gas operations are not subject to renegotiation of profits or termination of contracts at the election of the federal government.

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Restrictive debt covenants could limit our growth and our ability to finance our operations, fund our capital needs, respond to changing conditions and engage in other business activities that may be in our best interests.

     Our revolving credit facility contains a number of significant covenants that, among other things, restrict our ability to:

	•	dispose of assets;
	•	incur additional indebtedness;
	•	restrictions on all retained earnings and net income for payment of dividends on our common stock;
	•	create liens on our assets;
	•	enter into specified investments or acquisitions;
	•	repurchase, redeem or retire our capital stock or other securities;
	•	merge or consolidate, or transfer all or substantially all of our assets and the assets of our subsidiaries;
	•	engage in specified transactions with subsidiaries and affiliates; or
	•	engage in other specified corporate activities.

     Also, our revolving credit facility requires us to maintain compliance with specified financial ratios and satisfy certain financial condition tests. Our ability to comply with these ratios and financial condition tests may be affected by events beyond our control, and we cannot assure you that we will meet these ratios and financial condition tests. These financial ratio restrictions and financial condition tests could limit our ability to obtain future financings, make needed capital expenditures, withstand a future downturn in our business or the economy in general or otherwise conduct necessary corporate activities. We may also be prevented from taking advantage of business opportunities that arise because of the limitations that the restrictive covenants under the revolving credit facility impose on us. A breach of any of these covenants or our inability to comply with the required financial ratios or financial condition tests could result in a default under the revolving credit facility. A default, if not cured or waived, could result in acceleration of all indebtedness outstanding under the revolving credit facility. The accelerated debt would become immediately due and payable. If that should occur, we may not be able to pay all such debt or to borrow sufficient funds to refinance it. Even if new financing were then available, it may not be on terms that are acceptable to us.

We do not pay dividends on our common stock.

     We have never paid dividends on our common stock, and do not intend to pay cash dividends on the common stock in the foreseeable future. Net income from our operations, if any, will be used for the development of our business, including capital expenditures, to retire

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debt and to pay dividends on our outstanding shares of 6% convertible preferred stock. Any decision to pay dividends on the common stock in the future will depend upon our profitability at that time, the available cash and other factors. Our ability to pay dividends on our common stock is further limited by the terms of our revolving credit facility and the terms of our preferred stock.

Changes in control may be discouraged.

     Our certificate of incorporation, our bylaws and the Delaware General Corporation Law contain provisions that may discourage other persons from initiating a tender offer or takeover attempt that a stockholder might consider to be in the best interests of all stockholders, including takeover attempts that might result in a premium to be paid over the market price of our stock.

     On October 5, 2000, our Board of Directors adopted a stockholder rights plan. The plan is designed to protect Parallel from unfair or coercive takeover attempts and to prevent a potential acquirer from gaining control of Parallel without fairly compensating all of the stockholders. The plan authorized 50,000 shares of $0.10 par Series A Preferred Stock Purchase Rights. A dividend of one Right for each share of our outstanding common stock was distributed to stockholders of record at the close of business on October 16, 2000. If a public announcement is made that a person has acquired 15% or more of Parallel’s common stock or a tender or exchange offer is made for 15% of more of the common stock, each Right entitles the holder to purchase from the company one one-thousandth of a share of Series A Preferred Stock, at an exercise price of $26.00 per one one-thousandth of a share, subject to adjustment. In addition, under certain circumstances, the rights entitle the holders to buy Parallel’s stock at a 50% discount. See Note 9 to consolidated financial statements.

     We are authorized to issue 10.0 million shares of preferred stock, 950,000 shares of which were outstanding on March 1, 2005. Our Board of Directors has total discretion in the issuance and the determination of the rights and privileges of any shares of preferred stock which might be issued in the future, which rights and privileges may be detrimental to the holders of the common stock. It is not possible to state the actual effect of the authorization and issuance of a new series of preferred stock upon the rights of holders of the common stock and other series of preferred stock unless and until the Board of Directors determines the attributes of any new series of preferred stock and the specific rights of its holders. These effects might include:

	•	restrictions on dividends on common stock and other series of preferred stock if dividends on any new series of preferred stock have not been paid;
	•	dilution of the voting power of common stock and other series of preferred stock to the extent that a new series of preferred stock has voting rights, or to the extent that any new series of preferred stock is convertible into common stock;
	•	dilution of the equity interest of common stock and other series of preferred stock; and
	•	limitation on the right of holders of common stock and other series of preferred stock to share in Parallel’s assets upon liquidation until satisfaction of any liquidation preference attributable to any new series of preferred stock.

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     The issuance of preferred stock in the future could discourage, delay or prevent a tender offer, proxy contest or other similar transaction involving a potential change in control of Parallel that might be viewed favorably by stockholders.

General

     Our principal properties consist of developed and undeveloped oil and natural gas leases and the reserves associated with these leases. Generally, developed oil and natural gas leases remain in force so long as production is maintained. Undeveloped oil and natural gas leaseholds are generally for a primary term of five or ten years. In most cases, we can extend the term of our undeveloped leases by paying delay rentals or by producing reserves that we discover under our leases.

Producing Wells and Acreage

     We have presented the following table to provide you with a summary of the producing oil and natural gas wells and the developed and undeveloped acreage in which we owned an interest at December 31, 2004. We have not included in the table acreage in which our interest is limited to options to acquire leasehold interests, royalty or similar interests.

     At December 31, 2004, we owned interests in 218 gross (162.91 net) producing oil and natural gas wells for which we were the operator and 451 gross (152.02 net) producing oil and natural gas wells where we were not the operator.

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     The operator of a well has significant control over its location and the timing of its drilling. In addition, the operator receives fees from other working interest owners as reimbursement for general and administrative expenses for operating the wells.

     Except for our oil and natural gas leases, we do not own any patents, licenses, franchises or concessions which are significant to our oil and natural gas operations.

Title to Properties

     As is customary in the oil and natural gas industry, we make only a cursory review of title to undeveloped oil and natural gas leases at the time they are acquired. These cursory title reviews, while consistent with industry practices, are necessarily incomplete. We believe that it is not economically feasible to review in depth every individual property we acquire, especially in the case of producing property acquisitions covering a large number of leases. Ordinarily, when we acquire producing properties, we focus our review efforts on properties believed to have higher values and will sample the remainder. However, even an in-depth review of all properties and records may not necessarily reveal existing or potential defects nor will it permit a buyer to become sufficiently familiar with the properties to assess fully their deficiencies and capabilities. In the case of producing property acquisitions, inspections may not always be performed on every well, and environmental problems, such as ground water contamination, are not necessarily observable even when an inspection is undertaken. In the case of undeveloped leases or prospects we acquire, before any drilling commences, we will usually cause a more thorough title search to be conducted, and any material defects in title that are found as a result of the title search are generally remedied before drilling a well on the lease commences. We believe that we have good title to our oil and natural gas properties, some of which are subject to immaterial encumbrances, easements and restrictions. The oil and natural gas properties we own are also typically subject to royalty and other similar non-cost bearing interests customary in the industry. We do not believe that any of these encumbrances or burdens will materially affect our ownership or the use of our properties.

Oil and Natural Gas Reserves

     For the year ended December 31, 2004, our oil and natural gas reserves were estimated by Cawley Gillespie & Associates, Inc., Fort Worth, Texas.

     At December 31, 2004, our total estimated proved reserves were approximately 18.9 MMBbls of oil and 16.8 Bcf of gas, or 21.7 MMBOEs.

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     The information in this table provides you with certain information regarding the proved reserves as estimated by Cawley Gillespie & Associates, Inc., at December 31, 2004.

     Estimates of our proved reserves and future net revenues are made using sales prices and costs, estimated to be in effect as of the date of such reserve estimates that are held constant throughout the life of the properties, except to the extent a contract specifically provides for escalation. The average realized prices for our reserves as of December 31, 2004 were $40.59 per Bbl of oil and $5.65 per Mcf of natural gas.

     For additional information concerning our estimated proved oil and natural gas reserves, you should read Note 15 to the consolidated financial statements. See also Item 8 — Financial Statements and Supplementary Data on page 65 of this Annual Report on Form 10-K.

     The reserve data in this report represent estimates only. Reservoir engineering is a subjective process. There are numerous uncertainties inherent in estimating our oil and natural gas reserves and their estimated values. Many factors are beyond our control. Estimating underground accumulations of oil and natural gas cannot be measured in an exact manner. The accuracy of any reserve estimate is a function of the quality of available data, engineering and geological interpretation and judgment and the costs we actually incur in the development of our reserves. As a result, estimates of different engineers often vary. In addition, estimates of reserves are subject to revision by the results of drilling, testing and production after the date of the estimates. Consequently, reserve estimates are often different from the quantities of oil and natural gas that are ultimately recovered. The meaningfulness of estimates is highly dependent upon the accuracy of the assumptions upon which they were based.

     The volume of production from oil and natural gas properties declines as reserves are produced and depleted. Unless we acquire properties containing proved reserves or conduct successful drilling activities, our proved reserves will decline as we produce our existing reserves. Our future oil and natural gas production is highly dependent upon our level of success in acquiring or finding additional reserves.

     We do not have any natural gas or oil reserves outside the United States. Our oil and natural gas reserves and production are not subject to any long term supply or similar agreements with foreign governments or authorities.

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     Our estimated reserves have not been filed with or included in reports to any federal agency other than the SEC.

     From time to time, we are a party to ordinary routine litigation incidental to our business. As of March 1, 2005 we were not a party to any litigation. We are not aware of any threatened litigation. No litigation proceedings were terminated during the fourth quarter of 2004. We have not been a party to any bankruptcy, receivership, reorganization, adjustment or similar proceeding.

     We did not submit any matter to a vote of our stockholders during the fourth quarter of 2004.

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PART II

Market Information

     Our common stock trades on the Nasdaq National Market under the symbol PLLL. The following table shows, for the periods indicated, the high and low closing sales prices for the common stock as reported by Nasdaq.

     The last sale price of our common stock on March 1, 2005 was $6.99 per share, as reported on the Nasdaq National Market.

     As of March 1, 2005, there were approximately 1,569 stockholders of record.

Dividends

     We have not paid, and do not intend to pay in the foreseeable future, cash dividends on our common stock. The revolving credit facility we have with our bank lenders prohibits the payment of dividends on the common stock. Our 6% convertible preferred stock also contains provisions that restrict us from paying dividends or making distributions on our common stock if all dividends on the preferred stock have not been paid in full. Any dividends on our preferred

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stock that are not declared and paid will accumulate. All accumulated dividends must be paid in full before dividends may be paid to holders of common stock. The credit facility allows us to pay dividends on our outstanding shares of preferred stock as long as we are not in default under the terms of the credit facility. The holders of the preferred stock are entitled, as and when declared by the Board of Directors, to receive an annual dividend of $.60 per share, payable semi-annually on June 15 and December 15 of each year. See “Risks Related to Our Business — We do not pay dividends on our common stock” on page 20 and “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Capital Resources and Liquidity” on page 55.

Equity Compensation Plans

     At December 31, 2004, a total of 2,627,250 shares of common stock were authorized for issuance under our equity compensation plans. In the table below, we describe certain information about these shares and the equity compensation plans which provide for their authorization and issuance. You can find descriptions of our stock grant and stock option plans beginning on page 78.

Equity Compensation Plan Information

(1)		Includes the following plans: 2004 Non-Employee Director Stock Grant Plan; 1992 Stock Option Plan; 1997 Non-employee Directors Stock Option Plan; 1998 Stock Option Plan; and 2001 Non-employee Directors Stock Option Plan.
(2)		These shares include an aggregate of 200,000 shares of common stock underlying stock options granted in June, 2001 to non-officer employees pursuant to Parallel’s Employee Stock Option Plan. The Employee Stock Option Plan is the only equity compensation plan in effect that was adopted without approval of our stockholders. Directors and officers of Parallel are not eligible to participate in this plan. A description of the material features of this plan can be found under the caption “Employee Stock Option Plan” on page 86. The total number of shares shown also includes 275,000 shares of common stock underlying a stock purchase warrant we issued to an investment banking firm in November, 2001 and 100,000 shares of common stock underlying a stock purchase warrant we issued to the same investment banking firm in December, 2003. These warrants were issued under financial advisory services agreements with the investment banking firm, and not under employee or director compensation plans. The warrants issued in

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November, 2001 are exercisable, in whole or in part, at an exercise price equal to $2.95 per share, the fair market value of the common stock on the date of issuance of warrants, and are exercisable at any time during the four-year period commencing on November 20, 2002. The warrants issued in December, 2003 are exercisable, in whole or in part, at an exercise price equal to $3.98 per share, the fair market value of the common stock on the date of issuance of the warrants, and are exercisable at any time during the four-year period commencing on December 23, 2004. All of the warrants contain customary provisions providing for adjustment of the exercise price and the number and type of securities issuable upon exercise of the warrants if any one or more of certain specified events occur. The warrants also grant to the holder certain registration rights for the securities issuable upon exercise of the warrants.

Sale of Unregistered Securities

     At Parallel’s annual meeting of stockholders held on June 22, 2004, the stockholders approved the Parallel Petroleum Corporation 2004 Non-Employee Director Stock Grant Plan. You can find a description of this plan on page 82. Historically, Directors’ fees had been paid solely in cash. However, upon approval of the plan by the stockholders, we began paying an annual retainer fee to each non-employee Director in the form of common stock having a value of $25,000. Only Directors of Parallel who are not employees of Parallel or any of its subsidiaries are eligible to participate in the Plan. Under the plan, each non-employee Director is entitled to receive an annual retainer fee consisting of shares of common stock that will be automatically granted on the first day of July in each year. The actual number of shares received is determined by dividing $25,000 by the average daily closing price of the common stock on the Nasdaq Stock Market for the ten consecutive trading days commencing fifteen trading days before the first day of July of each year. On July 1, 2004, and in accordance with the terms of the plan, we issued a total of 20,888 shares of common stock to four non-employee Directors as follows: Jeffrey G. Shrader — 5,222 shares; Dewayne E. Chitwood — 5,222 shares; Martin B. Oring — 5,222 shares; and Ray M. Poage — 5,222 shares. The shares of common stock were issued without registration under the Securities Act of 1933, as amended, in reliance on the exemption provided by Section 4(2) of the Securities Act. Generally, shares issued under this plan are not transferable as long as the non-employee Director holding the shares remains a Director of the Company. Certificates evidencing the shares bear restrictive legends.

Repurchase of Equity Securities

     Neither we nor any “affiliated purchaser” repurchased any of our equity securities during the fourth quarter of the fiscal year ended December 31, 2004.

     In the table below, we provide you with selected historical financial data. We have prepared this information using the audited consolidated financial statements for the five-year period ended December 31, 2004. It is important that you read this data along with our consolidated financial statements and related notes, and “Management’s Discussion and Analysis of Financial Condition and Results of Operations” under Item 7 below. The selected financial data provided are not necessarily indicative of our future results of operations or financial performance.

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As compared to cash provided by operating activities, we believe operating cash flow is a better liquidity indicator for oil and natural gas producers because changes in assets and liabilities eliminates fluctuations related to the timing of cash receipts and disbursements which can vary from period-to-period because of conditions we cannot control.

     The following discussion is intended to assist you in understanding our financial position and results of operations for each year in the three-year period ended December 31, 2004. You should read the following discussion and analysis in conjunction with our consolidated financial statements and the related notes.

     The following discussion contains forward-looking statements. For a description of limitations inherent in forward-looking statements, see “Cautionary Statement Regarding Forward Looking Statements” on page (ii).

Overview and Strategy

     Our primary objective is to increase stockholder value of our common stock through increasing reserves, production, cash flow and earnings. We have shifted the balance of our investments from properties having high rates of production in early years to properties expected to produce more consistently over a longer term. We attempt to reduce our financial risks by dedicating a smaller portion of our capital to high risk projects, while reserving the majority of our available capital for exploitation and development drilling opportunities. Obtaining positions in long-lived oil and natural gas reserves will be given priority over properties that might provide

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more cash flow in the early years of production, but which have shorter reserve lives. We also attempt to further reduce risk by emphasizing acquisition possibilities over high risk exploration projects.

     During the latter part of 2002, we reduced our emphasis on high risk exploration efforts and started focusing on established geologic trends where we can utilize the engineering, operational, financial and technical expertise of our entire staff. Although we anticipate participating in exploratory drilling activities in the future, reducing financial, reservoir, drilling and geological risks and diversifying our property portfolio are important criteria in the execution of our business plan. In summary, our current business plan:

	•	focuses on projects having less geological risk;
	•	emphasizes exploitation and enhancement activities;
	•	focuses on acquiring producing properties; and
	•	expands the scope of operations by diversifying our exploratory and development efforts, both in and outside of our current areas of operation.

     Although the direction of our exploration and development activities has shifted from high risk exploratory activities to lower risk development opportunities, we will continue our efforts, as we have in the past, to maintain low general and administrative expenses relative to the size of our overall operations, utilize advanced technologies, serve as operator in appropriate circumstances, and reduce operating costs.

     The extent to which we are able to implement and follow through with our business plan will be influenced by:

	•	the prices we receive for the oil and natural gas we produce;
	•	the results of reprocessing and reinterpreting our 3-D seismic data;
	•	the results of our drilling activities;
	•	the costs of obtaining high quality field services;
	•	our ability to find and consummate acquisition opportunities; and
	•	our ability to negotiate and enter into work to earn arrangements, joint venture or other similar agreements on terms acceptable to us.

     Significant changes in the prices we receive for our oil and natural gas, or the occurrence of unanticipated events beyond our control may cause us to defer or deviate from our business plan, including the amounts we have budgeted for our activities.

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Operating Performance

     Our operating performance is influenced by several factors, the most significant of which are the prices we receive for our oil and natural gas and our production volumes. The world price for oil has overall influence on the prices that we receive for our oil production. The prices received for different grades of oil are based upon the world price for oil, which is then adjusted based upon the particular grade. Typically, light oil is sold at a premium, while heavy grades of crude are discounted. Natural gas prices we receive are influenced by:

	•	seasonal demand;
	•	weather;
	•	hurricane conditions in the Gulf of Mexico;
	•	availability of pipeline transportation to end users;
	•	proximity of our wells to major transportation pipeline infrastructures; and
	•	world oil prices.

Additional factors influencing our overall operating performance include:

	•	production expenses;
	•	overhead requirements; and
	•	costs of capital.

     Our oil and natural gas exploration, development and acquisition activities require substantial and continuing capital expenditures. Historically, the sources of financing to fund our capital expenditures have included:

	•	cash flow from operations;
	•	sales of our equity securities;
	•	bank borrowings; and
	•	industry joint ventures.

     Depletion per BOE in 2004 was $7.05 versus $6.83 in 2003 and $10.52 in 2002. The increase per BOE in 2004 was a result of increased drilling costs and producing property acquisitions.

     Our oil and natural gas producing activities are accounted for using the full cost method of accounting. Under this accounting method, we capitalize all costs incurred in connection with the acquisition of oil and natural gas properties and the exploration for and development of oil

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and natural gas reserves. See Note 3 to the consolidated financial statements. These costs include lease acquisition costs, geological and geophysical expenditures, costs of drilling productive and non-productive wells, and overhead expenses directly related to land and property acquisition and exploration and development activities. Proceeds from the disposition of oil and natural gas properties are accounted for as a reduction in capitalized costs, with no gain or loss recognized unless a disposition involves a material change in reserves, in which case the gain or loss is recognized.

     Depletion of the capitalized costs of oil and natural gas properties, including estimated future development costs, is provided using the equivalent unit-of-production method based upon estimates of proved oil and natural gas reserves and production, which are converted to a common unit of measure based upon their relative energy content. Unproved oil and natural gas properties are not amortized, but are individually assessed for impairment. The cost of any impaired property is transferred to the balance of oil and natural gas properties being depleted.

Results of Operations

     We changed our business model in 2002 from exploration on the Gulf Coast to acquisition and exploitation of long life assets in the Permian Basin. At the beginning of 2002, our reserves were approximately 3.2 million barrels of oil equivalent with a reserves to production ratio of approximately 4 to 1. Through the execution of this business model, our reserves at the end of 2004 were approximately 21.7 million barrels of oil equivalent with a reserves to production ratio of approximately 18.3 to 1. At the end of 2002, our production was 77% natural gas and 23% oil compared to 38% natural gas and 62% oil at the end of 2004. The production stream changed from short life Gulf coast natural gas to long life Permian Basin oil and has increased our lease operating expense primarily due to increased utilities and chemicals associated with the oil properties.

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     The following table show selected data and operating income comparison for each of the three years ended December 31, 2004.

Critical Accounting Policies and Practices

     Full Cost and Impairment of Assets. We account for our oil and natural gas exploration and development activities using the full cost method of accounting. Under this method, all costs incurred in the acquisition, exploration and development of oil and natural gas properties are capitalized. Costs of non-producing properties, wells in process of being drilled and significant development projects are excluded from depletion until such time as the related project is developed and proved reserves are established or impairment is determined. At the end of each quarter, the net capitalized costs of our oil and natural gas properties, as adjusted for asset retirement obligations, is limited to the lower of unamortized cost or a ceiling, based on the present value of estimated future net revenues, net of income tax effects, discounted at 10%, plus the lower of cost of fair market value of our unproved properties. Revenues are measured at unescalated oil and natural gas prices at the end of each quarter, with effect given to our cash

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flow hedge positions. If the net capitalized costs of our oil and natural gas properties exceed the ceiling, we are subject to a ceiling test write-down to the extent of the excess. A ceiling test write-down is a non-cash charge to earnings. It reduces earnings and impacts stockholders’ equity in the period of occurrence and results in lower depreciation, depletion and amortization expense in future periods.

     The risk that we will be required to write down the carrying value of oil and natural gas properties increases when oil and natural gas prices decline. If commodity prices deteriorate, it is possible that we could incur an impairment in future periods.

     Depletion. Provision for depletion of oil and natural gas properties, under the full cost method, is calculated using the unit of production method based upon estimates of proved oil and natural gas reserves with oil and natural gas production being converted to a common unit of measure based upon their relative energy content. Investments in unproved properties and major development projects are not amortized until proved reserves associated with the projects can be determined or until impairment occurs. Oil and natural gas properties included $9.5 million and $2.3 million for 2004 and 2003, respectively, for unproved properties not included in depletion. The cost of any impaired property is transferred to the balance of oil and natural gas properties being depleted.

     Proved Reserve Estimates. Our discounted present value of proved oil and natural gas reserves is a major component of the ceiling calculation, and represents the component that requires the most subjective judgments. Estimates of reserves are forecasts based on engineering data, projected future rates of production and the timing of future expenditures. The process of estimating oil and natural gas reserves requires substantial judgment, resulting in imprecise determinations, particularly for new discoveries. Different reserve engineers may make different estimates of reserve quantities based on the same data. Our reserve estimates are prepared by outside consultants.

     The passage of time provides more qualitative information regarding estimates of reserves, and revisions are made to prior estimates to reflect updated information. However, there can be no assurance that more significant revisions will not be necessary in the future. If future significant revisions are necessary that reduce previously estimated reserve quantities, it could result in a full cost ceiling writedown. At December 31, 2004, the excess of the ceiling over our capitalized costs was approximately $84.0 million. In addition to the impact of these estimates of proved reserves on calculation of the ceiling, estimates of proved reserves are also a significant component of the calculation of depreciation, depletion and amortization.

     While the quantities of proved reserves require substantial judgment, the associated prices of oil and natural gas reserves that are included in the discounted present value of the reserves do not require judgment. Accounting principles generally accepted in the United States require that prices and costs in effect as of the last day of the period are held constant indefinitely. Accordingly, the resulting value is not indicative of the true fair value of the reserves. Oil and natural gas prices have historically been cyclical and, on any particular day at the end of a quarter, can be either substantially higher or lower than prices we actually receive in the long-term, which are a barometer for true fair value.

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     Use of Estimates. The preparation of consolidated financial statements in accordance with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect reported assets, liabilities, expenses, and some narrative disclosures. Hydrocarbon reserves, future development costs and certain hydrocarbon production expense are the most critical estimates to our consolidated financial statements.

     Derivatives. The Financial Accounting Standards Board issued SFAS No. 133 and SFAS No. 138 requiring that all derivative instruments be recorded on the balance sheet at their respective fair values. We adopted SFAS No. 133 and SFAS No. 138 on January 1, 2001. For the periods prior to January 1, 2003, derivative contracts were not designated as hedges. Accordingly, the unrealized gains or losses were recorded in income. As of January 1, 2003 we designated costless collars, oil and gas swaps, and interest rate swaps as cash flow hedges. Accordingly, the effective portion of the unrealized gain or loss on cash flow hedges is recorded in other comprehensive income until the forecasted transaction occurs. We continued to record the unrealized loss on put positions outstanding in income during 2003. The purpose of our hedges is to provide a measure of stability in our oil and natural gas prices and interest rate payments and to manage exposure to commodity price and interest rate risk under existing sales contracts.

     Overhead Reimbursement — Joint Operations. As compensation for administration, supervision office services and warehousing cost, an operator may charge drilling and producing overhead costs based upon rates negotiated in the joint operating agreement.

     Overhead reimbursements charged to working interest owners for properties that we operate are treated as reductions in general and administrative expense for producing overhead. Capital costs were reduced by approximately $19,000 and $34,000 for 2004 and 2003, respectfully. General and administrative costs were reduced by approximately $324,000 and $123,000 for drilling and producing overhead reimbursements for 2004 and 2003, respectfully.

     Prior to 2003, overhead was recorded as other income. The amounts reimbursed to us for 2002 were $20,000.

     Incentive and Retention Plan. Parallel will account for the Plan under the provisions of Statement of Financial Accounting Standards No. 5, “Accounting for Contingencies” (SFAS No. 5). Parallel has determined that the likelihood of the occurrence of a corporate transaction or change of control, as defined in the Plan, is possible, however, the ultimate liability to Parallel is not readily determinable because of the inability to predict Parallel’s stock price on the future date of any corporate transaction or change of control. Therefore, the terms and conditions of the Plan will be disclosed in Parallel’s consolidated financial statements, but no liability will be recorded until such time as a corporate transaction or a change of control occurs.

Years Ended December 31, 2004 and December 31, 2003

     Our oil and natural gas revenues and production product mix are displayed in the following table for the years ended December 31, 2004 and 2003.

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Oil and Gas Revenues

     The following table outlines the detail of our operating revenues for the following periods.

     Oil revenues, excluding hedges, increased $10.2 million or 55% for the year ended 2004 compared to 2003. Oil production volumes increased 16% attributable to re-stimulations and additional acquisitions in the Fullerton San Andres Field, acquisitions in the Carm-Ann San Andres Field/N. Means Queen Unit and the drilling of producing and injection wells on our Diamond M Property. The increase in oil production increased revenue approximately $3.9 million for 2004. Wellhead average realized crude oil prices increased $9.94 per Bbl or 34% to $39.05 per Bbl for 2004 compared to 2003. The increase in oil price increased revenue approximately $6.3 million for 2004.

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     Natural gas revenues, excluding hedges, decreased $2.4 million or 13% for the year ended 2004 compared to 2003. Natural gas production volumes decreased 20% due to natural production declines in our south Texas Yegua/Frio and Cook Mountain projects. The decline in natural gas volumes decreased revenue approximately $3.6 million for 2004. Average realized wellhead natural gas prices increased 8% or $0.45 per Mcf to $5.85 per Mcf. The increase in natural gas prices had a positive effect on revenues of approximately $1.2 million for the period ending 2004.

     Losses on oil hedges increased $5.8 million or 350% for 2004 compared to 2003 due to the increase in oil prices. Natural gas hedge losses were $895,000 in 2004 compared to $907,000 in 2003. Although natural gas prices increased 8% in 2004, we had less natural gas volumes hedged for 2004. On a BOE basis, hedges accounted for a realized loss of $7.10 per BOE in 2004 compared to $2.16 per BOE in 2003.

     We have hedged certain oil and natural gas volumes (see Note 5 to Consolidated financial statements) to try and mitigate price changes in our oil and natural gas movements and to meet the requirements under our loan facility. Based upon our 2005 hedges currently in effect and if 2004 prices and volumes are held constant, a 10% increase in oil prices would have the effect of increasing oil revenues in fiscal 2005 by $1.9 million. Using the same parameters, a 10% decrease in oil prices would have an effect of an increase of approximately $1.6 million for 2005. At the end of 2004, in association with our property acquisitions, we hedged additional oil volumes for 2005 thru 2008, thereby increasing the average price hedged over 2004. This is the reason a decrease in oil prices can have a positive effect on this comparison. Based upon our 2005 hedges currently in effect and if 2004 prices and volumes are held constant, a 10% increase in gas prices would have the effect of increasing gas revenues in fiscal 2005 by $2.2 million. Using the same parameters, a 10% decrease in gas prices would have an effect of a decrease of approximately $765,000 for 2005.

Cost and Expenses

     Lease operating expense increased 14% or $915,000 compared to 2003. During 2004, 62% of our production was crude oil compared to 53% in 2003. The change in our business plan to long-life assets which influenced our purchase of assets in the west Texas Fullerton, Carm-Ann and work-to-earn agreement at Diamond M has shifted our production and reserves away from a natural gas base to a crude oil base. This shift has increased the lease operating expense due to the mechanical operations and utilities required to produce oil properties compared to

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natural gas properties. Lifting costs were $8.06 per BOE in 2004 compared to $7.07 per BOE in 2003 on a BOE basis. As we continue to exploit and develop our long-life Permian Basin oil properties (Fullerton, Carm-Ann and Diamond M), we expect that lifting costs will continue around the same level or decline due to increased activity. The lifting costs are also expected to be reduced by the development of natural gas properties in south Texas, Barnett Shale and New Mexico.

     Production taxes increased 8% or $162,000 in 2004, associated with a net wellhead increase in revenues of $7.8 million. Production taxes in future periods will be a function of product mix, production volumes and product prices.

     General and administrative in total increased 24% or $1.0 million in 2004 compared to 2003. Included in our total general and administrative costs is public reporting cost which increased 70% or $930,000 for 2004. The increase in public reporting cost was attributable to audit costs associated with the change of auditors at the end of 2003 and increased legal costs and costs attributable to the work on our internal control over financial reporting under Section 404 of the Sarbanes-Oxley Act of 2002 or “SOX 404”. The SOX 404 costs have been a significant portion of the increase in our public reporting costs and we expect SOX 404 costs to continue into 2005. General and administrative expenses capitalized to the full cost pool were $1.1 million for 2004 compared to $900,000 for 2003. On a BOE basis, general and administrative costs were $2.65 per BOE in 2004 compared to $2.54 per BOE in 2003, while public reporting costs were $1.92 per BOE and $1.12 per BOE for the same period. General and administrative expenses will increase in 2005 in association with reporting requirements and operational support of current and new acquisitions.

     Depreciation and depletion expense increased 4% or $322,000 for 2004 compared to 2003. Depletion per BOE was $7.05 for 2004 and $6.83 for 2003. This increase is attributable to increased drilling costs and producing property purchases. Depreciation expense increased with the cost of a new accounting and production system in 2004. Depletion costs are highly correlated with production volumes and capital expenditures. Fiscal year 2005 depletion costs will increase with increased production volumes.

     Other income (expense)