Unassociated Document

5555 San Felipe, Suite 725, Houston, TX 77056 (713) 622-5550 fax (713) 622-5552

November 29, 2006

April Sifford

Branch Chief

United States Securities and Exchange Commission

Division of Corporation Finance

100 F Street, N.E.

Washington, D.C. 20549-7010 via Federal Express

Re:	Securities and Exchange comment letter dated September 29, 2006
	Form 10-KSB for Fiscal Year Ended December 31, 2005

Dear Ms. Sifford:

We enclose the following material with regard to the referenced matter:

Capco Energy, Inc. response letter dated November 29, 2006

Schedule 1-ceiling test analysis, December 31, 2005 (comment #3)

Schedule 2-reconciliation of changes in proved reserves for year 2005 (comment #10)

Amendment #2 to Annual Report on Form 10-KSB/A for the fiscal year ended December 31, 2005, marked to show changes in response to the comment letter

Copy of Ryder Scott Company reserve evaluation report as of December 31, 2005

If you have questions, or require additional information at this time, please contact the undersigned.

Very truly yours,

Walton C. Vance

Chief Accounting Officer

5555 San Felipe, Suite 725, Houston, TX 77056 (713) 622-5550 fax (713) 622-5552

November 29, 2006

April Sifford

Branch Chief

United States Securities and Exchange Commission

Division of Corporation Finance

100 F Street, N.E.

Washington, D.C. 20549-7010

Re:	Form 10-KSB for Fiscal Year Ended December 31, 2005

Dear Ms. Sifford:

We provide the following in response to your letter dated September 29, 2006:

Evaluation of Disclosure Controls and Procedures, page 22

The disclosure has been revised to describe the steps that have been taken to correct the situation described in the disclosure. We anticipate that the deficiencies will be corrected no later than December 31, 2006.

Changes in Internal Controls, page 22

The disclosure has been revised to state that there have been no changes in the Company’s internal control over financial reporting during the last fiscal quarter that have materially affected, or are reasonably likely to materially affect, the Company’s control over financial reporting.

Consolidated Balance Sheet, page F-3

The Company’s ceiling test analysis (schedule 1 enclosed) reports an excess of ceiling over cost in the amount of $2.4 million. As indicated in the analysis, the book carrying value of oil and gas property has been reduced by $1.9 million for plugging and abandonment costs that are included in the book figures and also in the determination of discounted future net revenue. Not making the adjustment would result in a duplication of such costs in the analysis.

Liquidity and Capital Resources, page 16

The Company’s liquidity discussion has been revised to disclose the funding commitment of $74.7 million for the pending acquisition and the expected source of funds to satisfy the commitment.

Notes to Consolidated Financial Statements

Note 2-Business Combination, Acquisition and Divestitures, page F-17

As part of its ongoing oil and gas activities, the Company evaluates producing properties for possible acquisition. Beginning in late year 2004 and continuing into the first half of year 2005, screened acquisitions were presented to the management of Hoactzin Partners, L.P. (“Hoactzin”) for their consideration. Hoactzin is an unaffiliated investment fund located in New York City. Its management has other oil and gas investments and was introduced to the Company as a possible source of capital for oil and gas property acquisitions.

The Company and Hoactzin negotiated an arrangement whereby any target property selected by Hoactzin for acquisition would be contracted for by Capco with the selling party. Any earnest money deposits required as part of the negotiations would be funded by Hoactzin to be recorded as short-term loans to the Company. When the acquisition was closed, generally two to three months later, the closing was to be in the name of the Company; however, the property interests would immediately be conveyed to Hoactzin. Proceeds required at closing were to be funded by Hoactzin, and the short-term loan and corresponding deposit recorded by the Company when the deposit was funded were to be reversed from the Company’s accounts.

The first acquisition subject to this arrangement took place in the fourth quarter of 2004 with funding of the earnest money deposit provided by Hoactzin. The acquisition closed in February of 2005, with proceeds at closing provided by Hoactzin. The acquired property was located in Federal waters off the coast of Texas, which required that Hoactzin be approved by the Minerals Management Service (“MMS”) as an owner of Federal leases before the property could be conveyed to Hoactzin. This requirement delayed the immediate transfer of the acquired property interests to Hoactzin. In the first quarter of year 2005, Hoactzin acquired interests in two properties owned and operated by the Company. For total consideration of $1.5 million, Hoactzin acquired interests in the Company’s Brazos Field (partial interests in two producing wells and one idle well), and an interest in an exploratory well being drilled in offshore Federal waters. The $1.5 million proceeds were recorded as a reduction of the Company’s full cost pool as the transaction did not have a significant effect on the Company’s cost depletion rate.

In March of 2005, Hoactzin agreed to acquire interests in wells located offshore the state of Louisiana, in both Federal and state waters. The Company contracted for the purchase of the property interests, and in May 2005, the acquisition closed. At that time, Hoactzin had secured approval from the MMS to be an owner of Federal leases, so all properties acquired by Hoactzin, beginning with the acquisition that closed in February 2005, were conveyed to Hoactzin. The Purchase and Sale Agreement (“Agreement”) that was executed on May 4, 2005, with Hoactzin provided for the conveyance of all of the acquired property interests from the Company to Hoactzin.

At that same time, the Company and Hoactzin entered into a Management Agreement (“Agreement”), which provided the terms under which the Company would be the manager/operator of the acquired property interests for Hoactzin. In addition, the Agreement stipulated the compensation due to the Company as manager/operator, including net profit distributions that become payable upon Hoactzin achieving payout of its investment and the terms under which the Company could acquire ownership of the property interests. Additionally, the Agreement provided for the issuance of Warrants by the Company to Hoactzin based on the level of expenditures incurred by Hoactzin.

To date, the Company has not recorded any costs related to this arrangement in its full cost pool as the Company does not own any portion of the acquired property interests; the property interests are owned exclusively by Hoactzin.

The Company has reported in its balance sheet as “cost of financing under management agreement” the fair value of the Warrants granted to Hoactzin. At December 31, 2005, the fair value of the Warrants, plus certain cash expenditures incurred by the Company, totaled $10.1 million. As described in Note 2 (page F-18), the Company will begin amortization of this amount once Hoactzin’s investment has reached payout and net profit distributions to the Company have been initiated.

Note 15-Subsequent Events, page F-31

The disclosure in the Subsequent Events footnote is intended to provide the reader with updated information as to the remaining amount of Hoactzin’s investment that is to be recovered in order to achieve payout. As described in the Annual Report, the Company begins to receive a management fee equivalent to two-thirds of Hoactzin’s net cash flow once payout is achieved.

Exhibits 31.1 and 31.2

Exhibits 31.1 and 31.2 have been revised so that the certifications are worded exactly as contained in Regulation S-B Item 601 (b) (31).

Form 10-QSB for the Fiscal Quarters Ended June 30, 2005, September 30, 2005, March 31, 2006, and June 30, 2006

During the second quarter of year 2005, the Company closed its initial transaction with Hoactzin Partners, LP (discussed above). It was during this same time period that the Company was contemplating a change of independent accountants. The decision was made to effect the change of accountants at that time so that the accounting firm that would be providing audit services at the end of the fiscal year would also be involved in the review of the Hoactzin transaction from its inception. The process of engaging a replacement independent accounting firm was not completed until October 2005. The year end audit was completed in June 2006 and the annual report on Form 10-KSB was filed on August 11, 2006. Following that filing the Company has endeavored to prepare the interim period reports for filing as soon as possible. All of the periodic reports are in various stages of completion. The June 30, 2005, and September 30, 2005, reports are complete and have been provided to our independent accountants for their review. Financial statements for the two interim period reports for year 2006 are complete; the remainder of each interim report is being drafted. Upon completion these interim reports will be forwarded to our independent accountants for review.

Engineering Comments

Item 2. Description of Properties, page 9

Productive Wells, page 13

The disclosure of 93 gross oil wells that are producing or “capable of production including wells that are shut in” is attributable to the following three properties:

	Producing or capable	Currently
	of production	producing (1)	Shut-in

Bandwheel, Osage Co.,
Oklahoma	36	15	21
SUDS West, Creek Co.,
Oklahoma	55	13	42
Caplen Field, Galveston
Co., Texas	2	2	-

Totals	93	30	63

(1) as reported by IHS Petroleum Data for the month of December 2005

No amount of proved reserves was attributed to the shut-in wells.

Notes to Consolidated Financial Statements, page F-11

Supplemental Information About Oil and Gas Producing Activities (Unaudited), page F-31

The engineering report for year 2005, in hard copy, is included with this response letter.

Included with this letter is a reconciliation of changes to proved reserves from the beginning of 2005 to year-end (schedule 2), including detailed property-level technical information.

The Company did not discharge a consulting engineer due to disagreements over reserve estimates.

Standardized Measure of Discounted Net Cash Flows and Changes Therein, page F-33

The standardized measure for the year ending 2004 will be included in future documents, beginning with Amendment No. 2 to Form 10-KSB/A for the fiscal year ended December 31, 2005.

In preparation of its filings under the Securities Act of 1934, the Company acknowledges that:

·	The Company is responsible for the adequacy and accuracy of the disclosures in the filings;

·	staff comments or changes to disclosures in response to staff comments do not foreclose the Commission from taking any action with respect to the filings; and

·	the Company may not assert staff comments as a defense in any proceeding initiated by the Commission or any person under the federal securities laws of the United States.

Very truly yours,

Walton C. Vance

Chief Accounting Officer

Capco Energy, Inc.

Ceiling Test Analysis
12/31/2005		Schedule 1

Historical balances
Capitalized costs	17,525,627
Accumulated depletion	(2,902,401	)
Net book carrying value	14,623,226

Less portion of P&A costs included above which are also
in engineer's determination of PV10 (from Proved Reserves)	(1,915,998	)
Remaining basis	12,707,228


Estimated future net revenue
Undiscounted
Discounted @ 10%	16,673,058

Plus cost of property not being amortized	0

Less future income taxes @ 39%	(1,546,674	)
(= DFNR - basis @ 39%)

Estimated ceiling amount	15,126,384

Excess of ceiling over cost	2,419,156

Capco Energy, Inc.

Reserve Rollforward
12/31/2005	Schedule 2


		United States									Slick			Caplen			Coyle		B'wheel			Brazos 440			Brazos 478			Gr Ranch			Caplen			Brazos 440			Brazos 478			Gr Ranch
		Bbls			Mcf			BOE			Bbls			Bbls			Bbls		Bbls			Bbls			Bbls			Bbls			Mcf			Mcf			Mcf			Mcf
											A			B			C		D			E			F			G			H			E			F			G
YEAR 2005
Beginning of year	PDP		18,595			992,987			184,093			14,536											463			2,343			1,253						359,096			556,609			77,282
	PDNP		289,223			465,300			366,773			223,633			62,329								3,222			39						33,336			363,609			68,355
	PU		78,862			1,657,984			355,193						78,862																	201,408			1,456,576
			386,680			3,116,271			906,059			238,169			141,191			0		0			3,685			2,382			1,253			234,744			2,179,281			624,964			77,282

Acquisitions	PU		42,750						42,750									42,750

Extensions and discoveries			0						0

Revisions of previous estimates	PDP		84,395			456,663			160,506			2,138			35,738			0		46,366			2,221			(1,030	)		(1,135	)		0			612,434			(102,056	)		(53,725	)
	PDNP		(282,565	)		3,698,327			333,823			(223,633	)		(62,329	)		0		0			3,418			(21	)		0			(33,336	)		3,768,470			(36,807	)		0
	PU		(78,862	)		(1,657,984	)		(355,193	)		0			(78,862	)		0		0			0			0			0			(201,408	)		(1,456,576	)		0			0

Production	PDP		(12,620	)		(293,199	)		(61,487	)		(2,204	)		(4,333	)				(5,501	)		(165	)		(232	)		(88	)		0			(87,330	)		(197,657	)		(8,202	)

Sales of minerals in place	PDP		(1,295	)		(422,633	)		(71,734	)													(214	)		(1,081	)								(165,737	)		(256,896	)
	PDNP		(18	)		(31,548	)		(5,276	)																(18	)											(31,548	)
End of year			138,465			4,865,897			949,448			14,470			31,405			42,750		40,864			8,945			0			30			0			4,850,542			0			15,355

	PDP		89,075			733,818			211,378			14,470			31,405					40,865			2,305						30						718,463						15,355
	PDNP		6,640			4,132,079			695,320														6,640												4,132,079
	PU		42,750						42,750									42,750

A	Year 2004 report included PDP category assuming full restoration of waterflood reserves based on a study done several years previous. The year 2005 report gave no credit to this category of reserves as there had been no development activity during the intervening years.

B	At end of year 2004, there were no wells in current production. PDNP reserves were assigned based on production rates in effect when the wells were in production earlier in the year. Wells were returned to
	production during the year 2005, but at lesser rates than in 2004. Year 2005 PDP reserves reflect the reduced production rates.

	PUD reserves were dropped from the 2005 report as the current operator had not drilled any wells since acquiring the property in year 2000, and had no plans to drill in year 2006.

C	PUD credit assigned to property acquired during year 2005.

D	No reserves assigned to this property in 2004 as there was only start up activity by Capco at the end of year 2004. PDP reserves assigned for year 2005 based on 2005 production rates and expenses.

E	Based on year 2005 production and rework activities that began in fourth quarter of 2005 on shut-in wells, the estimate of proved reserves increased. One additional well was on-line at the end of year 2005, with re-work activities scheduled for at least three shut-in wells in the first quarter of year 2006

F	Well was not producing in commercial quantities, and no proved reserves were assigned at end of year 2005.

G	Year 2005 estimate was reduced based on actual production performance during the year.

H	There was no gas production during the year 2005, and engineers did not assign any credit for PUD locations as there were no plans to drill in year 2005.

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-KSB/A

Amendment No. 2 to Form 10-KSB

x ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES AND EXCHANGE ACT OF 1934

For the Fiscal Year Ended December 31, 2005

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

Commission File No. 0-10157

CAPCO ENERGY, INC.

(Exact Name of Small Business Issuer as Specified in its Charter)

COLORADO	84-0846529
(State or other jurisdiction of	(I.R.S. Employer Identification No.)
Incorporation or Organization)

5555 San Felipe, Suite 725, Houston, TX 77056

(Address of Principal Executive Office, Including Zip Code)

Registrant's telephone number including area code: (713) 622-5550

Securities registered pursuant to Section 12(b) of the Act: None.

Securities registered pursuant to Section 12(g) of the Act:

COMMON STOCK, $.001 PAR VALUE

Title of Class

Indicate by check mark whether the Registrant (1) has filed all reports required to have been filed by Section 13 or 15(d) of the Securities and Exchange Act of 1934 during the preceding 12 months or for such shorter period that the Registrant was required to file such reports and (2) has been subject to such filing requirements for the past 90 days. Yes x No o

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation SB 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-KSB or any amendment to this Form 10-KSB.

Yes o No x

Indicate by checkmark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act) Yes o No x

State Issuer's revenues for its most recent fiscal year: $3,572,000.

As of June 30, 2006, 116,080,769 shares of Common Stock were outstanding. The aggregate market value of the Common Stock of the Registrant held by non-affiliates on that date was approximately $11.7 million.

Transitional small business disclosure format Yes o No x

This Amendment No. 2 to Form 10-KSB is being filed in response to comments received from the Securities and Exchange Commission (“Commission”) by letter dated September 29, 2006, following the Commission’s review of Form 10-KSB for the year ended December 31, 2005, that was originally filed on August 11, 2006.

PART I

ITEM 1. DESCRIPTION OF BUSINESS.

GENERAL DEVELOPMENT OF BUSINESS

Capco Energy, Inc. ("Capco", the "Company", “we”, “us”, and “our”), with our mailing address at 5555 San Felipe, Suite 725, Houston, TX 77056, was incorporated as Alfa Resources, Inc. a Colorado corporation on January 6, 1981. In November 1999, we changed our name to Capco. We were organized for the purpose of engaging in oil and gas exploration, development and production activities.

In November 2003, we purchased properties in the Brazos Field, offshore in Matagorda County, Texas. We own a 65% working interest in a majority of the property and we are the operator of the acquired property. The acquired properties consist of 22 wells, four of which are currently in production.

In December 2004, we acquired a 100% working interest in an oil property consisting of approximately 80 wells located in Osage County, Oklahoma.

In February 2005, we acquired producing properties in High Island Block 196, which were to be assigned to a third party pending approval of that party as a holder of Federal oil and gas leases by the Minerals Management Service.

In March 2005, we sold 30% of our working interest ownership in two producing wells and one idle well in the Brazos Field.

On May 4, 2005, we closed on a Purchase and Sale Agreement and Management Agreement (“Agreement”) with Hoactzin Partners, L.P., (“Hoactzin”), an oil and gas investment affiliate of New York based investment firm Dolphin Asset Management Corp. We sold to Hoactzin the interests in High Island Block 196 which were acquired in February 2005, a portion of our interests in two producing wells and one idle well in the Brazos Field in Texas state waters, and a portion of our interest in the OCS Galveston Block 297 well on which drilling operations were in progress at that date. The Agreement also included working interests ranging from 14% to 100% in 11 producing wells situated on approximately 13,300 gross acres located in St. Bernard Parish, Louisiana, and Chandeleur Area, OCS Blocks 27, 29 and 30. The contract acquisition price of $20.0 million, plus a production payment of $1.0 million, was reduced to a closing cost of $12.1 million, after adjustment for net revenue credits for the period from the effective date to the closing date and for a cash deposit of $1.0 million paid by us. Hoactzin paid all of the funds required at closing, except for $0.1 million that we paid. The production payment is to be paid from 25% of the revenue produced by the acquired property interests once payout of the initial acquisition cost of $20.0 million has occurred.

Hoactzin had previously provided funding in the amount of $4.9 million for the acquisition of the High Island Block 196 property. Included in that amount was $2.0 million that was deposited with our surety company as collateral for bonds that were posted with the Minerals Management Service. Hoactzin had also advanced $1.5 million for the pending acquisition from us of working interests in three wells in the Brazos Field and the well being drilling in the OCS Galveston Block 297. We reported the total proceeds of $6.4 million as a note payable for a portion of the year 2005 until Hoactzin received owner approval from the Minerals Management Service, enabling us to assign the property interests to Hoactzin.

On November 30, 2005, Hoactzin closed on the acquisition of a producing oil property located in Orange County, Texas. Hoactzin funded the total acquisition cost of $2.6 million. The acquired property consists of approximately 550 acres and includes 130 previously drilled wells, of which 20 were in current production. As operator of the property, Capco intends to begin a program to return idle wells to production.

The Agreement is governed under the terms of a Management Agreement between the parties. Hoactzin owns title to the properties and retains all cash flow from the properties until their investment, including a return of 8% on the invested funds, is repaid (“Repayment Date”), at which time we will receive a management fee equal to 66.7% of the net cash flow from the properties. We have the option to purchase the property interests from Hoactzin at any time after the one-year anniversary of the Repayment Date, and Hoactzin has the option to sell its property interests to us at any time after the two-year anniversary of the Repayment Date. The option prices are based on formulas specified in the Management Agreement.

As of December 31, 2005, Hoactzin had expended a total of $21.2 million under this Agreement. Interest earned on invested funds totaled $0.8 million, and distributions of net cash flow to Hoactzin amounted to $11.4 million, resulting in a remaining investment balance of $10.6 million.

In connection with the acquisition of the Chandeleur Area properties, we secured participation from two outside investors. We used the proceeds from these investors, in the total amount of $0.7 million, to fund a portion of the $1.1 million that we contributed to the total acquisition cost of these properties. The proceeds were recorded as a reduction of our basis in the Agreement. For the consideration paid to us, the investors received a total of 5.5% of our rights and title to the Chandeleur Area properties. For an initial period of twelve months, beginning July 1, 2005, the investors are receiving distributions at the rate of $66,000 per month. At the end of that period, the investors’ accounts will be adjusted to reflect any difference between the cash distributions paid during the period and actual cash flow from the properties attributable to the 5.5% interest, with a settlement of funds either due to, or from, the investors. In addition, effective July 1, 2006, the investors will begin to receive payments equal to 5.5% of actual net cash flow from the Chandeleur Area properties.

At the closing of the Agreement with Hoactzin, we issued a series of common stock purchase warrants (“Warrants”) to Hoactzin. The Warrants are exercisable into a total of 24,226,181 shares of the Company’s Common Stock at initial exercise prices ranging from $0.176 to $0.30, subject to adjustments pursuant to the anti-dilution provisions set forth in the Warrants, and expire five (5) years from date of issue. The Warrants may be exercised upon payment of cash, exchanged for our Common Stock, or applied as a credit against the Aggregate Investment Amount (“AIA”), as that term is defined in the agreements. Using the Black-Scholes pricing model with a Common Stock price of $0.50, which was the closing price on the grant date of the Warrants, it was determined that the Warrants had a fair value of $10.8 million. This amount has been accounted for as Cost of Financing Under Management Agreement for obtaining the management fee as provided for in the Management Agreement, with a corresponding increase to our paid in capital account. The $2.0 million cash deposit with our surety company was allocated from this amount to be reported with other similar cash deposits. Cash payments in the total amount of $1.1 million that we contributed to the Agreement in connection with the acquisition of the Chandeleur Area properties have also been accounted for as Cost of Financing Under Management Agreement.

During the eight-month period from closing of the Agreement in May 2005 to December 31, 2005, Hoactzin expended an additional $2.9 million principally in connection with an acquisition of a producing oil field in southeast Texas. This expenditure resulted in grants of 5,248,196 Warrants with a calculated fair value, using the Black Scholes pricing model, of $0.9 million. This amount has been accounted for as Cost of Financing Under Management Agreement, with a corresponding increase to our paid in capital account. Hoactzin expended an additional $1.9 million in connection with the re-financing of a former subsidiary’s indebtedness for which we were providing a continuing guaranty. The re-financing resulted in our removal as a guarantor of the indebtedness. Warrants in the amount of 1.9 million with a calculated fair value of $0.3 million, using the Black Scholes pricing model, were granted to Hoactzin as a result of this expenditure. We have charged this cost to operations with a corresponding increase to our paid in capital account. All of the Warrants issued during this period have an exercise price of $0.195, and expire five (5) years from date of issue.

Effective October 1, 2005, we executed a Funding Agreement (“Agreement”) with Domain Development Partners I, LP (“Domain”), providing for the development of idle wells in our Brazos area in offshore Matagorda County, Texas. Under the terms of the Agreement, Domain would provide funding to pay for our portion of costs to rework as many as fifteen idle wells in an attempt to restore the wells to production. Domain’s only recourse for repayment of the funds expended is the revenue that results from such rework activities. Domain will receive 70% of our revenue interest in the wells until such time that it has received reimbursement for 150% of its expended cost, at which time Domain’s interest in our revenue will decrease to 35%. Following recovery of 200% of its expended cost, Domain will cease to have an interest in the wells. In connection with this transaction we issued warrants to Domain to acquire, for a period of two years, up to five million shares of Common Stock at a price of $0.175 per share. Using the Black-Scholes method of valuation, the warrants were determined to have a fair value of $0.4 million, which cost has been included in our full cost pool with a corresponding credit to paid in capital. As of December 31, 2005, rework activities had commenced on two wells at a cost of approximately $0.2 million. Domain had advanced funds in the amount of $0.2 million to pay such costs. Domain has been provided with a security agreement covering the wells for which it will be providing funding.

NARRATIVE DESCRIPTION OF BUSINESS

GENERAL

We are an independent energy company engaged primarily in the acquisition, exploration, development, production for and sale of oil, gas and natural gas liquids.

OIL AND GAS PRODUCTION

Property Acquisitions and Sales during 2004 and 2005

In February 2004, we purchased a production platform with nine additional wells in the Brazos Field, offshore in Matagorda County, Texas. We own a 90% working interest in the wells and will be operator of the property. In conjunction with the acquisition, we plan to acquire leases for the mineral interests at an estimated cost of $0.1 million. Such expenditure is necessary before we can initiate production from any of the acquired wells. Under the terms of the agreement, the seller agreed to contribute as much as $1.0 million to apply toward payment of abandonment costs when, and if, we incur such costs.

In February 2004, we drilled a coal bed methane well in Stephens County, Texas. The well was drilled to a depth of 1,100 feet at a cost of $0.1 million, and following a period of “dewatering” and evaluation was determined to be non-productive. By drilling the well we earned the right to negotiate the purchase of a leasehold interest in approximately 4,000 acres, along with wells previously drilled on the property.

Effective July 1, 2004, we acquired a 92.8% working interest in this 4,000 acre property in Stephens County, Texas. In addition to the acreage, the acquisition included one producing gas well drilled by the former owners, the coal bed methane well drilled by us during the year and seismic and geological studies. We issued 3.6 million shares of Common Stock as consideration valued at $0.4 million. The per share price of $0.16 approximated the market price of our Common Stock at that time. Approximately 70% of the acquired working interest in the property was acquired as a result of our exchange of shares for 100% equity ownership of Packard Gas Company with individuals, or entities controlled by individuals, who have either a direct, or beneficial, relationship to us, including our President. The negotiated acquisition price was determined in amounts prorated to all members of the selling group. Subsequent to the exercise of our option, we drilled and completed a gas well on the property at a cost of $0.2 million. Following a period of evaluation of the two producing gas wells the decision was made to discontinue further drilling activities on the property, and as a result, we only earned acreage attributable to each well location actually drilled on the property. In July 2004, we participated with a 15% working interest in the acquisition of leases covering approximately 7,000 gross acres in a drilling prospect located in Fayette County, Alabama. Two wells were drilled on the property and both were determined to be incapable of commercial production. We plan to further evaluate the undeveloped acreage to determine if additional drilling is warranted. We incurred expenditures for lease acquisition and drilling costs in the total amount of $0.2 million for our 15% participation.

In September 2004, our 80%-owned subsidiary, Bison Energy Company, acquired a 33.33% working interest in an oil property located in Natrona County, Wyoming at a cost of $30,000. The property consisted of 720 gross acres and included nine wells, four of which were in production. We sold our interest in Bison Energy Company in April 2005, at a price equal to our original investment.

Effective September 30, 2004, we sold our interests in non-operated producing properties located in Alabama and Louisiana to a company owned by our Chief Executive Officer. Sales proceeds in the amount of $0.4 million were received by us in October 2004 and were used for working capital. The sales proceeds were credited against our basis in oil and gas properties. No gain or loss was recognized from the sale as the disposition represented only 3% of our proved reserves at the time of sale. If it is determined through due diligence by us that the properties could have been sold for an amount greater than $0.4 million, then the related party has the obligation to pay such excess to us, or we, at our option, may repurchase the properties at the original sales price. No adjustment was made in 2005 to the transaction as originally recorded.

In October 2004, we acquired a 45% working interest in two properties located in Creek County, Oklahoma. The properties consisted of approximately 100 oil wells, the majority of which were not in production at the time of acquisition by us. Under the terms of the purchase agreement we are obligated to expend a total of $0.6 million over a specified period of time in an effort to bring injection and production wells back in to service to earn the entire 45% interest. In mid-year 2005, we acquired an additional 5% working interest from another joint interest owner, increasing our working interest to 50%. As of December 31, 2005, we had expended an amount in excess of the $0.6 million development obligation to earn our entire working interest position.

In December 2004, we acquired a 100% working interest in an oil property consisting of approximately 80 wells located in Osage County, Oklahoma. The acquisition cost of $0.2 million was to be settled by the issuance of 1.0 million shares of our Common Stock. The per share price of $0.20 approximated the market price of our Common Stock at the time the agreement was negotiated with the seller. The Common Stock was issued in March 2005. The seller of the property retained a net profits interest in the amount of $0.3 million that is to be paid from one-third of the net production from the property until paid in full. A total of $14,000 was paid against this obligation during the year 2005. The net profit distributions will be included with the acquisition cost of the property as we pay them. In addition, the purchase agreement stipulated that we expend a minimum of $0.1 million of property development costs within one year from the date of acquisition. Such costs were expended during the year 2005.

On December 31, 2004, we sold our interests in non-operated producing properties located in Michigan and Montana and other assets to our Chief Executive Officer for $4.7 million. We received a fairness opinion for the sale in January 2005. The sales amount was settled by the payment of a cash deposit in the amount of $0.7 million, assumption of debt against the properties in the amount $3.3 million and the issuance of a note payable to us in the amount of $0.7 million. The note was paid in full in March 2005. The disposition resulted in a significant change to the depletion rate in our full cost pool cost center, which required that gain or loss recognition be given to the sale. We recorded a gain in the amount of $0.4 million from the sale.

In February 2005, we commenced drilling operations on an exploratory well in Outer Continental Shelf (“OCS”) Galveston Block 297. Capco was the operator of the well, which was targeted for a total depth of 13,500 feet. If successful we would own a 27% working interest in the well, with the remaining interest owned by other oil and gas companies. Drilling activities were significantly extended past the anticipated timeline as it became necessary to sidetrack and re-drill a portion of the well due to encountering excessive gas pressures at a depth of approximately 13,350 feet. The well was drilled to its target depth and tested for the presence of hydrocarbons, but in the opinion of management and the other participants, the test results did not warrant a completion attempt, and the well was plugged and abandoned in May 2005. We filed a claim with our insurance company for recovery of a portion of the additional costs incurred during the drilling of the well, and received $3.2 million for our interest in November 2005. Our cost of drilling the well, after reduction for insurance proceeds and turnkey payments received from some of the participants in the well, was $2.8 million.

In March 2005 we received proceeds of $0.5 million for the sale of a portion of our working interest ownership in two producing wells and one idle well in the Brazos Field.

Effective October 1, 2005, we executed a Funding Agreement (“Agreement”) with Domain Development Partners I, LP (“Domain”), providing for the development of idle wells in our Brazos area in offshore Matagorda County, Texas. Under the terms of the Agreement, Domain would provide funding to pay for our portion of costs to rework as many as fifteen idle wells in an attempt to restore the wells to production. Domain’s only recourse for repayment of the funds expended is the revenue that results from such rework activities. Domain will receive 70% of our revenue interest in the wells until such time that it has received reimbursement for 150% of its expended cost, at which time Domain’s interest in our revenue will decrease to 35%. Following recovery of 200% of its expended cost, Domain will cease to have an interest in the wells. In connection with this transaction we issued warrants to Domain to acquire, for a period of two years, up to five million shares of Common Stock at a price of $0.175 per share. Using the Black-Scholes method of valuation, the warrants were determined to have a fair value of $0.5 million, which cost has been included in our full cost pool with a corresponding credit to paid in capital. As of December 31, 2005, rework activities had commenced on two wells at a cost of approximately $0.2 million. Domain had advanced funds in the amount of $0.2 million to pay such costs. Domain has been provided with a security agreement covering the wells for which it will be providing funding.

Equipment, Products and Raw Materials

We own no drilling rigs, but we do own two pulling units, which may be used for work-over activities on our operated wells. In addition, we own two crew vessels which are used to transport personnel and material to our properties located in the Texas Gulf Coast, and one lift boat which is used in connection with remediation activities at our production facilities in the Texas Gulf Coast. Effective June 30, 2006, we sold our equity ownership in our marine vessels, however, we have retained a first call on the availability of the vessels in order to provide timely service to our offshore properties.

Our principal products are crude oil and natural gas. Crude oil and natural gas are sold to various purchasers including pipeline companies, which service the areas in which our producing wells are located. Our business is seasonal in nature, to the extent that weather conditions at certain times of the year may affect our access to oil and gas properties and the demand for natural gas. Principally all of our oil and gas production is sold on a month-to-month basis with no firm sales contracts.

The existence of commercial oil and gas reserves is essential to the ultimate realization of value from properties, and thus may be considered a raw material essential to our business.

The acquisition, exploration, development, production and sale of oil and gas are subject to many factors, which are outside our control. These factors include national and international economic conditions, availability of drilling rigs, casing, pipe and other fuels, and the regulation of prices, production, transportation, and marketing by federal and state governmental authorities.

We acquire oil and gas properties from landowners, other owners of interests in such properties, or governmental entities. For information on specific our properties see Item 2. We currently are not experiencing any difficulty in acquiring necessary supplies or services as long as we can pay for the services and supplies nor are we experiencing any difficulty selling our products.

Competition

The oil and gas business is highly competitive. Our competitors include major companies, independents and individual producers and operators. Many of our numerous competitors throughout the country are larger and have substantially greater financial resources than us. Oil and gas, as a source of energy, must compete with other sources of energy such as coal, nuclear power, synthetic fuels and other forms of alternate energy. Domestic oil and gas must also compete with foreign sources of oil and gas, the supply and availability of which have at times depressed domestic prices. We have an insignificant competitive position in the oil and gas industry.

Governmental and Environmental Laws

Our activities are subject to extensive federal, state and local laws and regulations controlling not only the exploration for oil and gas, but also the possible effect of such activities upon the environment. Existing as well as future legislation and regulations could cause additional expense, capital expenditures, restrictions and delays in the development of properties, the extent of which cannot be predicted. Many states have been authorized by the Environmental Protection Agency to enforce regulations promulgated under various federal statutes. In addition, there are numerous other state as well as local authorities that regulate the environment, some of which impose more stringent environmental standards than Federal laws and regulations. The penalties for violations of state laws vary but typically include injunctive relief, recovery of damages for injury to air, water or property, and fines for non-compliance. Since inception, we have not made any material expenditure for environmental control facilities and do not expect to make any material expenditure during the current and following fiscal year.

Insurance

We have a commercial general liability policy, as well as other policies covering damage to our properties. These policies cover our facilities in all states of operation. The exploration for, and production of, oil and gas can be hazardous, including unforeseen events such as blowouts, cratering of surface locations, hurricanes, fires and loss of well control. Events such as these can result in damage to wells and production facilities, injury to persons, loss of life and damage to the environment. While management believes our insurance coverage is adequate for most foreseeable problems, and is comparable with the coverage of other companies in the same business and of similar size, our coverage does not protect us against all operational risks or for most third party liabilities relating to damage of the environment. Such environmental related coverage to third parties is generally unavailable or available only at a prohibitive cost.

Employees

We employ approximately 38 people, none of whom are represented by any collective bargaining organizations. Management considers our employee relations to be satisfactory at the present time.

ITEM 2. DESCRIPTION OF PROPERTIES.

OIL AND GAS PROPERTIES. Our principal oil and gas properties during the year ended December 31, 2005, were located in Oklahoma, Texas and the Texas Gulf Coast.

Oklahoma We own working interests in oil and gas properties located in Creek, Osage and Payne Counties, Oklahoma. For the year 2006, we plan to continue development activities on the properties located in Oklahoma to return inactive wells to service. We will assess other shut-in wells on these properties throughout the year in an effort to identify additional re-work locations. During the year 2005 we earned a 75% working interest in a property comprised of 80 gross acres located in Payne County, Oklahoma.

Texas We own working interests in oil and gas properties located in Stephens and Galveston Counties, Texas and conducted work over operations on some of the Galveston County wells in an attempt to increase production from the property. Subsequent to the end of year 2005, our interests in three wells in the Stephens County property that were shut-in as of the end of the year 2005 were conveyed to a third party to serve as operator and assume future plugging and abandonment obligations.

Texas Gulf Coast We own working interests ranging from 35% to 100% in thirty-six (36) wells located in offshore Matagorda County in the Texas Gulf Coast. Effective October 1, 2005, we executed a Funding Agreement (“Agreement”) with Domain Development Partners I, LP (“Domain”), providing for the development of idle wells in our Brazos area. Under the terms of the Agreement, Domain would provide funding to pay for our portion of costs to rework as many as fifteen idle wells in an attempt to restore the wells to production. Domain’s only recourse for repayment of the funds expended is the revenue that results from such rework activities. Domain will receive 70% of our revenue interest in the wells until such time that it has received reimbursement for 150% of its expended cost, at which time Domain’s interest in our revenue will decrease to 35%. Following recovery of 200% of its expended cost, Domain will cease to have an interest in the wells. As of December 31, 2005, rework activities had commenced on two wells at a cost of approximately $0.2 million. Domain had advanced funds in the amount of $0.2 million to pay such costs. In connection with this transaction we issued warrants to Domain to acquire, for a period of two years, up to five million shares of Common Stock at a price of $0.175 per share. Domain has been provided with a security agreement covering the wells for which it has provided funding.

Other Effective September 30, 2004, we sold our working interest ownership in non-operated properties located in the states of Alabama and Louisiana. During the year 2004, we participated in the leasing of more than 7,000 gross acres and the drilling of two exploratory wells on a prospect in Fayette County, Alabama. Although both wells were determined to be non-productive, we do not consider the entire acreage block condemned at this time. We plan further evaluation of the remaining acreage under lease during the year to determine if additional drilling is warranted.

OIL AND GAS ACREAGE. We hold interests in oil and gas leaseholds as of December 31, 2005, as follows:

	Developed				Undeveloped				Expiration
	Properties				Properties				Date (1)
	Gross		Net		Gross		Net
State	Acres		Acres		Acres		Acres
Alabama		-		-		6,409		961		Nov ’06-Mar ‘07
Mississippi		200		25		-		-
Oklahoma		4,140		2,655		80		60		Mar ‘06
Texas		13,250		8,598		-		-

Total		17,590		11,278		6,489		1,021

Net acres represent the gross acres in a lease or leases multiplied by our working interest in such lease or leases.

(1) Expiration date(s) of leases for undeveloped properties. Leasehold interests for developed properties are held by production.

PROVED DEVELOPED AND PROVED UNDEVELOPED RESERVES. The following table sets forth the proved developed and proved undeveloped oil or gas reserves accumulated by us, for the years ended December 31, 2005, 2004 and 2003. The reserves are based on engineering reports prepared by our independent engineers: Ryder Scott Company in 2005; Pressler Petroleum Consultants, Inc. in 2004; and Burroughs Engineering Services and Netherland, Sewell & Associates, Inc. in 2003. All of such reserves are located in the United States of America. For the year ended December 31, 2003, we also owned producing oil and gas property located in the province of Alberta, Canada, but the operations were minimal and estimates of proved reserves were not prepared at each year-end. In 2003, we sold the Canadian interests.

	2005				2004				2003
	Oil		Gas		Oil		Gas		Oil		Gas
	(Bbls)		(MCF)		(Bbls)		(MCF)		(Bbls)		(MCF)

Proved Developed Reserves		95,715		4,865,897		307,818		1,458,287		351,194		15,507,081

Proved Undeveloped Reserves		42,750		-		78,862		1,657,984		210,021		2,107,182

Proved Reserves		138,465		4,865,897		386,680		3,116,271		561,215		17,614,263

Our proved reserves at December 31, 2005 changed significantly from the reported quantities at December 31, 2004. Our oil reserves decreased 277,000 barrels due to revisions of previous estimates by our independent engineers. Based primarily on operating performance during the year 2005, the estimates of remaining proved oil reserves for our SUDS West property in Creek County, Oklahoma, and our Caplen Field in Galveston County, Texas were revised downward by 221,500 and 105,500 barrels of oil, respectively. The estimate of remaining proved oil reserves for our Bandwheel property in Osage County, Oklahoma was increased by 46,400 barrels of oil. Revisions of estimates of remaining proved gas reserves accounted for an increase of 2.5 mmcf of gas, all of which was attributable to our Brazos property located in offshore Matagorda County, Texas. Based on current year production and the initial results of the rework program which began in the fourth quarter of year 2005, including extensive geological study and log analysis, the independent engineers determined that the estimate of remaining proved gas reserves had increased from the end of the prior year.

We had a significant decline in reserves in 2004 attributable to our producing properties located in onshore and offshore Texas. Downward revisions to the Caplen Field located in Galveston County, Texas totaled 151,427 barrels of oil and 240,085 mcf of gas. Production in the year 2004 was significantly curtailed due to field operational problems. Wells, which were shut-in for an extended period during the year 2004, and remained shut-in at year-end, were reclassified to proved developed non-producing status. Proved developed gas reserves decreased from 317,506 mcf to 33,336 mcf. Approximately 55% of the decrease was due to the elimination of one well as it was determined during the year 2004 that the reservoir was depleted. Proved undeveloped oil reserves decreased from 210,021 barrels to 78,862 barrels due to the elimination of one location and per well reductions based on the incumbent engineer’s evaluation of the locations. Proved reserves attributed to the Brazos Field located in offshore Matagorda County, Texas were revised downward in the amounts of 50,877 barrels of oil and 7,351,615 mcf of gas. Work-over activities were conducted on five wells during the year in an attempt to either increase production rates or restore wells to service. Such activities were successful on only one well. As a result the incumbent engineer significantly reduced the previously reported proved reserves until such time that it can be demonstrated that the wells are capable of producing at economical levels. The changes reflect the engineers’ subjective evaluation of the properties based on a number of factors including data that was available when the evaluation was prepared, actual production during the current year and price changes. Properties sold by us during the year 2004 resulted in additional decreases of 190,400 barrels of oil and 6,262,000 mcf of gas. Properties acquired during the year 2004 resulted in an increase to proved reserves of 240,200 barrels of oil and 83,000 mcf of gas, while year 2004 production resulted in a decrease of proved reserves of 22,100 barrels of oil and 727,000 mcf of gas.

Proved reserves are estimates of oil and gas to be produced in the future. There are numerous uncertainties inherent in the process of preparing such estimates, including future rates of production, timing and cost of development expenditures and the actual results realized as a result of such expenditures. The estimates presented in this Report are based on several assumptions including constant oil and gas prices, operating expenses and capital expenditures. Actual future production, cash flow and ultimate recoverable quantities of oil and gas may vary significantly from the estimated quantities, as variances from the assumptions could result in significant differences in quantities and value.

No major discovery or other favorable or adverse event has occurred since December 31, 2005, which is believed to have caused a material change in our proved reserves.

RESERVES REPORTED TO OTHER AGENCIES. There have been no reserve estimates filed with any other United States federal authority or agency.

NET OIL AND GAS PRODUCTION. The following table sets forth the net quantities of oil (including condensate and natural gas liquids) and gas produced during the years ended December 31, 2005, 2004 and 2003:

	2005		2004		2003
Oil (Bbls):
United States		12,620		22,087		38,613
Canada		-		-		-
Gas (Mcf):
United States		293,199		727,336		408,747
Canada		--		-		7,584

The following table sets forth the average sales price and production cost per units of production for the years ended December 31, 2005, 2004 and 2003:

	2005		2004		2003
Average Sales Price:
United States:
Bbl	$	54.59	$	37.13	$	21.69
Mcf	$	6.67	$	5.54	$	4.92
Canada-Mcf	$	-		-	$	1.78

Average Production (Lifting)
Costs: Per Equivalent
Barrel of Oil:
United States	$	30.49	$	17.87	$	14.25
Canada	$	-		-	$	7.01

During the periods covered by the foregoing tables, we were not a party to any long-term supply or similar agreements with foreign governments or authorities in which we acted as a producer.

PRODUCTIVE WELLS (1). The following table sets forth our total gross and net productive oil and gas wells as of December 31, 2005:

	OIL				GAS
State	Gross(2)		Net(3)		Gross(2)		Net(3)
Oklahoma		91		60.7		--		--
Texas		2		1.2		6		3.2
Total		93		61.9		6		3.2

(1) Productive wells are producing wells and wells capable of production including wells that are shut in.

(2) A gross well is a well in which a working interest is owned. The number of wells is the total number of wells in which a working interest is owned.

(3) A net well is deemed to exist when the sum of fractional ownership working interests owned in gross wells equals one. The number of net wells is the sum of the fractional ownership working interests owned in gross wells expressed in whole numbers and fractions thereof.

UNDEVELOPED PROPERTIES. During the year ended December 31, 2005, we acquired a 75% working interest in 80 gross (60 net) acres of undeveloped property in Payne County, Oklahoma.

During the year ended December 31, 2004, we acquired a 15% working interest in approximately 7,049 gross (1,057 net) acres of undeveloped property in Fayette County, Alabama. Two dry holes were drilled on the property, resulting in the condemnation of 640 gross acres. The remaining acreage (6,409 gross) is under evaluation by us to determine if additional drilling is warranted. Leases on the property expire at various times during the period November 2006 to March 2007. We did not conduct any drilling activities on the property during year 2005.

Our oil and gas properties are in the form of mineral leases. As is customary in the oil and gas industry, a preliminary investigation of title is made at the time of acquisition of undeveloped properties. Title investigations are generally completed, however, before commencement of drilling operations.

We believe that our methods of investigating are consistent with practices customary in the industry and that it has generally satisfactory title to the leases covering our proved reserves.

DRILLING ACTIVITY. The following table sets forth certain information for the years ended December 31, 2005 and 2004, pertaining to our participation in the drilling of exploratory and development wells:

	2005		2004
	Gross(1)		Net(2)		Gross(1)		Net(2)
Exploratory
Oil		--		--		--		--
Gas		--		--		1		0.9
Dry(3)		1		0.3		3		1.2
Development
Oil		--		--		--		--
Gas		--		--		--		--
Dry(3)		--		--		--		--
Total
Oil		--		--		--		--
Gas		--		--		1		0.9
Dry(3)		1		0.3		3		1.2

(1) A gross well is a well in which a working interest is owned. The number of wells is the total number of wells in which a working interest is owned.

(2) A net well is deemed to exist when the sum of fractional ownership working interests owned in gross wells equals one. The number of net wells is the sum of the fractional ownership working interests owned in gross wells expressed in whole numbers and fractions thereof.

(3) A dry hole is an exploratory or development well that is not a producing well.

All of our drilling activities were conducted in the United States of America.

We did not conduct any drilling activities during the year ended December 31, 2003.

DELIVERY COMMITMENTS. We are not obligated to provide a fixed and determinable quantity of oil and gas in the future pursuant to existing contracts or agreements.

OFFICE FACILITIES. We lease space for our executive offices at 5555 San Felipe, Suite 725, Houston, TX, and lease additional office space at locations in Tustin, CA and Tulsa, OK. Total leased space is approximately 6,300 square feet at the rate of $7,300 per month.

ITEM 3. LEGAL PROCEEDINGS.

We are a party to certain litigation that has arisen in the normal course of our business and that of our subsidiaries. A company engaged by us to provide well service in connection with work-over operations on some of our offshore wells has filed a claim for unpaid invoices in the amount of approximately $0.2 million. We have recorded less than $50,000 of such costs in our accounts, and have claims against the service company for damages and costs to our wells in an estimated amount in excess of $1.0 million. We expect to show that our damages far exceed the claim amount asserted by the service company. No trial date has yet been set for this matter.

In a matter styled Harvest Oil & Gas, LLC v Capco Energy, Inc. filed in United States District Court, Eastern District of Louisiana on August 16, 2005, the claimant seeks collection of a $0.6 million finders fee on a transaction where title to oil and gas properties was initially taken by Capco, but then immediately transferred to the Hoactzin Agreement. The Company previously submitted an offer to settle in the amount of $0.2 million, but that offer was rejected. A trial date of January 22, 2007, has been set to hear the matter. The Company has not recorded any loss provision for this matter as it believes the complaint to be without merit, but in the event that the plaintiff is successful in obtaining a favorable result against the Company, Capco plans to seek reimbursement from the Hoactzin Agreement.

On March 2, 2006, Nabors Offshore Corporation (“Nabors”) filed a complaint in United States District Court, southern district of Texas, against Capco and a subsidiary, seeking recovery of $0.9 million for unpaid drilling rig service invoices for a well drilled by the Company during the year 2005. Capco disputes this claim and in turn has informed Nabors of a counterclaim of $3.7 million for recovery of excess cost resulting from the actions of Nabors and reimbursement for fuel cost that was charged to Capco. No trial date has yet been set for this matter.

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.

During the fourth quarter of the fiscal year covered by this Annual Report, no matter was submitted to a vote of our security holders through the solicitation of proxies or otherwise.

PART II

ITEM 5. MARKET FOR COMMON EQUITY AND RELATED STOCKHOLDER MATTERS.

PRICE RANGE OF COMMON STOCK

Our Common Stock has been traded on the Bulletin Board since June 2000. The following table sets forth the high and low bid prices of the Common Stock in the over-the-counter market for the periods. The bid prices represent prices between dealers, and do not include retail markups, markdowns or commissions, and may not represent actual transactions. Public trading in our Common Stock is minimal.

Quarter Ended	Bid High		Bid Low
March 31, 2004	$	0.37	$	0.11
June 30, 2004	$	0.26	$	0.14
September 30, 2004	$	0.21	$	0.14
December 31, 2004	$	0.23	$	0.12
March 31, 2005	$	0.59	$	0.19
June 30, 2005	$	0.68	$	0.19
September 30, 2005	$	0.19	$	0.10
December 31, 2005	$	0.27	$	0.11

The number of record holders of our Common Stock as of June 30, 2006, is approximately 581. Additional holders of our Common Stock hold such stock in street name with various brokerage firms.

Holders of Common Stock are entitled to receive dividends as may be declared by the Board of Directors out of funds legally available. We have not declared Common Stock dividends to date, nor do we anticipate declaring and paying Common Stock cash dividends in the foreseeable future.

The following table presents information regarding our equity compensation plans at December 31, 2005:

Plan category	Number of securities to be issued upon exercise of outstanding options		Weighted-average exercise price of outstanding options		Number of securities remaining available for future issuance under equity compensation plans

Equity compensation
plans approved by
security holders		5,660,000	$	0.14		5,948,077

Equity compensation
plans not approved
by security holders		13,000,000	$	0.15		--
Total		18,660,000	$	0.14		5,948,077

ITEM 6. MANAGEMENT'S DISCUSSION AND ANALYSIS OR PLAN OF OPERATION.

This report contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934 that include, among others, statements concerning: the benefits expected to result from our divestiture of petroleum marketing operations, including decreased expenses and expenditures that are expected to be realized by us as a result of the divestiture, and other statements of: expectations, anticipations, beliefs, estimations, projections, and other similar matters that are not historical facts, including such matters as: future capital requirements, development and exploration expenditures (including the amount and nature thereof), drilling of wells, reserve estimates (including estimates of future net revenues associated with such reserves and the present value of such future net revenues), future production of oil and gas, repayment of debt, business strategies, and expansion and growth of business operations. These statements are based on certain assumptions and analyses made by our management in light of past experience and perception of: historical trends, current conditions, expected future developments, and other factors that our management believes are appropriate under the circumstances. We caution the reader that these forward-looking statements are subject to risks and uncertainties, including those associated with the financial environment, the regulatory environment, and trend projections, that could cause actual events or results to differ materially from those expressed or implied by the statements. Such risks and uncertainties include those risks and uncertainties identified below.

Significant factors that could prevent us from achieving our stated goals include: declines in the market prices for oil and gas, adverse changes in the regulatory environment affecting us, the inherent risks involved in the evaluation of properties targeted for acquisition, our dependence on key personnel, the availability of capital resources at terms acceptable to us, the uncertainty of estimates of proved reserves and future net cash flows, the risk and related cost of replacing produced reserves, the high risk in exploratory drilling and competition. You should consider the cautionary statements contained or referred to in this report in connection with any subsequent written or oral forward-looking statements that may be issued. We undertake no obligation to release publicly any revisions to any forward-looking statements to reflect events or circumstances after the date hereof or to reflect the occurrence of unanticipated events.

LIQUIDITY AND CAPITAL RESOURCES

At December 31, 2005, we had a working capital deficit of $2.6 million, due, in large part, to costs incurred with the drilling of the OCS GA 297 exploratory well. Subsequent to December 31, 2005, we engaged in several transactions that directly affected this deficit.

We borrowed $1.4 million under a funding from Hoactzin Partners that was added to the Aggregate Investment Account, and an additional $0.3 million under a placement of a convertible promissory note. We used the proceeds from these fundings primarily to retire indebtedness in the amount of $0.4 million and to pay certain accrued expenses, including accrued interest related to the indebtedness, in the total amount of $0.5 million. The balance of the proceeds from the borrowings was used to pay trade accounts payable and for funding the acquisition of the Vermillion leases as discussed below.

On June 2, 2006, we agreed to purchase oil and gas properties located in Federal waters in the Gulf of Mexico for a contract price of $83.0 million. An acquisition deposit in the amount of $8.3 million was funded by Hoactzin Partners, which increased the Aggregate Investment Amount. Closing of the acquisition is scheduled for August 31, 2006. We anticipate that the remaining contract price of $74.7 million due at closing will be satisfied by production revenue credits for the period from the effective date to the closing date, commercial bank financing, participation in ownership of the acquired interests by third party industry partners and cash advances by the Company’s major shareholders.

On June 15, 2006, we sold our equity investment in Capco Marine LLC and ownership interest in Midway Sunset LLC to one of our shareholders for $1.5 million. The purchaser paid $0.3 million cash and assumed liabilities of $0.2 million. In addition, the purchaser’s promissory note of the remaining $1.0 million is due on September 30, 2006, with an option to extend to November 30, 2006.

On June 30, 2006, we received $1.3 million from a warrant holder who tendered 13,333,333 warrants in exchange for 9.0 million shares of fully paid Common Stock.

Net cash provided by operating activities totaled $1.4 million for 2005, compared to cash provided by operating activities of $3.1 million for 2004. In 2005, net loss, adjusted for reconciling items, resulted in a cash outflow of $1.7 million. Changes in assets and liabilities in 2005 resulted in a net cash source of $3.1 million. In 2004, net income, adjusted for reconciling items, resulted in a cash source of $1.7 million. Changes in assets and liabilities resulted in an additional cash source of $1.4 million.

Net cash used in investing activities totaled $6.2 million and $3.7 million for 2005 and 2004, respectively. Investments in the Hoactzin management agreement and Midway Sunset LLC in the amount of $1.4 million, fundings of bond collateral deposits in the amount of $0.7 million, capital expenditures for oil and gas property in the amount of $5.5 million, purchase of property and equipment in the amount of $0.5 million, purchase of marketable securities in the amount of $0.4 million, and an expenditure of $0.3 million for the re-financing of the liabilities attributable to assets under contract for sale were the principal cash outflows in 2005. Proceeds in the amount of $0.5 million from the sale of oil and gas property, proceeds in the amount of $0.8 million from sales of interests in the Hoactzin management agreement, proceeds in the amount of $0.4 million from the sale of marketable securities, and proceeds in the amount of $1.0 million from the collection of notes receivable were the principal sources of cash inflow in 2005. A deposit in the amount of $0.4 million on a property acquisition, advances to related parties in the amount of $0.5 million, capital expenditures for oil and gas property in the amount of $2.9 million, purchases of other property and equipment in the amount of $0.7 million and the issuance of notes receivable in the amount of $1.0 million were the principal cash outflows in 2004. Proceeds in the amount of $1.7 million from the sale of oil and gas properties were the principal source of cash inflow in 2004.

Net cash provided by financing activities totaled $3.8 million and $2.4 million for 2005 and 2004, respectively. In 2005, proceeds from borrowings provided cash inflows of $0.7 million, and increases in long-term liabilities provided additional cash inflow of $0.2 million. The sale of Common Stock provided cash inflow of $4.3 million in 2005. Payments on notes payable and long-term debt resulted in a cash outflow of $1.2 million in 2005. An additional $0.2 million was expended in 2005 for the re-purchase of Common Stock. Proceeds from borrowings and an increase in long-term liabilities provided cash inflows of $3.4 million and $0.4 million, respectively, in 2004. Payments on long-term debt resulted in a cash outflow of $1.4 million in 2004.

Our long-term debt decreased from $1.1 million at December 31, 2004, to $0.7 million at December 31, 2005. We received proceeds of $0.4 million to pay for asset and treasury stock purchases, and to fund service company costs, and we paid $0.8 million during 2005 to retire long-term debt. The balance of convertible promissory notes increased from $1.6 million to $2.1 million, as additional notes in the amount of $0.5 million were issued during the year. The balance of short-term notes payable decreased from $0.8 million at December 31, 2004, to $17,000 at December 31, 2005, as a result of payments made during the year.

We have various loans which will require principal payments of $0.6 million in 2006. Of this amount, $0.4 million is owed to one party. We paid this obligation in full in June 2006 with funds received from the Hoactzin management agreement. The remainder of the principal payments are anticipated to be made from cash flow available from our operations of producing property, and from proceeds from the sale of assets and equity and/or debt funding.

To the extent such cash flow is insufficient to make the debt payments and provide adequate working capital for our business, we may be required to reduce or curtail certain operations or seek other sources of capital. We have historically secured financing for our acquisition and development activities on a project-financing basis. Such financing has included the sale of portions of target acquisitions or drilling ventures to third parties, participation with co-venturers on financing arranged by the other party, private borrowings from individuals and private placements of our Common Stock. Other than financing arrangements already consummated in the first six months of 2006, we do not have any agreements or arrangements providing for such financing and it may not be available on terms acceptable to us.

In addition to debt service requirements, we have several other obligations that affect our available cash flow. We are obligated to pay operating lease costs of approximately $0.1 million in 2006 for land and facilities and have an obligation to a surety company to make monthly cash collateral deposits of $24,000 over a period of thirteen months, ending February 2007. Various purchase agreements require that funding obligations of $1.1 million and $0.3 million be paid from the net profits, if any, derived from the respective operations of the properties. A total of $14,000 was paid in 2005 against the $0.3 million obligation. Utilization of available cash flow to fund these requirements may affect our ability to adequately fund other planned activities.

We disposed of our equity ownership in certain business interests (“Enterprises”) during the year 2003, but remained as guarantor of certain indebtedness incurred by Enterprises prior to the date of sale by us. As of December 31, 2005, we were the guarantor of $1.3 million of obligations for trade accounts, real estate and equipment purchases and leases owed by Enterprises. The obligations are being serviced by Enterprises, and we believe that there is sufficient underlying collateral value in the related assets to significantly reduce the exposure of loss to us. Subsequent to December 31, 2005, Enterprises effected significant reductions to the outstanding indebtedness, such that as of April 30, 2006, the amount subject to our guarantee was $0.2 million.

We were also the guarantor of indebtedness issued to one lender by Graves, a former subsidiary of Enterprises, in the amount of $3.9 million at December 31, 2004. Our Chief Executive Officer owns Graves. In October 2005, a restructuring of the indebtedness provided for our removal as a guarantor of the indebtedness, although we are a party to an indemnification agreement that survived the settlement. Pursuant to the terms of the indemnification agreement, our liability for the items covered by the indemnification is limited to $0.3 million. For our part in the restructuring we agreed to fund a total of $0.3 million to be applied to the outstanding indebtedness. Of this amount, $0.2 million was paid in December 2005, and $0.1 million was paid in January 2006. We also granted 1.8 million warrants to Hoactzin as consideration for its participation in the refinancing of the indebtedness. Using the Black Scholes pricing model, the warrants were determined to have a fair value of $0.3 million, which has been charged to operations, with a corresponding increase to paid in capital. The warrants are exercisable for a period of five years with an exercise price of $0.195 per share.

We are responsible for any contamination of land we own or lease. However, there may be limitations on any potential contamination liabilities as well as claims for reimbursement from third parties.

We sell most of our oil production to certain major oil companies. However, in the event these purchasers discontinued oil purchases, we have made contact with other purchasers who would purchase the oil at terms standard in the industry.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

We have no material exposure to interest rate changes.

RESULTS OF OPERATIONS

YEAR ENDED DECEMBER 31, 2005, COMPARED TO YEAR ENDED DECEMBER 31, 2004

Our revenues from oil and gas sales were $2.6 million in 2005 compared to $4.8 million in 2004. This decrease is due to a decrease in production volumes offset by an increase in product prices paid at the wellhead. On a barrel of oil equivalent ("BOE") basis, our price per BOE increased to $43.03 in 2005 from $33.67 in 2004, resulting in an increase in revenue of $1.3 million. Total production was 61,500 BOE in 2005, compared with 143,300 BOE in 2004, resulting in a decrease in revenue of $3.5 million. This decrease was due principally to the disposition of certain producing properties during the year 2004. Such properties provided BOE of 91,700 and revenue of $3.0 million in 2004. These decreases were partially offset by our remaining producing properties, which reported an increase in production and revenue of 9,800 BOE and $0.8 million, respectively. Our revenue from gas gathering, marketing, and processing, and oil field services increased to $0.9 million in 2005 from $0.4 million in 2004 due to increased utilization of our marine vessels at the Brazos property and our on-land service rigs.

In 2004, we recorded gains of $0.6 million and $0.4 million from the sale of land and oil and gas properties, respectively. We did not have any such gains in 2005.

Our oil and gas production lifting costs, including expensed workovers, decreased to $1.5 million in 2005 from $1.6 million in 2004. Although production volumes decreased 57% from 143,300 BOE in 2004 to 61,500 BOE in 2005, our lifting costs registered only a minimal decrease, as the properties sold in 2004 were primarily gas properties with lower associated operating costs. The oil properties in Oklahoma, which we acquired in late 2004, and operated throughout the year 2005, incurred higher per unit operating costs due to the level of expenditures necessary to keep the wells in production. Production taxes decreased to $0.2 million in 2005 from $0.5 million in 2004 and gas gathering, marketing and processing decreased to $0.2 million in 2005 from $0.8 million in 2004, all due principally to the decrease in production volumes from 143,300 BOE in 2004 to 61,500 BOE in 2005. Our oil field services expenses increased from $0.2 million in 2004 to $0.8 million in 2005 due to increased utilization of our marine vessels at the Brazos property and our on-land service rigs.

Net operating revenues from our oil and gas production are very sensitive to changes in the price of oil making it very difficult for management to predict whether or not we will be profitable in the future.

General and administrative expenses were $2.1 million in 2005 and $1.3 million in 2004. The change is due to an increase in employment levels in our Houston, Texas office necessitated by the properties operated by us in the Texas Gulf Coast.

Depreciation, depletion and accretion were $1.3 million in 2005 and $0.8 million in 2004. This change is attributable to cost additions to our full cost pool during the year 2005 for which there were no associated proved reserves, resulting in an increase in the per unit cost depletion rate.

Interest income increased to $69,000 in 2005 from $19,000 in 2004 due principally to earnings on cash collateral deposits with our surety company.

Interest expense was $0.4 million in both 2005 and 2004. Although interest-bearing indebtedness declined from $3.5 million at the beginning of the year to $2.8 million at the end of the year, most of the change occurred in the second half of the year such that interest expense remained virtually unchanged throughout the entire year.

Losses from sale of marketable securities, including unrealized holding losses, decreased from a loss of $0.1 million in 2004 to a loss of $9,000 in 2005. The loss in 2004 was due principally to market value declines, while the loss in 2005 was the result of losses sustained in positions that were taken with available cash on a short-term basis. Other expenses increased to $0.3 million due to net profit distributions.

EFFECT OF CHANGES IN PRICES

Changes in prices during the past few years have been a significant factor in the oil and gas industry. The price received for the oil produced by us fluctuated significantly during the last year. Changes in the price that we receive for our oil and gas is set by market forces beyond our control as well as governmental intervention. The volatility and uncertainty in oil and gas prices have made it more difficult for a company like us to increase our oil and gas asset base and become a significant participant in the oil and gas industry. We sell most of our oil and gas production to certain major oil companies. However, in the event these purchasers discontinued oil and gas purchases, we has made contact with other purchasers who would purchase the oil and gas at terms standard in the industry.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

Management's Discussion and Analysis of Financial Condition and Results of Operations discusses our consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States of America. The preparation of these financial statements requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. On an on-going basis, management evaluates our estimates and judgments, including those related to revenue recognition, recovery of oil and gas reserves, financing operations, and contingencies and litigation.

Oil and Gas Properties

We follow the "full-cost” method of accounting for oil and gas property and equipment costs. Under this method, all productive and nonproductive costs incurred in the acquisition, exploration, and development of oil and gas reserves are capitalized. Such costs include lease acquisitions, geological and geophysical services, drilling, completion, equipment, and certain general and administrative costs directly associated with acquisition, exploration, and development activities. General and administrative costs related to production and general overhead are expensed as incurred. No gains or losses are recognized upon the sale or disposition of oil and gas properties, except in transactions that involve a significant amount of reserves.

Proceeds from the sale of oil and gas properties are generally treated as a reduction of oil and gas property costs. Fees from associated oil and gas exploration and development partnerships, if any, will be credited to oil and gas property costs to the extent they do not represent reimbursement of general and administrative expenses currently charged to expense.

In accordance with the full cost method of accounting, future development, site restoration and dismantlement and abandonment costs, net of salvage values, are estimated on a property-by-property basis based on current economic conditions and are amortized to expense as our capitalized oil and gas property costs are amortized.

The provision for depreciation and depletion of oil and gas properties is computed on the unit-of-production method. Under this method, we compute the provision by multiplying the total unamortized costs of oil and gas properties including future development, site restoration, and dismantlement abandonment costs, but excluding costs of unproved properties by an overall rate determined by dividing the physical units of oil and gas produced during the period by the total estimated units of proved oil and gas reserves. This calculation is done on a country-by-country basis. As of December 31, 2005, all of our oil production operations are conducted in the United States of America. The cost of unevaluated properties not being amortized, to the extent there is such a cost, is assessed quarterly to determine whether the value has been impaired below the capitalized cost. The cost of any impaired property is transferred to the balance of oil and gas properties being depleted. The costs associated with unevaluated properties relate to projects which were undergoing exploration or development activities or in which we intend to commence such activities in the future. We will begin to amortize these costs when proved reserves are established or impairment is determined. Management believes no such impairment exists at December 31, 2005.

In accordance with SFAS No. 143, “Accounting for Asset Retirement Obligations,” we report a liability for any legal retirement obligations on our oil and gas properties. The associated costs are capitalized as part of the full cost pool. Following is a reconciliation of the asset retirement obligation liability for the year ended December 31, 2005 (in thousands):

Asset retirement obligation at January 1, 2005	$	2,193
Liabilities incurred		1,759
Liabilities settled		(45	)
Accretion expense		87
Revisions in estimated liabilities		-
Asset retirement obligation at December 31, 2005	$	3,994

At the end of each reporting period, the unamortized cost of oil and gas properties, net of related deferred income taxes, is limited to the sum of the estimated future net revenues from proved properties using current prices, discounted at 10%, and the lower of cost or fair value of unproved properties, adjusted for related income tax effects ("Ceiling Limitation").

The calculations of the ceiling limitation and provision for depreciation, depletion, and amortization are based on estimates of proved reserves. There are numerous uncertainties inherent in estimating quantities of proven reserves and in projecting the future rates of production, timing, and plan of development. The accuracy of any reserves estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Results of drilling, testing, and production subsequent to the date of the estimate may justify revision of such estimate. Accordingly, reserve estimates are often different from the quantities of oil and gas that are ultimately recovered.

Revenue Recognition

We recognize revenue upon transfer of ownership of the product to the customer which occurs when (i) the product is physically received by the customer, (ii) we issue an invoice to the customer which evidences an arrangement between the customer and us, (iii) a fixed sales price has been included in such invoice, and (iv) collection from such customer is probable.

ITEM 7. FINANCIAL STATEMENTS.

Included at Pages F-1 through F-34 hereof.

ITEM 8. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND

FINANCIAL DISCLOSURE.

Dismissal of Independent Registered Public Accounting Firm

On October 7, 2005, Stonefield Josephson, Inc. was terminated as our independent accountants. Stonefield Josephson, Inc.’s report on our financial statements for the year ended December 31, 2004, contained no adverse opinion or disclaimer of opinion nor was it qualified as to audit scope or accounting principles. Stonefield Josephson Inc.’s report on our financial statements for the year ended December 31, 2003, included an explanatory paragraph expressing substantial doubt about our ability to continue as a going concern.

Our Audit Committee made the decision to terminate our prior accountants to utilize the services of a firm local to our primary business activities.

In connection with the prior audits for the years ended December 31, 2004 and 2003, and during the interim period from January 1, 2005, to October 7, 2005, there have been no disagreements with Stonefield Josephson, Inc. on any matter of accounting principles or practices, financial statement disclosure or auditing scope or procedure.

Engagement of New Independent Registered Public Accounting Firm

On October 10, 2005, we engaged Malone & Bailey, PC as our independent accountants. We did not consult with Malone & Bailey, PC with regard to any matter concerning the application of accounting principles to any specific transactions, either completed or proposed, or the type of audit opinion that might be rendered with respect to our financial statements.

ITEM 8A. CONTROLS AND PROCEDURES.

(a) Evaluation of disclosure controls and procedures

Our Chief Executive Officer and Chief Financial Officer, after evaluating the effectiveness of our “disclosure controls and procedures” (as defined in Sections 13a-14(c) of the Securities Exchange Act of 1934) as of the end of the period reported in this annual report (the “Evaluation Date”), concluded that our disclosure controls and procedures were not effective and designed to ensure that material information relating to us and our consolidated subsidiaries is accumulated and would be made know to them by others within those entities as appropriate to allow timely decisions regarding required disclosures. The Company’s conclusion that it’s disclosure controls and procedures were not effective is primarily due to the Company not having filed it’s quarterly and annual reports on a timely basis since the first quarter of 2005. Additionally, as part of the Company’s annual audit of the 2005 financial statements, Malone & Bailey, PC identified adjustments relating to the Company’s accounting for the issuance of warrants. These adjustments have been recorded in the Company’s Annual Report on Form 10-KSB as of December 31, 2005.

Our Chief Executive Officer and Chief Financial Officer, in consort with the Company’s Audit Committee, have taken steps to remedy these deficiencies. The accounting and financial reporting functions for the Company have been centralized in the Company’s Houston, Texas office. In October 2005, the Company retained the services of an independent accounting firm based in Houston, Texas to provide audit services. As a result of these changes, we believe that the deficiencies described will be fully resolved by the end of calendar year 2006.

(b) Changes in internal controls

There were no changes during the fiscal quarter ended December 31, 2005, that materially affected, or are reasonably likely to materially affect our internal control over financial reporting, except for those changes discussed in Item 8A (a) above.

We do not believe that there are significant deficiencies in the design or operation of our internal controls that could adversely affect our ability to record, process, summarize and report financial data. Although there were no significant changes in our internal controls or in other factors that could significantly affect those controls subsequent to the Evaluation Date, our senior management, in conjunction with our Board of Directors, continuously reviews overall Company policies and improves documentation of important financial reporting and internal control matters. We are committed to continuously improving the state of our internal controls, corporate governance and financial reporting.

Our management, including the Chief Executive Officer and the Chief Financial Officer, does not expect that our disclosure or internal controls will prevent all errors or fraud. A control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Further, the design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. Because of the inherent limitations in a cost-effective control system, misstatements due to error or fraud may occur and not be detected.

PART III

ITEM 9. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT.

The following table sets forth the name and age of each Director, indicating all positions and offices presently held with us, and their respective terms of service as a Director:

NAME:	POSITIONS:	PERIOD SERVED:
Ilyas Chaudhary	Director, President	November 18, 1999 to Present

Irwin Kaufman	Director	November 18, 1999 to Present

William J. Hickey	Director, Secretary	November 18, 1999 to Present

Paul L. Hayes	Director	July 19, 2000 to Present

Below are the names of all Directors and the principal occupations and employment of such persons during at least the last three years:

ILYAS CHAUDHARY - Mr. Chaudhary, 58, has been CFO, President and Director of the Company since November 1999. He also served as CFO during the period May 2003 to June 2005. He was an officer and a director of Saba Petroleum Company, an oil and gas company from 1985 until 1998. Mr. Chaudhary has 27 years of experience in various capacities in the oil and gas industry, including eight years of employment with Schlumberger Well Services from 1972 to 1979. Mr. Chaudhary received a Bachelor of Science degree in Electrical Engineering from the University of Alberta, Canada.

IRWIN KAUFMAN - Mr. Kaufman, 69, has been a director of the Company since November 1999. Mr. Kaufman spent more than 30 years in the public sector. He culminated his career as the executive in charge of computer operations for the New York City public schools. With a budget of more than $50 million, Mr. Kaufman implemented a plan to upgrade system wide computer operations. He has been a consultant with the Soros Foundation for several programs in the Baltic States, Ukraine and Russia. Mr. Kaufman served on the board of directors of Meteor Industries, Inc. and is presently a financial and educational consultant.

WILLIAM J. HICKEY - Mr. Hickey, 69, has been a director since November 1999, and Secretary since December 2001. Prior to joining the Company, he was a director, secretary, and legal advisor to Saba Petroleum. Earlier, he was a Vice President, and General Counsel to Litton Industries Inc. and Consolidated Freightways, Inc. In addition, he has been a Division Legal Counsel with General Electric Company. Mr. Hickey received his Doctorate in Law from Cornell University and attended the Harvard Business School’s Executive Management Program.

PAUL L. HAYES - Mr. Hayes, 69, has been a director since July 2000. He has over twenty years experience in the securities industry. He has been an investment banker, analyst and research director. His undergraduate degree is a B.S. in Petroleum Engineering from Oklahoma University and his graduate degree is an M.B.A from Harvard University.

Our Board of Directors held three meetings during the year ended December 31, 2005. Each Director participated in at least 75% of the aggregate number of meetings held by the Board of Directors and its Committees during the time each such Director was a member of the Board or of any Committee of the Board. The only standing committee of the Board is the Audit Committee consisting entirely of non-employee directors.

The Audit Committee met once during the fiscal year ended December 31, 2005. The Audit Committee is primarily responsible for the effectiveness of our accounting policies and practices, financial reporting and internal controls.

We do not have a nominating or compensation committee. Primarily because of the small size of our Board, the Board has determined not to establish another standing committee. Nominees for Director will be selected or recommended by our Directors who meet the Nasdaq/AMEX independence standards.

Section 16(a) Beneficial Ownership Reporting Compliance

Section 16(a) of the Securities Exchange Act of 1934 ("Section 16") requires that officers, directors and persons who own more than ten percent of our voting securities file reports of their ownership and changes in such ownership with the Securities and Exchange Commission (the "Commission"). Commission regulations also require that such persons provide us with copies of all Section 16 reports they file. Based on information provided to us, Messrs. Ilyas Chaudhary, Hickey and Kaufman each failed to timely file a Form 4.

Code of Business Conduct and Ethics

We have a Code of Business Conduct and Ethics, which is applicable to all of our employees, including executive officers and directors. The Code of Business Conduct and Ethics is included in the 2003 Annual Report on Form 10-KSB as Exhibit 14.

ITEM 10: EXECUTIVE COMPENSATION

Executive Officers

Our compensation program for executive officers is based on the following principles:

Compensation should be reflective of overall Company financial performance and an individual's contribution to the Company's success. Compensation packages should be based on competitive practices designed to attract and retain highly qualified executive officers. Long-term incentive compensation should be construed to closely follow increases in stockholder return. There is currently one employment contract with the president of the Company, terms of which are set forth in here below.

Cash bonuses and stock options are provided on a discretionary basis but the amounts of options issued are generally tied to the performance and prospects of the Company. Individual executive officers and managers can earn a portion of their cash and option bonuses based on financial performance of the Company compared to budget and additional bonuses are paid at the discretion of the Incentive Plan committee and approved by the Board of Directors.

Summary of Cash and Certain Other Compensation

The following table sets forth the compensation arrangement for the Chief Executive Officer for each of the last three fiscal years. No other officer of the Company was compensated in excess of $100,000 during the fiscal year ended December 31, 2005.


Executive	Year	Salary	Bonus	Executive equities (1)	Other benefits

Ilyas Chaudhary
CEO	2005	$327,000	$108,000	-	Medical/Vehicle
Ilyas Chaudhary
CEO	2004	$187,000	$ -	-	Medical/Vehicle/Home
					Office
Ilyas Chaudhary
CEO	2003	$198,000	$ -	4,000,000	Medical/Vehicle/Home
					Office

(1) Represents issuance of options to acquire 4,000,000 shares of Common Stock at an exercise price of $0.06 per share.

Option/SAR Grants During Current Fiscal Year:

We granted no options to the Chief Executive Officer during the year ended December 31, 2005.

Aggregate Option/SAR Exercises and Fiscal Year-End Option/SAR Value Table:

The following table sets forth information regarding (i) the exercise of stock options by the Company's Chief Executive Officer during the year 2005, and (ii) the value of unexercised options for such officer as of December 31, 2005:

No. of

Number of

Value of

underlying

unexercised

in-the-money

acquired

Value

options at

Name

on exercise

Realized

12/31/05 (1)

12/31/05 (1) (2)

Ilyas Chaudhary

4,000,000

670,000

(1) All unexercised options were exercisable at December 31, 2005.

(2) The value of unexercised in-the-money options is based on the difference between the exercise price of the options and $0.23, the closing price of our Common Stock at December 31, 2005.

Director Compensation

Each member of our Board of Directors, who is also not our employee ("outside Director"), receives $500 for each Board of Directors' meeting attended either in person or by telephone. We reimburse Directors for expenses incurred in attending board meetings. In addition, each outside Director receives an annual stock option award to purchase 200,000 shares of our Common Stock. The exercise price of the options is not less than the Common Stock’s market price at the time of the grant. The Options are considered fully vested and are exercisable for a period of five years from the date of grant.

ITEM 11. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS.

The following table sets forth the number and percentage of shares of the our $.001 par value Common Stock owned beneficially, as of June 30, 2006, by any person, who is known to us to be the beneficial owner of 5% or more of such Common Stock, and, in addition, by each of our Directors, and by all of our Directors and Executive Officers as a group. Information as to beneficial ownership is based upon statements furnished to us by such persons, or in the absence of such reports, from our records.

Name and address of beneficial owner	Shares of Common Stock owned		Shares of Common Stock underlying options		Total		Percentage of class

Bushra Chaudhary (1)
10441 Villa del Cerro
Santa Ana, CA 92805		11,660,316		--		11,660,316		10.0	%

Ilyas Chaudhary (2)
10441 Villa del Cerro
Santa Ana, CA 92805		19,968,290		4,000,000		23,968,290		20.0	%

Danyal Chaudhary
Foundation (3)
10441 Villa del Cerro
Santa Ana, CA 92805		21,480,000		-		21,480,000		18.5	%

William J. Hickey
505 Saturmino Drive
Palm Springs, CA 92262		-		1,000,000		1,000,000		0.8	%

Paul L. Hayes Jr.
209 Middle Ridge Road
Stratton Mountain, VT 05155		-		200,000		200,000		0.1	%

Irwin Kaufman
8224 Paseo Vista Drive
Las Vegas, NV 89128		280,000		1,000,000		1,280,000		1.1	%

Dolphin Offshore
Partners LP
129 East 17th Street
New York, NY 10003		-		38,827,055		38,827,055		25.1	%

J. Michael Myers
1319 Bradford Drive
Coppell, TX 75019		3,950,000		8,000,000		11,950,000		9.6	%

Peninsula Capital
Management, Inc.,
Peninsula Fund, L.P.,
Scott Bedford
235 Pine Street, Suite
1818, San Francisco,
CA 94104 (4)		-		6,650,000		6,650,000		5.4	%

JVL Advisors, L.L.C.,
John V. Lovoi
10,000 Memorial Drive,
Suite 550, Houston,
TX 77024 (4)		-		10,571,333		10,571,333		8.3	%

All Executive Officers
And Directors as a Group
(5 persons)		20,248,290		6,675,000		26,923,290		21.9	%

(1) Represents 11,660,316 restricted Common Shares held by Bushra Chaudhary, the wife of our CEO and Chairman, who claims no beneficial ownership of these shares.

(2) Consists of 8,760,400 controlled Common Shares held directly by Mr. Chaudhary, and 8,799,140 and 2,408,750 restricted Common Shares held by Sedco, Inc., and Capco Acquisub, Inc., respectively, private companies of which Mr. Chaudhary is Chairman of the Board, Chief Executive Officer and beneficially owns 100% of each company's outstanding stock.

(3) Represents 21,480,000 restricted Common Shares held by the Danyal Chaudhary Foundation, a California non-profit organization in which the trustees are Bushra Chaudhary, Faisal Chaudhary, Arshad M. Faroog and Ilyas Chaudhary, who claims no beneficial ownership of these shares.

(4) Represents beneficial ownership claimed by each listed party as reported by Form SC 13G filing.

ITEM 12. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.

None of our Directors or officers or security holder who is known to us to own of record, or beneficially, more than 5% of any class of our voting securities, or any relative or spouse of any of the foregoing persons, or any relative of such spouse, who has the same home as such person or who is a Director or officer of any parent or subsidiary of Capco Energy, Inc., has had any transaction or series of transactions exceeding $60,000 during the past two fiscal years, or has any presently proposed transactions to which we were or are a party, in which any of such persons had or is to have direct or indirect material interest, other than the following:

TRANSACTIONS INVOLVING THE COMPANY'S OFFICERS AND DIRECTORS

Year Ended December 31, 2005

We had several transactions with our Chief Executive Officer, Ilyas Chaudhary, and Sedco, Inc. and Meteor Enterprises, Inc., private companies controlled by Mr. Chaudhary ("affiliates"). We received cash advances in the total amount of $263,000 from affiliates. We paid expenses in the amount of $28,000 in behalf of affiliates, and were charged a total of $8,000 for expenditures made by affiliates in our behalf. We accrued compensation expense in the amount of $435,000 due to affiliates in accordance with the Chief Executive Officer's employment. Included in the amount is the $108,000 that was reported as prepaid compensation at the end of the year 2004. We made cash advances in the total amount of $521,000 to affiliates that included payment of accrued compensation, repayment of cash advances received during the year and settlement of expenditures made by the respective parties during the year in behalf of each other. At December 31, 2005, the amount of $49,000 was due to affiliates.

In October 2005, a private company owned by our Chief Executive Officer achieved a restructuring of indebtedness that provided for the removal of our debt guarantee, although we are a party to an indemnification agreement that survived the settlement. Pursuant to the terms of the indemnification agreement, our liability for the items covered by the indemnification is limited to $0.3 million. For our part in the restructuring we agreed to fund a total of $0.3 million to be applied to the outstanding indebtedness. Of this amount, $0.2 million was paid in December 2005, and $0.1 million was paid in January 2006. We also granted 1.8 million warrants to Hoactzin as consideration for its participation in the refinancing of the indebtedness. Using the Black Scholes pricing model, the warrants were determined to have a fair value of $0.3 million. This cost has been charged to our operations, with a corresponding increase to paid in capital. The warrants are exercisable for a period of five years with an exercise price of $0.195 per share.

Effective April 1, 2005, we divested our 80% equity interest in Bison Energy Company (“Bison”) that was acquired from one of our Directors during the year 2004, by selling the interest to the Director for our original investment. Funding provided to Bison by us in 2004 in the amount of $50,000 that had previously been accounted for as an advance to Bison was reclassified as a payment against long-term debt owed to the Director. We incurred interest expense in the amount of $7,000 on the indebtedness in 2005.

Year Ended December 31, 2004

We had several transactions with our Chief Executive Officer, Ilyas Chaudhary, and Sedco, Inc. and Meteor Enterprises, Inc., private companies controlled by Mr. Chaudhary ("affiliates"). We received cash advances in the total amount of $350,000 from affiliates. We paid expenses in the amount of $93,000 in behalf of affiliates, and were charged a total of $67,000 for expenditures made by affiliates on our behalf. We accrued, and paid, compensation expense in the amount of $175,000 due to affiliates in accordance with the Chief Executive Officer's employment. We made cash advances in the total amount of $766,000 to affiliates that included repayment of balances owed to affiliates at the beginning of the year, repayment of cash advances received during the year and settlement of expenditures made by the respective parties during the year in behalf of each other. Of such advances, $108,000 was considered to be advance payments of Mr. Chaudhary’s compensation for the year 2005, and has been reclassified as a prepaid expense in the accompanying financial statements as of December 31, 2004. No amount was due to, or due from, affiliates at December 31, 2004.

In October 2004, we issued 3.6 million shares of Common Stock as consideration for the acquisition cost of an oil and gas property. Approximately 70% of the acquired working interest in the property was acquired either from an entity controlled by our President or from individuals who are family members of an officer of us; however, the negotiated acquisition price was determined in a manner uniform to all members of the selling group.

Significant transactions with affiliates are initially negotiated by the management and then thoroughly discussed and carefully reviewed by the Board. Terms and conditions of all transactions always observe customary industry practices. In particular, these reviews include in-depth discussions with Ilyas Chaudhary concerning his negotiations with third parties, e.g.: the sale of the Michigan and Montana properties came about after several months of discussions and negotiations with third parties who were unable to complete the transaction separately because they could not “unbundle” from the Omimex debt constraints. Furthermore, the Board requires that “fairness opinions” be prepared by a qualified, disinterested third party to insure, that the Company receives, for all significant transaction, such as Meteor and Omimex properties the greatest consideration, having regard for all relevant attendant circumstances.

Specifically, sales of our assets to affiliates occur solely in cases where the subject property cannot, for any number of reasons, be sold to non-affiliated third parties. We, make every effort at the expense of depreciating the asset(s), to insure that there is no qualified, willing or interested independent purchaser available.

On the other hand, purchases of assets from affiliates are constantly reviewed and revisited to determine that the purchase price(s) was, and is, in every respect fair and reasonable.

SALES OF PROPERTY

Year Ended December 31, 2004

Effective September 30, 2004, we sold our interests in non-operated producing properties located in Alabama and Louisiana to a company owned by our Chief Executive Officer. Sales proceeds in the amount of $0.4 million were received by us in October 2004 and were used for working capital. We have the option to repurchase the properties for an amount equal to the sales price within the next twelve-month period. If it is determined through due diligence by us that the properties could have been sold for an amount greater than $0.4 million, then the related party has the obligation to pay such excess to us. No adjustment was made in 2005 for the transaction as originally recorded.

Effective December 31, 2004, we sold our interests in non-operated producing properties located in Michigan and Montana and other assets to our Chief Executive Officer for the amount of $4.7 million. The sales amount was settled by the payment of a cash deposit in the amount of $0.7 million, assumption of debt against the properties in the amount of $3.3 million and issuance of a note payable to us in the amount of $0.7 million. The note was paid in full in March 2005.

PART IV

ITEM 13. EXHIBITS

(a) Documents filed as part of this Report:

(1) The following Financial Statements are filed as part of this Report:

	Page

Report of Independent Registered Public
Accounting Firm, June 23, 2006	F-1

Report of Independent Registered Public
Accounting Firm, April 1, 2005 (July 19, 2006,
as to the effects of the reclassification as
disclosed in Note 1)	F-2

Consolidated Balance Sheet, December 31, 2005	F-3 - F-4

Consolidated Statements of Operations for the
years ended December 31, 2005 and 2004	F-5

Consolidated Statements of Stockholders'
Equity for the years ended December 31, 2005 and 2004	F-6 - F-7

Consolidated Statements of Cash Flows for the years
ended December 31, 2005 and 2004	F-8 - F-10

Notes to Consolidated Financial Statements	F-11 - F-31

Supplemental Information About Oil and Gas Producing
Activities (unaudited)	F-31 - F-34

(2) Exhibits

Exhibit Number	Description	Location
2	Not applicable

3.1	Articles of Incorporation and Bylaws	(incorporated by reference toExhibits 4 and 5, respectively, to Registration Statement No. 2-73529)

3.2	Articles of Amendment	(incorporated by reference to our Form 10-K filed May 31, 1984)

3.3	Articles of Amendment	(incorporated by reference to our Form 10-K filed May 31, 1985)

3.4	Articles of Amendment	(incorporated by reference to our Form 10-QSB filed January 19, 2000)

Exhibit Number	Description	Location
4.	Instruments Defining the Rights of Security Holders, Including Indentures	(incorporated by reference to Exhibits 4 and 5, respectively, to Registration Statement No. 2-73529)

10.1	1999 Incentive Equity Plan	(incorporated by reference to the Company's definitive proxy statement filed December 2, 1999)

10.2	Stock Exchange Agreement between Capco Energy, Inc. and Sedco related to Capco Resource Corporation	(incorporated by reference to the Company's Form 10-KSB for the year ended December 31, 1999, filed November 2, 2000

10.3	Stock Purchase Agreement, dated January 30, 2001, and between Capco Energy, Inc. and Meteor Industries, Inc.	(incorporated by reference to Form 8-K of Meteor Industries, Inc. dated February 13, 2001, SEC File No. 0-27698)

10.4	First Amendment to Stock Purchase Agreement dated April 27, 2001, by and between Capco Energy, Inc. and Meteor Industries, Inc.	(incorporated by reference to the Company's Form 8-K filed May 7, 2001)

10.5	Agreement by and among New Mexico Marketing, Inc., Meteor Marketing, Inc., Graves Oil & Butane Co., and the Sole Shareholder of Graves Oil & Butane Co., Inc.	(incorporated by reference to the Company's Form 10-KSB for the year ended December 31, 2002, filed April 23, 2003)

10.6	Stock Purchase Agreement dated April 30, 2003, by and between Capco Energy, Inc. and Sedco, Inc.	(incorporated by reference to the Company's Form 8-K filed May 16, 2003)

10.7	Amendment to Purchase Agreement by and between Sedco, Inc. and Capco Energy, Inc., September 30, 2003	(incorporated by reference to the Company's Form 10-QSB for the quarterly period ended September 30, 2003, filed December 10, 2003)

10.8	Purchase Agreement by and between Sedco Energy, Inc. and Capco Energy, Inc., December 31, 2003	(incorporated by reference to the Company’s Form 10-KSB for the year ended December 31, 2003, filed April 15, 2004)

10.9	Purchase Agreement by and between Sedco Energy, Inc. and Capco Energy, Inc., December 31, 2003	(incorporated by reference to the Company’s Form 10-KSB for the year ended December 31, 2003, filed April 15, 2004)

Exhibit Number	Description	Location
10.10	Letter agreement dated July 25, 2003, by and between Omimex Canada, Ltd., Jovian Energy, Inc., and Capco Resource Corporation	(incorporated by reference to the Company’s Form 10-KSB for the year ended December 31, 2003, filed April 15, 2004)

10.11	Letter agreement dated September 29, 2004, by and between Packard Gas Company and Midwest EOR, Inc.	(incorporated by reference to the Company’s Form 10-KSB for the year ended December 31, 2004, filed May 11, 2005)

10.12	Agreement dated November 23, 2004, by and among Capco Energy, Inc. and Ilyas Chaudhary	(incorporated by reference to the Company’s Form 10-KSB for the year ended December 31, 2004, filed May 11, 2005)

10.13	Letter of Intent dated November 24, 2004, between Packard Gas Company and Midwest EOR, Inc.	(incorporated by reference to the Company’s Form 10-KSB for the year ended December 31, 2004, filed May 11, 2005)

10.14	Securities Purchase Agreement dated March 10, 2005, by and among Capco Energy, Inc. and certain accredited investors	(incorporated by reference to the Company’s Form 8-K filed March 16, 2005)

10.15	Asset Purchase Agreement dated March 15, 2005, by and among Manti Resources, Inc., et al and Capco Offshore, Inc.	(incorporated by reference to the Company’s Form 10-KSB for the year ended December 31, 2004, filed May 11, 2005)

10.16	Purchase and Sale Agreement dated May 4, 2005, by and among Capco Offshore, Inc and Hoactzin Partners, L.P	Filed herewith electronically

10.17	Funding Agreement dated September 15, 2006, by and among Capco Operating Corporation and Domain Development Partners I, LP.	Filed herewith electronically

10.18	Purchase and Sale agreement dated October 1, 2005, by and among Tag Operating Company, Inc., Inland Gas Corporation and Packard Gas Company	Filed herewith electronically

Exhibit Number	Description	Location
10.19	Indemnification Agreement dated October 21, 2005, by and among Graves et al and Capco Energy, Inc.	Filed herewith electronically

10.20	Post-Default Settlement Agreement dated October 21, 2005, by and among Graves et al and Capco Energy, Inc.	Filed herewith electronically

14.	Code of Business Conduct and Ethics	(incorporated by reference to the Company’s Form 10-KSB for the year ended December 31, 2003, filed April 15, 2004)

21.	List of Subsidiaries	Filed herewith electronically

23.2	Consent of Stonefield Josephson, Inc.	Filed herewith electronically

31.1	Certification pursuant to	Filed herewith electronically

31.2	Section 302 of Sarbanes

31.3	Oxley Act of 2002, signed by Ilyas Chaudhary

31.2	Certification pursuant to Section 302 of Sarbanes- Oxley Act of 2002, signed by Mansoor Anjum	Filed herewith electronically

32.1	Certification pursuant to Section 1350 of Sarbanes- Oxley Act of 2002, signed by Ilyas Chaudhary	Filed herewith electronically

32.2	Certification pursuant to Section 1350 of Sarbanes- Oxley Act of 2002, signed By Mansoor Anjum	Filed herewith electronically

ITEM 14. Principal Accountant Fees and Services

Audit Fees.

The aggregate fees billed, or expected to be billed, for each of the last two fiscal years by Malone & Bailey, PC and Stonefield Josephson, Inc. for their audits of the Company’s annual financial statements and review of interim financial statements, including the Company’s Form 10-QSB reports, are $150,850 and $103,310 in the years 2005 and 2004, respectively.

Audit-Related Fees.

The Company was not billed for such services in either 2005 or 2004.

Tax Fees.

The Company was not billed for such services in either 2005 or 2004.

All Other Fees.

The Company was billed $2,970 by Stonefield Josephson, Inc. in the year 2005 for the review of a Form S-8 and the Company’s annual proxy statement; there were no such billings in the year 2004.

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, we have duly caused this Report to be signed on our behalf by the undersigned thereunto duly authorized.


	CAPCO ENERGY, INC.

Dated: August 9, 2006	By:	/s/ Ilyas Chaudhary
		Ilyas Chaudhary, CEO

Pursuant to the requirements of the Securities Exchange Act of 1934, this Report has been signed below by the following persons on behalf of the Company and in the capacities and on the date indicated.


Dated: August 9, 2006	By:	/s/ Ilyas Chaudhary
		Ilyas Chaudhary, CEO, President, and Director



Dated: August 9, 2006	By:	/s/ Irwin Kaufman
		Irwin Kaufman, Director



Dated: August 9, 2006	By:	/s/ William J. Hickey
		William J. Hickey, Director



Dated: August 9, 2006	By:	/s/ Paul L. Hayes
		Paul L. Hayes, Director

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders

Capco Energy, Inc. and Subsidiaries

Houston, Texas

We have audited the accompanying consolidated balance sheet of Capco Energy, Inc. and Subsidiaries, as of December 31, 2005, and the related consolidated statements of operations, stockholders' equity, and cash flows for the year ended December 31, 2005. These consolidated financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the consolidated financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Capco Energy, Inc. and Subsidiaries as of December 31, 2005, and the results of its operations and its cash flows for the year ended December 31, 2005, in conformity with accounting principles generally accepted in the United States of America.

/s/ Malone & Bailey, PC

Malone & Bailey, PC

www.malone-bailey.com

Houston, Texas

June 23, 2006

F-1

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders

Capco Energy, Inc. and Subsidiaries

We have audited the consolidated statements of operations, comprehensive income (loss), stockholders' equity, and cash flows for the year ended December 31, 2004. These consolidated financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the consolidated financial statements based on our audits.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the results of its operations and its cash flows for the year ended December 31, 2004, in conformity with accounting principles generally accepted in the United States of America.

/s/ Stonefield Josephson, Inc.

CERTIFIED PUBLIC ACCOUNTANTS

Irvine, California

April 1, 2005 (July 19, 2006, as to the effects of the reclassification as disclosed in Note 1)

F-2

CAPCO ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEET

DECEMBER 31, 2005

ASSETS

(Dollars in Thousands)

Current Assets:
Cash	$	762
Accounts receivable-trade, net of
allowance of $45		671
Prepaid and other current assets		244

Total Current Assets		1,677


Oil and gas properties, using full cost accounting,
less accumulated depreciation and depletion of $2,902		14,623

Other Assets:
Other property and equipment, less accumulated
depreciation of $147		1,097
Cost of financing under management agreement		10,092
Bond deposits		3,004
Other assets		388


Total Assets	$	30,881

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

F-3

CAPCO ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEET (continued)

DECEMBER 31, 2005

LIABILITIES AND STOCKHOLDERS' EQUITY

(Dollars in Thousands)

Current Liabilities:
Accounts payable, trade	$	2,470
Accounts payable, related party		84
Current maturities of convertible debt		25
Current maturities of long-term debt		556
Current maturities of long-term debt, related party		77
Accrued expenses		1,117
Total Current Liabilities		4,329
Non-current Liabilities:
Accounts payable, related parties		49
Long term debt, less current maturities		98
Convertible promissory notes, net		2,046
Other long-term liabilities		1,417
Asset retirement obligation		3,994
Total Non-current Liabilities		7,604

Total Liabilities		11,933

Commitments and Contingencies (Note 9)		-

Stockholders' Equity:
Common stock, $0.001 par value;
authorized 500,000,000 shares;
118,548,477 shares issued		119
Additional paid in capital		20,584
Treasury stock, 2,467,708 shares, at cost		(344	)
Retained deficit		(1,411	)
Total Stockholders' Equity		18,948
Total Liabilities and
Stockholders' Equity	$	30,881

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

F-4

CAPCO ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

For the Years ended December 31, 2005 and 2004

(Dollars in Thousands except per share)

	2005			2004
Operating revenues
Oil and gas sales	$	2,646		$	4,825
Gas gathering marketing and processing		-			275
Oil field services		926			155
Gains on sales of land and oil and gas property		-			974
Total operating revenues		3,572			6,229
Operating costs and expenses
Oil and gas production lifting costs		1,530			1,569
Production taxes		178			478
Gas gathering, marketing and processing costs		166			768
Oil field services		818			172
Net profits distributions		396			-
Depreciation, depletion and accretion		1,339			809
General and administrative		2,128			1,266
Total operating costs and expenses		6,555			5,062

Operating (loss) profit		(2,983	)		1,167

Other Income (Expenses):
Interest income		69			19
Interest expense		(408	)		(399	)
Losses on sales of investments-
marketable securities		(9	)		(63	)
Holding losses-marketable securities		-			(2	)
Other		(282	)		3
(Loss) income before taxes		(3,613	)		725

Provision for income taxes		-			-
Net (loss) income	$	(3,613	)	$	725

Earnings per share-basic:	$	(0.03	)	$	0.01
Earnings per share-diluted:	$	(0.03	)	$	0.01
Weighted average common share and common
share equivalents:
Basic		112,845,317			96,067,502
Diluted		122,640,846			105,741,590

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

F-5

CAPCO ENERGY, INC. AND SUBSIDIARIES

Consolidated Statements of Stockholders' Equity

For the Years Ended December 31, 2005 and 2004

(Dollars in Thousands)

										Accumulated
					Additional					(Deficit)/
	Common Stock				Paid-In		Treasury			Retained
	Shares		Amount		Capital		Stock			Earnings		Total

Balances at December 31, 2003		95,983,716	$	96	$	2,429	$	(127	)	$	1,477	$	3,875

Treasury stock (acquisitions)		-		-		-		(11	)		-		(11	)

Shares sold for cash		1,095,000		1		70		-			-		71

Shares issued in settlement of liability		300,000		-		30		-			-		30

Shares issued for acquisition of property		3,644,760		4		433		-			-		437

Discount on convertible notes		-		-		112		-			-		112

Net income		-		-		-		-			725		725

Balances at December 31, 2004		101,023,476	$	101	$	3,074	$	(138	)	$	2,202	$	5,239

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

F-6

CAPCO ENERGY, INC. AND SUBSIDIARIES

Consolidated Statements of Stockholders' Equity

For the Years Ended December 31, 2005 and 2004

(Dollars in Thousands)

										Accumulated
					Additional					(Deficit)/
	Common Stock				Paid-In		Treasury			Retained
	Shares		Amount		Capital		Stock			Earnings			Total

Balances at December 31 2004		101,023,476	$	101	$	3,074	$	(138	)	$	2,202		$	5,239
		-		-		-		(206	)		-			(206	)
Treasury stock (acquisitions)

Shares sold for cash		15,225,000		15		4,370		-			-			4,385

Shares issued in settlement of liabilities		2,000,001		2		373		-			-			375

Shares issued for conversion of promissory notes		300,000		1		59		-			-			60

Fair value of warrants issued		-		-		12,708		-			-			12,708

Net loss		-		-		-		-			(3,613	)		(3,613	)

Balances at December 31, 2005		118,548,477	$	119	$	20,584	$	(344	)	$	(1,411	)	$	18,948

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

F-7

CAPCO ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

For the Years Ended December 31, 2005 and 2004

(Dollars in Thousands)

	2005			2004
Cash Flows From Operating Activities:
Net (loss) income	$	(3,613	)	$	725
Adjustments to reconcile net (loss) income
to net cash used in operating activities:
Depreciation, depletion, accretion
and amortization		1,424			809
Share-based compensation		158			--
Foreign currency translation adjustment		--			57
Loss on sales of investments - marketable
securities		9			63
Loss on settlement of guarantor obligation		305			--
Loss on debt conversions		15			--
Holding losses - marketable securities		--			2
Increase in deferred tax asset		--			(1,298	)
Increase in deferred tax liability		--			1,298
Changes in assets and liabilities:
Accounts receivable - trade		(189	)		(225	)
Notes receivable (accrued interest)		--			2
Other current assets		(81	)		(113	)
Other assets		12			(5	)
Accounts payable		2,974			937
Accrued expenses		344			812
Net cash provided by operating activities		1,358			3,064

Cash Flows From Investing Activities:
Acquisition of subsidiary, net of cash		--			4
Cost of financing under management agreement		(1,117	)		--
Funding of bond collateral		(713	)		(8	)
Deposit on property acquisition		--			(400	)
Net repayments (advances) with related parties		49			(511	)
Proceeds from sales of oil and gas property		500			1,736
Proceeds from sales of interests in investment
in Hoactzin management agreement		770			--
Purchase of other assets		(312	)		(50	)
Capital expenditures for oil and gas property		(5,545	)		(2,872	)
Purchase of property and equipment		(525	)		(652	)
Proceeds from sale of marketable securities		390			128
Purchase of marketable securities		(398	)		--
Increase in assets attributable to businesses
under contract for sale		(283	)		(50	)
Collection (issuance) of notes receivable		981			(981	)
Net cash used in investing activities		(6,203	)		(3,656	)

Continued on Next Page

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

F-8

CAPCO ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

For the Years Ended December 31, 2005 and 2004

(Dollars in Thousands)

(continued)

	2005			2004
Cash Flows From Financing Activities:
Proceeds from issuance of debt		204			1,752
Proceeds from production payable		150			--
Proceeds from convertible promissory
notes, net		460			1,628
Increase in long-term liabilities		--			361
Payments on notes payable		(345	)		--
Payments on long term debt		(846	)		(1,438	)
Sale of Common Stock and exercise of options		4,385			71
Purchase of Common Stock		(206	)		(12	)
Net cash provided by financing activities		3,802			2,362

Net (decrease) increase in cash		(1,043	)		1,770
Cash, beginning of period		1,805			35
Cash, end of period	$	762		$	1,805

Supplemental disclosure of cash flow information:

Interest paid	$	233		$	333
Taxes paid	$	--		$	--
Supplemental disclosure of non-cash financing and investing activities:

Common Stock issued for conversions of promissory notes	$	60		$	--

Common Stock issued in settlement of liabilities	$	375		$	30
Note payable settled in connection with transfer
of oil and gas property interest	$	400		$	--
Cost of warrants issued in connection with
management agreement	$	11,745		$	--
Reversal of liability for businesses under contract
for sale	$	4,346		$	--

F-9

CAPCO ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

For the Years Ended December 31, 2005 and 2004

(Dollars in Thousands)

(continued)


Increase in liability for asset retirement
obligation	$	1,758	$	1,088
Reduction in oil and gas property additions
as originally invoiced due to settlement of
accounts payable for reduced amounts	$	657	$	--
Paid in capital provided as equity component of
debt financing	$	--	$	112
Acquisition cost of oil and gas property
settled with issuance of Common Stock	$	--	$	437
Accrual for acquisition cost of oil and gas
property to be settled with issuance of
Common Stock	$	--	$	200
Long-term debt and liabilities reduced
for property sold	$	--	$	3,297
Long-term liability (released) assumed in
connection with guaranty of indebtedness	$	--	$	(432	)

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

F-10

CAPCO ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2005

1. ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

NATURE OF OPERATIONS

Capco Energy, Inc. ("Capco" or "the Company") is an independent energy company engaged primarily in the acquisition, development, production of and the sale of oil, gas and natural gas liquids. The Company's production activities are located in the United States of America. The principal executive offices of the Company are located at 5555 San Felipe, Suite 725, Houston, TX 77056. The Company was incorporated as Alfa Resources, Inc., a Colorado corporation, on January 6, 1981. In November 1999, the Company amended its articles of incorporation to change its name from Alfa Resources, Inc. to Capco Energy, Inc.

BASIS OF CONSOLIDATION

The consolidated financial statements include the accounts of Capco and it's wholly and majority owned subsidiaries. Accordingly, all references herein to Capco or the Company include the consolidated results. All significant inter-company accounts and transactions have been eliminated in consolidation. The Company's significant subsidiaries in 2005 include Capco Operating Corporation, Capco Offshore, Inc., and Packard Gas Company, and in 2004 included Capco Offshore, Inc. and Packard Gas Company.

Effective April 1, 2005, the Company divested its 80% equity interest in Bison Energy Company (“Bison”) that was acquired from a Director of the Company during the year 2004, by selling the interest to the Director for the Company’s original investment. Bison is the owner of an oil property in the state of Wyoming. Operations from the property resulted in cumulative losses in the amount of $29,000 since the date of acquisition. Capco recorded a gain in the amount of $29,000 in 2005 as a result of the disposition. Funding provided to Bison by Capco in 2004 in the amount of $50,000 that had previously been accounted for as an advance to Bison was reclassified as a payment against long-term debt owed to the Director.

RISK FACTORS RELATED TO CONCENTRATION OF SALES AND PRODUCTS

The Company's future financial condition and results of operations will depend upon prices received for its oil and natural gas and the costs of finding, acquiring, developing and producing reserves. Prices for oil and natural gas are subject to fluctuations in response to changes in supply, market uncertainty and a variety of other factors beyond the Company's control. These factors include worldwide political instability (especially in the Middle East), the foreign supply of oil and natural gas, the price of foreign imports, the level of consumer product demand and the price and availability of alternative fuels.

USE OF ESTIMATES

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Management used significant estimates in determining the carrying value of its oil and gas producing assets and the associated depreciation and depletion expense related to sales' volumes. The significant estimates included the use of proved oil and gas reserve volumes and the related present value of estimated future net revenues there-from (See Supplemental Information About Oil and Gas Producing Activities).

F-11

CASH AND CASH EQUIVALENTS

Cash and cash equivalents consist of short-term, highly liquid investments readily convertible into cash with an original maturity of three months or less. The Company maintains its cash in bank deposit accounts that, at times, may exceed federally insured limits. The Company has not experienced any losses in such accounts. The Company had $0.5 million cash balances in excess of federal insured limits as of December 31, 2005.

FAIR VALUE OF FINANCIAL INSTRUMENTS

The Company measures its financial assets and liabilities in accordance with accounting principles generally accepted in the United States of America. For certain of the Company's financial instruments, including accounts receivable (trade and related party), notes receivable and accounts payable (trade and related party), and accrued expenses, the carrying amounts approximate fair value due to their short maturities. The amounts owed for long-term debt also approximate fair value because interest rates and terms offered to the Company are at current market rates.

CONCENTRATION OF CREDIT RISK

Financial instruments that potentially subject the Company to concentrations of credit risk are: cash and accounts receivable arising from its normal business activities. The Company places its cash in what it believes to be credit-worthy financial institutions. However, cash balances have exceeded the FDIC insured levels at various times during the year. The Company has a diversified customer base. The Company controls credit risk related to accounts receivable through credit approvals, credit limits and monitoring procedures. The Company routinely assesses the financial strength of its customers and, based upon factors surrounding the credit risk, establishes an allowance, if required, for un-collectible accounts and, as a consequence, believes that its accounts receivable credit risk exposure beyond such allowance is limited. The Company had an allowance of $45,000 as of December 31, 2005, that was based on its evaluation of specific customers’ balances and the collectibility thereof.

INVESTMENT IN EQUITY SECURITIES

For equity securities that the Company i) does not exercise control in the investee and ii) expects to divest within a short period of time, the Company accounts for the investment under the provisions of Financial Accounting Standards Board Statement of Financial Accounting Standards No. 115, "Accounting for Certain Investments in Debt and Equity Securities". In accordance with FASB No. 115, equity securities that have readily determinable fair values are classified as either trading or available-for-sale securities. Securities that are bought and held principally for the purpose of selling in the near term (thus held for only a short period of time) are classified as trading securities and all other securities are classified as available-for-sale. Trading and available-for-sale securities are measured at fair value in the balance sheet. For trading securities any realized gains or losses and any unrealized holding gains and losses are reported in the statement of operations. For available-for-sale securities any realized gains and losses are reported in the statement of operations and any unrealized holding gains and losses are reported as a separate component of stockholders' equity until realized.

F-12

OIL AND GAS PROPERTIES

Capco follows the "full-cost" method of accounting for oil and gas property and equipment costs. Under this method, all productive and nonproductive costs incurred in the acquisition, exploration, and development of oil and gas reserves are capitalized. Such costs include lease acquisitions, geological and geophysical services, drilling, completion, equipment, and certain general and administrative costs directly associated with acquisition, exploration, and development activities. General and administrative costs related to production and general overhead are expensed as incurred. No gains or losses are recognized upon the sale or disposition of oil and gas properties, except in transactions that involve a significant amount of reserves.

In accordance with the full cost method of accounting, future development, site restoration and dismantlement and abandonment costs, net of salvage values, are estimated on a property-by-property basis based on current economic conditions and are amortized to expense as the Company's capitalized oil and gas property costs are amortized.

The provision for depreciation and depletion of oil and gas properties is computed on the unit-of-production method. Under this method, the Company computes the provision by multiplying the total unamortized costs of oil and gas properties including future development, site restoration, and dismantlement abandonment costs, but excluding costs of unproved properties by an overall rate determined by dividing the physical units of oil and gas produced during the period by the total estimated units of proved oil and gas reserves. This calculation is done on a country-by-country basis. As of December 31, 2005, all of the Company’s oil production operations are conducted in the United States of America. The cost of unevaluated properties not being amortized, to the extent there is such a cost, is assessed quarterly to determine whether the value has been impaired below the capitalized cost. The cost of any impaired property is transferred to the balance of oil and gas properties being depleted. The costs associated with unevaluated properties relate to projects which were undergoing exploration or development activities or in which the Company intends to commence such activities in the future. The Company will begin to amortize these costs when proved reserves are established or impairment is determined. Management believes no such impairment exists at December 31, 2005.

In accordance with SFAS No. 143, “Accounting for Asset Retirement Obligations”, the Company reports a liability for any legal retirement obligations on its oil and gas properties. The associated costs are capitalized as part of the full cost pool.

Following is a reconciliation of the asset retirement obligation liability for the year ended December 31, 2005 (in thousands):

Asset retirement obligation at January 1, 2005	$	2,193
Liabilities incurred		1,759
Liabilities settled		(45	)
Accretion expense		87
Asset retirement obligation at December 31, 2005	$	3,994

F-13

OTHER PROPERTY AND EQUIPMENT

Non-oil and gas producing properties and equipment are stated at cost; major renewals and improvements are charged to the property and equipment accounts; while replacements, maintenance and repairs, which do not improve or extend the lives of the respective assets, are expensed currently. At the time property and equipment are retired or otherwise disposed of, the asset and related accumulated depreciation accounts are relieved of the applicable amounts. Gains or losses from retirements or sales are credited or charged to operations.

Depreciation for non-oil and gas properties is recorded on the straight-line method at rates based on estimated useful lives ranging from three to fifteen years of the assets.

IMPAIRMENT OF LONG-LIVED ASSETS

In October 2001, the FASB issued SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets.” This statement supersedes SFAS No. 121, “Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed of.” Although retaining many of the fundamental recognition and measurement provisions of SFAS No. 121, the new rules significantly change the criteria that would have to be met to classify an asset as held-for-sale. The statement also supersedes certain provisions of Accounting Principles Board Opinion No. 30, “Reporting the Results of Operations—Reporting the Effects of Disposal of a Segment of a Business, and Extraordinary, Unusual and Infrequently Occurring Events and Transactions,” and will require expected future operating losses from discontinued operations to be displayed in discontinued operations in the period or periods in which the losses are incurred rather than as of the measurement date, as presently required. The Company adopted this new statement on January 1, 2002, and concluded that the effect of adopting this statement had no material impact on its financial position, results of operations, or cash flows.

REVENUE RECOGNITION

The Company recognizes revenue upon transfer of ownership of the product to the customer which occurs when (i) the product is physically received by the customer, (ii) the Company issues an invoice to the customer which evidences an arrangement between the customer and the Company, (iii) a fixed sales price has been included in such invoice, and (iv) collection from such customer is probable.

STOCK BASED COMPENSATION

The Company accounts for employee stock options in accordance with APB No. 25 "Accounting for Stock Issued to Employees". Under APB 25, the Company recognizes no compensation expense related to employee stock options, as no options are granted at a price below market price on the date of grant.

F-14

In 2002, the Company adopted SFAS No.123 "Accounting for Stock-Based Compensation". SFAS No. 123, which prescribes the recognition of compensation expense based on the fair value of options on the grant date, and allows companies to continue applying APB 25 if certain pro forma disclosures are made assuming hypothetical fair value method, for which the Company uses the Black-Scholes option-pricing model. For non-employee stock based compensation the Company recognizes an expense in accordance with SFAS No. 123 and values the equity securities based on the fair value of the security on the date of grant. For stock-based awards the value is based on the market value for the stock on the date of grant and if the stock has restrictions as to transferability a discount is provided for lack of tradability. Stock option awards are valued using the Black-Scholes option-pricing model.

Had compensation cost been determined based on the fair value at grant dates for stock option awards consistent with the SFAS No. 123, the Company’s net (loss) income and earnings per share for the years ended December 31, 2005 and 2004, would have been adjusted to the pro-forma amounts indicated below (dollars in thousands, except per share):

	2005			2004
Net (loss) income as reported	$	(3,613	)	$	725
Compensation recognized under APB 25		--			--
Compensation recognized under SFAS 123		(450	)		(218	)
Pro-forma net (loss) income	$	(4,063	)	$	507
Net (loss) income per share:
Basic and diluted-as reported	$	(0.03	)	$	0.01
Basic and diluted-pro-forma	$	(0.03	)	$	0.01

The pro forma compensation expense based on the fair value of the options is estimated on the grant date using the Black-Scholes option-pricing model with the following assumptions used for grants: no dividends; expected lives ranging from 1 to 5 years for 2005 and from 3 to 5 years for 2004; expected volatility ranging from 244% to 246% for 2005 and from 85% to 217% for 2004; and risk free rates of return ranging from 3.84% to 3.90% for 2005 and from 3.29% to 3.74% for 2004. The weighted average fair value of those purchase rights granted in 2005 and 2004 was $0.20 and $0.13, respectively.

INCOME TAXES

Provisions for income taxes are based on taxes payable or refundable for the current year and deferred taxes on temporary differences between the amount of taxable income and pretax financial income and between the tax bases of assets and liabilities and their reported amounts in the financial statements.

Deferred tax assets and liabilities are included in the financial statements at currently enacted income tax rates applicable to the period in which the deferred tax assets and liabilities are expected to be realized or settled as prescribed in SFAS No. 109, “Accounting for Income Taxes". As changes in tax laws or rates are enacted, deferred tax assets and liabilities are adjusted through the provision for income taxes.

Deferred tax assets are reduced by a valuation allowance when, in the opinion of management, it is more likely than not that some portion or all of the deferred tax assets will not be recognized. The Company has recorded a 100% valuation allowance as of December 31, 2005.

EARNINGS PER SHARE

The Company uses SFAS No. 128, "Earnings Per Share" for calculating the basic and diluted earnings (loss) per share. Basic earnings (loss) per share are computed by dividing net income (loss) attributable to common stockholders by the weighted average number of common shares outstanding. Diluted earnings (loss) per share is computed similar to basic earnings (loss) per share except that the numerator is increased by the amount of interest expense attributable to the convertible promissory notes payable and the denominator is increased to include the number of additional common shares that would have been outstanding if the potential common shares had been issued and if the additional common shares were dilutive. On a diluted basis, the weighted average number of shares outstanding for the year ended December 31, 2005, have been increased for 9,795,529 shares of Common Stock determined under the “if converted” method, due to outstanding convertible promissory notes during the year. Under the treasury method of calculating additional shares outstanding, the Company’s weighted average number of shares outstanding for the year ended December 31, 2005, would have been increased for 8,098,153 shares of Common Stock if associated stock options and warrants would have had a dilutive effect. Due to the net loss reported by the Company, the effect of including shares attributable to stock options and warrants would have been antidilutive. On a diluted basis, under the treasury method of calculating the additional shares outstanding, the Company's weighted average shares outstanding for 2004, have been increased for 5,192,941 shares of Common Stock as associated stock options have a dilutive effect on net income. Additionally, the number of shares outstanding for 2004, have been increased for 4,481,148 shares of Common Stock determined under the "if converted" method, due to the issuance of convertible notes payable during 2004.

F-15

NEW ACCOUNTING PRONOUNCEMENTS

In December 2004, the FASB issued SFAS No.123 (revised 2004), “Share-Based Payment”. Statement 123(R) will provide investors and other users of financial statements with more complete and neutral financial information by requiring that the compensation cost relating to share-based payment transactions be recognized in financial statements. That cost will be measured based on the fair value of the equity or liability instruments issued. Statement 123(R) covers a wide range of share-based compensation arrangements including share options, restricted share plans, performance-based awards, share appreciation rights, and employee share purchase plans. Statement 123(R) replaces FASB Statement No. 123, Accounting for Stock-Based Compensation, and supersedes APB Opinion No. 25, Accounting for Stock Issued to Employees. Statement 123, as originally issued in 1995, established as preferable a fair-value-based method of accounting for share-based payment transactions with employees. However, that Statement permitted entities the option of continuing to apply the guidance in Opinion 25, as long as the footnotes to financial statements disclosed what net income would have been had the preferable fair-value-based method been used. Public entities (other than those filing as small business issuers) will be required to apply Statement 123(R) as of the first interim or annual reporting period that begins after December 15, 2005. The impact of the adoption of SFAS 123(R) would be similar to the Company’s calculation of the pro forma impact on results of operations included in Note 1 above.

Capco does not expect the adoption of any other recently issued accounting pronouncements to have a significant impact on its results of operations, financial positions or cash flows.

RECLASSIFICATION

Certain amounts have been reclassified in the prior year to be consistent with the classification as of December 31, 2005.

2. BUSINESS COMBINATION, ACQUISITION AND DIVESTITURES:

The Company had the following acquisitions and divestments during 2005:

Effective April 1, 2005, the Company divested its 80% equity interest in Bison Energy Company (“Bison”) that was acquired from a Director of the Company during 2004, by selling the interest to the Director for the Company’s original investment. Bison is the owner of an oil property in the state of Wyoming. Operations from the property resulted in cumulative losses of $29,000 since the date of acquisition. Capco recorded a gain of $29,000 in 2005 from the disposition. Funding provided to Bison by Capco in 2004 of $50,000 that had previously been accounted for as an advance to Bison was reclassified as a payment against long-term debt owed to the Director.

F-16

On May 4, 2005, the Company closed on a Purchase and Sale Agreement and a Management Agreement (“Agreement”) with Hoactzin Partners, L.P., (“Hoactzin”) an oil and gas investment affiliate of New York based investment firm Dolphin Asset Management Corp. The Company sold to Hoactzin its interests in High Island Block 196 which were acquired in February 2005, a portion of its interests in two producing wells and one idle well in the Brazos Field in Texas state waters, and a portion of its interest in the OCS Galveston Block 297 well on which drilling operations were in progress at that date. The sale also included working interests ranging from 14% to 100% in 11 producing wells situated on approximately 13,300 gross acres located in St. Bernard Parish, Louisiana, and Chandeleur Area, OCS Blocks 27, 29 and 30. The contract acquisition price of $20.0 million, plus a production payment of $1.0 million, was reduced to a closing cost of $12.1 million, after adjustment for net revenue credits for the period from the effective date to the closing date and for a cash deposit of $1.0 million paid by the Company. Hoactzin paid all of the funds required at closing, except for $0.1 million that was paid by the Company. The production payment is to be paid from 25% of the revenue produced by the acquired property interests once payout of the initial acquisition cost of $20.0 million has occurred.

Hoactzin had previously provided funding in the amount of $4.9 million for the acquisition of the High Island Block 196 property. Included in this amount was $2.0 million that was deposited with Capco’s surety company as collateral for bonds that were posted with the Minerals Management Service. Hoactzin had also advanced $1.5 million for the pending acquisition from the Company of working interests in three wells in the Brazos Field and the well being drilling in the OCS Galveston Block 297. The total proceeds of $6.4 million were reported by the Company as a note payable for a portion of the year 2005 until Hoactzin received owner approval from the Minerals Management Service and the Company assigned the property interests to Hoactzin.

On November 30, 2005, Hoactzin closed on the acquisition of a producing oil property located in Orange County, Texas. Hoactzin funded the total acquisition cost of $2.8 million. The acquired property consists of approximately 550 acres and includes 130 previously drilled wells, of which 20 were in current production. As operator of the property, Capco intends to begin a program to return idle wells to production.

The Agreement is governed under the terms of a Management Agreement between the parties. Hoactzin owns title to the properties and retains all cash flow from the properties until their investment, including a return of 8% on the invested funds, is repaid (“Repayment Date”), at which time the Company will receive a management fee equal to 66.7% of the net cash flow from the properties. The Company has the option to purchase the property interests from Hoactzin at any time after the one-year anniversary of the Repayment Date, and Hoactzin has the option to sell its property interests to the Company at any time after the two-year anniversary of the Repayment Date. The option prices are based on formulas specified in the Management Agreement.

In connection with the acquisition of the Chandeleur Area properties, the Company secured participation from two outside investors. Proceeds from these investors totaling $0.7 million were used by Capco to fund a portion of the $1.1 million that the Company contributed to the total acquisition cost of these properties, and were recorded as a reduction of the Company’s basis in the Agreement. For the consideration paid to Capco, the investors received a total of 5.5% of Capco’s rights and title to the Chandeleur Area properties. For an initial period of twelve months, beginning July 1, 2005, the investors are receiving distributions at the rate of $66,000 per month. At the end of that period, the investors’ accounts will be adjusted to reflect any difference between the cash distributions paid during the period and actual cash flow from the properties attributable to the 5.5% interest, with a settlement of funds either due to, or from, the investors. In addition, effective July 1, 2006, the investors will begin to receive payments equal to 5.5% of actual net cash flow from the Chandeleur Area properties.

F-17

At the closing of the Agreement with Hoactzin, the Company issued a series of common stock purchase warrants (“Warrants”) to Hoactzin. The Warrants are exercisable into a total of 24,226,181 shares of the Company’s Common Stock at initial exercise prices ranging from $0.176 to $0.30, subject to adjustments pursuant to the anti-dilution provisions set forth in the Warrants, and expire five (5) years from date of issue. The Warrants may be exercised upon payment of cash, exchanged for the Company’s Common Stock, or applied as a credit against the Aggregate Investment Amount, as that term is defined in the agreements. Using the Black-Scholes pricing model with a Common Stock price of $0.50, which was the closing price on the grant date of the Warrants, it was determined that the Warrants had a fair value of $10.8 million. This amount has been accounted for as Cost of Financing Under Management Agreement for obtaining the management fee as provided for in the Management Agreement, with a corresponding increase to the Company’s paid in capital account. The $2.0 million cash deposit with the Company’s surety company was allocated from this amount to be reported by the Company with other similar cash deposits. Cash payments in the total amount of $1.1 million contributed to the management agreement by the Company in connection with the acquisition of the Chandeleur Area properties have also been accounted for as Cost of Financing Under Management Agreement.

During the eight-month period from closing of the Agreement in May 2005 to December 31, 2005, Hoactzin expended an additional $2.9 million, principally in connection with an acquisition of a producing oil field in southeast Texas. These expenditures resulted in a grant of 5,248,196 Warrants with a calculated fair value, using the Black Scholes pricing model, of $0.9 million. This amount has been accounted for as a Cost of Financing Under Management Agreement, with a corresponding increase to the Company’s paid in capital account. The Warrants have an exercise price of $0.195, and expire five (5) years from date of issue.

The net cost of $10.1 million, including reduction for the proceeds received from the two investors discussed above, will be carried on the Company’s balance sheet at cost, to be reduced by amortization once the venture has achieved payout and management fee payments are initiated. The Company will periodically assess the carrying value of the Cost of Financing Under Management Agreement for possible impairment. In management’s opinion, no impairment existed as of December 31, 2005. In the event that the Company elects to exercise its option to acquire property interests from Hoactzin (one year following Repayment Date), the carrying value of the Cost of Financing Under Management Agreement will be considered to be a cost of the acquisition and reclassified to the oil and gas property full cost pool account.

The Company had the following acquisitions and divestments during 2004 and 2005:

ACQUISITIONS

Effective July 1, 2004, the Company purchased a 92.8% working interest in a property located in Stephens County, Texas. In addition to the acreage, the acquisition included one producing gas well drilled by the former owners, the coal bed methane well drilled by the Company during the year and seismic and geological studies. The Company issued 3.6 million shares of Common Stock as consideration for the acquisition cost of $0.4 million. The per share price of $0.16 approximated the market price of the Company’s Common Stock at that time. Approximately 70% of the acquired working interest in the property was acquired as a result of Capco’s exchange of shares for 100% equity ownership of Packard Gas Company with individuals, or entities controlled by individuals, who have either a direct, or beneficial, relationship to the Company, including Capco’s President of the Company. Subsequent to the exercise of its option, the Company drilled and completed a gas well on the property at a cost of $0.2 million. Following a period of evaluation of the two producing gas wells the decision was made to discontinue further drilling activities on the property, and as a result, the Company only earned acreage attributable to each well location actually drilled on the property.

F-18

In September 2004, the Company acquired from a Director of the Company, an 80% equity interest in Bison Energy Company (“Bison”), an entity organized for the purpose of owning, and operating, oil and gas properties in the state of Wyoming. The Director holds the 20% minority interest. Bison’s operations since date of acquisition resulted in a loss of $23,000. The entire amount of the loss has been reflected in the financial statements and no minority interest has been calculated. Until such time as operations recover the deficiency in minority interest of $4,600, Capco will report 100% of results of operations with no reduction for minority interest. In conjunction with the equity investment, the Director exercised options at a price of $0.0625 per share to acquire 800,000 shares of the Company’s Common Stock. The option proceeds of $50,000 were advanced to Bison to provide funding for the acquisition of a 33.33% working interest in an oil property in the amount of $30,000; Bison retained the balance for working capital. The property consists of 720 gross acres and includes nine wells, four of which are currently in production. Rework operations are in progress in an effort to restore the remaining wells to production.

OIL AND GAS PROPERTIES

On May 4, 2005, the Company closed on the sale of a portion of its working interest in two producing wells and one idle well in the Brazos area to Hoactzin. In addition, Hoactzin has the option to participate in work over activities in a fourth well if such activities are conducted. Sales proceeds in the amount of $0.5 million were credited against the Company’s full cost pool.

In February 2005, the Company commenced drilling operations on an exploratory well in Outer Continental Shelf (“OCS”) Galveston Block 297. Capco was the operator of the well, which was targeted for a total depth of 13,500 feet. If successful the Company would own a 27% working interest in the well, with the remaining interest owned by other oil and gas companies. Drilling activities were significantly extended past the anticipated timeline as it became necessary to sidetrack and re-drill a portion of the well due to encountering excessive gas pressures at a depth of approximately 13,350 feet. The well was drilled to its target depth and tested for the presence of hydrocarbons, but in the opinion of management and the other participants, the test results did not warrant a completion attempt, and the well was plugged and abandoned in May 2005. Capco filed a claim with its insurance company for recovery of a portion of the additional costs incurred during the drilling of the well, and received $3.2 million for its interest in November 2005. The Company’s cost of drilling the well, after reduction for insurance proceeds and turnkey payments received from some of the participants in the well, were $2.8 million and are included in the full cost pool.

The Company also incurred expenditures of $0.5 million in connection with the development of properties located in Creek County, Oklahoma, satisfying the terms of the purchase agreement to earn its entire 50% working interest in the properties. During the year 2005, the Company had increased its ownership in the properties from 45% to 50% by acquiring an additional 5% working interest from another owner of the properties.

Additionally, the Company expended in excess of $0.1 million for development of properties located in Osage County, Oklahoma, satisfying terms of the purchase agreement for that property. The Company also disbursed a total of $14,000 to the seller for the net profits obligation.

F-19

Effective October 1, 2005, the Company executed a Funding Agreement (“Agreement”) with Domain Development Partners I, LP (“Domain”), providing for the development of idle wells in the Company’s Brazos area. Under the terms of the Agreement, Domain would provide funding to pay for the Company’s portion of costs to rework as many as fifteen idle wells in an attempt to restore the wells to production. Domain’s only recourse for repayment of the funds expended is the revenue that results from such rework activities. Domain will receive 70% of Capco’s revenue interest in the wells until such time that it has received reimbursement for 150% of its expended cost, at which time Domain’s interest in Capco’s revenue will decrease to 35%. Following recovery of 200% of its expended cost, Domain will cease to have an interest in the wells. In connection with this transaction, Capco issued warrants to Domain to acquire, for a period of two years, up to five million shares of Common Stock at a price of $0.175 per share. Using the Black-Scholes method of valuation, the warrants have a fair value of $0.5 million, which cost has been included in the Company’s full cost pool with a corresponding credit to paid in capital. As of December 31, 2005, rework activities had commenced on two wells at a cost of approximately $0.2 million. Domain had advanced funds in the amount of $0.2 million to pay such costs. The Company provided Domain with a security agreement covering the wells for which it will be providing funding.

In February 2004, the Company closed on an acquisition of a production platform with nine additional well in the Brazos Field, offshore in Matagorda County, Texas. The Company owns a 90% working interest in the wells and will be operator of the property. In conjunction with the acquisition, Capco plans to acquire leases for the mineral interests at an estimated cost of $0.1 million. Such expenditure is necessary before the Company can initiate production from any of the acquired wells. Under the terms of the agreement, the seller agreed to contribute as much as $1.0 million to apply toward payment of abandonment costs when, and if, the Company incurs such costs. In accordance with FAS 141, contingent consideration that is not recognized at the acquisition date is recognized and measured when the contingency is resolved and consideration is issued or becomes issuable. As of December 31, 2005, the Company has not finalized its work program for this property, and had not expended any funds for lease acquisition.

In February 2004, the Company entered into an agreement to drill and complete a coal bed methane well in Stephens County, Texas. The well was drilled to a depth of 1,100 feet at a cost of $0.1 million, and following a period of “dewatering” and evaluation, was determined to be non-productive. By drilling the well Capco earned the right to negotiate the purchase of a leasehold interest in approximately 4,000 acres, along with wells previously drilled on the property.

In July 2004, the Company participated with a 15% working interest in the acquisition of leases covering approximately 7,000 gross acres in a drilling prospect located in Fayette County, Alabama. Two wells were drilled on the property and both were determined to be incapable of commercial production. The Company plans to further evaluate the undeveloped acreage to determine if additional drilling is warranted. Capco incurred expenditures for lease acquisition and drilling costs in the total amount of $0.2 million for it 15% participation.

Effective September 30, 2004, the Company sold its interests in non-operated producing properties located in Alabama and Louisiana to a company owned by the Company’s Chief Executive Officer. Sales proceeds in the amount of $0.4 million were received by the Company in October 2004 and were used for working capital. The sales proceeds were credited against the Company’s basis in oil and gas properties. No gain or loss was recognized from the sale as the disposition represented only 3% of the Company’s proved reserves at the time of sale. If it is determined through due diligence by the Company that the properties could have been sold for an amount greater than $0.4 million, then the related party has the obligation to pay such excess to the Company, or the Company, at its option, may repurchase the properties at the original sales price. There were no changes in 2005 to the transaction as originally closed in 2004.

F-20

In October 2004, the Company acquired a 45% working interest in two properties located in Creek County, Oklahoma. The properties consisted of approximately 100 oil wells, the majority of which were not in production at the time of acquisition by the Company. Under the terms of the purchase agreement the Company is obligated to spend $0.6 million over a specified period of time in an effort to bring injection and production wells back in to service to earn the entire 45% interest. As of December 31, 2004, the Company had incurred $48,000 of such costs. During the year 2005, Capco increased its working interest ownership from 45% to 50% by acquiring an additional 5% working interest from another owner of the properties. The Company also incurred property development expenditures of $0.5 million, satisfying the terms of the purchase agreement to earn its entire 50% working interest in the properties.

In December 2004, the Company acquired a 100% working interest in an oil property consisting of approximately 80 wells located in Osage County, Oklahoma. The acquisition cost of $0.2 million is to be settled by the issuance of 1.0 million shares of the Company’s Common Stock. The per share price of $0.20 approximated the market price of Capco’s Common Stock at the time the agreement was negotiated with the seller. The Common Stock was issued to the seller in March 2005. The seller of the property retained a net profits interest in the amount of $0.3 million that is to be paid from one-third of the net production from the property until paid in full. The net profit distributions will be included with the cost of the property as Capco pays them. In addition, the purchase agreement stipulates that the Company expend a minimum of $0.1 million of property development costs within one year from the date of acquisition. Capco expended in excess of $0.1 million of such costs during the year 2005.

Effective December 31, 2004, the Company sold its interests in non-operated producing properties located in Michigan and Montana and other assets to the Company’s Chief Executive Officer for the amount of $4.7 million. The Company received a fairness opinion for the sale in January 2005. The sales amount was settled by the payment of a cash deposit in the amount of $0.7 million, assumption of debt against the properties in the amount $3.3 million and the issuance of a note payable to the Company in the amount of $0.7 million. The note was paid in full in March 2005. The disposition resulted in a significant change to the depletion rate in Company’s full cost pool cost center, which required that gain or loss recognition be given to the sale. The Company recorded a gain in the amount of $0.4 million from the sale.

LAND

In December 2004, the Company sold 160 acres of undeveloped land located in Alberta, Canada. The Company had owned the land since 1999 with a cost basis of $0.2 million. Consideration for the sale consisted of $0.1 million cash received in December 2004, assumption by the buyer of related indebtedness in the amount of $0.4 million and $0.3 million cash received in March 2005. The Company realized a gain of $0.6 million from the sale. The buyer paid the note receivable in full in March 2005.

3. INVESTMENTS IN EQUITY SECURITIES-MARKETABLE SECURITIES

During 2005, the Company invested on a short-term basis temporarily available cash in marketable securities. As of December 31, 2005, the Company had disposed of all such investments, realizing total losses in the amount of $9,000.

During 2004, the Company disposed of its portfolio of marketable securities in common stock, realizing total losses in the amount of $65,000.

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4. OIL AND GAS PROPERTIES

Oil and gas properties consisted of the following as of December 31, 2005 (in thousands):

Properties being amortized	$	17,357
Properties not subject to amortization		168
Accumulated depreciation and depletion		(2,902	)
Oil and gas properties, net	$	14,623

At December 31, 2005, certain of these assets collateralized a portion of the Company's long-term debt (see Notes 6 and 7), as well as the Company's obligation to a surety company.

Depreciation and depletion expense totaled $1.3 million and $0.8 million for 2005 and 2004, respectively.

5. BUSINESSES UNDER CONTRACT FOR SALE

Effective December 31, 2002, the Company entered into an agreement to sell two subsidiaries whose assets consisted principally of land, buildings and equipment. The subsidiaries were in the business of distribution of refined petroleum products and convenience stores.

Capco agreed to continue to operate the businesses for a period of time subsequent to the date of sale to allow the buyer time to make separate credit arrangements with lenders and suppliers, and to negotiate for the removal of the Company as the guarantor of a significant portion of the indebtedness assumed by the buyer. Approximately $3.8 million of indebtedness was owed to one lender by one of the subsidiaries, and the subsidiary was in default on the indebtedness. The sales transaction resulted in a gain to the Company in the amount of $0.2 million; however, due to the significant risk still assumed by the Company in the form of the loan guarantees, the gain was to be deferred until such time that the risk either was significantly reduced or eliminated.

During the period 2003 to 2005, there were several attempts to achieve a renegotiation of the indebtedness, all without success. Some of the underlying property was sold with the proceeds applied to the indebtedness, but Capco’s guarantee remained in place.

The Company evaluated the exposure relating to the debt guarantees as of December 31, 2003, and determined that the Company would, in all likelihood, incur a loss from this disposal. It was estimated that the liabilities, which are guaranteed by the Company, exceeded the underlying net assets by approximately $0.3 million. The Company accounted for this deficit by eliminating the deferred gain of $0.2 million recorded in 2002, and by recording a $0.2 million charge in 2003.

In October 2005, the parties achieved a restructuring of the indebtedness that provided for the removal of Capco’s debt guarantee, although Capco is a party to an indemnification agreement that survived the settlement. Pursuant to the terms of the indemnification agreement, Capco’s liability for the items covered by the indemnification is limited to $0.3 million. For its part in the restructuring Capco agreed to fund a total of $0.3 million to be applied to the outstanding indebtedness. Of this amount, $0.2 million was paid in December 2005, and $0.1 million was paid in January 2006. Capco also granted 1,915,344 warrants to Hoactzin as consideration for its participation in the refinancing of the indebtedness. Using the Black-Scholes pricing model, the warrants had a fair value of $0.3 million. This cost has been charged to operations by Capco, with a corresponding increase to paid in capital. The warrants are exercisable for a period of five years with an exercise price of $0.195 per share.

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6. LONG TERM DEBT

Long-term debt consisted of the following as of December 31, 2005 (in thousands):

Note payable, interest at 8% per annum, payable in one installment of $80 and ten monthly installments of $10, which includes principal and interest, to November 2005, collateralized by oil and gas leases	$	17

Note payable to a related party, interest at 7%, payable
in monthly installments of $4, due on June 30, 2006		77

Note payable to an individual, interest at 12.0%,
payable in monthly installments of $75, which includes
principal and interest, due in June 2006, collateralized
by producing oil and gas properties and by the guarantee
of the Company's Chief Executive Officer		455

Notes payable for equipment and oilfield services, interest
ranging from 3.5% to 9.5%, payable in total monthly
installments of $8, due at various times to December 2009,
collateralized by equipment		182
Total debt		731
Less current maturities		(633	)
Long term debt	$	98

The following is a summary of the principal amounts payable over the next four years (in thousands):

Year ending December 31,
2006	$	633
2007		83
2008		7
2009		8
	$	731

Interest expense for all corporate borrowings totaled $0.4 million and $0.4 million for the years ended December 31, 2005 and 2004, respectively.

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7. CONVERTIBLE PROMISSORY NOTES

Convertible promissory notes consisted of the following as of December 31, 2005 (in thousands):

Note payable to an individual, interest at 9%,
plus an incremental interest rate of 1% for every $1 that
West Texas Intermediate Crude exceeds $21 per barrel
payable quarterly, convertible into common stock
at the option of the holder at $0.38 per share,
with the past due unpaid principal as of May 2003, no collateral	$	25

Notes payable to individuals, interest at 12%,
payable quarterly, convertible into common
stock at the option of the holders at $0.20 per share,
with the unpaid principal due during February to May
2007 (net of unamortized discounts of $12), no collateral		243

Note payable to an individual, interest at 10%,
payable quarterly, convertible into Common
Stock at the option of the holder at $0.18 per share,
with the unpaid principal due in
September 2008 (net of unamortized discount of $47),
collateralized by oil and gas properties		1,653

Note payable to an individual, interest at 12%,
payable quarterly, convertible into common
stock at the option of the holder at $0.15 per share,
with the unpaid principal due in September 2008, no collateral		150
		2,071
Less current maturities		(25	)
	$	2,046

At the option of the holders, the notes can be converted into as many as 11.8 million shares of the Company’s Common Stock. Notes not converted during the three-year period from date of sale are to be redeemed for their face amount on the third anniversary from the subscription date. Pursuant to EITF 98-5, “Accounting for Convertible Securities with Beneficial Conversion Features or Contingently Adjustable Conversion Ratios”, discounts of approximately $0.1 million attributable to the beneficial conversion feature were recorded as additional paid in capital. The discounts are being amortized using the effective interest rate method over the terms of the indebtedness.

8.	OTHER LONG-TERM LIABILITIES

Other long-term liabilities consisted of the following at December 31, 2005 (in thousands):

Minority interest in former consolidated subsidiary	$	361

Production payable		150

Vendor payable in dispute		879

Deferred income taxes		27
	$	1,417

9. COMMITMENTS AND CONTINGENCIES

ENVIRONMENT

Capco, as owner and operator of oil and gas properties, is subject to various federal, state, and local laws and regulations relating to discharge of materials into, and protection of, the environment. These laws and regulations may, among other things, impose liability on the owner of real property and the lessee under oil and gas leases for the cost of pollution clean-up resulting from operations, subject the owner/lessee to liability for pollution damages and impose restrictions on the injection of liquids into subsurface strata.

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Although Company environmental policies and practices are designed to ensure compliance with these laws and regulations, future developments and increasing stringent regulations could require the Company to make additional unforeseen environmental expenditures.

The Company maintains insurance coverage that it believes is customary in the industry, although it is not fully insured against all environmental risks.

The Company is not aware of any environmental claims existing as of December 31, 2005, that would have a material impact on its consolidated financial position or results of operations. There can be no assurance, however, that current regulatory requirements will not change, or past non-compliance with environmental laws will not be discovered on the Company's property.

LAND RENTALS AND OPERATING LEASES

The Company leases office facilities and equipment under operating leases expiring through March 31, 2007. As of December 31, 2005, future minimum rental payments required under operating leases are as follows (in thousands):

Year ending December 31,
2006	$	74
2007		2
	$	76

Rental expense charged to operations totaled $0.1 million and $64,000 for the years ended December 31, 2005 and 2004, respectively.

LEGAL PROCEEDINGS

The Company is a party to certain litigation that has arisen in the normal course of its business and that of its subsidiaries. A company engaged by Capco to provide well service in connection with work over operations on some of the Company’s offshore wells has filed a claim for unpaid invoices in the amount of approximately $0.2 million. Capco has recorded less than $50,000 of such costs in its accounts, and has claims against the service company for damages and costs to its wells in an estimated amount in excess of $1.0 million. The Company expects to show that its damages far exceed the claim amount asserted by the service company.

In a matter styled Harvest Oil & Gas, LLC v Capco Energy, Inc. filed in United States District Court, Eastern District of Louisiana on August 16, 2005, the claimant seeks collection of a $0.6 million finders fee on a transaction where title to oil and gas properties was initially taken by Capco, but then immediately transferred to the Hoactzin investment program. A trial date of January 22, 2007, has been set to hear the mater. The Company has not recorded any loss provision for this matter as it believes the complaint to be without merit, but in the event that the plaintiff is successful in obtaining a favorable result against the Company, Capco plans to seek reimbursement from the Hoactzin investment program.

OTHER

Capco is obligated to a surety company to make monthly cash collateral deposits of $24,000 over a period of thirteen months, ending February 2007.

Various oil and gas property purchase agreements require that funding obligations of $1.1 million and $0.3 million be paid from the net profits, if any, derived from the respective operations of the properties. A total of $14,000 was paid in 2005 against the $0.3 million obligation.

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Capco is guarantor of certain obligations of business interests that Capco sold during 2003 of $1.3 million at December 31, 2005. The obligations consist of vendor trade accounts, and real estate and equipment purchases and leases. Management believes that there is sufficient underlying collateral value in the related assets to significantly reduce the potential loss, if any, to Capco. Subsequent to December 31, 2005, the business interests effected significant reductions to the outstanding indebtedness, such that as of April 30, 2006, the amount subject to Capco’s guarantee was $0.2 million.

Capco has provided an indemnification in an amount not to exceed $250,000 to a party that formerly was the holder of indebtedness of which Capco was a guarantor.

10. EQUITY

COMMON STOCK

During 2005, Capco had the following significant equity transactions:

Capco issued 125,000 shares of Common Stock upon the exercise of options, realizing proceeds of $22,000.

Capco issued 1,074,286 shares of Common Stock to settle $213,000 in prior year liabilities. Included in these amounts were 1.0 million shares issued in settlement of an obligation for the acquisition of a property for $200,000.

Capco issued 925,715 shares of Common Stock under its 1999 Incentive Option Plan for compensation valued at $162,000, which had been reported as a liability as of the end of 2004.

Capco issued 300,000 shares of Common Stock upon the election by holders of convertible promissory notes of $45,000, to convert the notes into Common Stock.

Capco sold 1.0 million shares of Common Stock to an individual for $175,000.

On March 10, 2005, Capco sold 10 million shares of Common Stock for $3.0 million in a private placement. No underwriter discounts or commissions were paid.

On May 10, 2005, Capco sold 4 million shares of Common Stock for $1.2 million in a private placement. No underwriter discounts or commissions were paid.

On June 15, 2005, Capco increased the number of shares authorized from 150,000,000 to 500,000,000 shares.

During 2004, Capco had the following significant equity transactions:

Capco issued 300,000 shares of Common Stock in settlement of a $30,000 liability which represented the fair market value of the Common Stock when both parties agreed to the settlement.

Capco issued 1,095,000 shares of Common Stock upon the exercise of options, realizing proceeds of $70,500.

Capco issued 3,644,760 shares of Common Stock for the acquisition of an oil and gas property for $437,000, which represented the fair market value of the Common Stock when the acquisition closed.

TREASURY STOCK

In 2005, Capco repurchased 1.2 million shares of Common Stock for $205,740.

In 2004, Capco repurchased 60,600 shares of Common Stock for $11,000.

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STOCK OPTIONS

Capco has a Stock Option Plan providing for the issuance of incentive stock options and non-qualified stock options to Capco's key employees.

Incentive stock options may be granted at prices not less than 100% of the fair market value at the date of the grant. Non-qualified stock options may be granted at prices not less than 75% of the fair market value at the date of the grant.

No compensation cost was recognized for stock option grants in 2005 and 2004. The options were granted with maximum terms between one and five years.

A summary of the status of the Company's stock option plan as of December 31, 2005 and 2004 is presented below:

	2005					2004
	Shares			Weighted average exercise price		Shares			Weighted average exercise price
Outstanding
at beginning of year		16,000,000		$	0.14		15,880,000		$	0.13
Granted at less than
market		1,000,000		$	0.18		--			--
Granted at market		1,300,000		$	0.22		1,700,000		$	0.18
Exercised		(25,000	)	$	0.06		(1,080,000	)	$	0.06
Canceled		--			--		(500,000	)	$	0.20
Forfeited		--			--		--			--
Outstanding at end
of year		18,275,000		$	0.14		16,000,000		$	0.14
Options exercisable
at end of year		18,275,000		$	0.14		16,000,000		$	0.14

	Options Outstanding						Options Exercisable
Year options granted	Range of exercise prices		Number outstanding	Weighted average remaining contractual life		Weighted average exercise price	Number exercisable		Weighted average exercise price
2003	$0.06 to $0.25		14,775,000	2.16 years	$	0.13	14,775,000	$	0.13
2004	$0.17		1,200,000	3.75 years	$	0.18	1,200,000	$	0.18
2005	$0.17 to $0.22		2,300,000	3.58 years	$	0.20	2,300,000	$	0.20
		$0.06 to $0.25	18,275,000	2.44 years	$	0.14	18,275,000	$	0.14

Non-employee options

Capco did not issue stock options to any non-employee during 2005 and 2004.

In January 2003, options to acquire 600,000 shares of the Company's Common Stock at an exercise price of $0.20 were granted to an individual for market consulting services. Options to acquire 200,000 shares were exercised during 2005, and 15,000 options were exercised during 2004, leaving a balance of unexercised options of 385,000 at December 31, 2005. The unexercised options expired in January 2006.

F-27

OTHER DILUTIVE SECURITIES

In addition to the options discussed above, Capco has outstanding other dilutive securities. A summary of such securities follows:

Issue	Range of conversion/ exercise prices	Underlying shares of Common Stock		Weighted average remaining contractual life		Weighted average exercise prices
Convertible promissory
Notes	$0.15-$0.375		11,878,438		2.57 years		--

Warrants granted with
private placement of
Common Stock	$0.45		7,000,000		4.26 years	$	0.45

Warrants granted with
financing agreement	$0.176-$0.30		31,389,721		3.94 years	$	0.24

Warrants granted with
consulting agreements	$0.175-$0.27		7,000,000		2.23 years	$	0.20

11. INCOME TAXES

Following is a reconciliation of the Federal statutory rate to the effective income tax rate for 2005 and 2004:

	2005			2004
Federal income tax rate		(34.0	)%		34.0	%
State income taxes, net of
federal benefit		(6.0	)%		6.0	%
Utilization of NOL carry forward		--			--
Effect of valuation allowance		40.0	%		(40.0	)%
Effective income tax rate		0.0	%		0.0	%

At December 31, 2005, Capco had net operating loss carry forwards of approximately $9.6 million, which expire at various dates through the year 2021.

Deferred tax assets and liabilities reflect the net tax effect of temporary differences between the carrying amount of assets and liabilities for financial reporting purposes and amounts used for income tax purposes. Significant components of Capco’s deferred tax assets and liabilities are as follows at December 31 (in thousands):

	2005			2004
Deferred tax assets:
Marketable securities, receivables and
liabilities	$	27		$	27
Loss carry forward		3,837			2,871
Less: valuation allowance		(2,668	)		(1,047	)
	$	1,196		$	1,851

Deferred tax liability:
Property and equipment and investments	$	1,196		$	1,851

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The non-current portions of the deferred tax asset and the deferred tax liability accounts offset each other in the Company’s consolidated balance sheet.

12. RELATED PARTY TRANSACTIONS

Year Ended December 31, 2005

Capco had several transactions with Sedco, Inc. and Meteor Enterprises, Inc., private companies controlled by CEO Ilyas Chaudhary ("affiliates"). The Company paid expenses in the amount of $28,000 in behalf of affiliates, and was charged a total of $8,000 for expenditures made by affiliates in behalf of the Company. The Company accrued compensation expense in the amount of $435,000 due to affiliates in accordance with the Chief Executive Officer's employment. Included in this amount is the $108,000 that was reported as prepaid compensation at the end of year 2004. The Company made net cash advances in the amount of $258,000 to affiliates that included payment of accrued compensation and settlement of expenditures made by the respective parties during the year in behalf of each other. At December 31, 2005, the amount of $49,000 was due to affiliates.

In October 2005, a private company owned by Capco’s CEO achieved a restructuring of indebtedness that provided for the removal of Capco’s debt guarantee, although Capco is a party to an indemnification agreement that survived the settlement. Pursuant to the terms of the indemnification agreement, Capco’s liability for the items covered by the indemnification is limited to $0.3 million. For its part in the restructuring Capco agreed to fund a total of $0.3 million to be applied to the outstanding indebtedness. Of this amount, $0.2 million was paid in December 2005, and $0.1 million was paid in January 2006. Capco also granted 1.8 million warrants to Hoactzin as consideration for its participation in the refinancing of the indebtedness. Using the Black-Scholes pricing model, the warrants were determined to have a fair value of $0.3 million. This cost has been charged to operations by Capco, with a corresponding increase to paid in capital. The warrants are exercisable for a period of five years with an exercise price of $0.195 per share.

Effective April 1, 2005, the Company divested its 80% equity interest in Bison Energy Company that was acquired from a Director of the Company during 2004 by selling the interest to the Director for the Company’s original investment. Funding provided to Bison by Capco in 2004 of $50,000 that had previously been accounted for as an advance to Bison was reclassified as a payment against long-term debt owed to the Director. The Company incurred interest expense of $7,000 on the indebtedness in 2005.

Year Ended December 31, 2004

The Company had several transactions with its Chief Executive Officer, Ilyas Chaudhary, and Sedco, Inc. and Meteor Enterprises, Inc., private companies controlled by Mr. Chaudhary ("affiliates"). The Company received cash advances in the total amount of $350,000 from affiliates. The Company paid expenses in the amount of $93,000 in behalf of affiliates, and was charged a total of $67,000 for expenditures made by affiliates in behalf of the Company. The Company accrued, and paid, compensation expense in the amount of $175,000 due to affiliates in accordance with the Chief Executive Officer's employment. The Company made cash advances in the total amount of $766,000 to affiliates that included repayment of the balance in the amount of $159,000 owed to affiliates at the beginning of the year, repayment of cash advances received during the year and settlement of expenditures made by the respective parties during the year in behalf of each other. Of such advances, $108,000 was considered to be advance payments of Mr. Chaudhary’s compensation for the year 2005, and has been reclassified as a prepaid expense in the accompanying financial statements as of December 31, 2004. No amount was due to, or due from, affiliates at December 31, 2004, except as discussed below.

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Effective September 30, 2004, the Company sold its interests in non-operated producing properties located in Alabama and Louisiana to a company owned by the Company’s Chief Executive Officer. Sales proceeds of $0.4 million were received in October 2004. If it is determined through due diligence by the Company that the properties could have been sold for an amount greater than $0.4 million, then the related party has the obligation to pay such excess to the Company, or the Company, at its option, may repurchase the properties at the original sales price. There were no changes in 2005 to the transaction as originally closed in 2004.

In September 2004, the Company acquired from a Director an 80% equity interest in a start-up company formed for the purpose of acquiring producing oil and gas properties. Subsequent to the incorporation of the company, Capco advanced $50,000 to provide funding for the cost of an acquisition and for working capital.

In October 2004, the Company purchased a property for 3.6 million shares valued at $576,000. The per share price of $0.16 approximated the market price of the Company’s Common Stock at that time. Approximately 70% of the acquired working interest in the property was acquired as a result of Capco’s exchange of shares for 100% equity ownership of Packard Gas Company with individuals, or entities controlled by individuals, who have either a direct, or beneficial, relationship to the Company, including Capco’s President. The negotiated acquisition price was determined in amounts prorata to all members of the selling group.

Effective December 31, 2004, the Company sold its interests in non-operated producing properties located in Michigan and Montana and other assets to Capco’s Chief Executive Officer for $4.7 million. The Company received a fairness opinion for the sale in January 2005. The sales amount was settled by the receipt of $0.7 million cash in December, assumption of debt against the properties in the amount of $3.3 million and receipt of $0.7 million in March 2005.

Capco incurred interest expense in the amount of $11,000 on a note payable to a Director that was outstanding during 2004.

13. PROFIT SHARING PLAN

The Company maintains a 401(k) Plan covering all eligible employees. Profit sharing contributions are made (i) at the discretion of the Board of Directors; and (ii) on the employee's behalf from salary deferrals. Eligible employees may contribute on a pre-tax basis up to 100% of their qualifying annual compensation, to a maximum of $40,000. Employer discretionary contributions are not to exceed 50% of the first six percent of each employee's compensation. Capco did not incur any expense for employer matching contributions for either of 2005 and 2004.

14. MAJOR CUSTOMERS

During 2005, the Company had sales to two customers that accounted for approximately 73.6% and 24.9%, respectively, of total oil and gas sales. Five customers accounted for 22.7%, 21.6%, 12.9%, 12.7% and 10.4%, respectively, of accounts receivable as of December 31, 2005.

During 2004, Capco had sales to two customers that accounted for approximately 52.3% and 33.0%, respectively, of total oil and gas sales. One customer accounted for 49.6% of accounts receivable as of December 31, 2004.

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15. SUBSEQUENT EVENTS

Om March 2, 2006, Nabors Offshore Corporation filed a lawsuit against Capco and a subsidiary seeking recovery of $0.9 million for unpaid drilling rig service invoices for a well drilled by the Company during the year 2005. Capco disputes this claim and in turn has filed a counterclaim of $1.3 million for recovery of excess cost resulting from the actions of Nabors and reimbursement for fuel cost that was charged to Capco. No trial date has yet been set for this matter.

On June 2, 2006, Capco agreed to purchase oil and gas properties located in Federal waters in the Gulf of Mexico for $83 million. An acquisition deposit in the amount of $8.3 million was provided by Hoactzin, which increased their investment amount. Closing of the acquisition is scheduled for a date no later than August 31, 2006. The Company plans to obtain the balance of the necessary funding from either commercial lenders or industry partners.

As of December 31, 2005, the remaining investment amount to be recovered by Hoactzin, exclusive of future interest accruals, was $10.6 million. For the period from January 1, 2006, to June 16, 2006, Hoactzin made expenditures in the amount of $9.3 million, which included the $8.3 million discussed above, posted interest accruals of $0.2 million and received distributions in the total amount of $8.6 million. There remained $11.5 million to be recovered to achieve payout, which would result in the activation of Capco’s management fee equivalent to two-thirds of the venture’s net cash flow.

Effective June 30, 2006, the Company sold its membership interests in Capco Marine LLC and Midway Sunset LLC to an entity managed by a shareholder of the Company. Total consideration of $1.5 million consisted of $0.3 million cash, the assumption of Company liabilities of $0.2 million, and a note receivable of $1.0 million. The note bears interest at the rate of 10% per annum and matures for payment on September 30, 2006, with an option to extend the maturity date to November 30, 2006.

16. SUPPLEMENTAL INFORMATION ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED)

Capco’s independent engineers, Ryder Scott Company and Pressler Petroleum Consultants, Inc., prepared reserve estimates for the year-end reports for 2005 and 2004, respectively. Management cautions that there are many inherent uncertainties in estimating proved reserve quantities and related revenues and expenses, and in projecting future production rates and the timing and amount of development expenditures. Accordingly, these estimates will change, as future information becomes available.

Proved oil and gas reserves are the estimated quantities of crude oil, condensate, natural gas and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions.

Proved developed reserves are those reserves expected to be recovered through existing wells with existing equipment and operating methods.

The Company’s proved reserves at December 31, 2005 changed significantly from the reported quantities at December 31, 2004. Oil reserves decreased 277,000 barrels due to revisions of previous estimates by our independent engineers. Based primarily on operating performance during the year 2005, the estimates of remaining proved oil reserves for the Company’s SUDS West property in Creek County, Oklahoma, and Caplen Field in Galveston County, Texas were revised downward by 221,500 and 105,500 barrels of oil, respectively. The estimate of remaining proved oil reserves for the Company’s Bandwheel property in Osage County, Oklahoma was increased by 46,400 barrels of oil. Revisions of estimates of remaining proved gas reserves accounted for an increase of 2.5 mmcf of gas, all of which was attributable to the Company’s Brazos property located in offshore Matagorda County, Texas. Based on current year production and the initial results of the rework program which began in the fourth quarter of year 2005, including extensive geological study and log analysis, the independent engineers determined that the estimate of remaining proved gas reserves had increased from the end of the prior year.

F-31

Capco had a significant decline in reserves in 2004 attributable to its producing properties located in onshore and offshore Texas. Downward revisions to the Caplen Field located in Galveston County, Texas totaled 151,427 barrels of oil and 240,085 mcf of gas. Production in the year 2004 was significantly curtailed due to field operational problems. Wells, which were shut-in for an extended period during the year 2004, and remained shut-in at year-end, were reclassified to proved developed non-producing status. Proved developed gas reserves decreased from 317,506 mcf to 33,336 mcf. Approximately 55% of the decrease was due to the elimination of one well as it was determined during the year 2004 that the reservoir was depleted. Proved undeveloped oil reserves decreased from 210,020 barrels to 78,863 barrels due to the elimination of one location and per well reductions based on the incumbent engineer’s evaluation of the locations. Proved reserves attributed to the Brazos Field located in offshore Matagorda County, Texas were revised downward in the amounts of 50,877 barrels of oil and 7,351,615 mcf of gas. Work-over activities were conducted on five wells during the year in an attempt to either increase production rates or restore wells to service. Such activities were successful on only one well. As a result the incumbent engineer significantly reduced the previously reported proved reserves until such time that it can be demonstrated that the wells are capable of producing at economical levels. The changes reflect the engineers’ subjective evaluation of the properties based on a number of factors including data that was available when the evaluation was prepared, actual production during the current year and price changes. Properties sold by the Company during the year 2004 resulted in additional decreases of 190,400 barrels of oil and 6,262,000 mcf of gas. Properties acquired during the year 2004 resulted in an increase to proved reserves of 240,200 barrels of oil and 83,000 mcf of gas, while year 2004 production resulted in a decrease of proved reserves of 22,100 barrels of oil and 727,000 mcf of gas.

ANALYSIS OF CHANGES IN PROVED RESERVES

Estimated quantities of proved reserves and proved developed reserves of crude oil and natural gas, all of which are located within the United States, as well as changes in proved reserves during the past two years are indicated below:

	Oil (Bbls)			Natural Gas (MCF)

Proved reserves at December 31, 2003		561,215			17,614,263
Purchases of minerals in place		240,212			83,231
Extensions and discoveries		--			--
Sales of minerals in place		(190,355	)		(6,262,191	)
Production		(22,087	)		(727,336	)
Revisions of previous estimates		(202,305	)		(7,591,696	)
Proved reserves at December 31, 2004		386,680			3,116,271
Purchases of minerals in place		42,750			--
Extensions and discoveries		--			--
Sales of minerals in place		(1,313	)		(454,182	)
Production		(12,620	)		(293,199	)
Revisions of previous estimates		(277,032	)		2,497,007
Proved reserves at December 31, 2005		138,465			4,865,897
Proved developed reserves, December 31, 2005		95,715			4,865,897

F-32

There are no reserves attributable to partnership or minority interests at December 31, 2005.

The Company incurred the following capitalized costs related to oil and gas activities during the year ended December 31, 2005 (in thousands):

Properties being amortized	$	6,601
Properties not subject to amortization		--
	$	6,601

OIL AND GAS OPERATIONS

Depletion, depreciation and accretion per equivalent unit of production for the years ended December 31, 2005 and 2004, was $20.53 and $5.55, respectively.

Costs incurred by the Company during the year 2005 for acquisition, exploration and development activities are as follows (in thousands):

Acquisition of producing properties	$	--
Exploration and development		6,601
	$	6,601

STANDARDIZED MEASURE OF DISCOUNTED NET CASH FLOWS AND CHANGES THEREIN

The following information at December 31, 2005, and for the years ended December 31, 2005 and 2004, sets forth standardized measures of the discounted future net cash flows attributable to the Company's proved oil and gas reserves.

Future cash inflows were computed by applying year-end prices of oil and gas (with consideration of price changes only to the extent provided by contractual arrangements) and using the estimated future expenditures to be incurred in developing and producing the proved reserves, assuming continuation of existing economic conditions.

Future income tax expenses were computed by applying statutory income tax rates to the difference between pretax net cash flows relating to the Company's proven oil and gas reserves and the tax basis of proved oil and gas properties and available operating loss and excess statutory depletion carryovers reduced by investment tax credits. Discounting the annual net cash flows at 10% illustrates the impact of timing on these future cash flows.

The following table presents the standardized measure of discounted net cash flows at December 31, 2005 and 2004 (in thousands):

	2005			2004
Future cash inflows	$	44,160		$	34,039
Future cash outflows:
Production costs		(15,732	)		(10,418	)
Development costs (1)		(3,742	)		(5,787	)
Future net cash flows before
future income taxes		24,686			17,834

Future income taxes		(4,465	)		(4,586	)
Future net cash flows		20,221			13,248

Adjustment to discount future
annual net cash flows at 10%		(7,087	)		(3,683	)
Standardized measure of discounted
future net cash flows	$	13,134		$	9,565

(1)	Includes estimated expenditures in each of the next three years to develop proved undeveloped reserves as follows (in thousands):

2005: $1,583 (2006), $-0- (2007), and $-0- (2008)

2004: $1,919 (2005), $894 (2006), and $-0- (2007)

F-33

The following tables summarize the principal factors comprising the changes in the standardized measures of discounted net cash flows during the years 2005 and 2004 (in thousands):

	2005			2004
Standardized measure, beginning of
period	$	9,565		$	32,442
Sales of oil and gas, net of
production costs		(771	)		(2,264	)
Net change in sales prices, net of
production costs		(1,804	)		9,279
Changes in estimated future
development costs		3,565			(1,658	)
Purchases of minerals in place		661			2,956
Sales of minerals in place		(1,704	)		(11,841	)
Revisions of quantity estimates		2,402			(30,488	)
Accretion of discount		956			3,244
Other, including changes in production
rates (timing)		51			(2,845	)
Change in income taxes		213			10,740
Standardized measure, end of period	$	13,134		$	9,565

F-34

EXHIBIT 31.1

CERTIFICATION

I, Ilyas Chaudhary certify that:

1. I have reviewed this Amendment No. 2 to Form 10-KSB/A for the fiscal year ended December 31, 2005, of Capco Energy, Inc.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the small business issuer as of, and for, the periods presented in this report;

4. The small business issuer’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the small business issuer and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under my supervision, to ensure that material information relating to the small business issuer, including its consolidated subsidiaries, is made known to me by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) Evaluated the effectiveness of the small business issuer's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the small business issuer's internal control over financial reporting that occurred during the small business issuer's most recent fiscal quarter (the small business issuer's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the small business issuer's internal control over financial reporting; and

5. The small business issuer’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the small business issuer's auditors and the audit committee of the small business issuer's board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the small business issuer's ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the small business issuer's internal control over financial reporting.

Date: December XX, 2006

Ilyas Chaudhary, Chief Executive Officer

EXHIBIT 31.2

CERTIFICATION

I, Mansoor Anjum certify that:

1. I have reviewed this Amendment No. 2 to Form 10-KSB for the fiscal year ended December 31, 2005, of Capco Energy, Inc.;

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the small business issuer's internal control over financial reporting.

Date: December XX, 2006

Mansoor Anjum, Chief Financial Officer