MANUFACTURED HOUSING PROPERTIES INC. - Annual Report: 2010 (Form 10-K)

stratum10k123110_3262011.htm

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

Annual Report Under Section 13 or 15(d) of the

Securities Exchange Act of 1934

For the Fiscal Year Ended December 31, 2010

Commission File No. 000-51229

STRATUM HOLDINGS, INC.

(Exact Name of Registrant as specified in its charter)

Nevada	51-0482104
(State or other jurisdiction of incorporation)	(IRS Employer Identification Number)

Three Riverway, Suite 1590 Houston, Texas	77056
(Address of principal executive offices)	(zip code)

(713) 479-7050

(Registrant's telephone number, including area code)

Securities Registered Under Section 12(b) of the Exchange Act:

None

Securities Registered Under Section 12(g) of the Exchange Act:

Common Stock, $0.01 par value

Indicate by check mark if the Registrant is a well-known seasoned issuer (as defined in Rule 405 of the Securities Act): Yes [ ] No [X]

Indicate by check mark if the Registrant is not required to file reports pursuant to Section 13 or 15(d) of the Act): Yes [ ] No [X]

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

Indicate by check mark whether the Registrant has submitted electronically and posted on its corporate Website, if any, every Interactive Date File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months. Yes: [ ] No: [ ]

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

Indicate by check mark whether the Registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer,” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer ¨ Accelerated filer ¨ Non-accelerated filer ¨ Smaller reporting company [X]

Indicate by check mark whether the Registrant is a shell company (as defined in Rule 12b-2 of the Act): Yes [ ] No [X]

The aggregate market value of Common Stock held by non-affiliates of the Registrant (based upon the closing price of such shares as quoted on the OTC Bulletin Board) as of the last business day of the most recently completed second fiscal quarter was approximately $50,000.

The number of shares outstanding of the Registrant's Common Stock as of March 30, 2011 was 2,655,738 shares.

STRATUM HOLDINGS, INC.

2010 FORM 10-K

INDEX

			Page

PART I
	Item 1 and 2.	Description of Business and Properties.	3

	Item 3.	Legal Proceedings.	6

PART II
	Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.	7

	Item 6.	Selected Financial Data.	8

	Item 7.	Management's Discussion and Analysis of Financial Condition and Results of Operations.	8

	Item 8.	Financial Statements and Supplementary Data.	13

	Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.	13

	Item 9A.	Controls and Procedures.	14

	Item 9B.	Other Information.	15

PART III
	Item 10.	Directors, Executive Officers and Corporate Governance.	16

	Item 11.	Executive Compensation.	17

	Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.	18

	Item 13.	Certain Relationships and Related Transactions, and Director Independence.	19

	Item 14.	Principal Accounting Fees and Services.	19

PART IV
	Item 15.	Exhibits, Financial Statement Schedules.	19

		Signatures.	43

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PART I

Item 1 and 2. Description of Business and Properties.

Stratum Holdings, Inc. (“we” or the “Company”) is a holding company headquartered in Houston, Texas, which has operations in both the domestic Exploration & Production business and the Canadian Energy Services business. In the domestic Exploration & Production business, our wholly-owned subsidiaries, CYMRI, L.L.C. and Triumph Energy, Inc., own working interests in approximately 60 producing oil and gas wells in Texas and Louisiana, with net production of approximately 700 MCF equivalent per day. Our operations in the Canadian Energy Services business are conducted through our wholly-owned subsidiaries, Decca Consulting, Ltd. and Decca Consulting, Inc. (collectively referred to as “Decca”), which provide on-site drilling and completion consulting services to oil and gas operators, primarily in Canada.

Beginning in 2004 with a platform as a small construction services company (known as Tradestar Services, Inc.) the Company converted into its present energy format through a series of corporate level transactions as follows:

Acquisition of CYMRI Corporation and its subsidiaries, Petroleum Engineers, Inc. and Triumph Energy, Inc., in May 2006 for a net cost of $12.7 million;

Acquisition of Decca Consulting, Ltd., a Canadian Energy Services company, in March 2007 for a net cost of $5.7 million; and

Sale of Petroleum Engineers, Inc. (“PEI”), a domestic Energy Services subsidiary, in March 2008 for a sales price of $15 million.

As a result of the PEI sale, we exited from the domestic portion of our Energy Services segment in March 2008, leaving us with our core operations in the domestic Exploration & Production segment as well as the Canadian portion of our Energy Services segment. We operate these two continuing business on an essentially autonomous basis. We are considering a possible sale of Decca and recently entered into a non-binding letter of intent in that regard (see “Item 9B. Other Information”).

We seek to increase shareholder value through an approach focused on both organic growth and acquisition opportunities in the energy industry. Our management team has executive level contacts throughout the energy industry and has experience in leveraging contacts in one industry sector to generate opportunities in other industry sectors, as well as expertise in closing and integrating acquisition opportunities.

The following two sections provide additional background information on our domestic Exploration & Production business and our Canadian Energy Services business.

Exploration & Production

The Company’s Exploration & Production operations commenced with the acquisition of The CYMRI Corporation (“CYMRI”) in May 2006 for a combination of cash, notes payable and Common Stock totaling $12.7 million. CYMRI was originally formed by our present Chief Executive Officer, Larry Wright, in July 2001 to acquire long-lived oil and gas reserves. CYMRI completed a total of five oil and gas property acquisitions in South Texas, primarily known as the Burnell and Kibbe Fields, in 2001-2003.

CYMRI acquired PEI in June 2004 for total consideration of $5.1 million and that acquisition included interests in non-operated oil and gas properties in South Louisiana owned by Triumph Energy, Inc., a PEI affiliate. The Company’s sale of PEI in March 2008 did not include the business or properties of Triumph Energy, Inc.

Shown below are certain SEC required disclosures regarding the Exploration & Production segment.

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Oil and Gas Reserves

The following table sets forth summary information with respect to CYMRI’s proved oil and gas reserves, as estimated by the Company, based on consultation with an independent reservoir engineering firm, as of December 31, 2010:

	Oil		Gas		Total		PV10 Value
	(MBbl)		(MMcf)		(MMcfe)		(000's)

Proved developed reserves		473		830		3,668	$	9,572
Proved undeveloped reserves		48		-		288		676
Total proved reserves		521		830		3,956		10,248
Discounted future income taxes								(3,313	)
Standardized measure of discounted
future net cash flows							$	6,935

Reservoir engineering is a subjective process of estimating underground accumulations of crude oil, condensate and natural gas that cannot be measured in an exact manner, and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. The quantities of oil and gas that are ultimately recovered, production and operating costs, the amount and timing of future development expenditures and future oil and gas sales prices may differ from those assumed in these estimates. Therefore, the pre-tax PV 10 Value amounts shown above should not be construed as the current market value of the oil and gas reserves attributable to the Company’s properties. The pre-tax PV 10 Value may be considered a non-GAAP measure as defined by the Securities and Exchange Commission (“SEC”).

In accordance with the guidelines of the SEC, the reservoir engineers’ estimates of future net revenues from our properties and the pre-tax PV 10 Value amounts thereof are made using oil and gas sales prices in effect as of the dates of such estimates and are held constant throughout the life of the properties, except where such guidelines permit alternate treatment, including the use of fixed and determinable contractual price escalations. The average beginning of the month prices for the year ended December 31, 2010 used in such estimates were $75.69 per barrel of oil and $4.74 per Mcf of gas.

Productive Oil and Gas Wells and Acreage

As of December 31, 2010, CYMRI maintained ownership interests in a total of 34.0 gross (25.5 net) productive wells in the State of Texas and 28.0 gross (5.2 net) productive wells in the State of Louisiana for a grand total of 62.0 gross (30.7 net) productive oil and gas wells. CYMRI did not participate in the drilling of any new oil and gas wells in the three years ended December 31, 2010.

As of December 31, 2010, CYMRI had ownership interests in approximately 3,000 net productive acres in the States of Texas and Louisiana. CYMRI had no significant interests in any undeveloped acreage.

Production Prices and Costs

The average per barrel oil price received for CYMRI’s net oil production in the years ended December 31, 2010, 2009 and 2008 were $75.34, $64.03 and $113.89, respectively. The average per Mcf gas price received for CYMRI’s net gas production in the years ended December 31, 2010, 2009 and 2008 were $4.64, $7.35 and $10.50, respectively. In the same periods, CYMRI’s net production costs averaged $5.93, $4.42 and $7.11, respectively, per Mcf equivalent.

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CYMRI’s oil and gas production is sold to various purchasers in the States of Texas and Louisiana at spot or market sensitive prices under short-term contracts. CYMRI had no delivery commitments in the three years ended December 31, 2010.

Energy Services

As of December 31, 2010, the Company’s operations in the Energy Services segment were conducted through our wholly-owned subsidiaries, Decca Consulting, Ltd., acquired in 2007, and Decca Consulting, Inc., formed in 2010 (collectively referred to as “Decca”). Decca has its office in Calgary, Canada, with a cadre of up to 100 independent field consultants who provide drilling, completion and other on-site consulting services on a seasonal basis to oil and gas operators in Alberta and neighboring provinces as well as in selected international locations. These services are generally performed on a per diem rate for the customer operators, pursuant to term agreements which are subject to periodic rate adjustments. Decca’s customers include a number of international oil and gas companies with operations in Canada in addition to some of the largest independent oil and gas companies based in Canada.

Decca was formed in May 2003 as the successor to a company formed by the original principals in 1983 and was acquired by Stratum in March 2007. Since that time, Decca has operated as a generally autonomous subsidiary of Stratum. Decca owns no real property and has only a relatively small amount of office equipment and furniture. The company has historically had no employees and all of its functions, including management and administrative matters, are performed by independent consultants.

The work Decca performs in Canada is typically seasonal due to weather considerations. The Canadian consulting work normally reaches a peak in the first quarter of each year, then usually declines in the second quarter due to the spring thaw before increasing again in the third and fourth quarters. Decca attempts to mitigate the impact of this seasonality by maintaining a low overhead cost structure as evidenced by having no permanent employees.

Strategic Plans

The Company has reported substantial consolidated operating losses and working capital deficits since completing the acquisitions of CYMRI/PEI in May 2006 and Decca in March 2007. In order to address its liquidity needs, the Board of Directors authorized Management in July 2007 to pursue a range of alternative actions which culminated in the sale of PEI to an affiliate of Hamilton in March 2008. Since completing this sale, we have substantially reduced the Company’s level of corporate overhead expenses. We may decide to expand our domestic Exploration & Production business by making selective acquisitions of low risk oil and gas properties with exploitation potential. Since late 2010, we have considered a possible sale of Decca and in March 2011 we entered into a non-binding letter of intent to sell Decca (see “Item 9B. Other Information”).

Competition

Competition in the domestic Exploration & Production segment is extremely intense. Competitors include major oil and gas companies, large and small independent producers, and individual producers and operators. Many competitors have financial resources substantially greater than ours, and staffs and facilities substantially larger than ours. In the Exploration & Production segment, our success in operating our existing oil and gas properties as well as in acquiring and developing additional properties will depend on our ability to operate in this highly competitive environment. Competition in the Canadian Energy Services segment is likewise very intense coming from a broad spectrum of large and small service providers operating in Canada and elsewhere.

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Employees

As of December 31, 2010, the Company had a total of seven permanent employees between its corporate headquarters located in Houston, Texas, and its domestic Exploration & Production offices located in Lafayette, Louisiana (all of these individuals are employed by CYMRI, L.L.C.). As previously noted, Decca has historically had no employees and all of its business functions are performed in Calgary, Alberta, by independent consultants.

Regulation

The oil and gas industry is subject to extensive U.S. and Canadian governmental regulations which affect our domestic Exploration & Production and Canadian Energy Services segments. These governmental mandates include federal and state/provincial regulations governing environmental quality and pollution control, state limits on allowable rates of production by individual well or proration unit, the amount of oil and gas available for sale, the availability of adequate pipeline and other transportation and processing facilities and the marketing of competitive fuels.

Oil and Gas Terminology

The following terms are used to describe quantities of oil and natural gas in this document.

Bbl—One stock tank barrel, or 42 US gallons liquid volume, of crude oil or other liquid hydrocarbons.

Mcf—One thousand cubic feet of natural gas.

MBbl—One thousand Bbls.

MMcf—One million cubic feet of natural gas.

MMcfe—One million cubic feet of natural gas equivalent, converting oil to gas at the ratio of 6 Mcf of gas to 1 Bbl of oil.

Available Information

Our website address is www.stratum-holdings.com, however, the website information is not part of this report. We file annual, quarterly, and special reports, proxy statements, and other information periodically with the SEC. Such reports, proxy statements and other information filed with the SEC may be accessed electronically by means of the SEC's website at www.sec.gov. This material may also be inspected and copied at the public reference facilities of the SEC at 100 F Street N.E., Washington, DC 20549.

Item 3. Legal Proceedings.

Triumph Energy, Inc., a subsidiary in the Exploration & Production segment, and PEI are joint defendants in several lawsuits involving professional liability and other matters arising in the normal course of business in the State of Louisiana. It is not practical at the present time to determine the amount or likelihood of an unfavorable outcome to the Company’s consolidated financial position or results of operations of any of the these actions against Triumph. The Company believes that Triumph has meritorious defenses in each case and is vigorously defending these matters.

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In October 2008, an insurer for the Company’s inactive Construction Staffing subsidiary filed a lawsuit against the subsidiary alleging default on a premium finance obligation in the amount of approximately $200,000, plus interest and attorney’s fees. The Company believes that its inactive Construction Staffing subsidiary has a meritorious position in this matter and has not engaged legal counsel to defend this case. A non-appealable judgment was rendered in favor of the plaintiff in January 2011, however, the Company does not believe that it could be held liable for damages owing by its defunct Construction Staffing subsidiary.

With respect to the proceedings noted above, none involves primarily a claim for damages, exclusive of interest and costs, in excess of 10 percent of the Company’s current assets on a consolidated basis.

PART II

Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.

Since July 2005, our Common Stock has been quoted and traded on the OTC Bulletin Board. In March 2007, our trading symbol was changed to STTH.OB. Because we trade in the OTC Bulletin Board, a shareholder may find it difficult to dispose of or obtain accurate quotations as to price of our Common Stock. In addition, the Securities Enforcement and Penny Stock Reform Act of 1990 requires additional disclosure related to the market for penny stock and for trades in any stock defined as a penny stock.

On December 17, 2009, we completed a 1-for-10 reverse stock split of our Common Stock, pursuant to a plan approved by our Board of Directors. Accordingly, all Common Stock share and per share amounts in this annual report have been retroactively adjusted to reflect the reverse stock split. As of March 30, 2011, we had a total of 2,655,738 shares of our Common Stock outstanding and the number of holders of record of our Common Stock at that date was approximately 100. The following table sets forth the high and low bid prices of our Common Stock for each quarter during the calendar years 2009 and 2010:

	Bid Price
	High	Low
2009
First Quarter	$0.20	$0.20
Second Quarter	$0.20	$0.20
Third Quarter	$0.30	$0.20
Fourth Quarter	$0.50	$0.10

2010
First Quarter	$0.10	$0.05
Second Quarter	$0.12	$0.02
Third Quarter	$0.15	$0.08
Fourth Quarter	$0.14	$0.12

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We have never declared nor paid any cash dividends on our Common Stock and do not anticipate declaring any dividends in the foreseeable future. We expect to retain our cash for the operation and maintenance of our business. In addition, our senior bank credit facility contains restrictions on the payment of dividends to the holders of our Common Stock. We have made no repurchases of our Common Stock for the year ended December 31, 2010. The table below provides information relating to the Company’s equity compensation plans as of December 31, 2010:

Category	Number of Securities To be issued Upon exercise of Outstanding Options and Warrants	Weighted- average Exercise price Of Outstanding Options and Warrants	Number of Securities Remaining Available for Future Issuance Under Equity Compensation Plans

Equity compensation plans approved by security holders	37,500	$ 9.18	180,000
Equity compensation plans not approved by security holders	20,000	21.00	180,000

Total	57,500	$ 13.29	180,000

Item 6. Selected Financial Data.

Information for this Item is not required as the Registrant is a “smaller reporting company” as defined in Rule 12b-2 of the Exchange Act.

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.

The following discussion of our financial condition and results of operations should be read in conjunction with, and is qualified in its entirety by, the Company’s consolidated financial statements and notes thereto included in Item 8 in this Annual Report on Form 10-K. This item contains forward-looking statements that involve risks and uncertainties. Actual results may differ materially from those indicated in such forward-looking statements.

Overview

Stratum Holdings, Inc. (“we” or the “Company”) is a Nevada corporation, which has operations in both the domestic Exploration & Production business and the Canadian Energy Services business. In the domestic Exploration & Production business, our wholly-owned subsidiaries, CYMRI, L.L.C. and Triumph Energy, Inc., own working interests in approximately 60 producing oil and gas wells in Texas and Louisiana, with net production of approximately 750 MCF equivalent per day. Our operations in the Canadian Energy Services business are conducted through our wholly-owned subsidiaries, Decca Consulting, Ltd. and Decca Consulting, Inc. (collectively referred to as “Decca”), which provide on-site drilling and completion consulting services to oil and gas operators, primarily in Canada.

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We sold the capital stock of our former domestic Energy Services subsidiary, Petroleum Engineers, Inc. (“PEI”), to Hamilton Engineering, Inc. (“Hamilton”) in March 2008. As a result of the PEI sale, we exited from the domestic portion of our Energy Services segment leaving us with the Canadian portion of our Energy Services segment as well as our operations in the domestic Exploration & Production segment. We operate these two continuing business on an essentially autonomous basis.

Due to volatility in worldwide energy prices and tightening in credit markets, we have faced significant financial and operational challenges in the past two years and expect them to continue in the near term. Since late 2010, we have considered a possible sale of Decca and in March 2011 we entered into a non-binding letter of intent to sell Decca (see "Item 9B. Other Information").

Results of Operations

The following discussion reflects the revenues and expenses of our retained Canadian Energy Services and our domestic Exploration & Production segments as continuing operations while the revenues and expenses of our exited domestic Energy Services segment are reported as discontinued operations.

Year ended December 31, 2010 versus year ended December 31, 2009 — Total revenues from continuing operations for the year ended December 31, 2010 were $22,741,000 compared to $17,454,000 for the year ended December 31, 2009.

Revenues from Decca’s Energy Services for the year ended December 31, 2010 were $20,058,000 compared to $14,768,000 for the year ended December 31, 2009. This increase reflected a significantly higher level of work in Canada during the 2010 summer months compared to 2009 as well as a substantial increase in new work for Decca’s non-Canadian customers. Decca’s billings for Energy Services in the year ended December 31, 2010 were approximately 16,375 man days at an average billing rate of approximately $1,225 per day.

Revenues from CYMRI’s oil and gas sales for the year ended December 31, 2010 were $2,626,000 compared to $2,613,000 for the year ended December 31, 2009. In the year ended December 31, 2010, revenues from oil production were $2,289,000, reflecting volumes of 30,379 barrels at an average price of $75.34 per barrel, while gas revenues were $337,000, reflecting volumes of 72,540 Mcf at an average price of $4.64 per Mcf. On an overall basis, these amounts reflect a 30% secular increase in average oil and gas prices which was largely offset by a 22% decline in production volumes. The Company believes that continuing declines in CYMRI’s production volumes are likely in the foreseeable future.

Costs of Decca’s Energy Services for the year ended December 31, 2010 were $18,471,000 versus $13,491,000 for the year ended December 31, 2009. This increase in costs of Energy Services was in line with the previously noted increase in Decca’s Energy Services revenues. As a result of competitive pressures, Decca experienced a reduction in the gross margin on its consulting services to approximately 8% of gross revenues in the year ended December 31, 2010 from 9% in the year ended December 31, 2009.

Lease operating expenses (“LOE”), including production taxes, were $1,509,000 for the year ended December 31, 2010 versus $1,804,000 for the year ended December 31, 2009, representing LOE of CYMRI’s oil and gas production operations. This decrease was due to a reduction in certain non-recurring lease operating expenses, primarily in CYMRI’s Burnell Field, between these two periods.

Depreciation, depletion and amortization (“DD&A”) expense for the year ended December 31, 2010 was $528,000 versus $1,120,000 for the year ended December 31, 2009, representing DD&A of CYMRI’s oil and gas properties. This decrease was due to substantially lower depletion rates resulting from positive reserve revisions as well as lower production volumes.

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Impairment expense applicable to the goodwill assigned in the Decca acquisition was zero for the year ended December 31, 2010 compared to $1,900,000 for the year ended December 31, 2009. We recognized a non-cash impairment adjustment to the carrying value of the Decca goodwill in the first quarter of 2009 in the amount of $1,900,000, based on then current projections of Decca’s discounted future net cash flows (see Note 3). Impairment expense applicable to oil and gas properties was zero for the year ended December 31, 2010 compared to $907,000 for the year ended December 31, 2009 with the latter amounts reflecting a non-cash “ceiling test” adjustment under the full cost accounting rules, as more fully described in Note 3.

Workover expenses for the year ended December 31, 2010 were $475,000 versus $425,000 for the year ended December 31, 2009, representing workovers on CYMRI’s South Texas oil and gas properties. This relatively small increase was largely experienced in CYMRI’s Kibbe Field.

Selling, general and administrative (“SG&A”) expenses for the year ended December 31, 2010 were $1,814,000 compared to $2,076,000 for the year ended December 31, 2009. This decrease reflected a continuing reduction in the level of corporate overhead expenses following the PEI sale in March 2008.

Interest expense for the year ended December 31, 2010 was $790,000 versus $764,000 for the year ended December 31, 2009. This increase was mostly due to higher borrowing costs associated with Decca’s revolving bank credit and factoring agreements (see Note 6).

Gain on debt extinguishment for the year ended December 31, 2010 was $439,000 compared to zero for the year ended December 31, 2009. This increase was due to the forgiveness of a portion of the principal and all of the accrued interest on unsecured notes payable to certain unrelated parties in March 2010 (see Note 6).

Gain on oil and gas derivatives for the year ended December 31, 2010 was $51,000 versus a loss of $184,000 for the year ended December 31, 2009. The current year amount was due to an unrealized gain on the change in fair value of CYMRI’s outstanding oil and gas derivative contracts (see Note 5).

Income taxes attributable to continuing operations were a benefit of $139,700 for the year ended December 31, 2010 compared to a benefit of $1,451,000 for the year ended December 31, 2009. This relative change reflects a benefit rate of 39% in the current period on pre-tax net loss from continuing operations in the amount of $357,000.

Income from discontinued operations, net of income taxes, was zero for the year ended December 31, 2010 compared to a net loss of $25,000 for the year ended December 31, 2009. As further described in Note 4, we sold the capital stock of our domestic Energy Services subsidiary, PEI, to Hamilton in March 2008. The 2008 sales gain was subsequently reduced in March 2009 due to payment of an indemnified loss in the amount of $39,000 resulting in an after-tax net loss of $25,000 for the year ended December 31, 2009.

Liquidity and Capital Resources

Operating activities. Net cash used in operating activities from continuing operations for the year ended December 31, 2010 was $393,000 compared to net cash used of $1,505,000 for the year ended December 31, 2009. This net increase in operating cash flows reflected relative improvements in the levels of cash generated by both of the Company’s operating segments. Net cash used in operating activities from discontinued operations was zero for the year ended December 31, 2010 compared to $25,000 for the year ended December 31, 2009.

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Investing activities. Net cash provided by investing activities for the year ended December 31, 2010 was $1,474,000 compared to $1,318,000 for the year ended December 31, 2009. The primary sources of net cash provided by investing activities in both years were the conversions of previously restricted cash to unrestricted cash subsequent to the March 2008 sale of PEI. Such conversions consisted of a two-year escrow account expiring in 2010 in the amount of $1.6 million and a one-year tax reserve account expiring in 2009 in the amount of $1.5 million (see Note 4). Offsetting these conversions were capital expenditures for property and equipment in the amounts of $140,000 and $172,000 for the years ended December 31, 2010 and 2009, respectively.

Financing activities. Net cash used in financing activities for the year ended December 31, 2010 was $1,082,000 compared to net cash provided by financing activities of $151,000 in the year ended December 31, 2009. This relative decrease in financing cash flows was primarily due to the payment of unsecured notes payable to certain related and unrelated parties in March 2010 (see Note 6).

Following the sale of PEI in March 2008, we have remaining long term debt obligations to banks and other lenders (see Note 6). A substantial portion of our long term debt is in the form of a bank credit facility secured by CYMRI’s producing oil and gas properties. Borrowings under the bank credit agreement amounted to $2,951,000 as of December 31, 2010 and are subject to a borrowing base, which is periodically redetermined, based on oil and gas reserves. The bank credit agreement does not require monthly principal payments so long as outstanding borrowings are less than a declining borrowing base. As of December 31, 2010, the borrowing base stood at $2,951,000, with a scheduled maturity date in April 2011, however, the bank has informally agreed to extend the maturity on a month-to-month basis provided CYMRI makes monthly payments of $25,000 principal plus accrued interest during the extension period. The Company is currently seeking commitments from other financial institutions for a new credit facility to replace the maturing credit agreement.

The CYMRI bank credit agreement requires the maintenance of certain financial covenants regarding interest coverage level, total debt level, and the level of administrative expenses. Due primarily to operational circumstances occurring in early 2010, CYMRI did not meet these financial covenants under the credit agreement as of December 31, 2010. The bank is aware of these covenant violations, however, it has not requested, nor does the Company expect it to request, accelerated payment of this debt, which is classified in our current liabilities, as a result of both the covenant violations and the scheduled maturity.

As of December 31, 2010, we also had outstanding institutional borrowings of $1,807,000 under a factoring facility, which is secured by accounts receivable of Decca, our Canadian Energy Services subsidiary (see Note 6). This factoring agreement with a Canadian factoring company became effective in October 2010 and provides for a revolving borrowing base of 75% of qualifying accounts receivable up to $4,000,000 (Cdn) at an annual interest rate of 18.25%, compounded daily, for a minimum of 15 days. The factoring agreement includes customary restrictive covenants on Decca’s operations but does not include any financial covenants. The factoring agreement replaced a revolving bank credit agreement which expired in September 2010.

We also have other debt amounts outstanding to the sellers of acquired businesses and to stockholders as more fully described in Note 6 and reflected in the table below (however, we have no off Balance Sheet arrangements). The following table sets forth the contractual obligations under our long-term debt and operating lease agreements as of December 31, 2010 (in thousands):

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			Payments Due By Period
	Total		2011			2012-2013		2014-2015	After 2015

Long-term debt	$	5,954	$	5,617	$	337	$	-	$	-
Interest on long-term debt		498		474		24		-		-
Operating leases for office space		306		197		109		-		-

Total	$	6,758	$	6,288	$	470	$	-	$	-

With the completion of our sale of PEI in March 2008, our primary ongoing capital expenditures are in the Exploration & Production segment, which can be highly capital intensive. In this business, expenditures for CYMRI’s drilling and equipping of oil and gas wells are typically required to maintain or increase existing production levels. We normally attempt to finance CYMRI’s capital expenditure requirements through a combination of cash flow from operations and secured bank borrowings and we expect that these sources will be sufficient to meet our capital expenditures. We presently have relatively low capital expenditure requirements relating to CYMRI’s oil and gas properties as evidenced by a total of only $135,000 being spent in the year ended December 31, 2010. While we expect additional amounts of capital expenditures in calendar year 2011, we do not expect such amounts to be significant and we believe that such amounts, as well as any short term operating losses, can be financed under our bank credit agreements through a combination of a borrowing base increase and/or reduced monthly principal payments.

Going Concern

The accompanying consolidated financial statements have been prepared on a going concern basis, which contemplates the realization of assets and satisfaction of liabilities in the normal course of business. The Company has reported substantial losses from continuing operations in the last two years and has a net working capital deficit in the amount of $5,802,000 and a stockholders’ equity deficit of $290,000 at December 31, 2010. These factors, among others, have led our independent registered public accounting firm to conclude that the Company may be unable to continue as a going concern for a reasonable period of time. The consolidated financial statements do not contain any adjustments to reflect the possible future effects on the classification of assets or the amounts and classification of liabilities that may result should the Company be unable to continue as a going concern.

Critical Accounting Policies and Estimates

Our current business operations are in the Canadian Energy Services and Exploration & Production segments. Shown below are the critical accounting policies pertaining to those businesses.

Recognition of Revenues and Costs of Services

In our Canadian Energy Services business, revenues consist of daily charges billed to customers for the services of consultants assigned to worksites. Gross billings are rendered periodically and are recognized at the time services are provided to customers. Direct costs of services include compensation paid to worksite consultants, any related employment taxes, benefits and workers' compensation insurance. Costs of services are recognized when incurred based on days or hours worked by worksite employees or consultants.

ASC 605, "Reporting Revenues Gross as a Principal Versus Net as an Agent", establishes criteria for recognizing revenues on a gross or net basis. The Company is the primary obligor in its transactions, has responsibility for fulfillment, including the acceptability of services ordered and purchased by customers. In addition, the Company has all credit risk, retains substantially all risk and rewards of the services rendered, has sole discretion in staffing engagements and setting the billing rates of its consultants. Accordingly, the Company records all transactions at the gross revenue amount billed, consistent with the provisions of ASC 605.

- 12 -

Allowance for Doubtful Accounts

In our Canadian Energy Services business, the determination of the collectability of amounts due from our customers requires us to use estimates and make judgments regarding future events and trends, including monitoring our customer payment history and current credit worthiness to determine that collectability is reasonably assured, as well as consideration of the overall business climate in which our customers operate. Inherently, those uncertainties require us to make judgments and estimates regarding our customers' ability to pay amounts due us in order to determine the amount of valuation allowances required for doubtful accounts.

Provisions for doubtful accounts are recorded when it becomes evident that the customers will not be able to make the required payments at either contractual due dates or in the future. We believe that our allowance for doubtful accounts is adequate to cover anticipated losses under current conditions, however, uncertainties regarding changes in the financial condition of our customers, either adverse or positive, could impact the amount and timing of any additional provisions for doubtful accounts that may be required.

Full Cost Accounting for Oil and Gas Properties

In our domestic Exploration & Production business, we have adopted the “full cost” method of accounting for oil and gas properties. Under full cost accounting, all costs associated with acquisition, exploration, and development of oil and gas reserves, including directly related overhead costs, are capitalized. Other significant features of full cost accounting are as follows:

All capitalized costs of oil and gas properties, including the estimated future costs to develop proved reserves, are amortized on the unit-of-production method using estimates of proved reserves. Investments in unproved properties and major development projects are not amortized until proved reserves associated with the projects can be determined or until impairment occurs. If the results of an assessment indicate that the properties are impaired, the amount of the impairment is added to the capitalized costs to be amortized.

The capitalized costs are subject to a “ceiling test,” which basically limits such costs to the aggregate of the “estimated present value,” discounted at a 10-percent interest rate, of future net revenues from proved reserves, based on current economic and operating conditions, plus the lower of cost or fair market value of unproved properties.

Sales of properties are accounted for as adjustments of capitalized costs with no gain or loss recognized, unless such adjustments would significantly alter the relationship between capitalized costs and proved reserves of oil and gas, in which case the gain or loss is recognized in income. Abandonments of properties are accounted for as adjustments of capitalized costs with no loss recognized.

In our domestic Exploration & Production business, there is also a significant degree of complexity in our accounting for income taxes due to substantial differences between the financial accounting and tax treatments for certain oil and gas property expenditures.

Item 8. Financial Statements and Supplementary Data.

The required financial statements are included in this report as set forth in the “Index to Consolidated Financial Statements” on page 21.

Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.

None.

- 13 -

Item 9A. Controls and Procedures.

(a) Disclosure Controls and Procedures

Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by an issuer in reports that it files under the Securities Exchange Act of 1934 (the “Act”) is accumulated and communicated to the issuer’s management, including its principal executive and financial officers, to allow for timely decisions regarding required disclosures. As of the end of the period covered by this Annual Report, we carried out an evaluation, under the supervision of our Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures.

Based on this evaluation, our Chief Executive Officer and Chief Financial Officer have concluded that our disclosure controls and procedures as of the end of the period covered by this Annual Report were not effective because of a material weakness in our internal controls over financial reporting, as described below, which we view as an integral part of our disclosure controls and procedures.

(b) Management’s Annual Report on Internal Controls over Financial Reporting

Management is responsible for establishing and maintaining adequate internal controls over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) of the Exchange Act). Because of its inherent limitation, internal controls over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness of such controls to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Management has performed an assessment of the effectiveness of our internal controls over financial reporting as of December 31, 2010. In making this assessment, management elected to use the criteria set forth in Internal Control – Integrated Framework (1992) created by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”) as the chosen internal control framework. Based on our assessment using those criteria, management concluded that our internal controls over financial reporting were not effective, as a result of the material weakness noted below.

The material weakness relates to deficient completeness and cut-off controls with regard to revenues and cost of sales at our Canadian Energy Services subsidiaries, Decca Consulting, Ltd. and Decca Consulting, Inc. (collectively referred to as “Decca”). The situation giving rise to this lack of independent review arose since approximately the end of the second quarter of 2008 as Decca previously employed a highly experienced accountant to review the subsidiary’s monthly financial statements. In order to address this material weakness, management has implemented an interim compensating control in the form of an entity level analytical review by its Chief Financial Officer. To the extent practical in light of Decca’s subsequent financial performance (see Note 3), the Company anticipates the implementation of improved completeness and cut-off controls with regard to revenues and cost of sales at the operating unit level at an appropriate time. It should be noted, however, that the impact of this material weakness on Stratum’s consolidated results of operations is substantially mitigated in view of the fact that Decca’s receivables and payables invoices are recorded in simultaneous batches and Decca has a relatively low gross margin between revenues and cost of sales of approximately 8-9%.

Notwithstanding this material weakness, management believes that the consolidated financial statements included in this report fairly present, in all material respects, our consolidated financial position and results of operations as of and for the years ended December 31, 2010 and 2009.

- 14 -

This Annual Report does not include an attestation report of our independent registered public accounting firm regarding our internal controls over financial reporting. Management’s report was not subject to attestation by our independent registered public accounting firm pursuant to SEC rules that permit the Company to provide only management’s assessment in this Annual Report. Accordingly, management’s assessment has not been audited by MaloneBailey LLP or any other independent registered public accounting firm.

There was no change in our internal controls over financial reporting that occurred during the quarter ended December 31, 2010, that has materially affected, or is reasonably likely to materially affect, our internal controls over financial reporting.

Item 9B. Other Information.

In March 2011, the Company entered into a non-binding letter of intent to sell substantially all of the assets of its Canadian Energy Services subsidiary, Decca, to a private staffing services company. The letter of intent provides for a total sales price in excess of the Company’s net investment in Decca, payable in a combination of cash, collected accounts receivable and the issuance of a promissory note payable. If the sale is completed on those terms, the Company expects to report a pre-tax gain upon the projected closing of the sale in the second quarter of 2011. The Company would expect to apply the majority of the net proceeds of the sale to the repayment of debt and other accrued obligations.

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PART III

Item 10. Directors, Executive Officers, Promoters, Control Persons and Corporate Governance.

Directors and Executive Officers

The following table sets forth our Directors and Executive Officers, their ages and positions held with us as of March 30, 2011:

Name	Age	Position

Larry M. Wright	66	Chairman and Chief Executive Officer
D. Hughes Watler, Jr.	62	Chief Financial Officer

Larry M. Wright was elected to our Board of Directors on May 23, 2006 and was elected Chairman and Chief Executive Officer on May 27, 2008. Mr. Wright founded CYMRI and served as its Chief Executive Officer from its inception in 2002. He previously co-founded and served as Chief Executive Officer of PANACO, Inc., a public oil and gas company, through September 2000. Prior thereto, he served as an executive with various independent oil and gas companies after beginning his career with UNOCAL in 1966.

D. Hughes Watler, Jr. was elected Chief Financial Officer in February 2007 after initially joining the Company as Vice President-Capital Markets in September 2006. He previously served as Senior Vice President & Chief Financial Officer of Goodrich Petroleum Corporation (NYSE: GDP) from March 2003 to May 2006 and as a financial officer of several other public and private energy companies. He was formerly an audit partner with Price Waterhouse LLP.

Corporate Governance

Upon the election of Mr. Wright as Chairman and Chief Executive Officer and the resignation of certain former Board members on May 27, 2008, the Company ceased to have both an independent Audit Committee and an independent Compensation Committee. Accordingly, the duties formerly performed by those committees were assumed by the remaining Board members, consisting of Messrs. Wright and Richard A. Piske, III, who resigned from the Board on November 16, 2009, leaving Mr. Wright as the sole member of the Board of Directors (however, Mr. Wright does not qualify as an audit committee “financial expert”).

The Board of Directors and management strive to perform and fulfill their respective duties and obligations in a responsible and ethical manner. The Company has not formally adopted a code of ethics, however, it will consider the adoption of a code of ethics at a future date as growth and other circumstances should dictate. At the present time, we are a small company with less than 10 employees and our management is in close contact with the daily activities of all employees. Accordingly, we do not believe that it would represent a cost effective use of our limited financial resources to incur the legal fees and other expenses that would be required to implement a formal code of ethics pursuant to Item 406 of Regulation S-K.

- 16 -

Section 16(a) Beneficial Ownership Reporting Compliance

Under the Exchange Act, our directors, our executive officers, and any persons holding more than 10% of our Common Stock are required to report their ownership of the Common Stock and any changes in that ownership to the Commission. Specific due dates for these reports have been established and we are required to report any failure to file by these dates during the year fiscal ended December 31, 2010. The Company is not aware of any such persons who have not filed timely reports required by Section 16(a) of the Exchange Act for the year ended December 31, 2010.

Item 11. Executive Compensation

The following table summarizes certain information with respect to the compensation earned by the Company’s executive officers for services rendered in all capacities during the years indicated.

Summary Compensation Table

								Nonequity	Nonqual.
	Fiscal	Annual Compensation			Stock	Option		Incentive	Deferred	All Other		Total
Name & Principal Position	Year	Salary		Bonus	Awards	Awards		Comp.	Comp.	Comp.		Comp.

Larry M. Wright	2010	$277,500		$ -	$ -	$ -		$ -	$ -	$ -		$277,500
Chairman & CEO	2009	$272,500		$ 3,750	$ -	$ -		$ -	$ -	$ -		$276,250

D. Hughes Watler, Jr.	2010	$ 92,500	(1)	$ -	$ -	$ 11,525	(2)	$ -	$ -	$ 2,250	(3)	$106,275
Chief Financial Officer	2009	$158,400	(1)	$ -	$ -	$ 16,425	(2)	$ -	$ -	$ -		$174,825

_______________

(1)

For the two year period ended December 31, 2010 Mr. Watler became a Company employee effective February 1, 2010. Previously, he had received semi-monthly compensation as an independent consultant, with no Company paid benefits, since his employee status ended following the sale of PEI in March 2008.

(2)

Stock options granted to Mr. Watler in 2006 were approved by the Compensation Committee of the Board of Directors, at an exercise price of $21.00 per share, with a three year vesting period. The amounts shown above represent the compensation expense recognized for financial reporting purposes in the respective years in accordance with ASC 718 (for a discussion of valuation assumptions, see Note 8 to the Consolidated Financial Statements).

(3)

Effective January 1, 2010, the Company offered participation in a company sponsored 401(k) Plan to its employees. This amount represents the company contributions to the 401(k) Plan on behalf of Mr. Watler in the year ended December 31, 2010 (Mr. Wright did not participate).

- 17 -

Outstanding Equity Awards at 2010 Fiscal Year-End

The following table sets forth all outstanding equity option awards held by our named executive officers as of December 31, 2010 (there were no outstanding equity stock awards).

	Option Awards
Name	Number of Securities Underlying Unexercised Options Exercisable (#)	Number of Securities Underlying Unexercised Options Unexercisable (#)	Option Exercise Price ($)	Option Expiration Date

D. Hughes Watler, Jr.	5,000	-	$ 21.00	September 26, 2011

Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.

The following table sets forth information as to the shares of Common Stock beneficially owned as of March 30, 2011 by (i) each person known to us to be the beneficial owner of more than 5% of our Common Stock; (ii) each Director; (iii) each Executive Officer; and (iv) all of our Directors and Executive Officers as a group. Unless otherwise indicated in the footnotes following the table, the persons as to whom the information is given had sole voting and investment power over the shares of Common Stock shown as beneficially owned by them.

	Beneficial Ownership
Directors and Executive Officers	Amount		Percent

Larry M. Wright (1)		1,433,614		54.1
D. Hughes Watler, Jr. (2)		7,000		*
Directors and Executive Officers as a Group (3)		1,440,614		54.1

Other 5% Beneficial Owners

Clarence J. Downs (4)		350,027		13.2
Larry M. Wright, II (5)		251,400		9.5

__________________

*	Less than 1%

(1)	Consists solely of 1,433,614 shares of Common Stock held by Mr. Wright on his own behalf (his previously vested warrants to purchase a total of 7,143 shares of Common Stock expired in May 2010).

(2)	Includes the following securities: (a) 2,000 shares of Common Stock held by Mr. Watler on his own behalf; and (b) currently vested options to purchase a total of 5,000 shares of Common Stock.

(3)	Includes the following securities: (a) 1,435,614 shares of Common Stock held by Directors and Officers on their own behalf; and (b) currently vested warrants and options held by Directors and Officers to purchase a total of 5,000 shares of Common Stock.

(4)

Includes the following securities: (a) 348,534 shares of Common Stock held by Mr. Downs on his own behalf; and (b) 1,493 shares of Common Stock owned of record by Christopher Downs, the minor son of Mr. Downs. Mr. Downs served as President & Chief Executive Officer until May 23, 2006, at which time he resigned from those positions. He subsequently resigned as a Director of the Company. The address of Mr. Downs is 8825 Gypsy Drive NE, Albuquerque, NM 87122.

(5)

Includes 251,400 shares of Common Stock held by Mr. Wright, II on his own behalf. Larry M. Wright, II is the adult son of Larry M. Wright and has been employed in a management position by the Company’s wholly-owned subsidiary, CYMRI, L.L.C., since June 2008. The address of Mr. Wright, II is Three Riverway, Suite 1590, Houston, Texas 77056.

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Item 13. Certain Relationships and Related Transactions, and Director Independence.

In the year ended December 31, 2010, the Company partially repaid stockholder notes and advances from a company owned by Larry M. Wright in the net amount of $235,000. As of December 31, 2010, the outstanding balance of such advances owed to the company owned by Mr. Wright was $530,000. Such unsecured advances accrue interest at the rate 10% per annum (see Note 10 to the Consolidated Financial Statements). In addition, the Company has granted a second lien on its oil and gas properties to a former stockholder in the amount of approximately $900,000.

Our sole current director, Larry M. Wright, is not considered to be an “independent” director as that term is defined by The Nasdaq Stock Market.

Item 14: Principal Accounting Fees and Services.

In June 2008, the Board of Directors approved the appointment of MaloneBailey LLP to serve as our independent registered public accounting firm. The following table presents fees for professional audit services rendered by MaloneBailey LLP for the years ended December 31, 2010 and 2009 in their audits of our annual financial statements.

	2010		2009

Audit Fees	$	112,000	$	102,680
Audit-related Fees		-		-
Tax Fees		-		-
Other Fees		-		-
	$	112,000	$	102,680

PART IV

Item 15. Exhibits, Financial Statement Schedules.

The following Exhibits are required to be filed pursuant to Item 601 of Regulation S-K:

EXHIBIT NO.	DESCRIPTION

3.1	Articles of Incorporation of Tradestar Services, Inc. (incorporated by reference to Exhibit 3.1 of the Company’s Registration Statement on Form SB-2 filed July 30, 2004)
3.2	Bylaws of the Company (incorporated by reference to Exhibit 3.2 of the Company’s Registration Statement on Form SB-2 filed July 30, 2004)
3.3	Certificate of Amendment to Articles of Incorporation of Tradestar Services, Inc. (incorporated by reference to Exhibit 3.3 of the Company’s Annual Report for the year ended December 31, 2005)
3.4	Certificate of Amendment to Articles of Incorporation of Tradestar Services, Inc. (incorporated by reference to Exhibit 3.1 of the Company’s Current Report on Form 8-K filed March 8,2007)
10.1	Letter Agreement, dated February 28, 2007, by and among Tradestar Services, Inc., 383210 Alberta Ltd., Dave Hunter Resources Inc., Barry Ahearn and Dave Hunter(a)
10.2	Amended and Restated Stock Purchase Agreement, dated March 2, 2007, by and among Tradestar Services, Inc., 1297181 Alberta Ltd., 383210 Alberta Ltd., Dave Hunter Resources Inc., Barry Ahearn and Dave Hunter(a)

- 19 -

EXHIBIT NO.	DESCRIPTION

10.3	Registration Rights Agreement, dated March 2, 2007, by and among Tradestar Services, Inc., 383210 Alberta Ltd. and Dave Hunter Resources Inc.(a)
10.4	Pledge and Security Agreement, dated March 2, 2007, by and among Tradestar Services, Inc., 383210 Alberta Ltd. and Dave Hunter Resources Inc.(a)
10.5.1	Decca Promissory Note No. 1, dated March 2, 2007, made by Tradestar Services, Inc. in favor of 383210 Alberta Ltd. in the original principal amount of Cdn $725,000(a)
10.5.2	Decca Promissory Note No. 2, dated March 2, 2007, made by Tradestar Services, Inc. in favor Dave Hunter Resources Inc. in original principal amount Cdn $725,000(a)
10.6.1	Warrant, dated March 2, 2007, to purchase 100,000 shares of common stock of Tradestar Services, Inc. issued to 383210 Alberta Ltd.(a)
10.6.2	Warrant, dated March 2, 2007, to purchase 100,000 shares of common stock of Tradestar Services, Inc. issued to Dave Hunter Resources Inc.(a)
10.7	Second Amended and Restated Credit Agreement, dated August 5, 2008, among CYMRI, L.L.C. and Triumph Energy, Inc. (as Borrowers) and Texas Capital Bank, N.A. (as Lender) for a Reducing Revolving Line of Credit of up to $25,000,000 (b)
10.8	Guaranty Agreement, dated August 5, 2008, executed by Stratum Holdings, Inc. (Guarantor) for benefit of Texas Capital Bank, N.A (as Lender) (b)
10.9	Promissory Note, dated August 5, 2008, issued by CYMRI, L.L.C. and Triumph Energy, Inc. (as Makers) to Texas Capital Bank, N.A. (as Payee) in amount of $25,000,000 (b)
10.10	Security Agreement, dated August 5, 2008, among CYMRI, L.L.C. and Triumph Energy, Inc. (as Debtors) and Texas Capital Bank, N.A. (as Secured Party) (b)
10.11	First Amendment to Second Amended and Restated Credit Agreement, dated May 28, 2009, among CYMRI, L.L.C. and Triumph Energy, Inc. (as Borrowers) and Texas Capital Bank, N.A. (as Lender) for a Reducing Revolving Line of Credit of up to $25,000,000 (c)
10.12	Second Amendment to Second Amended and Restated Credit Agreement, dated November 16, 2009, among CYMRI, L.L.C. and Triumph Energy, Inc. (as Borrowers) and Texas Capital Bank, N.A. (as Lender) for a Reducing Revolving Line of Credit of up to $25,000,000 (d)
10.13	Exhibits I through VI to Second Amended and Restated Credit Agreement, dated August 5, 2008, among CYMRI, L.L.C. and Triumph Energy, Inc. (as Borrowers) and Texas Capital Bank, N.A. (as Lender) for a Reducing Revolving Line of Credit of up to $25,000,000 (e)
10.14	Factoring Agreement, dated September 27, 2010, among Century Services L.P., Decca Consulting, Ltd. and Decca Consulting, Inc. (f)
21.1	Subsidiaries of the Registrant CYMRI, L.L.C. (Nevada) Triumph Energy, Inc. (Louisiana) Decca Consulting, Ltd. (Alberta) Decca Consulting, Inc. (Nevada) Stratum Construction Services, Inc. (New Mexico)
31.1	Certification of Chief Executive Officer pursuant to Rule 13a-14(a)/15(d)-14(a)*
31.2	Certification of Chief Financial Officer pursuant to Rule 13a-14(a)/15(d)-14(a)*
32.1	Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002*
32.2	Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002*

___________________

(a) Incorporated by reference to the Exhibits to the Company’s Current Report on Form 8-K filed March 8, 2007.

(b) Incorporated by reference to the Exhibits to the Company’s Quarterly Report on Form 10-Q filed August 13, 2008.

(d) Incorporated by reference to the Exhibits to the Company’s Annual Report on Form 10-K filed April 15, 2010.

(e) Incorporated by reference to the Exhibits to the Company’s Quarterly Report on Form 10-Q filed August 11, 2010.

(f) Incorporated by reference to the Exhibits to the Company’s Quarterly Report on Form 10-Q filed November 8, 2010.

* Filed herewith.

- 20 -

STRATUM HOLDINGS, INC.

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

	Page (s)



Report of Independent Registered Public Accounting Firm	22

Consolidated Balance Sheets as of December 31, 2010 and 2009	23

Consolidated Statements of Operations for the years ended December 31, 2010 and 2009	24

Consolidated Statements of Stockholders' Equity (Deficit) for the years ended December 31, 2010 and 2009	25

Consolidated Statements of Cash Flows for the years ended December 31, 2010 and 2009	26

Notes to Consolidated Financial Statements	27-42

- 21 -

Report of Independent Registered Public Accounting Firm

To the Board of Directors

Stratum Holdings, Inc.

Houston, Texas

We have audited the accompanying consolidated balance sheets of Stratum Holdings, Inc. (the “Company”) as of December 31, 2010 and 2009 and the related consolidated statements of operations, stockholders' deficit, and cash flows for the years then ended. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with 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. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion. 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 consolidated financial position of Stratum Holdings, Inc. at December 31, 2010 and 2009 and the consolidated results of their operations and their cash flows for the years then ended, in conformity with accounting principles generally accepted in the United States of America.

The accompanying financial statements have been prepared assuming that the Company will continue as a going concern. As discussed in Note 2, the Company has losses from operations and has a working capital deficit. These factors raise substantial doubt about its ability to continue as a going concern. Management’s plans in regard to these matters are also described in Note 2. The financial statements do not include any adjustments that might result from the outcome of this uncertainty.

/S/ MaloneBailey LLP

Houston, Texas

March 30, 2011

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STRATUM HOLDINGS, INC.

Consolidated Balance Sheets

		December 31,
		2010			2009
Assets
Current assets:
Cash and cash equivalents		$	142,236		$	142,703
Restricted cash			-			1,613,637
Accounts receivable			4,532,676			2,948,159
Prepaid expenses and other			148,010			132,325
	Total current assets		4,822,922			4,836,824

Property and equipment:
Oil and gas properties, evaluated (full cost method)			14,560,532			14,425,950
Other property and equipment			149,676			144,625
			14,710,208			14,570,575
Less: Accumulated depreciation, depletion & amortization			(8,615,840	)		(8,017,822	)
	Net property and equipment		6,094,368			6,552,753

Other assets:
Goodwill			1,536,313			1,536,313
Other assets			111,139			76,021
	Total other assets		1,647,452			1,612,334

	Total assets	$	12,564,742		$	13,001,911
Liabilities and Stockholders’ Deficit
Current liabilities:
Current portion of long-term debt - stockholders		$	730,709		$	1,682,317
Current portion of long-term debt - others			4,885,961			5,226,861
Accounts payable			3,723,754			2,436,846
Accrued liabilities			1,246,232			1,518,698
Fair value of oil and gas derivatives			37,835			88,990
	Total current liabilities		10,624,491			10,953,712

Long-term debt, net of current portion			337,378			408,179
Deferred income taxes			1,559,500			1,513,847
Asset retirement obligations			333,670			305,370
	Total liabilities		12,855,039			13,181,108

Stockholders’ deficit:
Preferred stock, $.01 par value per share, 1,000,000 shares authorized, None issued			-			-
Common stock, $.01 par value per share, 5,000,000 shares authorized,
	2,655,738 shares issued and outstanding		26,557			26,557
Additional paid in capital			12,894,490			12,808,867
Accumulated deficit			(13,001,655	)		(12,783,790	)
Accumulated foreign currency translation adjustment			(209,689	)		(230,831	)
	Total stockholders’ deficit		(290,297	)		(179,197	)

	Total liabilities and stockholders’ deficit	$	12,564,742		$	13,001,911

See Accompanying Notes to Consolidated Financial Statements.

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STRATUM HOLDINGS, INC.

Consolidated Statements of Operations

		Year Ended December 31,
		2010			2009
Revenues:
Energy services		$	20,058,038		$	14,767,683
Oil and gas sales			2,625,586			2,612,954
Other			57,193			73,560
			22,740,817			17,454,197
Expenses:
Energy services			18,470,895			13,491,023
Lease operating expense			1,509,274			1,803,848
Depreciation, depletion & amortization			528,298			1,120,000
Impairment expense:
	Acquisition goodwill		-			1,900,000
	Oil and gas properties		-			907,000
Workover expense			475,356			425,033
Selling, general and administrative			1,814,446			2,075,584
			22,798,269			21,722,488

Operating loss			(57,452	)		(4,268,291	)

Other expenses:
Interest expense			(790,235	)		(764,221	)
Gain on debt extinguishment			438,967			-
Gain (loss) on oil and gas derivatives			51,155			(183,850	)

Loss from continuing operations before income taxes			(357,565	)		(5,216,362	)
Benefit for income taxes			139,700			1,450,856
Net loss from continuing operations			(217,865	)		(3,765,506	)
Discontinued operations, net of tax			-			(25,419	)
	Net loss	$	(217,865	)	$	(3,790,925	)

Net loss per share, basic and diluted
Net loss from continuing operations		$	(0.08	)	$	(1.42	)
Discontinued operations			-			(0.01	)
	Net loss	$	(0.08	)	$	(1.43	)

Weighted average shares outstanding, basic and diluted			2,655,738			2,655,738

See Accompanying Notes to Consolidated Financial Statements.

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STRATUM HOLDINGS, INC.

Consolidated Statements of Stockholders' Equity (Deficit)

For the Years Ended December 31, 2010 and 2009

										Accumulated
					Additional					Foreign			Total
	Common Stock				Paid-in		Accumulated			Currency			Stockholders'
	Shares		Amount		Capital		Deficit			Translation			Equity (Deficit)

Balance at January 1, 2009		2,655,643	$	26,556	$	12,758,510	$	(8,992,865	)	$	(157,715	)	$	3,634,486

Stock Based Compensation		-		-		50,357		-			-			50,357

Net Loss		-		-		-		(3,790,925	)		-			(3,790,925	)

Foreign Currency Translation		-		-		-		-			(73,116	)		(73,116	)

Reverse Split Fractional Shares		95		1		-		-			-			1

Balance at December 31, 2009		2,655,738		26,557		12,808,867		(12,783,790	)		(230,831	)		(179,197	)

Stock Based Compensation		-		-		11,525		-			-			11,525

Stockholder Debt Forgiveness		-		-		74,098		-			-			74,098

Net Loss		-		-		-		(217,865	)		-			(217,865	)

Foreign Currency Translation		-		-		-		-			21,142			21,142

Balance at December 31, 2010		2,655,738	$	26,557	$	12,894,490	$	(13,001,655	)	$	(209,689	)	$	(290,297	)

See Accompanying Notes to Consolidated Financial Statements.

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STRATUM HOLDINGS, INC.

Consolidated Statements of Cash Flows



	Year Ended December 31,
	2010			2009
Cash flows from operating activities:
Net loss from continuing operations	$	(217,865	)	$	(3,765,506	)
Adjustments to reconcile net loss from continuing
operations to cash provided by (used in) operations:
Depreciation, depletion & amortization		528,298			1,120,000
Impairment expense:
Acquisition goodwill		-			1,900,000
Oil and gas properties		-			907,000
Benefit for income taxes		(139,700	)		(1,450,856	)
Stock based compensation		11,525			50,357
Gain on debt extinguishment		(438,967	)		-
Unrealized (gain) loss on oil and gas derivatives		(51,155	)		88,990
Changes in current assets and liabilities		(147,664	)		(396,481	)
Other changes, net		62,903			41,802
Net cash flows used in continuing operations		(392,625	)		(1,504,694	)
Net cash flows from discontinued operations		-			(25,419	)
Total cash flows from operating activities		(392,625	)		(1,530,113	)

Cash flows from investing activities:
Decrease in restricted cash		1,613,637			1,490,063
Purchase of property and equipment		(139,633	)		(171,920	)
Net cash flows from investing activities		1,474,004			1,318,143

Cash flows from financing activities:
Proceeds from long term debt		1,920,581			696,333
Payments of long term debt		(2,541,573	)		(284,860	)
Net payments of stockholder advances		(460,854	)		(260,000	)
Net cash flows from financing activities		(1,081,846	)		151,473

Net decrease in cash and cash equivalents		(467	)		(60,497	)
Cash and equivalents at beginning of period		142,703			203,200

Cash and equivalents at end of period	$	142,236		$	142,703

Supplemental cash flow data:
Cash paid for interest	$	558,861		$	524,003
Cash paid for income taxes		-			273,682

Supplemental investing activity:
Non-cash additions to asset retirement obligations	$	-		$	113,000
Stockholder debt forgiveness		74,098			-

See Accompanying Notes to Consolidated Financial Statements.

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STRATUM HOLDINGS, INC.

Notes to Consolidated Financial Statements

December 31, 2010

(1) Business and Summary of Significant Accounting Policies

Description of Business – Stratum Holdings, Inc. (“we” or the "Company") is a Nevada corporation, which has operations in both the domestic Exploration & Production business and the Canadian Energy Services business. We sold the capital stock of our former domestic Energy Services subsidiary, Petroleum Engineers, Inc. (“PEI”), in March 2008 (see Note 4). As a result of the PEI sale, we exited from the domestic portion of our Energy Services segment leaving us with the Canadian portion of our Energy Services segment as well as our operations in the domestic Exploration & Production segment. The following accounting policies relate to the retained Canadian Energy Services and Exploration & Production segments as continuing operations while the exited domestic Energy Services segment is reported as discontinued operations.

Principles of Consolidation – The consolidated financial statements include Stratum Holdings, Inc. and its wholly-owned subsidiaries. Significant intercompany amounts are eliminated in consolidation. Certain reclassifications have been made to the prior year statements to conform to the current year presentation.

Cash Equivalents – For purposes of the statement of cash flows, the Company considers all highly liquid debt instruments with original maturities of three months or less to be cash equivalents.

Recognition of Energy Services Revenues and Costs – Revenues consist of daily or hourly charges billed to customers for the services of consultants or employees assigned to worksites. Gross billings are rendered semi-monthly or weekly and are recognized at the time services are provided to customers. Direct costs of services include compensation paid to worksite consultants or employees, any related payroll taxes, benefits and workers' compensation insurance. Costs of services are recognized when incurred based on days or hours worked by worksite consultants or employees. Accounting Standards Codification (“ASC”) 605, "Reporting Revenues Gross as a Principal Versus Net as an Agent", establishes criteria for recognizing revenues on a gross or net basis. The Company is the primary obligor in its transactions, has responsibility for fulfillment, including the acceptability of services ordered and purchased by customers. In addition, the Company has all credit risk, retains substantially all risk and rewards of the services rendered, has sole discretion in staffing engagements and setting the billing rates of its consultants or employees. Accordingly, the Company records all transactions at the gross revenue amount billed, consistent with the provisions of ASC 605.

Allowance for Doubtful Accounts – The Company has provided an allowance for uncollectible accounts receivable based on management's evaluation of collectability of outstanding balances. The allowance is based on estimates and actual losses may vary from current estimates. These estimates are reviewed periodically and, as adjustments become necessary, are reported in earnings in the period in which they become known.

Oil and Gas Operations – For its oil and gas operations, the Company follows the sales method for recognizing its revenues and the full cost method in accounting for its costs. Costs associated with acquisition, exploration, and development of oil and gas reserves, including directly related overhead costs, are capitalized. (a) Capitalized costs of oil and gas properties, including the estimated future costs to develop proved reserves, are amortized on the unit-of-production method using estimates of proved reserves. Investments in unproved properties and major development projects are not amortized until proved reserves associated with the projects can be determined or until impairment occurs. If the results of an assessment indicate that the properties are impaired, the amount of the impairment is added to the capitalized costs to be amortized; (b) The capitalized costs are subject to a “ceiling test,” which basically limits such costs to the aggregate of the “estimated present value,” discounted at a 10-percent interest rate, of future net revenues from proved reserves, based on current economic and operating conditions, plus the lower of cost or fair market value of unproved properties; and (c) Sales of proved and unproved properties are accounted for as adjustments of capitalized costs with no gain or loss recognized, unless such adjustments would significantly alter the relationship between capitalized costs and proved reserves of oil and gas, in which case the gain or loss is recognized in income.

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Asset Retirement Obligations and Environmental Costs - The Company records the fair value of legal obligations to retire and remove long-lived assets in the period in which the obligation is incurred (typically when the asset is installed at the production location). When the liability is initially recorded, the cost is capitalized by increasing the carrying amount of the related properties, plant and equipment. Over time the liability is increased for the change in its present value, and the capitalized cost in properties, plant and equipment is depreciated over the useful life of the related asset. Environmental expenditures are expensed or capitalized, depending upon their future economic benefit. Expenditures that relate to an existing condition caused by past operations, and do not have a future economic benefit, are expensed.

Other Property and Equipment – Other property and equipment, primarily office furniture and fixtures, is depreciated on a straight-line basis over their useful lives ranging from three to five years.

Goodwill – Goodwill has been recognized on corporate acquisitions as represented by the excess cost of the acquired entities over amounts assigned to the assets and liabilities of the acquired entities. Goodwill is not amortized and is tested for impairment annually (see Note 3).

Foreign Currency Translation – Assets and liabilities attributable to the Canadian Energy Services operations are translated from Canadian currency to U.S. dollars at the applicable exchange rate on the balance sheet date. Revenues and expenses are translated at average rates of exchange prevailing during the year. Unrealized foreign currency translation adjustments are reflected as a component of equity.

Stock-Based Compensation – The Company follows ASC 718, “Compensation – Stock Compensation,” requiring that compensation expense related to share-based payment transactions with employees be recognized in the financial statements (see Note 8).

Income Taxes – Income taxes are accounted for under the asset and liability method (see Note 9). Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases and operating loss and tax credit carryforwards. Deferred tax assets and liabilities are measured using statutory tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities from a change in tax rates is recognized in income in the period that includes the effective date of the change.

We follow ASC 740, “Income Taxes.” ASC 740 creates a single model to address accounting for the uncertainty in income tax positions and prescribes a minimum recognition threshold a tax position must meet before recognition in the financial statements. We apply significant judgment in evaluating our tax positions and estimating our provision for income taxes. The actual outcome of these future tax consequences could differ significantly from these estimates, which could impact our financial position, results of operations and cash flows. The evaluation of a tax position in accordance with ASC 740 is a two-step process. The first step is a recognition process to determine whether it is more likely than not that a tax position will be sustained upon examination, including resolution of any related appeals or litigation processes, based on the technical merits of the position. The second step is a measurement process whereby a tax position that meets the more likely than not recognition threshold is calculated to determine the amount of benefit/expense to recognize in the financial statements. The tax position is measured at the largest amount of benefit/expense that is more likely than not of being realized upon ultimate settlement. No liability for unrecognized tax benefits was recorded as of December 31, 2010 or 2009.

Net Income (Loss) Per Share – Basic income (loss) per common share is computed by dividing the net income or loss by the weighted average number of shares of Common Stock outstanding during the period. Diluted income per common share is computed by considering dilutive common share equivalents under the Treasury Stock method. For the years ended December 31, 2010 and 2009, the basic and diluted average outstanding shares are the same because inclusion of common share equivalents would be anti-dilutive.

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Reverse Stock Split – On December 17, 2009, the Company completed a Board of Directors approved 1-for-10 reverse stock split. Accordingly, all Common Stock share and per share amounts in the consolidated financial statements have been retroactively adjusted to reflect the reverse stock split.

Use of Estimates – Management has made a number of estimates and assumptions in preparing these financial statements in conformity with accounting principles generally accepted in the United States of America. Actual results could differ from those estimates.

Recently Issued Accounting Pronouncements – In April 2010, the Financial Accounting Standards Board (“FASB”) issued ASU 2010-14, “Accounting for Extractive Activities – Oil and Gas.” This update amends ASC 932-10-S99-1 to conform to the SEC’s recently issued final rules regarding amendments to current oil and gas reporting requirements. The Company’s adoption of ASU 2010-14 has had no impact on its financial position, results of operations or cash flows.

In July 2009, the FASB issued new guidance relating to the “FASB Accounting Standards Codification” at ASC 105, as the single source of authoritative nongovernmental U.S. generally accepted accounting principles (GAAP). The Codification is effective for interim and annual periods ending after September 15, 2009. All existing accounting standards are superseded as described in ASC 105. All other accounting literature not included in the Codification is nonauthoritative. The Company’s adoption of ASC 105 has had no impact on its financial position, results of operations or cash flows.

Effective for the quarter ended June 30, 2009, the Company implemented ASC 855, “Subsequent Events”. This standard establishes general standards of accounting for and disclosure of events that occur after the balance sheet date but before financial statements are issued. The Company evaluated all events or transactions that occurred after December 31, 2010 up through March 30, 2011, the date the Company issued these consolidated financial statements. The Company had no subsequent events during this period.

Changes in Accounting Principles – Effective January 1, 2010, the Company adopted revised oil and gas reserve estimation standards. These standards allow the use of reliable technology in determining estimates of proved reserve quantities and require the use of a 12-month average price to estimate proved reserves (see Note 13). The Company’s adoption of the revised reserve estimation standards did not have a material impact on its depreciation, depletion and amortization expense.

(2) Going Concern

The working capital deficit noted above reflects outstanding borrowings under a bank credit agreement, which will expire within one year (see Note 6). The Company is currently seeking to extend and/or restructure this credit agreement on a satisfactory basis. However, there is no assurance that the Company will be able to repay or refinance its present obligations.

The consolidated financial statements do not contain any adjustments to reflect the possible future effects on the classification of assets or the amounts and classification of liabilities that may result should the Company be unable to continue as a going concern.

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(3) Impairment Adjustments

In March 2009, the Company recognized a non-cash impairment adjustment in the carrying value of the goodwill assigned to its Canadian Energy Services subsidiary, Decca Consulting, Ltd. (“Decca”), in the amount of $1,900,000. This impairment adjustment was based on then current projections of Decca’s discounted future net cash flows. Based on the latest such projections, no further impairment has been recorded since that date through December 31, 2010. The Company did not recognize a tax benefit for this impairment adjustment in the year ended December 31, 2009 because no temporary difference was recognized when the goodwill was initially established upon the acquisition of Decca in March 2007.

In December 2009, the Company recognized a non-cash impairment adjustment in the carrying value of its oil and gas properties in the amount of $907,000. This adjustment reflected a full cost “ceiling test” write-down resulting from the downward revisions of the Company’s proved oil and gas reserves in the fourth quarter of 2009 (see Note 13). There was no such “ceiling test” write-down in the year ended December 31, 2010.

(4) Discontinued Operations

In March 2008, the Company sold the capital stock of its domestic Energy Services subsidiary, Petroleum Engineers, Inc. (“PEI”), to Hamilton Engineering, Inc. (“Hamilton “) for a total sales price of $15.0 million. The Company applied the sales proceeds to the repayment of debt and other accrued obligations including the outstanding indebtedness of PEI under a revolving bank credit agreement and unsecured seller debt and other liabilities. The Company recognized a pre-tax gain from the sale of PEI in the first quarter of 2008 in the amount of $1,358,000, however, this amount was subsequently reduced in the first quarter of 2009 due to payment of an indemnified loss on accounts receivable in the amount of $39,000. This payment was recorded as a, net of tax, loss on discontinued operations of $25,000 in the year ended December 31, 2009.

The Company indemnified Hamilton with respect to certain other pre-sale contingencies of PEI for a two year period. In order to secure such indemnities, Hamilton withheld sales proceeds in a two-year escrow account in the amount of $1.6 million and a one-year tax reserve account in the amount of $1.5 million. The two-year indemnity period expired on March 12, 2010 with no indemnified losses being paid from the escrow account. Accordingly, the Company received the full amount of the escrow account at that time in the amount of $1,614,000, including accrued interest, and applied most of the proceeds to pay unsecured notes payable to certain related and unrelated parties (see Note 6). The escrow account, along with accrued interest thereon, was reflected as restricted cash on the consolidated Balance Sheet as of December 31, 2009.

(5) Commodity Derivatives

Beginning in early 2009, the Company entered into three contiguous commodity derivative contracts with a major energy company covering a portion of a subsidiary’s annual domestic oil production. The first two contracts covering production in the years ended December 31, 2010 and 2009 have since expired or been terminated with the Company reporting a realized loss on the termination of one contract in the year ended December 31, 2009 in the amount of $94,860 (there was no realized gain or loss on the expiration of the other contract). As of December 31, 2010, the third commodity derivative contract was unexpired and remained open. This contract consists of a “costless collar,” with a floor price of $65.00 per barrel and a ceiling price of $105.50 per barrel, covering 1,000 barrels of oil per month for the calendar year 2011.

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The Company applies “mark to market” accounting to open derivative contract in accordance with ASC 815-20, “Accounting for Derivative Instruments and Hedging Activities”. As of December 31, 2010, the fair market value of the Company’s open derivatives contract was a liability of $37,835 (see Note 12). The Company accounts for commodity derivative contracts as non-hedging transactions, as defined in ASC 815-20. Accordingly, changes in the fair value of such derivative contracts are reflected in current earnings in the period of the change. In the years ended December 31, 2010 and 2009, the Company reported an unrealized derivative gain of $51,155 and an unrealized derivative loss of $88,990, respectively.

(6) Long-Term Debt

As of December 31, 2010 and 2009, the Company had the following long-term debt obligations:

	December 31,
	2010			2009
$25,000,000 line of credit with a bank, maturing in April 2011, interest at 1.0% above prime (but not less than 6.0%) payable monthly, secured by first lien on CYMRI, LLC’s oil and gas properties, with a declining borrowing base of $2,951,000 as of December 31, 2010	$	2,951,000		$	3,001,000

Notes payable to individuals and entities, incurred in acquisition of CYMRI, bearing interest at 10%, with principal and accrued interest due at extended maturity in March 2010, unsecured		-			1,125,000

$4,000,000 (Cdn) receivables factoring facility with a factoring company, interest on factored invoices at annual rate of 18.25%, compounded daily, for a minimum of 15 days, secured by accounts receivable of Canadian energy services business		1,806,581			-

$2,500,000 (Cdn) revolving line of credit with a bank, interest at 6.5% above Canadian prime (plus additional bank fees) payable monthly through extended maturity in September 2010, secured by accounts receivable of Canadian energy services business		-			1,389,667

Notes payable to 2 individuals, incurred in acquisition of Decca Consulting, Ltd., bearing interest at 9%, payable in monthly installments of $30,099 (Cdn) through extended maturity in June 2013, unsecured ($114,000 of additional principal added as compensation expense in December 2010)		538,087			618,179

Advances from stockholders, bearing interest at 10%, with principal and accrued interest due in March 2010, unsecured ($530,000 extended since March 2010 - see discussion below)		530,000			1,047,317

Other short term notes for liability insurance and accrued payables, interest rates at 7% to 9%		128,380			136,194

		5,954,048			7,317,357
Current portion of long term debt - stockholders		(730,709	)		(1,682,317	)
Current portion of long term debt - others		(4,885,961	)		(5,226,861	)
	$	337,378		$	408,179

Future maturities of long-term debt as of December 31, 2010 are as follows:

Year ending December 31, 2011	$	5,616,670
Year ending December 31, 2012		235,000
Year ending December 31, 2013		102,378
Year ending December 31, 2014		-
Year ending December 31, 2015		-

	$	5,954,048

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Borrowings under the bank credit agreement secured by the oil and gas properties owned by CYMRI, LLC (“CYMRI”), a subsidiary in the Exploration & Production segment, are subject to a borrowing base, which is periodically redetermined based on oil and gas reserves. The bank credit agreement does not require monthly principal payments so long as outstanding borrowings are less than a declining borrowing base.

As of December 31, 2010, the borrowing base stood at $2,951,000, with a scheduled maturity date in April 2011, however, the bank has informally agreed to extend the maturity on a month-to-month basis provided CYMRI makes monthly payments of $25,000 principal plus accrued interest during the extension period. The bank credit agreement requires maintenance of certain financial covenants with which CYMRI was not in compliance as of December 31, 2010. Due to the covenant violations as well as the scheduled maturity in April 2011, we have reported this debt in our current liabilities at December 31, 2010.

We also have outstanding institutional borrowings under a factoring facility, which is secured by accounts receivable of Decca, our Canadian Energy Services subsidiary. This factoring agreement with a Canadian factoring company became effective in October 2010 and provides for a revolving borrowing base of 75% of qualifying accounts receivable up to $4,000,000 (Cdn) at a daily discount rate of 0.05%, for a minimum of 15 days (an annualized interest rate of approximately 18.25%). The factoring company has recourse against Decca for factored accounts receivable until paid, therefore, Decca accounts for advances from the factoring company as revolving borrowings secured by the factored accounts receivable. As of December 31, 2010, Decca had outstanding factored accounts receivable amounting to $2,378,000 under the factoring agreement. The factoring agreement includes customary restrictive covenants on Decca’s operations but does not include any financial covenants. Either party may terminate the factoring agreement with sixty days advance notice to the other party. The factoring agreement replaced a revolving bank credit agreement which expired in September 2010.

On March 12, 2010, the Company’s unsecured notes payable to certain related and unrelated parties became due and payable in the principal amount of $2,172,000. At that time, the Company reached an agreement with noteholders in the principal amount of $1,407,000 to accept a payment of 80% of the principal balance in full satisfaction of their unsecured notes payable. Accordingly, the Company fully extinguished the debt to these noteholders in March 2010 with principal payments totaling $1,125,000 resulting in a total gain of $551,000 on the forgiven principal and accrued interest. Of this amount, $112,000 was attributable to debt of a current shareholder, therefore, the Company credited the after-tax equivalent of $74,000 to Additional paid in capital and recognized a pre-tax gain in the year ended December 31, 2010 on the remaining portion attributable to unrelated parties in the amount of approximately $439,000.

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Another unsecured noteholder is a company owned by our Chairman and Chief Executive Officer and the Company also reached an agreement with that company in March 2010 to make a net principal payment of $265,000, in exchange for deferring the maturity of the remaining balance of $500,000 to a date to be mutually determined (an additional $30,000 was borrowed on the same terms in May 2010). The Company evaluated the application of ASC 470-50 and ASC 470-60 and concluded that the revised terms constituted a debt modification, rather than a debt extinguishment or a troubled debt restructuring.

(7) Stockholders’ Equity (Deficit)

In the years ended December 31, 2010 and 2009, there were no transactions in the Company’s Common Stock, other than the effect of the reverse stock split in December 2009 (see Note 1). As of December 31, 2010, the Company had outstanding options to purchase a total of 22,500 shares of Common Stock at various exercise prices and expirations (see Note 8) as well as warrants to purchase a total of 20,000 shares of Common Stock at an exercise price of $21.00 per share, expiring in March 2012.

(8) Stock-Based Compensation

The Company has a stock-based compensation plan which was approved by the stockholders in October 2005 and amended in October 2006. Under the plan, as amended, a maximum of 240,000 shares may be awarded to directors and employees in the form of stock options, restricted stock or stock appreciation rights. The exercise price, terms and other conditions applicable to each stock option grant are generally determined by the Board of Directors. The exercise price of stock options is set on the grant date and may not be less than the fair market value of the Company’s Common Stock on that date. Option activity with directors and employees since January 1, 2009 were as follows (including options granted to directors outside of the plan):


	Number			Wtd. Avg.			Wtd. Avg.		Aggregate
	of			Exercise			Remaining		Intrinsic
	Shares			Price			Term (Yrs.)		Value

Outstanding at January 1, 2009		47,500		$	7.60
Option activity		-			-
Outstanding at December 31, 2009		47,500			7.60
Options forfeited		(25,000	)		(2.40	)
Outstanding at December 31, 2010		22,500		$	13.30			0.42	$	-

Exercisable at December 31, 2010		22,500		$	13.30			0.42	$	-

Stock-based compensation expense related to these options in the amounts of $11,525 and $50,357 have been recognized as a current period expense in the accompanying Consolidated Financial Statements for the years ended December 31, 2010 and 2009, respectively. As of December 31, 2010, there was no unrecognized compensation cost remaining to be recognized in future periods. The estimated fair value of the options granted to employees under the plan was calculated using a Black Scholes option pricing model.

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The following schedule reflects the assumptions included in this model as it relates to the valuation of such options: (a) Expected volatility – 95%; (b) Expected risk free interest rate – 6%; (c) Expected dividend yield – zero; (d) Expected option term – 3 to 4 years, calculated pursuant to the terms of ASC 718-10; and (e) Forfeitures – 0%, subject to adjustment for actual experience. Vesting terms of the options are generally three years. The aggregate intrinsic value of employee options granted as of December 31, 2010 was zero as there were no in-the-money options at that date.

(9) Income Taxes

The Company provided the following amounts of income tax (benefit) attributable to continuing operations for the years ended December 31, 2010 and 2009:

	Year ended December 31,
	2010			2009

Current income taxes	$	(147,200	)	$	-
Deferred income taxes		7,500			(1,450,856	)
Total	$	(139,700	)	$	(1,450,856	)

The following table shows components of income tax (benefit) attributable to both continuing operations and discontinued operations in comparison to the U.S. statutory tax rate of 34% for the years ended December 31, 2010 and 2009:

	Year ended December 31,
	2010			2009
Loss from continuing operations:
Tax benefit at U.S. statutory rate	$	(121,572	)	$	(1,465,429	)
Non-deductible items		7,372			14,573
Other		(25,500	)		-
		(139,700	)		(1,450,856	)
Loss from discontinued operations:
Tax benefit at U.S. statutory rate		-			(13,100	)
		-			(13,100	)

Total income tax benefit	$	(139,700	)	$	(1,463,956	)

As of December 31, 2010 and 2009, we have not recognized a tax benefit for certain non-deductible items reflected in continuing operations, the most significant of which were the impairment adjustments in the carrying value of our goodwill arising from the Decca acquisition (see Note 3). There was no tax benefit recognized for these adjustments because no temporary difference was recognized when the goodwill was initially established upon the acquisition of Decca in March 2007.

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The following table indicates the tax effects of temporary differences giving rise to our deferred tax assets and liabilities as of December 31, 2010 and 2009:

	December 31,
	2010			2009
Deferred tax assets:
Operating loss carryforwards	$	222,300		$	277,981
Other, net		72,700			305,222
Gross deferred tax assets		295,000			583,203

Deferred tax liabilities:
Property and equipment		(1,854,500	)		(1,850,663	)
Installment gain on PEI sale		-			(224,900	)
Other, net		-			(21,487	)
Gross deferred tax liabilities		(1,854,500	)		(2,097,050	)

Net deferred tax liabilities	$	(1,559,500	)	$	(1,513,847	)

As of December 31, 2010, we have consolidated U.S. tax operating loss carryforwards of approximately $654,000, which largely expire on December 31, 2020 (subject to certain annual limitations). We have offset the tax effect of our net operating loss carryforwards against our deferred tax liabilities to the extent permitted under the tax accounting rules.

(10) Related Party Transactions

The Company repaid net stockholder notes and advances in the amounts of $461,000 and $260,000 in the years ended December 31, 2010 and 2009, respectively. Stockholder advances, excluding amounts advanced to finance the cash portion of the CYMRI purchase price (see Note 6) are reflected as unsecured long term debt obligations and accrue interest at a rate of 10% per annum. As of December 31, 2010 and 2009, the Company had granted a second lien on its oil and gas properties to a former stockholder in the amount of approximately $900,000.

(11) Commitments and Contingencies

The Company and it subsidiaries have operating leases for office space under which rental expense amounted to $203,000 and $255,000 in the years ended December 31, 2010 and 2009, respectively. As of December 31, 2010, aggregate commitments under the Company’s operating leases were as follows (in thousands):

Year ending December 31, 2011	$	197
Year ending December 31, 2012		109
Year ending December 31, 2013		-
Year ending December 31, 2014		-
Year ending December 31, 2015		-
	$	306

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From time to time the Company may become involved in litigation in the ordinary course of business. At the present time, other than the Company’s disclosures below, the Company’s management is not aware of any such litigation that could have a material adverse effect on its results of operations, cash flows or financial condition.

A lawsuit was filed in February 2008 against Decca, the Company’s Canadian Energy Services subsidiary, claiming unspecified damages related to work performed by Decca on a well drilled in the U.S. in late 2006, prior to the Company’s acquisition of Decca. The plaintiff and Decca reached a settlement in late 2009 whereby the plaintiff agreed to dismiss its claim against Decca, while continuing to pursue its claim against a co-defendant. In accordance with the settlement agreement, Decca was responsible for the legal fees of its defense counsel, therefore, the Company recorded legal fee expense of $188,200 related to this matter in the year ended December 31, 2009.

Triumph Energy, Inc., a subsidiary in the Exploration & Production segment, and PEI (see Note 4) are joint defendants in several lawsuits involving professional liability and other matters arising in the normal course of business in the State of Louisiana. It is not practical at the present time to determine the amount or likelihood of an unfavorable outcome to the Company’s consolidated financial position or results of operations of any of the these actions against Triumph. The Company believes that Triumph has meritorious defenses in each case and is vigorously defending these matters. The Company has recorded no provision for estimated losses in these cases as of December 31, 2010.

The Company, as a lessee 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 lessee under an oil and gas lease for the cost of pollution clean-up resulting from operations and subject the lessee to liability for pollution damages. The Company maintains insurance coverage, which it believes is customary in the industry, although the Company is not fully insured against all environmental risks. The Company is not aware of any environmental claims existing as of December 31, 2010, which have not been provided for, covered by insurance or otherwise have a material impact on its financial position or results of operations. There can be no assurance, however, that current regulatory requirements will not change, or past noncompliance with environmental laws will not be discovered on the Company’s properties.

(12) Other Required Disclosures

Segment Information – With the sale of PEI in March 2008 (see Note 4), the Company’s remaining operations are in the Canadian Energy Services and domestic Exploration & Production segments. The table below reflects the allocation of certain amounts in the consolidated Income Statement, other than interest expense and various corporate related components (which the Company does not believe are feasible to allocate), and the consolidated Balance Sheet as of and for the year ended December 31, 2010 (in 000’s):

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	Energy			Exploration &
	Services			Production
	(Canada)			(U. S.)			Total

Income Statement Data:
Operating revenues	$	20,058		$	2,626		$	22,684
Other revenues		56			1			57
Total revenues		20,114			2,627			22,741
Depreciation, depletion & amortization		-			(528	)		(528	)
Other allocable operating expenses		(18,471	)		(1,985	)		(20,456	)
Gross profit (loss)	$	1,643		$	114			1,757
General and administrative expenses								(1,814	)
Operating loss								(57	)
Interest expense								(790	)
Gain on debt extinguishment								439
Unrealized gain on oil and gas derivatives								51
Net loss from continuing operations before income taxes							$	(357	)

Balance Sheet Data:
Subsidiary assets	$	4,156		$	6,821		$	10,977
Goodwill		1,536			-			1,536
Segment assets	$	5,692		$	6,821			12,513
Corporate assets								52
Consolidated assets							$	12,565

The table below reflects the allocation of certain Income Statement data between these two reportable segments for the year ended December 31, 2009 (in 000’s):

Income Statement Data:
Operating revenues		$	14,768		$	2,613		$	17,381
Other revenues			59			14			73
	Total revenues		14,827			2,627			17,454
Depreciation, depletion & amortization			-			(1,120	)		(1,120	)
Impairment expense			(1,900	)		(907	)		(2,807	)
Other allocable operating expenses			(13,491	)		(2,229	)		(15,720	)
	Gross profit (loss)	$	(564	)	$	(1,629	)		(2,193	)
General and administrative expenses									(2,075	)
	Operating loss								(4,268	)
Interest expense									(764	)
Realized loss on oil and gas derivatives									(95	)
Unrealized loss on oil and gas derivatives									(89	)
	Net loss from continuing operations before income taxes							$	(5,216	)

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Asset Retirement Obligations – The Company records an asset retirement obligation (ARO) when the total depth of a drilled well is reached and the Company can reasonably estimate the fair value of an obligation to perform site reclamation, dismantle facilities or plug and abandon costs. The Company records the ARO liability on the consolidated balance sheets and capitalizes a portion of the cost in oil and gas properties equal to the estimated future cost to satisfy the abandonment obligation using current prices that are escalated by an assumed inflation factor up to the estimated settlement date and adjusted for the Company’s credit risk. This amount is discounted to present value using an assumed cost of funds for the Company. After recording these amounts, the ARO is accreted to its future estimated value using the same assumed cost of funds. The Company did not abandon any properties in the years ended December 31, 2010 and 2009. Therefore, the only ARO transactions were to add abandonment costs of zero and $113,000, respectively, and accretion expense of $28,000 and $18,000, respectively, in the years ended December 31, 2010 and 2009.

Credit Risk Concentrations – As previously noted, the Company’s remaining operations are in the Canadian Energy Services and domestic Exploration & Production segments. In the Canadian Energy Services segment, the Company extends credit to a variety of customers on an open account basis, periodically assessing their credit worthiness, and requiring various forms of financial collateral where deemed necessary. In the domestic Exploration & Production segment, the Company sells produced oil and gas to large commodity purchasers from whom it does not require collateral. There were no customers of either segment, representing a significant portion of consolidated revenues in the years ended December 31, 2010 and 2009.

The Company maintains its U.S. unrestricted cash accounts in three different federally chartered banking institutions. Its bank accounts in each bank are government insured up to $250,000 and no book balances exceeded that level as of December 31, 2010.

Fair Value of Financial Instruments – ASC 820, “Fair Value Measurements,” establishes a framework for measuring fair value and expands disclosures about fair value measurements. This Statement applies under other accounting pronouncements that require or permit fair value measurements. Disclosures about fair value of financial instruments are based on pertinent information available to management and are not necessarily indicative of the amounts that could be realized on disposition of the financial instruments.

The statement requires disclosure that establishes a framework for measuring fair value and expands disclosure about fair value measurements. It requires fair value measurements be classified and disclosed in one of the following categories: (1) Level 1 - Unadjusted quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities. We consider active markets as those in which transactions for the assets or liabilities occur in sufficient frequency and volume to provide pricing information on an ongoing basis. (2) Level 2 - Quoted prices in markets that are not active or inputs which are observable, either directly or indirectly, for substantially the full term of the asset or liability. This category includes those derivative instruments that we value using observable market data. Substantially all of these inputs are observable in the marketplace throughout the full term of the derivative instrument, can be derived from observable data or supported by observable levels at which transactions are executed in the marketplace. Instruments in this category include non-exchange traded derivatives such as over-the-counter commodity price swaps, investments and interest rate swaps. (3) Level 3 - Measured based on prices or valuation models that require inputs that are both significant to the fair value measurement and less observable from objective sources (i.e. supported by little or no market activity). Our valuation models are primarily industry-standard models that consider various inputs including: (a) quoted forward prices for commodities, (b) time value, (c) volatility factors and (d) current market and contractual prices for the underlying instruments, as well as other relevant information.

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Management has estimated the fair values of cash, accounts receivable, accounts payable and accrued expenses to approximate their respective carrying values reported on these financial statements because of their short maturities. The carrying amounts of notes payable approximates fair value because their interest rates approximate market for items of similar risk. Additionally, ASC 820 requires that we disclose the valuation methodology for our commodity derivatives liability at December 31, 2010 in the amount of $37,835 (see Note 5). Pursuant to ASC 820, we valued this derivative liability based on a “Level 2” input which consisted of a valuation model provided by the counterparty.

(13) Oil and Gas Producing Activities (Unaudited)

Capitalized Costs of Oil and Gas Properties – The Company has owned working interests in oil and gas properties since acquiring CYMRI in May 2006. The table below reflects the capitalized costs of such oil and gas properties as of December 31, 2010 and 2009 (in thousands):

	December 31,
	2010			2009

Proved oil and gas properties	$	14,560		$	14,426
Unproved oil and gas properties		-			-
Gross oil and gas properties		14,560			14,426
Less: Accumulated depreciation, depletion & amortization		(8,480	)		(7,952	)

Net oil and gas properties	$	6,080		$	6,474

Costs Incurred in Oil and Gas Producing Activities – The table below presents the costs incurred in oil and gas producing activities for the years ended December 31, 2010 and 2009 (in thousands):

	December 31,
	2010		2009

Property acquisition	$	-	$	-
Exploration		-		-
Development		135		172

Total costs incurred	$	135	$	172

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Results of Operations for Oil and Gas Producing Activities – The table below presents the results of operations for oil and gas producing activities for the years ended December 31, 2010 and 2009 (in thousands):

	Year ended December 31,
	2010			2009

Revenues	$	2,626		$	2,613
Production costs		(1,985	)		(2,229	)
Depreciation, depletion & amortization		(528	)		(1,120	)
Impairment expense		-			(907	)
Income taxes		(38	)		559

Results of operations	$	75		$	(1,084	)

Oil and Gas Reserves – The following table sets forth summary information with respect to CYMRI’s proved oil and gas reserves, as estimated by the Company, based on consultation with an independent reservoir engineering firm, as of December 31, 2010. The estimates of proved and proved developed reserve quantities and the related measure of discounted future net cash flows are estimates only and do not purport to reflect realizable values or fair market values of the Company’s reserves. The Company emphasizes that reserve estimates are inherently imprecise and that estimates of new discoveries are more imprecise and generally more conservative than those of producing oil and gas properties. Accordingly, these estimates are expected to change as future information becomes available. All of the Company's reserves are located in the United States.

	Oil		Gas		Total		PV10 Value
	(MBbl)		(MMcf)		(MMcfe)		(000's)

Proved developed reserves		473		830		3,668	$	9,572
Proved undeveloped reserves		48		-		288		676
Total proved reserves		521		830		3,956		10,248
Discounted future income taxes								(3,313	)
Standardized measure of discounted
future net cash flows							$	6,935

Proved reserves are estimated reserves of crude oil (including condensate and natural gas liquids) and natural gas that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed reserves are those expected to be recovered through existing wells, equipment, and operating methods.

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The following table sets forth changes in the Company’s proved oil and gas reserves in the years ended December 31, 2010 and 2009 (in thousands):

	Oil			Gas			Total
	(MBbl)			(MMcf)			(MMcfe)

Balance at January 1, 2009		533			1,634			4,832
Revisions of previous estimates		(170	)		(824	)		(1,844	)
Production		(40	)		(91	)		(331	)
Balance at December 31, 2009		323			719			2,657
Revisions of previous estimates		228			184			1,554
Production		(30	)		(73	)		(255	)

Balance at December 31, 2010		521			830			3,956

The standardized measure of discounted future net cash flows is computed by applying estimated prices of oil and gas (at year-end 2010 average monthly prices) to the estimated future production of proved oil and gas reserves, less estimated future expenditures (at year-end 2010 costs) to be incurred in developing and producing the proved reserves, and assuming continuation of existing economic conditions. The estimated future net cash flows are then discounted using a rate of 10-percent per year to reflect the estimated timing of the future net cash flows. The Company does not believe that the standardized measure of discounted future net cash flows is necessarily indicative of the fair value of its oil and gas properties. The following table sets forth the components of the standardized measure of discounted future net cash flows relating to proved oil and gas reserves as of December 31, 2010 and 2009 (in thousands):

	December 31,
	2010			2009

Future net revenues	$	43,367		$	21,519
Future lease operating expenses and production taxes		(21,143	)		(10,731	)
Future development costs		(1,818	)		(1,678	)
Future income taxes		(6,596	)		(1,907	)
Future net cash flows		13,810			7,203
10% annual discount for estimated timing of cash flows		(6,875	)		(3,516	)

Standardized measure of discounted future net cash flows	$	6,935		$	3,687

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The following table sets forth changes in the standardized measure of the Company’s discounted future cash flows (“FCF”) relating to its proved oil and gas reserves in the years ended December 31, 2010 and 2009 (in thousands):

	Year ended December 31,
	2010			2009

Net changes in prices and production costs	$	5,653		$	(1,998	)
Sales and transfers of oil and gas produced		(1,116	)		(809	)
Net change due to revisions in quantity estimates		2,156			(2,513	)
Future development costs		117			(820	)
Net change in income taxes		(2,142	)		746
Changes in production rates, other		(1,789	)		1,854
Accretion of discount		369			657
Changes in standardized measure of discounted FCF		3,248			(2,883	)
Beginning standardized measure of discounted FCF		3,687			6,570

Ending standardized measure of discounted FCF	$	6,935		$	3,687

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SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

	STRATUM HOLDINGS, INC.


	By:	/s/ Larry M. Wright
		Larry M. Wright
		Chairman and Chief Executive Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed by the following persons on behalf of the Registrant in the capacities indicated on March 30, 2011.

Signature		Title

/s/ Larry M. Wright		Chairman and Chief Executive Officer
Larry M. Wright		(Principal Executive Officer)


/s/ D. Hughes Watler, Jr.		Chief Financial Officer
D. Hughes Watler, Jr.		(Principal Financial and Accounting Officer)

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