News and Press Releases

Final Results for the Year Ended 31 December 2008

May 6, 2009

Sefton Resources Inc., the AIM listed oil and gas production company with assets in California and Kansas, announces the company’s final results for the year ended December 31, 2008.

2008 Highlights

Increased capital expenditures
Increased production Increased proved developed reserves
Increased revenue Increased cash flow
Increased profits
Advanced development of additional assets
Engaged new Nominated Advisor and Broker

Chairman’s Statement

2008 was a year of moving our primary asset (Tapia Canyon Oil Field, California) into its initial enhanced recovery stage (cyclic steaming), and advancing other assets (Eureka Canyon Oil Field, California; Anderson County and Leavenworth County Projects, Kansas) towards contributing to the Company’s production base.

As with 2007, Tapia Canyon was our main focus which resulted in improved production, revenue, cash flow, profits and proved developed reserves.

Other assets, primarily Anderson County and Leavenworth County, Kansas, were expanded beyond just mineral leases to include drilling (Anderson County) and acquiring gas gathering and water disposal systems. These systems will provide a connection between the mineral leases (and subsequent wells) and interstate pipelines that will provide a future market for any natural gas production (conventional and CBM gas in both the Anderson and Leavenworth County Projects).

Financials

Our profit from operations of $1,248,000 (2007: $283,000) was up 340% on last year before interest costs of $192,000 (2007: $78,000) from our increased borrowings ($3.437 million up from $0.911 million in 2007, largely to finance the drilling and steaming programme at Tapia), leaving a normalized profit before tax of $1,055,000 (2007: $205,000). Whilst this represents an increase of almost 420% on 2007, it is considerably below our expectations in mid-December, due mainly to a $411,000 expense reclassification relating to the Yule 16 and Hartje #18 wells and to an increased depletion charge of $463,000 (2007: $305,000) which is attributable to additional assets in Kansas and the dramatic drop in the oil price towards the end of the year.

Oil and gas revenue increased to $4,688,000 from $2,978,000 as a result of increased production and oil price for most of the year.

Oil and gas production costs increased to $1,041,000 from $673,000 as a result of more production, more wells and increased costs of oil field services.

General and administration costs increased to $1,775,000 from $1,520,000 as a result of developing the Kansas assets – an investment in our future - which, together with higher interest costs, resulted in an overall improvement in cash flow from operations to $2,255,000 from $1,216,000.

In late December we completed the grant of a cell tower easement for $375,000 which has now all been received together with a contribution of $15,000 towards road maintenance costs. We have for the first time charged a retirement annuity provision of $1,112,000 of which $730,000 relates to our Chief Executive (who is closest to retirement), and the balance to other employees. The greater part of this non-cash charge relates to amounts incurred in respect of prior years service. The directors believe that the relevant employee contracts are necessary to ensure the Company’s continued success.

The CEO has agreed to forego retirement (beyond 2010) and when he elects this retirement provision, he has agreed to take the majority of such in new company shares at a price of the greater of 4 p or at a 10% premium of the trading price when the election is taken.

Net income for the year after exceptional charges from the retirement provision and income related to the cell tower easement was $333,000 (2007: $205,000) with a gain per share of $0.0029 (2007: $0.0018).

Engineering

Total proved reserves at December 31, 2008 decreased to 3,326,084 barrels of oil from 3,953,000 barrels – a result of a dramatic drop in oil price at year end. This reduced the expected economic life of the field to 30 years from 45 years when using the year end oil price (future years will use an average price for the year). A significant increase (regardless of price) was seen in proved developed reserves – 1,354,670 barrels of oil from 463,900 barrels – a direct result of additional wells being drilled and the preliminary results from a pilot cyclic steam program.

Outlook

While focusing on a more comprehensive cyclic steaming program in 2009 at Tapia Canyon to increase production from existing wells, we can also look to completing the infrastructure (geology, pipelines, etc.) in Kansas necessary to bring gas discoveries to market with minimal delays, thus increasing our production and cash flow base.

TEG Oil & Gas USA, Inc. (“TEG USA”)

OVERVIEW

TEG USA continued forward in 2008 with well drilling, field improvements and implementation of the Tapia Steam Pilot Program, resulting in an improvement in oil production rates over 2007. TEG USA had oil sales totaling 52,780 BO, equating to an average production rate of approximately 145 BOPD, a 14% increase over the previous year. The production from the combined Eureka Canyon and Tapia Canyon oil fields resulted in average net monthly oil revenue for the 2008 calendar year of $391,000 which represents an increase of 58% over 2007. The increase was the partial result of increased oil prices over the year averaging $90.12/bbl at the field level (versus $63.60/bbl average in 2007). Lifting costs were $19/bbl for 2008. The increase from the 2007 number of $14.50/bbl came on the heels of industry-wide increases in contractor and vendor costs. However, it should be noted that despite this increase, the average profitability margin between field level oil lifting costs and oil price increased from $49.08/bbl to $71.06/bbl, resulting in a greater profit to TEG USA.

WELL DRILLING

TEG USA completed the drilling of four wells in early 2008 on step-out locations in the Tapia Canyon oil field. This resulted in production now coming from all leases at Tapia. The wells on the Snow lease encountered a thicker than normal Yule oil reservoir. However, the rocks proved to be tighter than those encountered on other leases to the east, and the initial production oil rates were somewhat lower than average for the field. However, well logs indicated excellent oil saturation and, with the promise of later steam stimulation of these wells, these results did not dampen TEG USA’s enthusiasm for this lease. This interpretation was borne out later in the year when the steaming of the Snow #5 well increased the production from the well five-fold and thus proved up the earlier log interpretation and viability for future work in this area of the field. There remains a minimum of three locations on this lease to be drilled at a later time.

In December, 2008 TEG USA began a three-well drilling program. The first of the three wells, Yule #9 was drilled, logged and cased by the end of December, 2008. The two remaining wells Yule #11 and Hartje #18 were completed in January, 2009. The Yule #9 well was drilled as a gas supply well for the steam program. However, the well was drilled down through the Yule oil zone for future completion after the gas zone is depleted. Once on production in early 2009, the Yule #11 and Hartje #18 had 30-day initial production rates of 28 BOPD and 60 BOPD. 28 BOPD is approximately the average IP rate for all wells (combined) in the field.

CYCLIC STEAM STIMULATION - PILOT STUDY

TEG USA completed the steam stimulation of three wells during 2008 using both lease gas and propane gas as fuel sources. In doing so, TEG USA was able to prove the viability of economically steaming this reservoir and at the same time collected valuable data for design of our planned full cyclic program to be implemented in 2009. By varying steam injection volumes and duration of steam soak time, TEG USA can now model future steam stimulation cycles for optimum results. The steaming of the adjacent Yule #7 and #10 wells effectively doubled the production from the Yule lease during the production cycle. The steaming of the Snow #5 well later in the year resulted in an increase in oil production from <10 BOPD (pre-steam) to >50 BOPD (post steam), a greater than five–fold increase in oil production from the well.

FACILITY IMPROVEMENTS

TEG USA continued to reinvest into its surface facilities during 2008. In doing so, the Tapia Canyon facility has been made, as a whole, a safe and efficient oil field operation. During 2008, TEG USA replaced two more aging tanks at the Hartje Facility and installed new process piping, tank heaters and insulation blankets to speed oil/water separation and increase through-put capacity. Additionally, TEG USA completed the realignment of the produced water separation and re-injection system that will allow TEG USA to efficiently handle the increased water production anticipated with implementing cyclic steam stimulation. Tapia Canyon is now a model facility that can operate at efficient levels with relatively low lifting costs for a rejuvenated oilfield. It is also a facility that is environmentally safe and safe for our personnel. These efforts have not gone unnoticed by others. The State of California Division of Oil, Gas and Geothermal Resources nominated TEG USA for an award for operational excellence at Tapia. In March, 2009, TEG USA received formal notification that the Company will be presented with this award at an American Petroleum Institute function in May 2009.

EUREKA CANYON FIELD - RECONNAISSANCE MAPPING

TEG USA and contractor W.L. Gore and Associates completed infill geochemical field sampling in November, 2008 in a tight grid over a promising area of the Eureka leasehold. The samples were then processed and results compared to the earlier general survey. The preliminary results were not received until January, 2009, but these confirmed two positive hydrocarbon anomalies originally outlined by the earlier reconnaissance survey. TEG USA is now moving forward with the mapping of specific drilling prospects in these areas.

IN CLOSING

TEG USA benefited from the oil price spike in 2008 that resulted in an elevated profitability above earlier projections. The relaxing of these oil prices has not hindered us in our plans because our relatively low lifting costs will keep TEG USA profitable. We have already seen service and vendor costs adjust downward as a result of industry slow down. This is a decided advantage to a smaller operator like TEG USA. TEG USA believes that the implementation of the field-wide cyclic steam program in 2009 will dramatically increase production while not burden the cash flow with increased capital costs. This will allow TEG USA to take advantage of the growth opportunities that are bound to present themselves.

TEG MidContinent, Inc. (“TEG MC”)

For exploration and production companies, 2008 was the worst of times and the best of times. Record high oil prices were followed by extended periods of extremely low pricing. Projections and planning were difficult and, at times, nearly impossible. In response to the varied economic factors that plagued the industry, TEG MC moved cautiously by selectively focusing on prime acreage in its lease acquisition program and undertaking geological and engineering studies to include the design of a “pilot drilling program” that was implemented during the fourth quarter. The Company, through continued negotiations with industry partners, improved its asset base and positioned itself for future development and growth.

TEG MC feels that the time spent in analysis of properties and industry drilling, completion and operational procedures has been beneficial. These studies will allow TEG MC to undertake effective operations, while avoiding the costly mistakes (multiple zone completions and immediate connection to high-pressure sales lines) that many companies in the Forest City Basin have experienced.

In 2008, TEG MC acquired an additional 6,500 acres. The Anderson County and Franklin County project is now comprised of 42,000 plus acres and is supported by extensive geology, including detailed coal maps. The acreage is situated such that TEG MC has coverage on both conventional oil and gas possibilities and on the thicker, potentially more productive, Bevier and Riverton coal deposits.

During the fourth quarter of 2008, TEG MC negotiated an option to purchase, from Petrol, all of its assets, including 17 wells and associated equipment located in the Petrol Waverly Project. The assets included a gas gathering and water disposal system, two salt water disposal wells and a 10 million mcf per day processing facility. The connection point for the gathering and disposal pipelines is located three miles west of TEG MC’s CBM pilot program.

The Miller A2-1, the first well in the “pilot program”, was spud on December 9, 2008 with logs and casing run on December 12, 2008. Log analysis indicated eight feet of Riverton coal and a presence of conventional sand that calculated wet. The conventional sand tested gas during the drilling and the well is one mile west of the Lankard well that has cross-over on its logs.

In the first quarter 2009, TEG MC exercised its Petrol option. By completing this acquisition TEG MC has assured itself access into a major purchaser/interstate pipeline through the above described facility and availed itself to salt water disposal for its pilot program at a greatly reduced cost.

TEG MC’s acreage position in Leavenworth County is 7,000 acres. During 2008 TEG MC continued discussions with a number of independent pipeline operators that have access to the Southern Star system and are situated such that access could be achieved with minimal pipeline construction.

In the first quarter of 2009, the Company negotiated and executed a “Letter of Intent” to purchase, from HDP Inc., their inactive pipeline and gas gathering system, to include right-of-way. The “Vanguard Pipeline” is located west and north of TEG MC’s Leavenworth project, an area presently subject to “curtailed/seasonal gas sales”. The pipeline will provide a gathering system for TEG MC’s future drilling and will establish a basis for potential joint ventures in both exploration and gas gathering and transportation.

Consolidated Balance Sheets
As of December 31, 2008 and 2007

December 31, 2008

December 31, 2007


$

$

ASSETS



CURRENT ASSETS:



Cash and cash equivalents

97,357

5,789

Accounts receivable

451,264

414,801

Other receivables - related party

273,040

159,692

Prepaid expenses and other assets

26,974

6,769




Total current assets

848,635

587,051




OIL and GAS PROPERTIES FULL COST METHOD, net

14,595,804

9,789,223




EQUIPMENT AND VEHICLES, net

23,577

30,871







TOTAL ASSETS

15,468,016

10,407,145




LIABILITIES AND STOCKHOLDERS EQUITY



CURRENT LIABILITIES:



Accounts payable

939,477

810,942

Accrued expenses

347,508

162,666

Accrued expenses - related parties

221,083

179,549

Note payable, current portion

211,515

385,059




Total current liabilities

1,719,583

1,538,216




NOTES PAYABLE:



Note payable

390,000

338,335

Note payable – bank

3,436,513

911,317


3,826,513

1,249,652




RETIREMENT OBLIGATION

1,112,109

-




ASSET RETIREMENT OBLIGATION

1,164,263

504,096




Total liabilities

7,822,468

3,291,964




STOCKHOLDERS EQUITY:



Common stock, no par value, 200,000,000 shares authorized, 116,387,779 and

116,040,354 December 31, 2008 and 2007 shares issued and outstanding

13,254,180

13,049,227

Stock subscription receivable

(30,047)

(30,047)

Treasury stock

(66,393)

(58,602)

Accumulated (deficit)

(5,512,192)

(5,845,397)




Total stockholders equity

7,645,548

7,115,181




TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY

15,468,016

10,407,145



Consolidated Statement of Operations

For the years ended December 31,


2008

2007


$

$




OPERATING REVENUE:



Oil and gas sales

4,688,183

2,977,691




OPERATING COSTS AND EXPENSES:



Oil and gas production

1,040,573

672,845

Depletion and depreciation

462,685

304,965

General and administrative

1,774,819

1,519,848

Share based compensation

162,528

197,220




Total costs and expenses

3,440,605

2,694,878




PROFIT FROM OPERATIONS

1,247,578

282,813







OTHER INCOME (EXPENSE)



Interest and other income

390,000

417

Interest expense

(192,264)

(78,578)

Retirement liability

(1,112,109)

-




Total other income expense

(914,373)

(78,161)




Net INCOME

333,205

204,652







NET INCOME PER SHARE



Basic and diluted

0.0029

0.0018


Consolidated Statement of Cash Flows

For the years ended December 31,


2008

2007


$

$




CASH FLOWS FROM OPERATING ACTIVITES:



Net income (loss)

333,205

204,652

Adjustments to reconcile net loss to net cash used in operating activities:



Depletion and depreciation

462,685

304,965

Share based compensation

162,528

197,220




Changes in operating assets and liabilities:



Accounts receivable

(36,463)

(42,627)

Prepaid expenses

(20,206)

13,080

Other assets - related party

(113,348)

(69,115)

Accounts payable

128,535

326,499

Accrued retirement obligation

1,112,109

-

Accrued expenses - related party

41,534

154,549

Accrued expenses

184,843

126,985




Net cash provided by operating activities

2,255,422

1,216,208




Cash flows from investing activities:



Purchase of oil and gas properties

(4,589,000)

(2,184,816)

Purchase of property and equipment

(12,805)

(4,857)




Net cash used by investing activities

(4,601,805)

(2,189,673)




Cash flows from financing activities:



Proceeds from notes payable

2,647,695

948,318

Payments on notes payable

(244,378)

(147,473)

Proceeds from sale of common stock

42,425

109,486

Purchase of treasury stock

(7,791)

-




Net cash provided by financing activities

2,437,951

910,331




Effect of exchange rate changes on cash

-

-




Net Increase (decrease) in cash and cash equivalents

91,568

(63,134)




Cash and cash equivalents at beginning of year

5,789

68,923




Cash and cash equivalents at end of year

97,357

5,789







 

Notes

Financial Statements

The summary financial statements set out above have been extracted from the Company’s audited financial statements for the year ended 31 December 2008 (not presented herein). Those financial statements were prepared in accordance with United States Generally Accepted Accounting Principles. These summary financial statements do not constitute financial statements in accordance with United States Generally Accepted Accounting Principles as they omit substantially all the disclosures required by United States Generally Accepted Accounting Principles. A full set of accounts will be available on or around May 19, 2009 on the Company’s website at www.seftonresources.com and will be posted to shareholders.

The annual report of accounts will be posted to shareholders on or around 19 May 2009, copies of which will be available from the Company Secretary, Pinsent Masons Secretarial Services Limited, City Point, 1 Ropemaker St., London EC2Y 9AH or at www.seftonresources.com. The Annual General Meeting of the company will be held 24 June 2009 at 10:00 am in the offices of Chantrey Vellacott, Russell Square House, 10-12 Russell Square, London WC1B 5LF.

Income Per Share

The Company applies the provisions of Statement of Financial Accounting Standard No. 128, Earnings per Share (FAS 128). All dilutive potential common shares have an antidilutive effect on diluted per share amounts and therefore have been excluded in determining net income or loss per share. The Company’s basic and diluted income or loss per share is equivalent and accordingly only basic income or loss per share has been presented.

Dividends

The Directors are not recommending the payment of a dividend.

Enquiries

Jeremy Delmar-Morgan, Chairman, Tel: 077 8900 4876
John James (Jim) Ellerton, CEO, Tel: 00 1 303 759 2700
Peter Trevelyan-Clark/Nick Harriss/Wye-Li Long, Blomfield Corporate Finance Ltd., Tel: 020 7489 4500
Daniel Briggs, Religare Hichens, Harrison plc, Tel: 020 7382 4450

Sefton Resources is an AIM listed oil and gas production company. Its main core area of activity is in the East Ventura Basin in California, where it owns 100% of two oil fields, Tapia Canyon (heavy gravity oil) and Eureka Canyon (medium gravity oil), both of which have over twenty years of expected production life. In addition, Sefton has over 45,000 acres in the Forest City Basin of Eastern Kansas where Coal Bed Methane gases, as well as conventional oil and gas deposits, are targets.