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19 May 2008 11:17
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Sefton Resources, Inc.
(Sefton or the Company)
Final Results for the year endedΒ 31 December 2007
Sefton Resources Inc., theΒ AIMΒ listed oil and gas production company with assets inΒ CaliforniaΒ andΒ Kansas, announces the company's final results for the year endedΒ December 31, 2007.
2007 Highlights
Company Profitable
Put in place a bank line of credit for TEG Oil & Gas USA
Drilled two additional development wells atΒ TapiaΒ CanyonΒ oil field
Continued replacing old surface facilities with new equipment at Tapia oil field
Took delivery of the custom designed steam generator
Completed the geochemical survey atΒ EurekaΒ oil field
Acquired additional land holdings inΒ Kansas
Chairman's Statement
I am pleased to report that 2007 has been a year in which we have been able to put in place the components that will take Sefton on to the next phase of its development.The company is now tradingΒ profitably and generating good cash flow. In addition the $1 0m bank credit, together with our cash flow, hasΒ enabled us to continue to upgrade our production facilities and the drilling and steaming programme. The results from this activity will mainly be seen in 2008.
The majority of the expansion programme was concentrated on theΒ TapiaΒ CanyonΒ field where we hadΒ added additional surface facilities, taken possession of a custom designed steam generator and drilled twoΒ new wells by the year end. We have now successfully drilled our eleventh well and extended theΒ production area into the entire Tapia field. We have moved west through our Snow wells and east with the Lackie well. More detail is provided in the TEG USA review, but this is a very exciting developmentΒ especially as natural gas bearing sandstone has been identified at Snow and at Lackie, where it wasΒ previously unknown.
The main development in the business was therefore concentrated on Tapia, but we have also continued toΒ improve our asset base inΒ KansasΒ although at a more modest pace. Additional acreage was acquired,Β increasing our Anderson and Franklin project to 36,000 plus acres with a further 7,000 acres inΒ LeavenworthΒ County. We have continued our discussions with the various independent pipeline operatorsΒ and investigated joint venture opportunities. But we are not prepared to enter into any agreements if weΒ are not confidentΒ that it will be for the long term benefit of Sefton and its shareholders. Current gas pricesΒ and our improved financial position mean that we are under no pressure to move prematurely.
The major improvements, which I have outlined, occurred at the end of the year. The year end financial figures, therefore, reflect the cost of the two drilled wells, although they did not produce any significantΒ increases in production. The improvement in profitability was mainly due to increases in oil and gas prices.
FINANCIALS
Oil and gas revenue increased to $2,977,691 from $2,696,180 as a result of oil price increases. Oil and gasΒ production costs decreased to $672,845 from $833,716 primarily as a result of fewer work over costs withΒ newer wells versus old wells. General and administrative costs increased slightly to $1,519,848 fromΒ $1,478,696 which together with less interest expense ($78,578 from $186,247) and no expenses relating to Canadian operations (which were sold last year), resulted in overall income of $204,652 compared to a loss of $592,777 for the comparative period one year ago.
Non-cash expenses from depletion, depreciation andΒ share based compensation total 502,185.Β
ENGINEERING
Total proved reserves atΒ 31 December 2007Β still remained at approximately 4 million barrels of oil but with proved developed reserves increasing to 463,900 barrels from 282,800 barrels, as a result of twoΒ successful development wells drilled towards the end of 2007. The price of oil at the end of 2007 was approximatelyΒ $84 per barrel compared to approximately $53 per barrel for 2006, resulting in a "net present day value"Β (discounted 10%) of $114,004,000 for year-end 2007 proved reserves versus $57,095,800 for 2006.
For the year end 2007 engineering report, the life of the proved oil reserves was estimated at approximately 46 years (42 years for 2006) with an undiscounted return on investment of 17 (9 for 2006) and a rate of return of over 100% (little less than 100% for 2006). Lifting costs for all production was $14.55 per barrel versus $17.28 per barrel for 2006.
With four new wells completed and additional wells planned for 2008 (both California and Kansas),Β together with a pilot steam programme in California, we are expecting a significant change in the reserveΒ study, and a decrease in lifting costs as all infrastructure is in place.
OUTLOOK
The programme has continued into 2008 with an additional four wells drilled in the first quarter and theΒ initiation of a pilot steam programme where we expect to achieve significant improvement in revenueΒ during the coming year. The results from the pilot steam programme have provided us with significant dataΒ which will be put to use as we develop the rest of the field. We have already moved the steam injectionΒ packet to Yule 10 andΒ further wells will be steamed during the year. It is not possible to put a number onΒ how many we will achieve in 2008, although eventually we intend to steam all eleven new wells and someΒ of the old wells. In addition, during 2008 we plan to drill more wells at Tapia, further develop ourΒ EurekaΒ CanyonΒ field and initiate a pilot drilling programme inΒ Kansas. This will broaden the group's revenue sourceΒ while adding additional assets, all of which points to an exciting future.
On behalf of the Board I would like to thank staff and shareholders for their continued support. Thanks toΒ our staff's continued vigilance, problems faced during 2007 were minimised and leave us in an excellentΒ position to move the group forward.
Jeremy Delmar-Morgan, Chairman
TEG Oil & Gas USA, Inc. ("TEGΒ USA")
OVERVIEW
TEGΒ USAΒ moved forward in 2007 with plans for field improvements and drilling, while maintaining steady oil production rates. TEGΒ USAΒ had finished the 2006 year at approximately 130 BOPD at the Tapia Oil Field.Β Although there was some month to month fluctuations on oil production in 2007, TEGΒ USAΒ had oil sales totaling 46,250 BO, equating to an average productive rate of approximately 127 BOPD. New oil was notΒ added to the production stream until the month of December, however, the wells drilled in mid-2005Β remained steady producers. The production from the combinedΒ EurekaΒ CanyonΒ and Tapia oil fieldsΒ resulted in an average net monthly oil revenue of $248,000 for the 2007 calendar year, which represents aΒ Β 9.5% increase over 2006. The increase was the direct result of a steadily increasing oil price over theΒ year averaging $63.60/bbl at the field level (versus $55/bbl average in 2006). Lifting costs for all productionΒ was $1 4.55/bbl for 2007 verses $1 7.28bbl in 2006 despite industry-wide increases in contractor andΒ vendor costs.
FACILITIES IMPROVEMENTS
TEGΒ USAΒ continued with upgrading facilities to handle projected increases in throughput volumes andΒ temperatures (from future steaming) at the producing Yule and Hartje leases as well as the shut-in Snow and Lackie leases. These improvements included the following:
Installation of access catwalks and pipe racks for oil and gas flowlines at the Hartje Facility.
Installation of 480V electrical service to the Yule lease for the steam generator.
Running of gas supply lines for the steam generator on the Yule lease.
Complete lease cleanup including removal of all mothballed equipment, abandoned piping, and scrap.
Rebuilding of secondary containment berms and installation of fencing around the Yule Tank Facility forΒ public safety and security.
Installation of electrical service and flowlines for the two new wells drilled in November, Hartje #16 & #17.
Maintenance of lease roads including the application of road-base surfacing in the heavy traffic areas.
Construction of expansion-loop supply line and diverter lines for steam injection to the wellhead.Β
Β
CYCLIC STEAM STIMULATION EQUIPMENT
TEGΒ USAΒ took delivery of the 14 million BTU/hr rated steam generator in early June, approximately eight weeks later than promised by the vendor. The equipment was built with a low-NOx high-efficiency burnerΒ designed to exceed current air emissions standards for theΒ Los AngelesΒ air basin. The bank financing inΒ mid-August allowed the building of the field infrastructure for the steam pilot, including electrical service,Β water and gas supply pipelines and effluent steam lines. This work was completed by mid-October and the steam unit was subsequently test fired using Tapia lease gas and function tested by Clayton Industries. TEGΒ USAΒ did experience a minor setback during the final surface testing of the steam generator. Fluctuating gas supply rates from the Yule #8 gas well caused problems with the automated controls. TEGΒ USAΒ therefore decided to switch to the use of propane in the initial pilot test in order to expedite the programme, andΒ thus giving time to build a second gas supply line from the Snow #1 well on the neighbouring lease. The steaming of the initial well was pushed back into 2008.
Q4 2007 DRILLING PROGRAM
TEGΒ USAΒ drilled two oil wells on in the east-central portion of the Tapia Field. Both wells were drilled on the Hartje Lease. Hartje #16 & #17 were successfully drilled to depths of 1,250' and 1,255', respectively,Β into the Yule Sand oil reservoir, adding a total of 77 BOPD to the production by year's end. Additionally, aΒ shallower oil sand was identified in the Hartje #16 well on both the mudlog and the wireline logs. UnderΒ further examination, this same zone is identifiable on older wireline logs in the adjacent Hartje #10 wellΒ that is currently shut-in in the Yule Sand. TEGΒ USAΒ is formulating plans to test this zone in the Hartje #10Β well during 2008.
EUREKA CANYON FIELD - RECONNAISSANCE MAPPING
TEGΒ USAΒ and contractor W. L. Gore and Associates submitted final reports for the geochemical reconnaissance mapping programme on theΒ EurekaΒ CanyonΒ minerals leases in 2007 and results areΒ encouraging. The survey was conducted over a coarse grid pattern on the 1,500 acre lease. The resultsΒ showed areas of hydrocarbon fingerprinting. TEGΒ USAΒ is planning to infill the grid pattern over theΒ stronger hydrocarbon anomalies in the coming year and sample adjacent oilfields to better refine theΒ hydrocarbon signature. TEGΒ USAΒ is anxious to expand our redevelopment programme to the Eureka Canyon Field in the coming year and drill wells in both infill and step-out exploitation locations.
FUTURE
2007 closed strongly for TEGΒ USA'sΒ CaliforniaΒ operations with the start-up production from the two newΒ wells drilled. This momentum has carried TEGΒ USAΒ forward into early 2008 with the drilling of four additionalΒ wells. Now that pilot steaming has begun (February, 2008) TEGΒ USAΒ can benefit from increased productionΒ from both primary and secondary recovery techniques in the coming months and years ahead at Tapia.
Harry P. Barnum, President/Managing Director,TEG Oil & Gas USA, Inc.
TEG MidContinent, Inc. ("TEG MC")
Responding to the varied results achieved by industry operators in the Basin during 2007, TEG MC movedΒ cautiously, selectively focusing on prime acreage in its lease acquisition programme and undertakingΒ geological and engineering studies. The Company improved its asset base and positioned itself for future development and growth. TEG MC feels that the time spent in analysis of its properties and industry drilling, completion and operational procedures has been beneficial. These studies will allow TEG MC to undertakeΒ effective operations while avoiding the costly mistakes (multiple zone completions and immediateΒ connection to high-pressure sales lines) that some companies in theΒ ForestΒ CityΒ BasinΒ have experienced.
ANDERSON/FRANKLIN COUNTIES
During 2007, TEG MC acquired an additional 5,000 acres and now theΒ AndersonΒ andΒ FranklinΒ CountyΒ project is comprised of 36,000 plus acres, has close proximity to pipelines and is supported by extensiveΒ geology, including detailed coal maps and engineering analysis. The acreage is situated such that TEG MCΒ has coverage on both conventional oil and gas possibilities and on the thicker, potentially more productive,Β Bevier and Riverton coal deposits.
TEG MC has contracted for and received a design of a "pilot drilling programme" that may beΒ implemented late in 2008. The pilot programme consists of a re-entry of an existing wellbore to test bothΒ coals and conventional sand and the drilling of four (4) new test wells to test the Riverton and BevierΒ coals. In the alternative, TEG MC has initiated discussions with a number of potential joint venture partners.Β A properly structured "joint venture" would allow TEG MC and its parent to recoup some or most of itsΒ investment, thus providing capital for drilling and or pipeline acquisition inΒ LeavenworthΒ County.
LEAVENWORTHΒ COUNTY
TEG MC's acreage position inΒ LeavenworthΒ CountyΒ is 7,000 acres. The leasehold, some with temporarily abandoned wells (shut-in when pipeline gathering systems abandoned operations), provides TEG MC withΒ numerous potential Coal Bed Methane (CBM) and McLouth sandstone (conventional gas formation) locationsΒ through re-entry and re-completion of existing wellbores and/or new drilling. TEG MC has contracted for anΒ engineering evaluation of a number of existing wellbores that are located on TEG MC acreage.
TEG MC continues exploratory 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 minimalΒ pipeline construction.Joint development of acreage and pipeline systems could provide immediate marketΒ access ("hook-up") for several wells.
Bruce Mackay, President/Managing Director, TEG MidContinent, Inc.
Consolidated Balance Sheets
as ofΒ December 31, 2007Β and 2006
|
ASSETS |
2007 |
2006 |
|
Current assets: |
||
|
Cash and cash equivalents |
$ 5,789 |
$ 68,923 |
|
Accounts receivable |
414,801 |
372,174 |
|
Other receivables - related party |
159,692 |
90,577 |
|
Prepaid expenses and other assets |
6,769 |
19,849 |
|
Total current assets |
587,051 |
551,523 |
|
Oil and gas properties, full cost method, net |
9,789,223 |
7,517,673 |
|
Equipment and vehicles, net |
30,871 |
47,957 |
|
Total assets |
10,407,145 |
8,117,153 |
|
LIABILITIESΒ ANDΒ STOCKHOLDERS' EQUITY |
||
|
Current liabilities: |
||
|
Accounts payable |
810,942 |
484,443 |
|
Accrued expenses |
162,666 |
35,581 |
|
Accrued expenses - related parties |
179,549 |
25,000 |
|
Note payable, current portion |
385,059 |
128,810 |
|
Total current liabilities |
1,538,216 |
673,834 |
|
Notes payable: |
||
|
Note payable |
338,335 |
705,056 |
|
Note payable - bank |
911,317 |
- |
|
1,249,652 |
705,056 |
|
|
Asset retirement obligation |
504,096 |
134,440 |
|
Total liabilities |
3,291,964 |
1,513,330 |
|
Stockholders' equity: |
||
|
Common stock, no par value, 200,000,000 shares authorized, 116,040,354 and 115,109,527Β December 31, 2007Β and 2006, shares issued and outstanding |
13,049,227 |
12,742,521 |
|
Stock subscription receivable |
(30,047) |
(30,047) |
|
Treasury stock |
(58,602) |
(58,602) |
|
Accumulated (deficit) |
(5,845,397) |
(6,050,049) |
|
Total stockholders' equity |
7,115,181 |
6,603,823 |
|
Total liabilities and stockholders' equity |
||
|
$ 10,407,145 |
$ 8,117,153 |
Consolidated Statement of Operations
for the years endedΒ December 31, 2007Β and 2006
|
2007 |
2006 |
|
|
Revenues: |
||
|
Oil and gas sales |
$ 2,977,691 |
$ 2,696,180 |
|
Costs and expenses: |
||
|
Oil and gas production |
672,845 |
833,716 |
|
Depletion and depreciation |
304,965 |
314,145 |
|
General and administrative |
1,519,848 |
1,478,696 |
|
Share based compensation |
197,220 |
447,957 |
|
Total costs and expenses |
2,694,878 |
3,074,514 |
|
Profit/(loss) from operations |
282,813 |
(378,334) |
|
Other income (expense): |
||
|
Interest income |
417 |
6,738 |
|
Interest expense |
(78,578) |
(186,247) |
|
Foreign currency transaction losses |
- |
(56,693) |
|
Total other income expense |
(78,161) |
(236,202) |
|
Income/(loss) from continuing operations |
$ 204,652 |
$ (614,536) |
|
Discontinued operations: |
||
|
Income from TEG Canada Inc. |
- |
6,894 |
|
Gain on sale of TEG Canada Inc. |
- |
14,865 |
|
- |
21,759 |
|
|
Net income/(loss) |
204,652 |
(592,777) |
|
Income/(loss) per share: |
||
|
Income/(loss) from continuing operations per share Basic and diluted |
0.0018 |
(0.00583) |
|
Income/(loss) from discontinued operations per share Basic and diluted |
- |
0.00021 |
|
Net income/(loss) per shareΒ Basic and diluted |
0.0018 |
(0.00562) |
Consolidated Statement of Cash Flows
for the years endedΒ December 31, 2007Β and 2006
|
2007 |
2006 |
|
|
Cash flows from operating activities: |
||
|
Net income/(loss) |
$ 204,652 |
$ (592,777) |
|
Adjustments to reconcile net income/(loss) to net cashΒ (used in) operating activities: |
||
|
Depletion and depreciation |
304,965 |
314,145 |
|
Amortization of discount on convertible notes payable |
- |
119,000 |
|
Compensation expense related to stock options |
197,220 |
447,957 |
|
Gain on disposal of subsidiary |
- |
(14,866) |
|
Changes in operating assets and liabilities: |
||
|
Accounts receivable |
(42,627) |
96,324 |
|
Prepaid expenses |
13,080 |
27,438 |
|
Other assets - related party |
(69,115) |
(68,060) |
|
Accounts payable |
326,499 |
(241,344) |
|
Accrued expenses - related party |
154,549 |
(54,058) |
|
Accrued expenses |
126,985 |
11,893 |
|
Net cash provided by operating activities |
1,216,208 |
45,652 |
|
Cash flows from investing activities: |
||
|
Purchase of oil and gas properties |
(2,184,816) |
(738,790) |
|
Purchase of property and equipment |
(4,857) |
(27,492) |
|
Proceeds from disposal of subsidiary |
- |
284,728 |
|
Net cash transferred with subsidiary |
- |
(18,060) |
|
Net cash used by investing activities |
(2,189,673) |
(499,614) |
|
Cash flows from financing activities: |
||
|
Proceeds from notes payable |
948,318 |
376,315 |
|
Payments on notes payable |
(147,473) |
(75,176) |
|
Proceeds from sale of common stock |
109,486 |
38,944 |
|
Net cash provided by financing activities |
910,331 |
340,083 |
|
Effect of exchange rate changes on cash |
- |
56,693 |
|
Net decrease in cash and cash equivalents |
(63,134) |
(57,186) |
|
Cash and cash equivalents - beginning of year |
68,923 |
126,109 |
|
Cash and cash equivalents - end of year |
$ 5,789 |
$ 68,923 |
Notes
Financial Statements
The summary financial statements set out above have been extracted from the Company's audited financial statements for the year endedΒ 31 December 2007Β (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 UnitedΒ States Generally Accepted Accounting Principles as they omit substantially all the disclosures required byΒ United States Generally Accepted Accounting Principles. A full set of accounts can be viewed at www.seftonresources.com.
The annual report of accounts will be posted to shareholders byΒ MayΒ 20, 2007, copies of which willΒ be available from the Company Secretary, Pinsent Masons, CityPoint,Β 1 Ropemaker Street,Β LondonΒ EC2Y 9AHΒ or atΒ www.seftonresources.com. The Annual General Meeting of the company will be heldΒ at 10.30am, July 9,2007 at Nominated Advisors (NOMAD) London Offices; Seymour Pierce, 20 Old Bailey, London EC4M 7EN. 2. Net Income Per Share
The Company applies the provisions of Statement of Financial Accounting Standard No. 128, Earnings perΒ Share (FAS 128). All dilutive potential common shares have an antidilutive effect on diluted per shareΒ amounts and therefore have been excluded in determining net income or loss per share. The Company'sΒ basic and diluted income or loss per share is equivalent and accordingly only basic income or loss perΒ share has been presented.
3. Dividends
The Directors are not recommending the payment of a dividend.
Enquiries:
Jeremy Delmar-Morgan, Chairman, Tel: 077 8900 4874
John James (Jim) Ellerton, CEO, Tel: 00 1 303 759 2700
David Millham, Investor Relations, Tel:Β 078 5094 9324
Jonathan Wright, Seymour Pierce Ltd, Tel: 020 7107 8000 Nicola Marrin, Seymour Pierce Ltd., Tel: 020 7107 8000
Sefton Resources is anΒ AIMΒ 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 40,000 acres in the Forest City Basin of Eastern Kansas where Coal Bed Methane gas, as well as conventional oil and gas deposits, are targets.
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