BP PLC and partners BHP Billiton and Unocal Corp. reported an oil discovery on Green Canyon Block 823 in the deepwater Gulf of Mexico with the drilling of their Puma-1 exploration well.

The well, which was drilled using the BP-operated Ocean Confidence drillship 140 miles off Louisiana, found about 500 ft of net oil pay in Miocene sandstones. The well was drilled to 19,034 ft TMD in 4,130 ft of water.

Two subsequent sidetrack bores also encountered oil in reservoir intervals of a similar age, partner BHP said. Technical data was taken from the straight hole and sidetrack bores.

The well was drilled in a "structurally complex subsurface area and in a zone where seismic imaging data is of only moderate quality," said Steve Bell, BHP president, exploration and business development. For this reason, the partners plan further seismic reprocessing and appraisal drilling in order to evaluate the size and significance of the discovery, Bell added.

Drilling of Puma-1 began on Aug.14, 2003. The well lies just 8 miles west of the BP-operated Mad Dog development on Green Canyon Blocks 825 and 826.

BP holds 51.66% interest in the well, while BHP holds 33.34% and Unocal 15%.

The state has denied a request from Exxon Mobil for more time to decide on whether to develop the rich Point Thomson natural gas field near Prudhoe Bay.

The company had asked for more time to decide whether to exercise an option to give a large chunk of leased Point Thomson acreage back to the state and pay a $10 million penalty. The deadline was January 15.

State oil and gas director Mark Myers said he hadn't received formal notice from Exxon Mobil.

"We have not seen a check or heard if they do want to opt out," Myers said.

The terms calling for the oil companies to surrender about 40 percent of the 117,000-acre Point Thomson unit and pay the penalty are part of a package of agreements between the companies and the state to move toward development of the field.

Point Thomson is a highly pressurized, technically challenging gas field on state land along the Beaufort Sea coast about 50 miles east of the giant Prudhoe Bay oil field. Point Thomson contains an estimated 8 trillion cubic feet of gas.

Exxon Mobil is the largest owner, with major partners including BP, Chevron and Conoco Phillips.

In 2002, Exxon Mobil began making serious moves toward a $1 billion project to strip off that portion of the gas that naturally liquefies when brought to the surface and pipe it west for shipment down the 800-mile trans-Alaska oil pipeline. Exxon said the field could yield as much as 400 million barrels of liquids known as condensate.

But in mid-December, Exxon Mobil told the state that the project looked more expensive and less productive than originally thought, and efforts to obtain government permits were suspended.

The company said Point Thomson as a standalone development project wasn't viable prior to construction of a North Slope gas pipeline to the Lower 48. Such a pipeline could carry the vast, purely gaseous Point Thomson reserves to market.

Exxon Mobil asked to extend the January 15 opt-out deadline on acreage that was added to Point Thomson as part of a unit expansion in 2001. The state granted the company extensions twice last year.

The acreage likely would attract plenty of bids from other companies based on attractive resource assessments the state has made, said Division of Oil and Gas Director Mark Myers.

West Africa is poised to be a key supplier of natural gas to help meet ever-expanding U.S. energy demands, says Bill Hauhe, manager of global liquefied natural gas (LNG) market development at ChevronTexaco.

Speaking at a recent LNG workshop at the second annual Africa Oil and Gas Conference, sponsored by the Corporate Council on Africa in Houston, Texas, Hauhe said the United States is currently importing natural gas from Canada because U.S. demand now outstrips U.S. production. Demand for natural gas in the United States is predicted to increase year after year, he said.

(The United States Department of Energy recently forecast that by 2025, natural gas produced on the North American continent will meet only 75 percent of U.S. demand, thus further fueling the need for greater natural gas imports.)

"In North America the question is not market capacity," Hauhe told his audience. "To us [at ChevronTexaco] that is not the issue. The issue is how do you get LNG into the United States? There are only four LNG receiving terminals in existence right now," he said: Everett, Massachusetts, outside Boston; Cove Point, Maryland; Elba Island, Georgia; and Lake Charles, Louisiana.

ChevronTexaco's proposed Port Pelican LNG terminal -- which will be located 37 miles offshore in the Gulf of Mexico -- Hauhe said, will utilize existing pipelines and infrastructure to efficiently bring liquefied natural gas into the United States.

( LNG is natural gas cooled to minus 259 degrees Fahrenheit. The cold temperature shrinks the gas into liquid form so it can be transported aboard double-hulled tankers. The LNG is then regasified and fed into existing natural gas pipelines for distribution.)

Hauhe reminded his audience that ChevronTexaco is Africa's largest U.S.-based private investor, operating in more than 50 countries on the continent. It was ChevronTexaco, he said, that scored the first offshore oil discoveries in both Angola and Nigeria. He said the company plans to invest up to $20 billion on the African continent over the next five years.

Hauhe called LNG production a "catalyst for positive change" across the continent, noting that ChevronTexaco is hoping to export large amounts of LNG from its production operations located offshore of Nigeria and Angola.

Special challenges come with the development of natural gas fields, he said. "The challenge of [developing] gas as opposed to oil is that it usually has to be developed in very large volumes to justify the economics of the long-distance transportation" and infrastructure needed, he explained.

"Unless there is a local indigenous demand for that gas, the gas that is produced must find a market or be reinjected into the ground. The processing and transportation of needed gas to distant markets, he said, "requires vast sums of capital, specialized equipment, infrastructure, and special expertise."

For distances up to about 2,000 kilometers, he said, pipelines are usually the most economical way to move gas to market. For longer distances, such as between West Africa and North America, he said, special double-hulled LNG ships are the preferred option.

The construction of needed LNG infrastructure, Hauhe explained, will allow for the expansion of domestic gas utilization across the North American market.

Hauhe went on to outline what both host governments and investors are expecting to gain from the development of natural gas projects across Africa.

With natural gas, he said, host African governments are expecting to utilize gas revenues to achieve sustainable development. "They want something that is not just going to last for six years and go away. We are talking about decades of development and sustainability for the economy. Also, they want to see ... something done about developing and further enhancing their own energy resources."

From an investor perspective, Hauhe said, ChevronTexaco seeks host governments that will be supportive of LNG projects as they are developed. "These are long-term projects," he reminded everyone, "so we would like to see the governments there standing behind these projects and supporting them."

Acceptable price structures and predictable commercial and financing terms in the host country are also essential to any successful project, he said, because the natural gas price must be competitive worldwide.

In that regard, he said, "we want to make sure that each individual project is competitive within a portfolio of projects. We want to ensure that each project is robust for the company and partners, including the government if they take an equity stake."

What is also important, he said, is attention to the market. "LNG buyers can never be forgotten. The four key issues are reserves, and market, market, and market. LNG has to have a place to go. It is not a fungible [interchangeable] commodity like oil is yet."

LNG markets are more limited. "There are not that many places where you can deliver LNG" because of the extensive infrastructure required, he said.

Speaking for ChevronTexaco, Hauhe said his company looks for long-term relationships of 20 years or more.

Derek Oil & Gas (OTCBB:DRKOF) and Ivanhoe Energy announced on January 20, that formal agreements have been signed for the joint development of the LAK Ranch field, a thermal recovery/horizontal well oil project in Weston County, Wyoming. Surface preparations are under way and steaming operations are expected to begin before the end of the first quarter. Assuming successful development of the project, the companies expect to recover between 30 and 70 million barrels of oil using thermal recovery techniques. The LAK Ranch oil contains high levels of naphtha and is expected to command a premium to West Texas Intermediate (WTI) benchmark pricing.

Under the terms of a farm-in agreement and a joint operating agreement, Ivanhoe has become operator and will earn an initial 30% working interest in the project by financing the capital cost of the pilot phase. Following the pilot phase, Ivanhoe will have the option to increase its working interest to 60% by providing additional capital toward the initial development phase until a total of $5.0 million (U.S.) is reached. After that, all future capital expenditures will be shared on a working-interest basis. Should Ivanhoe elect not to proceed beyond the pilot phase, its working interest will be reduced to 15% and Derek will become operator.

The LAK Ranch field covers approximately 7,500 acres in Wyoming's prolific Powder River basin. To date, Derek has completed a SAGD (steam-assisted-gravity-drainage) well pair to a depth of 1,000 feet and 1,800 feet horizontally into the Newcastle Sand formation. Surface steam-injection and oil-recovery equipment is in-place. Extensive testing indicates that because of the viscosity of the oil, production can be expected to respond dramatically to the application of continuous heat through steam injection.

Initially, steam will be injected into the existing horizontal well and production is expected to commence shortly thereafter. By summer, five vertical steam-injection wells are expected to be drilled, providing continuous steam application to the reservoir and increasing production volumes from the horizontal production well. Ivanhoe also plans a high-resolution 3-D seismic data acquisition program to further identify the limits of the field.

Assuming a successful pilot phase, the development program is expected to include additional horizontal production wells, new steam-injection wells (vertical or horizontal) and expansion of surface facilities. Ivanhoe estimates that the initial development program could grow to more than 20 wells producing in excess of 4,500 barrels per day. Optimum daily production rates could exceed 10,000 barrels per day.

Derek has an agreement with SEC Oil & Gas Partnership (SEC) that will result in SEC becoming a 5% working-interest owner in the project if certain conditions are met. In that event, the working interests of the three parties in the LAK Ranch Project will be Ivanhoe 60%, Derek 35% and SEC 5%.

The average combined royalty payable to landowners and overriding royalty holders on the LAK Ranch Project is approximately 21%. This figure includes approximately 4.14% in royalties that Derek bought back on certain tracts within the LAK Ranch Project from landowner royalty holders and overriding royalty holders.

A horizontal well, with a lateral extension of 1,500 feet, is expected to cost approximately $600,000 (U.S.) and vertical steam injection wells are expected to cost approximately $60,000 (U.S.). The Newcastle Sand formation is Lower Cretaceous sandstone and there are many fields producing from this formation located elsewhere in the basin. Colorado-based Surtek, a reservoir-engineering firm specializing in enhanced recovery applications, has provided the estimates of 100 million barrels of oil in place for the LAK Ranch field. Ivanhoe currently estimates that between 30% and 70% of the estimated oil in place may be recoverable. Naphtha is a lighter fraction of crude oil and is used in the blending of jet fuel by the local refinery. Viscosity is used to describe the level to which oil products will flow; that is, lower viscosity or lighter oil flows more readily from the reservoir and through pipelines than heavier oil with a higher viscosity.

The Exploration Company (Nasdaq:TXCO) provided on January 20, a year-end operations update on its 480,000-acre lease block in the Maverick Basin of Southwest Texas. It also announced an initial, $23.4 million capital expenditure budget for 2004.

TXCO's net daily production at year end was 1,197 barrels of oil per day (BOPD) and 8.9 million cubic feet of natural gas per day (MMcfd), up from a 2002 exit rate of 1,036 BOPD and 7.8 MMcfd. For 2003, cumulative net production totaled 4.83 billion cubic feet equivalent (Bcfe), a 10.5 percent increase from 4.37 Bcfe in 2002. The Company's production at year end was 44 percent crude oil and 56 percent natural gas.

TXCO drilled or participated in 80 wells last year, including 71 new wells and nine re-entries or recompletions -- nearly double the activity in 2002 and an all-time Company record. Some 56 wells were completed, 23 were in progress at Dec. 31 while one was dry. TXCO participated in 13 wells during fourth-quarter 2003 despite a hunting season drilling moratorium on several leases. Current drilling and operating highlights include:

Jurassic

Perforating and testing are now under way on the Taylor 132-1 Jurassic wildcat following delays encountered by TXCO's operating partner, Blue Star Oil & Gas Ltd., when approximately 4,000 feet of drill pipe was inadvertently left in the well bore while cementing the final casing liner. The well found multiple, potentially productive intervals in the Jurassic and provided valuable geologic information about the formation, which should prove helpful in drilling future wells. TXCO believes that logging indicates the presence of the best porosity and most attractive completion targets are above 18,000 feet. With a total depth of 22,400 feet, the operator must carefully evaluate more than a mile of Jurassic-age zones, starting from the bottom up. Perforating and testing the multiple zones in succession, a process that has just begun, could continue for another 30 to 90 days. Management is cautiously optimistic that the well could ultimately be completed as a commercial producer of hydrocarbons from the Jurassic formation.

Final plans for a proposed second Jurassic well await testing and completion results from the Taylor well. TXCO holds rights to the Jurassic on approximately 300,000 acres of its Maverick Basin lease block with numerous potential locations identified by the Company's extensive seismic studies.

Georgetown

On the Pena Creek lease block, the Company placed the Myers 1-684 (50% working interest) on production at the end of December, flowing 3.1 MMcfd and 40 BOPD from the Georgetown formation. It marks TXCO's third successful horizontal Georgetown gas well in a row. Earlier in December, the Kothman 1-673 (50% WI) went on production from the Georgetown and was flowing 1.8 MMcfd and 23 BOPD at Dec. 31. The first of the three, the Vivian 1-687 (50% WI), started production in October and by early January had cumulative production of 246 million cubic feet of gas and 2,000 barrels of oil and had achieved payout. At year end, the Vivian well was flowing at 2.2 MMcfd and 18 BOPD.

Drilling began on the Covert 1-690 horizontal well in late December. In January tests, the well flowed at the rate of 826 thousand cubic feet per day (Mcfd) with no oil on a 15/64-inch choke with 650 psi flowing tubing pressure prior to an anticipated acid treatment. TXCO drilled these four wells using a new seismic processing technique that more accurately predicts formation faults and fractures. By using this technique, the Company has initially identified several hundred potential Georgetown well locations across its lease block. Since the Georgetown is a fractured reservoir, it is difficult to predict ultimate reserves for each well as such reservoirs typically have high initial production rates, which fall to lower, sustained rates. Overall, TXCO drilled or re-entered 18 Georgetown wells in 2003 with only the last four wells utilizing the new technique.

TXCO has spudded its first two horizontal Georgetown wells in 2004, the Kothman 1-691 and the Paloma 2-133, both using the same technique. Gross Georgetown production on TXCO's lease block reached 7.8 MMcfd and 227 BOPD from 27 wells at Dec. 31, up from 1 MMcfd and 16 BOPD from 13 wells at year-end 2002.

Glen Rose Oil

The hunting season drilling moratorium halted Glen Rose porosity interval drilling on TXCO's Comanche lease in November. The Company (50% WI) and its operating partner, Saxet Energy Ltd., plan to resume drilling in February after the moratorium expires this month.

At Dec. 31, gross production from the Comanche Halsell (6500) Field stood at 1,317 BOPD and 9,195 barrels of water per day (BWPD) from 16 producing wells. The 2002 exit rate was 1,720 BOPD and 3,600 BWPD from seven producing wells. During 2003, six horizontal wells and seven vertical wells -- drilled to delineate the areal extent of the porosity's oil-bearing rock -- were drilled, raising the combined number of wells since the oil play's discovery in February 2002 to 27. Saxet drilled five of the 2003 horizontal wells 50 to 150 feet above the porosity interval, only intersecting and draining those faults that extended above the zone. These wells have not responded as expected, contributing to the overall decline in field production late in the year. TXCO engineers have believed for some time that drilling horizontal laterals parallel to, rather than crossing faults, while staying within the porosity zone, could result in enhanced oil production from this complex reservoir. The Company has proposed using this technique for 2004 drilling in the porosity interval. Cumulative gross oil production has surpassed 1.4 million barrels of oil to date. The project remains very profitable and economics should improve as the partners better define the expansive play and perfect drilling techniques used to tap the oil in the formation.

Horizontal Glen Rose Shoal

TXCO continued its successful horizontal Glen Rose shoal drilling program last year, drilling 11 successful gas wells in a row (47% to 62% WI). The Kincaid 1-220 (100% WI), drilled on a new shoal complex, currently is pending completion. Three horizontal Glen Rose shoal wells started production in the fourth quarter. At Dec. 31, gross production from the Chittim E. (Rodessa 5300) Field was 9.7 MMcfd and 58 BOPD, compared with 7.6 MMcfd and 45 BOPD at year-end 2002.

San Miguel Waterflood

The Company had continuing success with its Pena Creek infill drilling program (100% WI) last year, drilling and completing 21 of 23 wells -- surpassing its original, 15-well target. Four wells went on production in the fourth quarter, raising production to 463 BOPD and 1,404 BWPD at Dec. 31, up from 262 BOPD and 651 BWPD at year-end 2002.

TXCO continues to expect significant new San Miguel oil reserve additions. The Company's internal geologic, seismic and engineering reviews of the field have identified more than 80 potential infill locations to date. The Company expects to establish a significant number of additional infill locations as warranted by ongoing drilling results. Meanwhile, testing continues on the economic potential of two additional, overlying San Miguel sands.

Coalbed Methane

Gas production continues to rise as TXCO proceeds with the dewatering phase of its Olmos/coalbed methane (CBM) project. At Dec. 31, 36 wells were producing 208 Mcfd of natural gas and 1,837 BWPD, compared with 165 Mcfd and 1,319 BWPD from 34 wells at the end of September 2003. A few wells have had notable gas production increases in recent months, indicative of dewatering progress. The Company continues to believe that the CBM project will result in significant reserve and production growth in the future.

Escondido

TXCO drilled five Escondido wells (100% WI) in 2003 on the eastern portion of its Comanche lease. Of these, three are on production, one is shut in and one is abandoned. These producing wells flowed an average of 132 Mcfd at Dec. 31. The low cost associated with drilling at these shallow depths provides attractive development opportunities. Economic development of the shallow, Escondido/Olmos sands, located at approximately 800 to 1,000 feet, will accelerate as pipeline infrastructure grows along with the development of additional Georgetown gas production in the area.

Seismic Database Expansion

The Company completed a 3-D seismic survey covering more than 37 square miles of its Burr lease block in the fourth quarter. Initial interpretation has identified numerous drillable locations in the Georgetown, Glen Rose and Jurassic intervals. The Company now holds 3-D seismic data covering more than 720 square miles, or more than 95 percent of its 750-square-mile (480,000-acre) Maverick Basin lease block.

2004 CAPEX

TXCO's initial capital expenditure program has been set at approximately $23.4 million. About 82 percent of the budget, or $19.2 million, has been earmarked for drilling 51 new wells and four re-entries targeting five horizons. The remainder of the capital budget will go toward seismic acquisition, pipeline and infrastructure improvements. The budget may expand or contract based on drilling results, operational developments, unanticipated transaction opportunities, market conditions, commodity price fluctuations and working capital availability.

Approximately $9.3 million will go to an expanded Georgetown drilling program. The budget calls for 25 wells, up from the 18 wells drilled in 2003. On the Glen Rose porosity oil play, TXCO has initially budgeted $4 million for eight new wells and four re-entries.

In the Pena Creek Field, the budget sets aside $2.7 million for 10 new wells as the Company continues its successful San Miguel waterflood expansion. An additional $500,000 has been allocated for injection well conversions. Other proposed projects include eight Glen Rose shoal or reef wells valued at $3.2 million. Provisions for CBM project expenditures have been excluded from the initial budget as TXCO continues evaluation of the dewatering program now under way.

TXCO's 2004 drilling budget also does not include expenditures for a second Jurassic well as the Company would have a 25 percent carried working interest should a second Jurassic well be drilled by Blue Star.

Management's Perspective

"We had the most ambitious drilling program in the Company's history in 2003, setting the stage for our 2004 CAPEX target, which should be the second-largest drilling program in the Company's history," said James E. Sigmon, president and CEO. "Our multi-play/multi-pay strategy in the Maverick Basin offers numerous -- and promising -- horizons to explore and develop. Although 2003 drilling results did not completely fulfill our expectations, I'm particularly encouraged by the recent improvement in results of our Georgetown horizontal well program. We expect to increase our focus on this expanding play.

"Testing started recently on Blue Star's Jurassic well and we remain cautiously optimistic about the potential of this unexplored formation. A successful Jurassic well could redefine the productive potential of the Maverick Basin for years to come. The Glen Rose porosity interval continues to be a technical challenge. Our talented staff of geologists, geophysicists and engineers have developed interpretive and mechanical techniques that we believe will greatly enhance oil recovery while minimizing water production. We look forward to employing these methods when we resume drilling next month."

Plains All American Pipeline, L.P. (NYSE: PAA - News) announced January 20, that it will proceed with the Phase IV expansion of its Cushing Terminal Facility. Under the Phase IV expansion, Plains All American will construct approximately 1.1 million barrels of additional tankage at its crude oil storage and terminal facility located in Cushing, Oklahoma. The Phase IV expansion project will expand the total capacity of the facility to approximately 6.3 million barrels and is expected to cost approximately $10 million. The Partnership estimates the project will be completed during the third quarter of 2004.

Plains All American's Cushing Terminal is one of the most modern, large- scale crude oil terminalling facilities in the United States, incorporating environmental safeguards and operational enhancements designed to safely and efficiently terminal, store, aggregate and segregate large volumes and multiple varieties of both foreign and domestic crude oil. Upon completion of the Phase IV expansion project, Plains All American's Cushing Terminal Facility will consist of sixteen 270,000 barrel tanks, four 150,000 barrel tanks, fourteen 100,000 barrel tanks and a manifold and pumping system capable of handling up to 800,000 barrels of crude oil throughput per day.

Cushing, Oklahoma, is the official designated delivery location for crude oil futures contracts traded on the New York Mercantile Exchange. Plains All American is the largest independent owner and operator of storage and terminalling capacity in Cushing and its facility is an approved NYMEX delivery location.

Plains All American Pipeline, L.P. is engaged in interstate and intrastate crude oil transportation, terminalling and storage, as well as crude oil and LPG gathering and marketing activities, primarily in Texas, California, Oklahoma and Louisiana and the Canadian Provinces of Alberta and Saskatchewan. The Partnership's common units are traded on the New York Stock Exchange under the symbol "PAA".

Terasen Inc. is considering a partial income trust conversion of its natural gas operations as a means of funding aggressive pipeline expansion plans, but analysts say such a move won't come soon.

B.C.-based Terasen is locked in fierce competition with Calgary-based Enbridge Inc. for oil pipeline business that would, if won by Terasen, cost more than $3-billion to build.

"A partial conversion would be one way of funding our plans," said David Bryson, Terasen treasurer.

Terasen has a $2-billion plan to twin its Trans Mountain pipeline, which carries Athabasca crude from Edmonton to ports in Vancouver and Washington State.

It also has a second $1-billion plan to build a crude-oil pipeline from Fort McMurray, the heart of Alberta's expanding oilsands development, to Edmonton, the main pipeline terminal for shipping Alberta's heavy oil to the United States and across Canada.

On both projects Terasen faces stiff competition from Enbridge, the country's largest oil pipeline operator.

Both companies are canvassing oilsands crude producers for firm commitments for the use of their proposed pipelines.

It is unlikely, at least in the near term, that more than one additional pipe will be needed on each route. Producers are expected to decide which company to back on each route after the middle of the year.

Mr. Bryson also said Terasen would consider "monetizing existing assets through income trust opportunities," if it sees significant acquisition opportunities. Those, he said, could lie in pipelines or in other parts of the business.

Other funding possibilities include creating a buying consortium (in the past, the company has made asset purchases in partnership with large pension funds), and issuing equity.

Analysts were leery that a trust conversion is imminent.

"Down the road, maybe it would be a possibility, but it's well down the road. And I would bet against it," said Robert Hastings, an analyst with Raymond James & Associates in Vancouver.

"Current regulation would probably have to change [for Terasen to effect a partial trust conversion], and there is no immediate need," he said.

Terasen's natural-gas delivery unit, which accounts for slightly more than half of the company's $2.6-billion market cap, is the most likely candidate for spin-off as an income trust.

The business supplies 95% of natural gas distributed to British Columbia consumers.

Terasen has been shifting its focus away from operating as a gas delivering utility, where growth opportunities are limited, to oil pipeline operations serving Alberta's oilsands.

Projects in the region pump out about one million barrels.

Texen Oil and Gas, Inc. (OTCBB: TXEO), is pleased to announce that the company will begin drilling a second well, Charles Kuester A-207 #A3 (CK A3), on the Charles Kuester lease in Victoria County, TX, where the company owns a 100% working interest.

The first well, Charles Kuester A-207 #A2 (CK A2), was successfully perforated with initial tests showing commercial well potential, and is now in production. CK A3 is offset 1200 feet west of CK A2 and was identified using 3-D seismic technology. CK A3 is permitted to 5,900 feet to the lower and upper Yegua, Miocene, Frio and Vicksburg formations. The company anticipates drilling to commence by February 15, 2004, weather permitting.

The Charles Kuester lease is situated on approximately 1,200 acres in the Helen Gohlke Field. This property has hosted approximately 20 deep-wells (8,000ft plus) since its discovery by Shell Oil in the 1950's. There are currently 13 well bores on this lease with the potential for re-work targeting the shallow formations in addition to potential new well development. The farmout agreement relating to the Helen Gohlke Field has expired with no further action required. Texen Oil and Gas, Inc. owns a 100% working interest and a 70% net revenue interest in the Helen Gohlke Field.

About Texen Oil and Gas, Inc.

Texen Oil and Gas, Inc. is a Houston based oil and gas exploration and development (E&D) company. The company owns approximately 6,000 acres of crude oil and natural gas producing properties in Victoria, DeWitt and Waller Counties, Texas. Texen Oil and Gas is focused on acquiring, developing and producing proven, developed and underdeveloped reserves which offer long-term value for the company.

U.S. Interior Secretary Gale Norton finalized a plan on January 22, to open more than seven million acres of untouched land in Alaska's North Slope to oil and gas development. Norton said the decision "will help meet America's need for environmentally sound energy development" but environmentalists see it as a gift from the Bush administration to the oil and gas industry.

The record of decision issued signed by Norton opens 7.23 million acres of the 8.8 million acre northwest planning area of the National Petroleum Reserve-Alaska (NPRA) to oil and gas development--it defers the remaining 1.57 million acres from leasing for 10 years.

The Interior Secretary said the plan safeguards the environment of Alaska's North Slope and ensures that all energy leases will be subject to strict environmental standards.

The U.S. Geological Survey estimates that the entire 23.5 million acre NPRA has between 5.9 and 13.2 billion barrels of technically recoverable oil with a mean estimate of 9.3 billion barrels.

The western Arctic reserve was created and earmarked for energy development by President Warren Harding in 1923--the U.S. Bureau of Land Management (BLM) assumed management responsibility for the NPRA in 1976.

The City Council has informally agreed to hire Bank One to manage the business side of letting private companies drill for natural gas and oil on city-owned property.

"This really puts the wheels under the cart," said Doug Rademaker, director of the city's engineering department. "Our goal is to have our first gas well this summer, and by late summer, we could be producing."

A "very good" well could generate $2.2 million and a "poor well" could generate $376,000 over the expected eight years of production, the city projects

Money generated by oil or gas drilling would go into the city's general fund, which pays for numerous services including police and fire protection and code enforcement. The council would approve each oil and gas lease.

"If they choose to carry this project forward, we hope they will listen carefully to the concerns of the citizens who will be affected" said Glenn Ford, conservation chairman of The Greater Fort Worth Sierra Club.

That's part of the job that Bank One will do for the city. In addition to drawing up contracts to let private companies drill, Bank One will also ensure that environmental concerns are addressed.

In recent years, private companies have shown renewed interest in drilling in the Barnett Shale, a vast underground natural gas reserve believed to be one of the largest in North America. It runs from the Oklahoma line through Denton, Wise, Tarrant, Parker and Johnson counties.

Sites generating the most interest for drilling include properties near Alliance Airport, Meacham Airport, the Village Creek Wastewater Treatment Plant, the Rolling Hills Water Treatment Plant, the Fort Worth Nature Center and Buck Sansom Park, officials said.

Under the plan, the city would probably lease its property to private drilling companies. In return, it would receive lease bonuses, royalties and annual revenue, officials said.

Bank One would receive a percentage, Rademaker said.

In return, the company's duties would include managing the city's portfolio; providing oil/gas attorney services; developing lease documents; reviewing proposals; creating a competitive bid process for oil and gas leases; reviewing bids; and negotiating leases.

The city may lease land it owns, as long as it is not a street, an alley or a public square in a densely settled area. More public hearings would be required if a lease were proposed for dedicated parkland.

Fort Worth regulations on drilling went into effect in recent years regulating distance, insurance, landscaping, safety, noise and operating hours in some areas. Wells are not allowed within 300 feet of habitable structures, for example, and would require permits and inspections.

Turner Valley Oil and Gas (OTC BB: TVOG) has announced that Phase 1 of the re-completion of the KARR PROPERTY well is now completed and initial testing operations are being conducted by Sun Ocean Energy Ltd., operator of the Karr Creek gas well (8-24-63-3W6) in northwest Alberta. The well flowed oil to the surface at over 500 bopd (barrels of oil per day) and produced gas rates of up to 3 mmcf/d (million cubic feet per day).

The flow and build up test results are still to be evaluated from reservoir pressure surveys, which are currently underway. The results will be reported by the Company in early February. Once the pressure surveys are completed these results will aid in the design of a permanent tie-in and production facility.

Due to environmental restrictions, the earliest that pipeline construction can commence is May 1, 2004. The well will be put on-line immediately following tie in. The Company will continue to report its progress as information becomes available.

Turner Valley Oil and Gas is an emerging oil and gas company focused on participating in low to medium risk re-completion projects along with higher risk drilling opportunities.

Turner Valley Oil and Gas is focused on increasing production by means of; continuing acquisitions, development projects and exploration drilling within a joint venture framework.

Heartland Oil and Gas Corp. announces that the initial phase of the company's first coal bed methane (CBM) pilot program in the Forest City Basin of northeast Kansas has been completed, on time and within budget. The 5-well pilot is located in the Engelke area of Nemaha County, where earlier drilling by Heartland encountered some of the thickest coal sections in the basin. The wells were fracture stimulated and put on pump in November 2003. Management is encouraged that the water content of the coals is less than anticipated, while gas pressures continue to build as expected. All water from these wells is being injected into Heartland's offsetting water disposal well.

Heartland has begun permitting for three new 5-well pilot programs, and three additional water disposal wells on its Engelke acreage. These new pilots are designed to further define the productivity of the Engelke acreage for CBM. Drilling of the additional 18 wells is expected to commence by the end of the first quarter of 2004.

Acreage Update:

Heartland has continued to acquire leases in selected areas within the Forest City Basin. At January 20, 2004 the company had more than 235,000 acres under lease, an increase of 67,000 acres since June of 2003. All of Heartland's leases are operated by Heartland and have a 100% working interest. Net revenue interest varies between 84.5% and 87.5%.

General

Heartland is developing its coalbed methane lands in the Forest City basin in the state of Kansas, USA. Using its proprietary mapping of the area and results from earlier drilling, Heartland has acquired a dominant position in what is believed to be the thickest part of the coal fairway in the Forest City Basin.

Heartland has acquired leasehold interests in approximately 235,000 acres in the Forest City Basin. Since Heartland initiated its CBM project in 2001 the Forest City/Cherokee basin fairway has experienced dramatically increased activity. There is existing coalbed methane production in the southern and eastern parts of the fairway and there are a number of pilot programs underway throughout the basin, that are expected to be completed within the next 6 months.

Canadian Superior Energy Inc. ("Canadian Superior") - (AMEX:SNG)(TSX:SNG) of Calgary, Alberta announced on January 28 two new natural gas discoveries in Western Canada in the Watts and Craigmyle areas of east central Alberta. The new wells are located at LSD 01-27- 30 -16W4 and LSD 11-5-32-18W4 and have been AOF tested 11.2 mmcf/d and 6.5 mmcf/d, respectively. It is expected that the wells will be tied in for production within the next 30 days. These wells are in addition to 12 wells successfully drilled by Canadian Superior in the Drumheller area during the past six months.

"Canadian Superior has been conducting an active drilling program in the Drumheller area and east central Alberta over the past several months and the two new gas discoveries represent an extremely successful drilling program for the Company", Company President Greg Noval said in Calgary. In total, the Company has drilled 14 wells in the area since the Drumheller area properties were acquired from El Paso Oil & Gas Canada, Inc. having established a success rate of 93% comprising of four oil wells, nine gas wells and one well abandonment.

The Company is maintaining an extremely active developmental drilling program in the area this winter, and in addition, Canadian Superior is proceeding ahead with high impact exploration plays in the Windfall area of west central Alberta and East Ladyfern area of northwestern Alberta. Plans are currently underway for the Company to spud an exploration well located in the Windfall area targeting the Upper Mannville and Gething formations at LSD 07-33-60-14 W4M. Also in the East Ladyfern area, the Company is just completing the acquisition of 25 square miles of high resolution 3-D seismic. This complements the extensive seismic data acquired and shot by Canadian Superior updip from the main Ladyfern field on the Slave Point carbonate bank during the fall of 2001 and winter of 2002, which has identified multiple Slave Point natural gas opportunities on the Company's extensive holdings which appear to be analogous to the main Ladyfern field and other major pools in the immediate area.

The first well of the Company's two natural gas discoveries, announced in April 2003, located on the Company's East Ladyfern natural gas play in northwest Alberta is scheduled for testing shortly in February. This bodes well the Company which has a strong acreage position in the area; comprised of 22 contiguous sections of land, located approximately 35 kilometers (22 miles) east southeast and updip of the main Ladyfern gas field.

Furthermore on the East Coast, Canadian Superior is pleased to advise that the Gorilla V jack-up drilling rig has completed drilling the main hole section (the 311 mm (12 1/4 inch) hole section) of the Canadian Superior El Paso "Mariner" I-85 well, drilling the well in record time, to a depth of 4,526 meters (14,849 feet); and has just completed running the 273 / 251 mm (10 3/4, 9 7/8 inch) immediate casing string from surface to the full current depth of the well. Current operations include the completion of various cementing operations and tasks in preparation to "drill out" below the casing shoe.

Drilling will then further proceed in the remaining 216 mm (8 1/2 inch) hole section of the well to total depth. The "Mariner" I-85 well is a high pressure high temperature well that is one of the deepest wells that will be drilled this year in North America and it is proceeding ahead on schedule, and will take about another four weeks to drill to its targeted total depth of approximately 5,600 meters (18,370 feet) at a total budgeted cost of U.S. $30 million. Testing and evaluation of the well will then take place upon the well reaching its targeted total depth which should take approximately another two weeks thereafter to complete.

The Canadian Superior El Paso "Mariner" I-85 exploration well, which has shown encouraging drilling results to-date, is located approximately 290 kilometers (180 miles) southeast of Halifax, Nova Scotia. To date, drilling has confirmed the Company's seismic/geological interpretation for the prospect, with the 'Mariner' I-85 well being over 100 meters (328 feet) structurally higher than the nearby significant discovery well at "Arcadia" J-16. Mike Coolen, Canadian Superior's Director, East Coast Operations said today: "Significant gas shows and early indications of the higher temperatures and higher pressures at "Mariner" I-85 appears to confirm that the nearby proven reservoir gas system extends into this prospect and this bodes well for the next section of the well where primary natural gas targets are anticipated."

Three large "world-class" prospects, with estimated potential reserves of 2.5 tcf of natural gas have been identified for drilling on the "Mariner" block (EL 2409) utilizing high-resolution seismic. The block encompasses a total area of 101,800 acres and directly offsets five significant discoveries near Sable Island including the 1.6 tcf Venture natural gas field. The "Mariner" well is a High Temperature High Pressure (HTHP) well, drilling to a total depth of approximately 5,600 meters (18,370 feet), utilizing the latest in drilling technology and it is evaluating one of the three large structures mentioned above, initially targeting 1.2 tcf of natural gas reserves identified on the first structure which has an estimated potential present value - P.V. 10% of Cdn. $1.8 billion.

El Paso Oil & Gas Canada, Inc., an indirect subsidiary of El Paso Corporation (NYSE:EP), is participating in the drilling of the "Mariner" Prospect by paying 2/3 of the costs to earn a 50% interest in the "Mariner" Prospect, with Canadian Superior retaining a 50% interest in the Block and paying 1/3 of the costs related to the "Mariner" test well. The Rowan Companies, Inc.'s ("Rowan" - NYSE: RDC) Rowan Gorilla V jack-up drilling rig, one of the largest new generation jack-up rigs in the world has been contracted to drill the well. This first "Mariner" well being drilled to the north of the eastern tip of Sable Island on the Scotian Shelf is only about nine kilometers (5 1/2 miles) northwest of Sable Offshore Energy Project's Venture natural gas producing field. This well is one of the deepest wells to be drilled in Canada over the next several months and it is located on Exploration License EL 2409, acquired by Canadian Superior in November 2001 for a work expenditure bid of Cdn. $15.5 million.

Canadian Superior is a Calgary, Alberta based oil and gas exploration and production company with operations in western Canada, offshore Nova Scotia and offshore Trinidad. The Company is one of the largest acreage holders offshore Nova Scotia, with interests in 1,293,946 acres offshore Nova Scotia (See: Canadian Superior's website at www.cansup.com to review Canadian Superior's "Marquis, Mariner, Mayflower, Marauder and Marconi Offshore Projects" and to view the "Table of Major Offshore Nova Scotia Acreage Holders" and "Offshore Nova Scotia Maps", to review information on the Company's Western Canadian operations and for information and detailed maps regarding Canadian Superior's new Trinidad "Tradewinds" Project).

2. ASIA

INDIA

RasGas Managing Director Jerry J Wolahan, addressed Qatar's role as India's natural gas supplier in a presentation given at the eighth session of the Fifth Indian Oil and Gas Conference, (IOGC).

Stressing the issue of regional cooperation, Wolahan stated that his company is "the natural partner" for India's petrochemical companies.

"The first LNG delivery to India from RasGas will take place later this month. Qatar's unmatched gas reserves would ideally meet India's growing petrochemical demands," he announced.

In addition to its SPA with Petronet of India, RasGas has long-term sales and purchase agreements (SPAs) with leading petrochem companies in the US, Europe, India, Korea and Taiwan.

He also briefed the audience on the substantial growth in LNG production that the company had witnessed in recent years rising from 3.3 million tons per annum (mtpa) in 2000 to 6.6mtpa in 2003. With the recent SPA with Edison Gas of Italy and Endesa Generacion of Spain and the Heads of Agreement signings with the Chinese Petroleum Corporation (CPC) as well as ExxonMobil for the supply of Qatari LNG to the US market, RasGas' LNG output will reach 36.6mtpa by the end of the decade.

Commenting on the scale of these agreements and the rapid rise of RasGas' LNG production, Wolahan said that despite these huge long-term volume commitments, if we only consider the Petronet agreement, during the lifetime of the initial SPA representing a total volume of 125 million tons of LNG or 1,950 cargoes, less than 0.01 per cent of the North Field reservoir would be depleted during this time. These vast natural reserves ultimately place Qatar at the forefront of gas supply nations."

Highlighting RasGas' capability and resources to meet new market demands, Wolahan said currently RasGas is progressing with five projects such as Train 3, a 4.7mtpa capacity train scheduled for completion in February 2004; Train 4, a 4.7mtpa capacity train scheduled for July 2005; the Helium Refinery project scheduled for July 2005; the Pipeline Sales Gas Unit with a capacity of 744 Mscfd, scheduled for October 2005 and the NGL extraction unit, which is planned for January 2006.

"In addition to this active construction, RasGas' train 5 (4.7mtpa), two large LNG trains 6 and 7 (combined capacity of 15.6mtpa) and additional pipeline sales gas projects were in the planning stages."

Gas Authority India Ltd (GAIL) announced its quarterly results recently. GAIL`s (Q, N,C,F)* 9-month net period has moved up 15 per cent to Rs.1239 crore. The EPS for the year ending March`03 is Rs.19.38.

Meanwhile, the stock price has moved down from Rs.240 in the current market down turn to Rs.219 levels. It is interesting to compare the steady performance of the company as revealed in the following figures with its stock price performance. EPS is steadily growing and is expected to grow by 20-25 per cent year over year if not slightly higher as the figures reveal.

The company has plans to more than double its gas pipe network. It earns 50 per cent of its profit from gas distribution. With India planning to import gas and fertilizer and power companies set on an expansion spree, the future outlook for Gail is very good, if not excellent.

Oil and Natural Gas Corporation (ONGC) is planning a major expansion by setting up two joint ventures to assist it in its downstream operations and in the acquisition of modern vessels, tankers and aircraft.

In a presentation to Petroleum Minister Ram Naik, the Chairman and Managing Director of ONGC, Subir Raha, pointed out that the corporation was facing a large number of problems in entering the marketing of petroleum products.

The major among them were the lack of manpower to handle the marketing operations and the scarcity of land in urban areas to set up retail outlets.

He said since the corporation could not afford to recruit fresh graduate trainees and build them up for 15 to 25 years to take up the marketing operations, OVaL would enable the company to recruit skilled and experienced executives (employed as well as retired) at market-oriented compensation benchmarked to the practices prevailing in its subsidiary, Mangalore Refinery and Petrochemicals Limited.

OVaL will also help ONGC purchase or lease sites for outlets and depots at market-related prices. This implies that for these sites, the corporation may even pay premiums over government valuations.

Regarding OPaL, Raha said ONGC owned 38 vessels and chartered more than 90 vessels, excluding rigs. ONGC vessels are operated under operation and maintenance (O&M) contracts. It owns three and charters more than 15 helicopters.

Operating expenses on the use of barges and ships for the operations relating to survey, supply, support, services, security, production, construction and transportation exceed Rs 1,000 crore every year.

He said ONGC’s operations were expanding fast because of largest-ever offshore service, deep-water exploration and development of three new fields.

However, the corporation has been facing problems because the right of first refusal is available to the owners of vessels and aircraft of Indian registry assuring them of contracts by matching L-1 prices.

The CMD said since ONGC’s performance was dependent on assured and sustained availability of cost-effective, operationally efficient, technologically modern vessels, tankers and aircraft maintained by professionals, OPaL is envisaged to take care of these constraints.

OPaL is expected to assist the corporation in the induction of professionally skilled and experienced persons and in the acquisition of modern fleet, improve fund management and profitability, and provide safety, reliability and adequacy.

Raha made it clear that though OPaL will not have exclusive right on ONGC’s business, it will provide ONGC the choice of on-and-off balance sheet financing as required.

MALAYISIA

Engineering group Ranhill Bhd, which has aspirations to become a global oil and gas player, is close to acquiring a major company in that sector, according to sources.

They declined to elaborate on the proposed acquisition, saying it was still under negotiation.

But the sources said Ranhill was confident of successfully acquiring the company soon based on its experience and record in the oil and gas industry.

"An announcement will be made once Ranhill has received the necessary letters of approval. The company is still waiting for the green light," one source said.

In another development, Ranhill, which has an order book of about RM1.5bil, is said to be poised to secure new contracts in the oil and gas sector.

"Ranhill is waiting for letters of intent for new oil and gas contracts. Announcements will be made once the contracts are secured. The company is waiting for the right time to do so," a source close to Ranhill told StarBiz.

It is believed the new contracts that Ranhill is bidding for would be different from the typical engineering and construction jobs that it has so far done for major oil and gas players in the world.

The new contracts – if and when secured – would herald the start of a new era for the group in the oil and gas sector, which is booming in the wake of new oil finds and the global economic upturn, analyst say.

The group had announced to the exchange on Jan 21 that it had been invited to participate in the US$3.56bil Papua New Guinea-Australia gas pipeline project.

In its statement to the exchange, Ranhill said it had been invited by PNG's Minister for Petroleum and Energy, Sir Moi Avei, to buy a portion of the PNG government's 22.5% stake in the gas pipeline project.

The project includes a 2,500km gas transmission system and is expected to start in 2007. Ranhill said it might also take part in commercial opportunities related to the sale of gas under the project as well as explore existing oil projects in PNG and in new areas.

Oil Search Ltd owns 51.37% of the PNG-Australia gas pipeline project, which is operated by ExxonMobil Corp and intended to pipe gas from PNG to eastern Australia.

Daewoo International Corp., Seoul, and Korea Gas Corp. discovered 4 to 6 tcf of recoverable gas on Block A-1 in the non-producing Rakhine basin shelf in the Bay of Bengal off northwestern Myanmar and plans to pursue other similar objectives on the block.

The Shwe-1/1A wildcat is the first wildcat drilled in the Plio-Pleistocene section off northwestern Myanmar and the country's first offshore discovery since Yetagun gas field in the Gulf of Martaban 12 years ago, Daewoo said. This is Daewoo's first well on its first project as operator.

Based on the first well results and 2D seismic analysis, the new field's areal extent is estimated at 14,900 acres. In view of the high productivity of the gas sands with 24% porosity and 190 md permeability, the expected daily production is to exceed 100 MMcfd.

Several seismic anomalies in Block A-1 appear similar to the one at the Shwe discovery, indicating considerable upside exploration potential, Daewoo International said.

The discovery well is several dozen kilometers south of southernmost Bangladesh.

Daewoo said intensive appraisal drilling will begin in November 2004 following a large 3D seismic survey in March and April before monsoon season.

Well and reservoir details

The Shwe-1A well, a sidetrack well of Shwe-1, was drilled to 10,210 ft in 361 ft of water.

The sidetrack penetrated a 191-ft gross gas interval that produced gas at a rate of 32 MMcfd by drill stem test of main sand unit.

Shwe-1/1A was originally programmed as a directional well. After encountering serious drilling problems, Daewoo International decided to drill a vertical well, Shwe-1.

After drilling vertically to 10,102 ft with disappointing results at the first three objectives, the sidetrack, Shwe-1A, was drilled to penetrate the deepest and most promising objective at sole risk by Daewoo International and Korea Gas. The larger block group of companies originally had participated in the well (OGJ Online, Dec. 19, 2003).

As a result, thick gas sands with a total net pay of 90 ft were discovered between 9,611 ft and 9,802 ft in the sidetrack. The discovered sands are 930 ft from the vertically penetrated location.

Shwe, or "gold," is a stratigraphic trap drilled at the fringe of a submarine fan system in the Bengal Fan. It is expected that the pay sands will thicken toward the central part of the fan system.

Daewoo owns a 60% stake in Block A-1. In addition to Korea Gas 10%, the non-operating partners are ONGC Videsh Ltd. 20% and GAIL (India) Ltd. 10%.Angolan Oil minister, Desidério Costa, said today in Lobito, central Benguela province, that the start of the construction of the future refinery is pending an approval of the project by the Cabinet Council.

Myanmar is likely to award at least one offshore oil and gas exploration block and refinery revamp project to Indian firms even as New Delhi is exploring the possibility of piping the huge gas reserves discovered in offshore Myanmar earlier this month.

Myanmar may award the prospective A-3 block in the Bay of Bengal to ONGC Videsh Ltd besides giving Indian Oil Corp a $116 million contract for revamping its old refinery.

"They (Myanmar government) have agreed to finalize the agreement for A-3 block as early as possible," Petroleum Minister Ram Naik told reporters after meeting his Myanmarese counterpart Lun Thi in New Delhi.

Block A-3 lies on the southern edge of Block A-1, where 4 to 6 trillion cubic feet of gas reserves was discovered earlier this month. Block A-3 is said to have both oil and gas potential while A-1 is believed to be more gas-prone.

The proximity of the two production-sharing contract areas would offer the potential to develop finds jointly or as tie-backs utilizing a common export pipeline.

"We are exploring if gas from Block A-1 can be brought to India," Naik said.

Petroleum secretary B K Chaturvedi said state-run gas firm Gas Authority of India will carry out a feasibility study to explore laying pipelines - an undersea line connecting the find to eastern cost or an onland version traveling through Bangladesh into the North-East or West Bengal.

India has also offered exporting surplus diesel from Numaligarh Refinery Ltd to Myanmar, he said adding Rangoon was likely to award a $116 million oil refinery revamp contract to IOC.

ORIGIN Energy is close to signing a deal to take part in the $NZ200 million ($173.9 million) development of the Kupe oil and gas field off New Zealand's Taranaki coast.

The investment will be Origin's first overseas foray into upstream exploration and production development.

Origin spokesman Tony Wood confirmed negotiations were at an advanced stage to buy into Kupe through the NZ government-owned electricity generator, Genesis Power.

Earlier, Genesis had bought the New Zealand Government's direct 11 per cent stake in the project but the power utility has no expertise in gasfield development or operation.

It is understood Origin has beaten off the Adelaide-based Santos in the bid to take up to half of Genesis's stake.

The Kupe field, estimated to contain 260 billion cubic feet of gas and 15 million barrels of oil, is targeted for early development with the rapid decline of the 10-fold larger Maui field.

An estimate prepared for the Asia Pacific Economic Co-operation Forum suggests that at current consumption, New Zealand's gas reserves are expected to last only until about 2014, with the Maui field possibly running out as soon as 2007.

Genesis plans to have Kupe producing by 2007 and will be its customer, using the gas in a combined cycle generating plant at Huntly.

An announcement could be made before the end of month.

Origin, which is in joint ventures around the Pacific and in PNG and New Zealand to sell bottled LPG, believes its experience in the $450 million Yolla development has given it expertise in developing small offshore gas fields.

Yolla, in which Origin is operator and has a 37.5 per cent stake, is about 150km offshore in Bass Strait and is estimated to contain 256 billion cubic feet of gas.

It supplies the BassGas project which aims to meet 10 per cent of Victoria's gas demand for 15 years through supplying about 20 billion cubic feet a year.

Origin has contracted to buy 95 per cent of the project's production.

Unlike its major Australian competitors, Origin's business strategy includes taking a stake in the downstream market opportunities for the gas it develops.

The minority 19 per cent stake in Kupe is held by New Zealand Oil and Gas which discovered the field in 1986.

Origin Energy believes there are similarities between the Yolla development and the plan to exploit Kupe that would lead to a ready transfer of experience.

London-based independent Premier Oil PLC has received a license from the Philippines Department of Energy to explore a 10,800 sq km area in the Ragay Gulf, off Luzon, Philippines. The initial work will consist of technical studies and a seismic survey, with which Premier will define specific drilling targets for exploration drilling.

Premier said it would assign a 42.5% ownership interest in the license to Pearl Energy and 15% to Philippines National Oil Co.

Premier said the Ragay Gulf is highly prospective for oil "with numerous leads in a variety of play types that have already been identified."

"We believe this area has been overlooked despite the existence of oil seeps, and recent seismic data supports its prospectivity," said Premier CEO Charles Jamieson.

The Viet Nam Oil and Gas Corporation (PetroVietnam) set a target of tapping 17.5 million tons of crude oil and 5.74 billion cu.m of gas in 2004. These goals were revealed at the corporation's conference to initiate its 2004 plan held in Ha Noi, January 12. In 2004, PetroVietnam aims for seeking more foreign investment for the exploration and exploitation work in newly discovered oil fields offshore while calling on local investors to conduct self-exploration in the Red river delta and the country's continental shelf.

The corporation will try to seek opportunities in oil and gas projects in other regions of the world in addition to implementing the existing contracts abroad. It was committed to improving on-shore services including technical, financial and insurance services in a bid to expand its markets regionally.

Intensive efforts will be made to push up major projects such as the construction of the Dung Quat Oil Refinery and the Gas-Electricity-Nitrogenous Fertilizer Complex, which will help create a firm foundation for the corporation to develop into a strong economic group and operate more efficiently in other fields, it said at the event.

In 2003, the Viet Nam Oil and Gas Corporation produced 17.62 million tons of crude oil and pumped 3.052 billion cu.m of gas, 566 million tons of crude oil and 882 million cu.m of gas more than the 2002 figures, respectively. The corporation exported 17.18 million tons of crude oil for US$3.82 billion

Statoil ASA, operator of the Norwegian Sea Åsgard license—once called "the most daring and complex subsea project ever launched"—plans to increase oil recovery by 26 million bbl from Smørbukk, one of Åsgard's three fields.

Phase I of the 1.8 billion kroner expansion program includes the drilling of two additional wells through a new, five-slot Q subsea template on the Smørbukk South deposit. The wellstream will be piped in two new flowlines to the Åsgard A floating production, storage, and offloading vessel.

Phase II of the project will include a gas injection well drilled through the existing R gas injection template on Smørbukk South.

FMC Technologies, Houston, will supply subsea production systems, including three trees and associated structure, manifold, and production controls system, and Transocean Offshore Inc.'s Transocean Searcher drilling and completion unit will drill the three wells, spudding the first in April (OGJ Online, Jan. 19, 2004). Production is scheduled to begin in early 2005.

Statoil said two wells in the 52-well Åsgard main drilling program also have yet to be drilled, with the Stena Don semisubmersible currently spudding the penultimate producer. The final well in that program also will be drilled through the new Q template.

Boston's Energy Security Analysis group said the long-running contest between Japan and China over how Russia shifts its Siberian oil to market is essentially over, the Oil & Gas Journal reported January 20.

Responding to Russia's desire to ship more oil from its vast Siberian fields, Japan joined Russia's state-owned Rosneft to propose a line to Nakhodka, a Russian port on the Pacific coast.

China, on the other hand, had joined privately held Yukos to propose a line to the Chinese city of Daqing.

"Yukos' mounting troubles, particularly the $3.3 billion taxes bill, have shifted the firms' priorities from expansion to survival. Plus, they indicated readiness to supply their crude to Nakhodka if the pipeline would be there," said Yulia Woodruff, ESAI Russian oil analyst.

Japan wants Russian crude oil to cut its dependence on Middle Eastern imports. Japan also worries about increased competition with China for oil. China became a net importer of oil in 1993 and in the coming decade will likely overtake Japan as the world's second-largest importer of oil.

Rosneft opened a port near Arkhangelsk from which the company plans to export 2.5 million tons per year of crude oil, enabling it to export oil to Europe and the United States.

The port's crude-oil terminal will be expanded to handle as much as 4 million tons per year at an unspecified date, Rosneft said in a presentation at the port, which is 10 kilometers north of Arkhangelsk. The port has been exporting oil products since 1978 and handles 2 million tons per year of diesel and other fuels.

The Arkhangelsk route "doesn't depend on Transneft,'' Rosneft chief executive Sergei Bogdanchikov said after the new terminal was opened.

LUKoil, Yukos and TNK, the country's top three oil producers, are planning a new pipeline to Murmansk that could ship crude to the United States.

The supervisory council of the Sakhalin-2 major oil and gas project has approved the spending of 2.5 billion dollars this year to expedite the construction of the main oil and gas pipelines from the north to the south of the island.

The first pipe welding on January 23 marked the official beginning of the work to implement the Sakhalin-2 project’s part related to the construction of the surface pipeline system.

Russian Starstroi Company will begin the construction of two 800-km-long pipe strings that will take two years and 1.2 billion dollars to complete.

"This event signifies a stride forward in the implementation of the second phase of the project that is grandiose in scale – the construction of the main pipelines through which oil and gas will be pumped to the south of the island for refining and exporting to buyers in the Asia-Pacific region and beyond," said Sakhalin Energy CEO Steve McVeigh.

The Russian oil giant LUKoil has received a proposal to join a consortium to participate in a tender for the privatization of the Romanian oil and gas company SNP Petrom, Nikolay Cherny, the president of LUKOIL Downstream Romania, told journalists on January 21. He did not specify what company had made this proposal but noted it was not Gazprom.

Currently, seven international companies have received the right to participate in the tender for selling a 33.34-percent stake in SNP Petrom, among them are Russia's Gazprom, the US Occidental Oil and Gas, the Austrian OMV and others.

SNP Petrom staffs more than 60,000 people. It produces about 7 million tons of oil and 6.1 billion cubic meters of natural gas a year.

LUKoil and ConocoPhillips are planning to jointly develop oil fields in the Timan-Pechora oil province in Russia's north.

LUKoil also said it planned to invest up to $200 million in its newly acquired Saudi Arabian gas project over the next five years as it believed in its high potential.

"We are planning to sign a final agreement in March, which will determine the total potential investment in the project. So far we are planning to spend $200 million on exploration," vice president Leonid Fedun said.

National Iranian Oil Company and its subsidiaries in the Caspian Sea are almost in final stage of talks with bidders on the development of oil and gas blocks in the oil- and gas-rich sea, IRNA reported from Tehran.

An informed source said on condition of anonymity on January 28, that a contract might soon be concluded for a project to develop such blocks as block eighth in the Caspian.

Iran has launched three-dimensional seismographic operations in the southern sector of the Caspian Sea, thus indicating its firm determination for development, exploration and production of oil and gas there.

Based on information available, Iran is to develop certain blocks in southern waters of the Caspian Sea in cooperation with other oil companies.

IRAQ

Japanese companies are involved in talks with senior officials of the Iraqi Oil Ministry to secure contracts over oil and gas fields in Iraq.

According to a January 5 report by the Dow Jones Newswire, a Japanese consortium headed by Mitsubishi Corporation is seeking the rights to develop the one-billion-barrel Al Gharaf oilfield in southern Iraq.

Interest in the field dates back to the late 1980s, when Iraq was one of Japan’s main suppliers of energy and Japan was one of Iraq’s largest trading partners. The 1991 Gulf War and the subsequent UN economic sanctions put an end to both the Al Gharaf deal, as well as Japan’s trading relations with Iraq. The US-led occupation is now providing Japanese companies with opportunities to revive their influence.

Mitsubishi signed a contract last year for crude oil purchases from Iraq’s State Oil Marketing Organization, which is under US control. The Japanese company has begun importing up to 40,000 barrels of Basra Light Crude a day.

Alongside the potential contract for the southern oilfield, Japanese firms are also involved in discussions with US company, KBR—the engineering and construction subsidiary of Halliburton—to develop the major Akkra gas fields in western Iraq.

The Japanese government, in addition to its commitment to deploy troops, agreed last year with the Bush administration to provide up to $US5 billion in reconstruction and humanitarian aid to Iraq over four years. In December, Koizumi also made a pledge to James Baker, Bush’s special envoy on Iraqi debt, to write off up to $7 billion owed to Japan by Iraq, with Japanese taxpayers footing the bill.

Japan had previously stated that it would not write off the debt on the grounds that Iraq would be in a position to repay it from future oil export revenues. The aid money and debt cancellation, however, has bolstered corporate Japan’s position at the bargaining table as contracts over Iraq’s resources are parceled out.

Some of the financing for the Al Gharaf and Akkra deals is even expected to come from the Japanese government’s aid.

Koizumi has pushed ahead due to the strategic importance of the Middle East to Japanese capitalism. Japan currently imports over 83 percent of its oil from the Middle East, relying at present on the United Arab Emirates, Saudi Arabia and Iran for the bulk of its oil. Some analysts have predicted that Japanese dependence on Middle Eastern oil could soon reach 100 percent if it does not get access to new supplies in Russia or Central Asia.

In the short term, Koizumi’s government sees its backing for Bush’s foreign policy as a means of strengthening Japan’s access to energy resources in the Middle East and gaining lucrative business contracts. More fundamentally, it has been used to reassert Japan’s position as a military power.

The interests of the US and Japan do not always coincide, however, and Koizumi’s assertion of Japan’s independent economic interests in the Middle East could become a source of conflict with the Bush administration.

This potential conflict is evident in Japan’s proposal to press ahead with the development of a lucrative oil project in Iran—a country that the Bush administration has branded as part of an "axis of evil". Negotiations are continuing between Tokyo and Teheran over a $2 billion agreement to develop the Azadegan oil fields, said to hold one of the largest reserves of untapped oil in the world.

Bidding in Kuwait's controversial plan to bring in international oil companies to develop its northern oilfields is due to start in the second half of this year, Kuwait Oil Company (KOC) said in remarks published on January 25.

Bader Al Zuwayer, KOC's public relations and information manager, told the Arab Times the legal contract for the multi-billion-dollar Project Kuwait had not been finalized yet 'but has progressed to an advanced stage'.

'The Northern Oilfields Project is an important national project and the process of receiving approvals at different levels required will take some time,' he said.

'We expect that all necessary approvals will be obtained and that the bidding process will commence some time in the second half of 2004.'

In November, Nader Sultan, deputy chairman and CEO of Kuwait Petroleum Corporation (KPC), KOC's parent, said the three oil major-led consortiums vying for the project could be invited to bid before the summer.

The three groups of companies which pre-qualified are led by ExxonMobil Corp, ChevronTexaco and BP.

Some parliamentarians oppose bringing foreigners into Kuwait, which has a 10th of global petroleum reserves.

But Zuwayer said the companies would not be given ownership or similar rights to Kuwait's oil and gas resources, adding that the legal basis for the project would be a services contract and the oil companies would receive cash.

The contract required these firms 'to bring their best technologies and practices to Kuwait to enhance development of northern oil fields and improve long-term recovery', he added.

'Kuwait recognizes that the contract must be reasonably attractive to the IOC's (international oil companies) if they are to be expected to bring the benefits of their technologies and experience to Kuwait,' Zuwayer said.

This was vital since key north Kuwait reservoirs were technically challenging and hadn't been developed to their full potential, he said.

Zuwayer declined to give a figure for the cost of the project, which has been put as high as $7 billion.

Industry sources say the winning consortium will be involved in raising output from the northern fields to about 900,000 barrels per day (bpd) from around 450,000 bpd at present.

Zuwayer said the development activity associated with raising production levels to 900,000 bpd would benefit the economy as service providers and suppliers would be asked to meet the needs of the project.

Sheikh Mohammed bin Ali Al Qatabi, the Minister of State and Governor of Dhofar formally inaugurated the 68 million Omani riyal Salalah gas pipeline at Raysut Industrial Estate on January 10.

Khalifa Al Hinai, adviser to the minister of oil and gas and board chairman of Oman Gas Company (OGC), said at the opening of the gas pipeline project that it would hugely benefit the economy of the Sultanate's southern region in particular.

He said the pipeline would help expand industrialization and create new jobs.

Suleiman Al Balushi, the OGC acting executive president, said the project was part of the company's expansion plans in implementation of royal directives to diversify sources of national income.

He said OGC had signed a five-year contract with a Canadian energy services company to undertake operation and maintenance of gas transporting facilities and prepare various technical systems and procedures.

Dr Mohammed bin Hamad al Rumhi, the Minister of Oil and Gas, said the Salalah gas pipeline was the start of a gas network the government planned to implement throughout the country for economic and environmental reasons.

The minister explained gas provides cheaper source of energy in the regions and is friendly to the environment. The 700-km Salalah gas pipeline, which is 24 inches in diameter, has a capacity to produce 4 million cubic metres a day.

It will provide the necessary energy for power plants in Dhofar governorate, industrial facilities in Raysut and Raysut Cement Factory. A number of local and international banks contributed to financing the project.

The track for the pipeline from Saih roll, in central Oman, to Dhofar governorate was determined to prevent damage to irrigation systems, farms and pastures and curb any negative effects on sanctuaries and archaeological and historical landmarks.

Syria invited international companies to participate in a new round of bidding for oil and gas exploration and production deals, part of efforts to find new energy sources before existing fields reach maturity.

"The Ministry of Oil and Mineral Resources and Syrian Petroleum Company invite hereby the international oil companies for the first 2004 bid round to explore for oil and gas in Syria under production sharing agreements," said a tender statement, published in Syrian newspapers.

It said 14 blocks spanning 88,890 square kilometers were on offer in areas believed to contain undiscovered petroleum reserves.

Syria, which produces about 550,000 barrels per day of crude oil with an estimated local consumption of 330,000 bpd, is seeking to improve production techniques, explore more widely for oil and gas and cut oil use in power generation.

The US Energy Information Administration has said Syria could become a net importer of oil in a decade. But Syrian Oil Minister Ibrahim Haddad said in local media Syria would be self-sufficient in oil until 2020 if no new reserves were found.

Despite the threat of US sanctions over its alleged support for terror, Syria has signed a string of 25-year exploration and production contracts with foreign companies in the past year, including three American firms.

Those have generally set the state's share at 12.5 per cent of production with the remainder shared on a scaled arrangement.

The statement set the end of the working day on May 31 as the closing date for bids.

Qatar said it expects to be the world's biggest producer of liquefied natural gas (LNG) within the next two years.

First Deputy Prime Minister Sheikh Hamad bin Jassim bin Jabr al-Thani told CNBC television Qatar was now producing 15 million tons a year of the fuel but aimed eventually to raise this to 60 million tons.

Indonesia is the top LNG producer at the moment followed by Algeria. 'Within the next two years we will be number one (producer) in the world. Within the next five years we will be far ahead -- three, four times -- from the second in the world as a producer.'

Opec producer Qatar ranks as the world's third biggest holder of natural gas reserves after Russia and Iran. State oil company Qatar Petroleum and its international partners have said they plan to spend QR83 billion ($22.8 billion) over the next four years to develop the Gulf producer's energy industry.

Of this total Qatar plans to invest QR33 billion on LNG and pipeline projects and QR30 billion on refined/gas-to-liquid schemes.

Hamad said he expected around 20 million tons of LNG a year to go to the United States and approximately 10 million to Britain. Qatar would send LNG to other destinations including India, Taiwan, Korea and Japan.

Qatar Petroleum has several large gas ventures with oil majors, including ExxonMobil, ConocoPhillips and Total.

Saudi Arabia has awarded Russia's Lukoil Holdings rights to explore and produce natural gas, the second deal struck since the kingdom decided to open up its upstream gas sector to foreign investment.

In the first of three tender results, the Oil Ministry said Lukoil would explore and produce gas in 30,000 square kilometers of acreage, known as "Zone A", located near Ghawar, the world's largest oil field. It said Saudi Arabian Oil Company would hold a 20 per cent stake in the drilling and production joint venture.

The value of Lukoil's 40-year agreement, to be signed in March, was not disclosed.

An Oil Ministry statement said tenders on two other blocks of gas acreage -- Zone B and Zone C -- will be announced January 27 and 28.

Saudi Arabia's opening up of its prized upstream natural gas sector came after negotiations failed in the late 1990s over the Saudi Gas Initiative, an integrated investment scheme coupling upstream gas exploration and production with downstream utilities and petrochemicals investments led by ExxonMobil Corp and Royal Dutch/Shell.

Last summer, Shell and Total won rights to set up a joint-venture with Saudi Arabian Oil Company to explore and produce gas in the southern deserts of the empty quarter, or Rub Al Khali in Arabic.

Lukoil, Russia's biggest integrated oil company, produces about one-quarter of Russia's oil output with about 19.3 billion barrels of oil equivalent reserves, half in western Siberia. The company has projects in the Caspian, Central and South America.

Lukoil is also fighting to keep oil exploration and development contracts it had signed oil contracts in Iraq before Saddam Hussein's regime in Baghdad was toppled.

Russia rivals Saudi Arabia as leading oil producer and threatens the Organization of Petroleum Exporting Countries' dominant position.

Opec has been gradually losing market share to the countries of the former Soviet Union as they hold back production to defend high prices.

Saudi Arabia has been actively courting Russia to bring them in line with the group's policies.

The two signed an energy co-operation agreement in September.

Russia's oil major LUKOIL said on January 28, it planned to invest up to $200 million in its newly acquired Saudi Arabian gas project over the next five years as it believed in its high potential.

"We are planning to sign a final agreement in March, which will determine the total potential investment in the project. So far we are planning to spend $200 million on exploration," LUKOIL Vice President Leonid Fedun told Reuters.

"If reserves are confirmed, the project will meet our profitability targets."

LUKOIL has said it is aiming to participate in a project with the return on investment of over 15 percent.

LUKOIL joined this week a small club of foreign energy firms with a foothold in Saudi Arabia, announcing a deal to find and pump gas in the world's top oil producing nation from the project known as Block A, covering 29,900 square kilometers.

The project is small by the standards of Saudi Arabia's immense hydrocarbon reserves, but it creates a potentially useful new link for producer cartel OPEC's leading member with Russia, the world's number two oil exporter.

Other gas projects' winners this week included Italy's ENI <ENI.MI>, Spain's Repsol YPF <REP.MC> and China's Sinopec.

The results, following last year's exploration and production deal with European majors Royal Dutch/Shell and Total, leaves a notable absence of U.S. firms in Saudi Arabia's upstream gas ventures.

While its vast oilfields remain in state hands, Riyadh wants foreign investment in the gas sector to fuel surging consumption. The gas auction follows two years of direct negotiations with multinationals for three huge industrial projects that collapsed last year.

LUKOIL President Vagit Alekperov told reporters in Yekaterinburg he believed that chances to discover big oil or gas reserves on the Saudi block were 70 percent.

"This is a very lucrative field. Some geological works have been already done and hydrocarbon reserves potential confirmed," he said.

LUKOIL has been Russia's oil sector leader over the last decade, although it recently ceded its top position to YUKOS.

LUKOIL is one of Russia's most active oil majors abroad. One of its ultimate overseas targets is to regain a giant West Qurna oilfield in Iraq, granted to the firm by the government of former Iraqi President Saddam Hussein in 1997.

Saddam's government scrapped the deal in late 2002, but LUKOIL has said it considers the deal still valid. Fedun and Alekperov confirmed that LUKOIL's representatives planned to travel to Baghdad in February.

In a major upstream gas offering, Saudi Arabia's Ministry of Petroleum and Mineral Resources has awarded three contracts to international oil companies (IOCs) to explore and develop non-associated natural gas in a 121,000 sq km section of the country's Rub' Al-Khali basin. International companies from Europe, Asia, and the US bid on the three areas.

Each successful bidder will form a separate exploration and production company, in joint venture with Saudi Arabian Oil Co. (Saudi Aramco), which will hold a 20% share.

Contract Area A, which consists of a 30,000 sq km, was awarded Monday to the Russian oil company OAO Lukoil, which will be operator.

Contract Area B, a 39,000 sq km section, was awarded to Sinopec International Petroleum Exploration & Production Corp. a unit of China Petrochemical Corp. Sinopec will be operator.

The 52,000 sq km Contract Area C, the last of the three areas bid, was awarded to a joint venture of Italian company ENI SPA and Spanish company Repsol-YPF SA. Operator ENI will hold a 50% stake and Repsol-YPF 30.

The three sections, located in a southeastern desert area known as the Empty Quarter, have been practically unexplored to date. If gas is found in sufficient commercial quantities, it will be used in the Saudi Arabian domestic market as feedstock for petrochemical plants, power generation, and water desalination, Saudi Aramco said.

The upstream contract packages were developed for bidding after a $25 billion natural gas development plan involving three core venture projects—initiated 4 years ago with IOCs led by ExxonMobil Corp. and Royal Dutch Shell—fell through last year from the sheer complexity of deals that included upstream, midstream, and downstream aspects (OGJ Online, June 10, 2003). Afterwards, it was decided that the projects be simplified and rebid separately, with Saudi Aramco taking a larger role in the negotiations.

A month later, Shell's $4 billion deal, which originally contained exploration in huge Shaybah field in the Rub' Al-Khali basin, development of Kidan gas field, pipelines from Shaybah to natural gas treatment plants east of Riyadh, and construction of a petrochemical plant in Jubail, was revisited last summer (OGJ Online, July 16, 2003) and reconfigured.

Operator Shell (40% interest) and partner Total SA (30 %) signed an agreement in November to form a JV with Saudi Aramco (30%) to explore a 200,000 sq km area in Rub' Al-Khali. That company, the South Rub'al-Khali Co., based in Al-Khobar, plans to begin seismic acquisition activities and other exploration operations this year.

Commenting on the latest IOC contracts, Saudi Aramco Pres. and CEO Abdallah S. Jum'ah said: "Saudi Aramco is very pleased to have another opportunity to partner with international oil companies. We look forward to putting forth our best efforts to leverage the kingdom's natural resources. We recognize the importance of natural gas to the future of the country, and it's gratifying to. . .participate in this endeavor."