OGJ Newsletter

July 1, 2002
As anticipated, the Organization of Petroleum Exporting Countries decided last week to keep its current oil production quota through September. OPEC members called for cooperation from other producers in curbing crude supplies "to minimize price volatility and maintain market stability."

Market Movement

OPEC extends production quota through September

As anticipated, the Organization of Petroleum Exporting Countries decided last week to keep its current oil production quota through September. OPEC members called for cooperation from other producers in curbing crude supplies "to minimize price volatility and maintain market stability."

But non-OPEC producers Russia and Norway, which went along with OPEC in curbing production for the first 6 months of 2002, now plan to increase oil production.

OPEC ministers will meet again Sept. 18 to reassess the market.

Demand driven

"The mood within OPEC is demand-reactionary rather than demand-anticipatory, and we expect that OPEC will only increase the official quotas in the face of a sustained high oil price or evidence that a demand increase has already occurred," said Tyler Dann, energy analyst for Banc of America Securities LLC.

Dann said, "A simple scatter plot of prices and production show that OPEC is effective at varying output with price levels in an attempt to keep the basket price within its stated range of $22-28/bbl (see graph). In the current environment, where Russian production threatens to take a strong hold on market share, OPEC has a vested interest in remaining coordinated in its effort to sustain both prices and market share."

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He said, "Over the past year, OPEC has been 77% 'compliant' with official production quotas, a mere C+ by pure academic standards." That translates into 1.4 million b/d over the official production target of 21.7 million b/d.

However, Dann claims a more important factor, "albeit more difficult to quantify, is the level of communication and coordination" now evident among OPEC members.

OPEC's decision to roll over its quota was "based on the most risk adverse and hence highly pessimistic view of global (supply and demand) balances" in order to "put a floor under prices and defend the downside," said Paul Horsnell, head of energy research for London-based JP Morgan Chase & Co. "However, it does also mean that (potential market) surprises are biased in one direction, and that will be supportive to prices," he said.

Demand surprise?

The biggest potential surprise, Horsnell said, is that the International Energy Agency and other analysts might be seriously understating the possible increase of world oil demand in the upcoming third quarter.

Horsnell sees world demand for oil escalating to justify an increase of 1.6 million b/d in OPEC production in the third quarter. That compares with projections of 600,000 b/d by IEA, 500,000 b/d by OPEC, and 200,000 b/d by officials at the US Department of Energy. By the fourth quarter, Horsnell expects world demand will require an extra 2.6 million b/d from OPEC. That's up from estimates of 1.7 million b/d by IEA, 1.1 million b/d by OPEC and 900,000 b/d by DOE.

Horsnell noted previous second quarter demand estimates "are steadily being revised upwards." That, he said, "might lead one to expect that (third quarter) estimates would also go up. After all, the macroeconomic factors leading to an upside surprise in (the second quarter) also impact on (the third)."

But many forecasters are not making similar third quarter adjustments because they "seem unwilling to let go of a pessimistic view of demand," he said. "Indeedellipsethey may even be depressing (third quarter) numbers in order to compensate for the (second quarter) surprise and hence keep their annual forecast flat."

Horsnell also claimed that a June 21 report claiming that Petroleos de Venezuela SA (PDVSA) planned to increase its oil production was a deliberate lie planted to embarrass the Venezuelan government. The report, attributed to an anonymous PDVSA source, triggered a small decline in oil futures prices in New York and London.

Dann questioned whether it might have been "a trial balloon of sorts." Apparent cheating among OPEC members "may be more coordinated than might be evident on the surface," he said.

But Horsnell saw more sinister overtones. "Elements within (PDVSA) have been a major source of opposition to Venezuelan President Hugo Chavez," he said. "Their current agenda would appear to be to increase friction within OPEC...and generally to bring down oil prices in such a way as to weaken the Venezuelan government."

Industry Scoreboard

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Industry Trends

Natural gas prices have fallen faster in the US Rocky Mountain region than elsewhere in the last 3 months because of increased coalbed methane drilling and resulting pipeline bottlenecks.

That word comes from Raymond James & Associates Inc. analyst Wayne Andrews. Henry Hub gas prices have hovered at $3-3.50/Mcf, while Rocky Mountain gas prices have fallen to $1-2.50/Mcf.

Andrews says the good news for industry is that he expects the gas price differentials will narrow within 12 months because of pipeline expansion projects (see table).

But gas producers face bad news because there are not enough gas pipelines to transport all of their excess gas supply to other parts of the country.

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"This bottleneck in pipeline capacity then creates gas-on-gas competition between producers to sell gas into the pipeline system, resulting in discounted price realizations for their gas," Andrews said.

Before 2000, increasing export capacity from the Rockies and modest volume increases kept the differential mostly below 50¢/MMbtu. But a recent boom in drilling activity has caused the region's production to outpace its infrastructure expansion, amplifying the differential problem, he said.

The long-term solution is that midstream pipeline expansion in the Rockies should ultimately eliminate the differential problem, he said.

"The Rockies represent the single largest, untapped, onshore natural gas basin in the US. In other words, if producers expect to significantly increase production from an area over a long period of time, midstream companies must be 'incentivized' to build the pipeline to transport that production to market.

"Furthermore, the long-lived nature of the reserves in the Rockies should allow pipeline companies to capitalize their investment over a longer period of time, creating a higher return on investment. In fact, a number of midstream companies have already stepped up to build more export capacity," Andrews said.

Government Developments

CANADA'S OPTIONS to implement the Kyoto Protocol will not work, argues the Canadian Association of Petroleum Producers (CAPP).

During a federal government stakeholders' session on climate change policy in Calgary last month, CAPP provided a technical overview of its key arguments. It maintains that none of the four options outlined in a Federal Discussion Paper on Climate Change adequately address key issues.

These issues include competitiveness, investment confidence, regional and industry sector fairness, achievability of the Kyoto targets, and consumer impacts, CAPP said.

"With this type of detailed work, we are getting into specifics on policy," said CAPP Pres. Pierre Alvarez. "Our input explains the flaws in the government's proposed plan and presents technical arguments that refute many of the assumptions that underpin the federal options.

"It leads us to the point that, if the government cannot design a workable or acceptable plan under the Kyoto framework, Canada can make an important contribution to reducing greenhouse gas (GHG) emissions in ways that are better suited to our particular circumstances."

CAPP planned to complete a more formal submission to the federal government by early July.

In a technical 13-page background paper, CAPP said, "The upstream oil and natural gas industry believes that Canada should do its part of the global effort to prevent climate change. For years, our members have been actively pursing greenhouse gas emission reductions in their operations."

CAPP called for the GHG policies to include:

    A clear statement of what the policies are intended to accomplish in terms of industry efficiency, economic structure, end-use consumption, and cost distribution.
  • An explanation of how the objectives fit with other government priorities.
  • How the policies would achieve those objectives.

The European Court of Justice criticized France for its state-owned golden share in TotalFinaElf SA.

The court said the golden share gives France "excessive discretionary powers" over the evolution of the supermajor's capital and contravenes the principle of free circulation of capital in the European Union.

Golden shares are state-controlled stock holdings that enable governments to veto takeovers of recently privatized companies. France kept its golden share when Elf Aquitaine SA was privatized in the early 1990s and extended it to TotalFinaElf when TotalFina SA acquired Elf (OGJ, Mar. 27, 2000, p. 36).

France's Finance Minister Francis Mer said the European Court of Justice did not dispute the principle of the golden share, and that France's golden share could be retained if amended to make it more specific to the country's oil supply security needs.

The court ruled that France had retained too much power in the way the golden share could be applied under the privatization law.

Quick Takes

Anadarko Petroleum Corp. made two natural gas discoveries in two areas: East Texas and North Louisiana. In East Texas, Anadarko made a gas discovery with Gregory A-1 well in Anderson County in its Bossier play area, which lies 130 miles north of Houston.

Patterson Rig 133 drills Anadarko Petroleum Corp.'s Davis Bros. 28-1 well on its Ansley prospect in North Louisiana. Photo courtesy of Anadarko.
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And west of Vernon field in North Louisiana, the company drilled and completed Davis Bros. 11-1 well, a new gas discovery at its Ansley prospect.

Gregory A-1 well was drilled to more than 17,500 ft TD and found 241 net ft of gas pay in multiple sands. The well, which flowed initially 8 MMcfd into a sales pipeline, was completed in the lowermost York sand interval. Anadarko holds 100% interest in the well and has exploration rights for 14,000 net acres in the area surrounding the well.

The company plans soon to drill three stepout wells to confirm the discovery, said John Seitz, Anadarko president and CEO, adding that he expected development drilling in the area "to continue for some time."

Seitz said, "As additional wells are drilled and we get more production data, we will develop a better assessment of the size of this new discovery. Available data suggest this field could open a new trend as significant and prolific as the Dew-Mimms area in Freestone County."

Dew-Mimms-which is producing 136 MMcfd (gross) from 277 wells-has estimated gas reserves of more than 1 tcf, Anadarko said.

The company has 6 rigs drilling throughout the main Bossier trend area in Texas and holds interest in 291,000 net acres. Total production from the Bossier play in Texas has averaged 275 MMcfd (gross) this year.

The Davis Bros. 11-1 well, drilled in Jackson Parish to 16,000 ft TD, logged 111 ft of pay in multiple sands and flowed 8 MMcfd initially into a sales line. Two miles west, follow up well Barnett 9-1 was drilled and logged 107 ft of "apparent pay" in multiple Lower Cotton Valley (Bossier) sands. Barnett 9-1 is being completed.

Anadarko holds a 52.3% interest in the Davis Bros. 11-1 well and 100% interest in Barnett 9-1. Other Davis Bros. 11-1 partners are Ocean Energy Inc., Houston, 44.6%, and Oklahoma City-based Devon Energy Corp. 3.1%.

Anadarko, which holds almost 100% interest in the overall Ansley prospective area, is drilling three additional wells in the area and intends to continue drilling in the area. "Based on the well results, we expect to have an ongoing and active development drilling program around Ansley in north Louisiana," Seitz said. He added that it was "premature" to estimate the field's reserves, although available data suggested that the area could be "similar in size and potential to the Vernon field."

Vernon, about 80 miles east of Shreveport, La., has 1 tcf of estimated reserves and is currently producing 92 MMcfd from 69 wells, Anadarko said.

Elsewhere on the exploration front, Pioneer Natural Resources Co., Dallas, said the Olowi Marin-2 appraisal well was drilled to 1,050 m on the Olowi Block off Gabon. The company said it plans to have enough data by 2003 to move forward with development there. The Olowi Marin-2 well is 4 km southeast of the Olowi Marin-1 discovery well, which was drilled last year. After being cored and logged, the same Lower Gamba reservoir found in the discovery well flowed at sustained rates of just over 2,000 b/d with no water from a 15 m perforation interval, Pioneer said. Pioneer operates the 314,000 acre permit with 100% working interest. The rig is being moved 9 km north to drill the Gnadi Marin-1 well to test the same reservoir with results expected by the end of July. Pioneer has had rights to explore, develop, and produce oil and gas on the Olowi Block since 1998. The block covers water depths less than 130 ft about 3 miles southeast of giant Gamba oil field. Olowi Block is along an oil productive trend that connects Gamba oil field northwest of the block with smaller oil fields southeast of the block (OGJ, Jan. 12, 1998, p. 24).

Vaalco Energy Inc., Houston, has successfully completed the first of three wells planned for the Etame concession off Gabon. The ET-3H well flowed at a rate of 7,630 b/d of oil through a 42/64-in. choke. Vaalco planned to move the Sedneth 701 drilling rig to its second location before the end of June. Etame field is expected to go on stream late in the third quarter with combined production from the three wells totaling an estimated 15,000 b/d of oil, Vaalco Energy said. Etame is estimated to hold more than 150 million bbl OOIP, 30 million bbl of which is recoverable. Robert Gerry, Vaalco chairman and CEO, said he believes the recovery factor will prove better than the initial outside estimates after production starts (OGJ, Mar. 4, 2002, p. 70).

A group led by Coparex Netherlands BV started up an oil and gas field off Tunisia that was undeveloped since its discovery in 1974. Two wells in sis field began producing in November-December 2001, and a third well began Jan. 27. A published report said the first two wells flowed a combined 11,500 b/d. No subsequent production figure was available. Isis is in 230 ft of water and at 90 miles offshore in the Gulf of Gabes is Tunisia's farthest offshore field. The concession's eastern edge is close to Libyan waters. Isis produces 35.5° gravity oil from the Isis sandstone of the Cretaceous Fahdene formation at 2,400 m subsea. Planned gas lift will involve injection of 3 MMscfd at 3,000 psi. Oil flows to a floating production, storage, and offloading vessel with facilities that can handle 30,000 b/d. Field interests are Coparex and Atlantis Technology Services, 40% each, and Tunisia's state Entreprises Tunisienne d'Activites Petrolieres 20%. Samedan Oil Corp. and the former Neste Oy of Finland shot 3D seismic data over Isis and considered developing the field, but Samedan wrote off its investment in late 1994.

Partners in the Buzzard oil discovery in the UK North Sea have completed the last of three wells under their appraisal program and will begin development of that field.

The discovery, which lies in license areas P986/P928, is estimated to contain reserves of more than 400 million bbl of oil. Tests confirming these reserves were completed earlier this year (OGJ Online, Feb. 6, 2002).

Calgary-based EnCana Corp. holds 45.01% of license area P986, which contains the Buzzard discovery well.

Other P986 license holders are Intrepid Energy North Sea Ltd. 30%, BG Group PLC 19.99%, and Edinburgh Oil & Gas PLC 5%. License area P928 interest holders are EnCana 35.29%, Intrepid Energy 29.41%, BG 29.41%, and Edinburgh 5.88%.

A total of eight wells and sidetracks have been drilled on the Buzzard structure since the discovery was made last year, BG said (OGJ, June 18, 2001, p. 8).

The partners have started to acquire a new 3D development seismic survey over the field, and they expect to award a front-end engineering design contract in August. First production is expected to begin in late 2005 or early 2006.

"If all goes well, we hope to submit a field development plan…at the end of 2002 or early 2003," said Jon Wormley, BG group executive vice-president, UK. Two of the recent wells, Wormley said, have confirmed the nature and extent of the field, while a third well has established a significant reservoir section in license area P928.

Karachaganak Integrated Organization (KIO) said it will invest $3.5 billion in a project to develop Karachaganak gas condensate field in Kazakhstan, Russia's Interfax news agency reported. KIO-a joint venture of BG PLC 32.5%, Agip SPA 32.5%, ChevronTexaco Corp. 20%, and OAO Lukoil 15%-said it plans to raise liquid hydrocarbon production from the field to 7 million tonnes/year by constructing additional production and export capacities, a KIO press service source told Interfax.

During 1995-97, a total of $160 million was invested in the field from a number of sources, Interfax reported. During 1998-2003, construction is to include a gas processing plant, a 240 Mw power generation plant, and three high-pressure compressors.

Later, KIO will build a 650 km export pipeline extending from Karachaganak to Atyrau, which will ultimately connect with the Caspian Pipeline Consortium system.

In 2001, gas production from Karachaganak field reached 3.75 billion cu m, with condensate production totaling 4 million tonnes, Interfax reported. This year, KIO plans to raise gas production to 4.7 billion cu m and condensate production to 5 million tonnes, Interfax said.

The field holds an estimated 2.25 billion bbl of oil and gas condensate reserves, according to the US Department of Energy's Energy Information Administration.

Elsewhere, China National Offshore Oil Corp. Ltd. (CNOOC) said platform C and platform D have been brought on stream, adding slightly more than 20,000 b/d of oil production to Qinghuangdao 32-6 field, 130 km east of the city of Tianjin. CNOOC operates the field with 51% interest. Partners ChevronTexaco Corp. and BP PLC each hold 24.5% interest. The first two platforms, A and B, were brought on line in October 2001 with an initial 25,000 b/d of oil (OGJ, Dec. 17, 2001, p. 61). Two more platforms, E and F, are expected to start production later this year, CNOOC said. Production is expected to peak at 65,000 b/d. Reserves are 103 million bbl.

Qatar Petroleum and ExxonMobil Corp. have agreed to supply LNG to the UK, starting with shipments in 2006-07 for 25 years, with the gas coming from Qatar's North Field.

The agreement covers development of two LNG trains, which ExxonMobil said would be the largest built to date, although the company declined at this time to disclose the trains' anticipated capacities.

Qatar Petroleum will have a 70% interest in the LNG trains, and ExxonMobil 30%.

The LNG trains will be built at the Ras Laffan Industrial City. ExxonMobil is investigating numerous UK sites for the LNG import facility.

Qatar Minister of Energy and Industry Abdullah bin Hamad Al-Attiyah said, "This agreementellipsehighlights another successful joint effort between Qatar Petroleum and ExxonMobil to provide an increasing share of the world's growing demand for clean burning and environmentally friendly natural gas."

Harry Longwell, ExxonMobil director and executive vice-president, said that the project will supply the first LNG imports to the UK in 20 years and will help ensure long-term reliable gas supply to that market.

"UK indigenous gas supplies are expected to decline in the near future, and by the end of this decade, a shortfall is anticipated that will have to be met from other sources, such as LNG imports," Longwell said.

In other gas processing news, Abu Dhabi Gas Industries Ltd. (Gasco) has awarded a project management contract to Foster Wheeler Inter-national Corp., the UK subsidiary of Clinton, NJ-based Foster Wheeler Ltd., to increase Gasco's production of condensate and natural gas liquids at four of the company's Abu Dhabi facilities. The project will focus on the following Gasco sites: two new gas plants at Habshan and Asab fields, an expansion of the existing Gasco plant at Ruwais, and an upgrade of existing NGL storage at the Takreer refinery at Ruwais. The Foster Wheeler unit will be responsible for endorsing the selection of the front-end engineering and design contractor and will manage it on behalf of Gasco. The new and expanded facilities will remove condensate and NGLs from natural gas taken from Abu Dhabi gas reservoirs.

These products will then be shipped to the coast via pipeline, where they will be treated for export and end use. Dry gas, meanwhile, will be reinjected. The wells and gathering system will be upgraded to deliver the additional gas quantities to the new Habshan gas plant, known as OGD-III. The new plant at Asab, AGD-II, will involve recovery of NGLs from the gas that is presently processed and injected into Asab field. The existing Ruwais processing plant will be expanded to add a new NGL fractionation train with utilities, storage, shipping, and control systems. The existing Takreer refinery at Ruwais, meanwhile, will be upgraded for treatment, fractionation, and export of the additional condensate volumes.