OGJ Newsletter

Oct. 27, 2003
The next 6-12 months will be a crucial period for the recovery of Iraq's oil industry and for future US influence in the Middle East, said Herman Franssen, president of International Energy Associates Inc., Chevy Chase, Md.

Market Movement

Iraq, US face crucial period

The next 6-12 months will be a crucial period for the recovery of Iraq's oil industry and for future US influence in the Middle East, said Herman Franssen, president of International Energy Associates Inc., Chevy Chase, Md. He is also the former senior economic advisor to Oman's energy minister and chief economist of the International Energy Agency.

Iraq faces a budget crisis if sabotage and looting keep its oil production substantially below 2.5 million b/d in 2004, said Franssen at a recent oil industry meeting in Dubai. And if the US-led coalition fails to restore electrical power, clean water, and other basic services to Iraq, it may lose forever its "battle for the hearts and minds" of Iraqis, he said.

The "worse-case scenario" for such failures, Franssen said, would be that Iraq's oil production remains volatile, the country drifts into civil war, and world oil prices would remain high.

"If, on the other hand, the occupation forces succeed in restoring security, achieve substantial progress in providing vital services to the Iraqi people, and revive oil production close to 2.5 million b/d, the outlook will be more positive, and Iraqi oil income will cover much of the budgetary requirements," he said.

"Oil supply disruption in Iraq, both during and after the war, and the inability to restore production have caused global oil prices to remain robust, creating large currency reserves in many [other members of the Organization of Petroleum Exporting Countries] while slowing down global economic recovery," said Franssen.

He said Iraq has the ability to return its oil production to 2.5 million b/d "sometime next year," increasing to 3.5 million b/d by 2005-06.

"Beyond the middle of this decade, Iraq has the potential to increase its capacity to 6 million b/d or more, making it potentially the second-largest OPEC oil producer [behind Saudi Arabia and ahead of rival Iran]," Franssen said.

If a democratically elected Iraqi government were to take charge of that country no later than 2005, with a new constitution and laws regulating foreign investment and the oil sector, international oil companies would be ready to invest in Iraqi exploration and production on a large scale, he said.

Meanwhile, World Bank directors expressed broad support for a proposed international reconstruction fund facility that was to be presented at the Oct. 23-24 donors' conference in Madrid.

Its purpose is to provide a coordination and trust fund mechanism for reconstruction of Iraq, in line with the joint United Nations-World Bank assessment of that country's needs, which was released earlier this month.

Strange data

The US Energy Information Administration's latest report of US inventories of crude and petroleum products for the week ended Oct. 17 is "a strange set of data, which run against several recent trends," said Paul Horsnell, head of energy research at Barclays Capital Research, a division of Barclays Bank PLC, London.

EIA reported last week that US oil stocks fell by 1.8 million bbl to 288.2 million bbl during that period, the first such drop since early September. "A trend of fairly sharply rising oil inventories [previously] had been generally taken for granted, but now there is some reason to question it," said Horsnell. "[US] crude imports are falling, with the 4-week average [of 9.7 million b/d] moving down to its lowest level since mid-July. At the same time, refinery runs of crude oil are on the increase."

Horsnell concluded "that any idea of rapidly rising crude inventories has to be abandoned or at least that the 2001 peaks of above 320 million bbl look too far away to be achievable particularly quickly.

It does also look as if the pressure on the supply chain is a constricting one and that the trend for refinery utilization is upward.

"Put all that together, and the end of the rising crude oil inventory trend is certainly coming closer, even if [these latest data] prove not to be the exact turning point," he said.

EIA also reported US distillate inventories grew by 2.6 million bbl to 132.4 million bbl in the latest period, with increases in both diesel fuel and heating oil. "In this case, the data look a bit more like an anomaly," Horsnell said. "This is too large a movement to be consistent." He noted that "in the key area for heating oil demand, the central Atlantic states, the situation was little changed, leaving inventories a little tighter than normal and still less than one would want unless the winter was likely to be a mild one."

Industry Scoreboard

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Industry Trends

A GLOBAL NATURAL GAS market is emerging, and LNG could fulfill up to 20% of US gas demand by 2020 compared with 1% in 2002, predicts Cambridge Energy Resource Associates of Cambridge, Mass.

CERA Chairman Daniel Yergin and Michael Stoppard, CERA LNG director, wrote an article entitled "The Next Prize" in the November-December issue of Foreign Affairs, a journal on global issues published by the New York-based Council on Foreign Relations.

Historically, the gas business has been limited by pipeline infrastructure and the absence of a global market. LNG enables underdeveloped and stranded gas reserves to be carried to consumers worldwide.

"Much is now expected of LNG," said Yergin and Stoppard. "But developing its full potential could cost as much as $200 billion worldwide, and energy companies will have to choose between investments in LNG and other investments."

Yergin said various risks will come from increased interdependence for gas supplies, but he said a growing diversified global gas market can manage these risks, which he calls less than the risk of the US and Europe facing a persistent natural gas shortfall.

Stoppard said, "The natural gas business is on the brink of profound change. It is set to become global and to adopt a more flexible market model."

Several potential market hurdles could capsize LNG's development, Yergin and Stoppard said. These include:

  • Low and volatile gas prices, even if they are only temporary, could discourage investors and stifle growth.
  • A lack of confidence in the developing market could prevent companies from committing the necessary capital and human resources.
  • State-controlled companies will have to resolve conflicts that are likely to arise between LNG's commercial attractiveness and other political and social imperatives.
  • Imposing price controls and restricting gas consumption might stop development altogether.

LNG IS BECOMING an increasingly popular topic regarding incremental US energy needs, but it offers a long-term supply solution rather than a quick fix, said Raymond James & Associates Inc. (RJA).

"More specifically, we believe that it is unlikely that LNG will alleviate the [US] production shortfall until at least 2007. In the meantime, expect gas prices to reflect a tight market for at least the next 3-5 years. Additionally, the minimal economic hurdle rate for LNG to hit our hubs suggests a 'global' gas price that ultimately will be tied to global oil prices," RJA said in a research note last month.

RJA analyst J. Marshall Adkins said 30 new LNG terminals have been proposed for North America, representing as much as 25 bcfd of additional LNG capacity. Adkins works in the Houston office of the St. Petersburg, Fla.-based RJA.

"Of course, most of these are not realistic. After weeding through these proposals, it looks as though there is only 1 bcfd of add-on LNG capacity that is currently under construction," Adkins said. That includes the recently reopened Cove Point facility (OGJ Online, Sept. 3, 2003).

Government Developments

LINGERING DISPUTES over energy tax incentives led US congressional leaders late Oct. 20 to push back a meeting to consolidate a pending comprehensive energy bill until early this week.

Republican bill managers blamed part of the delay on the House's shortened work schedule.

"Since the House is recessing for the weekUit is our intention to convene an energy bill conference early next week, as soon as the House and Senate come back into session," said Senate Energy and Natural Resources Committee Chairman Pete Domenici (R-NM) and House Energy and Commerce Committee Chairman Billy Tauzin (R-La.) last week.

Responding to criticism from Democrats that the bill is being revised in secret, Tauzin and Domenici said they will release the entire text of the draft conference report "at least 24 hr" in advance of the meeting. The two Republican leaders also predicted that the current disagreements over fuel ethanol incentives and other energy tax provisions, such as tax breaks for a proposed Alaskan gas export pipeline would be resolved.

Sticking points remain, however.

Environmentalists criticized efforts by Rep. Joe Barton (R-Tex.) to revise federal clean air rules so the US Environmental Protection Agency could extend the cleanup deadline for areas with serious smog problems. Majority Leader Tom DeLay (R-Tex.) supports Barton's plan, but it might not survive.

Meanwhile, a bipartisan group of 29 senators wants to make sure ethanol tax incentives are protected. Ethanol is a major sticking point because of its role in a provision designed to give fuel suppliers more flexibility in meeting clean fuel guidelines. Under the latest draft of the Renewable Fuels Standard, fuel providers would meet a target of 3 billion gal/year of ethanol-blended gasoline in the nation's fuel supply by 2005, reaching 5 billion gal/year by 2010. Suppliers instead can use a credit trading system if they do not want to use ethanol. In return, industry no longer will be forced to use oxygenates in clean fuel formulas and will be given limited liability protection for the clean fuel additive methyl tertiary butyl ether. MTBE producers also are expected to get "transitional assistance" to refit their plants for other oxygenates. Lawmakers are still arguing on some finer points, including when MTBE liability would kick in; the new law may have an impact on states with pending MTBE groundwater contamination suits. Some lawmakers also worry expanding ethanol's use could harm the highway trust fund, but a plan to protect the fund from an ethanol tax break drain may be crafted shortly.

Bill managers also are expected to drop two oil and gas supply-related provisions supported by the White House. A controversial House plan directing the secretary of the Interior to lease a limited portion of the Arctic National Wildlife Refuge is now gone as well as a Senate provision that inventories the entire Outer Continental Shelf. A provision that exempts hydraulic fracturing from drinking water protections is under fire and may not survive a final bill.

Quick Takes

REPSOL-YPF SA plans to invest $170 million in the next 3 years for development and exploration in northeastern Mexico's natural gas-prone Burgos basin, $42 million of it for work in 2004.

The Spanish-Argentine major is the first foreign company to participate in Mexican hydrocarbon E&D since nationalization in 1938. It bid $2.437 billion under Mexico's multiple service contract (MSC) program for work on the Reynosa-Monterrey block (OGJ Online, Oct. 16, 2003).

The bid came as part of an economic proposal that covers development of infrastructure and maintenance of production and the value of goods and services to be provided over a 20-year contract.

Reserves potential in Burgos basin have been pegged at 34.4 tcf, much of which is proven.

The 3,552 sq km Reynosa-Monterrey block, which borders the US south of the Rio Grande, already has 16 producing gas fields.

In 2004 Repsol-YPF will acquire and process 700 sq km of 3D seismic data, beginning the surveys in the first quarter. Plans call for drilling eight development wells immediately thereafter.

Repsol-YPF said the first-year outlays would result in gas production beginning in 2005. The company expects production to increase to 2 million cu m/day of gas by 2007 from the current level of 400,000 cu m/day.

The Reynosa-Monterrey block is one of the largest of seven Burgos basin blocks that are being tendered under the MSC process. The Repsol-YPF bid kicks off a bidding process that will last through mid-November, with the remaining bid awards to be announced for Cuervito Oct. 23, Mision Oct. 30, Corindon-Pandura Nov. 6, Ricos Nov. 13, and Fronterizo and Olmos both on Nov. 19.

Bids are two-phased—an economic proposal following a technical bid. The final contract awards for all blocks are to be signed by yearend.

As OGJ went to press last week, a consortium of Brazil's state oil company Petróleo Brasileiro SA (Petrobras), Japanese company Teikoku Oil Co. Ltd., and Mexican company D&S Petroleum had submitted a technical bid for the 136 sq km Cuervito block in the state of Nuevo León. Pemex estimates the Cuervito block will see more than 100 wells drilled over the life of that 15-year contract.

State oil company Petroleos Mexicanos is offering the MSCs—essentially turnkey service contracts awarded to operating companies—to boost domestic hydrocarbon supplies to meet rapidly growing demand without running afoul of constitutional bans on foreign ownership of reserves, although the MSCs have already drawn political fire.

Nevertheless, Pemex has projected that the MSCs could result in incremental production of 1 bcfd of natural gas and net as much as $10 billion of foreign investment in Mexico.

QATAR PETROLEUM (QP) signed separate agreements in the past 2 weeks with two supermajors that would result in the world's largest gas-to-liquids project in Qatar as well as further expansion of LNG export capacity in the tiny Persian Gulf nation (see related item, this page).

Both projects in Qatar center on new development and processing of natural gas from its supergiant North field, the world's largest offshore, nonassociated gas field.

QP signed a heads-of-agreement in Doha Oct. 20 with Qatar Shell GTL, a unit of Royal Dutch/Shell Group, to develop a block in North field to produce 1.6 bcfd of gas over the life of the project and to construct what is being hailed as the world's largest GTL plant at Ras Laffan Industrial City in Qatar.

Shell said it would invest $5 billion to develop the upstream gas and liquids facilities, which would include platforms and multiphase pipelines, and the GTL plant, which would produce naphtha and transport fuels, some normal paraffins and lubricant base oils, and associated condensate and liquefied petroleum gas.

The plant will be developed in two phases, Shell said, with two 70,000 b/d trains. The first train is scheduled to be operational in 2008-09 and the second by 2010-11.

QP ALSO SIGNED an HOA in Doha Oct. 16 to supply ExxonMobil Corp. with more than 15 million tonnes/year of LNG to be delivered to the US over a period of 25 years. The LNG exports would be shipped to a US regasification terminal—at a location yet to be decided—that sponsors say would be part of the largest US LNG import supply project.

The agreement with ExxonMobil includes development of two large LNG trains with a combined capacity of 15.6 million tonnes/year of LNG (2 bcfd of natural gas) by Ras Laffan Liquefied Natural Gas Co. Ltd. II (RasGas II), a joint venture of QP and ExxonMobil affiliate ExxonMobil RasGas Inc.

The two new trains, to be built at Ras Laffan, will represent the fifth and sixth such LNG units to be developed at the site by RasGas joint ventures.

RasGas II currently is constructing Trains 3 and 4—4.8 million tonnes/year each—that are slated for start-up in 2004-05. They will join two existing trains that produce more than 6 million tonnes/year of LNG for another joint venture led by QP and ExxonMobil. ExxonMobil currently is evaluating several locations in the US for a receiving terminal site, and the company said it expects to initiate the permitting process in the fourth quarter. Deliveries are expected to begin in 2008-09.

Total estimated investment, including LNG carriers, will be about $12 billion. QP will have a 70% equity interest in the project and ExxonMobil 30%.

In other LNG news, BG Group PLC unit BG LNG Services LLC (BGLS) signed a 20-year sale and purchase agreement (SPA) with Nigeria LNG Ltd. (NLNG) for the supply of 2.5 million tonnes/year of LNG to the LNG terminal at Lake Charles, La. In May, NLNG stepped up its presence in the US LNG spot market with the signing of a memorandum of understanding with BGLS for this supply (OGJ Online, May 14, 2003). Under terms of the SPA, NLNG will ship LNG from Trains 4 and 5 at Finima, Bonny Island, Nigeria, to Lake Charles, where BGLS has 81% capacity rights until September 2005 and 100% until 2024. BGLS will acquire the LNG starting in 2005 or early 2006 from the NLNG Plus project in Finima.

RASGAS II has chartered two LNG carriers—each with a storage capacity of 145,000 cu m—bringing to five the number of long-term chartered vessels in the fleet it will use to deliver LNG from facilities at Ras Laffan, Qatar. The vessels are being chartered for 25 years.

The two newbuilds, scheduled for delivery in 2005, will be built at the shipyards of Samsung Heavy Industries Co. Ltd. of South Korea by a consortium of Mitsui OSK Line, Q-Ship NYK, and K-Line that will own the vessels.

In other tanker activities, BG Group also entered into an agreement with Samsung to purchase three newbuild LNG carriers. The three 145,000 cu m ships, which will cost a total of $460 million, are scheduled for delivery in the second half of 2006. In addition, BG secured options for up to four additional newbuilds for delivery by Samsung in 2007.

THE US MINERALS MANAGEMENT SERVICE has issued a final notice of sale for eastern Gulf of Mexico Sale 189. The lease sale, to be held Dec. 10 in New Orleans, will include 138 unleased blocks covering 794,880 acres. The blocks are 100-196 miles offshore in water 1,600-3,425 m deep.

"This sale area [within an area of 256 blocks in the 1.47 million-acre Eastern GOM Planning Area] is the same as Eastern GOM Sale 181 held in December 2001," said MMS Regional Director Chris Oynes (OGJ Online, Dec. 6, 2001). "There is already production inside the sale area at BP's Kings Peak project in Desoto Canyon 133, and MMS has received 20 exploration plans for leases in the area."

Sale 189, which covers an initial period of 10 years, includes a provision for royalty suspension of 12 million boe for leases in water 1,600 m and deeper, subject to price thresholds. The deepwater royalty relief measure was recently adopted in the GOM as incentive to increase domestic production of natural gas and oil.

Undiscovered economically recoverable hydrocarbons in the area are estimated at 65-85 million bbl of oil and 0.26-0.34 tcf of natural gas. MMS estimates the net economic value for this sale at $100-500 million in 2003 dollars.

In other exploration action, Total SA's Nigerian subsidiary Elf Petroleum Nigeria Ltd., operator of Usan field off Nigeria under a production-sharing contract, has drilled an appraisal well that showed a "significant" extension of the field, which lies in Oil Prospecting License 222 off southeastern Nigeria, said partner Chevron Petroleum Nigeria Ltd., a ChevronTexaco Corp. unit. The Usan-4 appraisal well, drilled about 68 miles offshore and 3 miles south of the Usan-1 well, lies in 2,460 ft of water and is the third successful appraisal of the field, which was discovered in 2002 (OGJ Online, June 10, 2002). The most recent well was tested in two zones and flowed at 4,400 b/d and 6,300 b/d, respectively, under restricted flow conditions. The well "confirmed the presence of commercial quantities of oil as well as additional potential in previously untested reservoirs," Chevron Nigeria said. OPL 222 concessionaire is Nigerian National Petroleum Corp. Other partners are ExxonMobil Corp. unit Esso Exploration & Production Nigeria (Offshore East) and Nexen Petroleum Nigeria Ltd.

JAPAN, concerned about its dependence on the Middle East for oil and increased competition with China for oil, continues to push for a proposed $5 billion crude oil pipeline from Angarsk in Siberia to Nakhodka on the Pacific Coast.

The project competes with a $2.5 billion rival—a 2,400 km route into Daqing in Northeastern China, which Russia favors as more profitable. Russia earlier had said there is not enough export oil available currently in eastern Siberia to justify both pipelines (OGJ Online, May 30, 2003).

In a series of diplomatic visits to Russia, Japan has kept up the pressure for the Nakhodka line, and, contradicting earlier denials, Jiro Okuyama, a spokesman for the Japanese premier, said Japan may contribute $5-7 billion to the project if the pipeline terminates on the Pacific coast (OGJ Online, Oct. 13, 2003).

Swayed by the potentially large Asia-Pacific market for its oil exports via Nakhodka, Moscow last March offered a compromise plan, consisting of a main pipeline from Angarsk to Nahodka with a spur to Daqing.

That pipeline would have a capacity of 100,000 b/d of crude oil to Japan and South Korea and another 60,000 b/d to Daqing by 2010.

Japanese Prime Minister Junichiro Koizumi and Russian President Vladimir Putin have agreed to speed up discussions about the Nakhodka line, although Putin remains uncommitted and has offered assurances that his country will continue to honor its promises of increased exports of oil to China.

Talks with Japan began Aug. 1 in Moscow, and at least two more rounds of talks are planned in Moscow before Russian Prime Minister Mikhail Kasyanov visits Tokyo in mid-December to continue negotiations.

STATOIL SA reported Oct. 21 that it has begun production 2 months early from a Vigdis field extension, which it tied back to its existing Snorre A platform facilities in the North Sea.

The extension eventually will recover about 50 million bbl of oil from Vigdis field.

At start-up, one well is producing 12,000 b/d of oil, Statoil said, and plateau output from three wells is expected to be 57,000 b/d. Six wells eventually will connect to four seabed templates.

Vigdis extension is tied back to Snorre A subsea facilities. Illustration courtesy of Statoil SA.
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The project was sanctioned while Norsk Hydro SA operated Vigdis. Statoil became field operator Jan. 1 of this year and completed the development (OGJ Online, May 20, 2002).

To ensure continuity, Hydro personnel remained a part of Statoil's project team.