OGJ Newsletter

Feb. 14, 2005
Lukens Energy Group, Houston, forecasts that natural gas prices at Henry Hub will average $5.25-6/MMbtu for 2005 based upon the consultant's expectations for fuel oil prices.

General Interest—Quick Takes

US gas price forecast at $5.25-6/MMbtu

Lukens Energy Group, Houston, forecasts that natural gas prices at Henry Hub will average $5.25-6/MMbtu for 2005 based upon the consultant's expectations for fuel oil prices.

No. 6 fuel oil (resid) prices have set a floor for gas prices since December 2002. Currently, No. 2 distillate is setting a ceiling for gas prices, said Lukens analysts. They calculated a 2005 gas price based upon oil price expectations and natural gas supply and demand.

Lukens Vice-Pres. Glen Sweetnam has forecast that US and Canadian gas production will grow by 1-2% in 2005. The increase will stem from recovery of production in the Gulf of Mexico after an active 2004 hurricane season and from entry into the market of gas supplies from the Rocky Mountains.

"Drilling activity will offset natural declines in North American production from existing fields," Sweetnam said of onshore activities in the US and Canada.

Given normal weather, US and Canadian gas demand is expected to be flat for 2005, he said. Despite recent economic growth, he expects that a 2% decline in US industrial consumption will offset consumption growth in the residential and commercial sectors. Gas demand for power generation won't change.

"A slight growth in supply against flat demand means gas prices will trend to the lower end of the price range between the floor of residual fuel oil prices and the ceiling of distillate prices," Sweetnam said.

Winter gas price volatility will increase, while summer volatility will decline because of the link between gas prices and oil prices, he said.

Construction pace crucial to LNG supply

Controversy about the siting of LNG receiving terminals draws much attention in the natural gas-hungry US, but the infrastructure for LNG exporters cannot be overlooked.

The supply end of the LNG chain deserves attention, too, Sara Banaszak, a senior economist in the American Petroleum Institute's policy analysis group, told the Strategic Research Institute's annual LNG conference in Houston on Jan. 27-28.

"The pace of constructing new supply facilities is critical to LNG availability for long-term increases in imports," she said. "Liquefaction plants take longer to build than receiving terminals."

With export-capacity expansions under way in gas-rich Qatar, the Middle East's status as a global LNG supplier is destined to grow.

Banaszak pointed out that Middle Eastern LNG exporters have the "ability to deliver to either the Atlantic or Pacific Basin."

Until the 1990s, Asian exporters dominated LNG trade, she noted. But that's changing as supplies grow from the Middle East, North Africa, West Africa, and Latin America.

As importers, the US and Europe will gain on world-leading Japan, Banaszak said, adding that a flat economy is suppressing Japanese consumption.

Meanwhile, long-term contracts for about 20% of Japan's annual imports are slated to expire by 2010, and Japan is negotiating for newer, more flexible supply terms, Banaszak said.

The US is expected to rely on LNG for more and more of its natural gas supplies because gas production is declining in the US and Canada. The US can buy LNG from suppliers in either the Atlantic or Pacific Basin if enough West Coast receiving terminals are built, Banaszak noted.

"All of that LNG cannot come into the Gulf Coast. We've had a lot of success siting [receiving terminals] in the Gulf Coast. That has not been the case on the East," she said.

Keith M. Meyer, president of Cheniere LNG Inc., a wholly owned subsidiary of Cheniere Energy Inc., Houston, said he expects that one or two new receiving terminals will be built on the West Coast, one will be built in the US Northeast, and one will be built in the Bahamas or Florida.

The Gulf Coast is the most natural place for receiving terminals because of its existing pipeline infrastructure and because of the public's acceptance, he noted.

Cheniere is building one terminal and is planning three others, all on the Gulf Coast (OGJ Online, Dec. 22, 2004).

"New gas supply must come from new areas. Right now, we've got in this nation a gas price that is not sustainable," Meyer said. "LNG will stabilize and lower natural gas prices. It will do that from the supply side, not the demand side."

Meyer said he doesn't know how much LNG will lower US gas prices, but he believes lower gas prices are inevitable as demand falls, regardless of what happens with supply.

Fisoye Delano, a senior researcher with the Institute for Energy, Law & Enterprise at the University of Houston, said the US is undergoing "changing dynamics." The US Energy Information Administration forecasts that LNG imports could reach 6.4 tcf/year by 2025, or 21% of total US consumption.

Currently, there is no world natural gas index similar to the US Henry Hub gas price, he noted. But regional competition for LNG will grow and will influence gas prices worldwide.

"LNG will go to where the price is most advantageous," Delano said.

Chávez pushes for Citgo sale

Venezuela's President Hugo Chávez said Feb. 2 that his government plans to sell its interests in eight Citgo Petroleum Corp. refineries in the US along with an undetermined number of its 13,000 retail outlets, 90% of which are in the US and 10% in Puerto Rico. Citgo, the fifth largest gasoline refiner in the US, with annual revenues of $25 billion, is owned by PDV America Inc., a subsidiary of Venezuela's state oil company Petroleos de Venezuela SA (PDVSA).

Chávez said Citgo should be sold because it was "denying PDVSA adequate revenue and because it was, in effect, contributing tax to the government of President George W. Bush, rather than to Venezuela." Chávez claimed the contracts between Citgo and PDVSA are unfavorable to Venezuela due to the discounted prices of its exported crude.

Citgo currently refines 859,000 b/d of heavy crude but has the capacity for more than 1.1 million b/d, PDVSA said. It owns a 156,750 b/cd refinery at Corpus Christi, Tex., a 308,085 b/cd refinery at Lake Charles, La., and a 158,650 b/cd refinery at Lemont, Ill., along with asphalt refineries in Paulsboro, NJ, and Savannah, Ga. Citgo also owns 41% interest in a 268,850 b/cd Houston refinery, with Lyondell Chemical Co. holding 59%, and participates in a joint venture with Amerada Hess in a 495,000 b/d refinery at St. Croix in the Virgin Islands. Steven Paget of First Energy Capital Corp. Group put the sale value of the assets at $8-10 billion.

Venezuela produces 2.6 million b/d of heavy oil and exports 1.1 million b/d of it to the US.

Venezuela continues to strengthen ties to China and in a series of oil production agreements has agreed to significantly increase oil sales to that country. Chávez said proceeds from the sale of Citgo's US assets would be used to expand activities with China and with Argentina, where PDVSA is negotiating the purchase of a Royal/Dutch Shell subsidiary (OGJ Online, Feb 7, 2005).

Industry Scoreboard

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Exploration & Development—Quick Takes

South East Mananda development approved

Oil Search Ltd., Sydney, has approved the $82 million development—based on a major pipeline gorge crossing—of South East Mananda oil field in the highlands of Papua New Guinea.

Although containing only an estimated 10 million bbl of reserves, the development is significant as the first new oil field development in Papua New Guinea in a decade. Oil Search took over the reins in the highlands when it purchased the assets of Chevron Niugini in October 2003 (OGJ Online, July 22, 2003).

Innovative engineering and a more favorable tax regime will make development of SE Mananda economically feasible.

Chevron discovered the field in 1991 but considered it noncommercial because of its small size and because it lies on the wrong side of a 500-m deep, 470-m wide chasm known as the Hegigio Gorge. The discoverers could not justify the expense of a gorge crossing to connect with Agogo field facilities on the other side, which feed into the Kutubu central production hub and the head of the oil pipeline that takes highlands oil down to a shipping terminal in the Gulf of Papua.

Today the economics and incentives have changed.

Papua New Guinea, increasingly concerned by the decline in the country's oil production—now down to 43,000 b/d from highs of 140,000 b/d in the early 1990s—established a new tax regime in its 2003 annual budget. It changed the income tax for new petroleum operations to 30% of taxable income, down from 45% for projects established after 2001 and 50% prior to 2001.

The new rate is available for petroleum development licenses granted before the end of 2017 as an incentive to stimulate exploration ventures. Oil Search's request that the 30% tax rate also be applied to old undeveloped marginal fields was granted in January.

Engineers also devised a plan to construct a pipeline suspension bridge from lip to lip of Hegigio Gorge to carry the pipeline to Agogo from SE Mananda. The first cables will be flown across the gap by helicopter to form a "hanger" for a gondola to be built beneath. The pipeline will then be laid along the deck. The construction contract has been awarded to Perth-based engineering firm Clough Ltd.

At the field, Oil Search will reenter one of the two original wells to use as a producer and will drill two more wells to increase production to 10,000 b/d sustained over a 6-year period. First oil is scheduled for delivery to Kutubu in third quarter 2005.

The company also is encouraged by recent seismic work in the region that indicates a possible extension of the field from the PDL2 production license into adjoining exploration permit PPL219. In addition, there are two large undrilled prospects in PPL219 called Mananda Attic and Mananda Footwall. Oil Search plans to drill one of these prospects this year.

The new SE Mananda pipeline will enhance the viability of discoveries in this previously isolated side of the gorge.

Santos to appraise giant East Java basin discovery

Santos Ltd. plans to appraise an oil discovery in Java's Madura Strait that it said might be the company's largest oil field development.

The company began acquiring 3D seismic data in January over the Jeruk discovery, where it has drilled two deviated, high pressure-high temperature wells 1.6 km apart that defined an oil column at least 379 m thick (true vertical thickness). The Jeruk reservoir is in the Oligocene Kujung carbonate at 16,380 ft subsea in 44 m of water on the Sampang production-sharing contract.

Santos Managing Director John Ellice-Flint said the discovery "appears likely to contain more than the published, predrill contingent resource estimate of 170 million bbl. If our initial view is confirmed during the appraisal program, then the Jeruk discovery could significantly upgrade our current reserve base, and it would be Santos's largest oil field development." Well data, including cuttings, wireline logs, and test data indicate that the oil column could extend shallower and deeper than the current thickness. However existing 2D data on which the well trajectories were designed are imprecise at these depths, Ellice-Flint added.

A rig under contract to Santos was moving in January to drill the Agung-1 exploratory well on the North Bali 1 PSC in which Santos has 30% interest. That prospect, targeting a carbonate reservoir on a trend similar to the Jeruk discovery, has 550 million bbl of unrisked upside resource potential, Ellice-Flint said.

A drillstem test at Jeruk-2 yielded good quality, 33° gravity oil at the rate of 7,488 b/d through a 1/2-in. choke with 2,762 psi of flowing tubinghead pressure (OGJ Online, Oct. 19, 2004). Capacity of surface facilities limited the flow rate.

Acquisition, processing, and interpretation of the 3D seismic data will be completed in the second half of 2005.

Santos and Indonesia's PT Medco Energi International Ptk. hold 50:50 interests in the two wells. PSC partners who chose not to participate in the two wells could reclaim their interests by paying compensation, and that would reduce Santos's interest to 45%. Participation by an Indonesian government-nominated company could reduce that further to 40.5%.

Unocal logs deepwater pay off Indonesia

A Unocal Corp. subsidiary has made another deepwater discovery in the northeastern Kutei basin off East Kalimantan on frontier exploration acreage.

Hiu Aman 1, in the Donggala production-sharing contract (PSC) area, was drilled to 4,039 m TD in 14 days.

Preliminary analysis of the LWD (logging while drilling) and wireline logs, including modular dynamics test pressures and samples from the lower part of the well, indicates about 25 m of mostly gas pay.

The well lies seaward of West Seno field, Indonesia's first deepwater producing oil field. It is the first in a three-well drilling program on the block, where Unocal Donggala Ltd. is the operator. Partner Santos Ltd. will become the Donggala PSC operator in 2006.

Santos said it hopes the next wells confirm that the petroleum system in the basin's shallow water extends into the deepwater trend.

After wireline logging, the well will be plugged and abandoned. The rig will move to the Orca 1 drillsite, then to Pangkal 1 in the Papalang PSC to the south and Raksasa 1 in the Donggala PSC.

The Donggala PSC, which covers 3,821 km in 1,650-2,450 m of water, lies between the Popodi and Papalang PSCs.

Subject to regulatory approvals, Santos will gain a 65.45% total equity interest in the Donggala PSC and, pending additional agreements with existing PSC participants, plans to farm out 15.45% of its new equity interest.

Kerr-McGee gets deepwater block off China

Kerr-McGee China Petroleum Ltd. has signed a production-sharing contract with China National Offshore Oil Corp. (CNOOC) for deepwater Block 43/11, its first deepwater exploration contract with CNOOC

Block 43/11, about 220 miles southeast of Hong Kong, covers 2.4 million undeveloped acres in 5,000-10,000 ft or more of water in the South China Sea.

Kerr-McGee holds a 100% foreign contractor's interest in the first phase of exploration, and CNOOC has the right to participate with as much as 51% ownership when Kerr-McGee enters the development phase.

Kizomba B TLP arrives at Luanda

Angola's state-owned oil company Sociedade Nacional de Combustiveis de Angola (Sonangol EP) and Esso Exploration Angola (Block 15) Ltd. have reported the arrival of the Kizomba B tension leg platform (TLP) at Luanda.

The TLP is part of the $3.4 billion Kizomba B development on Block 15 about 350 km northwest of Luanda. It will be tied to a floating production, storage, and offloading system with storage capacity of 2.2 million bbl to serve as the center of operations for subsea wells in Kissanje and Dikanza oil fields. It is estimated that the Kizomba B fields, lying in 1,000 m of water, contain 1 billion bbl of oil.

The 30,000-tonne platform will be towed to the site by early March, and drilling is to start by the end of April.

Kizomba B production is expected to start in the second half of 2005 and rise to a peak of 250,000 b/d.

Block 15, with 17 discoveries to date, has an estimated 4.5 billion boe (gross) of reserves. The $3.4 billion Kizomba A project, which is developing Hungo and Chocalho fields, began production Aug. 7, 2004 (OGJ Online, Aug. 11, 2004). Current oil production from the block is 300,000 b/d.

Planning and design for the Kizomba C project also are under way. The three Kizomba projects will be developed at a total cost of $10 billion.

ExxonMobil Corp. subsidiary Esso is Block 15's operator and holds a 40% stake. Other shareholders are BP Exploration (Angola) Ltd. 26.67%, Agip Angola Exploration BV 20%, and concessionaire Sonangol 13.33%.

Timor-Leste prepares for licensing round

Timor-Leste's Energy and Minerals Directorate is preparing a geological and geophysical data package covering areas to be licensed in what will be the country's first offer of exploration rights in 3 decades as the country develops its energy industry.

The onshore and offshore licensing round, scheduled for April and June, will be based on a production-sharing contract system benchmarked competitively with that of other Southeast Asia countries.

Companies wishing to participate in the new licensing round may purchase 2D seismic data acquired last year by a joint venture of PetroChina Co. Ltd. and Norway's Global Geo Services ASA on 6,400 km of offshore areas south of Timor that are not in dispute with Australia.

Permits also will be offered in the country's onshore region.

Timor-Leste plans to establish a national oil company modeled on Brazil's state oil firm Petroleo Brasileiro SA to participate in upstream and downstream operations and a National Petroleum Fund to manage potential oil and gas revenues.

Directorate officials plan visits to Asia, Europe, and the US to make presentations on the licensing round.

Drilling & Production—Quick Takes

Harvest to suspend Venezuelan drilling

Harvest Vinccler CA (HVCA), the Venezuelan arm of Harvest Natural Resources Inc., Houston, said it would suspend drilling activities on its 158,000-acre South Monagas unit, where it operates Uracoa, Tucupita, and Bombal oil fields in eastern Venezuela's Delta Amacuro state.

The company said permit delays have prevented it from drilling seven wells required to maintain and increase oil and gas production in the unit. HVCA currently is producing 29,000 b/d of oil and 80 MMcfd of gas.

Although HVCA submitted requests to Petroleos de Venezuela SA (PDVSA) for the permits from the Ministry of Petroleum and Energy, a PDVSA affiliate is seeking to reduce HVCA's 2005 drilling program budget and to restrict production below planned levels.

HVCA said it is attempting to meet with Venezuelan government officials, the Ministry of Petroleum and Energy, and PDVSA to obtain the approvals.

US drilling slumps for second week

US drilling activity continued to fall for the second consecutive week, down by 8 units to 1,248 rotary rigs working, said Baker Hughes Inc. on Feb. 4. That's up from 1,117 active rigs during the same period last year.

Offshore drilling led the latest decline, down by 4 units in US waters overall, including a loss of 2 in the Gulf of Mexico. Land drilling lost 3 rigs with 1,127 still working. Inland waters activities dipped by 1 unit. Canada's rig count dropped by 18 to 576 units this week, up from 552 a year ago.

Line rupture likely cause of Suncor fire

Suncor Energy Inc., Calgary, expects its oil sands upgrader, which caught fire Jan. 4, to return to its full production capacity of 225,000 b/d in the third quarter (OGJ Online, Jan. 7, 2005). In January, production averaged 137,000 b/d of oil, including 17,000 b/d of in situ bitumen production.

During the repair period, which is under way, production is expected to average about 110,000 b/d of oil, in addition to bitumen production from in situ operations.

Suncor said the cause of the fire likely was a corroded recycle line, which caused the line to rupture, releasing hydrocarbon vapor that ignited. The line was not lined with stainless steel.

Suncor is now applying stainless steel lining appropriately in its operations and, during the recovery period, will bring forward planned maintenance projects.

The company said it intends to increase oil sands production capacity to 260,000 b/d of oil by yearend.

Processing—Quick Takes

BHAR plans Baku gasoline complex

Baku Heydar Aliyev Refinery (BHAR), a unit of State Oil Co. of Azerbaijan, has let a contract to UOP Ltd., Des Plaines, Ill., for basic design of a high-octane gasoline complex in Baku.

The complex will comprise a 300,000 tonne/year alkylation unit, a 130,000 tonne/year di-isopropyl ether unit based on UOP's Oxypro process, and a UOP Butamer process unit.

UOP's Alkylene technology uses a solid catalyst instead of liquid acid to alkylate C4 olefins with isobutane.

The project is part of a BHAR modernization program.

Production is scheduled to begin in 2008.

Transportation—Quick Takes

Sempra, Tractebel sign Cameron LNG pact

Sempra Energy unit Sempra LNG, San Diego, has signed a heads of agreement (HOA) providing Tractebel LNG North America LLC with as much as one third of the 1.5 bcfd capacity of Sempra LNG's Cameron LNG terminal under development 15 miles south of Lake Charles, La.

Under the nonbinding HOA, to be finalized by June 30, Sempra LNG would sell 325-500 MMcfd of throughput capacity to Tractebel LNG for 20 years. Tractebel LNG is the North American LNG business of Tractebel Electricity & Gas International, a division of the French firm Suez Group.

Sempra is negotiating other supply and capacity agreements for the Cameron project on which construction is slated to begin later this year (OGJ Online, Jan. 13, 2005).

Sempra LNG also has signed a 20-year agreement to provide Shell International Gas Ltd. with 500 MMcfd of gas from its Energia Costa Azul LNG terminal in Baja California, Mexico—half of that terminal's proposed capacity (OGJ Online, Dec. 22, 2003). Sempra has secured the remaining 500 MMcfd of LNG capacity from Indonesia's Tangguh LNG project. Construction of the Energia Costa Azul terminal is under way and scheduled for completion in early 2008.

Trans Mountain expansion receives support

Terasen Pipelines Inc., Calgary, received strong support from 17 existing and potential energy customers for capacity expansion on its Trans Mountain oil pipeline to the West Coast.

Terasen and Enbridge Inc. are competing to provide pipeline capacity to handle increased production from the Alberta oil sands.

Terasen said customers participating in the company's "expression of interest" review during the last 2 months want to see additional capacity out of Alberta by 2008 to serve markets in Canada, US, and abroad.

Terasen's initial expansion phase will increase the system's capacity to 300,000 b/d from 225,000 b/d by yearend 2008 with a second phase more than doubling the current system's capacity to 450,000 b/d by 2010.

Terasen Pipelines will prepare to call a formal open season this summer.

TransCanada builds gas storage facility

TransCanada Corp. is developing a $200 million (Can.) natural gas storage facility near Edson, Alta.

The 50 bcf facility, which will connect to TransCanada's Alberta system, will make TransCanada the owner of more than 110 bcf of storage capacity, one third of Alberta's total.

TransCanada recently signed a long-term contract with a third party for up to 40 bcf of existing Alberta-based storage capacity. The company owns 60% of CrossAlta Gas Storage & Services Ltd., which operates a 40 bcf storage facility near Crossfield, Alta.

The company plans to provide fee-based gas storage services directly to customers by April. It will phase in capacity of the Edson facility starting early in the second quarter of 2006.