OGJ Newsletter

Feb. 9, 2004
Energy futures prices were especially volatile Feb. 2-4, first soaring because of problems at three refineries in California, Illinois, and Indiana, then plunging with bearish reports of builds in US inventories of crude and petroleum products. ...

Market Movement

Energy price volatility increases

Energy futures prices were especially volatile Feb. 2-4, first soaring because of problems at three refineries in California, Illinois, and Indiana, then plunging with bearish reports of builds in US inventories of crude and petroleum products.

After falling sharply the previous week, energy futures prices shot up Feb. 2 following a series of problems at the three US refineries, with the March contract for benchmark US crude spiking by $1.93/bbl to $34.98/bbl on the New York Mercantile Exchange in the biggest 1-day price gain for a crude futures contract in more than 3 years (OGJ Online, Feb. 3, 2004).

A coker unit was taken down Jan. 30 at ChevronTexaco Corp.'s 260,000 b/d refinery in El Segundo, Calif. On Feb. 1, a fire shut down a crude unit at BP PLC's 410,000 b/d refinery in Whiting, Ind., while another fire forced the closure of a hydrotreating unit at ConocoPhillips's 286,400 b/d Wood River refinery in Roxana, Ill. Such problems at a time when refineries start switching their seasonal production from heating oil to gasoline triggered concerns about low inventory levels in previously complacent markets.

Bearish crude inventory builds

However, futures prices for crude and petroleum products fell in profit-taking Feb. 3 as traders shrugged off those previous worries in expectation that the US Energy Information Administration would report a build of 500,000-1 million bbl in US oil stocks for the week ended Jan. 30.

On Feb. 4, EIA reported an increase of 7.9 million bbl in commercial US crude inventories to 271.6 million bbl for the week ended Jan. 30. Even so, it said, US crude stocks remained 28.9 million bbl below the 5 year average for that time of year.

US distillate stocks fell by 6.8 million bbl to 124.2 million bbl during the same weekly period, with large decreases in both diesel fuel and heating oil. Gasoline inventories declined by 400,000 bbl to 205.6 million bbl, 9.5 million bbl below the 5-year average, said EIA officials.

The American Petroleum Institute's report on US inventories for the week ended Jan. 30 was more conservative, citing a jump of 6.3 million bbl to 274.5 million bbl of crude. US distillate stocks fell by 4.8 million bbl to 128.8 million bbl, API said, while gasoline inventories increased by 3.7 million bbl to 205.2 million bbl.

EIA cited "a big increase in [crude] imports and a decline in refinery inputs." US imports of crude increased by almost 1.9 million b/d to nearly 10.5 million b/d during the week ended Jan. 30—"the fourth largest weekly average since at least 1990," EIA officials said.

During the same period, crude inputs into US refineries were down by 202,000 b/d to 14.5 million b/d. "Most notable was that crude oil refinery inputs into the Gulf Coast averaged below 7 million b/d for the first time since the week ended Feb. 28, 2003," EIA said.

Because of profit-taking and market reaction to the latest reports of US inventories during NYMEX sessions on Feb. 3-4, the March contract for benchmark crude lost a total of $1.88 to close at $33.10/bbl, still retaining some of its earlier gain. After a gain of 5.04¢/gal on Feb. 2, gasoline for March delivery lost a total of 3.16¢ over the next two sessions to close at 98.57¢/gal on Feb. 4. Heating oil for the same month lost all of its earlier gain of 2.92¢/gal, however, down by a total 5.51¢ to 88.97¢/gal on Feb. 3-4 on NYMEX.

Gasoline demand remains high

However, Paul Horsnell, head of energy research with Barclays Capital Inc. of London, noted that US demand for gasoline "is running higher, and imports are running considerably lower," compared with a year ago. "With maintenance having taken 5% off the level of refinery utilization over the past month, there is not a lot of room for maneuver within the system," he said. "Last year there were two major gasoline price spikes, and the odds of another this year seem to be growing."

Meanwhile, he said, "The heating oil market is now in the middle of the normal period of fastest inventory drawdown." Horsnell said, "The rate of drawdown has been faster than normal and is keeping pace with what was the coldest part of the US winter last year. Indeed, in the key Central Atlantic states, the drawdown has been even faster than a year ago."

As a result, he said, "The heating oil market might have relaxed a little too early, running some risk of a repeat of last year's late season surprise."

Industry Scoreboard

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Industry Trends

CANADIAN OIL INDUSTRY financings reached $11.4 billion (Can.) for 2003, setting a new record compared with the 2002 total of $10 billion, Sayer Securites Ltd. said.

"In 2003, all the stars were aligned in the financing markets for the oil industry," said Calgary-based Sayer Securities analyst Brent R. Heinz.

He noted that 2003 marked the third consecutive year of increases, spurred by high oil and natural gas prices, low interest rates, increased market demand for royalty income trusts (RITs), and the resurgence of small-capitalization companies tapping the equity markets.

The most striking change in the three categories of financings was a sharp increase in RIT unit issues. The level increased to $4.1 billion in 2003 from $1.4 billion in 2002. In 2001 and 2000, total RIT financings were $1.4 billion and $800 million, respectively.

In 2003, RITs purchased $4.5 billion worth of assets, showing a high correlation between RIT unit issues and acquisition dollars spent. Much of RIT financing dollars went to acquiring new oil and gas assets to replace production and increase reserves, Heinz said.

The growth in RIT financings is related not only to more acquisitions for each RIT, but it also reflected a growing RIT market. The number of RITs was 15 in 2000 compared with 18 by the end of 2002.

"However, in 2003, 10 new RITs entered the market, primarily through reorganizations of exploration and production companies," Heinz said.

Despite the surge in capital entering the RIT market, the debt category still dominated 2003 statistics with a value of $5 billion, Heinz said. Mimicking the trend in 2002, straight debt dominated this category as opposed to convertible debt.

The primary issuers were the senior exploration and production companies, including Nexen Inc. ($1.18 billion in two transactions), PetroCanada ($814 million in two transactions), EnCana Corp. ($671 million in one issue) and Suncor Energy Inc. ($657 million in one issue). All the companies are based in Calgary.

Collectively RITs issued $1.55 billion in debt, spread over 11 transactions, which made up 31% of the total debt financings for the year. The combination of RIT unit offerings and RIT debt issues equated to a total contribution by RITs to the financing market of $6.5 billion, or 57% of total financings for the year compared with 19% in 2002.

Another strong area of the market was equities, with investors contributing $2.3 billion. This marked the third consecutive year of increasing equity issues and an increase from the 2002 total of $1.57 billion.

"Similar to 2002, in 2003 the lion's share of equity issues were by junior producers while the senior E&P companies were absent from the equity markets," Heinz said. "If the equity is split between straight equity and flow-through, or (tax) equity money, the statistics show that both types of investments have increased. Straight equity accounted for $1.74 billion, 40% higher than in 2002, and the highest amount since 1997."

Government Developments

ENERGY LEGISLATION remains stalled before the US Congress, although a key Senate sponsor is hopeful that a trimmer, less controversial version could still pass this session (see special report beginning on p. 18).

US Senate Energy and Commerce Committee Chairman Pete Domenici (R-NM) said Feb. 3 he plans to offer colleagues later this month a bill that no longer includes a contentious provision to extend liability protections to the fuel additive methyl tertiary butyl ether. He also will pare back the $31 billion tax title but has not said where the cuts will be.

A compromise bill brokered with the House last November failed by two votes to win final Senate approval; MTBE liability and tax breaks doomed the legislation.

Meanwhile, Domenici's House counterpart, Energy and Commerce Chairman Billy Tauzin (R-La.), plans to resign his leadership post Feb. 16; he will leave Congress at the end of the term. Industry lobbyists downplayed the impact his absence will have on the energy bill because House Majority Leader Tom DeLay (R-Tex.) was the lawmaker who orchestrated the House's position during last year's negotiations. Tauzin's anticipated replacement, Rep. Joe Barton, (R-Tex.) holds views similar to DeLay's on oil and gas issues.

In the past, House Republicans have said they will not accept a bill without MTBE liability protections; an earlier, Senate version extended the "safe harbor" to ethanol additives. Now, with the prospect of a new Senate bill to consider, some House Republicans are hinting they might accept legislation without MTBE liability protection if they can bring back other provisions to the negotiating table.

House Resources Committee Chairman Richard W. Pombo (R-Calif.), a DeLay protégé, wants to help fund a pending highway bill with federal lease sales from a portion of the Arctic National Wildlife Refuge. Opening just 2,000 acres for leasing could yield $2.1 billion to the US Treasury, Pombo suggested.

Both Republican and Democratic leaders are mulling the addition of streamlined energy legislation to the highway bill. But adding ANWR back into the discussion could kill energy legislation, according to Senate congressional sources. The Senate narrowly rejected the House's ANWR provision last year.

Unlike ANWR, a pending ethanol mandate provision now in the energy bill is expected to pass this Congress one way or the other. The proposal requires fuel suppliers to meet a 3.1 billion gal/year level beginning in 2005; it rises to 5 billion gal/year by 2012. Suppliers not interested in using ethanol could trade credits; US officials may suspend the targets if the mandate results in severe fuel shortages. House Republicans also are looking at alternative legislation to promote domestic energy, assuming the energy bill fails. Lawmakers from oil and gas producing states are drafting a plan that would give states more authority over offshore drilling (OGJ, Nov. 3, 2003, p. 28).

Proponents say they want to encourage exploration in gas-prone areas on the Outer Continental Shelf, now off-limits because of existing federal moratoriums. The White House officially opposes lifting existing OCS moratoriums.

Quick Takes

BG LNG SERVICES LLC, a wholly owned unit of BG Group, signed an agreement with Trunkline LNG Co. and Trunkline Gas Co., both units of Southern Union Co., for the second phase expansion of the Lake Charles LNG import terminal in Lake Charles, La.

Trunkline LNG this month will seek Federal Energy Regulatory Commission approval to begin Phase 2 work, and the Southern Union units will pay expansion costs.

BG holds rights to 100% of the terminal's capacity.

The terminal is the largest in North America, BG said. Phase 1 expansion, which is under way, will increase the terminal's natural gas send-out capacity to 1.2 bcfd from 630 MMcfd and terminal storage capacity to 9 bcf of gas from 6.3 bcf.

Phase 2 will boost send-out capacity to 1.8 bcfd of gas.

Trunkline Gas, meanwhile, will build a second 230 mile, 30-in. natural gas pipeline from the terminal, increasing total pipeline capacity out of the facility to 2.1 bcfd from the current 1.3 bcfd.

Phase 1 is slated to be in service by Jan. 1, 2006; Phase 2, in mid-2006.

BG added that because the arrangement with Southern Union removes the need for the proposed Lake Charles Express pipeline extension, that FERC application has been withdrawn.

Crystal Energy LLC, Houston, and the Alaska Gasline Port Authority (AGPA) have signed a memorandum of understanding to negotiate the delivery of Alaska LNG to the proposed Clearwater Port LNG terminal off Ventura County, Calif. AGPA would supply as much as 800 MMscfd of gas for 20 years to the terminal. The LNG would come from an LNG liquefaction plant to be built at Valdez, Alas. Both the Crystal Clearwater and AGPA projects are still in the development stage. The Clearwater Port project calls for converting the existing Grace platform 11 miles offshore into a regasification terminal to import LNG (OGJ Online, Nov. 5, 2003). Crystal Energy said it plans to submit applications by Feb. 12 for review by federal, state, and local agencies. AGPA was formed as a municipal port authority for the city of Valdez, the North Slope Borough, and the Fairbanks North Star Borough to deliver gas from Alaska's North Slope to energy markets in the Pacific Rim area.

PLAINS ALL AMERICAN PIPELINE LP, Houston, expects to complete in the third quarter a 1.1 million bbl expansion of its crude oil storage and terminal facility in Cushing, Okla. The $10 million, Phase IV expansion will expand the facility's total capacity to 6.3 million bbl.

The Cushing terminal stores and segregates many varieties of both US and foreign crude oil. Upon completion of Phase IV, it will consist of sixteen 270,000 bbl tanks, four 150,000 bbl tanks, fourteen 100,000 bbl tanks, and a manifold and pumping system capable of handling as much as 800,000 b/d of crude oil throughput.

Cushing is the official designated delivery location for crude oil futures contracts traded on the New York Mercantile Exchange.

PLC NORWAY'S STATOIL ASA this year will attempt one of the world's longest boreholes in the Norwegian North Sea. Starting in October, the company plans to deepen an existing producing well from the Gullfaks A platform to 10,000 m TMD to tap the nearby Gulltopp accumulation 5 km north of Gullfaks satellites Gullveig and Rimfaks. Gulltopp, formerly Dolly (OGJ Online, Nov. 27, 2002), has reserves of 25 million bbl of oil and 17.6 bcf of gas.

The sidetrack from Gullfaks A will be deviated to 83° from vertical to the point where it penetrates the Brent reservoir and then to 90° through the formation. The well's $43.9 million cost is 25% of the tab to develop Gulltopp via subsea template and dedicated multiphase flowlines. Success could help make other small Norwegian oil and gas prospects commercial, Statoil said, including several near Gullfaks.

Statoil on Jan. 26 spudded the first of 30 production wells in Phases 6-8 of the South Pars gas development project off Iran. Each well will be drilled to 4,000 m TMD. For this work, Statoil chartered the Rani Woro drilling rig, owned by Indonesia's PT Apexindo Pratama Duta in Jakarta, for a 3 year drilling program. Iran's Pars Oil & Gas Co., manager of overall South Pars development, has a 5 year contract with Japan Drilling Co. for the Sagadrill 2 rig, which also is being chartered to Statoil for 3 years. Sagadrill 2 is scheduled to spud its first well as soon as the second jacket for the wellhead platforms has been installed. The first of the three jackets in Phases 6-8 was installed Jan. 5, and the second jacket was slated for deployment to the field in early February (OGJ Online, Jan. 7, 2004).

FLORIDA has filed a lawsuit against former and current owners of the now-defunct St. Marks Refinery Inc. in Wakulla County, Fla., seeking penalties for environmental violations and more than $12 million the state spent to clean up pollution at the refinery site. The complex includes a shuttered 20,000 b/d refinery and a 465,000 bbl storage facility.

Defendants are current owner Houston-based American International Petroleum Co. (AIPC), AIPC unit St. Marks Refinery Inc., former owner Seminole Refining Corp., and former Seminole Refining Vice-Pres. James T. Young.

Although the plant has not operated as a refinery since 1985, asphalt was made there until 1998. For 50 years, the plant produced and stored asphalt, pentachlorophenol, and other petroleum products. Inspectors found that runoff from oil lagoons and tar pits had contaminated nearby water and soil, and dioxins were discovered at levels above state standards, Florida officials said.

Croatia's national oil and gas company, Industrija Nafte Zagreb (INA), plans to modernize its Rijeka refinery to increase production and improve safety and environmental performance. INA awarded a $3.8 million contract in January to Honeywell Process Solutions EMEA, Phoenix, Ariz., to automate the refinery and power the plant operations, which would provide more-accurate monitoring and control of the fluid catalytic cracking unit and power plant. Honeywell will provide engineering, on-site services, and project management throughout the refinery automation project.

STATOIL AND NORSK HYDRO ASA have awarded a $13 million contract to Stavanger-based Smedvig ASA for use of its West Navigator deepwater drillship.

The dynamically positioned West Navigator's new assignment includes drilling two exploration wells, Alve and Linerle, in the Norwegian Sea. Drilling will begin Mar. 15 and is expected to last 65 days.

West Navigator last year set a new drilling time record off Mauritania while drilling the Tiof West well in Chinguetti field for Woodside Mauritania Pty. Ltd. (OGJ Online, Dec. 19, 2003). It drilled 1,641 m in 5.3 days, including setting and testing the blowout preventer, in water 1,351 m deep, Smedvig reported.

Following completion of Statoil's project, West Navigator will return to an area off West Africa where Australia's Woodside Petroleum Ltd. has contracted for the drillship's continued use (OGJ, Jan. 5, 2004, p. 9). The drillship, which drilled 3 wells for Woodside in Chinguetti field in 2003, will drill 11 production wells and several exploration wells off Mauritania during June, 2004-July 2005 under an $80 million contract. Esso Production Malaysia Inc. awarded Smedvig an $18 million contract extension for T-2, a self-erecting tender rig currently drilling production wells for Esso in Malaysia. The 1 year extension, which began in January, includes an option for another 2 years. In April or May, T-2 will be replaced by T-9, which currently is under construction in Malaysia.

HOUSTON-BASED Tractebel North America Inc.'s planned 165 mile, 24-in. natural gas pipeline from the Bahamas to Florida received a boost Jan. 23 when FERC concluded that the US portion of the project can be built with minimal impact to the environment.

TNA said it expects to receive shortly a FERC certificate authorizing construction. It has filed numerous other permit applications with federal, state, and local agencies. The project received an approval in principle from the Bahamas government and is awaiting final approvals there.

Construction is scheduled to begin this year, with first deliveries in 2007.

Tractebel Calypso Pipeline LLC pipeline would deliver 832 MMcfd of gas from the planned Tractebel Calypso LNG regasification facility in Freeport, Grand Bahama Island, to a connection to Florida Gas Transmission Co.'s mainline system near Fort Lauderdale.

TNA is the business unit of Tractebel Electricity & Gas International, a subsidiary of Brussels-based Tractebel SA.

STATOIL reports that Glitne field in the North Sea now is thought to have more than 50 million bbl of crude oil—double the company's original estimate—and the field is expected to produce until 2007 from six wells instead of three, which were originally planned to shut down in 2003 (OGJ Online, Aug. 29, 2001).

The field is on Blocks 15/5 and 15/6 in the Sleipner area of the Norwegian North Sea about 40 km northwest of Statoil's Sleipner East development.

Glitne is being produced via the Petrojarl I FPSO. Photo by Bent Sørensen, courtesy of Statoil.
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Glitne is being produced using Petroleum Geo-Services ASA's Petrojarl I floating production, storage, and offloading ship, which has been chartered for 2-3 years. Production is set to reach a plateau of roughly 40,000 b/d of oil.

Far East Energy Corp., Houston, has drilling operations under way on its second gas well (FCY-EH02) on the Enhong-and-Laochang coalbed methane blocks in the Yunnan Province of southern China. A third test well (FCY-EH03) is scheduled for February, with completion of all three expected by early spring. Far East Energy will spend $1.1 million to drill the three wells and conduct desorption tests. A fourth and fifth well will be drilled by late spring, with dewatering and testing slated for the second quarter. The company said it also would drill 8 more wells in Yunnan Province during the second half of this year, for a total of 13, and eight more wells on the Enhong and Laochang tracts during the second half. Lafayette-based Stone Energy Corp. reports production under way from two discoveries in the Gulf of Mexico, both drilled from existing facilities. Production began in January on Stone's 100%-owned OCS-G 19869 A-5 well on the Harding prospect on Main Pass Block 287. Deep sands gas production is under way on the Maximus prospect from the OCS-G 1252 No. E-4 discovery well on South Timbalier Block 166. The well was drilled to 17,935 ft MD, and initial gross production was 19 MMcfd of gas and 432 b/d of condensate. The operator logged about 203 net ft MD of gas in three sands below 16,750 ft. Stone Energy has a 40% working interest in this block. Initial oil and gas production has begun at Vancouver, BC-based Ivanhoe Energy Inc.'s Citrus No. 1 well in California's San Joaquin basin. The well, the first horizontal well on the Citrus prospect area in the Antelope shale formation, extends the southern productive area of Lost Hills field. Ivanhoe is operator. The initial production, through a 35/64-in. choke, is 210 b/d of 34° gravity oil, and 195 Mcfd of gas, with flowing tubing pressure of 270 psi at the surface. Water production along with oil and gas is standard in this field. The total horizontal section—more than 1,900 ft—was drilled at 7,750 ft VD. Continued successful production from Citrus No. 1 could justify as many as 25 additional horizontal locations in the Citrus prospect area. The presence of five stacked, multiple oil zones in this well could justify multilateral horizontal well bores in future wells. The other four potentially productive oil zones in the Citrus No. 1 well have not been tested, but they do produce in offsetting wells. Each horizontal well, with a lateral extension of 1,900 ft, is expected to cost $1.8 million, about 50% more than a vertical well.