OGJ Newsletter

Crude oil prices then rose to $34.13 on Mar. 7 as gasoline prices rose to $1.529 the week of Mar. 20. On Apr. 10, crude oil prices fell to $23.85/bbl, and gasoline prices fell to $1.420/gal the week of May 1. Then, during the week of June 19, gasoline prices increased to $1.681/gal, and crude prices increased to $33.05/bbl on June 20.

"The sharp price declines of April following the March OPEC meetings have been reversed because crude oil supply-and-demand conditions remained tight worldwide," API said.

In June, OPEC resolved to increase quotas by an additional combined 702,000 b/d, and on July 3, Saudi Arabia said it would produce 500,000 b/d above its June quota increase.

"We have yet to see these additional volumes on the market," said API. "The US continues to import more than 55% of our petroleum needs and remains at the mercy of world oil markets."

API also noted that requirements for different fuels in different US regions has reduced the flexibility of the US refining and distribution system to respond to unforeseen events such as a pipeline or refinery outages-accounting for Midwest gasoline price spikes that went beyond the crude price rise.

Supply data turn bullish
API's inventory report last week was unexpectedly bullish (see Industry Scoreboard, p. 6).

That followed API's report that US gasoline stocks had risen 9 million bbl during the previous week, as imports declined 2 million b/d. Traders viewed the decline in imports as very significant.

Analysts said the decline in US stocks was very intriguing, as there was so much talk of output being increased by some major producers at a time when demand is declining.

NYMEX crude oil for September delivery rose 47¢ Aug. 1 in response to the API report to settle at $28.26/bbl, while the October contract stood at $27.97, up 39¢.

OPEC's recent caution to markets-as suggested earlier by the opec president's letter to oil ministers, outlining the reasons why it would be unnecessary to boost production further in August-also created a bullish sentiment (OGJ Online, Aug. 2, 2000).

Natural gas panic looming?
Some analysts are warning of a coming spike in natural gas prices this winter, expressing concerns over the low level of storage and the lag time in getting wellhead deliverability back up to where it belongs in order to meet expected spurts in demand as cold weather snaps arrive this winter.

AGA has warned that US consumers could face significantly higher natural gas prices this winter. Noting that spot gas prices have topped $4.50/Mcf in the past month and still hover near $4/Mcf, an AGA report says prices could go higher still in the near term as more supply is directed toward storage.

But Greenwich, Conn., analyst Charles Maxwell of Weeden & Co. fears that, given the increased gas-fired power demand cooling load, the strong US economy, and a return to normal winter weather-which the last few winters decidedly have not been-markets are likely to see storage to come in below 2.5 tcf. That's well below the 3 tcf that is considered the safe threshold for the start of the heating season.

Maxwell said, "In practical terms, unless the coming winter approaches the highly unusual, +13% warmer-than-usual season we have just passed through, US gas storage numbers are accumulating in a potentially disastrous pattern of insufficient gas to take this country through the full span of cold weather to April of 2001.

"There is the possibility that we will be forced to allocate gas supplies to private homes, government departments, and public institutions, to defense installations, and to schools, universities, hospitals, and so on."

He sees this as a likely scenario unless some reversal in the US gas consumption trend of 3%/year growth is forthcoming. Accordingly, Maxwell speculates that natural gas prices could peak in February at $6-7/MMbtu.

The results could be a higher price range for natural gas, application of new technology, increased drilling, more LNG terminals, and an increased push to bring Alaskan gas south.

Industry Trends

US oil companies still grapple with weak performance on wall street despite much-improved oil and gas prices.

Marathon Oil has devised a plan to refocus its upstream operations to rescue its recent poor stock performance.

Marathon plans to overhaul its upstream operations to help narrow a "value gap" that exists between analysts' target price for its stock and the actual price. There are four reasons that this gap exists, says new Marathon Pres. Clarence Cazalot Jr. during a conference call hosted by PaineWebber Inc. in late July. These reasons are-as detailed in a PaineWebber summary report-Marathon's poor underlying upstream sector performance, its relatively high exposure to the refining-marketing sector, the current corporate structure of USX-Marathon, and the company's lack of credibility with investors.

Cazalot presented five initiatives aimed at improving its upstream business: to improve significantly the core business through cost-cutting; to cultivate a profitable resource base; to construct a high-quality portfolio; to further reduce debt and maintain current capital outlays; and to deliver on what is promised. PaineWebber called Marathon's new upstream strategy "credible and very achievable."

Natural gas will be the primary target this year for drillers in Western Canada, says the Petroleum Services Association of Canada in its midyear forecast. PSAC says about 15,529 wells will be drilled in 2000, 60% of them gas. The forecast compares with 10,605 wells drilled in 1999.

The association forecasts 4,090 oil wells, 9,185 gas wells, 2,014 dry holes, and 240 service wells will be drilled. That amount of drilling activity is expected to generate $7.4 billion (Can.) in revenues in 2000 for oil field service and manufacturing companies.

PSAC estimates 11,095 wells will be drilled in Alberta this year, up 200% from 1999; 900 in British Columbia, up 64%; and 3,490 wells in Saskatchewan, up 225%.

The Canadian Association of Oilwell Drilling Contractors has forecast a slightly higher drilling total this year at 16,500 wells.

Elsewhere in Canada, high natural gas prices have boosted oilsands production costs above targets set for this year, says northern Alberta oilsands operator Syncrude Canada. Syncrude says its gas costs have increased 48% this year and are a factor in increasing production costs to $14.16/bbl. (Can.) from a target cost of $12.25.

Another factor in increased costs was a 45-day maintenance shutdown and work related to Syncrude's $6 billion expansion program now under way.

Meanwhile, US Well completions are up.

US well completions last quarter totaled 6,326, vs. 4,116 in the same period last year, a 54% jump, notes API.

In the second quarter, oil well completions rose 95% to 2,133, gas well completions 42% to 2,982, and dry holes 31% to 1,211. API also says total exploratory completions rose 14% in the second quarter, and completed development wells were 58% higher. It put total footage in the second quarter at 34,073,000 ft, a 41% increase.

Government Developments

US energy supply issues continue to heat up in this presidential election year.

US Rep. Don Young (R-Alas.) last week asked Pres. Bill Clinton to confirm or deny rumors that he intends to designate the Arctic National Wildlife Refuge Coastal Plain as a national monument. Young is chairman of the House resources committee, which has jurisdiction over federal lands.

This year, Clinton has used his executive powers under the 1906 Antiquities Act to establish 10 national monuments. He reportedly is considering declaring monuments in the ANWR Coastal Plain and the Copper River Valley area.

The coastal plain east of Prudhoe Bay field contains North America's largest undrilled structures that are postulated to hold, by the latest government estimates, a volume of oil perhaps equal to remaining US proved reserves. But the area cannot be leased unless authorized by Congress.

In a letter to Clinton, Young notes that the Alaska National Interest Lands Conservation Act mandates that only Congress can designate monuments, wilderness areas, and refuges on federal lands in Alaska. Young says the clause prohibits the president from even considering designating more conservation areas unless Congress explicitly authorizes it: "The president is flatly prohibited from even considering the creation of a new monument under the 1906 Antiquities Act in Alaska, as he has done in the Lower 48 states. I'm formally putting him on notice that he stands in stark violation of Federal law if he intends to create a monument in my state."

THE PUSH FOR A US BAN ON MTBE gathers momentum, threatening to disrupt future gasoline supply fungibility in the country, even as a federal investigation into the recent Midwest gasoline price spikes continues (see related story, p. 20).

Sen. Bob Smith (R-NH), the Senate environment and public works committee chairman, wants to phase out MTBE in gasoline within 4 years and plans to mark up the legislation at a Sept. 7 committee meeting. Unlike the Clinton administration's proposal, however, Smith's bill does not mandate a larger role for ethanol as a gasoline oxygenate.

The legislation would allocate $200 million from the Leaking Underground Storage Tank fund for MTBE cleanup activities. And it would allow states to waive the current federal requirement that reformulated gasoline contain 2 wt % oxygen. Also, the legislation would allow EPA to set toxicity standards for gasoline in order to preserve air quality gains from MTBE use and would require a study of those standards within 5 years.

US northeast winter fuel oil shortage concerns persist.

US Energy Sec. Bill Richardson said, "It's important that we address the heating needs of this region now. We are working with the Congress, state and local officials, and industry representatives to be prepared for the coming winter. If we wait until the temperature starts to drop, it will be too late."

A closed-door meeting will include a panel discussion among the Northeastern Fuel Industry members, heating oil distributors and terminal operators, transportation officials, and fuel market analysts, as well as the government officials.

Quick Takes

Caspian sea exploration prospects grow brighter.

Offshore Kazakhstan International Operating Co. (OKIOC) partners revealed a few details late in July about their Kashagan East 1 wildcat, spudded last fall in the North Caspian Sea. Drilled to 16,400 ft TD, the well found oil pay in Palaeozoic carbonates below 13,000 ft, says OKIOC. The lower zone, the first of two tests planned, flowed at rates as high as 3,700 b/d of 42-44° oil and 7 MMcfd of gas through a 32/64-in. choke. Kashagan East 1 is the first well drilled by OKIOC. The well was drilled 47 miles southeast of Atyrau with the world's only arctic-class barge rig, Sunkar Rig 257, owned by Parker Drilling (OGJ, Sept. 20, 1999, p. 90).

On the basis of this first well, local officials have touted the Kashagan reservoir as holding 8-50 billion bbl OOIP, but OKIOC has cautioned against such premature enthusiasm.

Elsewhere in the Caspian Sea, BP began drilling the third well in the Shah Deniz offshore contract area in the Azeri sector. Using the Azerbaijan-based Istiglal semi, BP is drilling the well in the northwestern part of the reservoir, close to Bahar gas-condensate field. The project goal is to confirm gas in the relatively shallow part of the field, where water depths are 50-100 m and to define the oil-gas or gas-water contact zones.

In other exploration news, Colombia awarded a 100% working interest in and operatorship of two new blocks to Canadian Occidental. The Fusa and Villarrica blocks cover 520,000 acres immediately east and south of CanOxy's Boqueron block. The company has identified a number of leads on the blocks that are "look-alikes" to the Guando play that it discovered on Boqueron in Colombia's Upper Magdalena basin earlier this year. About 420 km of 2D seismic will be acquired on Fusa and Villarrica at yearend, with a view to identifying locations for 2001 drilling. Swift Energy New Zealand spudded the Rimu B-1 appraisal well, 2.4 km south-southeast of the Rimu A-1 discovery well on PEP 38719 in New Zealand's Taranaki basin. Operator Swift holds 90% interest in the B-1 well; Bligh Oil & Minerals unit Marabella Enterprises and Antrim International each hold 5%. Rimu A-1 flowed on test 1,600 b/d of oil and 5 MMcfd of gas from Tariki, Bligh said. Rimu B-1 will likely be drilled to about 3,750 m. Next, the Rimu B-2 will be drilled directionally from the Rimu B site. Production start is expected in early 2001. Meanwhile, Fletcher Challenge Energy (FCE) and Origin Energy Resources NZ agreed to farm into Bligh's PEP 38728 exploration permit in the same basin. The permit covers 198.5 sq km and straddles the north-south structural trend of the Tarata thrust system, which defines the eastern limits of the Taranaki basin. The permit lies directly north of the Rimu discovery. FCE and Origin are to jointly fund 100% of the cost of a seismic program on the permit. Under the agreement, Marabella will hold 40%; FCE, 30%; and Origin, 30%. Petronas Carigali made an oil find with the Alab-1 wildcat on its 100%-owned Samarang-Asam Paya PSC off Sabah. Alab-1 was spudded May 22 and drilled to 3,724 m TD. It found five oil-bearing sands. A production test from one zone flowed at 4,700 b/d of oil. More appraisal drilling and seismic data acquisition are planned. Petronas notes the new field is close to Samarang field production facilities and may be put on track for early development. Ramco plans to drill its first well on its onshore Georgia Kaheti Block X license in the fourth quarter. The well will test a new play concept in the foothills of the greater Caucasus Mountains in eastern Georgia near the village of Ziari about 70 km east of Tbilisi. The Ziari-1 well is planned to spud in early October and reach the planned 2,000 m TD in about 30 days. Ramco manages the block license through its local operating company, Kaheti Oil, which holds 100% of the foreign investor interest.

Development of Chevron-BHP's Typhoon project continues.

Cooper Cameron is now testing the first of four subsea production systems, assembled from components of its Mosaic product line, for later installation in the deepwater Typhoon project being developed by Chevron and BHP in the Gulf of Mexico (OGJ, Apr. 10, 2000, p. 39). The subsea systems that Cameron is producing for Typhoon are modular assemblies of the company's standard field-proven products, including gate valves, compact modular actuators, and retrievable insert chokes. The assemblies will be landed on Cameron completion guide bases in 2,000-2,300 ft of water on Green Canyon Blocks 236-237 nearly 100 miles off Louisiana. Those bases are designed to automatically align the assemblies-aided by an ROV-in correct orientation for easier tie-ins to the small TLP, scheduled for installation next May.

Operator Chevron and BHP anticipate first oil from Typhoon by August 2001, less than 4 years after discovery. With a 50% equal stake, this is BHP's first commercial deepwater development project in the gulf.

A Parker-Saipem JV will begin Drilling in Kazakhstan.

Kazakhstan's Karachaganak consortium awarded a 3-year drilling contract to Parker Drilling and JV partner, Italy's Saipem.

Parker and Saipem will provide five rigs and conduct work for Karachaganak Integrated Organization on the Karachaganak development project near Aksai, western Kazakhstan. Parker and Saipem have formed a JV company named SaiPar Drilling Co. to conduct the work. A technical alliance and subcontract have been signed with Kazakhoil Drilling, a unit of Kazakhoil, to provide a sixth rig.

Operations are set to begin in December on the contract, which has three 1-year options. The rig mix will include three drilling and three workover rigs. The project will include workover, recompletion, and new development drilling.

Partners in the Karachaganak project are BG (32.5%), Agip (32.5%), Texaco (20%), and Lukoil (15%). The group signed a 40-year PSA with Kazakhstan in 1997.

In other drilling action, CNOOC says it drilled a deviated horizontal well in Qinhuangdao (QHD) 32-6 oil field in China's Bohai Bay to 3,715 m TD (1,492 m TVD). CNOOC says the A26H oil well's ratio of horizontal displacement to TVD was 2:1, a new record for Bohai offshore operation. The Chinese national firm says QHD 32-6 field has 170 million tonnes of proved reserves, making it the third largest oil field off China. CNOOC operates the field with partners Texaco and ARCO.

BRAZIL HAS ITS FIRST OFFSHORE PRODUCTION FROM A FOREIGN OPERATOR since the opening of oil and gas exploration to non-Brazilian companies in 1998.

Laying claim to that feat is Santa Fe Snyder, which started up production from the CES-124 well, a reentered Petrobras well in Carauna field in the Potiguar basin about 30 km off Brazil's Ceara state.

CES-124 flowed at an initial rate of 1,000 b/d of 23° gravity crude. Santa Fe Snyder plans to reenter a total of three wells and drill two additional wells in 2000 as a pilot program to conduct testing for 1 year.

The company anticipates that, after full field development, gross production will increase to a peak of more than 30,000 b/d by 2004. Operator Santa Fe Snyder holds a 51.4% working interest; other partners are: Repsol-YPF, 26.2%; Petrobras, 20%; and SOTEP, 2.4%.

The well is being produced through a mobile offshore production unit into a FSO tanker.

Topping pipeline news, state-owned Russian oil firm Rosneft is ready to sell part of its stake in the Caspian Pipeline Consortium, Rosneft Vice-Pres. Sergei Oganesyan said at a briefing in Moscow late last month.

CPC is building an oil export pipeline from western Kazakhstan to the Black Sea port of Novorossiisk. Rosneft is committed to transporting 2.7 million tonnes/year of oil in the pipeline. However, it does not have that much crude available to ship. Rosneft owns a 7.5% stake in the project jointly with Royal Dutch/Shell. The 28.2 million tonne/year capacity line is scheduled for completion in mid-2001. Capacity of the 1,580-km pipeline ultimately will reach 67 million tonnes/year after Phase 2 of the project is completed. Costs are estimated at $2.4 billion, rising to $4.2 billion by 2015.

In other pipeline happenings, The Doha-based Gulf Organization for Industrial Consulting, a Gulf Cooperation Council think tank, is studying the feasibility of a proposed $2 billion gas grid project among GCC countries. The proposal calls for a 1,300 km pipeline network to carry gas from Qatar's North field. Most of the construction and financing is expected to be carried out by the private sector. The proposal calls for 1.55 bcfd of natural gas to be shipped via a trunk line whose capacity will be later increased to 2.25 bcfd and finally 3.8 bcfd by 2020. The proposed pipeline network would be designated as Qatar to Dubai, Dubai to Oman, Saudi Arabia to Bahrain, and Saudi Arabia to Kuwait. The think tank met in late July in Doha with a 30-member GCC technical committee to discuss the project. The GCC consists of OPEC members Saudi Arabia, Kuwait, Qatar, and the UAE, plus non-OPEC members Oman and Bahrain. US FERC approved certificates for two major natural gas pipeline projects to serve northeastern US markets-for the Independence Pipeline project and for ANR Pipeline's SupplyLink project. FERC previously had withheld approval until the project sponsors could show their lines would meet market demand. Both companies had to file agreements showing that nonaffiliated shippers had contracted for at least 35% of their proposed project capacity. Independence filed agreements for 38% of its capacity and ANR for 78%. FERC said that, before construction can begin, both projects must file binding throughput agreements. It attached about 100 environmental conditions to the Independence project. More than 1,000 objections have been lodged against the project by landowners along the proposed right of way, and by others. Indepedence would be a 400.4-mile, 36-in. line from Defiance, Ohio, to a terminus near Leidy, Pa. The $677.9 million project would move up to 1 bcfd. FERC approved a proposal that National Fuel Gas Supply abandon facilities along its existing system in Eshbaugh and Lamont counties, Pa., so that Independence can use them. The SupplyLink Project would expand ANR's existing system, adding 72.4 miles of 36 and 42-in. line and compression facilities at five locations in Indiana, Illinois, Michigan, and Ohio.

In the refining sector, Technip has nearly finished installing a fluid catalytic cracker at the Turkmenbashi refinery in Turkmenistan.

The unit has capacity to process 1.8 million tonnes/year of oil and produce 900,000 tonnes/year of gasoline.

Technip's specialists completed most of the construction and installation work. Iranian engineering company Ninisk built the gasoline production unit. Japan's JGC installed auxiliary units, a water desalination plant, and an electricity substation.

Earlier this year, Chiyoda and Nichimen completed the first modernization project at the refinery, including installation of hydrorefining and catalytic reforming units designed to produce 750,000 tonnes/year of gasoline. The project more than doubled gasoline production capacity.

In late 2001 or early 2002, two units for production of lubricating oils and polypropylene will be brought on line. General construction work is being completed on the lubes unit, which will have capacity to produce 80,000 tonnes/year. JGC has begun work on the 90,000 tonne/year polypropylene unit. Foreign investment in the project now exceeds $1.3 billion. The refinery will process 6 million tonnes/year of oil by 2005 and 9 million tonnes by 2010.

A STRING OF MISFORTUNE WITH OIL SPILLS continues for Petrobras. On Aug. 1, the company reported that a processing unit at one of its refineries in Rio de Janeiro state had leaked MTBE.

It is the third incident involving the leakage or spill of Petrobras oil or products in the last month. Petrobras said in a statement that about 1,000 l. of the substance leaked from a unit in Paracambi, Rio de Janeiro, over the preceding weekend. Officials said they were not immediately able to determine the cause of the leak. The leakage has been stopped, however, with no significant environmental damage, says Petrobras.

In July, Petrobras reported a 4,000-l. crude oil spill from an oil tanker off the coast of Rio de Janeiro state. That same month, the company reported a 4 million l. crude oil leak from a pipeline at a refinery in Parana state (OGJ Online, July 17, 2000).