OGJ Newsletter

Oil markets were hinging little hope on the outcome of last week's OPEC oil ministers' meeting in Vienna, which was under way at presstime.

Brent crude futures hit a record low in London trading on Nov. 24-the day before the meeting.

London's International Petroleum Exchange (IPE) reported that Brent crude for January fell to $11.13/bbl in late trading, which was 2¢/bbl lower than the previous rock bottom price, reached Nov. 18.

At close of trading on the 24th, Brent for January delivery stood at $11.19/bbl.

In advance of the OPEC meeting, oil market analysts were expecting an extension of current production quotas. Julian Lee of London's Centre for Global Energy Studies said, "We expectellipselots of soul-searching about compliance with the current agreement, and the usual noises about those members that did not comply. Beyond that, OPEC is not in a position to do much more."

Although President Saddam Hussein of Iraq bowed to the threat of U.S. military action and allowed U.N. weapons inspectors to return to work, Iraqi exports were expected to hiccup as OGJ went to press.

Geoff Pyne, oil market analyst at SBC Warburg Dillon Read, noted that the current fourth phase of the U.N./Iraq oil-for-aid program ended at midnight on Nov. 25. "Iraq has said in the past that this would be the last round with which it would cooperate with the U.N., if sanctions weren't lifted," said Pyne.

"The U.N. is also being slow to pass a new resolution necessary to extend the scheme. While something is likely to be approved this week, it may not be enough to prevent a break in exports. (Iraqi oil marketing agent) SOMO must line up new sales contracts, obtain U.N. approval, then schedule liftings.

"Iraq wants the current fourth phase extended by 2 months. U.N. Security Council diplomats say that there is general agreement on this, but the U.S. is not 100% happy about the idea. The U.S. and U.K. are concerned that Iraq may see the 2-month extension as a deadline for the lifting of sanctions."

Floundering oil prices are causing difficulty for Simmons & Co. when it comes to predicting Gulf of Mexico (GOM) production through 2002. "As energy analysts, we find it difficult to forecast production volumes when activity levels are rapidly changing in response to economic factors," said the firm in its first of a series of depletion studies for various regions.

Nevertheless, GOM oil well depletion rates, currently about 33%/year, will be 33-35% in 2002, predicts Simmons's David Pursell. But natural gas production is the more important issue. Simmons expects gas production decline rates in the gulf to reach 49%/year in 2002 vs. 38%/year today.

"In 1999, 4.1 bcfd of deliverability must be replaced to simply keep GOM gas production flat. This will require almost 1,000 successful oil and gas completions," said the report. "In the intermediate term (2 years), Canadian gas imports and the deepwater GOM cannot offset this depletion. This means that GOM shelf drilling must remain relatively robust to maintain supply."

As a result, Simmons expects drilling activity and day rates to improve in time. In 1999, the gulf active rig count will average 104 rigs, essentially flat with current levels, predicts the firm. And contract utilization rates will average 80% vs. the current 76%. In 2002, the gulf rig count will reach 126 and utilization 95%.

"The industry must work harder just to keep supply flat," said the Houston analyst. The good news, however, is that economics support gulf shelf drilling: "Our analysis indicates that the shelf remains economically attractive given today's natural gas price and drilling costs."

Low oil prices won't put Norway's Saga Petroleum off from further developing its Tordis-area fields in the northern North Sea. The news coincides with a report by Wood Mackenzie throwing doubt on the economics of Norwegian developments in light of current prices (see story, p. 23).

Saga said Tordis would provide a 10% return, even at an oil price as low as $8/bbl. The fields' low development costs are partly due to Saga's ability to make use of spare capacity it has in the area.

Two new fields are being added to the subsea development.

H Central has been in test production since April (OGJ, May 11, 1998, p. 46), and Tordis East is slated to begin producing by month's end.

Two U.S. independent producers have decided to take a longer-term outlook and increase E&P activity in 1999-somewhat of a contrarian tactic in the current oil price environment.

Hunt Oil is expanding its Houston office to focus on additional onshore exploration activities in the U.S. Pres. Gary Hurford said, "Our company is announcing our expansionellipseat a time when the price of oil is low but when opportunities exist for us to add significantly to our U.S. exploration activities. We believe there remain significant (exploration) opportunities for a large, financially sound independent oil companyellipseWe intend to increase our lease positions, generate new prospects, and continue to wildcat in the U.S. We also feel our expanded presence in Houston will assist us with our search for domestic acquisitions."

CNG Producing is boosting its 5-year E&P capital budget by $1 billion over the previous 5 years. Spending for 1999-2003 will be $2.2 billion. "We intend to use CNG's financial strength to press our advantage in E&P," said Chairman George Davidson Jr.

One-third of CNG's $326 million capital budget for 1999 will be spent in deep water, and one-half on the OCS overall. The company hopes to achieve 20% growth in production next year.

More oil industry assets are changing hands amid continued revenue constrictions.

Ocean Energy and Seagull Energy are merging in a tax-free, stock-for-stock swap. The combined firm, which will keep the Ocean Energy name, is valued at $3.6 billion. The Houston-based operator will be the 10th largest U.S. independent E&P company, says Ocean Energy, itself the result of a merger of Flores & Rucks and United Meridian. The firms anticipate annual cost savings of about $45 million through the reorganization of core operating areas into three business units: Onshore North America, Gulf of Mexico, and International.

Duke Energy Field Services has inked a deal to acquire Union Pacific Resources' U.S. natural gas gathering, processing, pipeline, and marketing operations for $1.35 billion. UPR says the properties no longer fit its definition of core business assets.

The sale includes certain 5-year contracts enabling Duke to market UPR's U.S. natural gas and NGL production. It is part of a UPR deleveraging program unveiled earlier this year.

Ruhrgas intends to buy a 5% stake in Russian gas giant Gazprom in two parcels of 2.5%, reports German television station ZDF.

A Ruhrgas official told French press agency AFP that he could not confirm the report but did say that Russia wants to sell a 2.5% stake and that there exists an option for another 2.5%. He added that Ruhrgas intends to evaluate the attractiveness of the investment.

Look for future consolidation in the oil and gas futures trading sector now that the New York Mercantile Exchange and London's IPE are talking of merging. The two exchanges have set up a working party to investigate prospects for a merger. The move follows cooperation in after-hours electronic trading and parallel upgrading of their trading systems.

IPE said it "began discussing other areas of strategic alliance in July in recognition of the two exchanges' common membership base and the potential benefits to the entire energy industry."

Falkland Islanders will be consoling themselves with the thought that the discovery of North Sea oil required great persistence, now that the sixth and final well in a wildcat drilling program north of the Falklands has proved to be another dud.

Shell said its second well off the Falklands, Fitzroy-1, reached a total depth of 3,005 m, encountering several intervals with hydrocarbon indications but, as in Sebald-1, no commercial volumes.

Several of the wells have revealed oil shows, and Shell, like the other operators earlier, said it will review its position when data from its two wells have been evaluated.

As OGJ went to press, Shell Expro was waiting on weather to lift the topsides off the Brent spar, currently moored in a fjord near Stavanger.

The 1,600-metric-ton topsides were to be lifted off the 14,500-ton structure by the Thialf crane barge for scrapping at a nearby shipyard (OGJ, Feb. 9, 1998, p. 30). The operation was slated to begin Nov. 25 but had been put back by the Shell/Esso operating JV several times in the previous week because of storms.

Over the next 6 months, the spar will be raised in the water, and slices of the giant hull will be cut off and lifted onto barges for transportation to Mekjarvik, to be used in the foundations for a new quay.

Europe's refining woes are prompting some creative business decisions by sector participants.

Royal Dutch/Shell has revealed its next rationalization move, following recent decisions to close its U.K. Shell Haven refinery and explore alternatives for its Berre L'Etang, France, plant (OGJ, Sept. 14, 1998, p. 30).

Shell Europe Oil Products signed a nonbinding agreement to swap a 10% stake in its Pernis, Netherlands, refinery for a 22% interest in Statoil's Mongstad, Norway, refinery. Shell will close its 53,000 b/d Sola, Norway, refinery by 2000 because "the investment requiredellipseto meet more stringent future product quality requirementsellipsecannot be justified," said Shell.

Meanwhile, a venture of Shell, BP-Mobil, Elf, and Total that owns the Reichstett refinery in northeastern France has decided to try to walk the fence when it comes to tightening European fuel specs (OGJ, Nov. 16, 1998, p. 44). The plant will neither shut down nor invest in a benzene extraction unit. Instead, it will ship its gasoline output by barge to Shell's Godorf, Germany, refinery, where the benzene will be removed.

According to Shell, the scheme will enable the refinery to continue operating until the second phase of the European Auto-Oil program takes effect in 2005.

More Southwest U.S. gas may be moving to California as the state's oil supply patterns continue to change (see story, p. 27).

Questar Pipeline has acquired ARCO's Line 90-a 16-in. line extending from northwestern New Mexico's Paradox basin to Long Beach, Calif.-for $38 million. Questar will seek FERC approval to convert the line to gas transportation. The project is expected to take 18-24 months and result in 120-130 MMcfd of gas transmission capacity.

As a result of declines in Alaskan and Lower 48 oil production, California is importing more foreign crudes, reducing the need for oil pipeline capacity to the West Coast.