Higher oil taxes and tougher

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1 Be skeptical of gloomy prognostications from people who are in the business of peddling more government. DICK ARMEY, FEBRUARY 1993 Vol. 7, No. 2 $1 Alaska s source for oil and gas news Week of January 13, 2002 Dave LePain, geologist with the state's Division of Geological and Geophysical Surveys. Geologists find evidence of oil in gas-prone Brooks Range foothills Oil explorers who have written off the Brooks Range foothills on Alaska s North Slope as strictly a gas-prone region might have to reconsider their assumptions. State of Alaska geologists Dave LePain and Gil Mull recently told PNA that geological field work and lab results suggest there are oil-prone source rocks and possible oil reservoirs in the foothills from the vicinity of the Dalton Highway westward for 300 miles to the De Long Mountains on the southwestern edge of the National Petroleum Reserve-Alaska. We have close collaboration with the U.S. Geological Survey, and collectively our work has discovered previously unnoticed oil-prone source rocks in Jurassic and Gil Mull, geologist with the state Division of Oil and Gas Triassic age rocks, as well as a number of discoveries of sands with oil staining or strong petroleum odor in Fortress Mountain, Torok, and Nanushuk formations, and in Upper Cretaceous strata, Mull said. The combination of these two oil-prone source rock and really nice looking reservoir sands suggest there may be significant oil potential in the Foothills Belt and reservoirs in several stratigraphic units. Mull is with the Department of Natural Resources Division of Oil and Gas. The Foothills Belt is a geologically defined area that runs, east to west, from edge of the Arctic National Wildlife Refuge to the Chukchi Sea essentially what geographers call the foothills of the Brooks Range. News was a surprise to companies LePain, with DNR s Division of Geological and Geophysical Surveys, said news of possible oil potential in the Brooks Range see GEOLOGISTS page 10 I N S I D E Oil and gas bills prefiled 13 Corps reviews Alpine satellite plans 7 Mackenzie gasline takes leap forward 5 Unocal plans field expansion in Alaska 2 Cook Inlet Keeper says pipelines too risky 3 Agencies comment on proposed ACMP regs 13 Gil Mull P O L I T I C S Wildcatter warns oil tax increase will retard future investment Natural evolution of North Slope oilfields leads to smaller players, without clout to fight onerous taxes and regulations, says Fred James By Steve Sutherlin PNA Managing Editor Higher oil taxes and tougher permitting practices are a recipe for economic collapse in Alaska because smaller companies will simply stay away, says wildcatter and independent geologist Fred James. If the history of other oil producing regions is any indication, those smaller companies are the future of the industry in the state. James said the mega-majors such as BP and ExxonMobil must look to find mammoth reservoirs, while smaller firms such as Phillips can deal profitably with smaller pools. Independents, with their small business cost structure, are delighted to find pools that the majors would find marginal, or worse. Huge companies such as Exxon or BP survive by finding the Prudhoes and Kuparuks. We independents, we re looking for smaller fields. There are no more Prudhoe Bays, James said. But James said the state must take care to craft a tax and regulatory structure that will encourage Once you get the small companies involved, a lot starts to happen. Fred James, wildcatter and independent geologist investment by smaller companies. Typically the smaller companies don t have the staff to lobby for their needs, or to deal with excess bureaucratic hoops set in the way of development. It is important for the state to retain tax policies E X P L O R A T I O N & P R O D U C T I O N Gil Mull For the last eight years Fred James has been a contributing member of the industry consortium that has sponsored the Alaska Division of Geological & Geophysical Surveys field programs on the North Slope. (See related story on this page about oil in the Brooks Range foothills.) He is pictured here at a North Slope field camp set up by DGGS in the summer of Veteran state of Alaska geologist Gil Mull recently said of James, It is a delight to see a true authentic old style independent petroleum geologist working and competing successfully on the North Slope. He digs into the geologic maps, well logs, and whatever seismic data he can get, and applies a lot of old fashioned oil finding common sense to making his interpretations. His activities on the North Slope are not those of a speculator hoping to luck into something good, but are those of a true hard working earth scientist and oil finder in the classic sense, applying all the tools of the trade that are available to him in addition to just good old common sense. such as the economic limit factor, which are designed to encourage investment in smaller fields. The key is, you don t tax away profits, James said. The one reason we drill is the anticisee JAMES page 16 BP laying off 20 percent of Anchorage staff; some positions were temporary Company will shelve offshore Liberty project, focus on existing fields in strategy to make Alaska business cost effective for the long term By Kristen Nelson PNA Editor-in-Chief Following a decision last year to move frontier exploration to Houston and focus on exploration near existing fields, BP Exploration (Alaska) Inc. said Jan. 7 that it is reducing its Anchorage staff by 20 percent to make the company viable in the long term. BP Exploration (Alaska) spokesman Ronnie Chappell told PNA the company s focus will be on competitive replacement of production and reserves: We didn t just announce a reduction in force today, we rolled out a strategy for sustaining our business in Alaska over the long term, he said. That strategy involves cost-competitive replacement of production and reserves. We will continue to invest in what is one of the largest reserve bases in all of BP. But we re going to be more selective in the investments that we Ronnie Chappell make, Chappell said. We didn t just announce a reduction in force today, we rolled out a strategy for sustaining our business in Alaska over the long term. Ronnie Chappell, BP Exploration (Alaska) Inc. Liberty not competitive BP s Liberty project offshore east of existing development is being shelved after a review of the project and a determination that it is not competitive as a Northstar lookalike, he said. Chappell said BP will continue to evaluate see LAYOFFS page 15

2 2 Petroleum News Alaska Week of January 13, 2002 ON DEADLINE PIPELINES & DOWNSTREAM Pipeline shifts near Fairbanks Alyeska Pipeline Service Co. said Jan. 7 that ground surveillance crews found seven anchors had tripped on the vertical support members supporting the trans-alaska pipeline. Alyeska said the anchors had moved or tripped on VSMs in the Prospect Creek area near Pump Station No. 5. The company's system engineering team is investigating the cause of the movement, which was discovered Jan. 4. Many VSMs on the pipeline have anchor assemblies, Alyeska said. The system put in place to protect the integrity of the pipeline performed as designed and remains in good condition, the company said. That system consists of the anchors, the shoes and sacrificial components such as energy absorbers. No oil was spilled. Repairs began Jan. 7 and are expected to take seven to 10 days to complete. Pipeline surveillance was conducted between North Pole metering (just south of Fairbanks) and Pump Station No. 5 and Alyeska said that no other problems were observed. Alyeska spokesman Mike Heatwole told PNA Jan. 8 that the pipe shifted over a one and a quarter to one and a half mile stretch of line about 175 miles north of Fairbanks. The anchors moved from a few inches to 14 inches. F I N A N C E & E C O N O M Y Unocal sees 2002 worldwide capital spending at $1.7 billion, says Chairman and CEO Williamson In Alaska the company will redevelop large mature oil and gas fields; production growth will come from seven areas in , including South Kenai gas By Kristen Nelson PNA Editor-in-Chief Unocal Corp. said Jan. 7 that it expects capital expenditures for 2002 of approximately $1.7 billion, essentially unchanged from the estimated expenditures in The company said the capital-spending estimate does not include major acquisition expenditures for either year. We are shifting more of our capital spending emphasis in 2002 to development programs, Charles Williamson, Unocal chairman and chief executive officer, Charles Williamson, said in a statement. Unocal chairman and We expect to chief executive officer spend about $250 million, or 15 percent of our plan, on development of new deepwater oil and gas production in Indonesia and the Gulf of Mexico. We also will move forward in Azerbaijan with the phase-one oil development and construction of the main export pipeline. Development expenditures of about $1.1 billion for 2002 are up from $900 million for 2001, Williamson said. Unocal s exploration capital of $400 million is down from $500 million for The company said its 2002 exploration capital estimate includes spending for delineation of the Field expansion planned in Alaska Unocal Corp. Chairman and CEO Charles Williamson told a Jan.8 Goldman Sachs energy conference that Unocal is pursuing a number of niche strategies. For existing assets, the company plans to high grade inventory development projects and follow-on exploration opportunities. In Alaska and Indonesia the company will redevelop large mature oil and gas fields. And in both Alaska and China, Williamson said, Unocal will be pursuing new near-time gas development and market opportunities. He said production growth will come from seven areas in , including South Kenai gas in Alaska, where first production is expected in and estimated peak production is expected to be Unocal net of more than 9,000 barrels oil equivalent per day. In 2002, Williamson said, major development projects will be on track in several areas, including Alaska. Unocal Corp. Chairman and CEO Charles Williamson told a Jan.8 Goldman Sachs energy conference that... production growth will come from seven areas in , including South Kenai gas in Alaska, where first production is expected in and estimated peak production is expected to be Unocal net of more than 9,000 barrels oil equivalent per day. Trident deepwater Gulf of Mexico discovery and the Ranggas deepwater Indonesian discovery. Unocal said it will spend about $800 million in 2002 on international projects including continued development of oil and gas in the Gulf of Thailand, the West Seno deepwater oil project in Indonesia s Makassar Strait and phase one development and main export pipeline for oil fields in the Azerbaijan sector of the Caspian Sea. About $100 million of the international budget is earmarked for exploration work, including drilling on deepwater prospects offshore Indonesia and Brazil. North American capital spending is expected to total about $800 million, including initial development of the deepwater Mad Dog field in the Gulf of Mexico. Planned North American exploration spending is approximately $300 million, including deepwater Gulf of Mexico and Permian Basin.

3 Week of January 13, 2002 COOK INLET ON DEADLINE Petroleum News Alaska 3 Cook Inlet Keeper: Pipelines too risky Cook Inlet Keeper said Jan. 10 that new findings on pipeline spill trends and regulatory oversight show pipelines pose an unnecessary and serious risk to Cook Inlet water and wildlife. The citizen-based non-profit organization is dedicated to protecting Alaska s Cook Inlet watershed. It said in a statement that the number of pipeline spills in Cook Inlet has increased to nearly one per week in 2001; nearly one-fourth of Cook Inlet s on- and offshore pipelines receive little or no regulatory scrutiny; and industry has failed to make information available to help inform pipeline safety decisions. The organization said it would release a full report on these and additional findings in spring The current status of pipeline safety in Cook Inlet is unacceptable, said Lois Epstein, senior engineer and oil and gas industry specialist for Cook Inlet Keeper, and the principal researcher for the pipeline study. The technology exists to significantly improve Cook Inlet pipeline operations but operators have failed to use it, and regulators can t seem to find the traction they need to press for change, Epstein said in a statement. Cook Inlet Keeper said it is recommending immediate baseline integrity assessment for all pipelines that have not been recently assessed; integrity reassessment at least every three years; pipeline leak detection and shut-off valve upgrades; enhanced public reporting of pipeline operations; removal of inadequate lines from service; federal funding for state-level inspections; and establishing a strict liability standard for pipeline releases. The increased number of pipeline spills in Cook Inlet raises concerns that its antiquated pipeline network, with many pipelines built in the 1960s, cannot endure the inlet s harsh environmental conditions without extensive maintenance and upgrades, Cook Inlet Keeper said. The organization said the Alaska Department of Environmental Conservation requested funding from the Legislature last year to conduct a review of the operational status of Cook Inlet pipelines, but Unocal lobbied legislators Drew Pearce and Loren Leman and the funding was stripped from DEC s budget. Epstein said she was prevented by the Alaska Oil and Gas Association from appearing on a panel at a Jan. 10 forum on Cook Inlet pipelines, forcing her to present her findings during the public comment period. Index ON DEADLINE ARCTIC GAS EXPLORATION & PRODUCTION WORLD OIL/SERVICE & SUPPLY GOVERNMENT Kay Cashman, PUBLISHER Dan Wilcox Kay Cashman Kristen Nelson Steve Sutherlin Gary Park Alan Bailey Dawnell Smith Judy Patrick Photography Mary Craig Wadeen Hepworth Susan Crane Forrest Crane Steven Merritt Tom Kearney Brian Feeney Tim Kikta Dee Cashman Heather Yates CHIEF EXECUTIVE OFFICER PUBLISHER EDITOR-IN-CHIEF MANAGING EDITOR CANADIAN CORRESPONDENT CONTRIBUTING WRITER CONTRIBUTING WRITER CONTRACT PHOTOGRAPHER CONTROLLER ASSISTANT TO THE PUBLISHER ACCOUNT EXECUTIVE ACCOUNT EXECUTIVE PRODUCTION DIRECTOR ADVERTISING DESIGN INTERNET DESIGN CIRCULATION REPRESENTATIVE CIRCULATION REPRESENTATIVE ADMINISTRATIVE ASSISTANT Petroleum News Alaska and its supplement, Petroleum Directory, are owned by Petroleum Newspapers of Alaska LLC. The newspaper is published at weekly. Several of the individuals listed above work for independent companies that contract services to Petroleum Newspapers of Alaska LLC or are freelance writers. P.O. Box Anchorage, AK Editorial Editorial Fax Editorial edit@gci.net Bookkeeping & Circulation Bookkeeping & Circulation Fax Advertising Advertising Fax Advertising adsales@gci.net Petroleum News Alaska, ISSN , Week of January 13, 2002 Vol. 7, No. 2 Published weekly. Address: 5441 Old Seward, #3, Anchorage, AK (Please mail ALL correspondence to: P.O. Box , Anchorage, AK ) Subscription prices in U.S. $52.00 for 1 year, $96.00 for 2 years, $ for 3 years. Canada / Mexico $65.95 for 1 year, $ for 2 years, $ for 3 years. Overseas (sent air mail) $ for 1 year, $ for 2 years, $ for 3 years. Periodicals postage paid at Anchorage, AK POSTMASTER: Send address changes to Petroleum News Alaska, P.O. Box , Anchorage, AK

4 4 Petroleum News Alaska Week of January 13, 2002 ON DEADLINE GOVERNMENT Danco wants rehearing on unit decision Danco Inc., Monte Allen and George Kasper, M.D., filed applications late last month with the Alaska Oil and Gas Conservation Commission for a rehearing on the commission s Dec. 3 decision against Danco and Monte Allen s petition for an expansion of the North Cook Inlet unit to include two state leases in which Danco, Allen, Kasper and others hold an overriding royalty interest. Danco and Allen claimed hydrocarbons from the two leases were being drained by the adjacent North Cook Inlet unit, which is operated by Phillips Alaska Inc. Phillips owns the working interest in the two leases and opposed including them in the unit. On Jan. 3, in response to Danco and Kasper s applications for a rehearing, the commission issued an order granting the rehearing because according to state statute if the commission fails to act within 10 days of the application, it is considered a refusal. Because of the large number of points raised by the applications and the holidays, the commission said it needed more time to consider the applications. The commission will issue a further decision on the applications for rehearing no later than Jan. 23, the commission said. Kay Cashman FINANCE & ECONOMY John N. Seitz Seitz promoted to CEO of Anadarko Anadarko Petroleum Corp. said Jan. 9 that its board of directors has elected John N. Seitz as the company s chief executive officer. Seitz is currently president and chief operating officer and will add the role of CEO. Robert J. Allison Jr., currently chairman and CEO, will remain chairman of the board. John has been an instrumental part of Anadarko s tremendous success with exploration and development drilling for more than 20 years and he will now be the chief executive of the company, said Allison. I m proud of what we have achieved for shareholders. Allison also says he intends to be a full-time, active chairman and has no immediate plans for retirement. Allison joined Anadarko in 1973 as vice president of operations and was promoted to president in 1976 and CEO in He took on the additional role of chairman when Anadarko was spun off from Panhandle Eastern in Seitz joined Anadarko in 1977 as an exploration geologist. He was named vice president of exploration and production operations in 1989 and promoted to executive vice president of exploration and production and elected to the company s board of directors in In 1999, Seitz was promoted to the position of president and COO. Semco names chief financial officer Semco Energy Inc. said Jan. 3 that John E. Schneider has been appointed chief financial officer effective immediately. Schneider had been executive vice president and chief operating officer of Semco Energy Gas Co., the Michigan division of the company s natural gas distribution utility, since February In another top-level change, Jon A. Kosht, president and chief executive officer of the company s Michigan s utility, Semco Energy Gas Co., will assume chief operating officer duties for utility operations in Michigan and Alaska. Tony Izzo, president of Enstar Natural Gas Co., Semco s Alaska natural gas distribution division, will report directly to Kosht. Doyon picks new president A former Doyon Ltd. board member has been chosen to serve as the Alaska Native corporation s president. Orie Williams, formerly of Nenana, will fill the vacancy left by Rosemarie Maher, who died of a heart attack on July 6. Most of us who came of age in the early days of the Native land claims and the emergence of Native self-determination can only dream of leading our regional corporations, Williams, 56, said in a corporation press release. I have prepared for this all my life, he said. Doyon s board of directors selected Williams during a special meeting held in Anchorage Jan. 5. Williams leaves his position as executive vice president of the Bethel-based Yukon- Kuskokwim Health Corp. He has held that position for more than 11 years. Williams begins his new job Feb. 18. The Associated Press Natural gas spot prices up due to cold weather The U.S. Department of Energy's Energy Information Administration said the first week of January that natural gas spot prices in the Midwest and East moved up during the holiday period due to cold weather, with prices in Chicago close to $3 a million Btu the last week of the year, and prices in New York City approaching $5 an MMBtu. Nymex futures prices for February declined in recent trading due to higherthan-normal storage levels, which the EIA said continue to be the main contributor to the current strong natural gas supply situation. The agency said an estimated 2.9 trillion cubic feet of gas remained in storage as of Dec. 21, close to 1 Tcf more than last year at this time. The EIA said spot prices in many Lower 48 markets reached their highest levels this heating season on Dec. 31, with prices for delivery to many East Coast markets moving up sharply. But even with these sharp price increases, prices remained well below last year s near record-setting daily prices of late December and early January of more than $10 per MMBtu at the Henry Hub.

5 Week of January 13, 2002 Petroleum News Alaska 5 ARCTIC GAS CANADA Boards, agencies agree to streamline gas pipeline A myriad of Canadian boards and agencies have agreed to make a coordinated response to any proposal for a gas pipeline through the Northwest Territories, removing some of the obstacles that could slow approval of the project. Led by the National Energy Board and the Northwest Territories government, the 12 parties say the draft plan has been presented to their respective chairs and the Indian Affairs and Northern Led by the National Energy Board and the Northwest Territories government, the 12 parties say the draft plan has been presented to their respective chairs and the Indian Affairs and Northern Development Minister Robert Nault. Development Minister Robert Nault. The plan was released Jan. 7, the same day the Mackenzie Delta Producers Group announced it was proceeding to the regulatory phase of developing 5.8 trillion cubic feet of onshore Delta gas. The parties include environmental, land and water boards along the 850-mile Mackenzie Valley pipeline route. Last May, the federal government announced a single environmental review for any pipeline proposal. Natural Resources Minister Ralph Goodale said the one-project-one-assessment model would keep repetition and needless delay to a minimum during the regulatory process. Gary Park M A C K E N Z I E D E L T A Mackenzie Valley gas pipeline takes big leap forward Producers move to project definition phase; say start-up is 6 to 8 years away; analysts say Delta now leads, but slope producers see no impact on their plans By Gary Park PNA Canadian Correspondent Agroup of four foreign-controlled Mackenzie Delta gas producers has embarked on the regulatory stage of Arctic gas development, a move many analysts say has propelled the Northwest Territories ahead of the North Slope in an undeclared pipeline race. The Mackenzie Delta Producers Group announced Jan. 7 that it will spend up to C$250 million on the project definition phase aimed at filing plans with Canada s National Energy Board and 11 other regulatory agencies sometime in The group indicated it could take six to eight if the Mackenzie project is first to market, development of the North Slope could be stalled. (because) the Delta would have a firstmove advantage, by locking up qualified construction workers. Winfried Fruehauf, National Bank Financial Inc. years to complete the application, hold public hearings and bring the gas on stream at a cost of C$3 billion for a pipeline and C$1 billion to develop existing gas fields. But K.C. Williams, senior vice-president of Imperial Oil Ltd. the lead partner in the consortium cautioned that a number of obstacles could yet derail progress. While insisting the newest phase demonstrates the confidence of the producers group that the project is potentially commercial, he said an ultimate decision will hinge on natural gas markets, construction costs and regulatory and fiscal certainty. Partners control 15.8 trillion cubic feet of gas The Delta partners, who control 5.8 trillion cubic feet of onshore gas, are Imperial (69.6 percent owned by ExxonMobil Corp.) with a 50 percent stake; Conoco Canada Ltd. (a unit of Conoco Inc.) with 25 percent; Shell Canada Ltd. (78 percent owned by the Royal Dutch/Shell Group), with 17 percent; and ExxonMobil Canada (a wholly-owned subsidiary of ExxonMobil), with 8 percent. A spokesman for Imperial said this is really where we start to put some meat on the bones, as the proponents move from their two-year feasibility study to start drafting technical, engineering and environmental data in support of regulatory filings. For now, many of the closest observers of the Arctic gas debate say the Mackenzie Delta has edged ahead of the larger, more costly North Slope scheme. Winfried Fruehauf, a pipeline analyst with see MACKENZIE page 6

6 6 Petroleum News Alaska Week of January 13, 2002 ARCTIC GAS C A N A D A Gas producers drop price forecasts in face of excess supply Tenth annual survey by Canadian Energy Research Institute By Gary Park PNA Canadian Correspondent Tired of grappling with volatile supply-and-demand swings and worried about surplus supplies, Canada s natural gas producers may start basing their exploration and development plans on sharply reduced price expectations, says a study by the Canadian Energy Research Institute. CERI s 10th annual survey of forecasts for gas prices, capital spending, drilling and production found that producers are no longer as willing to base their decisions on even conservative price forecasts. The study said the reaction by producers to mild temperatures and a weakened economy last year was so strong that perceptions of a supply-constrained market now have been replaced by impressions of excess supply. As a result, the producers have predicted average gas prices of C$5.72 (US$3.60) per thousand cubic feet in 2001, C$4.42 in 2002 and C$4.05 in With cash flows tightening and gas prices again being battered by high storage levels and sagging U.S. demand, producers are continuing to chop drilling activity, said Peter Linder, an analyst with Research Capital Corp. in Calgary. Land sales drop The strongest evidence of tightened purse strings was a 61 percent drop in fourth quarter land sales in Western Canada from a year earlier, with average bids tumbling to C$50 per acre from C$165 in the second quarter of In addition, the latest profit report for Canadian oil and gas producers, covering the third quarter of 2001, showed capital spending totaled C$8.5 billion for the three With cash flows tightening and gas prices again being battered by high storage levels and sagging U.S. demand, producers are continuing to chop drilling activity, said Peter Linder, an analyst with Research Capital Corp. in Calgary. months, 49 percent more than cash flows of C$5.71 billion, after sky-high commodity prices in the first six months pushed cash flow well above reinvestment. For the first nine months of last year, the largest profit increases were posted by PanCanadian Energy Corp., up C$517 million; Husky Energy Inc., up C$420 million; Anderson Exploration Ltd. (since taken over by Devon Energy Corp.), up C$342 million and Petro-Canada, up C$326 million. The greatest third-quarter profit gains were by Anderson C$58 million, Suncor Energy Inc. C$23 million, Husky C$18 million and Canadian Hunter Exploration Ltd. (since taken over by Burlington Resources Inc.) C$12.8 million. A recovery in demand growth and continued strains on the industry to increase supplies will eventually tighten supply-demand margins again and makes prices in the C$4 (per thousand cubic feet) range achievable over the long term, said the CERI study. CERI predicted capital spending on gas at C$16.97 billion in 2001, C$18.17 billion in 2002 and C$19.5 billion in 2003, while production is expected to average 18.7 billion cubic feet per day in 2001, 18.9 billion in 2002 and 19.4 billion in Gas completions up Gas well completions have grown by more than 2,000 a year since 1998 and producers expected to reach 10,183 in 2001, including substantial increases in the shallow fields of southeast Alberta and Saskatchewan as well as northeastern British Columbia. But CERI said there were signs that exploration is gradually shifting to deeper plays in the Western Canada Sedimentary Basin. The diversion of capital to the Arctic and East Coast offshore could become an issue for future development in Western Canada, the survey said. While the next major developments on the frontiers are beyond the time horizon of the survey, their influence may be felt in a declining share of capital for Western Canada, beginning in 2003, the study authors said. But additional gas deliverability from the frontiers was not likely to show up until , putting pressure on Western Canada to maintain adequate production growth in 2004 and beyond, they said. continued from page 5 MACKENZIE National Bank Financial Inc. in Toronto, said he would put the Delta s chances of starting deliveries before Alaska at somewhat better than even odds right now. It looks like the Mackenzie Delta is in the lead, said Roland George, a principal with energy consulting firm Purvin & Gertz Inc. William Lacey, an analyst with FirstEnergy Capital Corp. in Calgary, said the Delta consortium would not be taking a C$250 million plunge into the project definition phase unless they think there s something feasible at the end of the process... but it s not a slam dunk. Delta could trip scales in favor of over-the-top Bob Hastings, an analyst with Raymond James & Associates, suggested the Mackenzie decision could also tip the scales in favor of an over-the-top route from the North Slope to the Delta because a pipeline would already be in service along the Mackenzie Valley. the Mackenzie decision could also tip the scales in favor of an over-the-top route from the North Slope to the Delta because a pipeline would already be in service along the Mackenzie Valley. Bob Hastings, Raymond James & Associates should affect Alaska. Fruehauf said that considering the lead time needed for the project, much could change, including the possibility that the two projects could be combined into the over-the-top route. Nellie Cournoyea, chair of the Mackenzie Valley Aboriginal Pipeline Corp., said everyone will take the project a little more seriously now. We re committed and (the producers) are committed. The aboriginal group has a chance for a one-third equity stake in the pipeline provided it can arrange for shipments of 400 million to 500 million cubic feet per day that are over and above the 800 million to 1 billion cubic feet per day the Delta consortium expects to produce initially. Mackenzie gas could feed oil sands Current plans are for the 850-mile Mackenzie Valley pipeline to extend from the Delta into Alberta, where natural gas would be fed into TransCanada PipeLines Ltd. s existing grid to eastern Canada and the U.S., while liquids would be stripped from the gas and included in Enbridge Inc. s oil pipeline from Norman Wells, Northwest Territories. Wilf Gobert, an analyst with Peters & Co. in Calgary, pointed out that Alberta s oil sands, which use gas as feedstock for extraction and processing operations, could absorb much of the initial Delta output. Imperial, Conoco and Shell are all major oil sands players and, alone, are estimated to need about 550 million cubic feet per day of gas. The overall oil sands sector may require up to 1.5 billion cubic feet per day of gas by Northwest Territories Deputy Premier Jim Antoine said the Delta producers announcement is a vital step towards construction of the line and an economic lift for the region, with the equivalent of 23,161 jobs lasting one year during peak pipeline construction, 40,000 permanent jobs for the gas industry and C$70 billion in federal royalties from the development. This is what we ve been waiting for, he said. It s something new, something exiting, something innovative for people in the North. Even so, Hastings cautioned that the project economics remain uncertain in today s depressed gas prices. This is not a horse race that has been won or is even close to being won, he said. Fruehauf suggested that if the Mackenzie project is first to market, development of the North Slope could be stalled. He said the Delta would have a firstmove advantage, by locking up qualified construction workers. Alaska team says Delta decision will have no impact A spokesman for the Alaska Gas Producers Pipeline Team said the Delta decision should not have any impact on the North Slope project. He said the partners are in the final stages of a one-year, $100 million feasibility study, which the sponsor companies BP, Phillips Petroleum Co. and ExxonMobil expected to evaluate results and announce their plans in the next few months. Quite frankly, it s two different projects, two different entities, he said. Yukon Economic Development Minister Scott Kent, whose government is a strong backer of an Alaska Highway pipeline route, was equally certain there was no reason why the Delta project

7 Week of January 13, 2002 Petroleum News Alaska 7 EXPLORATION & PRODUCTION STATEWIDE North Slope production up 2.4 percent in December Alaska North Slope crude production averaged million barrels a day in December, up 2.4 percent from an average million barrels a day in November, driven by increases at Northstar, Kuparuk and Prudhoe. The Department of Revenue attributed the boost in production to cooler December temperatures, which averaged minus 7 degrees Fahrenheit at Pump Station No. 1, compared to a plus 3.3 degree F average temperature in November. The North Slope s newest fields contributed an average of some 129,000 barrels per day in December, almost 12 percent of ANS production. Northstar, which began production in November, averaged 29,407 bpd in December, compared to 11,498 bpd in its first month. Alpine, which began production in November 2000, averaged 99,600 bpd in December compared to 101,453 bpd in November. Production from the Kuparuk River field (which includes West Sak, Tabasco, Tarn and Meltwater) averaged 221,249 bpd in December, up 2 percent from an average of 216,961 bpd November and Prudhoe Bay (which includes Midnight Sun, Aurora and Polaris) averaged 555,028 bpd in December, up 1.5 percent from an average of 547,075 bpd in November. Production from the Milne Point field (which includes Schrader Bluff and Sag River) dropped 3.8 percent, averaging 52,985 bpd in December compared to 55,086 bpd in November. Endicott (which includes Sag Delta, Eider and Badami) averaged 32,820 bpd in December, down 2.6 percent from a November average of 33,681 bpd. And Lisburne (which includes Point McIntyre, Niakuk, West Beach and North Prudhoe State) averaged 77,990 bpd in December, down 0.4 percent from a November average of 78,292 bpd. Cook Inlet production averaged 37,504 bpd, up 9.8 percent from a November average of 34,143 bpd, and Prudhoe Bay natural gas liquids averaged 51,037 bpd, up 0.3 percent from a November average of 50,894 bpd. Kristen Nelson ANCHORAGE BLM sets meetings on NPR-A plan, extends comment period Bureau of Land Management staff specialists will be on hand to explain the upcoming planning for 10 million acres in the northwest corner of the National Petroleum Reserve-Alaska at two public meetings. The agency said both meetings will open with an informal question and answer session at 6 p.m. followed by presentations at 7 p.m. see BLM page 8 P R U D H O E B A Y BP tackles goal of identifying long-term maintenance needs at Prudhoe Bay Preventive maintenance backlog at field being reduced with more staff; fire and gas upgrades, integrated maintenance system will take much longer By Kristen Nelson PNA Editor-in-Chief After completion this summer of a report from the Prudhoe Bay Operations Review Team, BP Exploration (Alaska) Inc. acknowledged concerns raised by employees at the field and said it would address them. (See stories in Dec. 2 and Dec. 9 issues of PNA.) Some of those concerns can be addressed more quickly than others. Tom Gray, BP s Prudhoe Bay operations integrity manager, told PNA in a December interview that the report confirmed tangible maintenance concerns that need to be addressed as well as W E S T E R N N O R T H S L O P E Corps of Engineers reviewing Colville Delta satellite plans Construction for Alpine satellites Fiord and Nanuk could begin in February 2003, with first production in third quarter 2004 By Kristen Nelson PNA Editor-in-Chief Tom Gray, BP Exploration (Alaska) Two satellite fields in the Phillips Alaska Inc.- operated Colville Delta unit on the west side of the North Slope could be in production by late The most recent schedule available, in a Jan. 3 comment request from the U.S. Army Corps of Engineers, says construction will begin in February 2003, subject to permit approval. The corps said the schedule supplied by Phillips Alaska in its application to lay gravel for development of the Colville North (Fiord) and Colville South (Nanuq) satellites calls for construction on two pads, a road and an airstrip to begin in February 2003, with first production expected in the third quarter of some staffing issues. Gray said the report also indicated that BP needs to make sure that when issues are brought up, the circle is closed and employees get a response. The operations integrity manager position is a new one. Gray, whose background is in operations and management, said his job is specifically to address the integrity issues making sure that we re fixing the things in the field. Preventive maintenance Backlogs in preventive maintenance were a concern raised by employees. Of some 10,000 pressure safety valves, preventive maintenance was behind on about 10 percent and BP has brought additional crews on to work off the backlog on pressure safety valves. And those backlogs have been reduced not eliminated yet but significantly reduced, Gray said. see MAINTENANCE page 9 Phillips Alaska spokeswoman Dawn Patience told PNA Jan. 7 that the earliest construction would begin would be Phillips has dedicated $47 million to Alpine plant capacity expansion. Both Fiord and Nanuq would be processed through the Alpine facilities and those, she said, are still running full. The facilities were built to handle an expected 80,000 barrels per day and since Alpine production began in November 2000, daily rates have at times exceeded 100,000 barrels. Two new pads will be built The proposed CD South (Nanuq) pad is approximately five miles north of the Village of Nuiqsut and four miles south of the Alpine Central Processing Facility. The proposed CD North see SATELLITE page 8

8 8 Petroleum News Alaska Week of January 13, 2002 EXPLORATION & PRODUCTION continued from page 7 BLM BLM said its planners are interested in the public's concerns and factual information that will help them write the plan. Planning for the northwest portion of NPR-A follows a similar effort in that identified areas suitable for oil and gas leasing on 4 million acres in the northeast corner of the NPR-A. BLM also said it has extended the BLM said its planners are interested in the public's concerns and factual information that will help them write the plan. public comment period for this phase of the planning effort until Feb. 15. The Fairbanks meeting will be Jan. 15 at the BLM Northern Field Office, 1150 University Ave. The Anchorage meeting will be Jan. 16 at the BLM Anchorage Field Office, 6881 Abbott Loop Rd. continued from page 7 SATELLITE (Fiord) pad is approximately five miles north of the Alpine processing facility. Phillips application is to place 639,000 cubic yards of gravel fill on 71.4 acres. The access road from the CD South satellite to the Alpine processing facility requires the most gravel, 254,000 cubic yards for 30.9 acres. The airstrip at the CD North satellite facility requires 120,000 cubic yards for 14.3 acres. The CD South satellite pad will require 122,000 cubic yards for 9.3 acres and the CD North pad will require 110,000 cubic yards for 12.6 acres. Gravel will also be used to modify the access road to the second drill site at Alpine as part of the CD South satellite work. The CD North satellite work also includes gravel for an access road from the pad to the airstrip and a taxiway and apron at the airstrip. The corps said the primary gravel source will be the Arctic Slope Regional Corp. s Kuukpik gravel mine, some six miles southeast of CD South and 13 miles southeast of CD North. Phillips is also proposing to reclaim 16,400 cubic yards of gravel from the Itkilik airstrip some 11 miles south of Nuiqsut. New road section at Alpine main facility The gravel road from the CD South satellite to the main Alpine pad will follow a naturally occurring ridge spanning approximately 80 percent of the route; the remaining 20 percent will be on discontinuous sections of the ridge. The road will parallel the Alpine runway at the processing facility. The corps said that to avoid existing dual use of the Alpine runway as both an airstrip and a roadway, Phillips has proposed 1,050 feet of new roadway to tie the existing second drill site at Alpine to the proposed CD South access road. The nine-acre drill pad at CD South will be above a 200-year return flood event and will be oriented parallel to prevailing winds to minimize snow accumulation on the pad. The pad site is approximately 130 feet from the nearest water body and more than 1,000 feet from subsistence fish camps on the Nigliq Channel. Access to the CD North satellite will be by 3,670-foot gravel airstrip and a 0.4 mile access road between the airstrip and the drill pad. The corps said the airstrip will accommodate fixed-wing aircraft or helicopters. Both the airstrip and drill pad will be above a 200-year return flood event. This drill pad will also be built be parallel to prevail winds to minimize snow accumulation. SUBHEAD: Drilling plans vary for the pads The planned drilling program includes 32 wells at each pad. The CD South wells would be drilled on a year-round basis depending on rig availability. The CD North wells will be drilled in the winter to avoid impacts to wildlife and subsistence activities during summer months. A minimum of 100 days per season will be required at CD North, and three to five winter drilling seasons will be required to complete the drilling program. The rig would be transported to other sites after each winter drilling season. New vertical support members will be required for pipelines from the satellite fields. The three-phase (oil, water and gas) pipeline will be 20 inches in diameter; there will also be an eight-inch diameter miscible gas injection line and a 10- inch diameter water line. The CD North pipeline will also have a two-inch diameter diesel line. The corps said that all pipelines would be constructed with pipe and vibration dampeners a minimum of seven feet above the tundra. The CD South pipelines will run east from the drilling pad for approximately 0.4 mile and then north parallel to and 10 feet west of the existing sales oil pipeline to the Alpine central facilities. The CD North pipeline corridor is approximately 5.8 miles. It follows naturally occurring higher ground and avoids some of the larger channels of the Colville River. Utilities, camps Electricity will be provided to both satellites from Alpine. All utility lines to CD South will be buried in the road. The electrical lines to CD North will be suspended on the proposed VSMs. The corps said there was no decision yet on how communications would be provided for the satellites. There will be no permanent camp facilities because processing will be at the Alpine main facility. Construction crews will be housed at Alpine, Kuparuk or at a temporary camp at CD North. The corps said a small temporary camp will probably be used during drilling to support 24- hour operations. The communications module will be designed to accommodate operators stranded at CD North by bad weather when the pad is operational. The corps said Phillips has conducted three years of environmental and technical studies in the satellite project areas and has provided a draft environmental evaluation document for the project.

9 Week of January 13, 2002 EXPLORATION & PRODUCTION Petroleum News Alaska 9 continued from page 7 MAINTENANCE Surface safety valves on the wellheads were another concern. Gray said some pads had more than a 10 percent failure rate in valve tests over the past year and a half, but he said the failure rate has dropped recently. One of the problems causing test failures at wellheads in the western operating area the side of the field historically operated by BP had to do with ice plugs in pressure sensors connected to flow lines. From experience in the western operating area, Gray said, that insulating the valves helps to keep them operating. All of the producing wells in the western operating area now have insulation boxes, a job that was completed at the end of November, he said. Fire and gas system, shutdown valves concerns There are also extra staff working on the fire and gas system maintenance backlog and the backlog in those items should be done by the end of the first quarter, Gray said. This system detects fire and temperature and gas, Gray said. In addition to maintenance, there is also an issue with the system itself: It was state of the art in the 1970s. So it s more difficult to get parts, he said. BP has a project under way to upgrade or replace the fire and gas system. But that s a huge project. We ve got some pilots going on some new equipment to find out what we want to use, Gray said. The system has thousands of components: In every single module we have dozens of fire alarms gas alarms and smoke detectors. Upgrading the system will stretch over years, Gray said. The key there is that you ve got to keep the existing system running, knowing that yes, in the meantime I m planning a new system. Gray said another challenge is emergency shutdown valves in the facilities. Checks have been done for a number of years on the emergency shutdown systems, verifying that the valves physically close. The question that is being addressed now, he said, is if a valve closed, is it sealing to the level we need it to seal? The where next is about making sure that we get management systems in place that ensure we don t get in this place again. Tom Gray, BP Exploration (Alaska) Inc. Some preliminary testing is being done, he said, along with planning for field-wide testing of critical shutdown valves. One of the concerns raised by staff, he said, is that these values really haven t been tested rigorously and it s time to go out and do that to make sure that the facilities are maintained in a safe condition. External corrosion requires checking 1,500 miles of lines Checking external corrosion on flow lines, another concern, is a matter of pace, he said. There are some 1,500 miles of flow lines at Prudhoe Bay and about 300,000 well connections on the external joints that have been particularly identified as an area for potential corrosion, Gray said. Only a small portion of those are inspected every year. That inspection effort will be tripled, he said, from about a $2 million program to about a $6 million program. External corrosion inspection will require more staff, Gray said, because it is very labor intensive and there are many miles of pipe, all insulated. Our problem is the corrosion underneath the insulation on the exterior of the steel, he said. A screening survey is done with radiographic equipment that identifies moisture and active corrosion. It doesn t tell you if the corrosion s so significant you need to repair a place, Gray said. That takes going to the site and removing the insulation. Staffing issues The report raised the issue of whether there was adequate staff. We immediately added some staff to take care of the backlog in critical safety devices like fire and gas and pressure safety valves. And those backlogs are being worked off, Gray said. Staff additions include about a dozen company people plus contract fire and gas technicians enough to double BP s capacity to do pressure safety valve certifications. Manning for the long term is being studied as part of a maintenance review that will probably take several months. Gray said BP hopes by mid-2002 to have a better view on exactly what do we need to maintain the facilities for the long term. Another staffing issue was the span of control of the operations team leaders, the first-line supervisors at the facilities. Concern raised in the report is we really stretched these people too thin, Gray said. An immediate fix was to make sure those people are not pulled away from their facility unnecessarily, which happened a lot for studies and reports, he said. And as part of an overall study of Prudhoe Bay staffing needs, we are going to look at those job descriptions to make sure that they do have time to focus on both communication and interaction with staff and addressing maintenance integrity. Closing the loop Communication issues are also being addressed, Gray said. People said they felt comfortable raising concerns, but they didn t feel like concerns were being resolved. So just listening isn t enough, Gray said. To me it s closing the loop, he said. Somebody raises something, make sure it gets documented. When it was raised. Who raised it. And then who s accountable for looking into it and then that we give feedback to that person. It doesn t necessarily mean that we ll do exactly what that person asked. But that person gets an answer on it. And the company can feel confident that we addressed the safety concern. Where next? So BP is working on preventive maintenance the things you can put your hand on and measure, Gray said. The where next is about making sure that we get management systems in place that ensure we don t get in this place again, he said. BP just completed a web-based data tracking system for surface safety valve tracking. Systems will be put in place for other areas of maintenance. The plan is to build a maintenance management system with reporting mechanisms, Gray said, to make sure that we do understand everything that needs to be done, when it needs to be done. And if it s not getting done then that s visible to us as managers. The challenge going forward, Gray said, is to have systems in place so we can in turn monitor the condition of facilities maintenance, understand what resources we need in order to maintain the facility for the long term.

10 10 Petroleum News Alaska Week of January 13, 2002 EXPLORATION & PRODUCTION continued from page 1 GEOLOGISTS foothills came as a surprise to everyone, including the companies that have helped subsidize the last four years of state geological work in the area. Many of the companies hold state and/or Native oil and gas leases in the foothills. Program a collaborative effort Our program in the state Division of Geological & Geophysical Surveys is partly funded by an industry consortium. Our salaries are paid for by the state but most operational funding the money it takes to get out in the field, rent a helicopter, send samples to a lab for analysis comes from industry, LePain said. In 2001, program support came from Anadarko Petroleum Corp., AEC Oil & Gas (USA) Inc. (a subsidiary of Alberta Energy Company Ltd.), Chevron U.S.A. Inc., BP Exploration (Alaska) Inc., Phillips Alaska Inc., ExxonMobil and Fred James (independent Kansas geologist, see related story on page 1). The industry consortium dates back to 1993, Mull said, when geologic fieldwork was being done in western NPR-A and then shifted back to the Haul Road area. This year AEC and Exxon were new. TotalFinaElf and Shell also expressed interest but didn t make a commitment, LePain said. Following the three to six week field season, the agencies lead a two-day field seminar open to the public that features the results of the field work and lab tests. LePain said news of possible oil source rocks and reservoirs in the foothills has peaked a lot of interest in several oil and gas companies. On-going programs dovetail The USGS and DGGS have several ongoing programs on Alaska s North Slope. LePain said the programs all dovetail and feed into each other. Mull is involved in all of the projects. We in DGGS have the NPR-A foothills program in which the long range plan is to map the bedrock geology in the NPR-A foothills and adjacent areas at an inch-tothe-mile scale. It s a larger scale, more detailed mapping than what Gil (Mull) is involved in with the USGS (see article in the Oct. 28 edition of Petroleum News Alaska). In addition to the mapping we carry out topical stratigraphic studies of commercially significant formations in an effort to understand depositional environments and source rock and reservoir potential, he said. The topical studies are carried out in collaboration with some of the students and faculty members from the University of Alaska Fairbanks. One of the more important ones that may have commercial significance is a study of the Triassic Otuk and Shublik formations, which are one of the sources of Prudhoe Bay oil. Basically, we focus on units that have resource significance either as a hydrocarbon source rock or as a reservoir rock (one that stores hydrocarbons). We focus in on those types of units that we think might have ecomonic significance, Mull said. Our goal is to do regional geological mapping and provide baseline data that industry can then utilize as a starting point for their more detailed seismic and other geophysical studies to identify specific drilling objectives, Mull said. We look at surface rock geology, at outcrops (part of a formation exposed at the surface), and determine how it might project to the subsurface. Sometimes we re proven right. Sometimes it s geo-fantasy. Definitions of Geological Terms Depositional environment: the set of physical, chemical and geological conditions (such as climate, stream flow and sediment source) under which a rock layer was laid down. Outcrop: part of a formation exposed at the earth s surface; to appear on the earth s surface (as a rock). Porosity: the condition of being porous (such as a rock formation); the ratio of the volume of empty space to the volume of solid rock in a formation, indicating how much fluid a rock can hold. Reservoir: a subsurface, porous, permeable rock body in which oil and/or gas or condensate has accumulated. Most reservoir rocks are sandstones, limestones or dolomites, or a combination. Reservoir rock: a porous and permeable rock that may contain oil or gas in appreciable quantity and into which petroleum may migrate. Sedimentary rock: rock composed of materials that were transported to their present position usually by water. Sandstone, shale and limestone are sedimentary rocks. Source rock: rock that contains organic material from which oil or gas may be generated. Turbidite: a characteristic sedimentary deposit formed by a turbulent underwater flow that may include gravel, sand, silt, and clay, with clay at the top. More oil poitential We still look at the foothills as mostly a gas province, but we believe there s more of an oil component to it than was originally thought, Mull said. LePain and Mull said the entire foothills belt appears to contain thin intervals with rich source rock. Mull said he is concentrating his efforts on collecting samples for organic geochemistry looking for rocks that will generate oil or gas. We ve discovered some thin, 30-foot intervals within a formation called the Otuk that contain up to percent total organic carbon. That s really rich and it s oil-prone carbon. see GEOLOGISTS page 11

11 Week of January 13, 2002 EXPLORATION & PRODUCTION Petroleum News Alaska 11 continued from page 10 GEOLOGISTS You don t necessarily have to have a huge volume of rock if you have extremely rich source rock per unit volume that extends over a wide area. You can generate a lot of oil from a thin formation, Mull said. One of the most interesting units we re dealing with is the Lower Jurassic part of the Otuk formation, he said. These are extremely rich source rocks; they're about 185 to 200 million years old and are about the same age as the source of the oil in the Alpine oil field Alpine was probably generated in rocks of early Jurassic age. It may have been generated from the rocks we re looking at in outcrop closer to the mountain front. Or rocks of the same age. One of the reasons the Foothills Belt has generally been considered gas prone is that most of the oil bearing rocks were thought to contain mostly gassy type organic material in addition to being overly mature having been heated up to the point where most of the oil has been driven off so that what s remaining is mainly gas. But we re finding some areas in which the depth of burial and level of thermal maturity is not as high as we thought it would be. The deeper rocks are buried, the greater the thermal heating that the rocks are subjected to," Mull said field work spurred oil interest The interest in the oil potential of the central Brooks Range foothills was spurred by field work done in 1998 by Dave Houseknecht of the USGS. Houseknecht, who is based in Reston, Va., led a geological team that included LePain to the Chandler River area miles west of the pipeline corridor. We found both a solid hydrocarbon dike and oil stained sandstones in the Torok Formation, stratigraphically beneath the Nanushuk Formation, LePain said. This indicated a petroleum-generating system in the Foothills Belt. Almost simultaneously, Mull's field work in the western Brooks Range foothills recognized the oil prone Triassic source rocks in the De Long Mountains foothills and western NPR-A." The USGS was able to extract oil out of the sands and do some isotope geochemical work that showed the oil was similar to the type of oil that would be derived from the Triassic source rocks, and it was similar to Prudhoe Bay oils. The oil that had migrated into these rocks was most likely coming from the foothills, LePain said work closer to mountains In 1999, the geologists started looking at source rock potential farther east, closer to the Dalton Highway. Mull, as an outgrowth of his earlier work in the western Brooks Range foothills, started looking at exposures in Triassic and Jurassic rocks in the central Brooks Range part of the Foothills Belt. Gil Mull started cracking rocks open and collecting samples. Again, laboratory analyses indicated there was a significant amount of oil-prone material in those rocks some right smack in the oil window as far as oil maturity is concerned and some contained the kind of organic material that would source oil, LePain said. Oil stained Upper Cretaceuous sandstone in the Colville Basin fold belt, northern Brooks Range foothills. Some sandstones reek of petroleum In 1998, 1999, 2000 and 2001 the field crews found oil stained sands west of the Dalton Highway in the Fortress Mountain, Torok, and Nanushuk formations. This past summer we found oil stained sands 10 miles east of the Dalton Highway in Upper Cretaceous sands. We re finding oil stained or smelly sands throughout the area at multiple stratigraphic levels, he said. DGGS is currently conducting stratigraphic studies of several formations with oil-stained sandstone. The goal, LePain said, is to understand the reservoir potential of these sands, which requires knowledge of their depositional environment and mineral composition. We re currently studying the Nanushuk and Tuluvak formations, which include shallow-marine shales and sandstones, and non-marine shales, sandstones, and conglomerates deposits in river channels and floodplains, LePain said. These are lithologically diverse formations that were deposited in a wide range of depositional environments. My work on the Nanushuk is focusing on trying to understand the reservoir potential of sands by conducting detailed investigations of the stratigraphy and depositional setting of the formation. In addition, samples of the sandstones are collected for petrographic analysis using a microscope and for measurement of porosity and permeability their ability to store hydrocarbons, he said. There are some pretty attractive looking sands in the Nanushuk from a reservoir point of view. Some have visible porosity in outcrop; and some of these same sands are oil stained as well. Actually, to call them 'oil stained' is a misnomer. What they are is a slightly different color than nearby nonstained sands a light gray. When you rub them, the sand grains tend to fall off and a distinct hydrocarbon odor comes up. They reek of petroleum, LePain said. Looking for more Tarn-type reservoirs The Nanushuk formation is roughly 92 to 105 million years old, is 4,000-8,000 feet thick in the subsurface, and is widespread in the Foothills Belt, he said. It s exposed in outcrop in the Brooks Range foothills from the pipeline corridor to the Chukchi Sea. Some of the cleanest Nanushuk sands we ve seen thus far are between May Creek and Ninuluk Bluff, south and west, respectively, of Umiat. Throughout the Nanushuk s outcrop extent it consists of shallow-marine and non-marine rocks, including abundant conglomerate and sandstone some with reservoir potential. The Tarn accumulation is basically in Upper Cretaceous sands overlying Nanushuk equivalent strata, just east of the Colville Delta area. Reservoir sands in Tarn field are deep-water turbidites and associated deposits. And what is really interesting is that the Nanushuk Formation in outcrop to the south, near its top, which is slightly older and a short distance stratigraphically below the Tarn reservoir, consists of sands deposited in shore zone and shallow-water settings that look pretty clean, include visible porosity, and appear to be associated with unconformities. Unconformities are Gil Mull surfaces of erosion immediately below which sediment has been eroded away and transported seaward to be deposited in deeper water settings in this case to the north and northeast, LePain said. This is significant, he said, because it suggests that relatively clean sand may have been transported basinward during Nanushuk time and deposited in deep-water settings as turbidite and associated sand accumulations accumulations that could contain economically recoverable hydrocarbons. East of the Haul Road Nanushuk equivalent strata include sandstone bodies up to 50 feet thick that are separated by shales of comparable thickness. These rocks are interpreted as turbidites and associated deep-water deposits. I am still trying to sort out depositional environments, but..these exposures may represent outcrop analogs for Nanushuk-equivalent deep-water Tarn-type reservoirs in the subsurface to the north and northwest, LePain said. Editor s note: A similar study to LePain s Nanushuk project, led by DGGS geologist Rocky Reifenstuhl, is addressing the reservoir potential of the Upper Cretaceous Tuluvak formation. The Tuluvak outcrops west of the Haul Road and includes some spectacular sandstones with Darcy-range permeability. Kay Cashman Who deserves quality phone service?... Everyone! With the acquisition of Barrow, Alaska, ASTAC is now in the position to effect the quality of communications across the North Slope of Alaska. So, as we adjust to our new role, we are also setting the lofty goal of connecting 100% of our customer base. We are encouraging every resident, and every business to get connected with local and/or long distance telephone service from ASTAC. For those who cannot afford the connection, we are aggressively promoting our Lifeline and Link Up Assistance programs to bring phone service to our low income membership. We want everyone to participate in modern telecommunications as a means to strengthen our communities, support those in need, and to support the widespread sharing of information. That s the power of membership. That s ASTAC. The North Slope- 100% connected, that s our goal! Arctic Slope Telephone Association Cooperative

12 12 Petroleum News Alaska Week of January 13, 2002 WORLD OIL/SERVICE & SUPPLY GULF OF MEXICO MMS approves use of ship-shaped floating production and storage Companies pumping oil from beneath the Gulf of Mexico may apply to use floating vessels to draw the oil from wells, store it and later unload it onto tankers, the Department of the Interior announced. Use of such ship-like floating production storage and offloading systems is touted by the industry and shipbuilders as a cheaper alternative to building permanent platforms, allowing production on what would otherwise be marginal sites. The Jan. 2 announcement was made in a news release by the Minerals Management Service of the Interior Department. The review found environmental risks posed by the floating production storage and offloading systems to be comparable to other offshore production systems now allowed in the Gulf. Companies wanting to use the system will have to apply with Minerals Management Service. Use of such ship-like floating production storage and offloading systems is touted by the industry and shipbuilders as a cheaper alternative to building permanent platforms, allowing production on what would otherwise be marginal sites. The system is already in use in other parts of the world and would be beneficial in some areas of the Gulf where oil and gas have been found, said Associate Director of Offshore Minerals Management Carolita Kallaur. Sometimes these discoveries are small and sometimes they are distant from existing infrastructure, she said. The new policy excludes a 471-block area just off the continental Shelf from Galveston to New Orleans where the Coast Guard now prohibits unloading of oil. That prohibition will continue for at least two more years while the Minerals Management Service and the Coast Guard study the issue. The system won t be appearing in the Gulf immediately. Caryl Fagot, an MMS spokeswoman said reviews of applications for use of system could take months. A floating production storage and offloading system draws in oil from undersea oil wells through pipes. The oil is stored in the hull of the vessel until it is loaded onto tankers that shuttle it to shore. The vessel s single-point mooring system enables it to turn with the wind, like a weathervane, so that it always faces prevailing winds, thus cutting down on motion. The Associated Press C A N A D A British Columbia s Ladyfern attracts U.S.-based small cap By Gary Park PNA Canadian Correspondent Abraxas Petroleum Corp. has surfaced as the latest U.S. player in British Columbia and Alberta after completing a C$150 million financing arrangement to support its development and acquisition activities in Canada. A wholly owned subsidiary of Grey Wolf Exploration Inc. of San Antonio, Texas, Abraxas said Jan. 3 that it plans to drill up to 40 wells in the natural gas-rich Caroline area of central Alberta and the Pace River Arch of northwestern Alberta. As well, it has scheduled six wells in northeastern British Columbia s Ladyfern area, which has contributed 50 percent of Canada s increased gas production in the past two years. One of the few small cap companies with a direct interest in Ladyfern, Abraxas owns between 33 percent and 100 percent working interest in 24,000 acres in partnership with Northstar Energy Corp, the Canadian affiliate of Devon Energy Corp., and Canadian Natural Resources Ltd. In participated in a 53-square-mile three-dimensional seismic program last winter and found a number of locations that were similar to those where major discoveries have already been made. The company said that each successful well could add significantly to its production, based on reserves of 30 billion cubic feet per well and 30 million cubic feet per day of production, assuming a 33 percent working interest. Abraxas chief executive officer Bob Watson said the financing deal with Mirant Canada Energy Capital Ltd. will permit us to greatly accelerate our development operations in Canada, which will allow us to grow production and reserves at a much greater rate than would otherwise be possible in the current environment. He said drilling in the Ladyfern area will progress rapidly, with a three-rig program set to drill six wells in the next few months. Abraxas has also contracted for firm capacity on a planned pipeline expansion that it hopes will allow a production startup before the spring thaw. SEATTLE Crowley names team for Ship Assist and Escort Services Group Crowley Maritime Corp. has named Rob Grune vice president and general manager of the company's newly formed Ship Assist and Escort Services Group based in Seattle. He reports to Tom Crowley Jr., president and CEO of Crowley Maritime. Reporting to Grune are Ed McCain, director of marine operations; Alex Sweeny, vice president and general manager of Valdez Services; Todd Busch, newly promoted director of sales in the Seattle office; Jerry Gasparo, manager of tug dispatch in San Pedro; Scott Hoggarth, Puget Sound manager of tug dispatch; and Jeff Andreini, recently promoted director of finance, also based in Seattle. Grune began his career with Texaco Inc. as an officer on its U.S. flag tanker fleet and has been with Crowley in various management positions since He is a graduate of the U.S. Merchant Marine Academy and has a master's in business administration from Wake Forest University in Winston Salem, N.C. Ship Assist and Escort Services has advanced tugs capable of assisting the largest ships in the world with operations in San Diego, Los Angeles-Long Beach, Puget Sound and Valdez, where Crowley is the sole marine contractor for Alyeska Pipeline Service Co. The Ship Assist and Escort Services Group has also responsibility for Crowley's role with Marine Response Alliance, of which Crowley is a founding member. The alliance is a joint venture with Marine Pollution Control and provides OPA 90 coverage for rescue towing, lightering, salvage and firefighting in every U.S. Captain of the Port Zone.

13 Week of January 13, 2002 GOVERNMENT Petroleum News Alaska 13 S T A T E W I D E Legislators pre-file oil and gas bills for 2002 session Rep. Whitaker proposes Alaska Gas Corp. and requirement to sell gas; Rep. Fate proposes changes to exploration credits, royalty reductions By Kristen Nelson PNA Editor-in-Chief Four oil and gas bills were pre-filed Jan. 4 for the 2002 session of the Alaska Legislature, which begins Jan. 14, two by Rep. Jim Whitaker, R-Fairbanks, and two by Rep. Hugh Fate, R-Fairbanks. Fate s bills extend existing legislation chronologically or geographically. Whitaker s bills propose major changes, one establishing a public corporation to build a gas pipeline and the other authorizing the Department of Natural Resources to require natural gas development from state oil and gas leases. The project to be evaluated includes the gas transmission pipeline from Prudhoe Bay to the Interior and from there either along the Alaska Highway through Canada or to tidewater on Prince William Sound or both. Alaska Gas Corp. Whitaker s House Bill 302 would establish a public corporation, the Alaska Gas Corp., within the Department of Revenue to develop a project plan to evaluate whether construction and operation of a natural gas transmission pipeline project by the corporation is feasible. Maximum benefit to the people of the state from the sale of Alaska North Slope natural gas, the intent language of the bill says, may be realized only through public ownership of a corporate entity that performs the essential government function of providing transportation infrastructure that otherwise may not be provided The bill provides that the Joint Committee on Natural Gas Pipelines of the 22nd Legislature will report to the governor, speaker of the house and president of the senate no later than the first day of the 23rd Alaska Legislature based on conclusions drawn by qualified engineering, consulting and other entities considered appropriate as to whether the construction and operation of a natural gas transmission pipeline (as defined in this bill) by a public corporation is feasible. The project to be evaluated includes the gas transmission pipeline and related property and facilities from Prudhoe Bay to the Interior and from there either along the Alaska Highway through Canada or to tidewater on Prince William Sound or both. Gas sales required The other bill pre-filed by Rep. Whitaker, HB 311, would limit the ability of the Department of Natural Resources to issue or extend oil and gas leases containing natural gas capable of being produced in paying quantities unless the lessee contracts to sell gas from the lease. The bill would change the statute so that oil and gas leases would only be automatically extended while both oil and gas are being produced from the leases. Current law provides leases shall be automatically extended if and for so long thereafter as oil or gas is produced in paying quantities North Slope leases, for example, produce only oil. Under the proposed legislation, leases would only be renewed if the lessee agrees to an amendment requiring it to contract to sell the gas that is produced from the lease The bill also provides that if there is more than one qualified bona fide purchaser the commissioner shall issue or extend the lease only if the lessee enters into an agreement with the qualified bona fide purchaser that, in the judgment of the commissioner, provides the greatest longterm return to the state. Small oil producers would be exempt from the requirement to also sell gas. HB 307 would delay to June 30, 2007, the last date for hydrocarbon exploration geophysical work or drilling of a stratigraphic test well or exploratory well to qualify for an exploration incentive credit. June 30, 2004, is the current expiration date. Credits extended The bills pre-filed by Rep. Fate extend existing exploration and royalty credits. HB 307 would delay to June 30, 2007, the last date for hydrocarbon exploration geophysical work or drilling of a stratigraphic test well or exploratory well to qualify for an exploration incentive credit. June 30, 2004, is the current expiration date. HB 308 extends discovery royalty credits established for Cook Inlet to oil or gas discoveries in the Tanana River drainage basin. The law now provides for discovery royalty credits in the Cook Inlet sedimentary basin on leases entered into before March 3, The bill would not affect Cook Inlet leases. Tanana River drainage leases would be eligible for the royalty credit for leases in existence before HB 308 becomes law. JUNEAU State agencies weigh in on proposed coastal management program regs Three state agencies filed comments with the state Division of Governmental Coordination on the second draft of DGC s proposed Alaska Coastal Management Program regulations. In some cases agency comments mirrored concerns of the Alaska Oil and Gas Association and other stakeholders (see story in the Jan. 6 issue of Petroleum News Alaska). In other cases the comments of the Department of Environmental Conservation, Department of Natural Resources and Department of Fish and Game support proposed regulations to which stakeholders strongly object. In a Dec. 13 letter, AOGA told DGC that the second draft of the ACMP regulations was unclear, undisciplined, unfair and illegal. Other stakeholders from the regulated community such as Chugach Alaska Corp. and Sealaska Corp. echoed similar concerns. Although changes to the proposed ACMP regulations were recommended, state agency comments were more supportive of the draft regs. The Division of Governmental Coordination is commended for its effort to work with resource agencies throughout the revision, DEC said in its cover letter. AOGA identified four questions it said the proposed regulations should, but do not, address for every project applicant: 1. Does the ACMP apply to my project? 2. What information must I submit for my application to be complete? 3. What standards will be applied to the consistency review of my project? 4. How long will it take to obtain a consistency determination? Does ACMP apply to my project? AOGA said the Legislature intended ACMP only to address projects with direct and significant impacts on coastal resources, and said DGC s proposed regulations expand the reach of ACMP to lands beyond that intent. Language in the proposed regulations expands the program to include activity that may affect any coastal use or resource or activity that may have a reasonably foreseeable direct or indirect affect on any coastal uses or resources. DEC supports the latter phrase, may have reasonably foreseeable direct or indirect effect on any coastal uses or resources, because it says the term reasonably foreseeable direct or indirect effect is more specific than the statement may affect. DNR proposed a number of changes it said would more clearly define the bounds of ACMP, and said regulations should define, list or provide examples that clarify environmentally sensitive areas, such as legislatively designated areas, critical habi- see AGENCIES page 15

14 14 Petroleum News Alaska Week of January 13, 2002 ADVERTISER INDEX

15 Week of January 13, 2002 THE REST OF THE STORY Petroleum News Alaska 15 continued from page 13 AGENCIES tat areas, wildlife refuges, or eelgrass beds. DNR supported the section that defines the scope of projects subject to consistency review saying current regulations are vague: The lack of clear definition leads to subjective interpretation and decisions. What information? Agencies generally agreed that applicants need more guidance on what information is required to complete an ACMP application. DNR asked DGC to identify, list or provide examples of what is meant by comprehensive data for applicants. The agency said DGC must clarify the level of data needed, otherwise an applicant does not know what they need to provide. DNR also called for clarification of what is necessary for a consistency review packet, the packet an applicant must turn in to DGC and the consulting agencies in order to get the ball rolling on ACMP review. DEC suggested that the packet need not be entirely complete before a review is started. DEC said the packet need only be sufficient to begin a review, rather than complete and asked that the word sufficient replace the word complete in this section, to accurately identify the level of information the state requires for review start up and notice. DEC also said it is impossible for an applicant to know that their project complies with and will be conducted in a manner consistent with the ACMP prior to review, yet the proposed regulations direct applicants to sign a certification that the project is consistent. DEC asked instead for language saying the applicant will comply with policies of ACMP. What standards? AOGA said the draft regulations would institutionalize illegal requirements known as homeless stipulations on permits for oil and gas projects. AOGA said homeless stipulations impose new obligations on oil and gas projects, yet have no basis in statute or regulation. The proposed regulations continue to allow state resource agencies to attach stipulations from the ACMP consistency determination as a requirement of permit approval, AOGA said. None of the responding agencies opposed continuing the practice of adding stipulations to permits by the alternative measures route. But for a variety of reasons the agencies took care to differentiate permit conditions from homeless stipulations. DNR said it is concerned that its ability to impose or modify permit conditions authorized by statute or regulation would be jeopardized if resource agencies were required to provide conditions during the consistency review comment period. If that proposed regulation was enacted, DNR said it fears the conditions provided during the process would be cast in stone if listed on the final consistency determination. It said the provision in the draft regulations that allows a resource agency to modify conditions after the final consistency is untested. It is unclear whether or not an agency may incur legal exposure by changing a condition after it appears on a final consistency determination, DNR said, asking that it instead be optional for agencies to provide such conditions. How long? AOGA said it is impossible to predict how long the ACMP review will take, that there are no clear timeframes for completion of many of the steps, and that too many extensions and other avenues exist to fudge the timeframe of the review. Commenting agencies said their workloads might hamper attempts to shorten the process. In the parts of the plan with clear timeframes and where DCG tried to trim time limits, workload issues factored into agency protests. In several instances where the proposed regulations shortened timeframes for agency review, public review, comments, or deadlines for agencies to request additional information from the applicant, DF&G and DEC objected. DF&G said shortened review times might result in less thorough, less complete reviews. The agency said the number of projects it can review could be reduced as a result of the shorter review period. Steve Sutherlin continued from page 1 LAYOFFS options for development of the Liberty accumulation, but hasn t yet identified a competitive option. The company s focus will be in and around existing fields, he said. Reserves at Prudhoe Bay, Kuparuk and Milne Point are 7 billion barrels, about one-third currently competitive. BP would like to increase that 30 percent to 40 or 50 percent. Last year BP brought a substantial number of people to Alaska to participate in the $100 million project to access natural gas. That project is largely completed and the size of that organization is being reduced to match the work plan for the coming year. Chappell said it will take new technology which will lower development costs to increase the amount of those reserves that are economic to produce. If we can lower drilling costs we can do more in-fill drilling, expand enhanced oil recovery and move forward with viscous oil development, he said. BP plans to spend about $700 million in Alaska this year, on a par with last year in existing fields. Cuts will be in Anchorage Chappell said BP has about 1,500 employees in Alaska, about 600 based in Anchorage. The Anchorage staff will be reduced by 20 percent, he said, with 120 employee and 75 contract positions to be cut. We will not be reducing the number of operations and maintenance personnel on the North Slope, he said. In fact, we expect to see that number increase. The contract staff reductions are not in companies which provide managed services in Anchorage, he said, but are BP contract staff, people who are brought into the organization to respond to an increase in activity and whose positions go away when the activity goes away. Managed services are outside the scope of this restructuring, Chappell said, although we expect they would also be making changes in response to changes in activity level. Some jobs were temporary Completion of projects is driving some staff reduction. Northstar is pretty much completed and is moving from construction into operation and maintenance, Chappell said: So the construction organization for Northstar is going away; those positions being eliminated. Last year BP brought a substantial number of people to Alaska to participate in the $100 million project to access natural gas. That project is largely completed and the size of that organization is being reduced to match the work plan for the coming year, which will be focused on working with state, federal, Canadian central and provincial governments to develop a fiscal and regulatory regime in which that project can move forward, he said. The exploration jobs lost when responsibility for frontier exploration shifted to Houston are also part of the 120 employee layoffs. Chappell said the company is not providing a specific breakdown of where the jobs are, but he said there will be reductions in every organization in the company. Involuntary downsizing Chappell said BP made the staff reduction announcement to employees Jan. 7. He said the company s plan is for all town-based BP staff to know their status by mid-february, although some may be asked to work past that date. BP will try to mitigate changes on employees by offering what we believe are generous severance packages and we will consider the wishes of employees in making staffing decisions; but this will be an involuntary program, Chappell said. Staff reduction decisions will be made on a business basis, but people can indicate if they are interested in leaving the company and receiving the severance package, he said, and where possible we will consider those requests. But it is an The exploration jobs lost when responsibility for frontier exploration shifted to Houston are also part of the 120 employee layoffs. involuntary program. State will push BP exploration Alaska Gov. Tony Knowles said BP s staff reduction announcement and a retreat from the development of frontier fields is disappointing for Alaska and disheartening for those employees and contractors directly affected. The governor said he has offered the assistance of the Department of Labor s jobs division to assist displaced workers. He said that while he concurs with BP s confidence in existing fields, I disagree with their approach on frontier development. The governor said he remains bullish about the potential for more oil and gas discoveries in Alaska. He also indicated he is unwilling to have BP sit on unexplored acreage: BP remains a significant holder of exploration leases and the state will work with the company to fulfill its commitments that these areas are aggressively explored. ENGINEERING EXCELLENCE Complete Multi-Discipline Engineering Services & Project Management Concept and Feasibility Studies Project Scope and Development Cost Estimating and Scheduling Engineering and Detailed Design Procurement Services Field Engineering Inspection and Quality Control Environmental Engineering Serving Alaska Industry Since 1974 ALASKA ANVIL INCORPORATED 509 W. 3rd Ave. Anchorage, AK (907) FAX: (907) Kenai Spur Hwy. Kenai, AK (907) FAX: (907)

16 16 Petroleum News Alaska Week of January 13, 2002 THE REST OF THE STORY continued from page 1 JAMES pation of profit. That expectation leads us to drill in your state, or someplace else. James, who is based in Kansas, said he understands Alaskans don t want to be told how to run their state by outsiders. He feels the same way about his state. But given a single industry supports state government and the lion s share of economic activity in the state, Alaska must consider the long-term health of that industry if it wishes to continue to rely on the benefits, he said. We geologists can look for oil anyplace. Where we look is where the economics are best, he said. The future for smaller companies operating in Alaska is bright, given the right investment climate. In states like Kansas, smaller companies have picked over most of the prospects, and the ones that are left are marginal, even for tiny companies. Small fields that look good to the Phillipssized companies look marvelous to us, James said. Big oil companies are looking where very big finds are possible, he said, in places like offshore Africa, Angola and the Caspian Sea. They are looking for billions of barrels, not millions. There are probably a whole lot of Alpines, Fiords and Tarns; together they may hold more oil than Prudhoe. Fred James Welcome competition James said that he attends industry functions around the country, and based on comments he hears at those meetings, interest in Alaska has never been higher. In addition to benefiting the state, the entry of varied players into Alaska will benefit other independent oil companies in a variety of ways. Once you get the small companies involved, a lot starts to happen, he said. Every time someone drills a wildcat, I learn something. As small companies reach out, the transportation infrastructure is extended bit by bit, and this in turn allows the next company to reach a bit farther. In most cases the smaller company doesn t have the resources to build long pipelines from scratch, so that makes leases close to existing infrastructure attractive. Small companies have got to have a rapid pay out, James said. In most cases they are spending current income and they can t tie up money waiting for a pipeline. As the transportation system branches out, more branches grow. The acreage grows, sort of like an amoebae, James said. Small companies will have to wait until lines are extended to consider areas such as the eastern North Slope beyond Badami and the National Petroleum Reserve-Alaska, James said. The good news is there is plenty of opportunity on the North Slope, and the varied structures tend to ensure that companies don t trip over each other to bid up the prices of properties. The slope is all oil country, James said. Rare is the hole that s been drilled that doesn t have a showing of oil things are going to happen. The structures that are left now are not so obvious as Prudhoe Bay and Kuparuk. The obvious fields were very obvious, everybody had knowledge of them, James said. Today a great deal of excellent seismic data is available to help geologists spot less obvious deposits. The North Slope shoots like a charm, mother nature provided the ideal setup for seismic, James said, adding that there are few features in the area that cloud seismic results, unlike other regions. However the seismic data is subject to interpretation, therefore companies are less likely to be clamoring for the same leases. No two geologists have the same opinion, he said. James is working with Kansas-based independent Alaska Venture Capital Group LLC, which is primarily focused on the Colville River area south of the Alpine field. AVCG also has a working interest in the Sakonowyak River unit on the North Slope in the vicinity of Gwydyr Bay, with BP Exploration (Alaska) Inc. BP is the operator of the prospect s exploration well. (See story in Oct. 21 issue of PNA.) We re looking for stratigraphic traps they are definable on seismic, but subject to interpretation, he said. It s a riskier play with a smaller payoff. Independents are often dependent on investors to put up money for drilling. Fred James is concerned because investors have been hearing stories about permitting delays in Alaska, and such concerns could affect the flow of money to deals in the state. That is an inevitable pattern for an oil producing area, James said. First the large, obvious plays are exploited, and then there is development of less obvious and more risky prospects. In all, however, James thinks the North Slope has a great deal of promise. There are probably a whole lot of Alpines, Fiords and Tarns; together they may hold more oil than Prudhoe, he said. Investment must be nurtured Independents are often dependent on investors to put up money for drilling. James is concerned because investors have been hearing stories about permitting delays in Alaska, and such concerns could affect the flow of money to deals in the state. But for now, interest is high. The level of interest in Alaska is going up exponentially, James said. The rest of the industry is coming in. But it s a delicate thing, you can kill that goose if people get too greedy.