"FROM THE TRENCHES"

COMMENTARY ON ENERGY AND MINERAL TOPICS
FROM THE PROFESSIONALS WHO ARE WORKING
IN THE INDUSTRY "TRENCHES"

     Ammonite's "From The Trenches" page is designed to provide commentary on current and future natural resource matters, hopefully, before the subject appears in the industry trade journals and financial press. Our professional consultants and industry "friends" are involved in projects around the world. We often know the facts, or at least have heard a rumor, before it becomes "news". We encourage our website visitors to contribute their own reports.

     

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ENERGY AND THE ENVIRONMENT:

Why Do Energy Companies Need to be
Concerned About Climate Change
and What Can They Do About It?

Commentary by Bill McLeod

June 27, 2002

     One of the most daunting environmental issues facing the world today is "Global Climate Change." Is the increase of carbon dioxide and other gases in the atmosphere causing an excessive rise in the collective temperature of the Earth ,and will that create a problem?

     Although there are many voices stating a variety of opinions on the issue, there is no clear unifying force to compel a global action. There is, however, scientific agreement that the average temperature of the Earth has increased about 1oF over the last hundred years and that the concentration of CO2 has increased from 315 ppm in 1958 (when precise monitoring stations were established) to 368 ppm in 1999.

     The issue is a higher priority in some areas of the world than others. In Europe, where there is strong support for the Kyoto Climate Change Treaty, various governments have enacted legislation and/or taxation to reduce greenhouse gas (GHG) emissions. In the U.S., the EPA has just publicly concluded that anthropogenic emissions are influencing the Earth's atmosphere. In other areas, such as the developing world, higher priorities of drought and famine (which some blame on climate change) keep the issue in the background.

     Business, governments, NGOs and academia are spending billions of dollars trying to resolve some of the many questions around this issue. Some companies are building up reserves of GHG reduction credits to offset potential future controls.

     Regardless of whether you believe global warming is occurring, think the problem is exaggerated or are waiting for more conclusive research on the subject, as a prudent business manager, it's crucial to assess and plan to address a number of related issues, including:

     With our unique perspective we can work with you to develop plans and strategies to balance the potential impacts against the related costs of a full range of events from a minimally changed GHG environmental picture to a dramatic mandated reduction.

     Potential actions include:

     The information on Global Climate Change is in a state of constant flux, and the potential exists for it to affect all industries in one way or another. Reasonable strategies based on careful assessments are a necessity for any organization in the energy business.

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UPSTREAM ISSUES:

SOME OBSERVATIONS - MAY 2002

The Exploration Process - Energy Supply - Mexico

Commentary by Skip Hobbs

     Exploration Opportunities Are Different Today. Ammonite is seeing a definite change in the exploration process - both domestically and internationally. Five factors are responsible. First, with industry consolidation and layoffs/early retirement of senior E&P professionals, there are now many small companies with very experienced and talented former "big company" trained explorationists on staff. Secondly, high-tech exploration tools - sophisticated workstations and interpretative software are now affordable for small companies, and are being used by very savvy hands. Third, on-line database services enable small firms to access and incorporate into their prospects huge amounts of data that, heretofore, simply were not available to the small independents. Fourth, companies are using the Internet to market their prospects and producing properties, which makes it very simple to see "what's out there". And finally, the majors and large independents are exiting mature onshore and offshore North American and international plays, thereby opening them to the smaller independent E&P companies. We are seeing much higher quality "science-based" prospects as a result of these factors. Some of the plays we are reviewing are actually quite significant - even for a major.

     The improved ability to seismically image reservoirs and deep structure in geologically complex areas is very exciting. Ammonite has evaluated on behalf of our clients "high-tech" projects ranging from: the deep Temblor play in the San Joaquin Basin of California; a deep basin-centered gas play in the Uinta Basin in Utah with multi-TCF potential; a deep (16,000 foot) Cretaceous turbidite play onshore the Texas Gulf Coast with 500 BCF - 1 TCF potential; deep water Gulf of Mexico plays with huge oil and gas reserve potential; a very large gas play offshore Thailand; and a play onshore Trinidad for which Ammonite managed the acquisition, processing and interpretation of a 170 square kilometer 3D shoot. We have also looked at "tight" shallow gas and coalbed methane plays in the Rockies that are "low tech", but require good science, operations and management to be successful.

     Tony Carvalho, Ammonite's Dallas-based Gulf Coast offshore geologist (formerly with Oryx), and I were recently invited by the frontier exploration team of a large oil company to look at a deep - and I mean deep - offshore play beneath the existing shallow production infrastructure on the Gulf Coast shelf. Proprietary new seismic processing technologies and regional geological studies support the drilling of $30 million dollar wells to giant 500 BCF to multi-TCF reserve potential prospects at depths of 20,000+ feet. Successful wells are expected to flow at rates of 50 - 100 MMcfg/day! We were honored to be the first persons outside the company to see the play. This resulted from my serving on an AAPG committee with the company's Gulf Coast frontier exploration manager. The company is looking for partners to share the high risk and cost of the exploration play, and wanted our advice on approaching non-traditional drilling partners. Historically, the company had always approached the majors and large independents, but now, due to mergers, allocation of a larger part of the budget to international ventures, and the fact that all companies have had to pull in their horns this past year, it is not so easy to find co-venturers.

     Ammonite's Calgary-based geophysicist/geologist, Susan Eaton, in her capacity as both a consulting geophysicist and journalist for several trade and professional society publications, has had the opportunity to review some very substantial Canadian plays. These include the giant Ladyfern Slave Point carbonate gas play in northeastern British Columbia, gas prospects in the McKenzie Delta, and the new plays offshore Eastern Canada.

     The public perception that we have already found most of the hydrocarbons that will be found in North America is simply not true. There are huge new plays onshore and offshore from Mexico to the Arctic, to the Canadian and USA Atlantic margin. New seismic data acquisition and processing technologies, particularly AVO and fluid factor analysis, as well as improved engineering technologies - i.e. drilling and producing hydrocarbons in 5,000+ feet of water, and from over-pressured reservoirs below 15,000 feet, are critical to the plays. However, without solid geological prospecting and conceptual play development, application of these technologies will be for naught.

     A word of caution to financial investors - make sure the management team that submits a proposal to you, or the company whose equity or debt securities you are evaluating, is bringing new ideas and technology to their plays, and have accessed all available data. There are some great opportunities in mature areas - i.e. the Deep Trenton Play in the Appalachians, and deep plays beneath the shallow Gulf of Mexico shelf, and smaller prospects in the North Sea, Southeast Asia, and elsewhere. Tight gas in the Rockies is fine if there is a ready market and the operator applies state-of-the-art frac techniques. We have seen some projects that looked great in the promoter's brochure, but upon closer examination, proved to be based on flawed assumptions, inadequate data, and "old" ideas.

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     Energy Policy and Supply. Since 2000 to the present, in my capacity as president, and now past-president of the American Association of Petroleum Geologists (AAPG) Division of Professional Affairs, I have been very involved with developing and presenting the AAPG's position on national energy policy. I testified before the Senate Committee on Energy and Natural Resources in July 2000, and my energy policy recommendations have been circulated around Energy Secretary Abraham's office (and we made no political contributions!). As a result of this work, I am very concerned about the ability of the nation to meet expected natural gas supply demand of 29 TCF by 2010. Not enough capital is being invested in the petroleum industry. There is a regulatory morass for exploratory drilling as well as regional development plays, such as coalbed methane in the Powder River Basin of Wyoming. Unexplored areas with the most hydrocarbon potential have been placed off-bounds on environmental grounds (i.e. much of the Rockies, the Eastern Gulf of Mexico, the USA Atlantic Margin, and ANWR).

     The National Petroleum Council estimated in its 1999 study that a staggering investment of $1.5 trillion (in 1998 $) will be required through 2015 to meet gas demand. Attracting this capital will not be easy. I find it very curious that this past winter, at a time of economic recession and unusually warm weather, gas prices were, and still are, so robust. Those in the know realize that the convergence of steep decline curves of Gulf Coast gas wells, significantly decreased drilling levels, and ever rising demand, are about to "bite" us again. New drilling in the Gulf of Mexico "Deep Play" is finding more oil than natural gas. In late April, Simmons & Company, who until recently were quite bearish about gas prices, raised their 2002 average gas price forecast from $2.25/mcf to $2.90/mcf. In my opinion, the average gas price may be higher.

     As I travel around the world and see the "masses" adopting a motorized and electrified life style, I am concerned about the long-term ability of the earth and its exploiters to meet the ever-increasing demand for energy fuels and raw materials (in an environmentally responsible manner). In their April 30th Global Oil Market Analysis report, analysts for A.G. Edwards & Co. noted that the worldwide decline rate from existing oilfields is 6.6%. This means that 5.5 MMBO per day has to be added annually just to keep pace - with no increase in demand. Normalized annual increase in worldwide crude oil demand is about 1.5%, or about 1.2 MMBO/day. OPEC appears to be toeing the line on production quotas. Russian exports are the "wild card", but I think their growing economy and increasing European demand will moderate downward pricing pressure from Russian exports. Unstable politics in the Middle East do not engender lower commodity prices. These factors lead me to believe that we can expect firm oil prices in the $22 - $30 per barrel in the near to intermediate term.

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     Mexico. Mexico has tremendous undeveloped and unexplored onshore and offshore Gulf Coast oil and gas potential. PEMEX simply does not have the $100 Billion capital necessary to meet rising Mexican demand for petroleum. Gas demand alone is expected to rise from 4.3 BCF/day in 2001 to about 9.0 BCF/day by 2010. Mexico's proven gas reserves are 30.4 TCF, but gas exploration is still in its infancy compared with the USA side of the Gulf Coast. Oil production is in decline. President Vicente Fox has recommended opening up Mexican E&P to foreign investment; however, this is a very sensitive political issue. Mexico still celebrates the 1937 nationalization of the petroleum industry with a national holiday. As a first step in the process, it appears that Mexico will offer $10 Billion in competitive "Multiple Service Contracts" to foreign operators to provide the financing and development of existing discoveries. Contractors will have no equity interest in the production.

     Last year, Tom O'Connor, Ammonite's Chief International Consultant (Tom was previously Chief Petroleum Engineer of the World Bank), and I formed a strategic alliance with the French geophysical contractor CGG, and Deutsche Bank, to examine Mexican E&P opportunities. CGG has been a contractor to Pemex for 15 years. Over the past three years Deutsche Bank has financed about 75% of the Mexican petroleum field redevelopment and infrastructure projects, including the massive Cantarell nitrogen injection project. We traveled to Mexico City and the Yucatan in August to meet with a significant Mexican service company, and in November I attended a Mexican petroleum exploration conference in Veracruz. Through AAPG meetings in Houston in 2001 and 2002, and the Veracruz meeting, I have become acquainted on a first name basis with Alfredo E. Guzman, Exploration Strategies Coordinator for Pemex.

     Our "sense" of the Mexican services contract plan, as presently structured, is that it will be very difficult for a foreign company to make any meaningful profit. The only reason that would justify participation, is to get one's foot "in the door", and thereby have a better chance of participating in future exploration licensing rounds. One must have a Mexican partner to succeed. There is no assurance, given the politics, that there will be future production sharing or other international-style licensing rounds. Mexico does have huge untapped potential, particularly offshore in the Gulf, and the country cannot afford to go it alone. Mexico is the only country in the world, that I am aware of, that still has a government monopoly on E&P. So stay tuned, the politics will eventually catch up with reality. From the standpoint of future potential, Mexico is very important.

May 22, 2002

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HIGHER GAS PRICES MEAN MORE WORK FOR THE TROOPS

Commentary By

Tom Moore

AAPG Certified Petroleum Geologist

Phillips Petroleum Co., Bartlesville, Oklahoma

     The "troops in the trenches" throughout the petroleum industry are doing their part to increase gas supply. I've not had a weekend in two months and my NORMAL day now is 12 hours, many 18. The guys I am working with in our (Phillips Petroleum) North American Division are running full tilt trying to get in a CBM drilling program before Elk Winter Range Habitat restrictions shut us down come Oct 1. We were two months trying to get rigs. Unfortunately, the first two were such pieces of junk , and had such rankly inexperienced crews, that they were dangerous and excruciatingly slow to the point, that we ran them off as soon as we found a couple of others. Those are not much better.

     Of course there are concerned citizens and some bureaucratic logs being thrown in the road with regards to CBM development in some parts of the Rockies. Because of some marginal operators doing some not-always-right things, they have some legitimate complaints. The BLM is facing an exponential increase in the number of permits. But, "all that water", since it is fresh enough to drink (I have, and it's better than what you get in town in Gillette), really should not be a major problem in the arid West.  I seem to remember the problem with construction of a coal-slurry line to carry coal to the Midwest that was stopped, essentially because there was not enough water to send East. They should not have that problem now.

     I happen to be in town this week because I am running training classes for new-hire geologists recruited last year, and now finally at work. They are being thrown into the fray as quickly as possible. My job is to try to get them ready as quick as I can. At the same time, I hear of Marathon and Unocal considering lay-offs, which I can't fathom when I look at the intensity level here. Everyone is running throttle-open. Now, if there were a few less hurdles, it would all go faster and we'd find more gas.

     I'm afraid, really afraid, that this winter is already a foregone conclusion. And if you go on the odds, we are due for a real winter, for a change. When Grandma freezes to death in Chicago come January, the petroleum industry and the gas distribution companies are going to be painted equally as the bad guys. I have suggested strongly to our PR department here that they start some "positive vibes" campaigning right now.

     OK, enough of an interlude....I gotta get back to work if I want to see my kids before bedtime.

Submitted September 17, 2000

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COALBED METHANE BOOMING IN BLACK WARRIOR BASIN WITHOUT SECTION 29 TAX CREDITS

Report by Read Holland, Ph.D.

Senior Ammonite Consultant

Tuscaloosa, Alabama

     Rumor has it that Phillips Petroleum is buying the assets of the River Gas Company, a major Black Warrior Basin coalbed methane producer, for an substantial undisclosed sum.  The word on the street is that Phillips is buying everything. However, my sources say that the sale might not include a new 400 well area under development north of the Blue Creek Field.

      CBM activity is picking up with higher commodity prices. The economics are just fine without the old Section 29 Tax Credit, due to new drilling and completion procedures, existing infrastructure, and naturally, higher gas prices.  SONAT/El Paso also have a major development project underway adjacent to the Blue Creek Field.

Submitted Sept. 5, 2000

EDITOR'S NOTE:  A press release on September 25th announced that Phillips Petroleum Co. had acquired the River Gas Company for $123 million.  All the assets of River Gas were included in the Sale.

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EASTERN GULF OF MEXICO, OCS SALE 181

(Scheduled for December, 2001)

Report by:

Norman F. Ross,

Ammonite Senior Geophysical Consultant,

Houston, Texas

OCS SALE 181 AREA

     The OCS sale 181 area covers about 1033 offshore blocks in the Eastern Gulf of Mexico, in an area that has had no leasing and vary sparse drilling since late 1988. The area is bounded by the Mississippi Canyon and Atwater on the west, the Comanchean shelf margin to the north in the Destin Dome area, the Florida Escarpment on the east-northeast, and a line connecting the southern boundaries of Lloyd block 485 and Lloyd block 516. Water depths range from 75 feet to over 10,000'.

GEOLOGIC OVERVIEW:

     The east central and eastern Gulf of Mexico area for OCS Sale 181 scheduled for December 2001, is an extension of the salt feature structural styles as seen immediately to the west, where recent discoveries include "Crazy Horse" (1 billion bbls) in Mississippi Canyon (MC) 778, and "Mickey" in MC 211. Other salt related structures and stratigraphic trap discoveries adjacent to sale 181, are primarily in Miocene slope fan deposits, and include Mensa, Columbe and Ram Powell fields.

     In addition to the deepwater clastic play, there is a known carbonate gas play in the area. The carbonate play is a basinal deepwater equivalent of the Cretaceous and Jurassic section penetrated by various prior shelf wells. This section may contain porous clastics (Norphet) sourced from the north-northwest, or skeletal grain sands and oolites shed from the ancestral carbonate shelf to the north and east. The clastic play is Tertiary age, and is underlain by a Mesozoic deepwater carbonate section. Miocene age sediments dominate the Tertiary clastic wedge. The Mesozoic section is composed of a Cretaceous and Upper Jurassic section that thickens in a westerly direction, similar to the Tertiary section. The base of the Upper Jurassic section coincides with the top of the Louann salt.

     Analog fields and discoveries can be projected into the sale 181 blocks from Mississippi Canyon and Viosca Knoll. Fields such as Ram Powell and Petronius can be used as analogs for stratigraphic traps in the sale area. Also discoveries as King, Aconcagua and Columbe, will be structural analogs for prospects in sale 181. All of the referred fields are a few miles from the western edge of sale 181.

TECHNOLOGY

     The 181 Sale area offers companies the unique opportunity to enter the play early with the same advantage as the other deepwater players. Although much of the area exceeds water depths of 5000', facility and drilling costs have decreased and production technology has improved since the last Eastern Gulf of Mexico sale in 1988. In addition, modern 2D and 3D seismic data sets are available to the industry now, thereby, allowing for all the modern seismic technologies to be used to evaluate the blocks prior to the sale. The data are of excellent quality and exhibit good deep penetration and high resolution.

MULTI-STATE INTERESTS

     Alabama and Louisiana are generally in favor of the sale, while Florida is cool to the sale. However, the 181 area is over 100 miles from Florida and should not be an issue. Florida is a large energy consumer, and it is forecasted that their population will double to 8 million by 2010, and triple by 2050. Florida depends heavily on imports to meet its fossil fuel needs. The U.S. DOE indicates that Florida has committed to increase its gas-fired electricity generation, and that 21 new gas-fired units are projected to be built between now and 2004. Sale 181 may contain large gas reserves, which would directly benefit Florida's energy requirements in the near future. Also, the MMS is actively working with industry and federal/state governments to resolve all issues, and is confident that OCS Sale 181 will be held in December 2001.

     This outline is merely a brief technical overview of OCS Sale 18, and is not intended to be a complete review of all issues regarding the sale. The author has personally reviewed and evaluated seismic data covering the 181 Sale area.

Submitted: July 20, 2000

Commentary on the Eastern Gulf OCS Sale 181

From

Tony Carvalho

Ammonite Senior Exploration Consultant

Dallas, Texas

     Norman Ross's write-up (see above) on the Eastern Gulf OCS Sale 181 sale is excellent. When I worked for Oryx, I was involved with the discovery, delineation and production planning for Oryx's Viosca Knoll 826 "Neptune" field, the world's first spar production system, which offsets Ram Powell (Neptune Project description at http://www.offshore-technology.com/projects/neptune/index.html).

     VK826 is a classic salt feature. Ram Powell is an extremely interesting field. It is COMPLETELY stratigraphic in a trapping sense, with questionable source- migration path, et cetera; but it's there. And the amplitudes jump off the section. For many years we (Oryx) always looked at extending these plays to the east, but of course couldn't, because of delay tactics used by the environmental groups and the state of Florida. The fields are obviously there. It should be a VERY big sale. The only problem will be water depth. That is still a consideration, though as Norman points out, so much less so compared to the late 80's. I am not familiar with the carbonate play. I worked the Miocene (Tex W) section. We did contemplate drilling the Austin Chalk equivalent horizontally at VK826, believe it or not, especially since Oryx was pioneering the Austin horizontal play at Pearsall at the same time!

Submitted August 3, 2000

LOWERING THE BARRIERS TO 3D SEISMIC DATA

FOR SMALL COMPANIES AND INDEPENDENTS

by,  

Michael Mackenzie, Ph.D.
Ammonite Senior Geological Associate
New Orleans

     3D seismic data, a strong factor in upgrading development and exploration drilling prospects, has been difficult for smaller players and independent prospect generators to acquire - primarily because of costs which have ranged from $20,000 to $90,000 per square mile.

     View Seis Partners, L.L.C., a company formed by three ex-Amoco geophysicists, has recently initiated a cost effective way to allow small companies/independents to use 3D data. The arrangement has four phases:

1. Client pays an initial fee associated with a View Seis License agreement which provides a 1 year access (renewable at original cost) to the data - to be viewed in View Seis's offices. Viewing rights cost $2,000 per square mile. Minimum commitment per project is 3 squares - maximum is 10 squares.

2. Interpretation of the data under the View Seis license - in their offices. Costs are $30/hour if work is done by client, $100/hour if done by View Seis.

3. Presentation to potential buyers/funders who can see the interpretations in View Seis offices. Also, client may take out one structure map and one seismic section for use in creating interest among potential buyers.

4. Sale of the prospect to buyers. Sale triggers the payment for a Conventional License to the seismic data. The purchase price will vary with the survey, depending on the terrain. It would likely cost about $50,000 per square mile for a South Louisiana data set. If no sale occurs, no payment for a Conventional License is necessary. In addition, an ORRI of about 1/2% of 8/8ths is assigned to View Seis Partners.

     As a bonus, View Seis is in a position to help clients fund their prospects through industry contacts and may exercise a first right to take, on client's terms, up to a 50% WI. The Partners currently have 6,000 square miles available from agreements with certain data owners. Much of this data is in south Louisiana, and some is in areas of Texas, New Mexico and Montana. View Seis will be expanding its database.

    I believe that View Seis's arrangement is an excellent step toward helping small companies and independents upgrade their prospects in a marketplace that insists on seeing 3D confirmation. Perhaps such arrangements will follow from other innovative data brokers.

     For more information, you can accessView Seis Partners, L.L.C. website at:  <www.VSP-LLC.COM>

View Seis partners include: Phil Johnson (New Orleans), tel. 504-558-7797; Frank Limouze (Lafayette, LA), tel. 337-693-4339;  and Bill Marshall (Houston), tel. 832-541-9325

Submitted July 14, 2000

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INTERNATIONAL SCENE

View from the North

Comments on the Canadian Scene

By

R. C. Mummery, P.Geol., Ph.D.

Ammonite Senior Exploration Consultant

Calgary, Alberta

     The past couple of years have seen tremendous changes in the Canadian Oil & Gas E&P industry. Acquisitions and mergers have decimated the ranks of the mid-size producers. This frenzy started when commodity prices were low and debt was high. Bottom-line financials for most companies went from black to red and resulted in depressed share prices for all E&P companies.

     Commodity prices have increased significantly from the very low values realized two years ago. Several pipeline projects are now underway to allow movement of new gas to markets. Surprisingly, the increase in oil and gas prices and new market potential, has not encouraged investors to get on board. Do these investors expect a significant long-term fall in prices? Why so little investment interest, especially when everything seems to point to increasing demand, particularly for natural gas?

     Two factors have adversely affected investment into Canadian E&P. One relates to the instant gratification that dot.com stocks were providing. Investors were able to invest in several issues and know that only one needed to hit the "Big-Time" in order to cover the losses of the others, and still provide a handsome profit. This investor romance with the Internet stocks has cooled off. Investors are looking for value. The second factor has to do with "credibility". The Canadian Oil & Gas Industry has a few "BreX" stories. To compete with the dot.coms, some smaller public companies exaggerated expectations. They could not deliver on their promises, and "burnt their bridge" to the investment community. Many have been unable to raise new capital required to continue their development programs. Many have seen their "liquidation' value fall below their asset value. This has been the main reason for most of the mergers and acquisitions. There have been, and still are, some tremendous bargains. It has been more cost effective to buy reserves through company ownership, compared with asset sales or exploration.

     So what is the future for Canadian E&P? No doubt, there is a tremendous future for oil & gas exploration and development in Canada. The initial focus will be along existing and new pipeline routes. Some of these areas are under-explored. Some areas have multi-zone hydrocarbon potential, which has not been fully exploited. Most of the existing pools have significant upside potential through either in-fill drilling or pool extensions. Northern Canada (mainly in the Yukon) will provide a link between the undeveloped gas fields on the North Slope of Alaska, McKenzie Delta and Beaufort Sea areas. Significant gas reserves have been discovered just north of the BC border in the Liard area. The majority of any pipeline routes from Alaska to Alberta & BC are unexplored.

     What is needed? The Canadian oil & gas industry needs long-term investments. This potential will be fueled by recognition of the opportunity to find significant large new reserves, and assured profits due to increasing commodity price. Investment in the low cost producer will guarantee success. Management changes will be required for other companies to ensure realistic growth targets, and a movement towards the bottom quartile for "Finding & Development" costs. This can work! Careful study of existing companies will lead to finding some "diamonds in the rough".

     Dr. Mummery has worked in the Oil & Gas E&P environment in Calgary as both a geologist and geophysicist for over 27 years. He is the Principal of a consulting company presently engaged by several clients to work on exploration projects in Canada, Alaska and Internationally. In the past Bob has worked on variety of E&P projects in at least 50 different geological basins in over 30 countries. He has served (including co-chairing) on several committees reviewing sector compliance and future directions of the Geological Survey of Canada for the Minister of Natural Resources of Canada.

Submitted August 10, 2000

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Current Significant Changes in Pakistan's Oil and Gas Sector

By

Thomas E. O'Connor

Ammonite Senior International Consultant

Washington, DC

     A recent Governmental Privatization Conference in Pakistan was convened to progress the privatization of all state entities, including those in the oil and gas sector. A series of major policy decisions resulted from this meeting that, if implemented, will be of significant interest to the international oil industry. As is common in the developing world, it is unclear how far down the governmental chain these political decisions have been promulgated to date, or how effective they will become in the future. Nevertheless, the decision-making process and its results, represent a major change, at least on the surface, in Pakistani petroleum policy.

     The progress of this privatization effort has been closely monitored and in part financed by, the World Bank, the Asian Development Bank and the IMF. These actual and potential changes in the present military government's policy thinking may therefore be of considerable interest to many of Ammonite's clientele. A synopsis of these changes follows:

Policy

The Government's objectives are to develop an enabling envelope within which there will be sufficient guarantees and confidence building components to insure a smooth and successful privatization of the Government's commercial interests within the sector. Towards this end, a number of concrete steps have been taken:

1) The Privatization Law has been drafted and will shortly be promulgated through a Presidential Ordinance. This Law is designed to provide the protection and guarantees that are required by investors to insure that their investment in the previously state-owned entities remains safe from unilateral renegotiation.

2) A Petroleum Regulatory Authority (PRA) is being established in collaboration with the Canadian International Development Agency (CIDA), that will regulate both the upstream and downstream portions of the petroleum sector independently of the control of the Government of Pakistan and the Ministry of Petroleum. The regulatory functions that are currently vested in the Ministry of Petroleum will be transferred to the PRA when the latter becomes functional in December 2000. A similar Gas Regulatory Authority will also be established in the near future.

3) A Policy Cell is in the course of being established within the Ministry of Petroleum with the assistance of the World Bank. The Cell will be responsible for the formulation of oil and gas policy. With the establishment of this cell, the function of the Ministry will be reduced to that of policy formulation.

4) The Boards of Directors of the public sector oil and gas companies have been restructured to facilitate the working of these companies within the context of a market economy. Private sector counterparts have replaced the directors, the Chief Executive Officers and the Presidents of these companies and the Boards have been given autonomy to operate independently along commercial lines. The companies in question are:

a. Oil and Gas Development Company Ltd

b. Pakistan State Oil Company Ltd.

c. Pakistan Petroleum Ltd

d. Sui Northern Gas Pipelines Company Ltd.

e. Sui Southern Gas Company Ltd.

f. National Refinery

5) The privatization of the major Government oil and gas companies is currently underway, utilizing external expert financial advisors and the process has bee designed to maximize transparency to improve investor confidence in the process.

a. Financial Advisors are being appointed for the privatization of Oil and Gas Development Company Limited.

b. In the case of Pakistan Petroleum Limited (PPL), the largest producer of gas in Pakistan with 45% of total production, revision of gas pricing has been a major issue. This is being undertaken over a four-year period o time at the end of which gas pricing should be at market valuation.

c. With the Sui Northern and Sui Southern Gas Companies, the existing rate of return calculations are being changed from current return on assets to return on equity. This should improve efficiency, enhance the financial viability of the companies and bring he companies into line with international financial practice.

Implementation status

     (Short Term (0-8 months; ie. Now until May 2001)

1) Divestment of the Government's minority Working Interests in a number of producing oil and gas fields and oil companies. The most significant of these are:

Fields

     Union Texas:  Badin-1 (40%); Badin-2 (25%)

     Orient Petroleum: Ratana (25%); Dhurnal (25%)

     Pak Oilfields: Minwal (17.5%); Adhi (11%)

Companies

     Attock Refinery Limited (ARL - 35%)

     Pakistan Oilfields Limited (POL-34.75%)

The appointment of Financial Advisors is being finalized and work is expected to commence shortly (early September)

2) The sale of the LPG components of a number of Government controlled petroleum supply and distribution companies is underway. To facilitate the sale of these business components, the formalization of Governmental guarantees of LPG availability is being finalized. The bidding process for LPG supply and distribution components was to have started in August.

3) Letters of Invitation to bid for the meter manufacturing plant of the Sui Southern Gas Company Ltd should be issued shortly. Structuring of the transaction, valuation, approval of reference prices and pre-qualification of bidders have all been completed as part of the Government's due diligence process.

Medium term program (8-20 months)

1) The non-core assets of the Oil and Gas Development Company Limited (OGDCL) will be divested as the first step in the eventual privatization of the company. The appointment of Financial Advisors is currently being finalized and work is expected to commence this month.

2) The Government's working interest in nine fields that are currently under development will be offered for divestment following declaration of commercial discovery and the establishment of recoverable reserves. These fields are:

Sawan ; Zamzama; Bhit Chacher; Kandra; Tando Allah Yar; Zarghun South ; Jhakra; Bhadra

3) The Existing Gas Purchase/Sale Agreements of Pakistan Petroleum Limited (PPL) are to be dismantled by the Government so as to rationalize gas pricing and to make the eventual sale of the gas company competitive. Proposals for Financial Advisors to assist in this process are currently being solicited.

4) The Pakistan State Oil Limited (PSO) Company is to be restructured as a mechanism for preparing it for privatization. Due to the large size of the company it is likely that it will be broken into two or three smaller companies. Proposals for Financial Advisors to assist the Government in this restructuration process have been received and are currently under study.

5) Proposals have been made to unbundle the transmission, marketing and distribution components of both the Sui Northern Gas Pipeline Ltd (SNGPL) and Sui Southern Gas Company Limited (SSGC), as part of the restructuration process. Work has not yet started on this unbundling activity, however.

Long Term Privatization Program (beyond 20 months)

     The National Refinery Limited (NRL), the largest oil refinery in the county, has been proposed for divestment/privatization as part of this long-term privatization program. Work on this process has not yet started with NRL.

Gas Supply Augmentation and Pipeline expansion

     As part of the policy review process, the Government has decided to augment the existing domestic natural gas supply with an additional 928 MMCFD of gas from new discoveries. An additional 800 km of pipeline with diameter ranging from 16 to 36 inches is to be constructed along with 18,000 HP of additional compression to handle this additional gas supply. Construction cost will be n the order of $400 million and will be undertaken largely by Sui Northern and Sui Southern Gas Companies.

     As a means of obtaining further supplies of natural gas, Pakistan continues to pursue gas import projects from Iran and Turkmenistan. Pipeline from Iran, continuing on to India, will have a total length of 2670 km and cost an estimated $3.2 billion. The line from Turkmenistan will have a length of 1440 km and an estimated completion cost of $1.7 billion. Both projects are government priorities and pre-construction work is continuing.

     To increase the two Sui companies' capacity to finance these projects, the Government has agreed to a series of financial decisions;

     a. SNGPL will be authorized to raise additional equity of more than 4.5 billion rupees during the period 2001-04 and the Government may contribute up to 36% of the cost.

     b. SNGPL will have its credit ceiling raised by the Government to Rs 11 billion during the same period and its regulations regarding the raising of local currency through national borrowing, relaxed as a means of raising additional funds.

     c. The Government will make available $90.45 million for the financing of the required foreign exchange

     d. In the event the above measures are insufficient, private sector involvement on a BBO/BOT basis may be utilized.

     In the recent past the Government has awarded a contract for the construction of an 845 km White Oil Pipeline to the Pak Arab Refinery Company Ltd,(PARACO) with a carrying capacity of 6 million tons/year, expandable to 12 million tons. The cost of the project is approximately $600 million.

     PARKO is a joint venture between the Government and ADNOC (UAE). PARCO is in the process of finalizing an equity share offering of 49% of the company to the international industry. Shell has proposed the purchase of 26% of the available shares and this offer is undergoing Board review. The remaining 23% is available and a number of international companies have expressed an interest in their purchase.

Tom O'Connor recently retired as Chief Petroleum Engineer of the World Bank.  He is an expert on international petroleum contracts, political and economic risk assessment, and risk mitigation.

Submitted 9/8/00

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International Opportunities

for the Small Independent

By

Naresh Kumar, Ph.D.

Ammonite Senior Exploration Consultant

Richardson, Texas

   Although an average well outside the United States produces almost 15 times more oil per day than an average domestic well, the median size of an international discovery is only approximately 10 MMBO. This size target is generally too small for majors and large independents to pursue internationally. With the recent mergers, consolidations and advent of "supermajors", the typical target size for large companies is only apt to increase. This environment provides an excellent scenario for the small independent to seek opportunities on a global basis. With their low-cost structure and efficient use of technology, small independents can profitably target small discoveries. Such projects can be especially profitable if a multiple of such "small" targets can be combined together. Key success factors in such an environment are: A global outlook, multidisciplinary expertise, local contacts and a lot of patience. In many cases, even the most "mature" basins in other parts of the world have drilling density orders of magnitude less than the "mature" basins in the United States. Technologies, such as three-dimensional seismic, horizontal drilling, enhanced oil recovery and low-cost production systems, that have become almost "routine" in the United States for targets of all sizes, have hardly been applied in most other basins internationally. Similar to the domestic mature basins, field rejuvenation, field extension, and exploration for deeper targets should yield significant new reserves in basins outside the United States as well.

   Dr. Kumar presented a talk at the AAPG Convention in New Orleans in April on international opportunities for small independents. His sights are presently on Brazil, where he has identified Petrobras field redevelopment opportunities. Naresh's thoughts on Brazil were quoted in a sidebar article on page 44 of the July, 2000 issue of Hart's E&P monthly magazine (ref: <www.EandPnet.com >).

Submitted July 23, 2000

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DOWNSTREAM ISSUES:

Comments on EPA NPRM "Control of Air Pollution from New Motor Vehicles: Proposed Heavy-Duty Engine and Vehicle Standards and Highway Diesel Fuel Sulfur Control Requirements"

By

John M. Powell

Ammonite Senior Consultant for Refining and Marketing

New Canaan, Connecticut

     In the Environmental Protection Agency's (EPA's) recent Notice of Proposed Rule Making (NPRM), several assumptions are made that affect the need for and the cost of low sulfur diesel fuel. Specific Particulate Material (PM) and Nitrous Oxides (NOx) emission technologies are assumed to be utilized by manufacturers to meet the 2007 requirements and the entire U.S. on-road diesel supply is assumed to need to meet diesel fuel requirements for the 2007 engines.

     The EPA established the PM and NOx emission standards based on the PM and NOx technologies they believed would be available for the 2007 model year. The technologies are not available today but the EPA believes they will be available by the 2007 model year. These technologies are dependent on utilization of very low (below 15 parts per million) sulfur fuel. The proposed standards for diesel fuel sulfur level was then set to permit implementation of the sulfur sensitive technology on the basis that it is necessary to meet the proposed emission standards. This method of setting the emission standards is somewhat circular. It also puts the refining system at risk of heavily investing to produce a fuel (15 ppm sulfur diesel) that might not be needed in the long run, should alternate technologies be developed, or the anticipated technologies are determined not to be feasible.

     To the extent that refineries are required to produce one grade of on-road diesel fuel, the existing fleet will be required to accept the cost penalty of the 2007 fleet requirements without generating environmental benefits, other than sulfate PM reduction. If refiners were given the flexibility to produce two grades of diesel fuel, the impact of the costly reduction in sulfur level to 15 ppm would be mitigated for the existing fleet. (However, to the extent that sulfur were reduced in the fuel for the existing fleet, there would be a sulfate PM benefit.)

     A compromise reflecting the refining industry's desire to go to a 50 ppm sulfur limit, and the manufacturer's perceived 15 ppm sulfur limit need (for anticipated 2007 fleet requirements, as well as to provide a fuel supply for future emission technological developments), is to permit the marketing of a primary 15 ppm sulfur diesel fuel grade, and a secondary 50 ppm sulfur diesel fuel grade. While the two-grade system might be cumbersome, it would:

     Implementation of a two-grade diesel system could closely parallel the implementation of low lead (then no lead) gasoline. Low/no lead was offered in the market as a third grade of gasoline. (Historically there were two grades - Premium and Regular.) A requirement could be put in place to require any retail outlet that offers diesel fuel for sale, to offer 15-ppm diesel fuel, with the second 50-ppm grade at their discretion. Much like retail outlets were prohibited from selling leaded gasoline unless unleaded were available (in stock), 50 ppm diesel could be prohibited from sales unless 15 ppm diesel were available (in stock).

     The 15-ppm sulfur proposal is a dramatic reduction in the level of diesel sulfur from today's 500-ppm level. A phased-in approach (two grades) would provide refiners flexibility to meet the 15-ppm level in a portion of their diesel fuel pool, and to expand the percentage of 15-ppm fuel as demand increases. This would spread out the need for capital investment, and could relieve some of the borrowing/engineering availability concerns.

     A two-grade on-road diesel strategy would permit:

     John Powell is a chemical engineer and expert on crude oil and refined product market analysis. His most recent project for an Ammonite client involved an evaluation of the gas to liquids (GTL) technology of a public company. Synthetic transportation fuels made from natural gas meet the EPA's 15 ppm sulfur limitation.   

Submitted August 22, 2000

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ENVIRONMENTAL MATTERS:

EDITOR'S NOTE:

     Our intent is not to re-broadcast day-to-day news items covered in the trade press. However, when we learn about something unusual that probably has limited distribution, and which could lead to new business opportunities for Ammonite and our website visitors, we will publish the item on the Ammonite website.

     The following is an interesting development - Pennsylvania, where the USA oil business got its start, is now advising developing countries like Kazakstan on petroleum environmental regulation. We hope that this can set an example for other progressive regulatory agencies, and entrepreneurial environmental advisors. The world requires energy resources and minerals to power  and build its economies. Resource exploitation can, and must be conducted in an environmentally responsible manner in every country. I have seen some horrific natural resource environmental abuses in my worldwide travels. All of these were totally unnecessary, and are responsible for the "black-eye" that the extractive industries now have before the public.

     The petroleum and mineral industries are working hard to correct the environmental abuses and attitudes of the past. Great progess is being made. It is "good business" to be "green".  We applaud the iniatives of Pennsylvania and USAID in helping developing countries become more environmentally responsible, and in creating regulatory regimes that protect the environment, yet do not discourge the resource extraction that is vital to the world's economies.

PENNSYLVANIA ENVIRONMENTAL REGULATORS VISIT KAZAKSTAN

News Item Submitted by Consulting Geologists Pam and Dan Billman, Mars, PA

(Pennsylvania DEP Press Release on September 1, 2000)

     As part of an ongoing information exchange program, James Erb, director of DEP's Bureau of Oil and Gas Management, returned from a 10-day visit to Kazakhstan on Aug. 28. The meetings with Kazakhstan officials are intended to help the former-Soviet state establish sound environmental and regulatory programs as it develops its vast oil and natural gas reserves.

     Erb was part of an American delegation that included representatives from the U.S. Energy Association and the Alabama Oil and Gas Board. The information exchange is part of the Caspian Oil and Gas Environmental Partnership, sponsored by the U.S. Agency for International Development (USAID).

     Since the collapse of the Soviet Union, Western companies have shown a renewed interest in developing the extensive oil reserves in the Caspian area. This is resulting in changes to the Soviet-style petroleum laws and regulatory policies. However, environmental guidelines and implementation assistance is needed to ensure that these resources are developed without environmental degradation.

     USAID initiated the program to provide regulatory and educational assistance to Kazakhstan, Turkmenistan and the Georgia Republic. USAID has committed approximately $1.3 million over three years to develop partnerships in Caspian Sea nations. As part of the partnership, representatives from these nations will also visit the United States for training. The program may also be extended to include Azerbaijan and Russia.

     Pennsylvania was invited to participate because it is one of the few states that has combined oil and gas resource development regulatory functions and environmental regulatory functions into a single program.

     For more information, contact James Erb at 717 772-2199 or e-mail <erb.james@dep.state.pa.us>

Last Update:  September 29, 2000

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