Future gulf supplies: Role of the federal government

Sept. 2, 2002
The US Gulf of Mexico (GOM), providing 1.8 million b/d of crude oil/NGLs and 14 bcfd of natural gas, has been a major source of domestic energy supplies. However, considerable uncertainty surrounds the outlook for this critical oil and gas producing area, with many concluding that production is or soon will be in decline.

The US Gulf of Mexico (GOM), providing 1.8 million b/d of crude oil/NGLs and 14 bcfd of natural gas, has been a major source of domestic energy supplies. However, considerable uncertainty surrounds the outlook for this critical oil and gas producing area, with many concluding that production is or soon will be in decline.

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If true, this could further influence a trend towards more volatile domestic prices and decreased energy security. The extent of the uncertainty, particularly for gas, is reflected in recently published projections (by the MMS) that show an uncertainty range of over 5 bcf in daily gas production in the next 5 years (Fig. 1).

The two previous articles in this three-part series made the case that significant GOM supply potential remains. The first article reviewed the development, production history, and future potential of the deepwater areas of the GOM in more than 200 m of water (OGJ, May 6, 2002, p. 52). The second focused on shallow water areas in 200 m of water or less (OGJ, July 1, 2002, p. 34). These articles concluded:

  1. As more is learned about the geology and resource characteristics of both shallow and deepwater prospects, assessments of the GOM resource potential continue to grow more optimistic.
  2. Technological advances have allowed the industry to economically develop and produce increasingly larger proportions of the GOM oil and gas resource.
  3. Past government policies have helped accelerate offshore developments, particularly the deepwater gulf.

However, economically developing the promising GOM resources is hindered by a series of barriers, including long development lead times, high costs, and progressively smaller fields. Price volatility and policy uncertainty further hinder timely exploration and development.

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Despite these barriers, the need grows for secure, stable supplies of domestically produced oil and gas, particularly after the events of Sept. 11, 2001. As such, the critical question is how much production can we expect from the GOM and by when. The factors influencing the future of the GOM on which public policy can play a crucial role include:

  1. The pace and extent of technological progress.
  2. Access to currently restricted areas of the Outer Continental Shelf.
  3. Financial incentives to stimulate development.
  4. Future environmental regulations.

The impact of these factors on future GOM oil and gas production will be explored in more detail in the rest of this article.

Technology development: Notable new technologies

More than anything else, progress in technology has unlocked and extended the life of the gulf. New technologies have enabled companies to develop the challenging, deep waters, pursue progressively smaller fields, and more intensely develop discovered fields. The essential technologies include:

  1. Lower cost platform designs: Technology advances such as regular and "mini" tension leg platforms (TLPs), SPARs, and floating production systems (FPSOs) have allowed the industry to cost-effectively push into deeper waters.

As the use of TLPs has become more widespread, their costs continue to drop. According to Shell, the installed unit cost of a TLP today is 50% of that for the Auger TLP launched in the early 1990s.1 "Mini" TLPs are also offering offshore developers a cost-effective option. For example, El Paso Energy's Marco Polo "mini" TLP, due to start up in 2004, will be in 4,300 ft of water and will handle 100,000 b/d. It will be one of seven "mini" TLPs operating in the gulf.

  1. Improved exploration technologies: Advanced seismic technologies have led to improved exploration success rates and supported successful exploration of subsalt prospects and the development of smaller fields. In 1990-97, Amoco's overall drilling success rate for wells drilled based on the application of 3D seismic was 47%, compared with a success rate of 13% for wells that relied on 2D seismic.2 Similarly, in 1999, 24 of 34 wildcat wells drilled by Vastar on the shelf were productive (a 71% exploration success rate).3
  1. Central hubs and subsea completions: Establishing a central hub, in either deep or shallow water, linked to a series of subsea completions, is becoming a favored development concept.

For example, the Canyon Express project ties three smaller (100 to 400 bcf) subsea completed deepwater gas fields to a shallow water central platform, enabling this set of fields to reach a critical size and become economic. Moreover, by standardizing subsea hardware, Shell was able to reduce the costs of subsea tree systems in the gulf by more than 40% and cut installation time 30% since Mensa field came on stream in 1997.4

While originally applied as a lower cost alternative to expensive, deepwater wells drilled from conventional platforms, subsea wells are becoming the preferred development option for marginal, shallow water fields. In fact, 136 of the 218 subsea wells drilled to date in the gulf are in shallow water.

  1. Deep subsalt well drilling: Industry has made significant advances in cost-effectively drilling ultradeep 25,000+ ft wells through extensive (10,000 ft) sections of salt.

Texaco recently drilled two ultradeep subsalt prospects at Walker Ridge. The Loyal well in 6,700 ft of water was drilled to 29,230 ft (TVD) in 154 days (including 30 days down time due to weather) and briefly held the GOM depth record. The Catahoula well in 5,500 ft of water went to 28,000 ft at a rate of 3 days/1,000 ft, making it one of the fastest ultradeep wells in the gulf.5

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  1. Combined effects of technology: Technology improvements in platform design, drilling systems, and 3D seismic have lowered offshore finding costs (for all water depths) from about $15/boe in 1986 to $5/boe in 1996 in today's dollars (Fig. 2). However, since 1996, finding costs have risen to nearly $10/boe, indicating that this past trend in technological improvement may be difficult to sustain without aggressive new efforts.

Continued technology progress

While the past advances in technology are impressive, continued technology progress is as important, if not more so, today as in the past.

GOM development is moving steadily toward deeper waters, smaller fields, and deeper formations, each driving up costs. In addition, there is a need to recover more oil and gas from already discovered fields through intensive development, from extension drilling into smaller pools, and from new efforts in enhanced oil recovery.

One option that may become increasingly effective, and one that is being examined for North Sea oil fields, is combining EOR with geologic sequestration of CO2 in favorable offshore fields. Industry and government, recognizing this need, are each pursing advances in oil and gas E&P technologies that would lower costs and increase recovery in the OCS:

Deepwater Staged Recovery (DeepStar) Project. The DeepStar Project, initiated in 1992, is an industry-led effort to develop economically viable, fit-for-purpose deepwater production technology with global applicability and to support the regulatory acceptance of this technology.6

DOE Offshore Technology Roadmap. The DOE's Office of Fossil Energy, in collaboration with the Minerals Management Service (MMS) and offshore producers, is also examining ways to accelerate OCS oil and gas development.

Workshops were held across the country in summer 2000, culminating with a "roadmap" of future technologies (www.fe.doe.gov/oil_gas/reports/ostr/roadmap.html).

The roadmap set forth a suite of exploration, drilling, and platform technologies for producing deepwater resources and a complementary set of technologies for protecting the offshore environment, defining a technology pathway that would reduce costs in ultradeep water by 40% in the next 10 years. The roadmap also highlighted possible regulatory actions and financial incentives for supporting continued deepwater oil and gas production.

The current focus of research is on the deep water. Given the mature state of the shallow water GOM fields, this area deserves its own dedicated research and technology focus, particularly on maintaining the productive life of the older fields and accelerating the application of enhanced oil recovery.

Advanced technology

To justify spending scarce R&D dollars (by industry or the federal government) one needs to identify if the benefits will exceed the costs and by how much. For this, the impact of developing and applying improved technology on GOM fields was examined using Advanced Resources' Gulf of Mexico Natural Gas & Crude Oil Capacity and Production Forecasting Model (ARGOM).7

The benefits of advanced technology were evaluated by characterizing its impact in three areas:

  1. Expanding into technically challenging frontiers. According to the MMS, as much as 108 tcf of gas and 16.8 billion bbl of crude oil exist in areas that push the limit of today's technologies (Table 1). These areas-subsalt formations, deep formations (>15,000 ft subsea), and ultradeep water (>1,600 m)-will require further advances in technology before they can be economically producible on a broad scale.
  2. Continued development of mature producing fields. Further technological advances will be required to maintain the historical pace of reserve growth in existing fields as operators pursue smaller and deeper pools and attempt to recover greater volumes from old fields.
  3. Efficiency improvements and continued cost reductions: Substantial improvements in exploration efficiency and reduced costs have characterized offshore E&P activities the past two decades. Of critical importance is the future pace of these improvements. Table 2 highlights the assumptions for several technology parameters used in this analysis.
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The impact of technology performance was examined using two cases:

A Reference Case, which assumes a slower rate of improved efficiency, cost reduction, and reserve growth in known fields. In addition, this case assumes that the technologically challenging areas described above remain relatively inaccessible the next 12 years.

An Advanced Technology Case that assumes a faster rate of technological improvements, cost reduction, and reserves growth, and assumes that technology advances begin to allow the technically challenging areas to be expanded and economically produced.

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Advanced technology resulting from more aggressive R&D efforts focusing on both shallow and deepwater resources could result in an additional 5,840 million bbl of cumulative oil production and an additional 30.5 tcf of cumulative gas production in 2002-2020 (Table 3).

Of this amount, 1,130 million bbl of oil and 16.2 tcf of gas is attributable to technological advances that help develop and produce more of the resource potential in shallow water areas. Achieving this level of technological advances would result in over $32 billion in extra federal royalty revenue.

CO2 and offshore EOR

With appropriate incentives, market prices, and technologies for sequestering CO2, it may soon become economically feasible to pursue CO2-based EOR in the gulf. While more detailed recovery and economic analyses are clearly required, a scoping level review indicates that this area offers considerable potential.

Assuming a GOM total oil endowment (past production, reserves, reserve growth, and undiscovered) of 85 billion bbl and an average recovery efficiency of 45%, the oil in place in the gulf is estimated at 190 billion bbl. Excluding smaller fields and pools, the target fields for EOR could hold about 100 billion bbl.

With an expected recovery efficiency of 15% of the oil in place (for a 40° gravity crude), the EOR potential is on the order of 15 billion bbl. One concern is that if joint sequestration of CO2 and EOR are to become feasible and contribute to increased domestic oil supplies and greenhouse gas reductions, important initial steps need to be taken before the gulf's offshore platforms are abandoned and removed.

GOM OCS leasing: Defining the field

Federal leasing history

In 1982, the MMS was created as a bureau within the Interior Department to manage OCS mineral resources in an environmentally responsible manner.

One of MMS's first steps was to introduce areawide leasing, which greatly expanded the available OCS areas of interest to industry. However, accelerated leasing in the gulf was offset by legislation that established a leasing moratorium on the Central and Northern California OCS. This was followed, in 1983, by the first pre-leasing moratorium for the North Atlantic.

In 1988, a drilling ban was issued for 73 existing leases in the Eastern Gulf of Mexico, which was later expanded to include the North Aleutian basin and existing leases off North Carolina. In 1990, offshore moratoria and drilling bans were extended and expanded to include all of the offshore West Coast and Atlantic, and the Eastern Gulf of Mexico (south of 28° N. Lat.) until after 2000. In 1998, these moratoria were extended to 2012.

Today, because of these moratoria, only 15% of the OCS acreage in the US is available for leasing, and the current MMS 5-Year Leasing Plan for 2002-07 offers no "new" areas for offshore leasing.

Eastern Gulf of Mexico

According to the MMS, the Eastern GOM is estimated to contain 2.4-6.6 billion bbl of oil (mean of 3.6 billion bbl) and from 10 to 19 tcf of gas (mean of 12 tcf). Of this, only an estimated 200 million bbl of oil (5%) and 1.2 tcf of gas have been offered for leasing to date (Table 4).

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The recent MMS Lease Sale 181 was the first offshore lease sale in the eastern gulf since 1988. This highly politicized sale pitted the Administration of President George W. Bush, which originally supported full leasing in the eastern gulf, against Jeb Bush, his brother and the current governor of Florida.

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The original proposed sale contained 240 million bbl and 1.8 tcf (MMS estimates). In the end, the federal government dramatically reduced the size of the lease sale, eliminating all lands within 100 miles of the Florida coast, and thus deleted from consideration all areas in less than 200 m of water (Fig. 3).

Even with the reduced acreage, Sale 181 conclusively demonstrated industry's belief in the potential of the region. Seventeen companies participated, with 95 tracts receiving high bids totaling over $340 million, and the average high bid was $622/acre, compared with $93/acre for Western GOM Sale 180 (in 2001), and $185/acre for Central GOM Sale 178 (in 2001).

Drilling has safely occurred in the eastern gulf the last 30 years. To date, 12 of the 47 wells drilled in the eastern gulf produced commercial quantities of oil and-or gas, including Chevron's at Destin Dome. This dry gas discovery, 10 miles from the recently built Gulfstream pipeline that serves growing Florida gas markets, is believed to contain at least 700 bcf of economically producible gas.

Alternative leasing policies

We have not examined how reopening the eastern gulf and lifting OCS leasing moratoria would improve oil and gas production and domestic energy security. Needless to say, we believe the volumes of production would be significant and of high value to the nation.

Moreover, maintaining the moratoria can be, in fact, counterproductive from an environmental perspective. Recent operating data from the gulf show that oil spills from offshore platforms are much less than oil spills from tankers carrying foreign oil imports, even after adjusting for the relative volumes involved.

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A recent National Research Council study concluded that less than 2% of the oil input to North American oceans is the result of oil and gas exploration activities (Table 5).8 And, offshore gas development, when properly designed, is an environmentally clean activity with many domestic energy supply and environmental benefits.

Financial incentives; stabilizing development

Deepwater incentives

In 1995, Congress passed the Deepwater Royalty Relief Act (DWRRA) that provided economic incentives for leases issued between Nov. 28, 1995, and Nov. 28, 2000. These incentives provided automatic suspension of royalties for OCS fields, as follows:

  • 200-400 m of water: relief on the first 17.5 million boe produced.
  • 400-800 m of water: relief on the first 52.5 million boe produced.
  • Greater than 800 m of water: relief on the first 87.5 million boe produced.

The introduction of deepwater royalty relief had a major impact on the industry. Prior to 1996 (Table 6), most of the acreage leased was in shallow water. Upon passage of deepwater royalty relief, combined with considerable advancements in technology, industry's leasing attention shifted to the deep water.

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Since 2000, with the expiration of deepwater royalty relief, (plus the growing participation of independent producers), once again more shallow water than deepwater leases are being acquired. In the most recent Central Gulf of Mexico lease sale (Sale 182), 57% of the blocks receiving bids were in less than 200 m of water.

Current federal policies

While the provisions of DWRRA expired on Nov. 28, 2000, new provisions became effective in 2001.

These new provisions will be specified for each lease sale based on prevailing economic conditions. They will be granted to individual leases, not fields as under DWRRA, and will be designated at the time of the final notice of sale.

For example, in Western Gulf of Mexico Sale 184, held Aug. 21, 2002, MMS offered royalty relief for tracts in more than 400 m of water, with the royalty "suspension volumes" defined as follows:

  • 400-800 m of water: royalty suspension on the first 5 million boe produced.
  • 800-1,600 m of water: royalty suspension on the first 9 million boe produced.
  • Greater than 1,600 m of water: royalty suspension on the first 12 million boe produced.

Moreover, the new rules allow for individual lessees to apply for further relief based on need.

Also included in the proposed notice is an incentive to drill for deep gas deposits located on the shelf. This incentive provides for royalty suspension for the first 20 bcf of production from a lease with one or more wells drilled 15,000 ft or more below sea level. MMS states that 1,642 blocks are subject to the deep gas incentive.

One of the shortcomings of this incentive is that, while it applies to gas production from new leases in less than 200 m of water, it provides no incentive for deep wells on existing leases that most likely hold the bulk of the deep gas deposits on the shelf.

Possible future policies

At this writing, Congress is considering potential provisions concerning deepwater incentives as part of a possible Energy Bill.

House Bill (H.R. 4) provides for a reexamination of existing offshore lease terms and conditions and to study and recommend incentives to "ensure that the US optimizes the domestic supply of oil and gas from the offshore areas of the Gulf of Mexico that are not subject to current leasing moratoria."

Similar provisions to examine offshore incentives and recommend possible modifications also exist in the Senate version of the Energy Bill. The Senate bill also advocates the extension of lease term in difficult settings (like subsalt) to allow more thorough geological and geophysical studies.

Estimated new benefits

Like that for supporting investments in technology, one needs to know the benefits of the incentives to justify spending federal dollars. For this assessment of impact, deepwater and shallow water incentives were considered separately, as follows:

Deepwater incentives: Two scenarios for deepwater royalty relief were considered:

  1. Reinstatement of DWRRA provisions. This scenario assumes that the provisions of the DWRRA are re-established and apply to deepwater fields indefinitely.
  2. No relief. This scenario assumes no royalty relief is available to deepwater fields.

The permanent re-establishment of deepwater incentives like those in the DWRRA, could result in the following (Table 7)-cumulative oil production increasing by 3,140 million bbl by 2020, and cumulative gas production increasing by 12 tcf in the same time period.

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Shallow water incentives: Three shallow water incentives are considered:

  1. New fields. This assumes that the DWRRA incentives applicable to fields in 200-400 m of water are extended to fields in less than 200 m.
  2. Marginal existing fields. This incentive, designed to extend the life of producing fields, would provide royalty relief to shallow water fields. The scenario assumes that royalty payments are suspended where the average production rate per well from a field drops below a specified rate.
  3. Deep gas incentives. At a gas price of $3/Mcf, the value of the incentive would amount to about $10 million to a lease. According to the American Petroleum Institute,9 deep offshore gas well costs ranged from $10 million/ well to $30 million/well in 1998. Therefore, the value of this incentive is equivalent to the low end of the cost range for a deep gas well.

The extension of the DWRRA incentives to shallow water fields could, by 2020, result in 230 million bbl of additional cumulative oil production and 3.1 tcf of additional cumulative gas production (Table 8).

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Royalty relief for already discovered marginally economic fields, which extends the life of these fields for several years, could result in another 400 million bbl of oil and 5 tcf of cumulative gas production between now and 2020.

Finally, the permanent establishment of the deep gas incentives-applied to prospects on existing leases-could result in additional cumulative gas production by 2020 of 4.7 tcf.

Environmental protection:Balancing costs, benefits

Government's historical role

For the past three decades, the offshore oil and gas industry has been the object of increasing public attention on the impact of oil and gas operations on the environment.

In response, a litany of legislative actions has, at least in part, been designed to ensure that industry operations are pursued with proper regard for the environment. In this article, three future potential actions are discussed:

  1. Possible future restrictions on the ocean discharge of drilling wastes and produced water from offshore facilities.
  2. Additional restrictions imposed on the emissions of air pollutants from offshore facilities.
  3. Constraints on offshore development imposed by the Coastal Zone Management Act.

Ocean discharge criteria

The Environmental Protection Agency plans to issue a Notice of Proposed Rulemaking in 2002 and a final rule in 2003 on new ocean discharge standards for offshore oil and gas E&P operations. Industry is concerned that more stringent compliance requirements would have a detrimental impact on the economic viability of offshore operations.

In this article, an admittedly worst-case scenario is assumed, where the discharge of the major wastes from offshore oil and gas E&P facilities would be prohibited. Specifically, for the management and disposal of drilling wastes, a stringent regulatory scenario assumes all drilling wastes must be either hauled to shore and disposed in an onshore waste disposal facility or must be reinjected to an appropriate subsurface formation.

Similarly, for the management and disposal of produced water, a stringent regulatory scenario assumes all produced water must be either hauled to shore or must be injected to an appropriate subsurface formation. For purposes of this analysis, it is assumed that all produced water is injected.

Estimated compliance costs of the more stringent regulations were developed based on EPA, DOE, and API data on the supply and economic impacts of potential zero discharge of drilling wastes and produced water from offshore oil and gas operations.9

Offshore air quality

EPA is currently responsible for control of air pollution in OCS areas of the Eastern Gulf of Mexico. MMS has jurisdiction over the Central and Western Gulf of Mexico.

For OCS sources located within 25 miles of states' seaward boundaries, the requirements for air emissions control are the same as requirements for sources located in the corresponding onshore area. New offshore stationary sources in this area are required to utilize "best available control technology" (BACT) in controlling emissions, while existing stationary sources are required to apply "reasonable available control technology" (RACT).

OCS sources located beyond 25 miles of the states' territorial seas are subject to federal requirements for Prevention of Significant Deterioration.

BACT is already required in offshore areas under EPA's jurisdiction. The possible future application of BACT requirements to the areas of the Gulf of Mexico currently under MMS jurisdiction could further impact the economic viability of GOM operations.

Based on analysis performed in 1998-99,10 extending BACT requirements to all offshore facilities in the GOM could add on the order of $7,300/well initial capital costs and $16,200/well annual operating costs to offshore E&P operations in the GOM.

Environmental costs

Imposition of these more stringent regulatory requirements for OCS oil and gas operations in 2005-2020 could result in the following:

Cumulative oil recovery could decrease by 2,390 million bbl.

Cumulative gas recovery could decrease by 12.0 tcf.

Receipts to the federal treasury from royalties could be reduced by nearly $13 billion.

Coastal Zone Act

Under the Coastal Zone Management Act (CZMA), a coastal state with a federally-approved Coastal Zone Management (CZM) Program is empowered to block offshore exploration and production plans provided the state can allege that the lessee's plans will have some impact on resources in the coastal zone.

In the Western and Central GOM, states have taken a responsible, collaborative approach to this requirement. In other areas like the Eastern GOM, states have used this authority to delay offshore development activity.

Improving CZMA will create greater willingness for operators to pursue offshore prospects and will provide them with greater predictability of the economic potential of offshore exploration prospects. The possible impacts associated with constraints imposed by this process under CZMA are not assessed in this article.

Summary of results

Federal policy actions-whether these are through more aggressive research and development programs, through long-lasting financial incentives, or through cost-effective, risk-based environmental requirements-will play a key role in the future of oil and gas production from the GOM.

A variety of possible federal actions-most effectively applied in strategic combinations-could serve to enhance the gulf's ability to continue to be a major source of oil and gas supplies to the US for many years. On the other hand, without focused government actions, the best years of this prolific petroleum province may be behind us, even with favorable assumptions about the gulf's deepwater resources.

This article presents the case that substantial benefits could result if the federal government continues policies and programs that enhance the economic resource potential of this world-class hydrocarbon area.

References

  1. McCaul, James R., "Deepwater remote fields rely on floating production systems," OGJ, June 11, 2001, p. 68.
  2. Aylor, William K., "Measuring the impact of 3D seismic on business performance," JPT, June 1999.
  3. Williams, Peggy, "The Gulf of Mexico Shelf," Oil & Gas Investor, Vol. 20, No. 2, February 2000.
  4. Anonymous, "Subsea technology leads to deepwater field development," in Shell E&P Technology, a supplement to Hart's E&P and Oil & Gas Investor, May 2002.
  5. Minerals Management Service, "Deepwater Gulf of Mexico 2002: America's Expanding Frontier," OCS Report MMS 2002-021, April 2002.
  6. Website (www.deepstar.org/public/information)
  7. Eppink, J.E., Kuuskraa, V.A., and Kuck, B.T., "Assessment of natural gas and oil supply issues in the deepwater Gulf of Mexico," OTC Paper 12225 presented at 2001 Offshore Technology Conference, Houston, Apr. 30-May 3, 2001.
  8. National Research Council, "Oil in the Sea III: Inputs, Fates, Effects," Ocean Studies Board and Marine Board, 2002.
  9. Environmental Protection Agency, "Economic Analysis of Final Effluent Limitations Guidelines and Standards for Synthetic-Based Drilling Fluids and other Non-Aqueous Drilling Fluids in the Oil and Gas Extraction Point Source Category," EPA-821-B-00-0123, December 2000.
  10. Godec, Michael L., and Petrusak, Robin, "The Answer to Increasing Environmental Compliance Costs: Regulatory Reform or Technological Advance?," SPE Paper No. 56495 presented at the 1999 SPE Annual Technical Conference and Exhibition, Houston, Oct. 3-6, 1999.

The authors

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Michael Godec ([email protected]), a senior technical advisor with Advanced Resources, has 18 years' experience, working with government agencies, industry associations, and private energy companies worldwide. His expertise includes energy market analysis and forecasting, environmental and economic impact assessments, energy policy analysis, asset valuation, and due diligence. He has a BSc in chemical engineering from the University of Colorado and an MSc from Washington University.

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Vello A. Kuuskraa is president of ARI, a firm that provides technical and consulting services in geology, engineering, and economics for natural gas and oil. He served on the US Secretary of Energy's "Assessment of the U.S. Natural Gas Resource Base" and was a member of the National Academy of Sciences' Committee on the National Energy Modeling System. He received an MBA degree (highest distinction) from the Wharton School, University of Pennsylvania, and a BS degree in mathematics/economics from North Carolina State University.

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Gregory Bank is a geologist with Advanced Resources International. He has worked on unconventional gas play assessments throughout the Rocky Mountains. He has an MS in geology from Virginia Tech and a BSc from Washington & Lee University.