At its December 1, 2000 Winter Meeting, the Western Governors

Association adopted two resolutions demonstrating a commitment to meet emerging regional energy shortages. The Energy Policy for the Americas (Resolution 00-036) called for an Energy Roundtable in February of 2001 to institute actions to address increasing prices and energy shortages and to emphasize the need for a national energy strategy. The Coal Policy (Resolution 00-037) reflected the governors’ understanding that the West is blessed with diverse fuel resources: fossil fuels, renewables, hydro and uranium. It stated that the West should be allowed to responsibly develop such resources, including coal, to ensure that a varied fuel mix is readily available for the West’s citizens, the nation and the Americas.

Four WGA policy resolutions in 1999 offered guidance on how to approach key energy issues. The Hydropower Relicensing Policy (Resolution 99-016) strongly endorsed protection of state authority over the water rights aspect of hydropower projects and the Implementation of NEPA Policy (Resolution 99-019) asserted that sound environmental assessments must be balanced with considerations of timeliness and efficiency in decision-making for energy development. The governors also addressed transportation and energy development as they relate to air quality in Policy Resolution 99-012. This resolution called for an incentive-based regulatory program that accommodates the unique western air quality protection issues. Finally, the overarching Principles for Environmental Management in the West (Resolution 99-013), offered a pathway for addressing the complexities created by western growth, the region’s (and nation’s) dependence on natural resources and the desire to protect the environment and quality of life characteristic of, and valued by, the region.

Although WGA has been proactive in adopting policy on energy in the West, the rapid rise in national gas prices and onset of electricity shortages and outages led the governors to call for an Energy Summit in December. It was the beginning of an intensive six-month effort to tackle both short-term and long-term energy issues facing the West. At the summit, many governors indicated a preference for market-based solutions and discouraged the use of price caps to resolve immediate price spikes.

At a subsequent Energy Roundtable in February, WGA agreed to a set of

"Recommended Actions for Addressing Immediate Electricity Problems in the West" and "Actions to Address Long-term Energy Needs." (Attached as Exhibits B and C) Knowing that the reality of the western electric power system had inextricably linked the energy future of the western states and having already implemented conservation measures in their states, the governors agreed in the short term to "conduct a regional assessment of whether and how gas supplies and its transmission can be increased in time to meet summer peak load demand". In addition, they began addressing longer-term energy infrastructure issues. The governors called for a "workgroup of major transmission system owners to identify where bottlenecks occur and to recommend needed new transmission facilities." Governors also chose to promote seven "demand-side" policies to refresh their commitment to more efficient use of energy resources.

The traditional approach of a vertically integrated utility was to own generation and make supplemental purchases. Transmission needed to support that supply was planned along with the generation. Much of the new generation added to the system recently has been built by merchant generators, independent parties selling to load serving entities – utilities, aggregators, and marketers – under forward contracts. Marketers play an increasing role in matching buyers and sellers of energy and in providing risk management services for forward contracts. This trend will continue as parties responsible for serving consumers rely increasingly on managing a portfolio of contracts to meet their requirements for a reliable supply of energy. Increasing inter-area transfer capability of the transmission system, as economically justified, will allow the regional competitive market to continue to grow.

Some have claimed that increasing trade over the transmission system will reduce system reliability – it need not. System reliability is maintained by establishing system operations and planning standards. The reliability standards become the acceptable limits of operation for all parties, regardless of ownership or function. It is the duty of the transmission system operator to maintain adequate reserves on line and to keep line flows within established ratings. The system operators implement procedures that translate reliability standards into requirements to be met by generators, marketers, utilities, transmission owners, and consumers. The procedures cover items like scheduling protocols, reserve responsibilities, and emergency response obligations. But expansion of the transmission system needs to occur within the boundaries established by reliability standards. Transmission interconnections also enable the capture of the benefits of diversity that exists between different areas of an interconnection. Taking advantage of this diversity also lowers the cost of providing reliable service through trade over the transmission system. There are two general types of diversity – load diversity and resource diversity. As load in a given area grows, local expansion may be required to meet increasing need. Such local expansion tends to have little effect on the ability of the interconnected system to make transfers from one area to another. The topography of the West makes this even more pronounced than might occur in the East. Load is concentrated by water availability and arable land with mountains and deserts between developed areas.

Load diversity exists at several levels, all of which arise because not all loads peak at the same time across an interconnection. In the West, there is substantial seasonal load diversity as generators in winter peaking areas like the Pacific Northwest sell surplus capacity to parties in summer peaking areas like California and the Desert Southwest. Areas with hydro storage enter into seasonal energy exchanges and hydro can be used to meet daily peaks with energy returns at night from base load plants. There is also daily load diversity because of the nature of Western topography. The 1.8 million square miles of the Western Interconnection covers two time zones and multiple climate zones -- coastal, desert, mountains, plains. Some areas peak in the morning while others peak in the afternoon. Weather systems move from West to East, affecting different loads at different times. These differences in the peaking behavior of the load reduce the coincidental peak of the entire system, thus reducing the total of generation required to serve the region. Price differentials between areas provide the signal to buyers and sellers for capturing these diversities through the trading in the energy markets.

In addition to the broad spatial distribution of load in the West, many of the resource options are also remote from load centers. The West has a significant degree of resource diversity, using a variety of sources and fuels to generate the needs of the region. Coal-fired generation, often at mine mouth plants, developed in the Intermountain states and provinces. Hydroelectric generation is the primary source in the Pacific and in Northern California. Gas-fired generation is a rapidly growing source across the West with great concentrations forecast in the near term for the desert Southwest.

Diversity of supply increases the reliability of the entire interconnection as it insulates customers from the risks of over-dependence on a single source. A balanced portfolio of resources (echoes Coal Policy Resolution) will provide good service for the long run by averaging the uncertainty associated with both the price and the supply of any single resource. "Coal by wire" is an example of developing a remote resource to serve an urban load. Wind and hydro resources must be transported by the transmission system since the primary resource itself cannot be transported to the load center by other means. Such new resources require use of the transmission system. If current transfer capability is insufficient within existing reliability criteria, new long distance transmission will be required. The topography of the west and the topology of the resulting network therefore make it possible to separate local transmission expansion from projects that create inter-regional transfer capability.

Balance of resource types minimizes overall risks and price as the strengths of one resource complements the weakness of another. Northwest hydro has seasonal energy surpluses available and large amount of peaking flexibility but is energy short annually. Coal-fired and nuclear generation is very efficient at producing energy when operated at high capacity factors, but is very poor at load following. Wind produces energy at low price but the energy must be shaped by other sources, which can follow load variations. Gas-fired turbines can provide peaking or can be combined with steam recovery (combined cycle) to operate as high efficiency baseload plants. A varied fuel mix in the marketplace allows buyers to diversify and mitigate their price risk due to events such as a rise in price for a single fuel, low water conditions, fuel shortages such as a coal strike.

Although some transmission limitations and constraints are perceived solely as transmission issues, some may be solved by a wide variety of both transmission and non-transmission alternatives, e.g. you may not need to expand a transmission line to solve a congestion problem. Non-transmission alternatives range from demand managment to distributed resources. Consideration of a variety of possible alternatives will offer higher probability that the finally preferred solution is effective for the long-term. The question to be addressed here is what sort of policy considerations should inform the choice of appropriate transmission alternatives. A future transmission system that serves the needs of both the existing generators and their customers, while also accommodating the requirements of new generation and its users, must take into account a wide variety of considerations. This section attempts to address some of those issues and why they are important.

A wholesale market for electricity that functions well will be characterized by a variety of different features. That market should generate power from a variety of resources. It should take advantage of seasonal diversity wherever possible. It should allocate risks appropriately among market participants. It should be characterized by efficient market prices. It should provide open access to a variety of participants. And it should allow for the improvement of power quality as necessary to keep up with the technology improvements in production processes. The goal of the system is to produce an adequate supply of energy ("keep the lights on") at reasonable prices. Each of these features of an efficient wholesale market is supplemented by, or in some cases dependent on, a wide-reaching and well-functioning transmission network.

Price is the mechanism the market uses to match supply and demand, with rising price expected to draw new supply into the market and demand responsive load reacting so as to provide a check on unrestrained price behavior. Under the functional separation standards of FERC Orders No. 888/889 and 2000, market price signals must provide the necessary linkage between generation siting and transmission expansion. In the absence of accurate price signals regarding the cost of transmission expansion, poor siting decisions can occur. The current effort relies heavily on modeling and assumptions about the size and location of future generating projects to determine the need for major expansions of transmission capacity on particular paths and particular projects. So there is risk in making major investment decisions, given the great uncertainty about which of the many plants that are currently announced will be built. Further, the current process for financing of transmission projects separates the risk from the parties that will benefit from the transmission expansion and places it on parties who cannot avoid it - ratepayers and taxpayers. Such a system encourages parties who would benefit to overstate the need for transmission expansions and makes efficient decisions difficult.

By contrast, RTO proposals currently being finalized for the western grid would manage congestion efficiently, in a way that would result in congestion prices that signal the value of congestion and the value of expanding specific paths. These proposals would allow those who would benefit to assess the value and risks of investing their own resources in system expansion. They would also focus attention and provide incentives

for generation and conservation in the areas where they would be most valuable. Looking to the future, effective congestion management systems in RTOs are a key element in producing needed price signals. In the new world of more competitive wholesale markets, price differentials should drive the need for new transmission and adequate transmission should provide a means to mitigate local market power .

We note a caution against overbuilding of transmission and distribution. The actual transmission and distribution costs borne by customers are clearly a function of the amount of annual usage of such facilities. It may be appropriate to beef up transmission and distribution to transmit power from baseload plants, but intermediate and peak loads may be better served by resources closer to loads, e.g. by non-transmission alternatives. Such alternatives can reduce the need for transmission, but in few cases will they eliminate it entirely. These might include small combustion turbines sited strategically with respect to existing transmission or distribution lines so that they actually relieve congestion. Load management and/or customer buyback programs, or conservation aimed specifically at peak loads, can provide similar relief of transmission congestion. Finally, on-site renewables may offer a unique and special case of distributed generation that accomplishes the same ends.

The current transmission planning process is fragmented based on individual utilities’ forecasts of their own individual needs and specific interconnection requests. Coordination is done on a sub-regional basis, at best. The current process raises a variety of concerns. Market uncertainties and modest regulated rate of return seem to have been discouraging investments by utilities and approvals by regulators. The coordination process is reactive, triggered by individual specific proposals, rather than proactive and forward-looking. There appears to be little support, if any, for plans that support regional efficiencies beyond the immediate boundaries of specific individual proposals. There is a wide gap between evolving merchant needs on the resources side (regional) and existing grid plans (local or sub-regional) on the transmission side. Planning assumptions are based primarily on local traditional resources and give little consideration to remote and non-conventional resources. In spite of the high hopes for the creation of a single west-wide RTO, the creation of as many as five smaller and separate RTOs plus several non-jurisdictional planning entities in the region may be retarding progress.

As we move forward in addressing the above issues, policies are needed to achieve an authoritative and proactive planning process that identifies need, benefit, and impact on a full regional basis. For example, the process could: facilitate the "transmission market" by providing information on forecast needs and on proposed projects, by coordinating technical study data and by facilitating the system rating process (which would define what the seller is selling and what the buyer has acquired); collect all potential generation requests/proposals; combine load, price and generation siting information to forecast expected inter-area transfer requirements; consider proposals for merchant transmission; verify transmission needs through open season subscription. Allowance of enhancements to regulated rates of return on transmission investment is needed to better reflect the risk and the benefit associated with expanded interstate trade. FERC has a limited time ruling on this that might be of more help if extended. States should consider adoption of a resolution to support plans that would provide regional benefits beyond immediate state boundaries and should extend their definition of "beneficiaries" to include the regional market at large. Steps should be taken to encourage a forward-looking and region-wide planning process in place of current efforts at after-the-fact coordination.

Several possibilities exist to provide market participants with the necessary incentive and cost recovery assurance to make the required transmission investments. Socialization, or a spreading of the costs across all users of the system, is one method. This approach assumes that upgrades to the system benefit all users by reducing congestion and lowering the cost to transmit power. FERC commissioner Pat Wood recently endorsed this method in a written opinion that he said he hoped would become FERC’s generation interconnection policy. In the document, Wood stated his belief that transmission-related upgrades should be funded by the transmission service provider and promptly recovered through transmission rates from all end-use customers by state and federal regulators. Barriers to this approach exist today since multiple parties own the system and no method currently exists to recover costs from all beneficiaries. Furthermore, multiple ownership of the system, including federal, state, municipal and private investors, cuts across both state and federal jurisdictions.

One way to spread transmission upgrade costs and collect payments is through an RTO uplift charge (a fixed fee assessed to all users of transmission). RTOs are not currently in place and therefore unable to make the needed commitments now. To bridge the gap, FERC may consider some form of guarantee or other incentive for builders to take the risk prior to the assurance of a revenue stream from an RTO.

Merchant financing is another approach that would provide incentive for transmission construction by allowing builders to collect "congestion rents" for a designated period of time. In addition to the wheeling revenue associated with the new line, builders would receive a portion of the avoided congestion costs resulting from the upgrade. This would compensate the builder for risk associated with new construction and help promote needed investment. Unfortunately, the majority of entities that could engage in market-priced transmission projects are vertically integrated utilities and are prohibited from charging market-based rates.

A third method to adequately compensate builders is implementation of an "open season" approach similar to that practiced in the natural gas industry. Under this scenario potential transmission investors conduct an open season to solicit bids from parties interested in utilizing additional capacity and paying for it . This ensures builders adequate revenue to secure financing for the upgrade, significantly reducing the risk. In today’s increasingly short-term market however, commitments are not available to justify an investment with a long-term recovery. This forces investors to take on the merchant risk in the out years with only a regulated return. Under these conditions, investors will not build major inter-regional transmission.

The siting of regional transmission lines by definition creates jurisdictional problems. These projects cross multiple states and or provinces. They also cross federal and state public lands and, in many parts of the West, tribal lands. If a line crosses the international boundary, an export permit is needed. Each state has a different siting process, each federal agency has its own process, there are varied degrees of cooperation between the states, between state and federal permitting agencies, and cooperation with the tribal interests add another layer of complexity to an already complex situation.

Options for fixing the problem range from cooperation to federal preemption. Regardless of how the multistate process is handled, each state should look at its own siting and permitting process and ask itself if its process is efficient, can be streamlined or will actually work in a competitive markets. Many states have not updated their siting processes to address the fundamental changes that have occurred in the electricity industry.

Informal Joint Process -- States would informally get together with each other and the federal government and develop a common process. Such a process could include common application requirements and timelines, joint interagency hearings and reviews, agreement on the types of reasonable alternatives that need to be reviewed and informal agreement on key factors that will decide the application. All states and federal agencies would use one record of decision for each project. The option has the advantage of voluntary cooperation among states and between states and the federal government. However, in spite of this advantage, should one state or federal agency opt out, then the entire cooperative effort would fall apart.

Formal Interstate Process --States could formally agree to a multistate process that could also include federal agencies. Such a formal agreement would have to come from a multistate compact, which is a very cumbersome tool. It is cumbersome in that Congress must first approve the compact and allow the states to form it, then each state must separately approve its joining the compact. Such a formal process is cumbersome, but it could provide for one multistate agency to do the work, create a record of decision and create the standard of review and decisions for these facilities. There are real advantages to the one-stop feature of this proposal. It is possible that the Western Interstate Energy Compact, that created the Western Interstate Energy Board could be modified to create some type of regional enterprise that accomplishes what the states need, without the effort of a new interstate compact. This option would not address state and federal permitting issues.

Federal Siting Authority -- The President’s National Energy Strategy and several members of Congress are talking about drafting legislation to give FERC jurisdiction over siting and permitting of multistate electricity transmission lines, similar to what FERC has with multistate gas transmission lines. These proposals also give FERC the power of eminent domain for such lines. Such a proposal creates one responsible agency for siting these lines and allow for cooperative efforts with states, but take the states completely out of the decision making process. These proposals do not address Canadian or Mexican issues. The Western Governors are not supportive of such proposals.

Recommendation -- Should the states fail to act, the Administration and Congress are poised to give the authority to the Federal government. The Governors should look at either pursuing a multistate siting compact among the states or working within the WIEB agreement to develop a regional siting mechanism.

Each transmission project selected will affect the economic development and environmental resources of each state differently. Therefore, it is appropriate that due consideration be given to how the set of projects identified in aggregate affect the economic development opportunities and use the environmental resources of each of the states.

New transmission projects can affect the economic development of communities, particularly rural communities, and thus the development of projects should be sensitive to local concerns. While new transmission projects are identified to address reliability concerns and to facilitate the transmission of electricity to regions of relative resource scarcity from those of relative resource abundance, the new projects also affect the dynamics of further resource development. As new transmission projects are built and become a part of the existing transmission infrastructure, the cost of developing additional generation projects is affected. Those locations that are proximate to the new transmission lines immediately become more cost-effective locations for building new generation facilities. Similarly, the cost of further expanding transmission to accommodate additional generation may be reduced by the construction of a new line. These considerations may be especially important in developing renewable resources since the best wind and geothermal resources are located in rural counties. In summary, the construction of new transmission lines will affect the cost of siting additional generation and transmission projects in specific locations and thus will affect the economic development of those locations.

Air quality and water availability vary dramatically among the western states, as well as among regions within the states. Just as resource diversity in power production is important for price stability and energy security, regional diversity in production is important for environmental resource balance. Those regions with poor air quality or scarce water supply may be unable to sustain additional electric generation without serious environmental consequences. Those regions with good air quality and abundant water supply may be able to accommodate additional electric generation while protecting the environmental quality of their region. Improving environmental quality and producing more energy are often presented as inconsistent goals but they need not be. Improved regional diversity in electricity production, replacement of older, dirtier plants with newer efficient plants, and the development of renewable energy resources can each contribute to a regional solution that increases environmental quality and increases the supply of energy. Selecting a set of transmission projects that in aggregate allow for environmental resource balance is thus a desirable goal.

In a restructured world, where deregulation of one sort or another has been done or is under contemplation, there are a variety of new ambiguities introduced into the planning process. In the old regulated world, the concept of obligation to serve drove all decisions. New investments or even mere alteration of existing systems were evaluated based on how they served the needs of clearly-defined groups of utility customers.

In the current world it is much more difficult to answer the question, who does a proposed transmission improvement serve? We no longer can clearly test whether service is improved for certain customers and are left with more perplexing questions. Is this improvement for the benefit of customers, or is it for the convenience of new entrants into the electricity business, be they generators or marketers? Do these new entrants really need public assistance in meeting their business needs, or should they pay their own way? Is the purpose of any proposed transmission upgrade really to offer benefit to the broad range of the general public?

Transmission is only a means of getting electric power from where it is generated to where it is ultimately used. And transmission still comprises only a small fraction of the delivered price of electricity to customers, whether at wholesale or retail. Guiding any transmission policy must be the realization that it is the needs of electricity customers, not those of transmission providers or even those of generation companies, that should drive the process of reconfiguring the Western electricity grid to better serve future generations. On the other hand, one can develop all available resources guided by the vision of a competitive market but a robust transmission highway is still needed. The fact that transmission is only a fraction of the cost cannot override the fact that it is still fundamental to the success of the market and the continuity of service to the customer. This is what makes transmission a high priority concern of the Governors .

Now in the wake of disastrous restructuring, we know firsthand how tenuous is that faith in the operations of the market, at least in the early stages of the transition from a fully regulated electricity market to one based more nearly on free market principles. It is quite important to explicitly consider some of these policy rather than assume that they will be taken care of by the operations of markets themselves.

· December 20, 2000. Denver Energy Summit. WAG met in Denver to develop a plan of action for WGA to take in 2001 on western energy issues. The governors agreed to hold their Energy Roundtable early in the year, open the meeting to a broad representation of energy interests and invite the new Administration to present its position.

· February 2, 2001. Portland Energy Roundtable. WGA heard from industry, tribes, environmentalists, energy experts, consumers and government officials on the issues to be addressed and potential solutions. At that time, new generation and transmission merged as two factors that needed attention to secure future energy supplies. WGA agreed to a set of "Recommended Actions for Addressing Immediate Electricity Problems in the West" and "Actions to Address Long-term Energy Needs."

· May 9, 2001. Salt Lake City Transmission Meeting. WGA met to better understand and discuss the transmission infrastructure problems in the West and set up a Transmission Working Group (TWG) to be headed by Jack Davis, Pinnacle West Corporation, and Marsha Smith, Idaho Public Utilities Commission, to explore what transmission enhancements are needed, as well as how they can be financed and expeditiously permitted.

· May 24, 2001. Phoenix Meeting of TWG. A modeling group agreed to use technical modeling to assess where bottlenecks might occur on the grid and to help identify priority areas for new transmission capabilities. Several scenarios were run to assess the location of transmission constraints under a variety of expected price and input conditions.

· June 6, 2001. San Francisco Meeting of TWG. Approximately 30 individuals representing a variety of energy sectors and government officials met to discuss the modeling process and the inputs, and offered adjustments as necessary. Three working groups were assigned to begin drafting the policies, refine the model inputs and assemble the final report.

· June 29, 2001. Portland Meeting of TWG. The TWG met to review and begin integration of the results of the smaller groups. The model results were presented and draft policies discussed. The TWG then made final recommendations for the Governors consideration.

The reality of the western electric power system has inextricably linked the energy futures of western states. Extraordinary wholesale electricity prices in the western wholesale power market have spawned much-needed power plant construction for the first time in a decade. However, these plants will not come on-line soon enough to mitigate the high prices and shortages in parts of the West.

Governors across the West have already called for and implemented conservation measures. However, we also believe the additional steps listed below should be considered.

1. Encourage California and power generators to enter into power supply contracts to reduce dependence on the spot electricity market. Long-term power contracts will reduce reliance on the volatile wholesale spot market and stabilize prices to consumers. Non-California utilities and direct end-use customers that rely extensively on the spot market should also reexamine their power purchase practices in order to appropriately hedge themselves against future price spikes.

2. Request utilities and state and tribal public utility commissions to adopt rate reforms that send more accurate price signals (or a proxy for such price signals ) to consumers. This is the first step in empowering customers to make wise decisions about their energy use and to make investments that reduce their total use and cost. This means developing and deploying technologies that allow building owners and other consumers to receive more accurate price signals that encourage them to reduce or shift consumption to off-peak times.

3. Ask Vice President Cheney and the federal inter-agency task force to accept as part of its mission to work with the Western Governors and tribal leaders to streamline regulatory processes to enable retired generation to be reactivated, existing generation to increase production, and new generation and natural gas and electricity transmission to come on line while protecting public health, safety and the environment. States, tribes and federal regulatory agencies need to expedite the review of any permits required to bring retired generation on line. They also need to expeditiously develop a plan that would allow existing back-up generation to come on-line without violating human health and environmental standards.

4. Ask state and tribal public utility commissions and all non-jurisdictional utilities to approve demand-exchange tariffs under which customers can voluntarily agree to reduce demand in exchange for compensation. A number of utilities have demand exchange programs underway and more utilities need to implement them. For example, Portland General Electric allows customers to voluntarily shed their load. The power can then be sold in the high price wholesale market. The profits from the sale of power are shared between the customer (90%) and utility (10%).

5. Ask state and tribal public utility commissions and non-jurisdictional utilities to eliminate barriers to clean distributed generation that can be in place in the next 12-24 months. Distributed generation includes small turbines (e.g., less than 5 MW), high efficiency co-generation, fuels cells, etc. that are typically installed on the consumer’s property, a practice sometimes referred to as net metering. Utilities have frequently blocked the installation of such technologies through cumbersome business practices or complex and inconsistent requirements for connecting such generation to the transmission grid. Requirements to ensure safety and reliability of the grid should remain in place.

6. Ask utility distribution companies and state and tribal energy agencies to develop energy efficiency measures that provide savings beginning within the next six months through technical assistance, financial incentives, accelerated penetration of new technologies, and appropriate regulation. Ask PUCs, state legislatures and tribal councils to take steps necessary to encourage funding of such measures (e.g., including utility costs in rates, adopting system benefit charges which are a non-bypassable fee on each kilowatthour sold).

7. Where states and tribes have not already acted, direct state and tribal agencies to accelerate the implementation of efficiency practices and investments in state and tribal buildings and ask the federal government and local government to take similar action.

8. Ask Congress, state legislatures and tribal councils to expand assistance to low income families and families and individuals with fixed incomes to help pay high energy bills.

9. Enact federal legislation consistent with WGA resolution 00-009 that would: enable the establishment of enforceable system reliability rules; provide for delegation and deference to the West; and enable the creation of regional advisory bodies of states and provinces.

10. Encourage WGA to seek the creation of a centralized grid-wide database that tracks prospective demand, and tracks generation and transmission facilities under construction, that are permitted, in the permitting process, or under consideration.

11. Support efforts to ensure the availability of information on loads, transmission, and generation where necessary for ensuring the adequacy, efficiency and reliability of the grid.

12. Continue to implement the region’s short-term conservation strategy adopted January 10.

13. Conduct a regional assessment of whether and how gas supplies and its transmission can be increased in time to meet summer peak load demand.

To maintain the Western Governors’ commitment to a healthy and viable economy in the West we need to pursue a national energy policy that will result in (1) abundant and diverse energy resources available to consumers and (2) more efficient use of energy. All of the West’s energy supply and demand options should be pursued.

1. At a minimum, supply-side policies should address:

Permitting Energy Facilities -- Streamline state, tribal and federal processes for siting new generation, electric transmission and natural gas pipelines while protecting public health, safety and the environment.

Coal -- Implement R&D and tax incentives to promote the development and deployment of new technologies to increase the efficiency and lower the emissions from coal-based generation.

Renewables -- Accelerate the development and deployment of promising renewable energy technologies through the extension and expansion of state and federal production tax credits and state and tribal policies such as system benefit charges, portfolio standards, renewable resource-based utility tariffs, and/or creative new incentives.

New energy development – Enable exploration and development of promising domestic oil, gas, coal, geothermal or wind resources where lands, air, water, fish and wildlife, and other environmental resources can be protected.

Environmental Regulation – Review environmental and natural resource policies to ensure they are as efficient as possible. These policies include the air quality regulations for health and regional haze. See WGA resolutions 99-013 Principles for Environmental Management in the West and 99-012, Air Quality Reform and Flexibility - Western Air Quality Initiative; and 00-015, Regional Haze. These policies advocate collaboration, flexibility to achieve compliance, and implementation of economic incentives. Credit trading programs are preferred over command-and-control approaches.

Energy Infrastructure – Support economic and environmentally sound energy infrastructure investments to transport energy to markets. Urge (1) construction of a pipeline to move natural gas from Prudhoe Bay along the Alaska Highway to the lower 48 states, (2) the expansion of natural gas pipeline systems in the lower 48 states, and (3) the expansion of electrical transmission capacity from areas rich in energy resources to load centers. Encourage a stable economic environment conducive to construction of needed electrical generation. Convene a workgroup of major transmission system owners to identify where bottlenecks occur and to recommend needed new transmission facilities.

2. At a minimum, demand-side policies :

Encourage rate structures that give utilities an incentive to reduce consumption.

Encourage long-term stability of government and utility conservation programs.

Accelerate the development and deployment of new, more energy efficient products in the market place. These activities accelerate the penetration of new technologies into the market place. Such efforts are best implemented at the state, tribal and regional level often with the assistance of the federal government.

Review and improve the energy efficiency of building codes in Western states and tribal lands.

Accelerate the development of federal government appliance efficiency standards that are cost-effective standards and recognize the unique conditions in the West (e.g., dry climates).

Support of federal R&D that maximizes the development of energy efficiency technologies applicable to the growing Western region.

Support of federal, state and tribal tax incentives to accelerate the introduction of new energy efficient technologies.

Page last updated 10/10/1999