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Transmission Working Group Report
to the
Comprehensive Regional Review Steering Committee

July 11, 1996


TABLE OF CONTENTS


1. Overview and Recommendations

The issues that surround the potential changes in the region's transmission system are complex and at times controversial. For this reason, it was not possible to obtain unanimous agreement to the recommendations included in this report. The Working Group is assembling a Progress Report that provides more detail than this report to the Steering Committee.

The Steering Committee said, in its charge to this Working Group, "that while the transmission system will need to be at least administratively separated from generation, a greater degree of separation was likely to be necessary." The Steering Committee also identified an Independent Grid Operator (IGO) as a way of accomplishing this greater degree of separation. The Steering Committee asked the Working Group to address the degree of control that should be given to the IGO.

For the purposes of evaluating transmission restructuring, the Working Group considered the region of interest to be the U.S. portion the Northwest Power Pool (NWPP) which encompasses the systems of Bonneville, seven investor-owned utilities (IOUs) and additional non-federal, publicly owned facilities in seven states. The current regional transmission system costs approximately $1.3 billion per year, including costs of the Southern and Eastern interties.

Based on our analysis and evaluation of transmission alternatives the majority of the Working Group supports the following recommendations:

  1. The Regional Review should support the formation of an Independent Grid Operator (IGO).
  2. Ideally a regional IGO should include Bonneville's system, the largest block of the transmission assets in the region. Without legislation to separate, BPA's analysis indicates that their transmission business cannot be included in a regional IGO. Therefore, a majority of the Working Group members recommend that BPA's transmission function should be legislatively separated from power marketing. The Working Group recognizes that issues related to existing obligations to public purposes and outstanding third party debt must be resolved.
  3. Legal separation of Bonneville's transmission must provide for FERC regulation equivalent to that which FERC applies to IOU transmission.
  4. The development of a regional IGO does not require the formation of a mandatory power pool although voluntary pools may form.
  5. A wires charge could interfere with efficient operation and expansion of the transmission system, and potentially produce uneconomic generation decisions. In addition, the Working Group found that if a wires charge was applied to BPA's system alone there are significant opportunities for customers to bypass BPA and avoid the charge. If a wires charge is imposed, it most predictably will recover anticipated revenues and will disrupt efficient price signals least if it is imposed on fixed elements of the transmission price. Decision makers should consider all options (wires charge, distribution charge, power marketing, state and local taxing authority etc.) to fund public purposes and legal obligations and select those that meet criteria of fairness, predictability, efficiency, and ease of implementation (including existing legal authority).
  6. A regional IGO must honor existing transmission contracts and prevent major cost shifts among customers during a reasonable transition period.


2. The Opportunity

Transmission is the highway system that allows competition and commerce in bulk electric power commodities. FERC policy, as embodied in Order 888 and Order 889, recognizes the critical importance of independent transmission operations to encourage competition in the provision of generation and generation related services. For an efficient competitive generation market, control of major transmission facilities should be independent of the interests of both power suppliers and consumers. Independent transmission operations will result in more efficient power markets providing potential benefits for customers from reduced bulk power costs. For example, for each 1 mill/kWh reduction in average power prices in the Northwest, customers will save more than $160 million per year.

The current multi-owner transmission system tends to impede the full development of competitive bulk power markets because, under current arrangements, transactions that cross several utility systems must negotiate multiple transmission contracts. The multiple terms, conditions and prices for passing through each transmission system is called pancaking Footnote1. Pancaking can significantly increase transaction and transmission costs, limiting the scope of the bulk power market and raising the cost of delivered power.

FERC's policies are currently forcing transmitting utilities to operate their transmission systems as nondiscriminatory common carriers that provide open access under tariffs whose terms, conditions and prices that are "comparable" to what they provide themselves. However, the accomplishment of these principles will require FERC to closely monitor the activities of vertically integrated transmission owners to ensure that no unfair advantage is gained from transmission ownership. Disputes between transmission owners, buyers and sellers will require continual dispute resolution by NRTA and regulation by FERC to ensure that transmission owners are not exercising transmission market power. The current FERC policies mandating "administrative separation" appear to be the first step in what may ultimately result in either independent grid operators or divestiture. Several of the region's investor-owned utilities are currently planning the formation of an IGO, to gain additional separation between transmission and power marketing functions.

In addition to the benefits of a competitive generation market, an IGO offers the potential for more efficient operation and expansion of the transmission system. Potential efficiency gains include:

  1. Fuller utilization of the physical transfer capability of the system
  2. Reduction of pancaking of transmission rates
  3. Coordinated expansion planning and the development of least cost alternatives to remove bottlenecks
  4. More accurate and easily-available posting of available transmission capacity
  5. More efficient operations and maintenance
  6. Uniformity of regulatory policy and oversight


3. Base Case

This case assumes that the region's utilities do not form an IGO, but must respond to regulatory changes already underway at FERC. Under this alternative regional IOUs are required to comply with the dictates of FERC Orders 888 and 889. FERC has broad authority over BPA's transmission terms, conditions and rates, and BPA has said that it will comply with Orders 888 and 889 to the extent consistent with law. Under FERC's reciprocity conditions, other regional utilities may choose to follow FERC's orders but they are not required to subject themselves to full FERC oversight. The Northwest Regional Transmission Association (NRTA) would continue to develop mediation and dispute resolution mechanisms with the hope that transmission disputes could be resolved within the region without having to appeal to FERC.

The FERC will closely monitor transmitters' compliance with the standard of conduct. However, even with FERC enforcement, lingering doubt will remain with customers about the behavior of the transmitters which will lead to very costly enforcement activities for the transmitter, the customer and the regulator. Transmission service issues will continue to result in disputes that NRTA or FERC would have to resolve.

For Bonneville, administrative separation will not excuse the Administrator from the statutory responsibility to use all of his/her authorities to meet all of the agency's financial obligations. Transmission and power marketing revenues will continue to be commingled in the Bonneville fund, although BPA separately accounts for transmission revenues and costs. For both IOUs and BPA it will be impossible to prevent the strategic direction of the company or agency from permeating the operation of both transmission and power marketing.

Transmission compensation to IOUs would be obtained through FERC approval of transmission tariffs. BPA would continue to establish transmission compensation under the 7(i) administrative process and expects to seek FERC review and approval under §212(i). Numerous alternative rate designs could be developed and used by the current transmission owners. Transmission tariffs for non-jurisdictional utilities will not be reviewed by FERC unless the utility seeks a FERC determination to establish reciprocity. The benefits of increased transmission coordination and reduced transaction costs will be difficult to achieve due to continued pancaking of transmission system tariffs.

In the base case, the current ownership and operational control of existing and new transmission facilities would continue. Current transmission owners will only agree to coordinate operations, planning and maintenance to the extent they provide benefits to each individual company or agency. It may be possible to design a single regional transmission tariff but actual implementation would be difficult given the wide differences that exist between the interests of the current owners. Rate pancaking would likely continue.


4. Independent Grid Operator (IGO)

The formation of a region-wide Independent Grid Operator is the alternative preferred by most members of the Working Group because it resolves some of the continuing problems of the Base Case, and provides a structure for transmission operations that is completely independent of competitive power market interests. Initially, utilities would retain ownership of their transmission facilities and only through voluntary choices by individual utilities would they choose to join the IGO. The IGO would operate transmission facilities owned by others under long term contractual relationships. The IGO would provide transmission and backstop ancillary services, for all loads and generators within its area of operations, but individual utilities could maintain control areas within the IGO's network. The IGO would also have the capability to build and/or own transmission facilities. By having the option to own transmission facilities, the IGO can remove bottlenecks which might not otherwise be removed. The IGO would be regulated by FERC to ensure that it provided fair, just, and reasonable transmission services and that only necessary transmission facilities could be included in its rates. This alternative was called the IGO-O alternative in the PNUCC Phase I report. The Working Group designed this proposal for a regional IGO to be consistent with the following principles:

  1. The IGO cannot be controlled by any individual market participant or any one class of participants engaged in the buying and selling of electric energy or services.
  2. Neither the IGO nor its employees can have a financial interest in any market participants.
  3. The IGO would follow reliability criteria consistent with procedures and policies of NERC, WSCC, NRTA and the NW Power Pool, while encompassing appropriate environmental and public interest goals.
  4. The IGO would own no generation but would procure backstop ancillary services in a non-discriminatory open bid available to all market participants.
  5. Intermittent, as-available and distributed generation shall be treated fairly in buying and selling necessary ancillary services and provision of transmission services.
  6. Transmission planning will follow long term least-cost planning principles.
  7. The IGO shall follow independent alternative dispute resolution procedures conforming to commercial arbitration protocols.
  8. Regulation and governance should provide incentives for efficient management, administration, use of facilities and an appropriate level of system reliability.
  9. The IGO allows free flow of information to support informed customer choice among power supply alternatives.


4.1. System upgrades

The IGO would plan and provide information for the region about transmission needs and the costs and benefits of alternatives. The IGO would also solicit proposals and analysis from users, other transmission owners, generation suppliers, end users (load management) and others for cost-effective alternatives to transmission development.

When available transmission capacity limits marketing opportunities, the IGO is expected to implement some form of congestion pricing. This pricing information will allow users of the system affected by a constrained transmission path to determine when it is in their economic interest to take action to relieve or remove a transmission constraint. The decision to build new transmission, or to correct a problem with a non-transmission solution, would be made jointly by the IGO, affected users, transmission owners, generation suppliers, or end use customers (DSM or conservation). Decisions by these parties would be based upon their individual analysis of the costs and benefits of alternative actions.

The IGO would monitor the reliability of the present and planned transmission system with respect to NERC, WSCC, NWPP and other applicable reliability criteria. When transmission reliability falls below prescribed levels, the IGO would be responsible for implementation of an appropriate response. When the IGO identifies a long-run, persistent transmission reliability problem, it would evaluate the degree of risk involved and whether the problem is worth fixing. If it is, the IGO would evaluate a full range of alternative solutions.

Some alternatives (e.g. congestion pricing, remedial action schemes, construction of new transmission) could be implemented by the IGO. Others (local generation, DSM) would require action by other parties. The IGO would use the tools at its disposal to ensure the lowest cost solution is implemented. If the best solution requires action by others, and IGO pricing and persuasion cannot evoke this action, the IGO would implement the most cost effective action within its transmission related authorities. The IGO would own the new facilities it has constructed and repayment of these facilities would be included in the IGO's pricing. Through this process, the IGO would assure the availability and reliability of the region's transmission system.


4.2. System operations

An Operations Subgroup was formed to examine alternative system operations for an IGO in the Northwest. The members of the subgroup preferred two operations concepts. A key difference between the two operational concepts is in their approach to achieving economic efficiency for the region's transmission and control functions.

One concept is an IGO with a single control area for the region. In this concept the IGO will manage the transmission system operations and also provide control area services for the region. Control area services include reactive supply, load regulation, frequency control, operating reserves, and automatic generation control (AGC). In prescribing requirements for transmission service, FERC has identified these services as ancillary services.

Under the single control area IGO concept, all control area services and ancillary services for transmission could be obtained from the IGO at FERC approved tariff rates. The IGO would not directly own the generating resources needed to provide load regulation, frequency control, AGC, and operating reserves but, would acquire these resources in amounts sufficient for its requirements through an open bidding process.

In the second concept, the region's multiple control areas and the IGO would manage the system control for the region as peers with the IGO managing a control area for its transmission. These other control areas would manage their loads as they do currently or as they choose to in the future. Those transmission ancillary services which the user (according to FERC) is not required to obtain from the IGO, may be obtained from the IGO or any qualifying provider.

The improvements on the current information systems to garner the "big picture" for meeting and implementing the industry's system security provisions can be accomplished under either of the two operations concepts.

To assure that the benefits from the changing electric utility industry are captured without sacrificing the reliability and control qualities of the northwest electric systems, the following principles are advanced to guide the development of operations under the IGO:

  1. Any changes in control area responsibilities should be voluntary and evolutionary, demonstrate increased economic benefits for the region's electric utilities, their customers and individual participants in the market while retaining or improving the reliability of the system.
  2. A reasonable set of alternatives should be considered.
  3. Changes in control area responsibilities should enhance open and non-discriminatory transmission access and promote competition in bulk power and ancillary services markets.


4.3. Facilities under the IGO's control

The IGO would need to control the major portions of the regional transmission grid. The specific facilities that are included in the grid would have to be negotiated between the IGO and the current owners. In order to free transmission owners from the obligation to respond to requests for transmission service under §211 of the Federal Power Act, the IGO would need to control facilities to the point at which service is requested.

Most of the region's rural utilities take delivery of a portion or all of their power requirements at sub-transmission voltages over facilities that they don't own. How the regional transmission grid is ultimately defined for the purposes of IGO control, pricing for use of facilities, and terms and conditions of access will have a direct bearing on these utilities' ability to provide the benefits of a competitive power market to their customers. This issue can be addressed through IGO pricing schemes, reasonable transition period policies and the development of options for utilities to gain control over delivery facilities.


4.4. Pricing of services

The Northwest Regional Transmission Association (NRTA) formed a tariff work group, in October, 1995 and has made significant progress toward fleshing out a pricing approach. However, concerns about cost-shifting remain. The work group believes that it will be possible to accommodate these concerns without giving up the pricing features that provide efficient incentives for use and development of the transmission system.

Transmission pricing takes on increased importance as FERC policy drives the industry toward a "common carrier" status involving more parties and more market-based transactions. Services previously transacted within and between vertically-integrated utilities will now be priced in an open but regulated market. Most members of the work group have concerns that "pancaking" and high transactions cost of the current pricing system cannot be supported in the future.

The NRTA work group assumed that an IGO would be administering a pricing system that would address the following issues:

Congestion in the Short Term. Currently, it appears that significant congestion in the Northwest transmission system is infrequent. However, as loads grow and more generation is sited and more through-region transactions occur, congestion could become more significant. The work group examined a number of proposed mechanisms for congestion pricing that would provide the correct incentives to transmission users. It concluded that congestion pricing over paths between a limited number of zones, rather than over all possible paths, should be sufficient to get most of the benefits of congestion pricing. The pricing mechanisms considered (operator redispatch, multilateral contracts among users and tradable capacity rights) are documented in some detail in the Working Group's progress report. These mechanisms have features that are significantly different, but it appears that they all could give appropriate incentives to users to relieve congestion.

Investment in Relieving Congestion and System Expansion. The work group examined pricing mechanisms that would provide proper incentives for investment to relieve congestion, which might involve transmission facilities or off-network alternatives such as relocated generation or demand side management . The work group is continuing to analyze transmission congestion contracts, rights to expanded capacity and "impacted MW-Mile" pricing as candidate pricing mechanisms. System expansion investment that cannot be assigned to specific transactions may have to be undertaken by the IGO with costs rolled into the existing system.

Collection of Embedded Cost. Embedded costs of the existing system will be responsible for a large (probably over 95 percent) part of transmission users' total transmission bills. The work group has discussed a variety of alternatives for recovering embedded costs. These alternatives can significantly affect both the efficiency of use of the transmission system and the distribution of total costs among transmission users. It has not been possible at this time to estimate the effects of pricing alternatives on representative types of transmission users.

Cost Shifting. It will be impossible to predict all the shifts in costs that will result from coming changes in the organization and operation of the transmission system, including its pricing. It should be possible, however, by estimation of impacts and tuning access charges, to develop some assurance that the shifts will not be severe. There is a recognition that transition strategies, such as phased-in changes, are likely to be necessary to mitigate unacceptable cost shifting.


4.5. IGO Governance

The Working Group identified four alternative governance structures that could be used to form a regional IGO. A more complete discussion of these alternatives will be included in the Progress Report. At this point, there are attractive aspects to all four models and the selection of the "best" governance structure is dependent on other decisions, such as the role that BPA's transmission will play in the formation of a regional IGO. BPA's legal analysis indicates that it will not be able to join an IGO or to allow an IGO to operate its transmission system without additional legislation. In addition, the issues surrounding the security and tax exempt status of third party debt that BPA financially backs may require a continued federal role in the operation of BPA's transmission. All of these governance structures are assumed to have FERC regulatory oversight as required in Order 888.

Federal IGO (FIGO). The IGO could be structured around a federal corporation following a legislative separation of BPA into a transmission agency and a power marketing agency. A FIGO would require legislation to establish a new federal corporation to own the federal transmission system and either become the IGO or join an IGO formed by others. The FIGO would be governed by a Board of Directors appointed by the President and confirmed by the Senate. It may be possible to define the type of individuals that should be selected for the Board or insure that nominations come from the region, but the ultimate authority must remain with the President with Congressional oversight.

Further analysis is necessary to determine the effects on net billed project participants and obligations to third party financing. It can be argued the formation of a FIGO could be structured to not affect the security for the payment of the net billed project bonds.

FERC's regulatory authority would be less than for other FERC jurisdictional utilities. FERC would need to take into account the FIGO's budgetary and repayment responsibilities as self-financing government agency. FERC could not disallow costs that would be disallowed for a public utility, and FERC could not order the construction of facilities if Congress or the Administration disagreed.

Mixed Federal/Private (Bonneville Transmission Corporation, or BTC). The Mixed Corporation (BTC) would initially be a wholly-owned government corporation to operate the federal transmission system. The BTC would have the authority to acquire or to operate under long term operating agreements the facilities currently owned and operated by other transmission owners. The BTC could operate these facilities along with the federal facilities as an integrated transmission grid. As distinct from the FIGO model, the federal legislation establishing the BTC could allow equity shares to be sold in public offering by the federal government.

BTC would be governed by a Board of Directors elected by the stockholders or appointed by the President if stock is held by the federal government. Directors would be required to follow strict conflict of interest requirements that precluded them from any interest in the competitive energy marketplace.

Further analysis is necessary to determine whether net billed project participants could take credits on BTC transmission bills to offset net billing payments and whether the security and tax exempt status of third party debt could be preserved.

Cooperative IGO. The IGO could be governed by a cooperative made up of transmission system users. Eligible members could also consist of state utility regulatory commissions, or state agencies with rate-making authority over transmission, and any other appropriate entities. The cooperative members that are users would have an incentive to keep rates as low as possible, but they could also have inconsistent individual financial objectives. The cooperative would have access to capital markets and would have the ability to use retained margins for capital investments. Governance is usually by a board elected by the members, with voting rules to prevent a member or class of members from controlling outcomes. There are concerns that a cooperative structure may present anti-trust problems for both transmission owners and users, but additional legal work is needed.

For-Profit Corporation. A private for-profit corporation would be chartered under state law. Capital would be raised by sale of stocks and bonds. Stock could not be held by any owner of power marketing or brokering businesses using the transmission system. It might be necessary to provide initial capital to allow the IGO to accept the financial risks of operating transmission that is owned by others. The IGO would be governed by a board of directors. Board members would have to follow strict conflict of interest restrictions that required complete independence from any generation or distribution system owners or from any other system users which take services from the IGO. Board members would be elected by the shareholders of the corporation.


4.6. Consistency with State Energy & Regulatory Policies

There are numerous transition issues in the formation of a regional IGO. While recognizing the exclusive federal jurisdiction over transmission and state jurisdiction over distribution, it would not be appropriate or acceptable to the current transmission owners to establish an IGO that would solely become a mechanism for avoiding state energy law and regulatory requirements. A regional IGO would need to acknowledge and follow the applicable public policies in each state where they operate transmission.


5. Independent Grid Scheduler (IGS)

The Public Generating Pool (PGP) members proposed the following as an alternative to moving directly toward an IGO. The PGP describes their proposal as follows and continues its development. The IGS would constitute incremental change in the direction of open and non-discriminatory access without the degree of centralization associated with a regional IGO. The IGS can be formed without the kind of legislative changes required for an IGO that includes BPA. . Further steps away from the status quo may prove necessary, but should also be taken on an incremental basis. This alternative should be easier to establish than a regional IGO that requires significant statutory changes; thus, the IGS could be put into place sooner than a regional IGO.

All transmission owners, including BPA, could voluntarily join the IGS. Current transmission owners would retain ownership of their facilities and the IGS would initially not have the capability of constructing and owning transmission facilities. The IGS would be governed by a Board of transmission users in the region. Initial discussion of the governance structure should focus on a class system similar to that of NRTA.

The IGS would accept transmission schedules from all users, including BPA's power marketing function, on an equal basis, based on Available Transmission Capacity (ATC) as submitted by transmission owners. The IGS Board would oversee the application of the ATC method by transmission owners. The IGS would accept transmission schedules within ATC as defined by existing and future transmission and power contracts. Resolution of ATC disputes would take place outside the IGS, perhaps within NRTA.

NRTA would perform the function of operational and expansion planning. The IGS would not finance or build any facilities itself. The operational functions of the IGS would include the following: operating an OASIS; scheduling transmission use; managing transmission system constraints and transfer capability; providing a market for ancillary services through the OASIS; facilitating voluntary redistribution of generation or other actions to relieve constraints; and coordinating implementation of NERC security guidelines. Detailed policies for implementing these functions would be established by the IGS Board.

The IGS would provide accounting information on transmission use to individual transmission owners, in support of invoicing by the owners under FERC-approved tariffs. The Board would determine a method for recovering the costs of operating the IGS, with incentives for efficient operation of the IGS itself. BPA will not be the IGS, but will interact with the IGS as any other transmission owner or user.


6. Public Purposes and Legal Obligation Implications

The transmission work group pursued a two-pronged approach to this task. First, the group considered the overall effects of alternative structural and pricing changes on public purpose and legal obligations. Second, and more narrowly, the group examined the feasibility of a transmission wire charge to fund public purposes and legal obligations. The work group has the following recommendations, described in more detail in the full report. Other important public interest principles are described in the IGO section above.

  1. Legal separation of BPA transmission may require specific actions to ensure the security and tax exempt status of third party debt.
  2. Decision makers should consider all alternatives (wires charge, distribution charge, power marketing, etc.) to fund public purposes and legal obligations and select those that meet criteria of fairness, predictability, efficiency, and ease of implementation (including existing legal authority)
  3. A wires charge could interfere with efficient operation and expansion of the transmission system, and potentially produce uneconomic generation, resource transactions, operations and construction decisions
  4. If a wires charge is imposed, it most predictably will recover anticipated revenues and will disrupt efficient price signals least if it is imposed on fixed elements of the transmission price
  5. Considerable physical opportunity may exist or be developed in the future to bypass Bonneville's transmission system. Therefore, if a wires charge is imposed, it most predictably will recover anticipated revenues if it is imposed on all transmission, not just on Bonneville wires. But see below.
  6. FERC has exclusive jurisdiction over transmission rates of investor-owned utilities. Current FERC rules do not allow recovery of stranded power costs by a generally applicable transmission charge and FERC has not allowed recovery of stranded benefits in transmission rates. Therefore, some other mechanism or statutory changes might be needed if the region decides to pursue a wire charge for jurisdictional utilities.
  7. If a wires charge is imposed, the revenues to be recovered through such a charge or the amount of the charge should be established on a one-time basis, and not revised as a periodic fallback if other collection mechanisms fail. This protects the separation of transmission and other elements of the competitive power market.


7. Poolco - Mandatory Power Pools

The Working Group was asked to compare the effects of a mandatory pooled wholesale market to those of a market organized by bilateral contracts. The group discussed the issues, but the discussion was one-sided, since no one advocated the formation of a mandatory pool. Those who support pool arrangements elsewhere have asserted that pools have the advantages of greater price transparency, lower transactions costs, efficient dispatch of generating plants, and compatibility with coordinated management of the transmission system. Opposition to a mandatory pool cited the pool's possible abuses of monopoly power, the possible exercise by some generators of market power Footnote2, and the limiting effect of the pool on competition and incentives to increase efficiency and reduce costs.

The system operators concluded that system physics do not require a single pool operator in order to operate reliably and that an IGO could operate efficiently without mandatory pooling of all generation in the Northwest.

There was no objection in the Working Group to the formation of voluntary pools. The group explored the possibility that voluntary pools could develop in parallel with a market based on bilateral contracts.

Footnote1
"Pancaking" is a term applied to charging for transmission service by adding up the full embedded cost of each owner on a contract path, regardless of the actual incremental cost to the owners of providing service.

Footnote2
Market power, if it exists, could be exercised in either a pool or bilateral contract market. This problem deserves consideration regardless of the market organization we expect the region to take.


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