With its membership opened, NEPOOL sets a transmission tariff, but still must develop competitive markets. In 1993, after a series of attempts going back as far as 1971, the New England Power Pool failed to reach agreement among its members for a regional transmission arrangement. But destiny then took over (em with help from the newly enacted Energy Policy Act (em to lead pool members back to the bargaining table. Finally, on Sept. 30, 1996, NEPOOL announced that its executive committee had agreed in principle on restructuring the pool. The agreement provided for a regional transmission group and tariff, a New England independent system operator, and criteria for developing competitive markets for energy, capacity and ancillary services.

But that's just the beginning. The NEPOOL experiment must yet face its first test when it undergoes review at the Federal Energy Regulatory Commission. (See Docket Nos. 0A97-237-000, et al., filed Dec. 13, 1996.) Granted, the New England negotiators made a good-faith effort to meet all FERC requirements for open access, while taking into account the particular history of the region. But that effort could fall short of demands for quick development of an open market for bulk power, free from domination by traditional players.

Whatever the result of the FERC review, the New England system will remain a work in progress. Work will continue on developing the market. Pressure may build to simplify the transmission rules. But as this process continues, the new ISO may well prove to be the most important part of the package, exerting broad authority over the evolution of NEPOOL.

Opening Membership

Even before the FERC required open membership, NEPOOL had taken two steps to make restructuring more inclusive. First, it had redefined membership eligibility and swiftly grew from 90 to more than 140 participants, adding marketers and independent power producers. (See sidebar, "NEPOOL Evolution.") Second, the NEPOOL Review Committee became the coordinating forum for restructuring. Committee membership was opened to any interested party. Utilities and marketers could

participate. So could state governments and regulators. This commitment to open the process complicated and slowed negotiations, but allowed all sides to be heard.

Though absent from the negotiations, the FERC still influenced the debate, with its various proposals and rules on transmission access, and especially with its Nov. 13 decision on restructuring the Pennsylvania-New Jersey-Maryland Interconnection. (See, Atlantic City Elec. Co., et al., al., 77 FERC ¶61,148.) These and other orders were studied for guidance and argued over as if they were theological testaments. The parties always attempted to minimize differences with FERC policy, but NEPOOL presented some special circumstances that did not fit neatly with FERC formulas.

The Regional

Transmission Group

A regional transmission arrangement was essential to restructuring. In this case, a NEPOOL transmission tariff would constitute a regional transmission group, or RTG.

NEPOOL already was a free-flowing transmission system that did not require scheduling for internal transactions. The pool required that new generation connecting to the grid should not adversely affect existing generation and transmission. As a result, new transmission was added to maintain the free flow. All essential ancillary services were provided by NEPOOL, except for reactive demand, which was supplied locally.

Transmission access was problematic, however, even though some owners, notably Northeast Utilities and Central Maine Power, had built lines in excess of need and derived significant revenues from wheeling for others. Certain transmission customers faced high costs for access to competitive power supplies because of highly pancaked rates. Transmission from Connecticut to Maine could cross four systems.

Thus, the keystone of a New England RTG lay in regional pricing. In this case, the parties developed a two-tiered pricing regime.

Regional Network Service. At the regional level, a single, regional network service rate will cover all so-called "pool transmission facilities," or PTF (em essentially all nonradial facilities 69 kilovolts and higher. The RNS rate is a non-pancaked formula rate of about $15.61 per kilowatt-year, which provides access to all parts of the NEPOOL grid. However, each transmission provider is allowed to vary from the regional average by as much as 30 percent, reflecting differences in its costs from the average.

RNS includes all types of transmission: firm, nonfirm, network, point-to-point and ancillary services. All loads in the NEPOOL control area must pay the RNS rate or leave the control area. Because loads pay for transmission, all generation is on equal competitive footing. Eventually, all new PTF will be financed regionally, by load, at a single regional rate, even though certain owners of current facilities charge different RNS rates, which are grandfathered for a transitional period.

NEPOOL will distribute RNS revenues according to the PTF transmission revenue requirement of providers. Thus, when an average rate is used, subsidies will flow from the customers of some transmission providers to others.

Transactions through NEPOOL or out of the control area, pay the full regional-average RNS rate. Revenues are distributed to transmission providers on a megawatts-per-mile basis, in accordance with an agreed-upon transmission matrix for the region, which recognizes major parallel flows.

While RNS provides for simple, nondiscriminatory transmission pricing, it cannot deal with congestion. NEPOOL has promised FERC to have such a system by July 1, 1997. (See sidebar, "NEPOOL's Future.") The system would allow transmission capacity to be reserved, at an added cost, to reduce congestion-pricing. For transactions subject to congestion pricing, NEPOOL likely will determine cost based upon the market price of power used out of merit order (em i.e., lowest available cost.

Local Network Service. The second tier is called local network service, or LNS, and provides service on all transmission facilities not classified as PTF. (Distribution facilities may be subject to an additional charge.) Each local network sets its own rate, with its own LNS tariff. With the exception of a local point-to-point (LPTP) rate to connect generators to the PTF, all local service is provided on a network basis.

The LNS serves as the residual cost-recovery mechanism. All transmission costs not otherwise recovered, mainly through RNS, are recovered through LNS.

To avoid immediate cost shifting among the customers of the various transmission providers, NEPOOL provides for a transition period. During the first five years, the RNS rate gradually increases from $1 per kW-year (with the 30-percent bandwidth) to the full rate in the sixth year.

Initially, one-quarter of RNS revenues are distributed on a flow basis, gradually phasing to the full-revenue requirement basis. Certain tie-line owners receive compensation from all NEPOOL participants because the reserve requirements are reduced by the diversity benefits provided by interconnection with neighboring control areas. Existing transmission arrangements among the parties remain in effect and do not fall under the RTG.

Finally, there is a schedule of fixed transition payments among NEPOOL participants as a settlement method to insure, so far as possible, revenue neutrality from changes resulting from the RTG.

The parties were unable to agree to the second five-year period after initiation of the RTG. One alternative provides that existing transmission arrangements terminate and that the average RNS rate applies. The second alternative continues transmission arrangements until expiration, and phases down the bandwidth over the next five years. In either case, some tie-benefit payments to tie owners continue and are phased out. Most parties agree that they will accept either alternative and leave the choice to the FERC. This package, as other aspects of the NEPOOL restructuring, received more than the required 85-percent vote. The principal parties abstaining were Massachusetts municipal utilities and Enron.

Competing Tariffs. The Massachusetts Municipal Wholesale Electric Company filed a competing tariff to the NEPOOL tariff. Enron may argue for a direct and immediate application of the FERC open-access transmission tariff.

The MMWEC proposal rejects RTG status, but moves more rapidly toward the "end state" envisaged by the NEPOOL tariff. It provides for the use of the full RNS rate from the outset and no transition or tie-benefit payments. It also calls for point-to-point service, and leaves all current transmission contracts in place with termination left up to FERC. It clarifies that NEPOOL may own new transmission facilities. Thus, to a notable degree, it strips away some of the gains obtained by transmission owners in the NEPOOL negotiations.

Houlton Water Company, a Maine municipal which is a NEPOOL participant but not located in the NEPOOL control area, signed the agreement but objected to the reciprocity provision of the tariff. The provision does not appear to require reciprocity from New Brunswick Power, to which system HWC is connected. Because such a provision would be the key to NEPOOL access to the Eastern Canadian market, Enron, a nonsigner, supports the HWC position.

Market Structure

The entire NEPOOL changed from dispatch on the basis of energy costs to a market-based approach, as mandated by new players that are both suppliers and purchasers.

The new NEPOOL market will include both bilateral transactions and a power exchange. Both will be voluntary, which means no entity need buy or sell through the power exchange. In fact, most transactions will likely occur through bilateral trades.

Capacity Requirements. Each load-serving NEPOOL participant will have an installed-capability requirement and will be required to carry adequate resources to meet it each month. Currently, the capability will be determined as a function of the total NEPOOL capacity and reserve requirement. Because this requirement is reduced by the reliability benefits of the ties with New York and New Brunswick, each participant's requirement can be reduced when a bilateral transaction across the tie lines reduces unused transfer capability.

In the restructured NEPOOL, those making transactions across ties must compensate others for the increased reserve requirement, through the so-called outside transaction adjustment, or OTA. In effect, the OTA increases the cost of purchases from outside of pool as compared with those from within it.

Resources to meet the installed capability requirement may be purchased and sold bilaterally. Because system generation and purchases may not match requirements, surpluses and deficiencies will be handled through the power exchange. The ISO will ensure adequate resources and that the most economical are used in merit order. The ISO will also arrange for surplus to be assigned to deficient loads at market rates (which should be a marginal transaction).

Tradeable Products. The market for interchange transactions will operate on a "clearing-clearing" basis. All bids at or below the price for the quantity required to clear the market will receive the clearing price. All purchases will be at the clearing price.

There will be markets for: installed capacity; operable capacity; automatic generation control; energy; and operating reserves composed of five 10-minute non-spinning; six 30-minute non-spinning; and seven 10-minute spinning. Eventually seven discrete markets will operate beside the bilateral market.

Two transmission ancillary services (em scheduling and system control, and dispatch and reactive demand (em will be provided by NEPOOL through the ISO.

To ensure reliability, all transactions must be scheduled through the system operator. Enron has said it views such scheduling as unnecessary (em that the market will ensure reliability.

Negotiating the market provisions proved to be complex. The challenge was to convert a closed, yet functional, world into an open, but still functional, world. As a result, the market provisions are to be implemented beginning in the second half of 1997, after the new transmission tariff becomes effective. A second phase will begin no more than six months later, complete with separate bid prices for each of the seven products. The market will shift from daily to hourly pricing.

Governance

NEPOOL's governance structure was designed both to produce results and to allow smaller parties an opportunity to influence decisions. When this structure developed, it was acceptable for the major generation and transmission providers to play a dominant role. Smaller participants could obtain entitlements in "Pool Planned Units," accorded special low-cost transmission pricing.

Dominant Players. For a long period, negotiations on governance remained bogged down over how new "nontraditional" participants could vote and the degree to which the dominance of traditional players could be reduced.

Finally, the parties arrived at a governance structure, which, perhaps surprisingly, paralleled the existing organization. NEPOOL will be composed of six major committees: the Management and Executive Committees, as at present; two operating committees; and two planning committees, one each for generation and for transmission. The structure includes a procedure for alterative dispute resolution.

Voting shares. All participants are members of the Management Committee and their votes are weighted in accordance with their "business interests." Five percent of the total vote is to be distributed by count, so that each member gets the same vote. The remaining 95 percent is divided evenly into six classes. Two classes are related to load: average monthly peak and average monthly loads. Two are related to power supply: capacity owned or purchased and energy produced or purchased. Two are related to transmission: transmission miles weighted by voltage and transmission revenue requirement.

A participant's vote may change monthly; its contribution to NEPOOL and the system operator's fixed costs will be proportional to its voting strength. No participant may hold more than 25 percent of the vote. The surplus is distributed among participants.

In its alternative proposal, MMWEC objects to the vote given to transmission interests, which, it argues, would add to the voting strength of the larger entities. It proposes instead that each transmission component be given 5 percent of the total weight, with the four load and supply components dividing 85 percent of the total weight equally. This approach increases the influence of load servers as compared with generation and transmission providers.

Executive Committee. The Executive Committee serves as the principal decision-making arm. Each participant having 3 percent of the vote in the management committee is entitled to a vote. In addition, the executive committee reserves five group seats for entities that may not have 3 percent: consumer-owned utilities, independent power producers, marketers and brokers, transmission-only companies, and small investor-owned utilities. Thus, the committee initially could include as many as 14 members.

Majorities required for action by the Management and Executive Committees have been reduced. For example, to amend the current NEPOOL agreement requires 85 percent of the vote, and a veto must include two or more participants. The restated agreement calls for 70 percent. The vote of any one participant, for purpose of the veto, is limited to 18 percent.

The reduction in the required majority for approval is supposed to reflect a broader and more diversified membership. In its filing, MMWEC argues for the current rule, stating that the reduced majority makes it too easy for the larger entities to dominate decision-making.

ISO Participation. The system operator will hold a non-voting seat on all committees and can seek to influence their decisions. But Eastern Utility Associates, which signed the restated agreement, expressed its concern that on many operation matters the committees will make decisions that the system operator will not review. This process would allow domination by the larger generation and transmission entities, says EUA, and could occur when the transmission interest of a single company had no position on a generation matter and simply voted with its affiliate.

Overall, these governance provisions may seem to fall far short of the measures necessary to insure that the traditional generation and transmission providers cannot dominate NEPOOL decisions. Negotiators were aware of this possible criticism, but it became increasingly academic as the role of the ISO grew.

The System Operator

The regulatory commissions for the six New England states focused their attention on the authority of the ISO, a nonprofit body that would contract with NEPOOL to be the system operator. While FERC does not require an ISO, it was evident that use of an ISO was preferred, and support by the New England regulators was virtually a requirement of the restructuring.

Gradually, NEPOOL participants understood that they could not withhold any element of final authority from the ISO and acquiesced in virtually all of the requirements of the state regulators.

The New England filing contains an interim contract between NEPOOL and the yet-unformed ISO. Almost all of the NEPOOL staff will be turned over to the ISO, which will be subject to an independent 10-member board, including the president, the full-time head of the group.

The ISO board will exercise ultimate operating authority over both the generation market and the RTG in New England. Of course, its most important role will be to insure reliability, and its authority, even over transmission facilities not included in RNS, will be absolute and immediate.

NEPOOL committees undoubtedly will continue to develop rules and procedures and to propose changes to the regional system. And NEPOOL will continue to have its own FERC-regulated agreement and tariff. But no longer will it have the last word.

The ISO may appeal any matter from NEPOOL to its board. During an appeal initiated by the ISO, the matter is suspended, meaning it can halt any NEPOOL action. And, if it needs to take immediate action, it can bypass NEPOOL committees.

The ISO initially will be funded by assessments on NEPOOL participants. There is little chance for the pool to refuse an ISO levy. Ultimately, service fees could fund the ISO, enhancing its independence.

NEPOOL has the option, with FERC approval, of terminating its contract with the ISO and finding another entity to be system operator. Hence, it is conceivable that a for-profit entity, responding to performance incentives, could eventually replace the nonprofit ISO. t

Gordon L. Weil was chair of the NEPOOL transmission negotiations in their final phase, drafted the RTG negotiating agreement and served as part of the liaison team with the FERC and with state regulators relating to the ISO. He is President of Weil and Howe, Inc., a consulting firm based in Augusta, Maine. Weil last reported on events at NEPOOL in "Requiem for a Heavyweight," PUBLIC UTILITIES FORTNIGHTLY, July 15, 1993.

NEPOOL Evolution

Historical Milestones

Jan. 1, 1995 (em Executive Committee agrees to restructuring concepts, including plan to open membership, keep NEPOOL a single, central-dispatch control area and future study of alternative pricing.

Sept. 15, 1995 (em Files with FERC 32nd amendment to NEPOOL Agreement to open membership to power brokers and marketers.

Nov. 16, 1995 (em FERC ok's amendment. Six new entities apply by month's end.

Jan. 15, 1996 (em Executive Committee adopts restructuring plan, "NEPOOL-Plus," to include: bid-based, central-energy dispatch; expanded governance base; increased function of pool as a non-marketing, ISO, and plan to discuss regional transmission.

Sept. 30, 1996 (em Executive Committee agrees to create New England ISO. Also agrees to balanced governance participation, nondiscriminatory regional transmission tariff and competitive-market criteria.

Dec. 31, 1996 (em Files agreements with FERC to restructure, and create New England wholesale electric power market.

Source: William P. Sheperdson, manager, public information, NEPOOL.

NEPOOL's Future

Upcoming Milestones

Feb. 28, 1997 (em Target date to submit market power study to FERC, plus information on new NEPOOL market structure.

March 1, 1997 (em Requested effective date for NEPOOL Open-Access Transmission Tariff, and new governance and general provisions.

March 1997 (em NEPOOL committees are reconstituted; new voting formula gives representation to all participants.

April 1997 (em Candidates selected and nominated for ISO corporate board of directors.

May 1997 (em Election of the initial ISO board. Interim ISO/NEPOOL agreement takes affect.

July 1, 1997 (em Transfer control area responsibility and tariff administration from NEPOOL staff to ISO.

July - Dec. 1997 (em Modifify interim ISO agreement; execute definitive ISO/NEPOOL agreement.

Jan. 1, 1998 (em Target effective date for final market arrangements.

Source: "Transmittal Letter," to FERC, Dec. 30, 1996, pages 8-9.

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