| In the Matter of the Investigation by the Department of Public Utilities upon its own Motion Commencing a Notice of Inquiry/Rulemaking Establishing the Procedures to be Followed in Electric Industry Restructuring | Docket No. D.P.U. 96100 |
The Massachusetts Municipal Light Plants ("MLPs") support the Department of Public Utilities' ("Department" or "DPU") decision to include within the scope of its rulemaking consideration of the effect of restructuring on municipal electric light plants. D.P.U. 96-100, at 6, Issue 11 (March 15, 1996). As stated in our comments filed in D.P.U. 95-30, the MLPs are very interested in restructuring issues due to their unique position as municipally owned and operated entities. The MLPs appreciate the DPU's concern with the effect of restructuring on MLPs and their customers.
The DPU, in its March 15, 1996 Order in D.P.U. 96-100, set forth twelve issues to be discussed in comments on restructuring. As stated above, issue eleven directly concerns MLPs. The MLPs' comments are focussed on five of the remaining eleven issues the DPU identified in its Order: (1) market power, (2) transmission, (3) market structure, (4) stranded cost calculation and recovery method, and (5) default service. As part of these five issues, the MLPs will discuss reliability and NEPOOL issues. Accordingly, the MLPs' comments are organized in the following fashion. First, the MLPs summarize their positions with regard to each of these five issues. Second, with respect to each of the five issues, the MLPs set forth and comment on each of the five proposals submitted to the DPU. Third, the MLPs propose rules relating to the five issues.
As a preliminary matter, the MLPs again emphasize their opinion that competition must occur and flourish at the wholesale level before it is permitted at the retail level. The MLPs note that the Department's authority to require retail wheeling is undetermined and that the DPU's authority is that which has been expressly delegated to it by the Legislature or is necessarily implied to carry out the underlying purpose of its enabling legislation. As the Department set forth in its D.P.U. 95-30 (1995) decision, if the DPU possesses such authority, it would be pursuant to its general supervisory or ratemaking authority under G.L. c. 164, §§76, 94. These Sections are inapplicable to MLPs under statutes, court precedent and DPU precedent. As the MLPs set forth in their Initial Comments, at pages 51-71, in D.P.U. 95-30, the DPU does not have the authority or jurisdiction to order MLPs to retail wheel. The DPU recognized this point when it ordered, in D.P.U. 95-30, that all private electric companies, but not municipal light plants, comply with the DPU's Order regarding retail wheeling and restructuring. As discussed later in these comments, the MLPs set forth that the DPU does not have the jurisdiction to order the MLPs to retail wheel and thus, the MLPs should not be included within any retail wheeling order which restructures the retail electric industry. Nonetheless, the MLPs understand that they will be affected by retail wheeling and restructuring, if it occurs, and the DPU must establish regulations that assure competition and give the MLPs an equal opportunity to compete. In their comments, the MLPs have given much thought to and have set forth how equitable competition can be obtained and the manner in which the DPU, given its limited authority over the total electric industry, can directly shape such competition. Certain of the proposals, such as that provided by Massachusetts Electric Company ("MECO"), do not promote competition and actually utilize New England Electric System's ("NEES") control in generation and monopoly position in transmission to reduce competition and provide monopoly rents to itself.
The MLPs can provide the DPU with valuable input as it develops rules to govern the restructuring process. The MLPs are in a unique position in the electric power marketplace since they have boards selected by an elective process, are run by a public official -- the manager, and have ratepayers and no stockholders. The MLPs have handled and continue to face competition with their neighboring private electric companies and thus provide "yardstick" competition. In addition, as transmission dependent utilities ("TDU"), the MLPs have broad experience as users of transmission in the wholesale market. MLPs have participated as buyers and sellers in hundreds of power transactions. MLPs can draw on their experience in the wholesale market to offer valuable input to the DPU so that it may make informed choices and decisions. The MLPs, as TDUs and power purchasers, are dependent on competition in the electric marketplace and thus their experience is relevant to electric retail end-users who will be transmission dependent and purchasers of power. The MLPs have had to intervene in numerous Federal Energy Regulatory Commission ("FERC") proceedings to assure competition in merger, NEPOOL, wholesale rate, power agreement and transmission related cases. The MLPs are also active participants in NEPOOL restructuring and regional transmission discussions.
The MLPs completely agree with the DPU's analysis in D.P.U. 95-30 that there needs to be fair competition in the wholesale power market. The MLPs discussed in their Initial Comments, at pages 1-23, in D.P.U. 95-30, that there must be equitable competition in the wholesale power market before there can be competition in the retail market. Equitable competition is crucial since power supply amounts to approximately seventy-five (75%) percent of an electric utility's total cost. If such competition in the power supply marketplace does not exist, then with deregulation, there will not be increased efficiencies and lower rates, but only higher prices and profits. This unwanted situation can occur and is what has resulted in the United Kingdom.
It is important to note that in the last few years in over forty-five, ten year wholesale deals reached as a result of RFPs, amounting to over 800 MW of purchases for public entities, almost all of them were won by one of the three big electric utilities in New England - Northeast Utilities ("NU"), New England Power Company ("NEP") and Boston Edison Company ("BECO"). These three big electric utilities control above seventy (70%) percent of the generation in New England. The wholesale price of electricity is lower than the retail price because there is a significant amount of excess capacity in New England and not because there is substantial competition in the wholesale power market. We all remember when a capacity shortage resulted in a significant increase in wholesale power costs (NU's slice of system). This allowed NU to bundle groups of its generation resources rather than providing the generation sought. The same situation can result in a deregulated market where sufficient competition does not exist.
For sufficient competition to exist in the New England marketplace, no one entity can control price in any of the products sold in the wholesale power supply market. For sufficient competition to exist, there must be a sufficient number of competitors in each segment (i.e., daily, monthly, seasonal, annual, short, intermediate, long term, system, reserves) of the power supply marketplace. Membership in NEPOOL must be open to power supply sellers. Such sellers must have the rights and obligations of NEPOOL members. The unbundling of NEPOOL and power supply services must occur so that all competitors have the same economic and competitive access to those services and NEPOOL must not be governed by utilities possessing market power. NEPOOL is controlled by the same vertically integrated private electric companies that control the generation and transmission markets in New England. It is important to note that NEPOOL members such as NU, NEP and BECO have a significant competitive advantage in the marketplace in that they can offer firmer, more reliable sales through system type offerings while unit contract owners (such as Non-Utility Generators ("NUGs")) cannot by themselves economically match these types of offerings and thus lose out on the sales. This situation dampens competition.
Entities such as the MBTA, Massport and the Land Bank for the Fort Devens conversion all wanted the same type of firm, reliable service that they were obtaining but only at the currently lower wholesale market rate. This gave significant competitive advantage to NEP, BECO and NU since they can offer firm, all requirements offers. Even MLPs prefer firm-like system power with its reduced risk that NU, BECO and NEP can offer.
It is interesting that both NU and NEP, in their restructuring proposals, make the statement that control is not an issue in the wholesale marketplace. Of course they make that statement since they have the control.
The MLPs are of the opinion that the wholesale marketplace is not sufficiently competitive and thus retail wheeling with deregulation and less constrained monopoly power, at this time, will produce less competition and higher electric prices. In this market, there will need to be merchant type plants. Such financings in the electric utility industry have not truly occurred. Very difficult environmental regulation will still exist in New England. It will still take much time to permit power plants. New power plants may well not be on-line when need occurs. This situation clearly favors entities with existing generation, especially the three aforementioned utilities with large generation market shares. Add to this the fact that after the transition period, the cost of this existing generation, under NEP/Massachusetts Electric Company's ("MECO") and BECO's proposals, will be written down to almost no fixed costs at ratepayers' sole expense. As can be seen, this approach will also damage competition.
As will be discussed below, changes in the electric market structure can help to achieve competition in the wholesale market. While the DPU does not have jurisdiction in areas governed at the federal level, it can craft rules which can at least encourage and shape competition. The DPU can have a rule that if a distribution company is affiliated with an entity that has more than 20% of the generation in New England, the distribution company cannot take part in the retail end-use marketplace resulting from retail wheeling. The DPU can relate the percentage of stranded investment a distribution company can obtain to the percentage of the New England generation market that affiliated entities control. The higher the latter factor, the lower the former factor. If the DPU wants to increase competition, the MLPs respectfully state that it is a necessity that the DPU, at a minimum, should issue such rules.
The MLPs, as TDUs, propose that transmission must be common-carrier like in order for real competition with greater efficiencies and lower prices to occur. The transmission entity must treat every entity that wants to sell, buy and wheel power the same. The transmission entity should not be in a position to price its product so as to enrich itself and improve its competitive position to the disadvantage of its competitors in another part of the electric market. The transmission entity should not be in a position to refuse to or be recalcitrant in building new transmission because such an action may hurt its competitiveness in generation markets. If only functional unbundling occurs, noncompetitive situations that already exist will continue.
In the natural gas industry, the transportation entity is completely distinct and independent from the other parts of the gas market (i.e. production and local distribution). Similarly, the MLPs must state that the only way in which competition can truly occur in the electric industry is if real corporate unbundling (divestiture) occurs for entities having market power and the transmission entity is corporately separate and independent from the entities in the generation and distribution markets.
The MLPs are of the strong opinion that functional unbundling alone will work for entities having market power. Functional unbundling will still cause the revenues and income from transmission to go to the holding company that owns the generation and distribution entities. Since transmission and distribution will continue to be monopolies and rate regulated, it will be in the interest of a vertically integrated entity to increase the prices for its transmission and distribution products, especially with respect to transmission where the vertically integrated entity's competitors will be using this necessary and monopoly service. The vertically integrated entity will use the increased revenue and profits obtained from its higher transmission and distribution rates to lower its generation prices in the only electric market that could be competitive. This abusive situation does not increase competition, decrease electric prices or increase efficiencies. In fact, this situation does the opposite and chills competition. This is the very situation that the D.C. Court of Appeals found to be anticompetitive. If transmission assets are spun off, transmission rates need to reflect standard cost of service principles and original net book cost.
We are not talking about a hypothetical situation. MECO's and BECO's proposals actually say they will increase transmission and/or distribution prices. NU has already increased its transmission rates significantly. In fact, NEP has proposed a rate increase which will approximately double its transmission rates to the MLPs which are TDUs of NEP. Meanwhile, NEP is proposing almost no increase to MECO. This case will be heard at FERC. Given the vertically integrated nature of the electric utility industry, the likelihood of an acceptable Regional Transmission Agreement ("RTA") that fosters competition is probably minimal given the negotiations that have taken place over the last few years. In this system, the ability to have Region-wide and non-pancaked rates is made almost impossible. Region-wide rates would go far to increase competition by removing the segmentation of the market.
Since the entities that control generation also control transmission and the limited ties to contiguous regions, they will not build more transmission between the regions. Such construction would hurt their positions in the more competitive generation market and thus will not occur. However, increased transmission would be of great aid in increasing competition in the wholesale power market.
Meanwhile, these vertically integrated electric utilities that control generation and transmission will have the opportunity to game the system to increase their profits. They will try to change NEPOOL so as to increase their position in the generation market. The MLPs think that before such NEPOOL changes can occur, an acceptable RTA with a New England-wide postage stamp rate should be required.
Thus, the MLPs think that an independent transmission entity is necessary to bring about competition with lower prices and increased efficiencies. As the MLPs set forth in the wholesale power market section, the DPU can help to obtain corporate unbundling and assure real competition by instituting rules whereby: if an entity has more than 20% of generation in New England and also has a monopoly in transmission in terms of service to competing entities, it could not take part in the retail end-use marketplace resulting from retail wheeling and would obtain a smaller percentage of stranded investment.
As discussed above in the Market Power and Transmission sections of these comments, the MLPs are of the opinion that for there to be increased and real competition and not just increased monopoly rents, vertically integrated entities that control the generation marketplace cannot also control the transmission of electricity used by their competitors. These entities must be corporately unbundled.
For there to be true competition, the MLPs think that the markets must also be structured so that: no one entity can control the price of any power supply product; enough competitors are in the market for the sale of each power supply product; power supply products are unbundled with each product available to competitors; transmission must be common-carrier like; transmission has to be regional with the elimination of pancaked rates; and transmission has to be built between the regions so that under the resulting increased competition power will flow between the regions.
The MLPs have suggested rules whereby the DPU can help to achieve these results. The large, vertically integrated electric utilities, such as NEES, have stated that the DPU has little control over them. Therefore, these utilities are indicating that the DPU does not have authority to order retail wheeling and assure equitable competition. Thus, given the manner in which the electric utility industry is segmented between federal and state jurisdictions and that New England is regional, the DPU authority to restructure the industry is only partial and such partial restructuring could well lead to less competition and higher prices. However, the DPU does have some significant control over private electric companies in what is allowed in rate base under used and useful principles, the rates of return it can allow, the amount of stranded investment it can grant and the extent to which it can allow such companies to partake in a restructured, retail, end-use marketplace.
As the MLPs set forth above and in their Interim and Reply Comments in D.P.U. 95-30, the DPU does not have the authority or jurisdiction to order the MLPs to retail wheel. The Legislature has established a statutory scheme that produces such a result for the following significant reasons: the MLPs do not have stockholders; the MLPs are owned by their ratepayers; the ratepayers determine who is on the MLP Board; the MLP Board appoints the Manager; a MLP is a very important asset of a city or town; a MLP has been established by the city or town voters to serve a franchise; the MLPs' revenues support their cities' and towns' bond ratings; the MLPs' revenues are the security behind a political subdivision's (MMWEC) bonds and certain cities' and towns' General Obligation Bonds; and the MLPs provide in lieu of taxes to their cites and towns.
For these very same reasons, if the MLPs were subject to retail wheeling, they would need recovery of 100% of their stranded investment costs. The MLPs have no stockholders against whom the stranded investment can be written off. As tax exempt entities, MLPs cannot write off losses from the write down of stranded investment against the federal government and federal taxpayers. MLPs only have ratepayers and thus if one customer buys power from another entity and causes stranded investment, this investment can only be charged to other ratepayers. MLPs are concerned that residential and small commercial customers would be harmed by increased rates resulting from retail wheeling. In addition, since MLPs have obtained much of their power supply through tax exempt bonds, under the 1986 tax act, MLPs' ability to mitigate the stranded power investment by selling it to private entities is extremely limited without losing their bonds' tax exempt status. The MLPs' revenues also support over $1 billion of bonds issued to buy power for the MLPs. All of these financings were approved by the DPU. The Supreme Judicial Court has ruled that the MLPs' revenues must support and pay for such bonds. If the MLPs' financial position is jeopardized, their cities' and towns' positions will also be jeopardized. The MLPs cannot even go bankrupt without bankrupting their cities and towns. For all of the above reasons, the MLPs would need 100% of their stranded investment for the entire period of such stranded investment.
The MLPs take very seriously their obligation to serve. A MLP's city or town votes to establish a MLP's franchise which the MLP must serve. As stated above, the DPU does not have the authority to order retail wheeling for MLPs. However, if the MLPs ever retail wheeled, given the MLPs' obligations and responsibilities to their cities and towns, they would reluctantly, but of necessity, have to support the idea of default service by the local distribution company (or "LDC").
However, in developing default service, there must be certain strict rules. In an era of retail wheeling, the standards cannot nearly be the same regarding obligation to serve or planning. We currently have an industry that does long term, least cost planning with short term consequences. We will now be entering into a new era with short term planning having long term consequences. In such an era, the Energy Facilities Siting Board must no longer determine need in building jurisdictional facilities. The DPU must no longer rule on an electric utility's demand forecast and/or supply plan. The DPU must adopt rules to effect these changes if retail wheeling is to be implemented.
In order for default service to be workable, if a customer buys power from another source and then wants to return to be served by the LDC, the LDC should be required to provide such power only if it is available. The LDC should be able to price such power at the marginal costs. The DPU should adopt rules to that effect.
In instituting default service, the DPU must remember that with customers taking power from other sources, the LDC will have less revenues and less working capital. The LDC will have less funds to make emergency expenditures. The LDC may be impacted to a greater extent by bad debts. Thus, with any default service, the LDC should not be obligated to enforce an alternative supplier's contract with a customer or to cover the customer's nonpayment.
As requested by the DPU in its March 15, 1996 Order, the MLPs will now comment on NEP/MECO's, Western Massachusetts Electric Company's ("WMECO" or "NU"), Eastern Edison Company's ("Eastern Edison" or "EUA"), BECO's and the Division of Energy Resources ("DOER") restructuring proposals as they relate to MLPs and to the MLPs' positions on market power, transmission, market structure, stranded investment and default service.
NEP has stated that it will not go forward with restructuring until there is agreement on a restructured NEP and MECO wholesale agreement and termination charge. The fact that MECO is the largest electric utility in Massachusetts combined with this statement clearly shows the nature of market control that a dominant utility company can exert to continue to exercise market control.
Northeast Utilities supplies about 30% of the total load in New England but implies a much larger market extending from Maryland to Eastern Canada and represents about 7% of the load in the Northeastern United States. Not surprisingly, NU does not address the impact of inter-regional transmission constraints in describing the market in which it does business nor does it discuss either its horizontal (generation) market power or vertical (transmission) market power. However, Eastern Edison provides a series of analyses regarding generation market power which concludes that NU possesses market power as well as NEP and BECO within certain relevant markets. Eastern Edison argues for a regional approach to retail competition.
The BECO E-Plan calls for functional unbundling, but not necessarily corporate unbundling. Under the E-Plan, a marketer could own or contract for generation. Similarly, under the E-Plan, a utility generation owner or NUG could provide retail marketing services. BECO proposes operation of the transmission system by an Independent System Operator ("ISO"). BECO contends that NEPEX provides the basis for a future ISO. The ISO would determine whether the network can accommodate the schedule requested by generators and the Power Exchange, and adjust the schedule pursuant to transmission agreements. BECO advocates reform of NEPOOL, and voices support for NEPOOL Plus, rather than design of an entirely new alternative. BECO further envisions the development of a spot market or Power Exchange and advocates for the provision of a visible hourly clearing price.
DOER argues for corporate unbundling with Distribution Companies providing Distribution Service and Basic Service, and sale or spin off of the remaining retail functions of the currently regulated utilities. DOER notes that the degree of concentration of generation assets will require review.
DOER further contends that spot market services provided by the Power Exchange ("PX") must be in place as soon as generation pricing is deregulated with voluntary participation, unless participation is required to preclude the use of market power. DOER proposes an ISO to control transmission and argues that the ISO should not be owned or governed by generation owners as NEPOOL is. With respect to NEPOOL Plus, DOER argues that contemplated changes would not create a truly independent system operator or result in a fully market-oriented system. Further, DOER argues that the inability of participants to obtain operating reserves from the Pool could disadvantage smaller players and does not allow the market to play a role in selecting cost-effective reserves. DOER argues for (1) discontinuing own-load dispatch to promote the ability of load aggregators to obtain supply from and generators to sell into the spot market and (2) establishing participant ability to obtain reserves from the pool.
The MLPs agree with Eastern Edison that a regional approach to retail competition would to some extent mitigate the generation market power possessed by NEP, BECO and NU. However, a regional approach is not sufficient, in and of itself, particularly in light of the significant transmission ownership and control exerted by at least two of the utilities with generation market power. The DPU's proposed regulations should force those utilities which have market power to divest themselves of a significant portion of their existing generation. In addition, the DPU should provide additional protections against the abuse of market power which would distort the competitive markets the DPU seeks to create by assuring that: (1) barriers to market entry are reduced and (2) pricing and transaction information in both the spot and bilateral wholesale markets are readily available to all market players. Price transparency in the spot and bilateral markets will allow regulators and market participants to quickly identify any abuse of market power and take appropriate action. This is particularly important as NEPOOL transitions from a cost based dispatch system to a bid based system. Ironically and incorrectly, one element of NEPOOL Plus is an increased emphasis on confidentiality.
Market entry will also be enhanced if new market entrants are confident that the price signals available from the spot markets and reflected in any futures market which may develop are free of market power distortions and accurately reflect current market prices. The MLPs concur with BECO's and DOER's assertion that a spot market or power exchange of sufficient depth, competitors and competition is essential. DPU regulations should, therefore, require adequate participation in the spot market being created in NEPOOL Plus to insure the market has the depth necessary to provide price signals to encourage new market entrants.
As discussed in the introduction to these comments, the MLPs are concerned that a truly competitive wholesale marketplace will not develop if owners of large percentages of generation may also participate in the retail end-use marketplace. For this reason, the MLPs set forth a rule that qualifications based on an entity's share of the New England generation market be required for participation in the end-use retail market. However, with respect to DOER's proposal that Distribution Companies sell or spin off retail functions, the MLPs believe participation in the end-use retail market should not be completely restricted. Sale of competitive services by smaller Distribution Companies should be permitted. Such distribution companies make for more competition and more informed and reputable buyers and sellers in the marketplace. Vibrant competition requires more and not fewer players.
As explained more completely regarding market structure in the comments provided infra and as an Appendix, the MLPs believe that the determination of whether an ISO is necessary cannot be made until NEPOOL Plus rules are available for evaluation. The MLPs do, however, strongly urge corporate unbundling. The MLPs do not support discontinuance of own-load dispatch. Own-load dispatch prevents the gaming of the system to obtain monopoly or oligopolistic profits. Finally, the MLPs agree with DOER that concentration of generation assets must be eliminated and the MLPs have proposed rules linking generation market share to corporate unbundling, entry into the restructured retail market, stranded investment and other requirements.
NEP has indicated that it will file and develop separate rates for each transmission service to provide nondiscriminatory service to NEP, affiliated distribution companies and third parties. It has also indicated that these rates will apply to retail transactions and that network transmission rates will be billed to affiliated distribution companies based on their peak loads. These same rates would be charged to third parties. However NEP's actual transmission filings do not demonstrate this policy of equity and fairness, as shown below.
In a separate filing at FERC, NEP has developed the network and point to point transmission charges it proposes to implement as part of this restructuring. These rates go up very little to MECO customers, not a significant amount to point to point users of transmission, but by substantial amounts for mandated network service to captive, transmission dependent utilities purchasing power at wholesale. The disparity in these rates is illustrative of continued monopoly control combined with market power.
Eastern Edison's choice and competition proposal "allows for an RTG which embraces all of New England. NU indicates that an RTG will be a component of NEPOOL Plus and will "...supersede existing company-specific transmission tariffs and the provisions of the NEPOOL Agreement currently governing transmission price in New England."
Under the BECO E-Plan, the regulated utility's transmission business unit would own, install and maintain its transmission facilities, with wheeling on a network and point to point basis available to all parties at FERC-set rates and on a non-discriminatory basis. The transmission business unit's control of transmission flows would be coordinated with and administered by an independent third party. As noted previously, BECO advocates operation of the transmission system by an ISO and supports centralized, bid-based dispatch. BECO states that the ISO would perform the functions that NEPOOL currently performs with respect to maintaining reliability of the regional system. BECO proposes that, in order to perform real-time operating functions, the ISO should enter into contracts with generators for ancillary services with certain of these services secured competitively and others secured at a local level.
DOER also advocates the establishment of an ISO. Under the DOER proposal, the ISO would not be owned or controlled by one or more groups of buyers or sellers of generation or transmission. As discussed in more detail in the description of DOER's proposals regarding market power supra, DOER contends that the proposed NEPOOL Plus changes would not be sufficient to prevent abuse of market power.
The DPU must examine (1) the basis for NEP's proposal to charge non-affiliated wholesale customers for network service to determine if it is discriminatory and (2) NEP's continued ownership of transmission to ensure that market power is not exerted over its proposed transmission entity, NEES Transmission, Inc. The MLPs have been paying for this transmission for decades and should be given credit for the share of the transmission system for which they have paid.
Competitive generation markets as well as competition for retail customers require that all market participants have equal access to the region's transmission system at fair and equitable rates. Eastern Edison calls for a RTG, however, to date, there is not even agreement on the fundamental principles to be incorporated in such a RTG despite on and off negotiations and discussions over the past (5) years. Without strong requirements by the New England States' regulatory commissions, the MLPs are concerned that an acceptable RTG will continue to be nothing but a vague promise. The NEPOOL Agreement's transmission provisions which provide assured access and regional pricing are currently applicable to only a handful of generating facilities operating in the Region. Even this limited use of POOL transmission has come under attack. The MLPs believe that the underlying principles of NEPOOL transmission should be expanded, not further constrained. To support retail competition, a system of transmission pricing that overcomes the inequities and fallacies of the existing contract path, owner-pancaked pricing must be in place. That the major owners of transmission continue to cling to owner-pancaked pricing should come as no surprise in that this pricing methodology effectively reduces the size of the market in which they must compete and favors their existing generation.
The continued ownership and control of the transmission system by large vertically integrated utilities in a competitive environment creates a system in a deregulated industry where these systems will transfer certain of their generation costs onto their regulated transmission system and thereby to their competitors. NEP's recent filing, increasing rates by over 200%, contains numerous examples of such dubious charges. NU is also seeking a substantial increase in its transmission charges as we begin this transition to increased competition. Under current FERC regulations these charges can go into effect, subject to refund, pending a decision by FERC. However, even if ultimately found unreasonable, such charges may prevent economically efficient transactions from occurring while they are in effect. FERC's precedent of applying the vertically-integrated utilities' overall cost of capital to transmission investment, despite the lower risk associated with this monopoly service effectively requires competitors utilizing a vertically integrated utility's transmission system to subsidize the utility's capital associated with its competitive generation investments.
When, if, and how FERC will address these issues in the current MEGA NOPR is uncertain. FERC's intention is to enhance wholesale competition through transmission reforms. It is not FERC's intent nor is it authorized to develop an efficient transmission system based on retail customer choice. What may be acceptable as an initial step toward increased wholesale competition may prove to be woefully inadequate to support retail choice. Furthermore, FERC must, by necessity, approach reform on a national level and what appears as a step forward from a national perspective may be less efficient than the existing NEPOOL transmission arrangements already in place in New England.
The MLPs have previously stated that functional unbundling will not achieve the goals set forth by the DPU and FERC for a competitive, restructured industry. The MLPs view corporate unbundling as an essential prerequisite to a fully competitive market. The MLPs have set forth rules where the DPU can achieve such corporate unbundling and increased competition. Retail competition cannot exist where an entity that controls transmission of its competitors also has control (over 20% share) of generation. As discussed more fully in the comments regarding market structure infra, until NEPOOL Plus rules are available, the MLPs cannot determine whether an ISO will be necessary.
NEP controls and operates all generation and transmission resources of the NEES companies, including MECO as a truly integrated system. During the transition period NEP will: functionally unbundle transmission, distribution and generation by assigning transmission to NEES Transmission, Inc.; establish affiliated Distribution Companies in each state; and maintain generation as it does today. NEP will still retain ownership of transmission and continue to build, permit and operate this system during the transition period. NEP will assign rights, entitlements and obligations in return for the reimbursement of all of NEP's costs associated with the transmission system.
Both Eastern Edison and WMECO in their filings with the Department recognize the need for a regional approach. An integral part of these proposed regional changes is reformation of the existing NEPOOL Agreement. NU devotes a considerable portion of its filing to the proposed implementation of NEPOOL Plus and suggests that step 1 will be filed with the FERC in the first half of 1996 and step 2 shortly thereafter. NEPOOL Plus is presented as "...able to accommodate retail choice..."
As regards corporate structural changes, NU proposes no changes from its existing corporate structure suggesting that such changes are premature until FERC establishes functional unbundling rules for transmission. Eastern Edison asserts that it is already corporately, functionally unbundled as regards distribution, and proposes to functionally unbundle Montaup's generation and transmission services. Neither entity suggests what type of protections should be in place to protect consumers against vertical market power abuses (i.e., generation competitors' ownership of essential transmission services).
BECO contends that vertically integrated utilities should be functionally unbundled and that corporate unbundling is not necessarily required. BECO proposes that transmission and distribution remain regulated as "Network Service" which would include access to and use of the transmission and distribution delivery network. Network Service will include stranded cost charges. Under the E-Plan, generation, marketing, and energy services would be fully competitive and unregulated as "Energy Service." The E-Plan allows for some producers and retailers to be affiliates of current utilities. As noted previously, the E-Plan calls for an ISO and advocates a spot market. BECO proposes that centralized, bid-based dispatch be applicable to all suppliers.
DOER proposes corporate unbundling and disaggregating regulated utilities into unregulated generation and regulated Distribution Companies. DOER further proposes that utilities separate their retail functions from monopoly Distribution Companies. As noted previously, the DOER proposes establishment of an ISO that is not controlled by groups of buyers or sellers of generation or transmission. DOER further proposes development of a separate, independent, and voluntary PX to facilitate trading on a regional basis through a spot market and to settle imbalances.
Difficulties arise from NEP's approach since NEP Transmission will still be owned by the same holding company that owns generation and distribution with revenues and profits continuing to flow to the same stockholders and a holding company with a transmission and distribution monopoly and significant generation market power.
NEP states that it will not open its service area to other Massachusetts utilities unless the entire Massachusetts retail market is opened to choice. If this means that it will not open its service area unless MLPs also open their borders to choice, this is contrary to the DPU Order in this case. The DPU has clearly stated it has no authority to cause municipals to adopt customer choice. If this is NEP's intent, this condition to NEP's restructuring position is one that is not within NEP's control or the DPU's jurisdiction. In fact, NEP/MECO have put forth a proposal that will not allow for competition in a retail restructuring industry.
Given the interconnected operation of the electric utility system in New England, the dependence of MLPs on the transmission services provided by the Region's investor owned utilities ("IOUs"), and their active participation in the Region's existing wholesale power markets, the MLPs will be directly and significantly impacted by structural changes proposed by the IOUs and related regulations ultimately adopted by the Department. The MLPs are particularly concerned that any restructuring of the industry not diminish the economic and reliability gains which have resulted from the regionalization of the electric utility industry through the formation of NEPOOL.
With respect to NU's assertion that NEPOOL Plus will accommodate retail choice, the MLPs note that NEPOOL Plus is not being developed or evaluated as the most efficient pooling and operator system to support retail choice but rather as an incremental means of accommodating increasing wholesale competition. Furthermore, NEPOOL Plus to date is nothing more than the summary vision contained in Exhibit FPS-2 as part of WMECO's proposal, with numerous details yet to be resolved. Absent such detail, it is impossible to determine whether NEPOOL Plus will provide the necessary regional structure to efficiently support retail competition. For example, NU refers to the establishment of detailed criteria which will allow the pool to operate as an ISO. However, absent such rules and without a clear definition of voting rights, the MLPs are unable to determine whether NEPOOL Plus will, in fact, provide the necessary regional ISO function essential to enhanced wholesale competition and support the Department's goal of efficient retail competition. Therefore, it is the MLPs position that a determination that an ISO must be established is premature in light of the fact that the NEPOOL Plus rules are still being developed. NEPOOL reform may be sufficient to address the needs of a restructured electric industry.
NEPOOL Plus envisions establishment of a RTG, yet no specific proposal is presented on which the MLPs can comment. If adequate protections are not incorporated into the final rules governing NEPOOL Plus to prevent market abuses by the large players which currently control both NEPOOL voting and the Region's generation and transmission capacity, the MLPs and the electric consumers of the Commonwealth may be better served by the type of truly independent ISO envisioned by DOER. NEPOOL Plus is described as evolutionary and incremental, yet the Department's proposal and schedule for retail competition is radical and sudden. The changes proposed in NEPOOL Plus may not be extensive enough or be in place in time to meet the Department's timeline vision of a restructured industry. Regulations developed by the Department as they pertain to the implementation of retail competition should require utilities to file detailed proposals for a restructured NEPOOL and should require FERC approval of such changes before any retail wheeling is implemented. The MLPs think that it is dangerous to implement retail wheeling before fair and equitable wholesale competition occurs. For example, in California, the PUC first ordered procedures to assure wholesale competition before beginning to implement retail wheeling.
The lack of specificity in NU's and Eastern Edison's proposals regarding protecting consumers from vertical market power may well reflect the difficulty in clearly separating and defining individual and sometimes conflicting obligations and responsibilities when each subsidiary is ultimately accountable to the same stockholders.
The MLPs strongly disagree with BECO's contention that functional unbundling, without corporate unbundling, is all that is required. The MLPs support DOER's proposal to require corporate unbundling. The MLPs suggest, however, that the DPU should not adopt a hard and fast rule requiring all Distribution Companies to sell or spin off retail functions. Rather, the MLPs suggest that retention of retail functions be allowed for small Distribution Companies that would not present market barriers presented by entities with large market shares. Finally, DOER is correct that a robust spot market will be needed at the outset of competition.
In its transition principal number one, the DPU states, "Utilities should have a reasonable opportunity to recover net non-mitigable, stranded costs associated with commitments previously incurred pursuant to their legal obligations to provide electric service." NEP argues that its access charge (contract termination charge between affiliates, NEP and MECO) does just that by recovering: (1) regulatory assets associated with generation; (2) nuclear obligations independent of operation; (3) power contract obligations in excess of actual market value; and (4) strandable costs associated with generation. The contract termination charge compensates NEP for waiving the 7-year termination provision of its agreement with MECO. NEP argues that the resulting cost to customers will be lower under its proposal than if regulation were continued. NEP also claims that it needs this access charge to give it inducement to provide a stable standard offer to retail customers.
NU and EUA advocate recovery of stranded investment. NU and EUA support recovery of decommissioning expenses as a part of stranded investment recovery. As indicated by Eastern Edison, these decommissioning expenses will need to be reconciled with actual obligations which arise in order to assure adequate funds will ultimately be available to safely decommission nuclear plants at the end of their useful life. However, EUA does not provide for recovery of "going-forward nuclear generation costs."
NU proposes a charge based on the projected "market clearing price for generation" which would be reexamined by the DPU after 5 years. Eastern Edison's calculation is dependent on market cost projections only as they relate to IPP/QF contracts adjusted annually. However, EUA assumes a market price of 2.671¢/kWh while NU projects a 3.1 ¢/kWh (18% higher) market price in 1998. In addition, it is not clear that the projected market prices reflect the same product given an additional ancillary service charge proposed by NU.
BECO proposes a non-bypassable network access charge to be paid by customers as a condition of receiving delivery service over the distribution system, with a portion continuing until all costs are recovered and a portion continuing for 10 years following implementation of retail choice. Under the E-Plan, stranded cost recovery would include nuclear decommissioning costs and deferred charges previously approved by regulators. BECO would also include above-market costs associated with power purchase contracts with NUGs, with adjustments to reflect changes in the market price or in charges under such contracts. With respect to stranded costs associated with generation investments, BECO proposes recovery of all net plant investment.
DOER advocates for the provision of a reasonable opportunity to recover sunk costs that are genuinely unavoidable and verified using a market-based standard. To obtain market-based valuations of stranded costs, DOER advocates the sale by auction or stock valuation following spin-off of non-transmission and distribution ("non-T&D") assets between 1998 and 2000. DOER proposes stranded cost recovery for: unrecovered net book value and an appropriate return on outstanding balance, with the return limited to an overall rate equal to embedded cost of debt associated with those assets. DOER proposes that nuclear decommissioning liabilities remain with the Distribution Company. In addition, DOER proposes incentives for re-negotiation or buy-outs of above-market power sales agreements ("PSAs").
The termination charge agreed to by NEP and MECO is simply an agreement among parties with the same interest, protecting their position which is really that of their holding company. It should not be relied on as an arms length or independent transaction fairly establishing which costs should be recovered through this charge. Given this position, the actual access charge and the method of its assessment has the effect of allowing NEP to charge any wholesale market price it wishes for its power since it can automatically recover the difference between this wholesale charge and the cost of its generation. This will allow NEP to control the wholesale market by underbidding all other power marketers while still getting full recovery of cost. The MLPs propose that stranded cost recovery be linked to the percentage of the New England generation market owned by affiliates of a distribution company.
In addition, NEP will recover all costs associated with its waiver of the seven year notice period in the contract between NEP and MECO. This seven year notice is another item established by the same entity on both sides of the table and hence cannot be construed as necessarily a fair measure of net non-mitigable stranded cost.
NEP's argument that its stranded investment charge is intrinsically fair since the resulting cost to retail customers will be lower than if regulation were continued is flawed. It is based on wholesale costs of power delivered to wholesale customers ranging from 2 to 3 cents per KWH hour. NEP claims that this market based power charge when added to a cap of 3.0 cents access charge plus transmission and distribution costs is lower than existing costs and the ratepayer will immediately benefit from customer choice. Our dealings in the same competitive power market yield no such current or future estimates of market costs from any recognizable marketer, including NEP. Careful examination of these issues needs to be undertaken before the impact of this access charge can be determined. The burden of proof for this undertaking must rest with NEP and MECO.
Like NU and Eastern Edison, the MLPs support recovery of net, nonrecoverable stranded investment. As stated previously, MLPs need to be able to recover all costs associated with their investment in generating facilities and purchased power commitments. In addition, the MLPs support recovery by the Region's IOUs of net, non-recoverable stranded investment. Existing IOU capacity is essential to maintaining reliability within the Region. If failure to recover stranded investment results in the loss of significant amounts of existing generating capacity, the resulting supply constriction would lead to a rapid run-up in the market price of generation until new capacity could be brought to the market. Furthermore, MLPs do not generally have ownership control over their power supply resources. In many instances, their power supply is dependent on power purchases based on MLPs' or MMWEC's minority ownership interests in regional generating plants. Therefore, the financial viability of the other joint-owners is of vital interest to the MLPs.
This interdependence with the Region's IOU systems is of particular importance as it relates to the MLPs and MMWEC's participation in the Region's nuclear power plants. Financial pressures and cost cutting could have significant safety implications which would be beyond the ability of a minority joint-owner to control. The DPU must be mindful of the special circumstances surrounding nuclear generation and safety as it drafts its regulations. The U.K. specifically dealt separately with nuclear generation in its restructuring. The MLPs are concerned that an approach like EUA's, which does not provide for recovery of going-forward nuclear generation costs, fails to reflect the unique nature of nuclear generation and the joint-ownership of certain of the Region's nuclear facilities.
Although the MLPs support recovery of net, non-recoverable stranded investment they are mindful of the fact that determining the actual level of stranded investment is problematic yet essential to the creation of competitive markets. If stranded investment levels are set too low (generation market values too high), financial constraints on existing utilities may prevent them from acting as effective competitors. Conversely, if stranded investment levels are set too high (generation market values too low), new entrants will effectively be precluded and any benefits from competitive markets indefinitely deferred.
Given the variation in market price estimates and proposals for periodic adjustments evidenced in NU's and EUA's proposals, the Department's rules must clearly define how market values are to be determined. The MLPs are concerned that DOER's proposal to sell assets in a three-year period may result in artificially low market values due to a distressed market sale in the current surplus market. Care also needs to be taken in assuming that NEPOOL Plus will give an accurate indication of market price (see comments regarding market structure).
With respect to DOER's proposal for corporate unbundling of all non-T&D assets, the MLPs believe that this may be appropriate depending upon the market size of the entity. The MLPs do not advocate a complete restriction against ownership by Distribution Companies. The distribution and transmission benefits associated with locally distributed generation should not be precluded. Regarding DOER's proposal for incentives for renegotiation or buy-outs of above-market PSAs, the MLPs note that parties could also resolve such negotiations through arbitration. The DPU should encourage parties to engage in arbitration.
The MLPs do agree with the non-bypassable aspect of a stranded investment charge. The MLPs do support non-bypassable distribution.
NEP has stated that its existing obligation to provide generating capacity to meet future load growth will be deleted from its wholesale contract with MECO. Consequently, MECO's obligation to serve its retail customers will be limited to delivery of service at non-discriminatory rates including an access charge to recover its termination charge with NEP. NEP claims that its proposed access charge will enable it to provide a stable standard offer during the stranded cost recovery period.
MECO also provides "safety net service" provided to customers not adequately provided with service by the market. The distribution companies would be obligated to provide this service any time service has been denied by the competitive suppliers pursuant to DPU rules or termination of a customer's supply contract. The Distribution Company would periodically award safety net service on the basis of short term market prices provided by successful bidders. The payment by the Distribution Company to the winning bidder would be included in its charge for distribution service, paid for by all distribution customers, in much the same manner as today.
BECO maintains that the regulated distribution arm of the utility will have the obligation to connect customers and deliver service the customers choose, but not the obligation to provide service. BECO states that the distribution unit would assume the role of "supplier of last resort" by acting as a conduit to make service available under a standard offer or to make energy available at the spot market price. The BECO standard offer would allow recovery of all sunk generation costs in exchange for a price guarantee. The standard offer price would be equal to BECO's current total unit price escalated by the CPI less productivity. BECO states that low income consumers can be protected and the provision of essential electric service preserved through a separate charge as part of the regulated distribution business.
DOER proposes that Distribution Companies provide Basic Service under a tariff tied to the spot market to all customers who have not authorized the Distribution Company to assign a supplier or who are not receiving all of their load from a supplier.
MECO's method for providing default service appears to be adequate by combining appropriate parts of a competitive market with requirements to provide socialized service. Critical to its success will be the willingness of NEP's affiliated Distribution Companies to choose a truly competitive supplier and not be influenced by a company that is part of a family of companies controlled by the same holding company. If this is not done, the distribution customers will again be subsidizing the profits of the parent company through rates of an affiliate.
The MLPs' preference would be for default service to be offered
at the marginal cost, spot market prices as MECO and DOER suggest,
rather than as so-called "fixed price" offers from the
distribution arm of a customer's current utility. The MLPs note
that the "fixed price" offers proposed are based on
current rates with escalation provisions and, as such, would not
necessarily reflect the market and provide accurate price signals.
Convergence Research - 6/1/96