Microsoft word - nescoe rps plan - exelon comments - final
New England States Committee on Electricity
Coordinated Competitive Renewable Power Procurement
Prepared Comments of
Jonathan A. Lesser, PhD
Continental Economics, Inc.
On Behalf Of
August 30, 2012
Exelon Corporation (“Exelon”) urges the New England States Committee on Electricity
(“NESCOE”) to abandon
its proposed long-term, multi-state renewable resource procurement
plan (“RFP Plan”) for the following reasons:
(1) The proposed long-term procurement will itself undermine competitive markets, including
development of competitive markets for renewable generation. By assuming competitive markets will not work in the future, the RFP Plan proposes to implement an approach that will create a self-fulfilling prophecy.
(2) The RFP Plan is a “back-to-the-future” contracting approach that repeats the failures under
the Public Utility Regulatory Policies Act of 1978 (“PURPA”). PURPA forced electric utilities and ratepayers to pay for over-priced, long-term purchase power contracts, whose rates were set administratively by public utility commissions. The contracts also forced captive ratepayers to bear all of the risks of generation resource development and significant stranded costs, which were both key reasons for developing restructured electric markets that would reallocate business and financial risks to the generation developers best able to manage them.
(3) The structure of the RFP process, which allows individual state procurement authorities
and/or electric distribution utility to opt out of individual projects, has the potential to create tremendous uncertainty for developers, which will increase costs, to the detriment of ratepayers and individual state economies.
(4) The long-term power contract between Hydro-Quebec and Vermont electric utilities provides
an example of “political buyer’s remorse” that this RFP Plan is likely to engender. Having extensively litigated the cost-effectiveness of the contract in the late 1980s, the Vermont legislature decided that the price “step-up” provisions in the mid-1990s were unacceptable, and exerted political pressure on the Vermont Public Service Board to reject recovery of the contract’s costs. As a result, when Green Mountain Power filed a rate case in 1997, the Vermont Public Service Board ruled the contract to be both imprudent and not “economically” used and useful, and in doing so brought Green Mountain Power to the edge of bankruptcy, harming both ratepayers and shareholders.
(5) Rather than directly intervening in competitive markets based on an assumption
renewable resources will not be procured, the New England states should first evaluate the potential impediments to competitive renewable resource development, including: siting and permitting procedures, infrastructure and interconnection issues, changing RPS rules, alternative compliance payments that cap the maximum prices for renewables, and price suppression in forward capacity markets because of forced out-of-market intervention by
states. States should focus on removing all of the identified impediments to market development, rather than creating new ones through this approach.
To the extent that NESCOE feels compelled to “do something” and issue an RFP on or before December 31, 2012, a far better approach would be to seek non-binding proposals from project developers, similar to the “Energy Highway” approach used in New York State. The current RFP Plan is too open-ended to incent meaningful responses. It fails to specify quantities to be procured, types of resources desired, price structures, delivery dates, and so forth. Such an open-ended structure will render unbiased comparisons of binding offers impossible. Instead, it is likely to create a situation in which “winners” are selected based on political considerations, rather than economic ones, to the further detriment of New England ratepayers.
Exelon’s detailed comments are provided on the following pages.
New England States Committee on Electricity
Coordinated Competitive Renewable Power Procurement
Comments on Behalf of Exelon Corporation
August 30, 2012
On behalf of Exelon Corporation (“Exelon” or “the Company”), thank you for this opportunity to comment on the August 10, 2012, “Coordinated Competitive Renewable Power Procurement Draft Work Plan” (“RPP Plan”).
Exelon has asked that I prepare these comments because of my background as an economist who has been an active participant in development of competitive wholesale and retail power markets; as someone who has published in peer-reviewed journals regarding both economically efficient means of acquiring renewable generating resources and the economic consequences of such resources; and my experience with resource planning and long-term power contracts, including the long-term contract signed between Hydro Quebec (“HQ”) and Vermont electric utilities in 1990, which was the subject of extensive litigation by the Vermont Public Service Board (“VPSB”) in 1997-1998.
SUBSIDIZED, LONG-TERM CONTRACTS ARE A FAILED LEGACY OF
PURPA THAT SHOULD NOT BE RECREATED
The proposed RFP Plan, as structured, is a “back-to-the-future” regulatory approach that will recreate the problems experienced by utilities and their ratepayers under the Public Utility Regulatory Policies Act of 1978 (“PURPA”). The high-cost of PURPA resources that electric utilities were compelled to purchase were the result of regulators’ and politicians’ failure to accurately predict future market conditions. This is not meant to malign these well-meaning individuals; rather, it is an admission of a basic fact: clairvoyance is always in short supply. These failures to predict the future accurately led to utilities being locked-in to long-term contracts to purchase renewable resources at above-market costs. Those costs were, of course, all passed along to utility ratepayers.
The well-known failures of PURPA led to its modification under the Energy Policy Act of 2005 (“EPAct 2005”), which requires PURPA contracts to be based on prevailing wholesale market prices. This makes far more economic sense: if utilities are to be forced to purchase electricity from PURPA qualifying facilities, at least they, and their ratepayers, do not have to pay above-market prices for the privilege.
Given the well-known failures of long-term contracts procured under government mandate, and the controversies raised by New England utilities that entered into long-term contracts, it is ironic that the RFP Plan seeks to implement a convoluted procurement process that recreates the same weaknesses as PURPA, and conditions that have previously led to regulatory and political controversies in New England, notably the contract between 24 Vermont electric utilities and Hydro-Quebec.
A. The States Should Not Repeat the Controversy of Vermont’s Long-term
Contract with Hydro-Quebec.1
In 1987, a group of nine Vermont utilities, collectively called the Vermont Joint Owners (“VJO”), entered into a thirty-year contract, from 1990 to 2020, for power from HQ. Given the duration of this contract, the VJO was required to seek regulatory approval because the State of Vermont requires that parties seeking long-term supply commitments (five years or longer) obtain a Certificate of Public Good (“CPG”). The contract was amended, in 1988, because of concerns about obtaining all of the necessary regulatory approvals. Under the amended contract, the parties had until April 30, 1991 to terminate the contract if the necessary regulatory approvals were withheld or simply unsatisfactory to the party. In October 1990, the VPSB issued a CPG to the Vermont utilities, providing interim approval for the contract and the participation agreement among the nine utilities. However, in early 1991 HQ was running into its own regulatory problems, and was dissatisfied with one of the conditions of the regulatory approval it obtained from the Canadian National Energy Board. Because HQ was appealing that condition to the Canadian Court of Appeals, it sought to extend the April 30, 1991 termination deadline. The parties subsequently signed a new agreement with a termination deadline of December 1, 1991. This new agreement was also approved by the VPSB.
In July 1991, the Canadian Court of Appeals affirmed the export license to HQ and struck down the condition to which HQ had objected. By the end of August 1991, the parties had locked-in the contract. In February 1992, the VPSB approved the allocation of the contract costs among the participants. Under the agreement, the cost of power under the HQ contract increased significantly beginning in 1995, but would then be tied to the rate of inflation. However, in light of the forecasts for fossil fuel prices and inflation, those higher HQ contract costs still appeared to offer benefits to Vermont ratepayers, including price stability. The forecasts of rapid fuel price and demand increases did not come to pass. The recession in the early 1990s reduced the demand for power in Vermont. By 1994 deregulation of natural gas supplies had also significantly reduced fuel costs and increased supplies. The ideal solution that the HQ contract initially provided was appearing to be less than ideal.
1 For a detailed discussion of the contract, see
J. Lesser, “The Used and Useful Test: Implications for a
Restructured Electric Industry,” Energy Law Journal
23 (November 2002), pp. 349–82.
In June 1997, Green Mountain Power Corporation filed for a 16.7% rate increase, primarily to recover the costs of its HQ contract obligations. Under political pressure because the forecasts of high fossil fuel prices had not come to pass, the VPSB ruled that signing the contract had been imprudent (despite having previously approved the contract in 1991) and that the contract was not economically used and useful. That is, the purchase price under the contract was expected to be higher than other generation alternatives.
The VPSB (wrongly) determined that the contract would never be economic compared to alternatives and, as such, disallowed recovery of the higher contract prices. The VPSB ordered Green Mountain Power to reduce its rates.2
The financial consequences were immediate and extreme. Green Mountain Power was brought to the verge of bankruptcy because lenders refused to provide the company with continued access to capital. Had the company gone bankrupt, the “step-up” provisions of the contract would have led to a cascading series of bankruptcies by Vermont’s other utilities. Only when the VPSB modified its stance and allowed Green Mountain Power to recover additional costs was the financial crisis averted.3
Fifteen years later, the New England states appear ready to repeat failed history. Under the RFP, it would be possible for HQ to supply hydroelectric generation that would be delivered by the proposed Northern Pass transmission project. What will happen if, years after signing, that contract, too, is found to be more costly than market-based alternatives? What will happen if states that agreed to purchase a portion of that output decide, for political reasons, they no longer wish to bear those costs, or simply default on their obligation? Will the other states be required to “step-up” and bear the remaining contract costs? Will there be protracted litigation to break contracts, paid for by taxpayers? How will stranded costs be addressed? Of course, these questions are relevant for all long-term renewable resource contracts.
HQ, and all other renewable generation developers, will obviously account for such contract risks into the prices they bid. Moreover, depending on how contract prices are set, such as the “front-loaded” pricing typical of many long-term PURPA contracts, there are significant risks that developers may default; having collected more revenues up front, renewable resource developers will have less incentive to continue contract performance.
2 See In re Green Mountain Power Corp
., 184 P.U.R. 4th 1 (Vt. 1998). As a witness in this
proceeding, I prepared an analysis using a decision tree approach to show that the contract was not uneconomic. The VPSB rejected this analysis, arguing that the methodology was more advanced than what was used in the original contract evaluations and thus inapplicable.
3 After a severe ice storm in January 1998 caused extensive damage to transmission lines in Quebec,
the Vermont legislature forced Green Mountain Power and Central Vermont Public Service to claim that HQ had violated the terms of the contract because power could not be delivered, and as a result, the utilities could break the contract. After spending several million dollars in legal fees, an arbitrator ruled that the ice storm was an “Act of God” that did not abrogate the contract.
B. In Attempting to “Solve” a Non-Existent Problem the RFP Will Crowd-Out
Competitive Renewable Generation Development
The RFP Plan notes that “[c]ompetitive markets have met the demand to date for renewable resources,” but that they may not do so in the future because of five factors:
a) fundamental shifts in the natural gas supply have lowered forecasted energy revenues for renewable resources; b) macroeconomic conditions have exacerbated the challenge of financing renewable resource development; c) diminishing available transfer capacity on the New England transmission system in regions with lowest cost renewable resources have complicated the interconnection incentives; d) changing market rules that may limit renewable resources ability to clear in the current capacity market, and e) the clogged interconnection queue, which can impede all generation resource development.4
These five factors offer an interesting perspective on views of RFP Plan proponents. “Fundamental shifts in the natural gas supply” refers to the rapid increase in shale gas development, which has increased natural gas supplies and reduced wellhead prices. This has made natural gas-fired generating resources less costly, reducing wholesale market electric prices, and has contributed to retirements of coal-fired generation units. The result is lower-cost electricity and less pollution, a seemingly “win-win” outcome for New England states. Yet, rather than viewing this result in a positive light, it is presented in the RFP as a “negative.”
It is, of course, true that the lack of economic growth and more restrictive financing is hobbling development of all new generating resources. However, the reduction in economic growth has reduced the overall demand for electricity, which has reduced the need for new generating resources. Out-of-market intervention that subsidizes renewable resources will further suppress market prices, thus reducing the incentive for future market development of any generation – renewable or otherwise. By artificially intervening in the market, the RFP Plan will create a self-fulfilling prophecy that, in the long-run, will lead to less investment, greater financial uncertainty and more restrictive financing, higher electric costs, and lower economic growth.5
Diminishing transfer capabilities and interconnection delays will not be solved by an extra-market, long-run RFP. Rather, they are likely to be exacerbated. New England utilities do not have coordinated interconnection policies. Moreover, because many utilities have their own supply portfolios, they may wish to discourage customer migration to alternative suppliers. Forcing utilities to enter into long-term contracts for renewable resources will exacerbate this problem. A better approach is to divest utility generating resources and develop uniform interconnection rules.
4 RFP Plan, p. 2, fn. 2. 5 See, e.g
., J. Lesser, “Gresham’s Law of Green Energy,” Regulation
, Winter 2010-2011, pp. 18-22.
Finally, the “clogged” interconnection queues will not be solved through the long-term procurement envisioned under the RFP Plan. Resources bid in response to the RFP Plan, if any, will still require all of the same interconnection studies, unless the RFP is designed to acquire only “behind-the-meter” renewable resources. The most economic renewable resources will be developed in consideration of existing transmission constraints and the costs of reducing or eliminating those constraints. To the extent that the six New England states lament the lack of transmission capacity, the solution is to address existing siting and permitting requirements that make it difficult to expand that transmission capacity.
Similarly, changing capacity market rules have been put in place to prevent exactly the type of non-market intervention contemplated under the RFP Plan, because of the adverse long-term impacts on wholesale capacity markets and, thus, long-term resource adequacy.
Ultimately out-of-market long-term contracts for renewable generation will not only force ratepayers to bear the costs of renewable resources that may be uneconomic, just as under the original PURPA, but states will make it more difficult, if not impossible, for market-based renewable resources to compete. Renewable resource developers, given a choice between bearing financial risk themselves or off-loading that risk to captive ratepayers and taxpayers, will invariably choose the latter. Financing for competitively developed renewable generation will decrease for the same reasons, further reducing competitive generation development.
These adverse impacts will not be limited to renewable resources. By incenting subsidized, out-of-market generation development, the states will artificially reduce wholesale energy and capacity prices, and thus reduce competitive generation development, such as natural gas-fired generation needed to “firm-up” the inherently variable output of wind and solar resources. In the long-run, the result will be higher overall wholesale and retail electric prices paid by consumers, and reduced reliability.
C. The States Should Identify and Address the Underlying Reasons for the
Perceived “Impediments” to Renewable Resource Development
Rather than jumping to the conclusion that the RFP Plan is the “solution” to perceived impediments to renewable resource development, a better approach is to step back and evaluate renewable resource policy goals and the impediments to meeting those goals. This may sound obvious, but as someone who has worked to develop state energy policies, one approach is to first identify policy goals and then evaluate the least-cost approaches to meeting those goals. An even more efficient approach is to evaluate whether the benefits of the policy goals exceed the costs. For example, if some renewable resources are cost-competitive in the market, why do they need additional subsidies, including the ability to transfer financial risk to captive ratepayers through long-term contracts signed by individual state power authorities, when other, competitively supplied generating resources do not? Furthermore, if some renewables are not cost competitive, does acquiring such resources represent sound energy and economic policy,
given weak state economies and the economic “drag” imposed by above-market cost electricity supplies.6
In addition, before issuing any RFP, states may be better served by evaluating their own siting and permitting procedures, specific infrastructure and interconnection issues, and changing RPS rules and requirements. All of these increase the difficulty of competitive resource development of all types, not just renewable resources. By addressing the underlying impediments and creating environments that help foster competitive markets to develop new resources, rather than create additional impediments to these markets through mandated long-term contracts and non-market intervention.
THE RFP PLAN LACKS SUFFICIENT SPECIFICITY REGARDING CRITICAL
The RFP Plan lacks the specificity needed to attract bids and, more importantly, compare alternative bids in a consistent manner. Specifically, the RFP Plan:
x Fails to specify what constitutes a “long-term” contract. x Fails to specify what types of resources are sought, the quantities of resources sought, and
x Fails to specify what pricing structures are sought. x Fails to specify how proposals submitted by developers could be modified if certain
states decide to “opt-out” of specific contracts.
x Fails to address how specific resources would, or would not, satisfy in-state renewable
x Fails to address treatment of renewable energy credits (“RECs”) and specialized RECs,
such as solar renewable energy credits (“SRECs”).
x Fails to specify how interconnection, system upgrade, and ancillary services transmission
system costs would be allocated, e.g., would costs be allocated based on cost-causation, beneficiary pays, or require developers to bear all such costs?
Given this lack of specificity, bidders will be unlikely to submit binding proposals. Moreover, evaluating alternative bids will be problematic. How, for example, would a 10-year contract with a nominal levelized price, and an option to renew, be compared with a 30-year contract with a real levelized price? How will the RECs and SRECs be valued? Will renewable resources that
6 For example, in a 2010 decision in which it rejected a high-cost wind contract, the Rhode Island
Public Utilities Commission stated, “It is basic economics to know that the more money a business spends on energy, whether it is renewable or fossil based, the less Rhode Island businesses can spend or invest, and the more likely existing jobs will be lost to pay for these higher costs.” In Re: Review of New Shoreham Project Pursuant to R.I. Gen Laws § 39-26.1-7
, Docket No. 4111, Report and Order, April 2, 2010, p. 82.
are bid be credited based on the capacity they provide to the ISO-NE capacity market and, if so, how will resources developed in constrained zones be treated?
Although Section III.B of the RFP Plan briefly mentions some of these issues, but approaches them in a haphazard manner, such as “determining collective preferences” for aggregate volumes, resources, products, and evaluation criteria. The lack of specificity on these criteria, and more, including legal and financial obligations, will create a haphazard review process. It is inconceivable that all of these issues can be resolved prior to the end of the year. Moreover, resolution of these issues must involve not only the individual state procurement authorities, but also potential bidders and local distribution companies.
Exelon urges NESCOE to abandon the RFP Plan, because it will damage competitive wholesale electric markets, to the detriment of all ratepayers. The RFP Plan seeks to “solve” a non-existent problem and, in doing so, will exacerbate the very problems it cites.
If, despite Exelon’s recommendation, NESCOE insists on proceeding with issuance of an RFP before the end of this year, Exelon urges the RFP to be non-binding, similar to the proposals received for the New York “energy highway.” Non-binding proposals would provide NESCOE and the individual states with additional information regarding renewable generation development in the region, as well as clarify issues requiring resolution if additional quantities of renewable generation are to be incented.
Exelon also urges NESCOE to address obstacles to all competitive generation development before concluding that the competitive market is failing to procure generation resources of all types. There are currently many issues that are restricting competitive generation resource development of all types. We detail many of these below.
1. Perhaps the most difficult to overcome are siting and permitting rules that increase costs and
delay development. In Vermont, for example, siting requirements for generation resources under Section 248 or Act 250 are especially onerous. Approvals can take years to obtain and potential developments can be easily derailed by opponents. This increases financial uncertainty, raises costs, and reduces the incentive to develop generating resources and supporting infrastructure, whether natural gas pipelines, transmission lines, and so forth.
2. Infrastructure and interconnection issues that differ by state and utility are also problematic.
In some cases, utilities may wish to discourage new resource development because they have their own supply portfolios whose economic value can be reduced when the supply of generating resources increases. Mandatory procurement of renewable resources through long-term contracts can exacerbate this problem by “locking-in” those generating resources for many years, just as under PURPA. As such, local utilities may have an incentive to delay generating interconnection with the utility’s transmission grid to prevent the economic value of such resources from decreasing.
3. Changing RPS rules affect renewable resource development. States have changed those
requirements over time. These changes increase uncertainty and discourage new investment. Again, this issue affects not only renewable resources directly, but also affects development of all generating resources because it increases perceived uncertainty over future regulation and thus the economic value of generating resources. Moreover, in-state RPS mandates are likely to conflict with the “collective” acquisition approach proposed by NESCOE.
4. Property tax assessments that tax energy production disincent new generating resources. For
example, if a state wishes to incent solar development, but then punitively increases property taxes paid by a solar developer (whether utility scale or distributed), that clearly reduces the incentive to develop resources.
5. Alternative compliance payments that cap the maximum prices for renewables, and
uncertain and discontinuous treatment of renewable incentives, such as feed-in tariffs, also increases uncertainty and reduce the incentive to invest
Exelon believes that no generating resources—whether fossil or renewable—should be subsidized, even though Exelon itself has developed renewable generating resources. Instead, Exelon believes that robust competitive markets provide accurate market signals to incent new generating resources and allocate risks away from captive ratepayers. Rather than further distorting competitive markets, as the RFP Plan will do, Exelon respectively suggests that the New England states resist the urge to “do something” about renewable generation development and let markets work.
Thank you for this opportunity to comment.
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