The filing triggers a complex, multi-forum struggle among creditors, energy providers, and many other diverse stakeholders.  The impact of the restructuring process will be far reaching, jeopardizing compensation to wildfire victims, the state's implementation of its ambitious climate and renewable energy policies, and the ultimate future of the utility as a partner in those efforts.

2017 and 2018 Northern California Wildfire Liabilities

Although California has always experienced wildfires, due to the trifecta of climate change-induced drought and excessive heat, poor forest health caused by bark beetle infestation, and increasing encroachment of development into the urban wildland interface, the past two fire seasons have been the most calamitous in California's history.

PG&E's significant liability exposure for wildfire damages is rooted in the California constitutional doctrine of inverse condemnation, which subjects privately-owned public utilities to strict liability when their equipment is a substantial cause of a plaintiff's damages.[1]  Investigations by the California Department of Forestry and Fire Protection (Cal Fire) into the 2017 Northern California wildfires implicated PG&E equipment as the cause with respect to a majority of the fires, although Cal Fire recently concluded that PG&E equipment was not the cause of the most destructive of them, the Tubbs Fire.

And while Cal Fire has yet to determine the cause of the devastating 2018 Camp Fire, which wiped most of the town of Paradise off the map, according to PG&E's own Form 8-K filing, utility equipment in the vicinity of the ignition point experienced problems shortly before the fire began and damage was observed to a PG&E transmission line later that day.Thus, despite Cal Fire's report on the Tubbs Fire, PG&E continues to face tens of billions of dollars in potential wildfire liability (before accounting for punitive damages, fines, or penalties), while possessing insurance coverage of an order of magnitude less.  Coupled with the prospect that the California Public Utilities Commission (CPUC) will ultimately disallow recovery of those costs from the utility's ratepayers, as it has in another case, these risks pushed the utility to the brink.

Stopping short of altering the doctrine of inverse condemnation, the California Legislature enacted Senate Bill (SB) 901 in 2018 due to the then-unprecedented level of damages and costs stemming from the 2017 fires.  SB 901 allows for securitization of 2017 liabilities in excess of what the utility can bear and changes the regulatory framework for consideration of whether post-2019 wildfire liabilities should be borne by the utilities' shareholders or ratepayers.SB901没有处理与2018灾难野火相关的责任问题,2018野火签署后短短数周开始。After the CPUC instituted a rulemaking to implement SB 901 that the utility believed would postpone its ability to securitize costs for the 2017 fires for several years, PG&E concluded that bankruptcy was the only viable option and in the best interests of all stakeholders.

PG&E's bankruptcy filing creates significant uncertainty for wildfire victims: PG&E announced just days before filing that it would stop paying negotiated settlement amounts to victims of the 2015 Butte Fires.  Due to the effect of the automatic stay, victims of the 2017 and 2018 fires are now barred from prosecuting their claims against PG&E in state court.As a consequence, regardless of where they are liquidated, the claims of victims of the state's deadliest wildfires are subject to the rules and statutes applicable to creditor recoveries in bankruptcy.

The Risk to Renewable Energy Contracts

Other than the wildfire victims, perhaps no group of stakeholders has received more attention from the Governor's office and Legislature than the renewable energy generators who provide the power needed for PG&E to meet its obligations under the California's Renewables Portfolio Standards (RPS) Program and climate change mandates.

Many of these power purchase agreements (PPAs) are now significantly above market rates, as the price of procuring renewable energy resources has declined precipitously in recent years.  At the same time, PG&E has experienced a substantial decline in demand for renewable energy due largely to the departure of its customers to Community Choice Aggregators (CCAs) within its service territory.  CCAs are projected to serve a significant and increasing percentage of load within PG&E's service territory in the near future, resulting in a corresponding reduction in PG&E's obligation to procure renewable energy resources to meet the RPS.  Although PG&E may still seek to reject many of its renewable energy PPAs or renegotiate them at lower rates under the threat of rejection, PG&E said in its filing with the court that it has not made "any decisions yet regarding whether to assume or reject any PPAs ...s/sanluisobispo.com/news/local/article22496960.htmlOnly a few days later, FERC granted the requested relief on January 25 and January 28, asserting that it has "concurrent jurisdiction" to review disposition of wholesale contracts and that its "approval is required" for PG&E to reject wholesale PPAs.  As FERC acknowledged in its orders, however, the jurisdiction issue is unresolved and has been decided differently by a federal appeals court and two district courts, with one of the district court decisions currently on appeal.

Along with its Chapter 11 filing, PG&E also commenced an adversarial proceeding requesting a declaratory order that the bankruptcy court has exclusive jurisdiction over its rejection of contracts and that it is not required to seek or obtain FERC approval of any rejection of its contracts.  PG&E also asked the bankruptcy court to enforce the automatic stay provisions of the bankruptcy law and enjoin FERC from enforcing its orders in the NextEra and Exelon cases.  FERC will almost certainly oppose PG&E's filings, as it has done in the First Energy bankruptcy pending in the Sixth Circuit.FERC must file its answer by March 5 in the Adversary Proceeding before the bankruptcy court, and the court has scheduled a status conference on the automatic stay motions for March 26.  The resolution of this jurisdictional dispute will have significant implications for renewable energy providers that are party to contracts with PG&E, with the potential for FERC to act as a significant check on PG&E's ability to reject and renegotiate its contracts.

Impacts May Ripple Broadly Across the Energy Sector

Beyond the impacts on renewable energy providers, PG&E's January 29 filing may result in potential financial exposure and disruption for a diverse group of stakeholders, including:

• CAISO market participants, which may be required to fulfill PG&E's share of grid management payments in the event PG&E defaults and its collateral is exhausted.
• CCAs, for which PG&E continues to manage customer billing and transfer of customer payments back to the CCAs, which may face interruptions in cash flow as payments are held up as a result of the bankruptcy filing.
• Electric vehicle charging infrastructure investments, which, while already authorized by the CPUC, may face delays or suspension as the bankruptcy process continues to unfold and other issues and expenditures are prioritized.
• Producers and consumers of energy, who may need to take up the slack and achieve even deeper reductions in their own emissions to keep the state on track towards its climate targets if PG&E should default on its expected share of reductions.

Indeed, the prospect of PG&E halting its heavy investments in energy efficiency, transportation electrification, electric system decarbonization and grid modernization could realistically put the state's attainment of its ambitious climate goals at risk.  More broadly, due to California's outsized role in climate change mitigation, the outcome of the Chapter 11 case could realistically influence the progress that other states and subnational jurisdictions are making to address climate change and decarbonize their energy sectors.

[1] See Cal.康斯特艺术I,§19em>Barham v南卡尔市Edison公司 ,74CalApp.4th744,753 (1999) (控股私有电商为公有实体逆判)

Carbon pricing is seen by many as an effective means of reducing carbon dioxide (CO₂) emissions from electricity generation.  California and several Eastern states have enacted "cap and trade" emission allowance programs, which have forced generators in those states to pay a price for their CO₂ emissions.  With the Obama Administration's Clean Power Plan not being implemented, there is currently no federal policy in place that would result in carbon pricing for electricity.  In a singular proposal, acting without any state or congressional mandate, but with the support of State regulatory agencies, the New York Independent System Operator (NYISO) proposes to require carbon pricing for all power sold in New York State through the NYISO wholesale electricity market.  For the first time, the Federal Energy Regulatory Commission (FERC) will be called upon to decide whether and how carbon pricing may be incorporated into wholesale electricity market tariffs solely under the authority of the Federal Power Act.

The NYISO carbon pricing proposal must be fully developed and vetted through a stakeholder process that could take one to two years to reach consensus on a tariff amendment that would be submitted to FERC for review and approval.  This stakeholder process and the subsequent FERC proceeding will grapple with complex issues of electricity market design and novel jurisdictional and policy issues.  The outcome of this process could lead to a push for the adoption of carbon pricing in other FERC-regulated organized regional electricity markets throughout the nation.

The NYISO carbon pricing proposal

The NYISO proposes to fix the price of carbon emissions from electricity generation at the "social cost of carbon," which is a measure developed by federal agencies and endorsed by New York State agencies.  The social cost of carbon is more than triple the recent market price of CO₂ allowances in state cap and trade programs.

The NYISO operates auction-based wholesale electricity markets, which establish market-clearing prices that all suppliers receive and all wholesale purchasers pay.  Suppliers submit bids to the NYISO to provide quantities of electricity at different prices and the highest-priced offer that is needed and accepted to meet electricity demand in each hour sets the single market-clearing price for that hour.Under competitive market conditions, market clearing prices are determined by the marginal costs of production (i.e., generators' fuel costs) of the last increment of supply that clears the market.  Today, suppliers' bids include emission allowance costs, but these are a fraction of the social cost of carbon.  The NYISO's carbon pricing proposal would require that all suppliers' bids include the social cost of carbon of all of the CO₂ emissions from in-state generation resources that would supply the quantity of power the bids require.

To the extent carbon-emitting resources set the market-clearing electricity price, which they are likely to do for much of the foreseeable future in New York State, electricity prices paid by retail utilities and energy service providers will rise substantially.  Some experts predict NYISO wholesale electricity prices could increase by between 50 and 75 percent, although much of the price increase is proposed to be rebated to consumers.  Zero-carbon resources, such as wind, solar and nuclear facilities, will receive the full market clearing price.  Carbon-emitting resources, such as coal and natural gas facilities, will have their carbon costs deducted from their market revenues.  The aggregate difference (referred to as "Carbon Residuals") between amounts the NYISO collects from all wholesale purchasers and amounts paid to suppliers (reflecting the carbon charge to suppliers) would be rebated in some manner to retail customers.

Jurisdictional and Market Design Issues

Does the Federal Power Act authorize carbon pricing?In the absence of a state or other federal law that imposes carbon costs on electricity generators, FERC and the courts will need to decide whether, acting solely under the authority of the Federal Power Act, FERC may approve and establish the imposition of a carbon price adder on all electricity sold under an ISO tariff.  Some may challenge the carbon price adder as a ‘tax" that must be enacted by Congress or as an environmental measure beyond the jurisdiction of an economic regulator such as FERC.  Others will defend the proposal as a "just and reasonable" measure necessary to establish economically efficient and non-discriminatory wholesale electricity markets.  Conversely, it may be argued that the absence of a carbon price is a "practice affecting wholesale electricity rates" that is discriminatory and unjust and unreasonable, which must be corrected by FERC under the Federal Power Act.

Who sets the carbon price?NYISO建议纽约公共服务委员会确定碳的社会成本,部分依赖自此由s/www.whitehouse.gov/pative-actions/presidential-destruction-promoting-Energy-evenity-NYISO建议只对COsub>2 生成设施燃烧排放量强制规定碳价,但其他人可能建议碳社会成本应反映与燃料提取和运输相关的上游碳排放量(包括甲烷)。

Under the Natural Gas Act (NGA), FERC certificates the construction and operation of pipelines to transport natural gas in interstate commerce if they are "required by the present or future public convenience and necessity."  For almost two decades, FERC has used a 1999 policy statement's guidelines to evaluate whether new pipelines meet that statutory standard.  The use of natural gas has been steadily growing, and in 2017 FERC certificated over 2,700 miles of new interstate pipelines, the highest annual level in history.

Now FERC is conducting a top-to-bottom review of the 1999 guidelines and issued a Notice of Inquiry (NOI) requesting public comments on whether and how they should be revised.  The outcome of FERC's review could have a significant impact on the development and transportation of shale gas, and the availability of new pipeline capacity to serve increasing demand from gas-fired electricity generators and LNG export facilities.

The 1999 policy statement 

The policy statement sets out the analytical steps the Commission takes in evaluating a new pipeline application.  If the applicant has existing pipeline customers, the threshold issue is that the project must be able to proceed without subsidies from those customers.  This usually means that the project would be incrementally priced.

FERC then conducts what it calls an "economic test" by balancing evidence of the new pipeline's public benefits against its adverse effects.  FERC determines whether there are any adverse effects on (1) the existing customers of the pipeline proposing the project, (2) existing pipelines in the market and their captive customers, or (3) landowners and communities affected by the new pipeline's route.  If there are, the Commission may identify conditions that it could impose on the certificate that would minimize or eliminate the adverse impacts.

Where there are residual adverse impacts, an applicant must show a project's public benefits that are proportional to the project's adverse impacts.  Examples of public benefits are meeting unserved demand, eliminating bottlenecks, access to new supplies, lower costs to consumers, providing new interconnects that improve the interstate grid, providing competitive alternatives, increasing electric reliability, or advancing clean air objectives.

Applying the guidelines to certificate applications over the years, FERC has shown flexibility.  For example, the NOI notes that as evidence of unserved demand, applicants have most often presented precedent agreements with prospective customers for long-term firm service, and the Commission has accepted those customer commitments as the principal factor in demonstrating project need.

A pipeline application for certification also triggers environmental review under the National Environmental Policy Act (NEPA).FERC审查探讨对各种环境资源的影响,包括地质学、土壤、地下水、地表水、水生资源、植被、野生生物、特殊状态物种、文化资源、土地使用、娱乐、美学、社会经济学、空气质量、气候变化、噪声和可靠性安全性。

NOI指出,过去十年中,联邦承认部落、受影响的土地所有者和环境组织参与拟议的天然气项目进程显著增加。他们的关注主要集中在新项目需求、替代物、累积影响以及与天然气生产和消费相关的影响上,尤其是温室气体排放对全球气候变化的推波助澜问题。变化包括:(1)天然气生产技术革命导致生产和生产区剧增(2) 客户在项目编程阶段例行承诺公司服务的长期先例协议增加使用天然气发电(4) 土地所有者和社区可能受拟议项目影响的更多关注和(5) 增加对环境冲击的兴趣。

This is the second post of three on this blog providing short summaries of the generic electricity policy initiatives already teed up and awaiting possible action by the newly-constituted FERC.  Together, these three posts describe initiatives that address fundamental market and resource issues spanning a broad range of FERC's electricity authorities.

Today's post summarizes initiatives affecting new transmission development, generator interconnection and access to the market by qualifying facilities, also known as QFs.  The first post addressed initiatives affecting wholesale market rules.  The third post, in a few days, will deal with FERC initiatives concerning analytic issues.

Competitive transmission development

In Order No.1000, FERC paved the way for new transmission companies that would compete with incumbents for the right to install new transmission resources by directing the RTOs to establish competitive processes.  Since then, market participants have expressed a variety of concerns regarding perceived inadequacies in the competitive processes RTOs have implemented.

To air these concerns,  FERC held a two-day conference in June 2016.  The major issues addressed at the conference included:

• Cost containment provisions in offers to develop new transmission, including how transmission planning regions evaluate such proposals and whether rates that include cost containment provisions and result from a competitive process should be presumed to be just and reasonable.
• Incentives and competitive transmission development, including whether incentives are needed to encourage developers to participate in competitive processes, the relationship between cost containment provisions and incentives, and whether there are alternatives to return-on-equity adders for projects subject to competitive development processes.
• Interregional transmission coordination and competitive transmission development, including how interregional coordination processes interact with regional planning processes.

Post-conference comments have been filed.  The Commission has not indicated how it will address the concerns aired in this conference.

Reform of generator interconnection procedures and agreements   

In a December 2016 Notice of Proposed Rulemaking, FERC found that 1) aspects of the current interconnection process for large generators (larger than 20 MW) may hinder the timely development of new generation!2) 互连研究过程可能导致不确定性和不准确信息and 3) interconnection processes may be discriminatory with respect to new technologies entering the generation market.

Accordingly, FERC proposed reforms that fall into three broad categories.

The first category is improved certainty by giving interconnection customers more predictability in the interconnection process.  Proposals include:

• Require transmission providers to set a schedule for conducting restudies.
• Allow the interconnection customer to unilaterally exercise the option to build.
• The transmission owner/provider and an interconnection customer must agree before the transmission owner/provider may elect to initially fund network upgrades.
• RTOs/ISOs must have dispute resolution procedures that allow a party to unilaterally seek dispute resolution.
• Set a cost cap to limit an interconnection customer's network upgrade costs.

The second category is improved transparency by providing more information to interconnection customers.   Proposals include:

• Require transmission providers to provide detailed information and models used for interconnection studies.
• Revise the definition of a "Generating Facility" to include electric storage resources.
• Set timeframes for transmission providers to report on their completion of interconnection studies.

The third category is an enhanced interconnection processes.  Proposals include:

• Allow customers to request a level of interconnection service that is lower than the generating facility's capacity.
• Provisionally allow new generating facilities to interconnect pursuant to existing and updated studies while needed additional studies are completed.
• Allow interconnection customers to utilize or transfer surplus interconnection service at existing generating facilities.
• Transmission providers must evaluate if their methods for modeling storage resources for interconnection studies account for the operational characteristics of those resources.

Comments on the proposals have been filed.   Although the timing of further Commission action on this proposal is uncertain, FERC has been engaged in a steady march over several years aimed at perfecting its generator interconnection rules.

Implementation issues under PURPA

In June 2016, FERC held a conference regarding the Commission's implementation of the Public Utility Regulatory Policies Act  (PURPA).

Two major issues were aired at the conference.  The first was utilities' obligation to purchase QF power in light of changes in electricity markets since the enactment of PURPA in 1978, long before the introduction of competitive generation and open access to the grid.  A concern of some utilities is that in order to be released from the purchase obligation they must rebut a presumption that QFs sized 20 megawatts and below do not have nondiscriminatory access to competitive organized wholesale markets.

The other major issue was avoided cost calculations that determine QF pricing, including whether an avoided cost methodology may reflect the locational and/or time value of QF output.

Post-conference comments have been filed.   As well-structured wholesale electricity markets have become more prevalent, the Commission's rules for market access by QFs have continued to evolve as well.  The concerns raised at the conference may lead to further rule changes.

With two new Commissioners confirmed by the Senate and sworn in, FERC's seven-month period without a quorum is over and it can get back to business.  And with another two nominations now before the Senate with a hearing scheduled for September 7, the agency should be at full strength within the next few months and ready to take on important policy issues.

There are quite a few critical generic electricity policy initiatives already teed up and awaiting Commission action.   Together, the initiatives address fundamental issues spanning a broad range of FERC's electricity authorities.  Over the course of three posts, this blog will provide short summaries of those initiatives.  Today's post addresses initiatives affecting wholesale market rules.  The second post, in a few days, will summarize initiatives affecting new resources development and entry issues.  The third post will deal with FERC initiatives concerning analytic issues.

Of course, the new Commission may have other electricity policy priorities in mind.  Hence, it is difficult to predict whether or how the Commission will address these initiatives.  Nonetheless, Commission staff has no doubt already done a good deal of spade work on these policy questions and Commission action is possible over the next few months.

State policies and the eastern organized wholesale markets

New generation resources in the states served by the PJM and New England RTOs and the New York ISO are selected for wholesale capacity and energy payments through competitive auctions in those organized markets.  Those with the lowest-prices offers are selected.  However, states in these regions want certain types of resources developed to meet certain state policy objectives.  These resources may not be the lowest cost and may receive state subsidies, thereby creating tension with the basic RTO market design that is based on least cost principles.

FERC opened a proceeding (AD17-11) to discuss how the competitive wholesale markets, particularly the eastern organized markets, can select resources of interest to state policy makers while preserving the benefits of regional wholesale markets and economic resource selection by the RTOs.  The Commission held a two-day conference in May 2017.  Some of  the issues raised were:

• The features of the existing RTO market design that should be modified to meet specific state and region policy goals.
• Ways to achieve state or regional policy objectives within the RTOs centralized energy and capacity markets.
• The consequences for wholesale markets, as well as for market participants' ability to make long-term decisions, of continued state financial support for certain resources outside wholesale markets.

One of the thorny issues here is what is known as the Minimum Offer Price Rule that is applied in the RTO auction markets.  This rule, intended to prevent subsidized resources from lowering market prices and driving out other investments, requires supply offers to be no lower than non-subsidized costs.  The problem is that states view this rule, and others, as preventing them from supporting resources that attain their policy objectives.

FERC requested post-conference comments and invited commenters to address five potential "paths forward."  The paths basically presented  varying degrees of applying the Minimum Offer Price Rule.  FERC also wanted comments on other topics, including the principles and objectives that should guide the selection of a path forward and the degree of urgency for reconciling wholesale markets and state policies.

Intertwined in this proceeding is the boundary between FERC and state jurisdiction.  The Federal Power Act reserves jurisdiction over generation facilities to the states but gives FERC responsibility for prices in wholesale markets.  Last year the Supreme Court set out some guidance on this issue, finding that states may not tread on FERC jurisdiction over wholesale power markets but have some latitude to encourage certain types of generation.  Recently, Federal courts in Illinois and New York found that certain state subsidy programs for nuclear generation facilities did not encroach on FERC's jurisdiction.

Resolving the question of whether or how FERC should defer to state preferences as it seeks to ensure wholesale market integrity is of critical importance to the power industry and consumers.   This area of policy is likely to play out over several months or years in an iterative process involving decisions by FERC, various states, and the federal courts.

FERC may face an additional challenge of harmonizing policy-driven resource selection in the organized RTO markets.  In April, the Secretary of the Department of Energy directed his staff to prepare a study examining electricity markets and the reliability of the U.S.电机系统具体地说,研究是要探讨批发能源和能力市场是否充分补偿属性,如现场燃料供应和增强电网应变能力的其他因素,如果不是的话,这将影响电网未来可靠性和应变能力的程度The report, not yet issued, may propose policy changes to protect baseload generation resources (i.e., nuclear, coal and natural gas-fired power plants).   Any such proposals are likely to be controversial.   Given that DOE has limited authority over wholesale electricity markets, it will be left to the new FERC to grapple with whether or how to implement DOE's proposals in the organized and bilateral wholesale markets.

Electric storage participation in markets operated by RTOs and ISOs

FERC has expressed concern that, as the capabilities of electric storage resources and distributed energy resources continue to improve and their costs continue to decline, such resources may face barriers that limit them from participating in organized wholesale electric markets.  Accordingly, FERC issued a Notice of Proposed Rulemaking in November 2016 intended to knock down barriers to storage resource participation.  The proposed rule would require each RTO and ISO to revise its tariff in two ways:

• Establish market rules that recognize the characteristics of storage resources and accommodate their participation so that those resources no longer have to participate in the markets under rules designed for other types of resources.
• Allow distributed energy resource aggregators to participate in the markets so that individual resources can satisfy operational and other requirements that they could not meet on a stand-alone basis.

Because storage and other distributed resources may be located on local distribution systems regulated by state and local authorities, the proposal raises issues regarding the boundaries of state and federal jurisdiction, such as:

• Whether FERC may force states to allow retail customers to bypass retail programs and participate directly in the wholesale market.
• Whether states should be able to opt-out of allowing wholesale market participation of electric storage resources.
• Whether states will lose jurisdiction over storage resources participating in wholesale markets — given FERC's exclusive jurisdiction over wholesale sales.
• Given that FERC does not have jurisdiction to regulate local distribution systems, how will local distribution system reliability be maintained?

Comments on the proposed rule have been filed.

Use and compensation of electric storage resources in organized markets

Storage resources can be used to provide both what are traditionally classified as transmission services as well as standard wholesale electricity services, and they may even  provide different types of service simultaneously.  How these services are classified can have important implications for pricing in the markets.  FERC policy now applies quite different pricing policies to these different services.  Transmission service compensation is limited to cost-based rates because such service is usually provided by a monopoly transmission operator.  In contrast, generation services in wholesale markets are generally allowed unlimited pricing flexibility.  Thus, defining what storage-provided services may be classified as transmission, generation, or both, is important.

FERC held a technical conference in November 2016 and then received comments aimed at distinguishing between these services.  The conference also addressed a number of operational and compensation issues associated with storage resources, such as:

• The operational implications of using storage resources as both transmission assets and as providers of other wholesale electricity services, such as power sales.
• The types of resources that can provide simultaneous services, and how those services should be priced and considered in grid planning models.
• The potential for quickly deployable storage resources to compete to supplant uneconomic traditional generators needed to meet reliability needs.

FERC has not indicated how these issues will be addressed in future policy determinations.  Nonetheless,  paving the way for full participation in wholesale markets by innovative storage resources would be an important step by FERC.

Fast-start pricing in markets operated by RTOs and ISOs

A fast-start resource can start up in 10 minutes or less and has a minimum run time of one hour or less.快速启动资源有价值,因为它们通常是实时投放,非常接近需要时,并快速响应意外系统需求。

WhileRTOs和ISOs开发了一些快速启动资源定价元素,FERC表示担心这些做法可能产生不反映快速启动资源价值和不为高效投资提供奖励的价格。ferc.gov/whats-new/comm-meet/26/1216/E-2.pdfAmong other things:

• Fast-start pricing must be applied to any fast-start resource committed by the RTO/ISO that submits economic energy offers to the market and must be used in both day-ahead and real-time markets.
• A committed fast-start resource's commitment costs, i.e., start-up and no-load costs, must be included in energy and operating reserve prices during the fast-start resource's minimum run time.
• An RTO/ISO must relax the economic minimum operating limit of fast-start resources and treat them as dispatchable from zero to their economic maximum operating limit for calculating prices.

Comments on the proposal have been filed.

*    *    *

The initiatives described above are aimed at ensuring that wholesale market policy evolves to keep up with changes in the marketplace.  How FERC should deal with state generation preferences that affect wholesale markets is a question that looms large and cannot be ignored by the Commission.   Clearing out unnecessary barriers to market participation by innovative resources is similarly of critical importance.    The new Commission will have the opportunity to deal with these and other pressing wholesale market policies.

Entergy's large transmission system and five operating companies in Louisiana, Arkansas, Mississippi and eastern Texas have been integrated into the Midcontinent Independent System Operator (MISO).  This extends MISO's footprint to 15 states from Canada down to the Gulf of Mexico, making MISO the largest Regional Transmission Organization (RTO) by geography.  The integration adds about 18,000 miles of transmission lines and 40,000 MW of generation to the MISO footprint.

Both MISO and Entergy have described the customer benefits that joining MISO will provide, including an estimated $1.4 billion in cost savings for customers and associated operational efficiencies.  A number of other transmission owners and market participants in the Entergy region joined MISO as well, riding the coat tails of Entergy.

RTOs such as MISO dispatch generation, operate day-ahead and real-time energy and ancillary services markets, control the transmission grid and maintain reliability over a defined region.  As a general matter, increasing the geographic scope of the RTO increases dispatch efficiencies and provides benefits to customers and other market participants.  In orders issued by FERC more than a decade ago that defined the RTO concept, FERC specified large regional scope as an important feature that would enhance the value of the RTO as a grid manager and market operator.  At FERC's December 19 public meeting, Acting Chairman LaFleur and Commissioners congratulated MISO and Entergy on the successful integration.