West Virginia electric utilities offer discount for new or expanding businesses

Two electric utilities serving customers in West Virginia have announced a new discounted "incentive rate" to attract new businesses and grow existing businesses.

Appalachian Power Company and Wheeling Power Company announced on February 14, 2019, that they are are offering discounted rates for electric service to new or expanding businesses meeting defined standards. The discount reduces qualifying customers' incremental billing demand by 40% for a 5-year term. The utilities are offering this new rate to new or existing customers who establish at least 500 kilowatts of new demand for electricity and meet criteria including creating at least 10 jobs or investing at least $2.5 million in an expansion in West Virginia.

The announcement follows a January 29, 2019 decision by the Public Service Commission of West Virginia to approve the companies' "Economic Development Rider" tariff proposed by the utilities in a November 28, 2018 filing. According to the Commission, the discounted rate is "experimental in nature" and is limited in size to an aggregate of 250 megawatts for the companies. As approved by the Commission, the rate will impose no incremental rate burden on any of the companies' West Virginia retail customers, and should result in a net contribution to defray the companies' fixed costs.

According to the Commission's order, the discounted rate will not be available in instances where there is "simply a change in ownership of existing customer operations", where operations are merely relocated within the companies' services territories, or where increases in demand result from the resumption of normal operations following abnormal operating conditions. The rate is also unavailable to "business facilities engaged in the retail sale to the average customer of consumer or final goods" due to concerns that adding new customers engaged in competitive retail sales of consumer goods would increase the "likelihood that the new load will displace an existing load with the net result being zero benefits."

The Commission noted the companies' expectation that the rate "will serve as an inducement for economic development in the West Virginia service territories of the Companies" and that "the resulting economic development will be beneficial to the West Virginia retail ratepayers of the Companies and to the economy of West Virginia."

Appalachian Power and Wheeling Power are subsidiaries of American Electric Power. AEP Appalachian Power has 1 million customers in Virginia, West Virginia and Tennessee.

Report: 50 GW US electric storage potential

A recently adopted federal regulation aimed at helping electric storage resources participate in wholesale electricity markets could unlock 7,000 megawatts of storage potential -- or up to 50,000 megawatts if all benefits can be captured through state and federal action -- according to a report by consulting firm The Brattle Group.

The study is titled, “Getting to 50 GW? The Role of FERC Order 841, RTOs, States, and Utilities in Unlocking Storage’s Potential.” Released on February 22, 2018, the report concludes that electric storage market potential could grow to 50,000 MW within the next ten years, if storage costs continue to decline and state and federal regulatory policies continue to be supportive.

The Brattle report comes one week after the Federal Energy Regulatory Commission's issuance of Order No. 841, a final rule aimed at removing barriers to the participation of electric storage resources in wholesale markets operated by regional transmission organization and independent system operators. The Brattle report describes Order 841 as "an important step in unlocking the value in wholesale energy, ancillary services, and capacity markets," noting the consulting firm's finding that at least half of storage's total possible value can be achieved in wholesale electricity markets.

Crucially, the Brattle study finds that fully realizing the value of electric storage will require state policy reforms similar to those at the federal level. Generally speaking, wholesale electricity sales and interstate transmission are subject to federal jurisdiction, while retail sales and local distribution are subject to state jurisdiction. This split jurisdiction means that some value streams available through battery storage can be only captured at the state level -- for example benefits from deferring or avoiding investments in transmission and distribution infrastructure by using storage as a non-transmission alternative, or customer benefits like increased reliability and engagement with power supply.

Storage can also save customers money -- as noted in the report, avoiding retail rate demand changes is one of the primary business drivers for storage deployment by U.S. commercial and industrial customers. But these values can only be fully captured through state action to remove the barriers that remain.

Some states are acting to incentivize or require energy storage investments. California set a mandate of 1,325 megawatts of storage by 2020, and Oregon and Massachusetts have also set state storage mandates.

The report also covers implications for existing storage resources, most of which are hydropower. It finds that existing storage resources can provide substantial new capabilities, if they can be operated more flexibly than today. As noted in the report, "Increasing flexibility of existing hydro can be very valuable, reducing the need for new investments." The report also suggests that optimizing operating strategies could increase storage revenues by 2 to 5 times.

Maine 2017 solar, energy legislative proposals

The 128th Maine Legislature's first session kicked off last month in Augusta.  Over 2,000 legislative requests or proposed bills were submitted for the 2017 session, most of which will eventually be "printed" or released to the public as bills or "Legislative Documents."  Energy items on this session's docket are expected to include a variety of bills addressing solar energy.  While most of these bills have yet to be printed, energy-related bills that have been printed so far include items related to protecting the grid against geomagnetic disturbances and electromagnetic pulses, consumer protection in the form of limits retail electricity rates, and retooling the Governor's energy office:

• LD 255, An Act To Implement Electric Grid Reliability Recommendations: as drafted, this concept draft proposes directing the Maine Public Utilities Commission to take certain actions regarding geomagnetic disturbances and electromagnetic pulses on the State’s electric grid, including installation of equipment to enable grid monitoring and protection. 
• LD 259, An Act To Limit Rates Charged by Competitive Electricity Providers: as drafted, this bill would prohibit competitive electricity providers from charging a residential consumer a rate for generation service that is higher than the applicable standard-offer service rate.
• LD 260, An Act to Create the Maine Energy Office: as drafted, among other changes this bill would revamp the Governor's Energy Office into a Commissioner-led office, with funding from Efficiency Maine Trust.

Beyond the bills that have been printed so far, a list published by the Legislative Information Office of bill titles organized by subject matter shows 12 legislative requests relating to solar energy:

• LR 19, An Act To Encourage and Support Solar Energy for Use in the Private and Public Sectors 
• LR 34, An Act To Grow Maine's Economy through Increased Solar Power Generation
• LR 179, An Act To Enhance the Commercial Development of Solar Energy
• LD 394, An Act To Modernize Maine's Solar Power Policy and Encourage Economic Development
• LR 402, An Act To Promote the Development of Solar Energy in Maine
• LD 529, An Act To Modernize Maine's Solar Power Policy and Encourage Economic Development
• LR 1071, An Act To Protect and Expand Access to Solar Power in Maine
• LR 1367, An Act Regarding Solar Power for Farms and Businesses
• LR 1424, An Act To Advance Locally Owned Solar Energy Systems
• LD 1425, An Act To Modernize Community Solar Policy
• LR 1856, An Act Regarding Large-scale Community Solar Procurement
• LD 1944, An Act To Address Solar Power in Maine 

The Joint Standing Committee on Energy, Utilities and Technology will hold public hearings on bills referred to it over the course of the session.  

NY considers ESCO reforms

New York utility regulators have launched consideration of reforms to how retail electricity suppliers called energy service companies or ESCOs operate in that state.  A December 2, 2016 notice issued by the New York Department of Public Service describes a history of "substantial overcharges and deceptive practices by the ESCO industry harming New York consumers," and establishes a process to "push ahead with reforms to ensure that ESCOs provide useful, value-added, economical services to New York consumers."  New York's ESCO reform process will play out in conjunction with other state initiatives, such as the Reforming the Energy Vision program.

As described in the Notice of Evidentiary and Collaborative Tracks and Deadline for Initial Testimony and Exhibits, the New York Public Service Commission initially opened up the energy services market to retail competition "to spur innovation in the creation of value-added products, particularly energy efficiency services that regulated rates may not provide, and to create commodity price competition that would result in efficiencies."  The notice summarizes the regulatory philosophies driving the historic decision to separate monopoly services (transmission and distribution) from competitive services (energy commodity), and the expectation that robust competitive markets would yield societal benefits.

But based on its "considerable experience with the offering of retail service to mass market customers by ESCOs," in 2014 the Commission determined "that the retail markets serving mass-market customers are not providing sufficient competition or innovation to properly serve consumers."  In the Commission's view, its subsequent efforts to realign the retail market have not succeeded: "customer abuses and overcharging persist, and there has been little innovation, particularly in the provision of energy efficiency and energy management services.  Commodity price differentiation has not worked, and the market for differentiated services is immature or non-existent."

For these reasons, on December 2, 2016, the Commission gave public notice that it "continues to examine measures that must be taken to ensure that these customers receive valuable services and pay just and reasonable rates for commodity and other services."  Among the measures identified for consideration by the Commission are:

• whether ESCOs should be completely prohibited from serving their current products to mass-market customers;
• whether the regulatory regime, rules and Uniform  Business Practices (UBP) applicable to ESCOs need to be modified to implement such a prohibition, to provide sufficient additional guidance as to acceptable rates and practices of ESCOs, or to create enforcement mechanisms to deter customer abuses and overcharging, including whether the Commission decision not to subject ESCOs to Article 4 of the Public Service Law should be revisited; and
• whether new ESCO rules and products can be developed that would provide sufficient real value to mass-market customers such that new products could be provided to them by ESCOs in the future in a manner that would ensure just and reasonable rates.

To pursue these efforts, the Commission established two procedural tracks.  An evidentiary track will consider the first two bullets listed above, while a "collaborative" track will focus on the third bullet. 

The Commission has previously described ESCO reforms as supportive of New York's Reforming the Energy Vision initiative, a comprehensive revisioning of the state's electricity sector.  In a February 2016 order, the Commission noted, "Development of markets in which vendors offer innovative services of value to consumers, and in which consumers can participate with confidence, is critically important to the success of the Reforming the Energy Vision (REV) initiative. Retail energy markets focused on commodity-only products, and in which ESCOs do not meet expectations of many customers, will thwart these objectives."

Initial pre-filed testimony and exhibits for the Track I evidentiary case on ESCO reforms are due on or before April 7, 2017.

Court ruling cuts demand response uncertainty

Yesterday the U.S. Supreme Court issued an opinion upholding federal regulation of the compensation paid for wholesale electricity demand response.  The Court's opinion, FERC v. Electric Power Supply Assn., hinges on the distinction between wholesale and retail sales of electricity.  It provides the latest look at the boundary between federal and state jurisdiction over the electric grid.

Under the Federal Power Act, the Federal Energy Regulatory Commission is authorized to regulate "the sale of electric energy at wholesale in interstate commerce."  Its jurisdiction under the Federal Power Act does not extend to "any other sale of electric energy," such as a retail sale.  Traditionally, sales of energy directly to users are viewed as retail sales subject to state ratemaking jurisdiction, while sales of energy for resale are viewed as wholesale sales subject to federal ratemaking jurisdiction.

The case before the Supreme Court arose from a challenge by a group of generators to FERC Order No. 745.  Through that order, FERC adopted a rule requiring wholesale market operators to compensate cost-effective demand response resources for their performance at the same price paid to generators.  Last year, the D.C. Circuit Court of Appeals vacated FERC Order No. 745 on the ground that FERC lacked jurisdiction to set rates for this kind of demand response.  The D.C. Circuit implied that "wholesale" demand response was really retail in nature and thus subject only to state ratemaking jurisdiction.  FERC appealed this decision to the Supreme Court.

As described in the Supreme Court opinion, the appeal presented two legal issues:

First, and fundamen­tally, does the FPA permit FERC to regulate these demand response transactions at all, or does any such rule impinge on the States’ authority? Second, even if FERC has the requisite statutory power, did the Commission fail to justify adequately why demand response providers and electricity producers should receive the same compensa­tion? The court below ruled against FERC on both scores. We disagree.

In analyzing the first issue, the majority found that compensation for demand response directly affects wholesale prices -- "Indeed, it is hard to think of a practice that does so more."  The majority found, "A FERC regulation does not run afoul of section 824(b)’s prescription just because it affects―even substantially―the quantity or terms of retail sales."  The Court finally noted that FERC had offered substantial reasoning and arguments in support of its conclusion that demand response should be paid comparably to generation, and thus that FERC's actions satisfied the applicable standard that they not be "arbitrary and capricious."

The case now returns to the D.C. Circuit for further proceedings consistent with the Supreme Court's opinion. The most widespread direct impact of the Supreme Court in FERC v. EPSA will likely be a reduction to the uncertainty that has hung over the markets since the D.C. Circuit decision.  Market participants, consumers, aggregators, and grid operators have all been awaiting the ruling.  Some market changes, such as ISO New England's implementation of full integration of demand response, had been delayed pending a decision from the Court, as regional wholesale demand response programs hinge on FERC approvals under the Federal Power Act.  With the jurisdictional question resolved, these changes, and other refinements to regional transmission organizations' wholesale demand response programs, can now get back on track.

US Supreme Court upholds wholesale demand response

The Supreme Court of the United States has issued an opinion upholding regional electricity grid operators' ability to operate wholesale demand response programs under federal authority.  In that opinion, FERC v. Electric Power Supply Assn., the Supreme Court reversed a lower court's decision invalidating the Federal Energy Regulatory Commission's regulation of electricity demand response.   While further evolution of demand response will continue, the Supreme Court's 6-to-2 ruling puts regional wholesale demand response programs back on surer footing after the uncertainty injected by the lower court's previous ruling.  A grid portfolio including some degree of demand response can provide beneficial environmental, reliability, and economic effects compared to pure generation.  It appears relatively more likely that existing regional wholesale demand response programs may continue to operate under federal authority, and relatively less likely that a new state-driven demand response paradigm will arise.

As described in the Supreme Court opinion, wholesale electricity demand response programs pay consumers for commitments to reduce their consumption of electricity during peak demand periods or other times of scarcity or high prices.  For about 15 years, wholesale market operators have increasingly adopted wholesale demand response programs, with the blessing of both Congress and the FERC.  In 2011, the FERC issued its Order No. 745, establishing a rule requiring market operators to pay the same price to cost-effective demand response providers for conserving energy as to generators for producing it. 

But that order was challenged by an association of generators, among others.  In May 2014, the D.C. Circuit Court of Appeals issued a ruling in Electric Power Supply Association v. Federal Energy Regulatory Commission vacating Order No. 745.  Its chief logic was that FERC lacked authority to issue the order on jurisdictional grounds -- because in the lower court's view, Order No. 745 directly regulates the retail electric market.  Under the Federal Power Act, FERC is authorized to regulate "the sale of electric energy at wholesale in interstate commerce," but cannot regulate "any other sale" (i.e. any retail sale) of electricity.

But today's Supreme Court ruling held that the Federal Power Act does provide FERC with the authority to regulate wholesale market operators' compensation of demand response bids.  The Court divided its analysis of this point in three parts.

First, the Supreme Court held that the practices at issue directly affect wholesale rates.  In the Court's words, "Wholesale demand response is all about reducing wholesale rates; so too the rules and practices that determine how those programs operate."

Second, the Supreme Court noted that FERC has not regulated retail sales.  "Here, every aspect of FERC's regulatory plan happens exclusively on the wholesale market and governs exclusively that market's rules.  The Commission's justifications for regulating demand response are likewise only about improving the wholesale market."  Putting the first and second sets of conclusions together, the Court found that the rule established by Order No. 745 complies with the plain terms of the Federal Power Act.

Third, the Court noted that adopting a contrary view would conflict with the core purposes of the Federal Power Act: "The FPA should not be read, against its clear terms, to halt a practice that so evidently enables FERC to fulfill its statutory duties of holding down prices and enhancing reliability in the wholesale energy market."

The Supreme Court also addressed an alternative holding by the D.C. Circuit Court that the Order No. 745 compensation scheme is arbitrary and capricious under the Administrative Procedure Act.  The Supreme Court noted that its "important but limited role" in reviewing FERC's decision "is to ensure that FERC engaged in reasoned decisionmaking."  Noting FERC's detailed explanation of its choice to compensate demand response providers at LMP, the same price paid to generators, and its lengthy responses to contrary views, the Supreme Court held that "FERC's serious and careful discussion of the issue satisfies the arbitrary and capricious standard."

Justice Kagan delivered the Court's opinion, joined by Chief Justice Roberts and Justices Kennedy, Ginsburg, Breyer, and Sotomayor.   Justice Scalia filed a dissenting opinion, in which Justice Thomas joined, noting his belief that the Federal Power Act prohibits the FERC from regulating the demand response of "retail purchasers of power."  Justice Alito did not participate in the case.

The case now returns to the D.C. Circuit for "further proceedings consistent with this opinion." If Order No. 745 stands and FERC retains jurisdiction over the compensation paid to wholesale demand response market participants, it seems likely that existing regional wholesale demand response programs will continue to operate under federal authority.  As the Supreme Court found, these wholesale demand response programs can provide significant consumer savings when properly implemented.  How will demand response continue to evolve in the wake of FERC v. EPSA?  How does this decision reshape the boundary between wholesale (federal) and retail (state) jurisdictions?  What's next for demand response?

Santee Cooper sets solar standby charge

The board of South Carolina's state-owned electric utility has approved a plan to increase retail rates and -- controversially -- add new charges for customers who install solar panels.  Santee Cooper is South Carolina's largest power producer, providing electricity for about 2 million people.  Its interim rider for distributed generation includes a "standby fee" charged to customers with rooftop solar projects and other customer-sited generation.  It also declined to adopt a net metering structure similar to those used by South Carolina's investor owned utilities.

Notably, Santee Cooper says it "supports development of solar power resources".  Its Distributed Generation Approach notes that Santee Cooper has generated solar energy for its customers since 2006, including demonstration projects across South Carolina.  Santee Cooper buys solar power from sources including the 3-megawatt Colleton Solar Farm.  The Colleton project, owned and operated by TIG Sun Energy, is South Carolina's largest solar installation.  Santee Cooper also offers its customers blocks of Green Power.
But residential solar projects aren't typically owned by or developed for utilities.  From the utility perspective, this means that the costs associated with serving customers with solar generation need to be recovered from ratepayers.  But the allocation of those costs among ratepayers is an issue.  Should they fall on all consumers equally?  Or should a rider or specific charge be added to recover these costs from the consumers who install distributed solar generation?

In Santee Cooper's case, the board approved a new charge, called a “standby fee,’’ on residential customers of $4.40 per month per kilowatt of installed solar capacity.  It also elected to use rebates and credits to reward customers for solar generation, instead of a net metering rate.  At the same time, the board set the rates for crediting generation at less than its retail rate.

From the utility perspective, it needed to adjust its rates to account for growth in rooftop solar and other distributed generation resources, and to protect customers who don't develop solar projects from unfairly bearing costs imposed by those who do.   Cost-shifting is a typical utility concern; the issue is to make sure that the allocation of consumer costs is fairly related to how the costs were incurred.
  
But from the perspective of advocates for rooftop solar and other distributed generation resources, a "solar fee" would deter people from developing alternative energy projects.  Under this view, these fees and rate structure are unnecessary and "penalize customers for exercising their right to use this clean, renewable resource."

Santee Cooper is not alone in considering how to adjust utility rates to handle more rooftop solar projects.  But its approach differs from that of South Carolina's largest investor owned utilities, Duke Energy Carolinas and South Carolina Electric and Gas, which have agreed to net energy metering and solar development targets.

How should utility rate design allocate the costs and benefits of connecting distributed solar projects to the grid?  How can essential fairness in ratemaking be balanced against policy values like customer choice and renewable energy?

Maine standard offer prices jump up 23%

The upward trend in wholesale natural gas and electricity prices in New England will begin to hit retail consumers later this summer, based on the bids accepted today by the Maine Public Utilities Commission for standard offer electricity service.

Following Maine’s deregulation of the electric power industry, transmission and distribution utilities no longer sell electricity but merely provide wires enabling the delivery of power. For their energy needs, customers may choose among licensed competitive electricity providers, or may receive so-called “standard offer service” by default. Most residential consumers receive standard offer service, while more than half of the load of medium and large commercial and industrial customers is served by customer-selected competitive providers.

The providers of standard offer service, and the prices customers pay for standard offer service, are selected by the Maine Public Utilities Commission through a competitive process. In deliberations this afternoon, the Commission established new prices for standard offer electricity supply service for medium commercial and industrial customers of Maine’s two largest utilities, Central Maine Power Co. and Bangor Hydro Electric Co. Over a six-month term starting on September 1, 2013, Central Maine Power’s medium commercial and industrial customers taking standard offer service will pay an average price of 7.5 cents/kWh. Bangor Hydro customers will pay 7.45 cents/kWh. These new prices are over 23% higher than current standard offer prices for these customers, and are between 17% and 19% higher compared to last year’s standard offer pricing.

Why have these prices gone up? One explanation is that suppliers are pricing the recent upward trend in regional wholesale natural gas and electricity prices into their retail bids. Wholesale electricity pricing in New England is generally set by the price of natural gas. Despite the availability of low-cost natural gas throughout most of the country, peak demands for natural gas in New England for heating and for electric power generation exceed the capability of the natural gas pipeline network to deliver gas into the region. As a result, the wholesale price of natural gas – and electricity – spikes as demand for gas increases.  Based on last winter's experience with this phenomenon, retail electricity suppliers are expecting similar high wholesale prices this winter, and are increasing their retail rate bids accordingly.

One solution that could keep downward pressure on the cost of natural gas and electricity is expanded pipeline infrastructure to enable a balance between supply and demand for natural gas deliveries into New England. New England states are working to promote this solution, which could save consumers over $1 billion per year. Until then, the likelihood is for continued upward pressure on wholesale electricity prices, and corresponding upward jumps in the retail price consumers pay for electricity as evidenced by the new standard offer prices.

Maine utility launches time-of-use rates

A Maine electric utility has launched a program to offer residential consumers rates that vary depending on whether the consumption occurs during times of peak demand on the electric grid.  Central Maine Power Company's residential time-of-use rates are designed to encourage consumers to shift their use of electricity-intensive equipment to off-peak hours, generally between 8:00 p.m. and 7:00 a.m. and on weekends. How many customers will choose this option?  What effects will it have, both for the consumers opting in and for society as a whole?

Traditionally, electric ratepayers pay the same price for every kilowatt-hour of energy they consume, without regard to the time of consumption or to conditions on the grid.  But the cost of producing a given kilowatt-hour of electricity depends on factors including the portfolio of generators operating at the time, as well as on the instantaneous demand for electricity in the overall regional market.  Because they are not directly exposed to the real-time price of power, consumers individually and collectively may not make efficiency choices about how much power they consume, and when they consume it.  For example, energy prices are typically lower at night, when demand is reduced, but consumers have not traditionally had any incentive to shift their consumption to lower-priced nighttime hours.  Some utilities have offered industrial and commercial businesses time-of-use rates to encourage efficiency, but most residential ratepayers have not had this option in recent years.

Central Maine Power now offers residential consumers the option to choose time-of-use rates.  Prices during peak hours will be about 15 percent higher than under the default rate schedule, with off-peak prices about 20 percent below the default rates.  The structure offers the opportunity for consumers to choose to shift heavy-consuming applications like air conditioning and heating to off-peak hours.  This could save these consumers money - but it would require them to modify their behavior, invest in new "smart" technology, or both.  Will consumers find the opportunity for savings to be worth these changes?

The current enrollment window is open through January 31, 2013.