Vermont PUC report on electric vehicles

Vermont utility regulators have recommended steps Vermont could take to accelerate the use of electric vehicles (EVs) in the state, including creating state incentives for EV purchases as well as encouraging electric utilities to adopt new rate structures.

Like most other states, Vermont's transportation sector contributes more greenhouse gas emissions than any other sector of the state's economy. Due in large part to emissions from cars and trucks powered by fossil fuels, the transportation sector is responsible for about 47% of Vermont's total greenhouse gas emissions; by contrast, Vermont's electricity generating sector is relatively small but nearly entirely renewable, and has the lowest carbon dioxide emissions of any state according to federal data. Other New England states are similar -- for example, Maine's transportation sector contributed 53% of the state's total greenhouse gas emissions in 2017, while electric power generation in Maine accounted for just 9 percent of the state’s total carbon emissions.

Indeed, the New England electricity grid has experienced significant decarbonized in recent decades, and renewable energy can now be consumed in the transportation sector through the use of EVs. In 2016, Vermont adopted a Comprehensive Energy Plan aiming to power 10% of transportation with renewable energy by 2025, and 80% by 2050, while reducing the sector's emissions by 30% by 2025. Vermont estimates that reaching these goals would require adding about 50,000 to 60,000 EVs to replace vehicles with internal combustion engines by 2025, for a compound annual growth rate of about 54%.

On June 27, 2019, the Vermont Public Utilities Commission released its report to various state legislative committees, "Promoting the Ownership and Use of Electric Vehicles in the State of Vermont." The report recommends that Vermont create incentives for EV purchases or leases, whether in the form of time-of-sale rebates or tax credits. It also recommends that Vermont buy EVs for the state vehicle fleet, and encourage the development of EV charging infrastructure through zoning or building code modifications.

The report also suggests that the Commission encourage electric utilities to take additional actions to promote EV adoption, such as funding EV purchase incentives through Vermont's Renewable Energy Standard program, or developing time-of-use retail rates to encourage car charging at off-peak times. It also noted that utility rate structures which impose demand charges on most commercial accounts but not on residential accounts make public direct-current fast-charging more expensive than at-home charging.

The report also notes that increased education and outreach efforts -- by utilities as well as by car dealers and other third parties -- could encourage consumer adoption of EVs.

Maine advances legislation restoring net metering

The Maine state legislature has voted to advance a bill that would amend the state's statute governing the net metering of small distributed renewable energy projects. If enacted into law, the amendment would reverse regulatory changes imposed in 2017 that reduced the value of net energy billing to participating customers.

Maine has allowed customers with distributed renewable energy generation to use the power they produce to offset their electricity bill since the 1980s. In 2017, the Maine Public Utilities Commission amended its rules governing net energy billing to reduce the amount of power that a customer could net against its electric utility bill. The Commission did this by inventing a concept called "gross metering," which allowed electric utilities to collect charges even for power generated and consumed on-site in real time, while requiring participating customers to install a second meter.

The "gross metering" concept was controversial for a variety of reasons, including the fact that it deterred customer adoption of solar power and other distributed renewables (by adding costs while cutting compensation), and the fact that for the first time ever it allowed utilities to collect charges from customers for power produced and consumed entirely on the customer's premises even where that power never went on utility grid facilities.  The Commission later exempted most medium and large customers from this policy after finding that the cost of installing an extra meter wasn't justified, but left the gross metering requirements in its Rule Chapter 313 governing net energy billing. In response, in 2019 various state legislators proposed bills that would alter or restore the net energy billing paradigm.

One of these bills has now received favorable votes in both the state House and Senate. LD 91, An Act to Eliminate Gross Metering, was originally sponsored by Representative Seth Berry. It clarifies the statutory definition of net energy billing, which currently defines the concept as "a billing and metering practice under which a customer is billed on the basis of net energy over the billing period taking into account accumulated unused kilowatt-hour credits from the previous billing period." As amended by LD 91, the definition would specifically define "net energy" as the "difference between the kilowatt-hours delivered by a transmission and distribution utility to the customer over a billing period and the kilowatt-hours delivered by the customer to the transmission and distribution utility over the billing period." This clarification removes the Public Utilities Commission's ability to define "net energy" in any other way. LD 91 also directs the Commission to amend its rules "to be substantively equivalent to the rules in effect on January 1, 2017" (that is, before the Commission's 2017 regulatory amendment.)

LD 91 faces additional votes in the state legislature, before it would move to the desk of Governor Janet Mills for her signature. The legislature is also expected to consider other bills affecting net energy billing or expanding incentives for solar development, later this session.

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.

Maine legislature considers EV incentives

The Maine State Legislature is considering several measures that could create new incentives for purchasing or leasing electric vehicles.

At least two bills proposing new incentives for electric vehicles have been printed so far:

• LD 604, An Act To Create an Electric Vehicle Tax Credit: Sponsored by Senator Chenette, this bill would provide an income tax credit for the purchase of a new plug-in electric-drive motor vehicle that is eligible for a federal income tax credit. The credit would be $300 plus $50 for each kilowatt-hour of battery capacity in excess of 5 kilowatt-hours, up to a maximum credit of $1,500. (As a point of reference, the base model 2019 Nissan Leaf comes with a 40-kilowatt battery.) LD 604 has been referred to the Legislature's Joint Standing Committee on Taxation.

• LD 614, An Act To Provide Purchase Rebates for Battery Electric Vehicles: Sponsored by Representative Henry Ingwersen, this bill would establish an "Electric Vehicle Rebate Fund" to be administered by the Efficiency Maine Trust. The bill would direct the Trust to create a program, beginning July 1, 2020, that would pay a direct rebate of $2,500 to Maine residents who purchase or lease an eligible electric vehicle and meet certain criteria, including a certification of intent to retain ownership of the electric vehicle (through purchase or lease) for at least 36 months. The program would be limited to fully electric, zero-emission vehicles that have an on-board electrical energy storage device that is designed to be recharged using an external energy source. LD 614 has been referred to the Legislature's Joint Standing Committee on Energy, Utilities and Technology. 

More bills proposing incentives for electric vehicle adoption could still surface later in the Maine legislative session. For example, a list of legislative requests submitted by legislators includes LR 1380, An Act To Encourage Municipalities, State Agencies, Colleges and Universities To Adopt Electric Vehicles.

Outside Maine, a number of other states offer incentives for electric vehicle adoption. Additionally, the federal Internal Revenue Service offers a tax credit for qualifying electric vehicles, ranging from $2,500 to $7,500 per new EV purchased for use in the U.S., depending on the size of the vehicle and its battery capacity.

Energy issues in Maine's 2019 legislative requests

With the 129th Maine Legislature convened for its first regular session, the Office of the Revisor of Statutes has released a list of the titles of proposed legislation timely submitted by legislators. While the text of most of these legislative requests has not yet been publicly released, the preliminary list of working titles of over 2,000 precloture legislator bills suggests the scope of issues that will come before the Maine State Legislature in 2019. On energy matters, themes emerging from this list include reforms to Maine's renewable portfolio standard; efforts to reduce greenhouse gas emissions; incentives for microgrids, renewable energy and electric vehicles; and changes to energy efficiency standards for most newly constructed buildings.

Based on the working titles and legislative committee assignments, a number of bills will propose changes to Maine's renewable portfolio standard or other laws regarding renewable energy. Among others, these bills could include:

• LR 26, An Act To Update Maine's Renewable Energy Policy (Spkr. Gideon of Freeport)
• LR 82, An Act To Update the State's Renewable Energy Goals (Rep. Berry of Bowdoinham)
• LR 119, Resolve, To Establish a Working Group To Develop a Stand-alone Renewable Energy Certificate Program for the Biomass Industry (Sen. Carpenter of Aroostook)
• LR 403, An Act To Diversify Maine's Energy Portfolio with Renewable Energy (Rep. Hubbell of Bar Harbor)
• LR 845, An Act To Encourage the Use of Renewable Energy (Sen. Lawrence of York)
• LR 872, An Act To Extend to December 31, 2020 the Deadline for Community-based Renewable Energy Projects To Become Operational (Rep. Higgins of Dover-Foxcroft)
• LR 1034, An Act To Establish a Green New Deal for Maine (Rep. Maxmin of Nobleboro)
• LR 1123, An Act To Repeal the 100 Megawatt Limit on Power Generation (Rep. Hanley of Pittston)
• LR 1405, An Act To Clarify the Definition of "Renewable Capacity Resource" (Rep. Babine of Scarborough)
• LR 1431, An Act To Study Transmission Solutions To Enable Renewable Energy Investment in the State (Rep. Berry of Bowdoinham)
• LR 1470, An Act To Modernize Maine's Renewable Portfolio Standard (Sen. Lawrence of York)
• LR 1558, An Act To Increase Maine-based Energy Sources (Pres. Jackson of Aroostook)
• LR 1616, An Act To Reform Maine's Renewable Portfolio Standard (Sen. Vitelli of Sagadahoc)
• LR 1803, An Act To Benefit Maine Consumers, Businesses and Communities through Expanded Renewable Energy (Sen. Dow of Lincoln)

Other bill titles suggest possible proposed changes to other aspects of Maine's renewable policy, such as Maine's version of net metering or rules governing community solar projects:

• LR 15, An Act To Eliminate Gross Metering (Rep. Berry of Bowdoinham)
• LR 299, An Act To Replace Net Energy Billing with a Market-based Mechanism (Rep. O'Connor of Berwick)
• LR 404, An Act To Protect Ratepayers from Gross-metering Costs (Rep. Hubbell of Bar Harbor)
• LR 535, An Act To Eliminate the Cap on Solar Energy Generation Farms (Sen. Miramant of Knox)
• LR 536, An Act To Require Transmission and Distribution Utilities To Purchase Electricity from Renewable Resources at Certain Prices (Sen. Miramant of Knox) 
• LR 1259, An Act To Eliminate Restrictions on Community Solar Projects (Rep. Higgins of Dover-Foxcroft)
• LR 1621, An Act To Expand Community-based Solar Energy in Maine (Sen. Sanborn of Cumberland)

Several more bill titles appear designed to expand opportunities for microgrids or other local private sales of electricity:

• LR 18, An Act To Allow Microgrids That Are in the Public Interest (Rep. Devin of Newcastle)
• LR 213, An Act To Authorize Businesses Located Adjacent to Electric Power Generators To Obtain Power Directly (Rep. Campbell of Orrington)
• LR 1464, An Act To Allow the Direct Sale of Electricity (Sen. Woodsome of York)

Beyond a direct focus on renewable energy, several bill titles address Maine's participation in the Regional Greenhouse Gas Initiative or efforts to reduce fossil fuel use:

• LR 254, An Act To Develop a State Energy Plan To Provide a Pathway to a Fossil-free Energy Portfolio (Rep. Devin of Newcastle)
• LR 1493, An Act To Ensure the Regional Greenhouse Gas Initiative Trust Fund Continues To Promote Energy Efficiency and Benefit Maine Ratepayers (Rep. Wadsworth of Hiram)

At least three bill titles call for increased incentives for electric vehicles:

• LR 862, An Act To Provide Purchase Rebates for Battery Electric Vehicles and Fuel Cell Electric Vehicles (Rep. Ingwersen of Arundel)
• LR 1380, An Act To Encourage Municipalities, State Agencies, Colleges and Universities To Adopt Electric Vehicles (Rep. Ingwersen of Arundel)
• LR 1687, An Act To Create an Electric Vehicle Tax Credit (Sen. Chenette of York) 

At least five bill titles address the Maine Uniform Building and Energy Code:

• LR 561, An Act To Amend the Maine Uniform Building and Energy Code (Rep. Kessler of South Portland)
• LR 537, An Act To Strengthen the Maine Uniform Building and Energy Code (Rep. Caiazzo of Scarborough)
• LR 619, An Act Regarding the Maine Uniform Building and Energy Code (Rep. Ingwersen of Arundel)
• LR 866, An Act To Amend the Laws Governing the Maine Uniform Building and Energy Code (Rep. Rykerson of Kittery)
• LR 1743, An Act Regarding the Application and Administration of the Maine Uniform Building and Energy Code (Rep. Fecteau of Biddeford) 

Experience suggests that most of these legislative requests will result in printed bills, and will be given public hearings before legislative committees before votes by the House and Senate.

NH revises, reopens C&I solar rebate program

New Hampshire utility regulators have reopened a program offering a rebate to commercial and industrial electric customers who undertake qualifying solar energy projects, while reducing the size of the incentive and changing other program terms.

To encourage commercial and industrial (C&I) customers to participate in solar photovoltaic and solar thermal energy projects, the New Hampshire Public Utilities Commission first approved a solar rebate program in 2010. That program disburses funds from the state's Renewable Energy Fund to customers in exchange for customers' development of qualifying solar projects.

Terms and conditions for New Hampshire's C&I solar rebate program have varied since 2010, and the amounts of rebates available under the program have generally decreased over time. In 2015, the Commission created two separate categories of eligible projects with different rebate rates: Category 1, consisting of solar electric and thermal systems rated less than or equal to 100 kilowatts (AC) or thermal equivalent, and Category 2 consisting of solar electric systems greater than 100 kilowatts (AC) but less than or equal to 500 kilowatts (AC).

A 2016 Commission order set program rebate levels at $0.65 per watt (AC) for Category 1 new electric projects, and $0.55 per watt (AC), but not in excess of $175,000, for Category 2 new electric projects, in each case subject to a limit of 25 percent of the total project cost if less than the incentive payment otherwise calculated.

But the program closed to new applications as of July 14, 2017, due to "record demand" and a lack of funds. Even the allocation of additional funds only reopened the program for waitlisted applications, while keeping it closed to new applicants.

On February 13, 2018, Commission staff recommended reopening the program, while modifying it to further reduce the applicable incentive levels and to consolidate Category 1 and 2 projects into a single program that would allow applications for projects with capacities up to and including 500 kW AC.

On March 8, 2018, the Commission issued its Order No. 26,111, modifying the solar rebate program's terms and reopening the program. The changes include reduction in the amount of the rebate to $0.40 per watt up to a maximum of $50,000, or 25 percent of total project cost, whichever is less; and consolidation of Category 1 and 2 photovoltaic projects into a single program that would allow applications for projects with capacities up to and including 500 kilowatts AC. No change was made to the program terms and conditions applicable to solar thermal projects.

Under the order, the modified program terms and conditions became effective on March 19, 2018, and the program was reopened as of that date. The Commission noted that in anticipation of "robust demand for and potential oversubscription of the reopened program," it will conduct a public lottery in April to allocate initial queue positions for applications.

Massachusetts develops next solar incentive

The Massachusetts Department of Energy Resources (DOER) is designing a new solar incentive program to encourage the continued development of solar renewable energy generating sources by residential, commercial, governmental and industrial electricity customers, based on a state law enacted this spring. The so-called "next solar initiative" program could affect the pace of solar photovoltaic project development in Massachusetts, as policymakers seek a smooth transition from the current SREC II program as it reaches full capacity.

On April 11, 2016, Governor Charlie Baker signed into law An Act Relative to Solar Energy, also known as Chapter 75 of the Acts of 2016.  The law preserved and expanded net metering, preserving the value of that policy for projects developed by residential, small commercial, municipal and government customers.

As described by the Baker administration, the law also allows DOER and the Department of Public Utilities to "gradually transition the solar industry to a more self-sustaining model." In particular, section 11 of the act directed DOER to "develop a statewide solar incentive program to encourage the continued development of solar renewable energy generating sources by residential, commercial, governmental and industrial electricity customers throughout the commonwealth."

The law prescribed twelve requisite characteristics of the solar incentive program, but left the creation of rules and regulations to DOER.  Some criteria are process-oriented, such as that the program "promotes the orderly transition to a stable and self-sustaining solar market at a reasonable cost to ratepayers," or considers underlying system costs, environmental benefits, energy demand reduction and other avoided costs provided by solar renewable energy generating facilities.

Other criteria define structural requirements for the program, such as that it "relies on market-based mechanisms or price signals as much as possible to set incentive levels," "differentiates incentive levels to support diverse installation types and sizes that provide unique benefits," and "features a known or easily estimated budget to achieve program goals through use of a declining adjustable block incentive, a competitive procurement model, tariff or other declining incentive framework."  The law also requires the program to promote investor confidence through long-term incentive revenue certainty and market stability.

After the solar bill's enactment, DOER held two public listening sessions, and solicited comments on the development of the "next solar incentive" through June 30, 2016.  Many commenters expressed support for a continuation of the SREC framework, such as "SREC III."  Other comments focused on locational issues, such as proposing policies to deter the development of projects located on farmland or other undeveloped "greenfield" sites.

DOER is expected to release a first draft of its next solar incentive program this summer.

DesertLink transmission project wins rate incentives under Section 219

Federal energy regulators have granted a petition by the developer of a proposed electric transmission project in Nevada for certain transmission rate incentives available under federal law.  On August 19, the Federal Energy Regulatory Commission ruled on DesertLink, LLC's petition for declaratory order, with respect to DesertLink's new Harry Allen to Eldorado 500 kV transmission project.  The order grants DesertLink's requests for transmission rate incentives under section 219 of the Federal Power Act, and illustrates how those incentives operate.

DesertLink, a member of the LS Power Group, is the developer of a transmission project to be located in Nevada, but connected to a substation in the grid controlled by the California Independent System Operator Corporation.  CAISO designated the project for competitive bidding under its 2013-2014 transmission plan, and in January 2016 selected DesertLink as the approved project sponsor under its Order No. 1000-based process for eligible transmission developers to submit bids to develop and construct certain transmission projects.  The project is designed to have an in-service date of May 2020.

Rate incentives can be available to promote capital investments in certain transmission infrastructure.  The Federal Power Act authorizes the Federal Energy Regulatory Commission to regulate the transmission and wholesale sales of electricity in interstate commerce.  Through the Energy Policy Act of 2005, Congress added a new section 219 to the Federal Power Act, directing the Commission to create rules establishing incentive-based rate treatments.  The Commission's Order No. 679 sets forth the processes by which a public utility may seek transmission rate incentives under section 219, and the Commission has issued a Transmission Incentives Policy Statement offering guidance on how it evaluates applications for transmission rate incentives.

Section 219 and Order No. 679 require an applicant for rate incentives to show that “the facilities for which it seeks incentives either ensure reliability or reduce the cost of delivered power by reducing transmission congestion.”  Order No. 679 established a rebuttable presumption that this standard is met if:

(1) the transmission project results from a fair and open regional planning process that considers and evaluates the project for reliability and/or congestion and is found to be acceptable to the Commission; or (2) a project has received construction approval from an appropriate state commission or state siting authority.

Order No. 679 also requires an applicant to demonstrate that there is a nexus between the incentive being sought and the investment being made.  The Commission clarified in Order No. 679-A that this "nexus test" is met when an applicant demonstrates, on a project-specific basis, that the total package of incentives requested is “tailored to address the demonstrable risks or challenges faced by the applicant.”

In DesertLink's case, on May 11, 2016, the applicant applied for transmission rate incentives, including (1) deferred recovery of all prudently incurred precommercial costs through the creation of a regulatory asset (regulatory asset incentive); (2) full recovery of 100 percent of prudently-incurred costs, including pre-commercial expenses and construction costs, if the Project is abandoned for reasons beyond DesertLink’s control (abandonment incentive); (3) use of a hypothetical capital structure consisting of 50 percent debt and 50 percent equity until the Project achieves commercial operation (hypothetical capital structure incentive); and (4) a 50-basis point adder to DesertLink’s Return on Equity (ROE) for participating in a Regional Transmission Organization (RTO), namely, CAISO (RTO participation incentive).

Last week, the Commission granted DesertLink's petition.  First, the Commission found that DesertLink is entitled to the rebuttable presumption that the Project will ensure reliability or reduce the cost of delivered power by reducing transmission congestion, because the CAISO transmission planning process found annual production cost benefits of $9.4 million in 2019 to $8.4 million in 2024 and beyond, and annual capacity benefits of $19.7 million in 2020 to $8.8 million in 2025 and beyond.

Next, the Commission found that DesertLink had demonstrated that its total package of requested incentives is tailored to address the demonstrable risks or challenges faced by DesertLink.  The Commission found that the regulatory asset treatment of pre-commercial costs appropriately addresses the risks and challenges of the Project, because it provides DesertLink with added upfront regulatory certainty, reduces interest expenses, and assists in the construction of the Project.  On the abandonment incentive, the Commission found that recovery of abandonment costs was an effective means to encourage transmission development by reducing the risk of non-recovery of costs.  Regarding a hypothetical capital structure, the Commission noted that its use "will aid DesertLink in raising capital during the construction phase of the Project, and will assist DesertLink in maintaining low debt costs while its actual debt-to-equity ratio varies."  The Commission also found DesertLink would qualify for the RTO participation incentive, based on its commitment to become a member of CAISO and to transfer operational control of the project to CAISO after placing it in service.

The Commission's determination takes the form of a declaratory order granting authorization for the rate incentives, but it does not directly authorize DesertLink to include the incentives in its filed rates.  As the Commission noted, "While our determination on DesertLink's Petition establishes whether it qualifies for the requested transmission rate incentives, if DesertLink seeks to put these incentives into effect, it must submit a subsequent filing under section 205 of the FPA."  In such a case, the applicant will need to make a variety of showings before including certain incentives in its rate base, including the justness and reasonableness of costs relating to pre-commercial, formation, and plant abandonment.  Nevertheless, securing the declaratory order gives DesertLink greater certainty about its qualification for these key incentives for electric transmission development.

Supreme Court rules on state energy incentives

The U.S. Supreme Court has released its ruling on a case affecting how states may provide incentives for electric power generation.  In Hughes v. Talen Energy Marketing, LLC, the Court upheld a lower court's ruling invalidating a Maryland program to subsidize construction of new power plants.  The ruling provides important insight into how the Court views the boundary between federal and state jurisdiction over energy matters.

The Supreme Court of the United States.

The Hughes case involved a new Maryland program to encourage in-state generation capacity, and its relationship to federally blessed capacity market.  Under the Federal Power Act, the Federal Energy Regulatory Commission has exclusive jurisdiction over wholesale sales of electricity in the interstate market, while States regulate retail electricity sales. 

For years,  Mid-Atlantic regional grid operator PJM Interconnection has held capacity auctions to identify need for new generation and compensate generators for development.  PJM's auctions have been approved by the Federal Energy Regulatory Commission under the Federal Power Act.  But due to concern that the PJM auction was failing to encourage development of sufficient new in-state generation, Maryland enacted its own regulatory program.  Under that state program, Maryland held a competitive process to select a developer for a new power plant, and required load-serving entities to enter into a 20-year pricing contract (called a "contract for differences") with the developer.  The developer would still sell its capacity to PJM, but would receive extra money under the state program to make up the difference between the PJM market price and the contract price.

But incumbent generators challenged the new Maryland program; a federal district court issued a declaratory judgment holding that Maryland's program improperly sets the rate the developer receives for interstate wholesale capacity sales to PJM.  On appeal, the Fourth Circuit affirmed, finding that Maryland's program was preempted because it impermissibly conflicts with FERC policies.  The case then came to the Supreme Court of the United States.

The Supreme Court's April 19, 2016 decision affirms the lower courts' rulings.  The Court agreed with the Fourth Circuit's judgment "that Maryland's program sets an interstate wholesale rate, contravening the FPA's division of authority between state and federal regulators."  In the majority opinion's words, "States may not seek to achieve ends, however legitimate, through regulatory means that intrude on FERC's authority over interstate wholesale rates, as Maryland has done here."

The Hughes ruling sheds light on how the Court might view other state programs to incentivize new or clean generation.  That said, the Court emphasized that its holding in Hughes is limited -- that it rejected Maryland's program "only because it disregards an interstate wholesale rate required by FERC."  The Court explicitly said it would not address "the permissibility of various other measures States might employ to encourage development of new or clean generation," such as tax incentives, land grants, direct subsidies, construction of state-owned generation facilities, or re-regulation of the energy sector.

The majority opinion concludes with a reminder that "[s]o long as a State does not condition payment of funds on capacity clearing the auction, the State's program would not suffer from the fatal defect that renders Maryland's program unacceptable."  This suggests one potential path for permissible state incentives for electric power generation.

FERC to examine competitive transmission incentives

The Federal Energy Regulatory Commission has scheduled a Commissioner-led technical conference for this summer to discuss issues related to competitive transmission development processes.  At issue will be the use of cost containment provisions, the relationship of competitive transmission development to transmission incentives, and other ratemaking issues.

As part of the Energy Policy Act of 2005, Congress added section 219 to the Federal Power Act.  Section 219 directs the Commission to establish, by rule, incentive-based rate treatments to promote capital investment in certain transmission infrastructure.  The Commission's Order No. 679 sets forth processes by which a public utility may seek transmission rate incentives pursuant to section 219.  To qualify, an applicant must show that "the facilities for which it seeks incentives either ensure reliability or reduce the cost of delivered power by reducing transmission congestion" and also demonstrate a nexus between the incentives being sought and the investment being made.  Order No. 679-A clarified that this nexus test is satisfied when an applicant demonstrates that the total package of incentives requested is tailored to address the demonstrable risks or challenges faced by the applicant.

But a case decided earlier this year has led the Commission to reevaluate broader policy considerations relating to the role of cost containment proposals in competitive transmission development.   In a January 8, 2016 order, NextEra Energy Transmission West, LLC, 154 FERC ¶ 61,009, the Commission partially rejected a request by a public utility transmission owner for certain transmission rate incentives pursuant to section 219 and Order No. 679.  That case involved proposed transmission development under the California Independent System Operator Corporation (CAISO)'s competitive transmission developer selection process adopted to comply with Order No. 1000.

Most controversial in the "NEET West" case was a conditional adder to the utility's return on equity that would be triggered if the return on equity fell below the 10 percent that was the foundation for the utility's competitive bids for transmission project development.  On the specific facts and circumstances of that case, the Commission found that the utility had not provided adequate support for the "conditional ROE incentive" and therefore denied it.

But in ruling on the NEET West case, the Commission noted that "this case highlights broader policy considerations related to the potential benefits of cost containment proposals in the context of competitive transmission development." In the NEET West order, the Commission signaled its intent to convene a technical conference in the future to explore further such issues, including how they relate to a 2012 Policy Statement issued by the Commission providing additional guidance regarding its evaluation of applications for transmission rate incentives under section 219 of the Federal Power Act and Order No. 679.

The first specific issue identified in the NEET West order involves the relationship between an expectation stated in the Policy Statement and risks associated with cost containment proposals. The Policy Statement requires an applicant seeking an incentive ROE to demonstrate that the proposed project faces risks and challenges that are not either already accounted for in the applicant’s base ROE or addressed through risk-reducing incentives.  The Commission expressed interest in exploring more broadly "why cost containment-related risks would not be accounted for in a base ROE level below 10 percent and yet would be accounted for in a base ROE of 10 percent" as NEET West argued.

The second specific issue involves "whether and how risks voluntarily assumed through submittal of a cost containment proposal relate to the second expectation set forth in the Policy Statement." The Commission expects an applicant seeking an ROE incentive based on a project’s risks and challenges to demonstrate that it is taking appropriate steps and using appropriate mechanisms to minimize its risks during project development.  But it noted that NEET West "voluntarily submitted cost caps to make its bids to CAISO more attractive, which exposes NEET West’s shareholders to risks they would not have faced absent the cost caps."  The Commission expressed intent to explore "whether and how voluntarily assuming this type of risk is consistent with minimization of risk envisioned by the Policy Statement."

On March 17, the Commission denied a request by ITC Grid Development for a declaratory order on whether cost-capped bids that won a competitive transmission project selection process should automatically be considered just and reasonable.  But that same day, the Commission issued a Notice of Technical Conference in Docket No. AD16-18-000.  In a footnote, the notice states that topics to be discussed include, but are not limited to, those that the Commission described in its NEET West order.

The technical conference to explore these and related issues has now been scheduled for June 27 and 28, 2016, at the Commission ’s headquarters at 888 First Street, NE, Washington, DC 20426.

Section 242 hydroelectric incentive program funding

For the first time, the U.S. Department of Energy has funding for its Section 242 hydroelectric incentive program.  The program, arising from Section 242 of the Energy Policy Act of 2005,  provides incentive payments for adding new turbines or other hydroelectric generating devices to existing sites. The Department is accepting applications for the incentive payments through February 1, 2016.

In 2005, as part of the Energy Policy Act of 2005, Congress created the Section 242 hydroelectric incentive program to support the expansion of hydropower energy development at existing dams and impoundments.  Section 242 establishes an incentive for qualified hydroelectric facilities, defined as "a turbine or other generating device owned or solely operated by a non-Federal entity which generates hydroelectric energy for sale and which is added to an existing dam or conduit."  The incentive is set at up to 1.8 cents per kilowatt-hour of net electric energy generated and sold by a qualified hydroelectric facility, indexed for inflation (about 2.3 cents per kilowatt-hour today) up to a maximum of $750,000 per year, for a specified 10-year period.

To get this money, an owner or operator must apply for the incentive payments.  An application for an incentive payment for electric energy generated and sold in a calendar year must be filed during the applications period defined by the Department of Energy in the Federal Register.  But according to the Energy Department's final guidance for the Section 242 program, "DOE will accept applications and make payments to qualified hydroelectric facilities in years when appropriations are available for this purpose."  Until recently, no such appropriations were available.

In Congressional appropriations for Federal fiscal year 2015, the Department of Energy received funds to support this hydroelectric incentive program for the first time. As shown in the conference report to the law that made appropriations for Fiscal Year 2015, Congress appropriated $3,960,000 for conventional hydropower under section 242 of EPAct 2005.

With funding now available, the Energy Department is only accepting applications from owners and authorized operators of qualified hydroelectric facilities for hydroelectricity generated and sold in calendar year 2014. Applications for this round of Section 242 funding are due by February 1, 2016.

Maine community renewable energy project winds down

Maine energy regulators will soon act on proposals for community-based renewable energy projects, as legal authority for a community energy pilot program winds down.

In 2009, the Maine Legislature enacted An Act To Establish the Community-based Renewable Energy Pilot Program, P.L. 2009, ch. 329.  The Act established a pilot program to provide incentives for the development of community-based renewable projects.  To qualify, projects must be “locally owned electricity generating facilities” (51% or more of the facility must be owned by “qualifying local owners”) and must not exceed 10 MW.  The Maine Public Utilities Commission was charged with administering the program, including certifying qualifying facilities.  To a community renewable energy project developer, the program offered the opportunity to win a long-term contract to sell project power to a Maine utility at predictable prices.

A 2015 law amended the community-based renewable energy program.  Among other changes, it required the Commission to perform a "viability assessment" of all projects that have been certified under the program but have not yet reached commercial operations.  For any projects the Commission determines will not be viable by December 31, 2018, the Act states that the Commission must revoke any contract awarded, though the projects will remain certified.  In September 2015, the Commission completed its viability assessment and identified approximately 21 megawatts of capacity that is available for contract awards. 

The 2015 law effectively provides that the Commission's authority to order utilities to enter into community-based renewable energy projects expires on December 31, 2015.   In light of the 21 megawatts of program capacity identified as available, on September 30, the Commission issued a request for proposals for projects seeking the remaining contract awards.

Proposals were due by November 6, 2015. According to the RFP,  the Commission will complete its evaluation of proposals and accept or reject proposals no later than December 31.

Value of distributed solar energy

What is the value of distributed solar photovoltaic electric generation?  An investigation by the Maine Public Utilities Commission into this question is ongoing, and will culminate in a report to the state legislature this winter.  At stake are policies and incentives to foster the growth of solar energy in Maine.

Distributed solar generation -- such as solar panels on rooftops and ground-mounted solar arrays -- is a small but rapidly growing sector of the U.S. energy mix.  Solar panels can produce renewable electricity, with no direct fuel use, emissions, or reliance on foreign energy sources.  Customer-sited and other distributed generation resources can also enhance the reliability of the local electric grid, and reduce the need for more expensive transmission and distribution upgrades.  The growing shift to solar energy is also seen as a driver of jobs and economic development.

Rooftop solar photovoltaic panels on a business in Patten, Maine.

In recognition of these benefits, states and the federal government have enacted a variety of policies and incentives for solar power development and use.  These policies include renewable portfolio standards which mandate that utilities source certain amounts of their power from renewable resources, as well as net metering policies which allow a customer to offset its power bill with energy produced from on-site solar panels.

But what is the true value of distributed solar energy resources?  In an effort to find out, in 2014 the Maine Legislature enacted An Act To Support Solar Energy Development in Maine.  This law is also known as the Maine Solar Energy Act, P.L 2013 Chapter 562 (codified at 34-B M.R.S. §§ 3471-3473).  The law expresses the legislative finding that Maine's solar energy resources "constitute a valuable indigenous and renewable energy resource."  Moreover, the law is predicated on the findings that solar energy development is unique in its benefits to and impacts on the climate and the natural environment, and that it can help Maine because it can displace fossil fuel combustion and associated air pollution and greenhouse gas emissions.   The Act set a state policy "to encourage the attraction of appropriately sited development related to solar energy generation, including any additional transmission, distribution and other energy infrastructure needed to transport additional solar energy to market, consistent with all state environmental standards; the permitting and financing of solar energy projects; appropriate utility rate structures; and the siting, permitting, financing and construction of solar energy research and manufacturing facilities for the benefit of all ratepayers."

With these findings noted, the Act directed the Maine Public Utilities Commission to construct a report by February 15, 2015 on the value of distributed solar energy generation in Maine.  In so doing, the Act requires the Commission to develop a method for valuing distributed solar energy generation.   By statute, this method must, at a minimum, account for:

• the value of the energy;
• market price effects for energy production;
• the value of its delivery, generation capacity, transmission capacity and transmission and distribution line losses; and
• the societal value of the reduced environmental impacts of the energy.

The also Act requires the Commission's report to include a summary of options for increasing investment in or deployment of distributed solar energy generation, which may include recommendations for what Maine should do.

The Commission's investigation is ongoing.  On October 23, 2014, the Commission released a draft of its consultants' initial report, "Maine Distributed Solar Valuation Methodology."  That document is designed as a draft of the methodology to be used in the valuation phase, offered for public review and comment.

The Commission will accept written comments on the draft report until November 12, 2014.  In addition, the Commission and its consultant, Clean Power Research, will hold a work session on the Draft Methodology on October 30, 2014.

Following the first phase to establish the valuation methodology, the Commission and its consultants will conduct a second phase in which the methodology will be applied to Maine to calculate the value of distributed solar generation.  The Commission's work will be summarized in its report to the legislative energy committee, a draft of which the Commission plans to release in January 2015.

USDA announces renewable and energy efficiency funding

The United States Department of Agriculture has announced a new round of funding for assistance to agricultural producers and rural small businesses for energy efficiency and renewable energy projects.  USDA's Rural Energy for America Program (REAP) offers eligible farms and businesses incentives to improve their energy efficiency or produce energy from renewable sources.

USDA's mission includes revitalization of rural economies to create opportunities for growth and prosperity, support innovative technologies, identify new markets for agricultural producers, and make better use of natural resources. Authorized by the 2008 farm bill (formally the Food, Conservation, and Energy Act of 2008), the USDA REAP program's goals are to help agricultural producers and rural small businesses reduce energy costs and consumption and help meet the nation's critical energy needs.  Through the end of the 2012 fiscal year, REAP has funded over 6,800 renewable energy and energy efficiency projects, feasibility studies, energy audits, and renewable energy development assistance projects.

Today USDA announced that it will accept applications for three REAP program categories:

• Renewable energy system and energy efficiency improvement grant applications and combination grant and guaranteed loan applications until April 30, 2013
• Renewable energy system and energy efficiency improvement guaranteed loan only applications until July 15, 2013
• Renewable energy system feasibility study grant applications through April 30, 2013

USDA plans to make funding available despite the current federal budget sequestration, which appears to have cut REAP funding by at least $2 million in fiscal year 2013. 

Application requirements for REAP assistance vary depending on the type of assistance sought.  Those interested in applying for assistance can contact their local USDA office for more information, or consult a professional with experience working with the REAP program.

Preti Flaherty helps our clients evaluate whether REAP assistance is a good match for their businesses; I have assisted my clients in securing REAP funding for their energy projects.  Please contact us at 207-791-3000 for more information.

NJ tweaks solar energy law

New Jersey Governor Chris Christie has signed into law a bill designed to support the Garden State's solar energy industry.  The bill, which amends New Jersey's electric renewable portfolio standard, is hoped to remedy a perceived oversupply in the state market for solar renewable energy certificates, or SRECs.

Under New Jersey law, electric public utilities are required to source a specified portion of their power from solar electric generating facilities.  This solar-produced power is represented by SRECs, a tradable commodity issued by the New Jersey Board of Public Utilities to generators for each megawatt hour of solar energy they generate from grid-connected facilities.

Solar photovoltaic panels on the roof of Gallagher's Auto Parts, in Patten, Maine.

New Jersey's renewable portfolio standard requires utilities need to procure a specified amount of SRECs.  When the law first took effect, New Jersey had a shortage of eligible installed solar generation compared to this legislative demand, so SREC prices were high -- over $600 per MWh.  These prices were a significant incentive to develop solar capacity.  New Jersey installed more solar capacity in the first quarter of 2012 than any other state, and led the nation in solar installations on commercial and industrial properties in 2011. Today there are over 16,000 solar installations throughout the state, totaling over 800 MW in installed solar capacity.  Another 600 MW of solar capacity is in various stages of installation.

As New Jersey experienced significant growth in solar capacity, SREC supplies grew to the point where they exceeded the level of utility demand required by the renewable portfolio standard.  SREC prices fell below $200 on spot markets.  These low prices hurt solar developers and other stakeholders whose financing is reliant on REC sales and assumed higher prices.

The bill signed into law this week, "An Act concerning certain electric customer metering and solar renewable portfolio standards requirements and amending P.L.1999, c.23" (available as Senate Bill 1925 and Assembly Bill 2966), is designed to fix this problem.  It increases the amount of solar energy utilities must buy in the near-term.  As of June 1, 2013, the state’s solar energy mix will change from a fixed megawatt-hour requirement to a percentage-based requirement.  In proximate years, the change will represent an increase over the current solar carve-out; over time, it will return to the currently-planned arc of solar requirements.

The exact effect of the new law on SREC markets remains to be seen.  With a short-term increase in SREC demand, prices may rise, leading more projects to come online.  Will the short-term accelerated increase in demand lead to long-term price support, more development, both - or neither?