Maine regulators approve long-term contract

Maine utility regulators have approved a long-term contract to purchase the output of a 72.6-megawatt wind power project under development by Weaver Wind, LLC in Hancock County, Maine. The 20-year contract bears a price of 3.5 cents per kilowatt-hour, escalating at 2.5 percent per year.

A Maine statute enacted in 2006 authorizes the Public Utilities Commission to direct investor-owned transmission and distribution utilities to enter into long-term contracts, to the degree necessary to ensure reliability, meet energy efficiency program requirements, or reduce customer costs. In 2008, the Commission used this law to order a contract with the Rollins Wind project. After three subsequent procurement rounds, in 2017 the Commission approved a contract to buy 75 megawatts from Dirigo Solar, LLC, at a price of 3.4 cents/kWh escalating at 2.5% annually for 20 years.

In response to its most recent solicitation, earlier this year the Commission approved a term sheet for a contract to buy 100 megawatts from Three Rivers Solar Power, LLC’s solar project, with a price of 3.5 cents/kWh escalating at 2.5% annually for 10 years. Most recently, on July 12, 2019, the Commission approved a contract to buy the output of the Weaver Wind project, also at a price of 3.5 cents/kWh escalating at 2.5% annually for 10 years.

In addition to this existing law, in 2019 the Maine state legislature enacted several additional long-term contracting programs. One new law creates a new "Class IA" renewable portfolio standard, and requires the procurement by December 31, 2020 of energy or renewable energy credits from Class IA resources sufficient to cover between 7 and 10 percent of Maine's retail electricity sales, with a second round bringing the total procurement to 14 percent of Maine's retail electricity sales. Another new law requires the procurement of 375 megawatts from distributed generation resources between 2020 and 2024, with each project sized at less than 5 megawatts, and specific requirements for participation by non-residential and "community" or shared-ownership projects.

Collectively, these laws create a variety of opportunities for electric power generation projects to compete for and win long-term contracts to sell their output to Maine utilities.

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.

NH PUC considers efficiency plan

New Hampshire utility regulators are considering a three-year statewide energy efficiency plan proposed by several electric and gas utilities. The case could shape the near-term future of New Hampshire energy efficiency programming.

Under a 2016 settlement agreement, the New Hampshire Public Utilities Commission approved the implementation of an Energy Efficiency Resource Standard (EERS) beginning 2018, subject to Commission approval of the specific programs proposed to meet this standard. On September 1, 2017, utilities Liberty Utilities, Public Service Company of New Hampshire, Unitil Energy Systems, Inc. and Northern Utilities, Inc. jointly proposed a 2018-2020 Statewide Energy Efficiency Plan for approval by the Commission. The proposed 2018-2020 New Hampshire Statewide Energy Efficiency Plan document spans 369 pages, and is supported by testimony filed by the utilities.

As described by the utilities, their proposals would extend and expand existing "NHSaves" programs for another 3 years, and would add new initiatives including "a new residential energy audit option, a financing option for moderate income residents, new measure offerings in both residential and commercial programs, and multi -year energy planning to encourage long-term energy savings projects among large commercial customers."

According to the utilities, the measures implemented through the 2018-2020 Plan will save more than 4 billion electric kilowatt-hours and 7.5 million natural gas MMBtu, plus another 5.4 million MMBtus from other fuels, yielding customer energy cost savings of more than $867 million in energy costs over the life of the measures. The utilities also project that the measures "will reduce peak demand by 39 MW, which in tum will reduce costs for all customers."

The Commission has docketed the proceeding as Docket No. DE 17-136, and set a procedural schedule for the case including the filing of testimony and pursuit of possible settlement through November 2017, with hearings on the merits in early December.

Maine biomass commission to meet

A commission charged by the Maine legislature to study the state's biomass energy industry will hold its first meeting next month.  The study committee's work will result in a report to the legislature, and could include recommended changes to state law.

The Maine State House.

At the end of its 2016 session, the Maine legislature enacted a resolve establishing the Commission to Study the Economic, Environmental and Energy Benefits of the Maine Biomass Industry.  The resolve directed the commission to:

1. Review and evaluate the economic, environmental and energy benefits of Maine's biomass resources, as well as public policy and economic proposals to create and maintain a sustainable future for the Maine biomass industry;
2. Consider the interconnection of economic markets for biomass and forest products and the energy policy of the State;
3. Consider whether the environmental, economic and energy benefits of biomass support updating the State's energy policy to strengthen and increase the role that biomass and the forest products industry play throughout the State;
4. Consider the costs of implementing any recommendations and the effect of leaving current policies in place; and
5. Examine any other issues to further the purposes of the study. 

The Maine biomass commission has now been formed, and has scheduled its first meeting for August 2, 2016.  As prescribed by the resolve, its membership includes a mix of legislators and others interested in the state's biomass energy policy.

The resolve directed the biomass study commission to submit a report and any suggested implementing legislation for committee consideration by December 6, 2016.

Biomass was a hot topic in the past legislative session.  On a separate track, this spring the Maine legislature enacted a law establishing a long-term contracting program for biomass-fueled power plants.  The Maine Public Utilities Commission has issued a request for proposals under that program, with contract proposals due on or before July 29, 2016.

FERC Order 676-H adopts NAESB standards

Last week the Federal Energy Regulatory Commission issued Order No. 676-H, adopting and incorporating into its regulations most of the latest version of a set public utility business practice standards and communications protocols developed by the North American Energy Standards Board (NAESB).  While most of the NAESB standards will now become mandatory and enforceable, to enable smart grid innovation the Commission posted NAESB's five Smart Grid standards as non-binding guidance.

Industry standards enable cooperation and communication, and can lead to more efficient and competitive markets.  Formally known as Version 003 of the Standards for Business Practices and Communication Protocols for Public Utilities adopted by NAESB's Wholesale Electric Quadrant (WEQ), the newly adopted standards represent the latest evolution of NAESB's consensus-based standards for public utilities.  NAESB is an ANSI-accredited non-profit standards development organization formed to develop and promote business practice standards that promote a seamless marketplace for wholesale and retail natural gas and electricity. Since issuing Order No. 676 in 2006, the FERC has incorporated elements of NAESB's standards into its regulations.

While the FERC made most of the NAESB standards mandatory, it decided to include NAESB's smart grid standards only "informationally, as guidance."  While FERC noted that the smart grid standards have value and should be adopted by public utilities, it ultimately agreed with utility trade group Edison Electric Institute and the ISO/RTO Council that NAESB's five Smart Grid standards should neither be incorporated into formal federal regulation nor be enforceable and mandatory.  Notably, as prepared by NAESB the Smart Grid standards are meant to be optional and informative, not prescriptive or restrictive, and could prove difficult to enforce.

Thus to "encourage further developments in interoperability, technological innovation and standardization", the FERC chose to include NAESB's five smart grid standards in Order No. 676-H as guidance, but not to incorporate them into its formal, enforceable regulations.

Through Order No. 676-H, the FERC hopes to improve business practices and interoperability among public utilities.  The order also shows an intent to foster smart grid technologies, without stifling their development through overly prescriptive or unenforceable regulations.  Will Order 676-H usher in a new era of smart grid and utility cooperation?

Maine regulators approve tidal energy PPA concept

Yesterday, the Maine Public Utilities Commission approved the terms of a power purchase agreement between three large utilities and a hydrokinetic tidal power project in Maine waters.

Low tide at Preble Cove, Great Cranberry Island, Maine.

Hydrokinetic energy projects produce electricity from moving water like tides, waves, ocean currents, or rivers, typically without dams.  As I noted yesterday, a 2010 Maine law required the PUC to conduct a competitive process to solicit proposals for long-term contracts for offshore wind and tidal projects.  The PUC received multiple submissions in response.  Commission staff have been negotiating with some of the bidders, and yesterday approved a proposal by Ocean Renewable Power Co. to sell the output of a small tidal project in Cobscook Bay to Maine's three largest utilities.

Under the terms approved the Commission, ORPC will receive a 20-year contract with utilities Central Maine Power Co., Bangor Hydro-Electric Co., and Maine Public Service Co. to sell the output of its underwater tidal power generation units.  ORPC plans to install the first of these units in Cobscook Bay this summer, and plans to expand its pilot project to include sites off Lubec and Eastport in the next 4 years.

While many of the terms of the resulting contract remain to be worked out, one piece appears firm: the price.  Utilities will pay 21.5 cents per kilowatt-hour for the tide-generated electricity in the first year; this base price of 21.5 cents will escalate at 2% per year, reaching a price of about 39 cents per kWh in the final contract year.  (By way of comparison, the Cape Wind offshore wind PPA approved in Massachusetts starts at 18.7 cents per kWh, with a 3.5% annual escalator over its 15 year term.  The ORPC initial rate is over twice the average rate currently paid by Maine utility customers on "standard offer" default service, or about 5 times higher than the current wholesale price in the New England market.)

For ORPC, the contract is a significant boon.  Securing a 20-year power purchase agreement should greatly assist the developer in securing financing for the project.  This project is designed as a demonstration or pilot project, but may be able to serve as a proof that ORPC's technology and installation systems will work on a larger scale.

For ratepayers, the volume of the contract is relatively low - as licensed by FERC, the Cobscook Project has a maximum capacity of 300 kW - meaning that its above-market costs will be diluted in the much larger pool of power consumed in Maine.  Nevertheless, if the contract volume grows as ORPC builds more of its scalable tidal generation units, those costs will become less and less dilute.  On the other hand, the contract itself - which still needs approval by the PUC once it is finally negotiated - may include other products or commodities such as capacity or renewable energy credits (RECs).  Developers typically prefer securing long-term contracts for as many commodities as possible, which helps solidify their future revenues, but it can make it harder to compare two contracts.

Many tidal projects today face high capital costs, let alone research and development expenses, but many believe that their fuel-free nature will ultimately enable tidal power to have a low fundamental cost of production of electricity in the future.  ORPC's project may shed some light on how that belief fares in the Gulf of Maine.

Incremental hydropower tax incentives

Upgrading existing hydroelectric facilities to improve their efficiency or capacity can be cost-effective.  Not only will the plant produce more electricity more efficiently, but the upgrades may qualify the facility for a tax incentive designed to spur the development of new renewable electricity generation.  For example, installing inflatable flashboards or high-efficiency turbine runners could qualify a project for an energy production tax credit of 1.1¢/kWh. 

As part of the sweeping Energy Policy Act of 2005, Congress amended section 45 of the Internal Revenue Code to expand the renewable electricity production tax credit (or PTC) to incremental production gains from efficiency improvements or capacity additions to existing hydroelectric facilities.  Eligible improvements must be placed in service after August 8, 2005, and before January 1, 2014. 

To qualify incremental hydroelectric generation for the tax credit, the project owner applies to the Federal Energy Regulatory Commission under section 1301(c).  The Commission is required to certify the “historic average annual hydropower production” and the “percentage of average annual hydropower production at the facility attributable to the efficiency improvements or additions of capacity” placed in service during that time period.  The applicant is then able to take the production tax credit for the incremental amount of electric energy produced as a result of the upgrades.

While a credit of 1.1¢/kWh may seem small, hydroelectric projects typically produce relatively large amounts of electric energy at a relatively low operating cost.  Depending on the energy market, at times the tax credit may be worth half as much as the value of the underlying energy.  Also, in this context, the tax credit is only available for the incremental generation produced above the historic baseline; thus allowing incremental hydropower production to qualify for the PTC arguably rewards investment in upgrades.

At the same time, the continued availability of the tax credit for any kind of renewable electricity is in doubt.  Under current law, most renewable resources must be placed in service by the end of 2013 to qualify for the production tax credit.  Wind energy projects must be placed in service by the end of 2012.  Congress is considering whether to renew the tax credit, as it has done a number of times since it was first enacted in 1992.   According to a Congressional Budget Office report released this month, tax credits for renewable energy sources cost the government $1.4 billion in fiscal year 2011.

Headwater benefits charges affect hydropower projects

Suppose you own a federally-licensed dam and hydroelectric generation facilities on a river.  The amount of electricity you can produce is determined by factors including how much water is flowing through your turbines every second and the dam’s “head”, or effective height through which that water falls.  Over an entire year, the amount of power you can produce is also affected by how much water can be stored in the watershed above your dam, and how well you can regulate the flow of water through your turbines.  For example, if you can impound more floodwaters upstream instead of spilling excess water over the dam, you can maintain maximum flows through your powerhouse for a longer period of time than you otherwise could.

Now suppose someone else builds a dam upstream from your site that enables better storage and regulation of water flows through the river.  Setting aside any environmental impacts from that change in flow, one upside of the improved flow regulation is that you can produce more power at your dam thanks to the upstream improvements.

Under the Federal Power Act, you may be required to reimburse that upstream dam owner for an equitable part of the benefits you receive from its improvements.  Federal hydropower licenses typically include a provision requiring the licensee to reimburse the owner of an upstream improvement for these headwater benefits.

Under the Commission’s regulations, headwater benefits charges can be calculated using an “energy gains” methodology.  This analysis includes an assessment of the difference between the number of kilowatt-hours of energy produced at a downstream project with the headwater project and that which would be produced without the headwater project.  Alternatively, dam owners may negotiate an agreement on headwater benefits charges and present it to the Commission for approval as a settlement offer.