FERC's PURPA questions

U.S. energy regulators have invited comments on two issues related to the implementation of the Public Utility Regulatory Policies Act of 1978 (PURPA): its so-called "one-mile rule," and minimum standards for PURPA-purchase contracts.  This opportunity for comment follows a technical conference held earlier this summer.

Congress enacted PURPA to encourage domestic cogeneration and renewable energy production, among other aims.  PURPA established a new class of generating facilities called qualifying facilities (QFs), and gave QFs special rate and regulatory treatment.  Under PURPA, QFs fall into two categories: qualifying small power production facilities and qualifying cogeneration facilities. 

PURPA defines a small power production facility as “a facility which is an eligible solar, wind, waste, or geothermal facility, or a facility which (i) produces electric energy solely by the use, as a primary energy source, of biomass, waste, renewable resources, geothermal resources, or any combination thereof; and (ii) has a power production capacity which, together with any other facilities located at the same site (as determined by the Commission), is not greater than 80 megawatts.”

Under the Commission's so-called "one-mile rule" found in Section 292.204(a) of its regulations, small power production facilities are considered to be at the same site if they are located within one mile of each other, share the same energy resource, and are owned by the same person(s) or its affiliates.  In a September 6, 2016, Notice Inviting Post-Technical Conference Comments, the Commission asked for comments on whether this presumption should be made rebuttable or whether some different spacing requirement should be imposed.

The Commission also asked for comment on the appropriate minimum length of a PURPA purchase contract, or other required contract terms and conditions affecting the development of qualifying facilities (QFs).  To date, the Commission has not required any particular minimum contract length or other minimum contract provisions in PURPA-purchase contracts.

Comments in Docket No. A16-16-000 are due on or before November 7, 2016.

Vermont's new net metering program

Acting under a 2014 law, this summer Vermont utility regulators established a revised net-metering program to take effect in 2017. In a pair of orders, the Vermont Public Service Board prospectively changed the rules governing net metering of solar panels and other distributed generation facilities.  The result is a revision of Vermont's net metering program.

Vermont defines what it calls “net-metering” as “the process of measuring the difference between the electricity supplied to a utility customer and the electricity supplied by the customer’s generation system during the customer’s billing period."  Under the current net-metering program, most net metering customers receive bill credits of either 19 or 20 cents per kilowatt-hour of energy produced by their system. Net-metering customers may also retain the associated renewable energy credits or RECs, and may choose to sell those RECs, transfer the RECs to the utility, or retire them themselves.

As noted by the Public Service Board, net-metering offers benefits for Vermont and ratepayers. It can provide renewable energy and support state greenhouse gas reduction goals. It can benefit ratepayers by avoiding line-losses, reducing capacity charges, and reducing transmission costs. Net-metering can also create local jobs for installers of net-metering systems.  As a result, distributed generation is booming in Vermont -- mostly in the form of net-metered solar photovoltaic installations. According to the Board, “The explosive growth of net-metering in Vermont— particularly due to the development of large net-metering projects— is a direct testament to how attractive the current net-metering incentives are.” The Board noted that the prior program will lead to the development of about 130 megawatts of net-metering capacity.

While net metering in Vermont has been governed by statute since 1998, that law changed in April 2014 when the state legislature passed Act 99 of 2014. That law required the Board to establish a revised net-metering program, pursuant to criteria and standards defined by the legislature.  Based on facts including the growth rate of net-metered capacity, the Board concluded that the current pace of net-metering program needs to be moderated so as to be sustainable in the long term and to mitigate associated rate impacts.

After study and a report by the Department of Public Service, workshops and opportunities for public comment in 2014 and 2015, on June 30, 2016, the Board issued its Order Adopting A Revised Net-Metering Program Pursuant to Act 99 of 2014.  That order laid out a vision for a revised program to be effective in 2017.  At the same time, the board emphasized that its decision was subject to a reconsideration period of 10 business days, during which time comments may be filed seeking reconsideration of the net-metering program.

The Board received over 100 comments in response. In its August 29 Order on Reconsideration, and an accompanying Attachment A, the Board made further changes to its program. For example, the June 30 order set an annual limit on the growth of net-metering installed capacity, with each year’s incremental limit defined as 4% of the state’s peak capacity. The Board described this provision as one of several “intended to manage the pace of development of net-metering systems in Vermont.” But many commenters argued that a 4% annual limit would create market disruptions and a “rush to the door” as applicants race to secure space within the annual quota.

With reconsideration now over, the Board's June 30 and August 29 orders define the new net-metering program that will take effect next year.  From the perspective of rates and bill credits, the new program adopted by the Board features three valuation components. The value of a credit is the sum of “(1) the applicable blended residential retail rate, (2) any applicable REC adjustor, and (3) any applicable siting adjustor.”

The Board defined the applicable blended residential retail rate as the lowest of three possible rates: (1) if the electric company does not have block pricing, the company’s general retail rate, (2) if an electric company uses block pricing, then a blend of those rates, or (3) the weighted average of the blended residential rates for all Vermont electric companies. Under this approach, the statewide average rate acts as a cap on the value of net-metering credits.

The Board adopted two adjustors – a REC adjustor and a siting adjustor – “to encourage and discourage certain behaviors through monetary incentives and to adjust the overall value of net-metering credits.” These adjustors are added to (or subtracted from) the applicable blended residential rate to yield the value of a credit.

The REC adjustor is designed to capture the value related to the customer retaining the RECs associated with net-metered energy. The Board set the values of the REC adjustors as positive (+3) cents per kWh for customers who transfer RECs to their utility and negative (-3) cents per kWh for customers who do not, for a net 6-cent difference between the total compensation received by customers who choose to retain RECs and customers who elect to transfer RECs. This difference matches the 6-cent alternative compliance price for Vermont’s distributed generation or Tier II standard under Vermont’s renewable energy standard statute.

The Board also adopted siting adjustors “to encourage net-metering customers to select more environmentally friendly sites for new net-metering systems.” The Board said siting adjustors will “encourage the environmentally beneficial siting of net-metering projects and thereby help ensure that such projects are in the public good,” and that siting adjustors will allow for better accounting of the benefits and costs of net-metering. For example, the initial siting adjustors provide greater financial incentives to construct net-metering systems up to 150 kW with limited environmental impacts, such as systems that are located on previously developed areas like roofs and parking lots. The siting adjustors will allow the Board to pace the development of net-metering systems over time.

The new program includes a biennial update process, by which the Board will determine the values of REC adjustors, siting adjustors, the state-wide blended residential rate, and the criteria applicable to different categories of net-metering systems. The Board described this section as designed “to ensure that: (1) the pace of deployment of net-metering systems is consistent with the state’s renewable energy goals, (2) net-metering does not result in undue rate impacts, (3) the program accounts for changes in costs of technology over time, and (4) net-metering does not result in cost shifts between net-metering customers and non-net-metering customers.” The Board may also conduct an update sooner than biennially at its own discretion or upon petition by the Department of Public Service.

The Board exempted pre-existing systems from certain requirements of the revised net-metering program, including non-bypassable charges, for a period of 10 years from the date the system was commissioned.  Pre-existing net-metering systems will continue to receive their existing incentive for that 10-year period, after which the value of a credit will be the applicable residential retail rate, without siting or REC adjustors.  The Board said it provided this exemption "in recognition that these systems were installed by customers who relied on a certain set of financial assumptions when they decided to engage in net-metering—a behavior the state has expressly sought to encourage in support of its renewable energy goals." After the 10-year period provided for in this section expires, customers using pre-existing systems will be required to pay non-bypassable charges.

The new program will be effective on January 1, 2017, unless or until it is superceded by a duly adopted rule.  The Board is expected to file its revised Attachment A with the state Secretary of State as a new proposed rule in due course.

ISO-NE offshore wind economic study

Regional electric grid operator ISO New England Inc. has released a report examining the economic impacts of adding significant offshore wind energy into the mainland grid.  Overall, the results project reductions in production costs, energy expense, CO₂ emissions, average wholesale electricity prices, and congestion on key regional transmission interfaces, as offshore wind is added to the grid portfolio.  The study also suggests the scale of revenues available to the offshore wind industry from this scale of development.

The report in question is ISO-NE's 2015 Economic Study: Evaluation of Offshore Wind Deployment.  That report, released on September 2, 2016, presents the results of a study requested last year by the Massachusetts Clean Energy Center (CEC), focusing on the economic impact of up to 2,000 megawatts (MW) of offshore wind deployment into the Southeastern Massachusetts/Rhode Island (SEMA/RI) area. 

According to ISO-NE, the results of this study suggest that "offshore wind deployment could bring sizable economic and environmental benefits to New England."  The study found that while results were sensitive to assumptions like transmission constraints, fuel prices, and carbon allowance costs, overall offshore wind deployment would yield economic benefits.  Annual production cost savings would range from $104 million to $807 million depending on the scenario and scale of development,  while annual load-serving entity cost savings would range from $56 million to $491 million.

The study also found that adding offshore wind would reduce annual systemwide carbon dioxide emissions (by between 1,518 kilotons and 4,230 kilotons), because energy produced by offshore wind would mainly offset emission-producing thermal units.

The study also modeled revenues flowing to offshore wind facilities under the various scenarios, ranging a low of $83 million per year for 1,000 MW under the least favorable conditions, to $732 million with 2,000 MW of offshore wind and most favorable conditions.

While the U.S. is not yet home to any commercially operating utility-scale offshore wind project, interest in marine renewable energy resources is booming.  Deepwater Wind's project off Rhode Island's Block Island is expected to come online this year.  Massachusetts has recently enacted legislation calling for utility procurement of 1,600 megawatts of offshore wind; the developer of a project proposed off Massachusetts was recently acquired by a Danish investment fund; and federal efforts remain ongoing to lease sites on the Outer Continental Shelf for commercial offshore wind development.

Federal dams, nonfederal hydro, and preliminary permits

Can a hydropower developer obtain a preliminary permit from the Federal Energy Regulatory Commission for a project to be located at a federal dam, where the federal entity owning the dam says it opposes the project?  In a series of recent decisions, the Commission has denied preliminary permits in these circumstances, saying there is no purpose in issuing a preliminary permit.

U.S. federal law generally encourages the development of hydropower at existing dams.  Under sections 4(e) and 4(f) of the Federal Power Act, the Commission has general authority to issue preliminary permits and licenses for hydropower projects located at federal dams and facilities.  There are limits on this jurisdiction, such as if federal development of hydropower generation at the site is authorized, or if Congress otherwise unambiguously withdraws the Commission’s jurisdiction over its development.

The Commission also has discretion to deny a preliminary permit application, so long as it articulates a rational basis for its decision.  Through recent precedent, one basis the Commission has developed for denying applications is if the project would rely on modifications to federal facilities, but the federal entity says it would not approve those modifications or opposes the project.

For example, on April 25, 2016, Loxbridge Partners, LLC applied to the Commission for a preliminary permit to study the feasibility of the proposed McNary Second Powerhouse Project No. 14777. The project would be located at the U.S. Army Corps of Engineers’ McNary Lock and Dam facility on the Columbia River in Oregon.  On May 16, 2016, Commission staff asked the Corps for its opinion on whether non-federal development is authorized at McNary Dam, and if so, whether Loxbridge’s proposal would interfere with existing dam operations or improvement plans.  The Corps responded that it believed the Commission does not have jurisdiction to issue a preliminary permit or license for the site, and that the Corps opposed Loxbridge's proposed project on the ground that it would interfere with the Corps’ operation of McNary Dam.  The Corps asked the Commission to reject the permit application.

On September 2, 2016, the Commission denied Loxbridge's preliminary permit application.  It cited recent decisions in which "the Commission has denied preliminary permits for projects at federal facilities after the federal entities indicated that no purpose would be served in issuing a permit because the federal entity would not approve modifications to its federal facilities."  One of these decisions cited, Advanced Hydropower, Inc., 155 FERC ¶ 61,007 (2016), even relates to a different proposal for non-federal hydropower development at the McNary Dam.  The Commission also noted that "because the Corps, which owns the McNary Lock and Dam facility and whose permission would be needed for the development of any project at that facility, has stated that it opposes the project, there is no purpose in issuing a preliminary permit."

The Commission has issued similar denials with respect to Rivertec Partners LLC's proposed Clearwater Hydroelectric Project No. 14753 to be located at the Corps' Dworshak Dam in Idaho, Owyhee Hydro, LLC's proposed Anderson Ranch Pumped Storage Hydroelectric Project No. 14648 to be located at a Bureau of Reclamation dam in Idaho, and Symphony Hydro LLC's proposed Project No. 14627 to be located at the Corps' Upper St. Anthony Falls Lock and Dam on the Mississippi River near Minneapolis.

The policy highlights the importance for project developers of cultivating good relations with federal agencies owning dams and other facilities with hydropower development potential.

Climate change and Katahdin Woods and Waters National Monument

President Obama has established the Katahdin Woods and Waters National Monument in Maine.  His presidential proclamation establishing the monument under federal law cites climate change in two ways: both as an object of study enabled by the monument's protection, and as a challenge against which the monument lands may have special resilience.

Federal law gives the President discretion and authority to establish national monuments, or to "declare by public proclamation historic landmarks, historic and prehistoric structures, and other objects of historic or scientific interest that are situated on land owned or controlled by the Federal Government to be national monuments."  The Antiquities Act of 1906 also allows the President to reserve parcels of land as a part of the national monuments.  While the use of this power can be controversial -- either generally or as applied to specific lands -- well over 100 sites have been designated since President Teddy Roosevelt established Devils Tower as the first national monument in 1906.

Over a century later, on August 24, 2016, in honor of the 100th anniversary of the National Park Service, President Obama used his authority under the Antiquities Act to establish the Katahdin Woods and Waters National Monument.  The new national monument, managed by the National Park Service, protects approximately 87,500 acres of north-central Maine.  It covers land recently donated to the U.S. by philanthropist Roxanne Quimby’s foundation, Elliotsville Plantation, Inc.  That foundation also donated $20 million to supplement federal funds for initial operational needs and infrastructure development at the monument, plus another $20 million in pledged future support.

Climate change and human responses have been a major theme of the Obama administration's policy, and they appear as well in the Maine monument proclamation.  In establishing Katahdin Woods and Waters National Monument, President Obama noted that the monument would enable scientific investigation of the effects of climate change across the boundaries between ecoregions:

Katahdin Woods and Waters possesses significant biodiversity. Spanning three ecoregions, it displays the transition between northern boreal and southern broadleaf deciduous forests, providing a unique and important opportunity for scientific investigation of the effects of climate change across ecotones.

The proclamation also notes the monument area's likely resilience to climate change:

Although significant portions of the area have been logged in recent years, the regenerating forests retain connectivity and provide significant biodiversity among plant and animal communities, enhancing their ecological resilience. With the complex matrix of microclimates represented, the area likely contains the attributes needed to sustain natural ecological function in the face of climate change, and provide natural strongholds for species into the future.

In a statement released along with the official proclamation, the White House noted, "In addition to protecting spectacular geology, significant biodiversity and recreational opportunities, the new monument will help support climate resiliency in the region. The protected area – together with the neighboring Baxter State Park to the west – will ensure that this large landscape remains intact, bolstering the forest’s resilience against the impacts of climate change."

Emera Maine proposes Swans Island Electric Coop acquisition

Maine utility Emera Maine and Swan's Island Electric Cooperative have asked the Maine Public Utilities Commission for approval of Emera Maine's proposed acquisition of the island cooperative.  The electric companies say reducing electric rates for consumers is the motivation.

Swan's Island Electric Cooperative is a member-owned rural electric cooperative incorporated in 1949.  The cooperative provides electric service to approximately 560 meters in the island communities of Swan's Island and Frenchboro.  It receives electricity from the mainland Emera Maine system, via undersea cables running from Mount Desert Island.

In a petition filed September 1, Emera Maine and the cooperative and described a proposed transaction through which Emera Maine would acquire most of Swan's Island Electric Cooperative's assets, acquire all of its service territory, and provide electric service to all Swan's Island and Frenchboro customers. Swan's Island Electric Cooperative would cease providing utility service, wind up its affairs, and formally dissolve the Cooperative.

The petition states that the "primary benefit of the proposed transaction is that Swan's Island and Frenchboro ratepayers will receive immediate and substantial rate relief."  According to the petition, the costs of providing electricity to a remote island and small cooperative membership have led to high electricity rates for customers of the cooperative.

The petition notes that Swan's Island customers currently pay delivery charges of 12.343 cents per kilowatt hour and Frenchboro customers pay 15.917 cents per kilowatt hour.  Fixed meter charges add another $46.84 per month for Swan's Island customers (or $48.26 for Frenchboro.)  The petition contrasts these rates to "a typical residential customer in Emera's Bangor Hydro District", with a delivery charge of 10.770 cents per kilowatt hour and a minimum charge of $7.48 per month.

According to the petition, the cooperative's high rates prompted members to investigate the possibility of a merger with Emera.  This led to the August 31, 2016 execution of an Asset Purchase Agreement, under which Emera will purchase the bulk of the cooperative's assets, acquire its service territory and provide service to its current customers, subject to regulatory approval.  According to the petition, 90% of votes by cooperative members supported the transaction.

The petition describes Emera's commitments as including the installation of modern "smart meters" for all new cooperative customers, and notes anticipation that the undersea cables will need replacement "within the next several years at an estimated cost of $3.4 million."  Emera points to its experience providing service to remote areas, including the Cranberry Isles.

The transaction requires approval by the Maine Public Utilities Commission.  The Commission has docketed it as Docket No. 2016-00209.

ISO-NE Winter Reliability Program 2016-2017

As winter approaches, the operator of New England's wholesale electricity markets is preparing to run another seasonal Winter Reliability Program to address operational concerns related to fuel adequacy.

Since the winter of 2013-2014, ISO New England Inc. has operated a seasonal program to address winter fuel security and power system reliability concerns, relating largely to natural gas pipeline constraints.  After two initial program years, last fall the Federal Energy Regulatory Commission approved a three-year plan for ISO-NE's Winter Reliability Program.

That program, developed chiefly by market participant group New England Power Pool (NEPOOL), was designed to address reliability concerns through at least 2017-2018, when new “Pay-for-Performance” incentives and penalties in New England's redesigned capacity market are set to take effect.  The winter reliability program encourages generators fueled by oil and liquefied natural gas (LNG) to secure fuel before the winter season begins, by compensating them for some costs related to fuel inventory that remains unused at winter's end, and includes a demand response component.  According to ISO-NE, last year's participants included 77 oil-fired units, 8 LNG units, and 6 demand response assets.

The program's rules are specified in Appendix K to Section III of the ISO New England Inc. Transmission, Markets and Services Tariff.  As approved by FERC, the current program retains the three core components of the 2014-2015 Winter Reliability Program: (1) compensation for certain oil inventory that remains in New England following the end of each winter period; (2) end-of-season compensation for LNG contract volumes kept available for winter use but not actually called upon to produce energy; and (3) a supplemental demand response program.

ISO-NE has also published a memorandum describing payment rates for the 2016-2017 winter program.  Under its tariff, ISO-NE first determines a "Set Rate," representing partial compensation for the per-barrel carrying costs of stored fuel oil.  The Set Rate is translated into an equivalent rate for the other, non-oil services that are compensated through Appendix K.

Requests to participate in ISO New England's 2016-2017 Winter Reliability Program are due to ISO-NE by October 1, 2016.