ISO-NE files info on 2022-2023 capacity market auction

This week the operator of New England's wholesale electricity markets made a series of filings with its federal regulator providing information on its upcoming thirteenth forward capacity auction, through which electric generators may commit to providing electric capacity during the period from June 1, 2022 through May 31, 2023.

ISO New England Inc. is the independent system operator and wholesale market-maker for most of New England's electricity grid. It is a private, not-for-profit entity, which operates pursuant to a tariff on file with the Federal Energy Regulatory Commission. As part of its planning for system operations, ISO-NE operates a forward capacity market through which it conducts annual auctions through which qualified generators and other resources may bid to obtain commitments to provide capacity in a future year, in exchange for which resources will be compensated. The next primary auction for capacity supply obligations will be Forward Capacity Auction 13 (or FCA 13), which will be held beginning on February 4, 2019, and will cover the 2022-2023 capacity commitment period.

In advance of each primary auction, ISO-NE calculates an "Installed Capacity Requirement," which it defines as a measure of the installed resources that are projected to be necessary to meet reliability standards in light of total forecasted load requirements for the New England Control Area and to maintain sufficient reserve capacity to meet reliability standards. In computing the Installed Capacity Requirement, the grid operator considers parameters and assumptions including load forecast, resource capacity ratings, and resource availability. It also considers what relief can be obtained during a capacity deficiency through measures including emergency assistance (tie benefits) from neighboring interconnected regions (New Brunswick, New York, and Quebec), load reduction by reducing system voltage by 5%, and running the system at a minimal level of operating reserve.
 
In its November 6 Installed Capacity Requirement filing, the grid operator told the Commission that it proposed a installed capacity requirement for FCA 13 of 33,750 megawatts, after taking into account 969 megawatts of credits over interconnection with Canadian utility Hydro-Quebec.

In a parallel Informational Filing for qualification in FCA 13, the grid operator noted that 31,432 megawatts of existing generating capacity resources qualified for the 2022-2023 capacity commitment period, as did 80 megawatts of existing import capacity resources, and 3,413 megawatts of existing demand capacity resources, totaling 34,925 megawatts of existing capacity. Some resources submitted bids to retire, and 3,223 megawatts of resources submitted bids to withdraw in part or in whole from the auction if it clears below a defined price. Additionally, ISO-NE qualified 238 new capacity resources, totaling 8,716 megawatts.

ISO-NE will conduct its thirteenth forward capacity auction starting on February 4, 2019.

FERC Order 845 reforms interconnection process

U.S. utility regulators have issued an order adopting a final rule reforming the procedures through which electric generators obtain interconnections to the utility grid. The Federal Energy Regulatory Commission's Order No. 845 adopts a final rule which implements ten specific reforms designed to provide interconnection customers better information and more options, in the hopes that transmission providers will better be able to focus on interconnection requests that are likely to reach commercial operation.

Generally speaking, generators need to interconnect to the utility grid (and to consumers) for their power to be valuable. Under the Federal Power Act, many generator interconnections are subject to regulation by the Commission. In December 2016, the Commission issued a Notice of Proposed Rulemaking proposing 14 sets of reforms to its interconnection regulations. In that notice, the Commission cited changes to the electric power industry since the Commission issued its Order No. 2003 governing interconnections, and concerns including long queues and delays for interconnection studies, and a lack of certainty around timing and costs.

As a result, in 2016 the Commission preliminarily found that the interconnection process may hinder the timely development of new generation, and thereby stifle wholesale competition, resulting in rates, terms, and conditions that are not just and reasonable or are unduly discriminatory or preferential. The Commission also preliminarily found the interconnection process could result in uncertainty and inaccurate information, and a potential for discrimination as new technologies enter the market.

Now, following a technical conference and 63 public comments, the Commission issued its order adopting the final rule on April 19, 2018. The final order adopted many of the Commission's 2016 proposals, while deviating from that earlier proposal in some regards.

Among other items, the final rule includes two sets of reforms designed to improve certainty for interconnection customers, four aimed at promoting more informed interconnection decisions, and four designed to enhance the interconnection process.

The Commission also decide to revise its pro forma Large Generator Interconnection Procedures and  Large Generator Interconnection Agreement, to mitigate concerns about systemic inefficiencies, discriminatory utility practices, and time spent on interconnection requests that are unlikely to reach commercial operation.

The final rule, codified as 18 C.F.R. Part 37, will become effective 75 days after its publication in the Federal Register.

FERC Order 842 requires primary frequency response by generators

U.S. energy regulators have issued an order amending standard interconnection agreements to require new generators to install, maintain and operate a functioning governor or equivalent controls capable of primary frequency response as a precondition of interconnection. The Federal Energy Regulatory Commission's Order No. 842 also amended the pro forma interconnection agreements to include certain operating requirements including maximum droop and deadband parameters, and sustained response provisions.

As described by the Commission, reliable operation of an alternating current grid requires maintaining system frequency within predetermined boundaries above and below 60 Hertz. Frequency response describes an interconnected grid’s ability to arrest and stabilize deviations from this predetermined range of frequencies after a sudden loss of generation or load.

Historically, the U.S. grid's primary frequency response capability came from baseload synchronous generators such as coal-fired power plants. But many such plants have retired in recent years, with further retirements expected. In 2016, the Commission noted that shifts in the portfolio of U.S. electric generators meant fewer resources could likely provide primary frequency response, especially if new variable energy resources such as wind and solar did not provide this service. In response, it opened an inquiry into what primary frequency response reforms it should make.

On February 15, 2018, the Commission issued its Order No. 842 revising its regulations to require newly interconnecting large and small generating facilities, both synchronous and non-synchronous, to install, maintain, and operate equipment capable of providing primary frequency response as a condition of interconnection. The final rule also amends the Commission's pro forma interconnection agreements to include certain operating requirements including maximum droop and deadband parameters, and sustained response provisions. It provides exemptions for nuclear power plants and some combined heat-and-power plants.

These requirements will apply to most newly interconnecting generation facilities that execute, or request the unexecuted filing of, an LGIA or SGIA on or after the rule’s effective date, as well as to existing large and small generating facilities that take any action that requires the submission of a new interconnection request that results in the filing of an executed or unexecuted interconnection agreement on or after the effective date.

In a press release, the Commission said its action was intended to address "the increasing impact of the evolving generation resource mix." Commissioner LaFleur made a separate statement in which she noted that while decreases in the nation's portfolio percentage of synchronous generation have contributed to declining frequency response performance, "recent technological advancements have enabled new non-synchronous generating facilities, such as wind and solar, to cost-effectively include primary frequency response capabilities in their facilities." Improved inverters and battery storage are among these innovations.

The Commission has also recently noted the potential of electric storage resources to provide frequency response and other services. Its Order No. 841 is designed to remove barriers to the participation of electric storage resources in wholesale markets operated by regional transmission organization and independent system operators, including markets for frequency response.

Will clustering help New England's interconnection queue?

Faced with a persistent backlog of requests to interconnect to the electric grid across parts of New England, will the region's major grid operator adopt a "clustering" methodology to streamline the study process and reduce procedural delays?

At issue are ISO New England's interconnection procedures, which govern the process through which generators and transmission lines may interconnect to the New England bulk power system.  For nearly all large projects and some smaller ones, ISO-NE administers the process and conducts extensive engineering studies to determine whether such interconnections would be feasible without adversely affecting reliability and how they should be accomplished.  In general, ISO-NE uses a first-come, first-served basis: a project's impacts on the grid are studied in sequential order based on that project's position in the interconnection queue.  In practice, this means that a project's studies do not commence until the studies for projects ahead in line are complete.

According to ISO-NE, this system has worked well for most of the region.  Excluding northern and western Maine, the grid operator reports that on average, system impact studies are completed within a year of the customer's interconnection request.  But ISO-NE notes that its "Interconnection Queue has experienced a persistent backlog of requests to interconnect in northern & western Maine."  Many of these requests relate to wind projects located relatively far from the transmission system, but similar challenges could arise relating to large solar projects in parts of Maine, Vermont, or New Hampshire.

The grid operator may be able to address this backlog by changing its interconnection procedures to be more in line those adopted in other regions, by allowing "clustering" or pooled and simultaneous study of certain resources. As described by ISO-NE in a presentation delivered last year, all of the other Independent System Operators or Regional Transmission Organizations -- such as NYISO, PJM, MISO, CAISO, and SPP - include some form of clustering in the interconnection process; New England stakeholders have requested that ISO-NE investigate clustering; and the Federal Energy Regulatory Commission has also addressed clustering, including in a May 2016 technical conference.

ISO-NE's proposed clustering methodology would allow, under specific circumstances, for two or more Interconnection Requests to be analyzed in the same System Impact Study (SIS) effort.  Projects participating in a cluster would share cost responsibility for certain shared interconnection related transmission upgrades, known as Cluster Enabling Transmission Upgrades (CETU), identified by ISO-NE as necessary for the applicable interconnection requests to interconnect.

As noted in an April 2017 presentation to the NEPOOL Participants Committee, this proposal was favorably voted by the Transmission Committee on January 24, 2017 and by the Participants Committee on February 3, 2017.

The presumptive next step forward in New England's attempt to resolve the interconnection queue backlog by clustering studies would be that ISO-NE will file its tariff revisions with the FERC -- but the grid operator has signaled an intent to wait to file the revisions until there is "a high probability of a FERC quorum."  Three of the five seats on the Commission are presently vacant, and the Commission is currently operating without a quorum.  In the meanwhile, ISO New England's present tariff does not allow clustering of studies, so for now customers and others proposing to interconnect generation or transmission into the New England grid will continue to wait and push for reform.

Nova Scotia tidal turbine installed

A Canadian tidal power developer has installed a turbine at a test site in the Bay of Fundy. Cape Sharp Tidal's project off Nova Scotia could demonstrate the feasibility of larger-scale marine hydrokinetic power plants connected to the mainland electricity grid.

Cape Sharp Tidal is a joint venture between Canadian utility Emera Inc. and marine turbine manufacturer OpenHydro.  Its project entails a grid-connected 4-megawatt array consisting of two tidal turbines.  The project is located at the Fundy Ocean Research Center for Energy (FORCE) site.  Headquartered near Parrsboro, Nova Scotia, FORCE is Canada's leading research center for in-stream tidal energy, with demonstration berths, a grid interconnection capable of accepting tidal power, and environmental monitoring capabilities.

This week Cape Sharp Tidal deployed the project's first turbine-generator, a 2-megawatt OpenHydro unit.  In subsequent work, crews interconnected the turbine cable tail to the FORCE site's main interconnection cable, an existing 16MW subsea export cable connected to an onshore substation.

Previous efforts to develop hydrokinetic tidal energy projects in the Bay of Fundy have met with difficulty.  While the bay offers large and powerful tides, weather and sea conditions can prove challenging, as can obtaining environmental and regulatory approvals.  A test tidal turbine deployed in 2009 was quickly destroyed; the turbine installed this week was originally slated for installation earlier but was delayed due to concerns over impacts to fisheries and the environment.  This week's installation represents a concrete step forward for Canadian tidal power.

Cape Sharp Tidal intends to install and connect a second turbine at the FORCE site in 2017.  According to the developer, its future plans -- subject to regulatory and business approvals -- could include a commercial-scale project of up to 300 megawatts capacity within 15 years.

Electric storage resources technical conference set

U.S. energy regulators have scheduled a technical conference to discuss electric storage resources and how they could fit into the electric grid -- and how they might be compensated for doing so.  The Federal Energy Regulatory Commission will convene the discussion on November 9, 2016.

An electric storage resource is a facility that can receive electric energy from the grid and store it for later injection of electricity back to the grid.  Different projects might use different storage mediums -- for example, batteries, flywheels, or pumped hydropower.  A storage resource could be as small as a household battery, or as large as gigawatt-scale pumped storage. Projects could be interconnected in various ways -- such as to the transmission system, distribution system, or behind a customer meter -- and could serve different markets, ranging from regional transmission organizations and independent system operators, to transmission or distribution utilities, to customers or end users of electricity.

While each energy storage resource configuration offers its own different advantages and disadvantages from various perspectives, overall the Commission has noted that "storage resources may fit into one or more of the traditional asset functions of generation, transmission, and distribution."  In the Commission's Notice of Technical Conference, it expressed a desire "to explore the circumstances under which it may be appropriate for electric storage resources to provide multiple services, whether the RTO/ISO tariffs need to include provisions to accommodate these business models, and how the Commission may ensure just and reasonable compensation for these resources in the RTO/ISO markets."

The specific subject of the conference described in the Notice is "the utilization of electric storage resources as transmission assets compensated through transmission rates, for grid support services that are compensated in other ways, and for multiple services."  The Notice also sets up discussion of other issues including

(1) potential models for cost recovery for electric storage resources utilized as transmission assets, while also selling energy, capacity or ancillary services at wholesale;

(2) potential models to enable an electric storage resource to provide a compensated grid support service (like a generator providing  ancillary services under a reliability must-run contract) rather than being compensated for providing transmission service; and

(3) practical considerations for electric storage resources providing multiple services at once (i.e., providing both wholesale service(s) and retail and/or end-use service(s)). 

FERC will webcast and transcribe the conference, in addition to allowing in-person attendance.  The Commision directed those wishing to participate to submit a nomination form online by 5:00 p.m. on October 14, 2016.

Energy storage is attracting increased interest.  In another open docket, the Commission issued a series of data requests and a request for public comment in an effort to identify barriers to electric storage resources' participation in organized electricity markets in the U.S that could lead to unjust and unreasonable wholesale electricity rates.  In 2009, then-Chairman Wellinghoff testified before the Senate Committee on Energy and Natural Resources on the role of grid-scale energy storage as it relates to U.S. energy and climate goals, including its ability to integrate variable resources such as wind and solar into the grid.  Meanwhile, states too are pursuing storage opportunities.  A Massachusetts state energy office has issued a report finding that Massachusetts has the potential to develop for 600 MW of energy storage by 2025, which could lower costs, reduce carbon emissions, and improve grid reliability.

Maine examines interconnection standards

The Maine Public Utilities Commission has opened an inquiry into whether it should change its rule governing how small distributed generation resources may interconnect with the electric grid.  This small generator interconnection procedures inquiry may reshape how distributed energy resources will interconnect with the Maine grid going forward.

While many large central power plants are subject to some federal regulation, states generally may prescribe the standards for how most solar photovoltaic panels and other small distributed energy resources may interconnect with the grid.  Interconnection standards and procedures are designed to provide a safe, fair, and timely way for utility customers to connect generation to the grid.

In a 2009 report, the Maine Public Utilities Commission concluded that it should create standardized, statewide interconnection procedures for Maine’s utilities.  In the Commission’s view, “standardized rules would increase the efficiency of the interconnection process, encourage the increased use of renewable energy and other distributed generation resources like micro combined heat and power systems, and may foster an easier business environment for the companies that sell and install small generation systems.”

In 2010, the Commission adopted its Rule Chapter 324, Small Generator Interconnection Standards.  That rule was based largely on model standards released by the Interstate Renewable Energy Council (IREC) in 2009, which were themselves based on the federal Small Generation Interconnection Procedures.  While the Commission adopted minor changes to Chapter 324 in 2013, it remains largely as originally adopted.

At the same time, the intervening years have brought changes to some of the context for interconnection issues.  First, IREC has updated its model standards.  The most recent edition, released in 2013, features significant changes from the prior standards, including the creation of a pre-application report, changes to the application fees for interconnection review, and definitional clarifications.

Second, increasing adoption of distributed generation has led FERC and state regulators to consider whether small generation facilities should be required to have “frequency and voltage ride through capability”, an ability to protect the grid’s reliability as amount of distributed generation grows on the electrical system.

In light of these developments, the Maine Commission has issued a notice of inquiry seeking comment on these issues.  According to that notice, the inquiry will assess “whether and to what extent Chapter 324 should be revised to (1) reflect changes in the IREC interconnection standards and procedures and (2) incorporate requirements for frequency and voltage ride through capability of small generation facilities.”

The Commission has docketed the case as Docket No. 2016-00068, and requests public comment by May 20, 2016.

Generator interconnection technical conference scheduled

The Federal Energy Regulatory Commission has scheduled a technical conference to generator interconnection issues, including interconnection of energy storage.

The case has its origins in a 2015 petition to the Commission by the American Wind Energy Association, seeking a rulemaking to revise certain provisions of the Commission's pro forma Large Generator Interconnection Procedures (“GIP”) and pro forma Large Generator Interconnection Agreement (“GIA”).

AWEA is a national trade association representing a broad range of entities with a common interest in encouraging the expansion and facilitation of wind energy resources in the United States. Its members include wind energy facility developers, owners and operators, construction contractors, turbine manufacturers, component suppliers, financiers, researchers, utilities, marketers, customers, and their advocates.

In that petition, the trade group argued:

the time is ripe for the Commission to make certain regulatory and policy changes to interconnection procedures in order to remedy unduly discriminatory and unreasonable barriers to generator market access that inhibit the development of electric generation to meet the growing needs of electricity customers, and to facilitate the current dramatic transformation of the electric generation system (driven, in part, by Federal and State policies) in a timely, reliable and cost-effective manner.

AWEA's petition called for a variety of reforms to the interconnection procedures and agreement, particularly aimed at improving "(a) certainty in the study/restudy process; (b) transparency in the interconnection process; (c) certainty of network upgrade costs; and (d) accountability in the interconnection process."  After many comments were submitted on the rulemaking petition, AWEA asked the Commission to hold a technical conference as a forum for "open discussion" among interested parties.

The Commission has now issued notice of a technical conference to be held on May 13.  According to the notice:

The purpose of this conference is to discuss select issues related to a petition for rulemaking submitted by the American Wind Energy Association (Docket No. RM15-21-000). In addition, the conference will explore other generator interconnection issues, including interconnection of energy storage.

The notice also states that discussions at the conference may involve issues raised in other proceedings pending before the Commission, including without limitation 8 sets of specifically listed cases:

• E.ON Climate & Renewables North America LLC, Pioneer Trail Wind Farm, LLC, Settlers Trail Wind Farm, LLC v. Northern Indiana Public Service Company, Docket No. EL14-66-002;

• Entergy Arkansas, Inc., Docket No. ER14-671-000;

• Internal MISO Generators v. Midcontinent Independent System Operator, Inc., Docket No. EL15-99-000;

• Midcontinent Independent System Operator, Inc., Docket No. ER16-675-000;

• California Independent System Operator Corporation, Docket No. ER16-693-000;

• ISO New England, Inc., Docket No. ER16-946-000;

• Midcontinent Independent System Operator, Inc., Docket No. ER16-1120-000; and

• Midcontinent Independent System Operator, Inc., Docket No. ER16-1211-000. 

The conference will be held on May 13 at Commission headquarters in Washington, DC.

FERC considers Primary Frequency Response reforms

U.S. energy regulators are considering whether reforms are needed to regulations for the provision and compensation of primary frequency response, a function essential to the electric grid's operation.

In general, the U.S. bulk power system operates on an alternating current.  For reliability and interoperability, that current must maintain its frequency within predetermined boundaries above and below 60 Hertz.  An interconnected grid’s ability to arrest and stabilize frequency deviations within those boundaries after a sudden loss of generation or load is called "frequency response." A grid's frequency response characteristics are affected by factors including inertial response (as spinning generators speed up or slow down when load changes), primary frequency response, and secondary frequency response.  Historically, most primary frequency response has been provided by baseload synchronous generators as an ancillary service.

But the U.S. electric grid's energy mix is changing.  In a Notice of Inquiry released on February 18, 2016, the Federal Energy Regulatory Commission notes that changes to the U.S. electric supply portfolio likely mean that fewer resources are now primary frequency response.  In particular, the U.S. has seen broad retirement of coal-fired baseload synchronous generators, some of which provide primary frequency response, while some have been replaced with variable energy resources such as wind and solar which do not typically have primary frequency response capabilities.

In response, FERC solicited public input on whether and what action is needed, including whether to:

• Amend the pro forma Large Generator and Small Generator interconnection agreements to require that all new generation resources have frequency response capabilities as a precondition of interconnection;


• Implement primary frequency response requirements for existing generation resources; and


• Establish procurement and compensation mechanisms for primary frequency response.

FERC has docketed the matter as RM16-6-000, Essential Reliability Services and the Evolving Bulk-Power System — Primary Frequency Response.  Comments on the Notice of Inquiry are due 60 days after publication in the Federal Register.

Park and forest service renewable energy

Managers of national and state parks and forests are considering whether they can cut their energy bill by developing distributed generation projects.  In many cases, distributed generation such as solar photovoltaic systems can be a good match for powering facilities like park headquarters, campgrounds, and maintenance buildings.  This can be especially true for places that are off the main electric grid, such as pockets of development within preserved lands.  It can also be true for grid-tied facilities, as incentives like net metering can make rooftop solar or other projects cost-effective for the end user.

Solar photovoltaic panels power the campground at Goblin Valley State Park, Utah.

Whether developed by a national park or state forest, connecting renewable generation to the grid involves working with the local electric utility.  In many parts of the country, interconnecting with the utility can be a challenging process.  Utilities typically must study whether the proposed generation can work with the existing set of transmission and distribution wires, and may get into disputes with customers over whether and how much upgrading is needed.  Some utilities claim to be swamped with interconnection requests, and are missing deadlines for studying system impacts and cooperating with customers.

In California, a different set of difficulties is preventing millions of dollars of renewable energy projects on federal land from connecting to the grid.  In response to economic incentives favoring distributed generation, the National Park Service and U.S. Forest Service have developed major new renewable projects at a variety of sites in California.  For example, the Park Service developed an $800,000 solar project at Death Valley National Park, anticipated to cut 70% off the visitor center's annual electric bill of about $45,724.  The Forest Service developed a large solar project at its Mono Lake facilities, along with other projects at existing sites.  However, the federal agencies have been unable to sign interconnection agreements with utility Southern California Edison, meaning the parks' renewable projects remain idle despite federal policy supporting sustainable operations.

At issue is a provision of federal law that prevents agencies from signing contracts exposing them to the risk of unknown future damages because such contracts would commit money outside the congressional budgeting process.  Federal agencies have been able to work around this restriction with other utilities, as evidenced by Yosemite National Park's successful interconnection of its $5.8 million solar photovoltaic project with the Pacific Gas & Electric grid.  Southern California Edison appears to be a holdout.

Will 2012 see a continuation of the trend toward replacing diesel electric generation in parks and national forests with alternative resources?

Massachusetts may revamp solar and distributed generation interconnection process

Being able to interconnecting electricity generating units to the grid is almost always necessary.  Even islands - literal or figurative - often have their own microgrids to which new generation must be interconnected, but usually the electric grid in question is run by a public utility.

Despite federal and state policies designed to promote the development of solar energy projects and other renewable and efficient distributed generation, many utilities are failing to process interconnection applications within the timelines required by their tariffs.  (As I previously wrote, regulators in the Canadian province of Ontario are currently wrestling with this problem as well.)  A recent filing by the energy office of the Commonwealth of Massachusetts appears likely to trigger reforms to the process for interconnecting new distributed generation to the grid.

The Massachusetts Department of Energy Resources’s filing consists of a consultant's report commissioned by DOER and the Massachusetts Clean Energy Center, coupled with a formal petition requesting that the Department of Public Utilities open an investigation on interconnection procedures.

Prepared by consulting firm KEMA, the report provides a snapshot of the current interconnection process, as well as offering recommendations for improvements.  The report is based on surveys of distributed generation developers and utilities.  The report’s key findings include:

• Significant Increase in New Distributed Generation:  Recent years have brought a significant increase in the volume of applications for interconnection of distributed generation in Massachusetts.  The volume of interconnection applications reviewed grew by a factor of 7 between 2004 and 2010 - a significant increase in interconnection requests.
• Current Process Can't Handle the Volume:  A very high percentage of utility reviews of interconnection requests have missed key deadlines.  For example, in 2009, 100% of the interconnection application review conducted under utilities’ standard process exceeded the timeline specified in the utility’s tariffs.  Currently, utilities face no penalty for missing these deadlines.  As the report notes, “There is no consequence to the utilities for delays, even though there are consequences – often significant – to the DG applicants.”
• Interconnection Costs Cause Frustration:  While current application fees and witness test costs may be reasonable, the report notes that applicants are generally dissatisfied with the costs of the interconnection facilities upgrades and equipment required by utilities.  Disputes over the nature and cost of new and upgraded facilities increase costs, add delays, and further chill distributed generation development through increased uncertainty.

The report notes that these failings come despite significant policy support for distributed generation:

In summary, the meta-message of this report rests at the intersection of several trends.  Massachusetts has created a vibrant policy environment for DG, underpinned by one of the best interconnection processes in the country, a process which has generally worked well for most DG applicants since its introduction in 2004. Over the last seven years, however, and particularly under the Patrick Administration, the growth in DG volume has grown significantly.

Yet, our survey showed that 79% of Expedited applicants and 75% of Standard applicants are “Somewhat dissatisfied” or “Very dissatisfied” with a process they describe as long, inconsistent, and “too complicated to comment”. . . .

We define a successful process as one that meets its customer demand with high quality outcomes, within acceptable parameters of time and cost. This review demonstrates that – seven years after its introduction – the current process by which DG is interconnected in Massachusetts is no longer meeting the demands of three-quarters of its customers.

Based on these findings, the report offers recommendations to remedy the system's failure, including proceedings before the State Department of Public Utilities to redesign the interconnection process to be better suited to high-volume penetration of distributed generation.

The DOER’s petition was filed on August 18, 2011.  The Department of Public Utilities is expected to respond to the petition by opening an investigation on interconnection along the lines suggested in the report.  How that proceeding affects the experiences of utilities, distributed generation owners or developers, and ratepayers remains to be seen.

August 15, 2011 - Canadian utility versus distributed solar

State and provincial governments are implementing programs designed to promote the growth of small-scale distributed renewable energy projects like solar photovoltaic installations.  For these programs to succeed, new distributed energy projects need to be able to interconnect into the existing utility grid on a fair and predictable timeline.  For this reason, feed-in tariff and other distributed generation programs must work hand-in-hand with utility tariffs requiring fair interconnection access – but some solar and renewable industry groups are concerned that utilities may not be honoring these obligations.

A small solar array serving the Utah Communications Agency Network radio system atop Beaver Mountain, UT.

Consider the example of the Canadian province of Ontario.  The Ontario Power Authority – the entity charged with ensuring an adequate, long-term supply of electricity in Ontario – offers feed-in tariff programs for qualified generation.  Ontario’s “micro-FIT” program gives developers of small renewable power projects – 10 kW or less – long-term contracts to sell the projects’ output at a fixed price.  For rooftop solar projects, these contracts pay 80.2 ¢ per kWh for a 20-year term – about ten times the most recent regulated retail electricity price in Ontario.

As anticipated, this program has drawn interest from thousands of developers of small generating units – perhaps as many as 25,000 by earlier this year.  Each of these projects is entitled to interconnect to the electric grid in a timely fashion, but doing so requires the local utility to evaluate the technical and engineering aspects of the interconnection to ensure safety and system reliability.  For example, a utility must formally offer to interconnect with a project within 15 days if it is at an existing interconnection point, with actual interconnection to be completed within 5 days after the utility receives its customer’s payment and signed agreement.

Some utilities are having trouble complying with this schedule.  In a case currently pending before Ontario’s energy regulator, one utility has asked for a waiver of the interconnection timeline.  Hydro One Networks Inc.’s April 2011 petition to the Ontario Energy Board, docketed as case EB-2011-118, notes that it was in non-compliance on an estimated 442 interconnection applications based on the utility’s failure to meet tariffed deadlines.  As a result, the utility asked to be relieved of its scheduling commitments for six months.

Businesses, homeowners, and the solar installation industry have objected to this request, pointing out that they have already suffered great harm as a result of the utility’s failure to meet its interconnection timing deadlines.  Evidence submitted in the case suggests millions of dollars in lost revenue, layoffs, and business closures as a direct result of the utility’s missed deadlines.

The Ontario Energy Board conducted hearings on the utility’s waiver request, but has not yet issued a ruling.  When it does, it may affect not only people interested in solar energy development but moreover the balance between traditional centralized utility organization and Ontario’s pro-distributed generation feed-in tariff policy.

July 27, 2011 - why FERC issued Order No. 1000, and what it means

I've been covering FERC Order 1000, a landmark regulatory decision that will reshape the U.S. electric grid.

To understand what FERC's Order No. 1000 means for the U.S. transmission system, you need to understand the direction in which the electric industry is changing.  A shift in the generation mix coupled with a sharp uptick in transmission line construction are largely responsible for the need for reforms.

Utility investment in transmission lines is booming.  For example, utility members of the Edison Electric Institute reported $55.3 billion in new transmission facility investment, while another report commissioned by EEI suggests about $298 billion in new transmission facility needs between 2010 and 2030.  In the next five years, new transmission line mileage will be built at a rate nearly three times higher than the historical average.

Why is so much new transmission line being built?  FERC points to changes in the generation mix.  Between air emissions regulation, state renewable portfolio standards, and fuel costs, the mix of energy resources used to generate electricity is shifting.  An increasing reliance on natural gas and large-scale integration of renewable generation means new transmission lines are needed to connect these new generators to markets.  Meanwhile, while coal-fired generation continues to be significant, some facilities like the Salem Harbor Power Station are being retired.  The existing electric grid was not built to accommodate these shifts in the energy mix.

With so much transmission line development underway, the stakes are high.  How lines are planned affects whether society finds the least-cost solution to our electric needs.  How the costs of new transmission lines are split affects whether users of the electric grid -- including both consumers and generators -- get fair treatment.  In issuing Order No. 1000, FERC concluded that the status quo can lead to inefficient and higher-cost decisions being made:

We conclude that the narrow focus of current planning requirements and shortcomings of current cost allocation practices create an environment that fails to promote the more efficient and cost-effective development of new transmission facilities, and that addressing these issues is necessary to ensure just and reasonable rates.

Order No. 1000 aims to fix these shortcomings through new requirements on the transmission planning and cost allocation processes.

September 1, 2010 - vehicle energy efficiency; federal renewable power?

A stone wall, forgotten in the woods in Bath, Maine.  Most stone walls in New England were built between 1750 and 1850; in 1940, a United States government survey estimated that there were more than 250,000 miles of stone walls in New England -- almost all built by manual labor and power from draft animals, during a time of lower energy intensity.

 
From the vehicle energy efficiency department: the U.S. Environmental Protection Agency and Department of Transportation are jointly revising vehicle window stickers for the 2012 model year. This Wired article describes one option they are considering: assigning new vehicles letter grades for fuel efficiency.  (Examples from the article: Nissan Leaf: A+.  Plug-in Toyota Prius: A.  Toyota Camry: B-.)  Electric vehicles appear more likely to play a larger role in transportation in years to come.

Some may recall the day in 1979 when President Jimmy Carter installed solar panels on the roof of the White House.  They didn't stay there long; President Reagan removed them in 1986.  By 1990, they were donated to Unity College in Maine.  Now, Bill McKibben and others are taking the solar panels to Washington in an effort to convince President Obama to install solar or other renewable generation at his house -- not to mention the federal government's role as the nation's largest energy consumer.

I watched this week's deliberations of the Maine PUC as the Commissioners conditionally approved Central Maine Power's plan to upgrade a section of its 34.5 kV transmission line to 115 kV.  The reason?  To let power from Record Hill Wind LLC's project reach the grid.  The Commission required the wind developer to make a three-month prepayment to CMP of all construction costs, and report to the Commission quarterly as the project moves forward.

Island issues: I've written before about the difficulties of ensuring a water supply on island communities -- both potable water for drinking and any old water for firefighting.  Monhegan, for example, has a culture that is purposely very alert to fire danger.  Today's news has an example of why: fire destroyed a home on Pole Island in Quahog Bay in Harpswell -- despite valiant efforts by firefighters, neighbors and volunteers.