Maine commission rejects LNG contract proposals

Friday, May 19, 2017

Maine utility regulators have decided not to order utilities to enter into contracts for liquefied natural gas storage capacity, after finding that none of the proposed contracts satisfied statutory requirements.

In 2013, the Maine legislature enacted the Maine Energy Cost Reduction Act in response to concerns about natural gas and electricity price increases driven by constraints on natural gas supply into and within the New England region.  That law authorized the Maine Public Utilities Commission to execute (or to direct utilities to execute) one or more "energy cost reduction contracts" for natural gas pipeline capacity, if certain prerequisites were met.

In 2016, the legislature enacted a further law amending the Maine Energy Cost Reduction Act, to include liquefied natural gas storage capacity -- "physical energy storage"-- along with interstate natural gas pipeline as within the Commission’s authority for long-term capacity contracts.  In a subsequent proceeding, the Commission solicited bids, ultimately considering 11 physical energy storage contract (PESC) proposals from 6 bidders.

But according to the Commission's order, analysis by its consultant Navigant "indicated that no PESC proposal would provide more than a minimal reduction to natural gas or electricity prices in the regional wholesale markets. Thus, no PESC would reduce electricity prices for Maine consumers, and any benefits of the PESC come from managing the purchase and sale of gas stored in the physical energy storage facility at differing times of the year and flowing those differences back to ratepayers."  The Commission noted that "perhaps the most useful aspect of the Navigant analysis is the extent to which it demonstrates the risks of the PESCs, given the extent to which the cost-benefit results are shown to be highly sensitive to assumptions about the future, such as the presence or absence of ANE and the use of winter peak-day vs. average-day prices."

The Commission further found that "there is no barrier that would prevent private entities from developing LNG storage facilities in the region; thus, under existing market rules, private transactions can be expected to achieve substantially the same market price impacts as those which might occur through the execution of a PESC."  The Commission also concluded that "the proposed PESCs do not meet the statutory prerequisites with respect to market rules and private transactions, cannot be considered economic or commercially reasonable, will not have a significant impact on natural gas or electric prices, and will not significantly enhance reliability in Maine or the region. Moreover, the proposed PESCs expose the State's utility ratepayers to substantial risk and could result in significant rate increases, particularly in the near term."

For these reasons, the Commission concluded that "none of the PESC proposals presented in this docket satisfy the statutory requirements specified in LNG Storage Act. Therefore, the Commission cannot order the execution of a PESC."

In the meantime, progress on an Energy Cost Reduction Contract for pipeline capacity appears stalled, despite years of proceedings and initial progress.  The Commission issued its Phase 1 Order on November 13, 2014 in which it made the necessary prerequisite findings for ordering a pipeline contract, and invited proposals.  It issued its Phase 2 Order on September 14, 2016, finding that two pipeline capacity proposals satisfied the statutory requirements for acceptance and would benefit ratepayers.  But on November 26, 2016, the Commission postponed further activities regarding the development and review of a precedent agreement for pipeline capacity, pending future developments in other New England states, noting that it would monitor such developments and would renew activity in the docket in the future if circumstances warrant. There has been no activity in the pipeline contract docket since the issuance of that November 26 order.

Massachusetts community microgrid projects solicited

Thursday, May 18, 2017

A Massachusetts economic development agency focused on clean energy has launched a program seeking to catalyze the development of community microgrids throughout Massachusetts.

Generally speaking, a microgrid is a localized power grid that can disconnect from the traditional grid to operate autonomously.  According to the U.S. Department of Energy, a microgrid's ability to operate while the main grid is down means microgrids can strengthen grid resilience and mitigate disturbances, while enabling faster system response and recovery once reconnected to the main grid. Microgrids can also support flexibility and efficiency, by enabling the integration of growing deployments of renewable and distributed energy resources like solar, and by reducing energy losses in transmission and distribution.
 
A "community microgrid" could be defined in several ways, but a typical definition focuses on a multi-user microgrid providing electrical and/or thermal energy to multiple consumers, integrated with and supported by the local community, relevant utilities, and building or site owners.  As with other microgrids, a community microgrid implementation could reduce energy costs and reduce greenhouse gas emissions, while providing increased energy resilience.

While federal support for microgrids has existed for years, states are now becoming active in exploring how microgrids can help meet society's energy needs and policy goals. Massachusetts is one hotbed of interest in microgrids, and a recently announced program could help stimulate the microgrid industry. The Massachusetts Clean Energy Center’s (MassCEC) Community Microgrids Program anticipates providing about $75,000 in funding to support each of 3 to 5 prospective community microgrid projects with the following characteristics:
  • Are community, multi-user microgrids (as opposed to single owner or campus-style microgrids) located in Massachusetts -- but MassCEC will consider proposals from Applicants with an existing campus wishing to extend the microgrid to additional parties outside of its borders;
  • Demonstrate significant potential to reduce greenhouse gas emissions through the integration of energy efficiency, Combined Heat and Power (“CHP”), renewable energy systems, electric and/or thermal storage technologies, demand management, energy efficiency, and other relevant technologies;
  • Have the active and engaged support of the local utility (either investor-owned or municipal light plants) and other relevant stakeholders;
  • Encompass a public or private critical facility, including but not limited to schools, hospitals, shelters, libraries, grocery stores, service (gas) stations, fire/police stations or waste water treatment plants;
  • Support the distribution system by addressing capacity concerns, providing black start capability, facilitating renewables integration, or providing other services that are meaningful to the local utility;
  • Attract third party investment; and 
  • Highlight Massachusetts-based clean energy/microgrid technology.

MassCEC is presently soliciting Expressions of Interest from groups interested in participating in feasibility assessments for community microgrid projects meeting its defined criteria.  According to MassCEC, respondents may include municipalities and their public works departments, electric distribution companies, municipal light plants, emergency services departments, owners of critical infrastructure such as hospitals and financial institutions, self-organized groups of commercial building owners, developers or any other actor that either owns property within a potential microgrid or can demonstrate that they represent stakeholders with the capability of developing a community microgrid.  Support from the local government and the relevant electric or gas distribution company is also required.

MassCEC says it intends its funding to support feasibility assessments to advance the selected microgrid projects through the early project origination stages, enabling them to attract third-party investment. Projects that produce a favorable feasibility assessment may then be eligible for additional technical assistance or grants for later stages of project development

Completed expressions of interest, including all required documentation, must be received by MassCEC by Friday, June 23, 2017 by 4:00pm. MassCEC anticipates awarding the first round of feasibility assessments in Q3 2017.

Will clustering help New England's interconnection queue?

Tuesday, May 16, 2017

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.

Boom in FERC hydro relicensing

Friday, May 5, 2017

U.S. federal hydropower regulatory staff currently has a full workload processing original license, relicense, and exemption applications, as well as its compliance and dam safety work, according to testimony presented to the House Energy & Commerce Committee, Subcommittee on Energy -- and this workload is expected to increase as many hydro projects face relicensing proceedings.

The Federal Energy Regulatory Commission regulates over 1,600 non-federal hydropower projects located at over 2,500 dams, under Part I of the Federal Power Act.  These projects collectively represent about 56 gigawatts of hydropower capacity, over half of the nation's total hydropower capacity.

The Federal Power Act generally requires non-federal hydropower projects to be licensed by the Commission if they: (1) are located on a navigable waterway; (2) occupy federal land; (3) use surplus water from a federal dam; or (4) are located on non-navigable waters over which Congress has jurisdiction under the Commerce Clause, involve post-1935 construction, and affect interstate or foreign commerce.  Licenses are generally issued for terms of between 30 and 50 years, and are renewable.

According to testimony presented to the House Energy & Commerce Committee, Subcommittee on Energy on May 3, 2017, the Commission's relicensing workload "has started to increase and will continue to remain high well into the 2030s."  Between fiscal years 2017 and 2030, the Commission projects that about 480 older projects will begin the pre-filing consultation stages of the relicensing process.  These projects facing relicensing represent about 45 percent of Commission-licensed projects, and one-third of jurisdictional licensed hydropower capacity.

The testimony also notes that some of these projects may face different standards in a relicensing context than were considered when their current or original licenses were issued.  Many projects now entering relicensing were first licensed in the early to mid-1980s, following the enactment of PURPA but prior to enactment of modern environmental standards.

For example, the Electric Consumers Protection Act of 1986 directed the Commission, when issuing licenses, to give equal consideration to power and development, energy conservation, fish and wildlife, recreational opportunities, and other aspects of environmental quality.  This mandate may not have applied to a 40-year license issued in 1982, but would come into play during a relicensing case initiated in 2017.

The House Subcommittee on Energy is considering discussion drafts and several pieces of legislation affecting hydropower, including the Hydropower Policy Modernization Act of 2017; the Promoting Hydropower Development at Existing Non-Powered Dams Act; the Promoting Closed-Loop Pumped Storage Hydropower Act; the Promoting Small Conduit Hydropower Facilities Act of 2017; and the Supporting Home Owner Rights Enforcement Act.

Total eclipses, solar PV and the grid

Wednesday, May 3, 2017

Utilities and electric grid coordinators are preparing for a total solar eclipse that is projected to temporarily reduce solar photovoltaic generation across parts of North America this summer. 

The 2017 total solar eclipse will be the first in the U.S. in 26 years (since Hawaii 1991), and the first in the lower 48 states since 1979.  While the duration of the total eclipse across the U.S. will be roughly 93 minutes, some areas in its path will experience up to 95% of the Sun being obscured.

The eclipse is projected to affect solar PV generation.  Solar resources occupy an increasing role in the U.S. electric generating portfolio. Between 2000 and 2016, total U.S. solar capacity increased from 5 megawatts (MW) to 42,619 MW.  But as more solar resources are connected to the grid, the potential impact of an eclipse on grid operations may change.

According to a May 1, 2017 presentation to the Board of Governors of the California ISO, the eclipse is projected to reduce solar output in the CAISO region by 4,194 megawatts, while gross load will increase by 1,365 MW.  Taking into account estimated wind production, the presentation projects a net load increase of 6,008 MW during the eclipse.

The ramp rate, or speed at which supply and demand will change, is also a factor.  The eclipse is projected to diminish solar output by about 70 MW per minute as it approaches totality, and about 90 MW per minute on the return.  By contrast, a typical average ramp rate for CAISO might be 29 MW per minute.  Thus the eclipse is projected to call for a greater degree of fast-ramping or flexible resources, compared to typical operating conditions.

But according to international electric reliability organization NERC, the August 21, 2017 total solar eclipse "is unlikely to cause any reliability issues to the North American bulk power system."  NERC documented its findings in an April 25, 2017 white paper, A Wide-Area Perspective on the August 21, 2017 Total Solar Eclipse.  NERC's report identifies California and North Carolina as the states most likely to experience the greatest impact from solar production fall-off from the eclipse. At the same time, NERC recommends "that utilities in all states perform specific studies of the eclipse’s impact of solar photovoltaic power output on their systems and retain necessary resources to meet the increased electricity demand requirements."  In particular, NERC notes that generation and system operators may greater visibility into utility-scale solar projects than into behind-the-meter or distributed solar photovoltaic resources, highlighting the need to model all scales of solar development.

Following the 2017 eclipse, the next total solar eclipse is projected to cross North America on April 8, 2024.

New England summer 2017 electricity supply forecast

Tuesday, May 2, 2017

New England will have an adequate supply of electricity this summer, according to the regional grid operator, but its forecasts show the possibility of occasional "tight system conditions."

ISO New England Inc. is the operator of the region's wholesale electricity markets and bulk power system.  To help inform its planning, the grid operator prepares seasonal short-term forecasts.  ISO New England's most recent projection, covering summer 2017, found that "New England is expected to have the resources needed to meet consumer demand for electricity this summer."

Weather can have a significant impact on consumer demand for electricity.  ISO New England projects that under normal weather of about 90 degrees Fahrenheit (°F), this summer's electricity demand will peak at 26,482 MW.  This forecast falls between last year's summer system peak (August 12, 2016, at 25,466 MW) and the all-time record peak demand (August 2, 2006, at 28,130 MW).  But if the summer of 2017 is unusually hot, New England might set a new record for system demand: the grid operator projects that demand could rise as high as 28,865 MW under extreme summer weather, such as an extended heat wave of about 94°F.

ISO also notes that its "forecast estimates indicate the possibility of a tighter-than-expected margin of supply and reserves" because "up to 700 megawatts (MW) of expected new resources are delayed and may not be available this summer."  In addition, the 1,500 MW Brayton Point coal- and oil-fired power plant in Massachusetts will retire, leaving New England with approximately 29,400 MW of total capacity available this summer.  Meanwhile, approximately 2,000 MW of behind-the-meter solar facilities are currently installed throughout the region, which can reduce demand for grid power.

In its press release, ISO New England noted its readiness to maintain system reliability under tight supply conditions this summer.  Measures the grid operator could take in case of a supply deficit under peak summer conditions include importing additional electricity from neighboring regions, and implementing a variety of operating procedures to keep the grid balanced including calling on demand-response resources to curtail energy use.