FERC approves energy storage tariffs

U.S. utility regulators have approved the first two regional implementations of a landmark 2018 order designed to remove barriers to the participation of electricity storage in wholesale markets.

In 2018, the Federal Energy Regulatory Commission issued its Order No. 841, requiring each organized power market to revise its tariff to establish a "participation model" for electric storage resources in the capacity, energy and ancillary service markets. The rule requires each market's participation model to include market rules that recognize the physical and operational characteristics of electric storage resources and facilitate their participation in those markets. The Commission later affirmed the rule, through its Order No. 841-A.

Last week, the Commission issued two orders approving Order No. 841 compliance filings by Southwest Power Pool, Inc. and by PJM Interconnection. The Commission generally found that the SPP and PJM tariff revisions complied with the new rule, and largely accepted their filings. For example, the Commission found that both proposals "generally enable electric storage resources to provide all services they are capable of providing; allow electric storage resources to be compensated for those services in the same manner as other resources; and appropriately recognize the unique physical and operational characteristics of electric storage resources."

However, the Commission also provided directives for further compliance filings by SPP and PJM to be made within 60 days. The Commission found that while both filed tariffs generally satisfy Order No. 841’s directive allowing electric storage resources to de-rate their capacity to meet minimum run-time requirements, neither tariff included minimum run-time requirements for resource adequacy and capacity, respectively. Because "such requirements affect rates, terms and conditions of service," the Commission initiated proceedings under section 206 of the Federal Power Act to address the specific issue of minimum run-time requirements.

In a pair of separate statements (on SPP and on PJM), Commissioner McNamee concurred with the orders insofar as they found compliance with the Commission's orders and regulations. But Commissioner McNamee said, "I write separately, however, to express my continuing concern that the Commission exceeded its statutory authority under the Federal Power Act, and should have, at the very least, provided states the opportunity to opt-out of the participation model created by the Storage Orders." Commissioner McNamee also reiterated jurisdictional concerns he had previously raised in a partial concurrence to and partial dissent from Order No. 841-A, "to the extent the Commission’s Storage Orders exercised authority over the distribution system and behind-the-meter."

Other organized wholesale market operators, such as ISO New England, Inc., are also adopting tariff revisions to comply with Order No. 841, to enhance the ability of electric storage facilities to participate in regional wholesale electricity markets.

ISO-NE 2018 Regional Electricity Outlook

Regional electricity grid operator ISO New England, Inc. has released its 2018 Regional Electricity Outlook. According to the report, "the biggest challenge to the reliability of the grid is the lack of fuel infrastructure to supply the fleet of natural-gas-fired generators, further emission restrictions on oil-fired generation, and the reality that older oil and nuclear generators are becoming less economically competitive and may retire before the region has added sufficient new energy sources to replace them."

The report cites competitive forces has having "unleashed new approaches for producing electricity in a cleaner way and integrating technology that enables different types of resources to participate in the wholesale markets." It notes new resource types entering the wholesale market, including demand resources, and fast-responding energy storage devices.

With respect to energy supply, the 2018 outlook notes that the amount of wind and solar power in New England continues to grow "and is making a difference in how the ISO operates the power system and designs the wholesale markets." In 2017, the amount of new wind power seeking interconnection in New England surpassed proposed new natural-gas-fired generation for the first time, including significant amounts in Maine and offshore of Massachusetts.

On the demand side, it notes that significant investments in solar resources and energy-efficiency measures have moderated demand for wholesale electricity, but that electrifying the transportation and heating sectors to reduce their carbon emissions could lead to increased demand.

ISO-NE has previously identified the risk that power plants will run out of fuel as the foremost challenge to a reliable power grid in New England. Last month, ISO-NE released an operational fuel security study analyzing fuel security risks facing region's power plants under a wide range of hypothetical future scenarios. That report concluded that maintaining the electric grid's reliability "is likely to become more challenging, especially if current power system trends continue."

The 2018 Regional Electricity Outlook notes that while ISO-NE plays a role in addressing regional fuel-delivery constraints, "it will be up to market participants and state officials to take actions to secure forward fuel arrangements or bolster supply- or demand-side infrastructure." The report identifies potentially appropriate investments as including "enhancements to natural gas infrastructure or the supply chains for liquefied natural gas and oil; relaxation of rules to allow easier permitting and operation of dual-fuel resources; investments in even more renewable energy and any transmission needed to deliver it; or further measures to significantly reduce demand on the power system or the gas system," or some combination of these.

While reliability is core to the grid operator's priorities, the report acknowledges that New England's policymakers, businesses and citizens also value economic and environmental goals. The report specifically highlighted what it called "the reliability, economic, and environmental consequences of our situation: that regional action to resolve fuel-security risks will involve costly infrastructure investments and perhaps the retention of certain critical energy resources, but inaction will also come with a bill for high energy prices when energy supply is constrained—as well as the potential for greater risks to power system reliability and higher emissions."

ISO New England Regional Electricity Outlook 2016

The New England regional power system is in a state of major transformation, according to regional grid operator ISO New England, Inc.'s 2016 Regional Electric Outlook.

ISO New England is the private, non-profit entity that serves as the regional transmission organization for New England.  In this role, the ISO plans and operates the New England bulk power system, administers New England’s organized wholesale electricity market, and has some responsibility over system reliability.

The 2016 Regional Electric Outlook report is the latest annual installment of the grid operator's update on the state of the grid and the ISO’s efforts to ensure reliable electricity and to improve services and performance.  This year's report describes the New England grid administrator as "in the vanguard of a major transformation in how electricity is produced and delivered in the US."

Three waves of change -- natural gas, renewable energy and demand resources, and distributed generation -- are affecting New England's fleet of power resources, according to the report:

Natural-gas-fired generation has displaced older coal, oil, and nuclear plants. Weather-dependent renewable power resources and energy-efficiency measures are multiplying. On the horizon comes a “hybrid grid”—a combination of large power resources supplying the regional system while smaller ones directly supply consumer sites.

According to the report, coal, oil, and nuclear resources are retiring; it noted that resources representing about 30% of regional capacity have committed to cease operation or are at risk of retirement by 2020.  Most power plants planned to replace them will rely in part or in whole on natural gas or renewable generation.  The report notes:

Our region's natural-gas-fired power resources are among the newest, most efficient, and lowest-emitting plants in the country. When their access to low-priced gas from the Marcellus shale is unrestricted, New England has reliable, low-priced electricity.

The report also states that "wintertime access to natural gas has grown tight over recent years because the regional fuel transportation network has not kept up with demand from both generation and heating sectors."  As a result of pipeline constraints, the ISO notes "grid reliability challenges, emission increases during winter, and spikes in wholesale electricity prices."

The report also describes the ISO's tactics for managing the reliability risks associated with these shifts in the region's energy mix, including stronger "pay for performance" financial incentives for power resources to perform as required.  It cites various ISO studies indicating "that, ultimately improving the natural-gas-delivery infrastructure in New England" will best address reliability concerns, price spikes, and unnecessary emission impacts from oil and coal units during winter.

The report, along with previous years' reports, are available on the ISO's website.

ISO-NE Winter Reliability Program 2015 by the numbers

The operator of New England's electric grid is running a special Winter Reliability Program to address fuel security and power system reliability concerns, relating largely to natural gas pipeline constraints.  A December 2015 presentation by ISO New England, Inc.'s CEO provides initial cost and participation data on this winter's program.

More than 45% — about 13,650 MW—of the total generating capacity in New England uses natural gas as its primary fuel.  Out of this gas-fired capacity, ISO-NE's Winter Outlook has identified 4,220 MW of natural gas-fired generation at risk of not being able to get fuel when needed due to constraints on interstate natural gas pipelines.

As in 2013 and 2014, in 2015 ISO-NE again proposed a Winter Reliability Program to address concerns over reliability.  The 2015-2016 program includes 4 main components: oil, LNG, demand response, and dual-fuel commissioning.  According to a December 2015 presentation to the NEPOOL Participants Committee, program participation and expected cost exposure breaks down as follows:

Oil Program

• 81 units submitted intent to provide 4.464 million barrels
• Total eligible oil is anticipated to be 2.965 million barrels
• Total oil program cost exposure is anticipated to be $38.25M (@$12.90/barrel

LNG Program

• 8 units submitted intent to provide at least 1.42 million MMBTU
• Total eligible LNG is 1.278 million MMBTU
• Total LNG program cost exposure is anticipated to be $2.75M (@$2.15/MMBTU

Demand Response Program

• 7 assets submitted an intent to participate; 6 accepted by ISO-NE, to provide at least 26.5 MW of interruption capability
• Total DR program cost exposure is anticipated to be $132K

Dual-fuel Commissioning Program

•  6 units submitted intent to commission Dual Fuel Capability
• 4 units for 2014/15 (1,039 MW)
• 2 units for 2015/16 (735 MW)
• Total additional winter seasonal claimed capability represented: 1,774 MW

ISO-NE will release additional information on actual 2015/2016 Winter Reliability Program operations and costs over the winter period.

ISO-NE files IRC-related values for 2019-2020

In advance of an upcoming auction to sell electric generating capacity into the New England market, regional grid operator ISO New England Inc. has submitted key information about its plans to the Federal Energy Regulatory Commission.

ISO New England is the private, non-profit entity that serves as the regional transmission organization for New England.  In this role, ISO-NE plans and operates the New England bulk power system, administers New England’s organized wholesale electricity market, and has some responsibility over system reliability.  Reliability can be stated in terms of a loss of load expectation or “LOLE”, which measures how often non-interruptible customers are disconnected.

New England has adopted a capacity market as part of its wholesale electricity market structure.  One aspect of system reliability is ensuring sufficient generating capacity is available to meet consumer demand.  Pursuant to Section III.13 of the Tariff, the ISO administers periodic Forward Capacity Auctions, or FCAs, in order “to procure the amount of capacity needed in the New England Control Area.”

ISO-NE will hold its tenth Forward Capacity Auction in February 2016, covering the 2019-2020 Capacity Commitment Period.  To do so, ISO-NE must first identify how much generation will be needed 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.  One key value characterizing this need is the "Installed Capacity Requirement" or ICR.  ICR refers to the amount of resources needed to meet the reliability requirements defined for the New England Control Area of disconnecting non-interruptible customers no more than once every ten years.  Under Section 205 of the Federal Power Act, ISO-NE files with the FERC proposed ICR-Related Values for the each auction.

On November 10, 2015, ISO New England submitted to the FERC its Installed Capacity Requirement, Local Sourcing Requirement for the Southeastern New England Capacity Zone, Hydro Quebec Interconnection Capability Credits, and Demand Curve Values for the 2019-2020 Capacity Commitment Period.  In that filing, ISO-NE proposed an Installed Capacity Requirement (net of certain credits for imports) of 34,151 MW.

ISO-NE noted that for the most part, this and other key values were calculated using the same Commission-approved methodology that has been used to calculate the values submitted and accepted for other recent Capacity Commitment Periods. One key difference for the tenth FCA is the inclusion of behind-the-meter photovoltaic (“PV”) resources that are not yet reflected in historical loads as a reduction in the load forecast. This change addresses a requirement imposed by the FERC in its January 2, 2015 Order accepting the Installed Capacity Requirement and related values for the ninth FCA.

ISO-NE asked FERC to accept the proposed ICR-Related Values for the tenth FCA to be effective on January 9, 2016 (i.e. 60 days after filing), to enable their use in the tenth FCA scheduled for February 2016.

Record low prices in summer 2015 New England wholesale electricity market

The summer of 2015 brought New England the lowest wholesale electricity prices since 2003, thanks to record low prices for natural gas.  According to regional grid operator ISO New England Inc., this illustrates what happens "when New England power plants can access the vast supply of lower-priced, domestic natural gas being produced in the Marcellus shale deposit."

ISO-NE, "Summer 2015: The lowest natural gas and power prices since 2003"

In a post on its ISO Newswire site, the grid operator noted that the average real-time wholesale electricity price for June, July, and August 2015 was $26.86 per megawatt-hour (MWh). By comparison, the average real-time price of wholesale electric energy in 2014 was $63.32 per megawatt-hour.  While summer energy prices have typically averaged lower than winter prices in New England, 2015's summer prices were low even in comparison to other recent summers: $34.31 in 2014, or $43.94 in 2013.

What explains New England's low wholesale electricity prices this summer?  According to ISO New England, it's because existing natural gas-fired power plants could get fuel at a low price:

In essence, the reason was the low price of natural gas that could be delivered to the power plants that burn natural gas to make electricity. For most of the year, the price of natural gas is low in New England, and as a consequence, the demand for natural gas for both heating and power generation just continues to grow. In fact, in 2014, New England power generators using natural gas produced 44% of the region’s electricity.

The ISO-NE post describes how low-priced natural gas plus adequate interstate pipeline transportation capacity yields New England low electricity prices.  Indeed, the average price of  natural gas in New England during June, July, and August averaged a record low $2/MMBtu.  This is nearly 40% below last year's summer average ($3.27/MMBtu), itself the next-lowest summer record.

New England's average summer electricity price was even below that of other regions, like the Midwest.  According to ISO-NE, "This summer’s prices indicate that the region’s electricity prices can be competitive, in the more commonly understood sense, with other regions of the US when low-cost fuel is available." Indeed, at times the price of natural gas in New England was below that of the benchmark Henry Hub.

The post also describes how heavy winter demand for natural gas for both heating and power generation, combined with pipeline constraints, yields high natural gas prices and thus high electricity prices.  This has occurred repeatedly in recent winters, such as in January and February 2014 and February 2015.  What is at issue is thus the ability of the interstate natural gas pipeline transportation network to ship enough gas into the Northeast -- a capability exceeded through much of the recent winters, with the resulting price paid in coal and oil emissions as well as dollars.

As ISO-NE notes, most customers' retail rates for electricity are set using mechanisms to reduce rate volatility, and time of use rates are not yet widely adopted.  But the net movement of wholesale markets is eventually priced into retail rates.  Can New England keep competitive with other regions?

Northern Pass files with NH SEC

The developer of the Northern Pass Transmission Project, a proposed high-voltage transmission line from Canada into New Hampshire, filed a formal application to New Hampshire regulators this week.

First proposed in 2009, the Northern Pass project would include about 190 miles of new direct current transmission lines and an AC-DC converter station.  Collectively, the project would be capable of importing over 1,000 megawatts of power from Canada into the New England electric grid.  Its formal sponsors are two companies affiliated under the Eversource family: Northern Pass Transmission LLC and Public Service Company of New Hampshire d/b/a Eversource Energy.

Early versions of proposal drew criticism and controversy over issues including siting, visual impacts, the potential use of eminent domain, and impacts to domestic renewable energy production.  After a series of public information meetings and other dialogue, Eversource released a revised route and plan in August 2015.

On October 19, Eversource announced that it had filed a formal application to the New Hampshire Site Evaluation Committee.  The Northern Pass Transmission application to the SEC is available on the project's website.  It describes a project cost estimate of $1.6 billion, and a capacity of 1,090 megawatts. 

The SEC was established by the state legislature for the review, approval, monitoring and enforcement of compliance in the planning, siting, construction and operation of energy facilities.  It includes members from the Public Utilities Commission, cabinet level commissioners, and two members of the public.  The SEC has jurisdiction to review applications for siting and construction of large-scale energy facilities and to issue a Certificate of Site and Facility enabling a project's development.  The process before the SEC is likely to play out through 2016.

Northern Pass proposes new transmission plan

The developer of a proposed $1.4 billion electric transmission line connecting Quebec to New Hampshire has released a revised route for the project, following public opposition to earlier plans.  The new vision for the Northern Pass project would bury more of the line underground and reduce the project's overall capacity to haul power.  Will this version of the Northern Pass gain more traction?

First proposed in 2009, the Northern Pass would be a 192-mile high-voltage direct current (HVDC) transmission line.  It would bring up to 1,000 megawatts of power from Canadian power plants into New England, running from the Canadian border to a proposed converter terminal in Franklin, New Hampshire.  From there, a new alternating current (AC) transmission line would deliver the energy to New England’s electric grid at an existing substation in Deerfield, New Hampshire. 

Since it was first proposed, the Northern Pass route has drawn criticism; the project was delayed, and despite revisions to the route public opposition remained.  Throughout the process, many comments have focused on local siting impacts, like the effect of above-ground transmission lines and poles through Franconia Notch State Park, the White Mountain National Forest, and the Appalachian Trail.  Eversource proposed running 8 miles of cable underground to reduce these impacts, but argued that undergrounding more would make the project too expensive.

But the forces motivating the Northern Pass project and other proposed HVDC lines from Canada remain strong: demand in New England and New York for electricity, and in particular for hydropower and other renewable electricity imported from Canada.

On August 18, project lead Eversource Energy announced changes to the route and scope of the project.  While the previous vision included 8 miles of underground cable to avoid visual impacts, the so-called "Forward New Hampshire Plan" now includes 60 miles of underground cable. Eversource described its revised route as striking "a balance between New Hampshire and our region’s need for a reliable new energy source and avoiding potential impacts to the state’s scenic landscapes."  At the same time, the revised proposal reduces the line's capacity from 1,200 megawatts to 1,000 megawatts, ostensibly to hold total costs at the previously estimated $1.4 billion.  The plan now includes $200 million to establish the "Forward NH Fund", a pool of money designed to support clean energy innovations, economic development, community investment, and tourism.

The Northern Pass project now faces public hearings.  Eversource is expected to file an application for site review with the New Hampshire Site Evaluation Committee in mid-October.

ISO-NE projects slow growth in electricity demand

New England's electric grid operator predicts slow growth in annual energy usage in the region over the next decade, with slightly quicker growth in peak demand.

A Maine power plant -- the ecomaine Waste-to-Energy plant in Portland, Maine.

ISO New England, Inc. develops an annual long-term load forecast using factors including state and regional economic forecasts and 40 years of weather history.  Its most recent baseline forecast projects a compound annual growth rate of 1.0% in total energy usage in New England from 2015 to 2024.  For 2015, ISO-NE projects 138,745 gigawatt-hours (GWh) of load, growing to 152,280 GWh in 2024.

ISO-NE's forecast also projects future peak demand, a measure of the highest amount of electricity used in a single hour in New England.  Often, peak demand drives the need for constructing and maintaining power plants and transmission lines (and energy efficiency investments).  According to the latest ISO-NE forecast, New England's peak electricity demand is projected to rise by a compound annual growth rate of 1.3%, from 28,395 MW this year to 31,905 MW in 2024.

These baseline projections for future peak demand and energy usage take into account load reductions that can be expected from future installations of distributed solar photovoltaic facilities.  ISO-NE has prepared a separate Distributed Generation Forecast to estimate the load-reducing effects of distributed solar facilities developed as a result of state policy goals.

ISO-NE's baseline projections do not account for significant energy-efficiency savings, neither those committed through the region’s three-year Forward Capacity Market (FCM) nor future savings that can be expected beyond the FCM timeframe.

More solar faster, predicts New England grid operator

New England will likely see even more solar photovoltaic energy projects over the next decade than was previously projected, according to the latest draft forecast by the operator of New England's electric grid.

Solar photovoltaic panels on the roof of a Massachusetts home.

To help plan for future needs, grid operator ISO New England, Inc. is developing an updated forecast of solar photovoltaic project development in New England.  In 2014, ISO New England developed its first multistate forecast of PV capacity growth.  It based its 2014 PV forecast heavily on development goals articulated as policies in the six New England states.

ISO New England is now updating that forecast for 2015.  Its draft 2015 Solar PV Forecast, released on February 27, notes that PV development is happening more rapidly than was previously projected.  Using updated historical data, it acknowledges that through 2014, 40% more solar capacity was developed in the region than it previously estimated.  As a result of this faster-than-expected growth, the draft now predicts a higher level of cumulative photovoltaic project development through 2023.

Perhaps more significantly for the solar boom, ISO-NE's draft 2015 forecast also frontloads more new project capacity into 2015 and 2016, while decreasing the amount predicted to be newly developed in later years.  While last year's forecast also predicts more incremental solar capacity will be developed in each of the next three years than in later years, the frontloading is more prominent in the draft 2015 forecast.

The draft 2015 forecast projects that 2,138.8 megawatts of solar photovoltaic projects will be developed in New England by 2024.  This capacity is stated as an alternating current nameplate rating, even though photovoltaic cells essentially generate direct current electricity.  The study derates direct current capacity to alternating current with an 83% array-to-inverter ratio, so this implies an even higher number of megawatts if stated as direct current capacity, as most solar projects are described.

The draft 2015 forecast projects that these solar photovoltaic projects will give rise to a summer seasonal claimed capability of 748.6 megawatts.

ISO New England did not include in its draft 2015 PV forecast any update to its forecast of how much energy these projects would produce.  Instead it suggests that it must first finalize its forecast of installed photovoltaic capacity, and can then estimate the energy production associated with the forecast.  The report does repeat 2014's forecast of energy as illustrative, keeping in mind that actual amounts of energy generated from solar photovoltaic capacity in New England will likely be higher if capacity forecasts are revised upward as is proposed in this draft.

The 2015 draft PV report is now under review by ISO New England's Distributed Generation Forecast Working Group.  That group next meets on April 14, where the final draft forecast will be presented.

Developer applies to VT for Clean Power Link transmission line

A proposed electric transmission line from Quebec into New England took a step forward this week, as the developer of the New England Clean Power Link applied to Vermont regulators for key project approvals.

Transmission Developers Inc. subsidiary TDI New England has proposed the New England Clean Power Link to bring Canadian hydropower and other electricity to the renewable-hungry New England market.  With an estimated project cost of $1.2 billion, the 1000-megawatt high-voltage direct-current transmission line would run under Lake Champlain and underground to a converter station in Ludlow, Vermont, near where it would connect to the existing electric grid owned by Vermont Electric Power Company (VELCO).

Under Vermont law, the state Public Service Board regulates many aspects of the electric grid.  Section 248 of Title 30 of Vermont's statutes requires companies to obtain approval from the Board before beginning site preparation or construction of electric transmission facilities, electric generation facilities and certain gas pipelines within Vermont.  For facilities like the proposed transmission line, that Board approval comes in the form of a Certificate of Public Good. 

On December 8, 2014, TDI subsidiary Champlain VT, LLC d/b/a TDI New England applied to the Board for a Certificate of Public Good for the project.  TDI's petition notes that the project "would contribute to meeting State and regional energy and sustainability goals and result in millions of tons/year in reduced greenhouse gas emissions by replacing electricity generated by fossil fuels," and that running cables under the lake and underground avoids adverse impacts from above-ground installations.  Other benefits touted by TDI include economic development (with about $1.5 billion in claimed economic benefits to Vermont and the entire region over the project's 40-year life), improved electric reliability and fuel diversity, and help in mitigating the impacts of the anticipated loss of the Vermont Yankee nuclear station and other major power plants.

TDI's proposal includes components specifically designed to yield local community benefits and thus to cultivate local support for the project.  These components include creating $122 million in funds to improve Lake Champlain's water quality, habitat, and recreational values, plus another $40 million for Vermont's Clean Energy Development Fund.

TDI's project now comes before the Vermont Public Service Board for review.  The project also needs a presidential permit issued by the U.S. Department of Energy to cross the international boundary, as well as a U.S. Army Corps of Engineers permit for impacts to water resources.

At the same time, another transmission line has been proposed under Lake Champlain, namely the $2.2 billion Champlain Hudson Power Express meant to connect Quebec to New York City.

ISO New England's Winter Reliability Program 2014-2015

Keeping the lights on is what electric grid operators do around the clock – but challenges in New England are leading its grid operator to prepare for a winter when the availability of affordable electricity may be challenged.  In preparation, ISO New England, Inc. has received federal approval for a new Winter Reliability Program for the 2014-2015 winter season.

Winter is coming.

ISO New England is the federally-designated regional transmission organization for almost all of New England.  In this role, it is responsible for planning and operating electricity markets to balance supply and demand in real time.   

The grid operator first turned to a Winter Reliability Program in 2013.  ISO New England projected that a limited supply of natural gas and the retirements of several major generating plants would lead to a shortage of about 2 million megawatt-hours of energy during the winter months.  To insure against this gap, the grid operator held a competitive process to procure up to 2.4 million megawatt-hours of energy for the winter season, from a combination of oil-fired generators, dual-fuel generators, and demand response assets.  In exchange for their commitment to provide power when called upon, the selected generators and demand response assets received payments regardless of whether they were actually needed.

In ISO-NE's eyes, the 2013-2014 Winter Reliability Program proved essential in maintaining reliability during the “polar vortex” and other unusually cold conditions.  After adjusting for resource unavailability, the final cost of the 2013/2014 program was approximately $66 million, which came in below the original estimates of about $75 million.

While last year’s program was intended to be a one-time solution to bridge a reliability gap, this summer ISO-NE and regional stakeholder body NEPOOL identified additional challenges for the coming winter.  Specifically, more severe pipeline constraints, difficulty replenishing oil inventories, and large-scale generator retirements continue to threaten the coming winter's reliability and expose consumers to the risk of price spikes.

As a result, ISO-NE asked the Federal Energy Regulatory Commission to approve another program to mitigate reliability concerns for the 2014-2015 winter.  The new program, which the FERC accepted last month, combines features of last year’s program with further modifications.  For example, the new demand-response component is much the same as in last year’s program, while permanent rules related to auditing dual-fuel generators and the partial elimination of higher-cost fuel requirements are based on similar features in last winter’s program.

On the other hand, the new program has been modified as a result of several market changes that will be in effect prior to winter 2014/2015 as well as the FERC's clarification of what generators must do to procure adequate fuel for their expected run times.  The new program also adds a liquefied natural gas (LNG) component to improve fuel neutrality, and changes the basis for compensation from upfront inventory to actual unused inventory at the end of the winter.  While participants in last year's program were paid on an as-bid basis, the new program provides compensation for the fuel inventory and demand response programs based on a set rate of $18 per barrel.  This $18 price is designed to represent the carrying costs, price risk, availability cost and liquidity risk of the last resource needed to meet a cumulative inventory of 3.5 million barrels of oil.

The program also includes incentives for commissioning duel-fuel capacity: the ability to run on either oil or gas. Generators that have not operated on oil since at least December 1, 2011, and that demonstrate a plan for commissioning, or recommissioning a mothballed dual-fuel unit, by December 1, 2016, will be eligible for compensation to offset some of the associated costs.

The new program is moving forward.  On September 9, 2014, the FERC issued an order accepting the region’s proposed 2014/2015 Winter Reliability Program.  In the order, FERC requires ISO-NE to initiate a stakeholder process by January 1, 2015, to develop a proposal to address reliability concerns for the 2015/2016 winter and future winters, as necessary, to schedule meetings and submit progress reports, and to include certain analysis and recommendations in its Annual Markets Report.

For the proposed 2014/2015 program, the Analysis Group estimated costs for the separate components: the maximum cost of the demand response component would be about $2.4 million; the cost of the unused oil inventory and LNG contract volume components would be based on how much fuel remains unused, and assuming, at the high end, that 100% of the targeted amount of fuel is unused, the estimated cost would be $82.6 million; and the maximum cost for the dual-fuel commissioning program is estimated to be $12.9 million for units that commission by December 1, 2015.  The dual-fuel auditing provisions are estimated to cost a maximum, annually, of $7 million.

Consistent with the Commission’s order on the first winter program, the costs will be allocated to real-time load obligation, which is paid by load-serving entities, rather than to regional network load, which is paid by transmission owners.

Requests to Participate in the Oil Program, LNG Program, or Demand Response Program were due to ISO New England Customer Service by October 1, 2014. Dual Fuel Commissioning Requests are due by December 1, 2014

Atlantic offshore wind energy targeted

A report released by the National Wildlife Foundation highlights the potential of U.S. states on the Atlantic Ocean to generate electricity from offshore wind -- and calls upon state leaders to take action to promote offshore wind development.

The 24-page report, Catching the Wind: State Actions Needed to Seize the Golden Opportunity of U.S. Offshore Wind Power, describes responsibly developed offshore wind as "a golden opportunity to meet our coastal energy needs with a clean, local resource that will spur investments in local economies."  In particular, the Atlantic coast offers a high-quality wind resource in close proximity to power-thirsty coastal cities.

Key findings in the report include:

• Offshore winds off New England and New York blow consistently during periods of high electric demand, including summer heat waves and winter cold snaps.
• Federal environmental reviews are complete for over 1.5 million acres of Atlantic sea space, with over 16,000 megawatts of potential wind capacity.
• Diversifying states' energy mix with offshore wind can reduce prices and offset volatility, citing a 2014 study showing New England would save $350 million per year in reduced energy costs, or 2%, if 1,200 megawatts of offshore wind is added.
• Offshore wind reduces air pollution, including carbon emissions.
• Offshore wind development creates jobs, and can be done in an environmentally responsible manner.

The report highlights Massachusetts and Rhode Island as leading America's pursuit of offshore wind, followed by Maryland, Virginia, New York, New Jersey, and Delaware, with Maine, North Carolina, South Carolina, and Georgia bringing up the rear.  New Hampshire, Connecticut, and Florida are noted as "states to watch" with no offshore wind planning activities.

The report calls on state leaders to:

• Set a bold goal for offshore wind in the state's energy plan.
• Take action to ensure a competitive market for offshore wind power.
• Advance power contracts for offshore wind.
• Ensure an efficient, transparent, and environmentally responsible offshore wind leasing process that protects wildlife.
• Invest in key research, initiatives, and infrastructure needed to spur offshore wind development.

Will Atlantic states develop their offshore wind resources? 

End in sight for New England's largest coal plant

New England's largest coal-fired power plant will close by May 2017, according to its owner.  The Brayton Point Power Station in Somerset, Massachusetts, consists of three coal-fired units and a unit capable of burning natural gas and oil, with a net generating capacity of 1,537.6 megawatts.  Within 4 years, it will follow other large New England coal-fired power plants like Salem Harbor Power Station into history.

The Salem Harbor Power Station in Salem, Massachusetts, scheduled to close in May 2014.

The forces leading to Brayton Point's closure have been gathering for years.  The U.S. energy industry is in the midst of a revolution led by affordable and abundant natural gas supplies.  Meanwhile, tighter environmental regulations on air emissions from coal-fired power plants have made these traditionally cheap generators more and more expensive to run.  This past March, Brayton Point's previous owner Dominion Resources Inc. announced plans to sell the plant and two other fossil-fired plants to a subsidiary of Energy Capital Partners LLC.  That deal was consummated in August.

In an effort to keep the plant economic, Energy Capital Partners reportedly worked with regional electricity grid operator ISO New England Inc. on an agreement under which Brayton Point would have been paid for its ability to be called upon to provide electric generating capacity when needed.  But when Brayton Point demanded a higher price for this capacity than ISO New England was willing to offer, the generator submitted papers indicating that it would not provide capacity for the 2017-2018 forward capacity year.

Without those capacity market revenues, Brayton Point's owners have said it will close by May 2017, according to AP reports.  If it does, it will follow Salem Harbor and other coal-fired power plants around the country which have either closed or been converted to natural gas.  What will the future hold for Brayton Point's site in Somerset?  With transmission lines already in place, will it be redeveloped with other energy infrastructure?  What environmental issues will closure or repowering entail?

Tackling New England natural gas pipeline constraints

Natural gas offers consumers a relatively low-cost energy source with fewer environmental impacts than coal or oil.  Throughout most of the United States, natural gas is displacing other fossil fuels in electric power generation, heating, and transportation.  But as a recent federal report found, inadequate pipeline infrastructure into New England is keeping prices for natural gas and electricity in the Northeast higher than in other regions.

In its 2012 State of the Markets report, the Federal Energy Regulatory Commission described how the availability of low-cost natural gas drove electricity prices downward last year.  However, as power plants, businesses, and homes convert to natural gas for their energy needs, growing competition between heating and electric load for a limited natural gas supply drives prices of both gas and electricity upward during the winter season.

New England's demand for natural gas peaks in the winter, due primarily to heating demand from the residential and commercial sectors.  As electric generators have increasingly turned to natural gas as the fuel of choice, total demand for gas has increased correspondingly.  In recent years, to meet peak demands for natural gas, New England has relied on imports of liquefied natural gas (LNG), as well as natural gas produced from Canada's offshore Sable Island field.  But last year, low domestic natural gas prices led to low imports of LNG and Canadian natural gas.  LNG imports hit their lowest level since 2002.  Sendout from the with Canaport LNG facility in St. John, New Brunswick, was drastically reduced, as LNG shippers chose to send their cargoes to higher-priced markets in Europe and Asia.  As FERC found: 

Lack of LNG and natural gas from Canada exacerbated pipeline constraints into New England from the southern supply corridor, including Marcellus Shale natural gas production, as New England relied more heavily on these pipelines for supply. This led to concerns that extreme cold weather could result in some service interruptions, particularly to power generators that generally rely on interruptible pipeline capacity to meet their fuel needs.

In particular, during cold snaps, demand from power plants coincides with peak residential and commercial natural gas demand.  Despite an unusually warm winter that suppressed residential and commercial load during the first quarter of 2012, demand reached pipeline capacity for part of the winter.  As a result, last winter New England consumers paid over a billion dollars more for natural gas and electricity than they would have if adequate pipeline capacity existed.

Unless LNG imports once again become economic, or domestic pipeline constraints are relieved, this situation is likely to repeat itself in New England next winter.  As consumers find wider uses for natural gas -- from converting vehicles and the transportation sector to compressed natural gas, to increased access to natural gas for home heating -- the number of days when demand reaches pipeline limits will likely grow.  This reality has led states like Maine to stimulate the development of new pipeline capacity by authorizing its Public Utilities Commission to enter into contracts for natural gas capacity.  While it may be several years until the constraints can be relieved, other states are likely to follow Maine in addressing the problem.

Study quantifies New England distributed generation, growth

Distributed generation – small-scale electric generation facilities installed at consumer sites – plays a growing role in the resource mix used to meet society’s needs. Typical distributed generation assets include solar photovoltaic panels and co-generation or combined heat and power units developed at homes and businesses. A study released yesterday found that distributed generation capacity in New England could roughly triple in the next decade – and that regional electric grid operator ISO New England Inc. needs to account for distributed generation in its planning.

As New England’s regional transmission organization, ISO New England plans for and coordinates the development of electric transmission infrastructure. In the past decade, New England ratepayers have spent approximately $5 billion on transmission additions and expansions. ISO New England’s 2012 Regional System Plan calls for the investment of another $6 billion in transmission projects in the coming years. As a result, regional transmission rates roughly tripled between 2006 and 2010, and continue to grow.

ISO New England’s plans are based on its forecasts of future system needs, including anticipated load growth and changes in the electric generation portfolio used to satisfy customer demand. But ISO New England may be underestimating the extent to which non-transmission alternatives like distributed generation can satisfy demand at a lower total cost than transmission line development. According to “Forecasting Distributed Generation Resources in New England: Distributed Generation Must Be Properly Accounted for in Regional System Planning”, prepared by Synapse Energy Economics Inc., ISO New England is significantly underestimating the current and potential distributed generation in New England, particularly with respect to solar photovoltaic resources.   According to Synapse, “This practice results in the ISO ignoring likely transmission and reliability benefits and overestimating electricity load—with ratepayers being asked to pay for larger, more expensive transmission upgrades than are needed.”

ISO New England predicts that about 800 MW of solar photovoltaic generation will be installed in New England by 2021, but excludes other types of distributed generation from its projection. But Synapse found that over 980 megawatts of distributed generation assets are already installed in the six New England states. By 2021, Synapse predicts that this could grow to over 2,855 MW based on existing policies and development trends.

Synapse Energy Economics, Inc., Forecasting Distributed Generation Resources in New England: Distributed Generation Must Be Properly Accounted for in Regional System Planning, at page 19.

State policies and the favorable economics of distributed generation projects are driving their adoption on a wider scale than in previous years.  For example, after exceeding its previous solar photovoltaic target, Massachusetts recently increased its target to 1,600 MW.  Renewable portfolio standards, net metering policies, and feed-in tariffs all contribute to the proliferation of distributed generation, as does a cost differential that makes natural gas-fired cogeneration more cost-effective than burning oil for heating and purchasing electricity in commercial and industrial applications.

Synapse’s report concludes, “It is essential that the ISO stop ignoring the impacts DG resources have on system planning—both their benefits and their challenges. This report provides a reasonable estimate of what the future holds for these resources and makes one thing very clear: assuming that these resources do not exist is unacceptable.”

Whether and how ISO New England and the states take distributed generation into account remains to be seen, but if the trends noted in the Synapse report play out to even a modest degree, non-transmission alternatives such as distributed generation may be able to limit further increases in regional transmission rates.

Grid operator expects sufficient electricity this summer

Regional electricity grid operator ISO New England, Inc. issued its 2013 summer outlook on April 29.  In that report, New England regional transmission organization found that regional electricity supplies during the upcoming summer are expected to be sufficient to meet consumer demand under normal weather conditions.  But if any number of contingencies occur, such as a heat wave, the grid could be seriously strained.

ISO New England noted that under normal conditions, there should be enough electricity this summer.  But it identified a series of risk factors could tip the balance of supply and demand for electricity, including extreme summer weather conditions or unexpected resource outages.  These factors could create "operational challenges", meaning a hard time finding enough electricity to meet peak demand.  New England may be forced to resort to  importing emergency power from neighboring regions, and asking businesses and people to voluntarily conserve energy.

The report's base assumption is for "normal" summer weather conditions of about 90 degrees in key southern New England cities.  Under these conditions, ISO New England forecasts electricity demand could reach 26,690 megawatts (MW).   If an extended heat wave pushes temperatures to 95, demand could rise to 28,985 MW.  Last summer’s load peaked July 17 at 25,880 MW, about 3% smaller than the base amount forecast for summer 2013.  New England set its record for peak demand on August 2, 2006, when demand reached 28,130 MW.

On the supply side, ISO New England identified several risks that could lead to unexpected shortages of electricity.   First, most natural gas pipeline maintenance in the region is scheduled for the summer months.  Maintenance activities could affect natural gas supplies to some power plants. On this point, the grid operator said it was coordinating with the pipeline companies to ensure that the supply is adequate for power generation during the maintenance season.

Second, liquefied natural gas (LNG) is in high global demand.  Current LNG prices are roughly three times higher in Europe and Japan than in the United States.  This mean LNG deliveries into New England might be reduced this summer.  At times, New England electric generation relies on LNG, which could also affect power plant operations.

Overall, ISO New England reported that it expects electricity supplies to be sufficient to meet consumer demand under normal weather conditions this summer.  If shortages occur, they will likely affect both the reliability of the grid and the wholesale price of power.  The winter season is likely to be worse, as regional demand for natural gas for heating increases during the winter, placing a tighter squeeze on the amount and price of gas available for electric generation.  The grid operator's prediction will be put to the test in the coming months.