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.

Landmark FERC electric orders promote fairness

The Federal Energy Regulatory Commission is the lead federal agency in a variety of energy-related fields.  FERC regulates the transmission and wholesale sales of electricity in interstate commerce, the transmission and sale of natural gas for resale in interstate commerce, and the transportation of oil by pipeline in interstate commerce.  FERC also approves the siting (and abandonment) of interstate natural gas pipelines and storage facilities, as well as siting applications for electric transmission projects under limited circumstances.  FERC also licenses and inspects private, municipal, and state hydroelectric projects.

FERC has issued a number of landmark orders pursuant to its jurisdiction over electric utilities.  These landmark orders focusing on promoting fair and competitive markets include:

• Order No. 888 (Transmission Open Access. Promoting Wholesale Competition Through Open Access Non-discriminatory Transmission Services by Public Utilities; Recovery of Stranded Costs by Public Utilities and Transmitting Utilities).  This landmark rulemaking fostered greater competition in wholesale power markets by reducing barriers to entry in the provision of transmission service.  Historically, vertically integrated utilities dominated the electric power industry.  Despite efforts to empower independent power producers and to promote competition, the Commission noted that “[b]ecause many traditional vertically integrated utilities still did not provide open access to third parties and favored their own generation if and when they provided transmission access to third parties, access to cheaper, more efficient generation sources remained limited.”  In 1996, the Commission adopted Order No. 888 prohibiting public utilities from using their monopoly power over transmission to unduly discriminate against others.  The Commission required interstate transmission utilities to file open access non-discriminatory transmission tariffs – Open Access Transmission Tariff or OATTs – containing minimum terms and conditions of non-discriminatory service. It also obligated such public utilities to “functionally unbundle” their generation and transmission services.
• Order No. 890.  An outgrowth of Docket Nos. RM05-17-000 & RM05-25-000 (Preventing Undue Discrimination and Preference in Transmission Service), Order No. 890 cracked down on opportunities for utilities to unduly discriminate against certain customers under the Commission’s pro forma OATT.  In Order No. 890, the Commission strengthened its pro forma OATT to remedy undue discrimination, facilitate the Commission’s enforcement, and increase transparency of transmission planning and use rules.
• Order No. 1000.  The result of Docket No. RM10-23-000 (Transmission Planning and Cost Allocation by Transmission Owning and Operating Public Utilities), FERC Order No. 1000 reforms how public utilities plan and pay for transmission upgrades.  Previously, grid operators had fairly broad discretion to determine who should pay for an approved transmission line -- all regional consumers, the subset of consumers benefited by the line, generators, or others.  FERC observed that the lack of a uniform framework for cost allocation decisions meant that on the one hand, consumers could be paying more for transmission than they should, while on the other hand renewable power projects might be stifled by a lack of transmission expansion.  To fix this problem, the Commission issued Order No. 1000 to provide a framework for fair and open evaluation of transmission needs and to allocate the costs of transmission solutions fairly to those who receive benefits from them.
• Order No. 719.  The product of Docket Nos. RM07-19-000 and AD07-7-000 (Wholesale Competition in Regions with Organized Electric Markets), Order No. 719 offered a series of reforms to improve the operation of organized wholesale electric power markets.  Based on the premise that improving the competitiveness of organized wholesale markets is integral to the Commission's mission, FERC required regional grid operators to reform their tariffs and practices in the areas of demand response, long-term power contracting, market monitoring, and the responsiveness grid operators to their customers – and through them, to the consumers who benefit from and pay for electricity services.
• Order No. 745.  The product of Docket No. RM10-17-000 (Demand Response Compensation in Organized Wholesale Energy Markets), Order No. 745 requires regional grid operators to compensate customers fairly for reducing their consumption of electric energy in response to the grid operator’s warnings of supply scarcity – demand response – when that reduction in energy use is cost-effective and capable of displacing the need to additional generation online.

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.

July 26, 2011 - how FERC Order No. 1000 affects the US electric grid

FERC Order No. 1000 reforms how public utilities plan and pay for transmission upgrades.  The 620-page order and final rule, issued on July 21, 2011, is designed to move our electric grid toward a more efficient and cost-effective system -- part of the smart grid movement.

Order No. 1000 (620-page PDF) covers both transmission planning and cost allocation, at both the regional and interregional level.  As FERC notes in the order, under current transmission law, utilities can engage in local transmission planning without having to consider whether regional solutions would be more efficient or cost effective.  Likewise, regional grid operators have been able to approve transmission projects without being required to consider whether an interregional solution -- like connecting New England's electric grid to that of a neighboring region -- would be more efficient or cost effective.  Once a transmission line is approved, the status quo allows grid operators fairly broad discretion in determining who should pay for the line -- all regional consumers, the subset of consumers benefited by the line, generators, or others.  As a result, consumers may be paying more for transmission than they should, while a lack of transmission expansion in certain areas may be stifling the development of renewable power projects.

To fix this problem -- or in the language spoken by FERC as framed by the Federal Power Act, to "ensure that the rates, terms and conditions of service provided by public utility transmission providers are just and reasonable and not unduly discriminatory or preferential" -- FERC issued Order No. 1000 with two primary objectives:

(1) ensure that transmission planning processes at the regional level consider and evaluate, on a non-discriminatory basis, possible transmission alternatives and produce a transmission plan that can meet transmission needs more efficiently and cost-effectively; and

(2) ensure that the costs of transmission solutions chosen to meet regional transmission needs are allocated fairly to those who receive benefits from them.

Expanding this reform of regional transmission development, Order No. 1000 places a similar framework around interregional transmission planning and cost allocation.

Order No. 1000 will become effective 60 days after the final rule is published in the Federal Register.