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RESEARCH

North America Power and Utilities | Demand Response

Demand Response to Grow Under Alternate Scenarios Regardless of FERC Order 745 Outcome

Demand Response Will Continue to Play a Role in Electricity System Resource Mix Regardless of Supreme Court Decision

Key Takeaways:

Demand response participation in wholesale power markets has varied across Regional Transmission Organizations since the Federal Energy Regulatory Commission finalized Order 745

Despite equal compensation under Order 745, demand response participation in wholesale energy markets is currently low and it is difficult for this resource to justify economic participation in low energy price environments

Due to its currently low participation, an upheld Order 745 vacatur will not significantly impact existing wholesale energy markets across all regions, and demand response would continue to grow under state- and utility-led retail programs

Entities Mentioned:

California ISO

Electric Reliability Council of Texas

EnerNOC

FirstEnergy

Midcontinent ISO

New England ISO

New England Power Generators Association

New York ISO

PJM Interconnection

Southwest Power Pool

March 2, 2015 Policy Brief

Author Erin Carson Chief Policy Strategist

Eric Davis Research Manager

Contact

(212) 537.4797 [email protected]

Related Research

Demand Response Parity in Wholesale Markets Hinges on FERC 745 Outcome RTOs Look to Tariff Revisions as FERC Petitions Supreme Court to Review Order 745

http://enerknol.com/demand-response-parity-wholesale-markets-hinges-ferc-745-outcome/

http://enerknol.com/demand-response-parity-wholesale-markets-hinges-ferc-745-outcome/

http://enerknol.com/rtos-look-tariff-revisions-ferc-petitions-supreme-court-review-order-745/



© 2015 EnerKnol, Inc. All rights reserved. 2

RESEARCH | POWER & UTILITIES MARCH 2, 2015

Legal Debate over FERC 745 Focuses on Demand Response Use in Wholesale and Retail Markets Demand response is reduced energy consumption in response to high prices, incentives, or emergency events, and it has been active in both wholesale and retail markets. The reduction in electric energy by customers from their expected consumption can be in response to either an increase the price of electric energy – a “retail-level” demand response – or to incentive payments designed to induce lower consumption, which the Federal Energy Regulatory Commission (FERC) found to be a “wholesale demand response,” setting the framework for the current debate.

If demand response is found to be a retail, not a wholesale, product, it would be outside FERC’s statutory jurisdiction, and the vacatur on Order 745 would be sustained. But according to FERC, demand response is an important factor for competitive and organized wholesale markets. They reasoned that its equal compensation level is just and reasonable. The basis for this justification stems from both statutory authority to regulate wholesale rates and from policies to reduce consumer prices using a market-based system instead of rate-based cost of service. FERC’s statutory authority to monitor wholesale markets stems from provisions in two federal laws:

The Energy Policy Act of 2005 (EPAct 2005), Section 1252(e)(3), and Section 1223, which provide a congressional mandate for demand response in organized wholesale electricity markets, direct FERC to coordinate with states, and specify that FERC encourage deployment of advanced transmission technologies, including controllable load.

The Federal Power Act (FPA) of 1935, Sections 205 and 206 and Sections 824D and 824E, which establish FERC’s authority over ensuring just and reasonable wholesale power market rates. Sections 205 and 206 task FERC with ensuring “all rules and regulations affecting . . . rates” in connection with the wholesale sale of electric energy are “just and reasonable.”

Over time, FERC responded to these statutory authorities by implementing market structures within wholesale markets to ensure that products and structures allowed the rates to be just and reasonable. And, since FERC saw demand response as a product that ensured consumers received fair rates in power markets, it incorporated demand response into those markets. Accordingly, FERC also promulgated several rules that further eliminated barriers to demand response participation, including Order 719 in 2008, which removed barriers to demand resources in organized, wholesale markets; and Order 745, which created uniform payment levels for demand response in wholesale day-ahead and real-time markets (Figure 1). According to FERC, Order 745 was a response to variance in demand response compensation schemes from different ISOs and RTOS, and it was designed to level the playing field by allowing users who reduced their consumption in response to higher wholesale power prices to be paid for those reductions at the same rate that

FERC Order 745 mandates consistent demand response compensation across RTOs equal to other generators



electric generators are paid to provide power – a compensation price known as locational marginal price (LMP).

Figure 1 – FERC Orders Pertaining to Demand Response

October 17, 2008 – FERC issued Order 719 requiring RTOs and ISOs to compensate demand response comparable to other (generating) resources, and accept wholesale market bids from aggregated retail customer demand response providers.

March 15, 2011 – FERC issued Order No. 745 (the Order), requiring RTOs and ISOs to compensate demand response in wholesale energy markets at the full locational marginal price (LMP).

May 23, 2014 – Court of Appeals for the DC Circuit (Appeals Court) ruled in Electric Power Supply Association (EPSA) v. FERC, deeming demand response a “retail” market product under state jurisdiction, invalidating FERC’s jurisdiction over demand response compensation in wholesale (energy) markets.

September 17, 2014 – The Appeals Court denied petitions for rehearing.

October 20, 2014 – The Appeals Court granted FERC a stay on its ruling, giving the Solicitor General (on behalf of FERC) until December 16 to file a petition for writ of certiorari for the Supreme Court to review the case.

December 8, 2014 – The Solicitor General applied – and was granted – for an extension to January 15 to file petition for a writ of certiorari to review the EPSA v. FERC Order 745 decision.

January 15, 2015 – The Solicitor General petitioned the Supreme Court for writ of certiorari.

Source: EnerKnol data

Order 745 Vacatur Decision Brings Market Uncertainty In its decision, the D.C. District Court determined that FERC has no power to order energy buyers in RTO-organized markets to compensate retail consumers for demand response. The court vacated the order on two grounds: 1) FERC did not have jurisdiction under the FPA to issue Order No. 745 because demand response is part of the retail market, which is exclusively under state jurisdiction; and, 2) even if FERC did have jurisdiction, FERC failed to properly consider concerns that Order No. 745 would result in unjust and unreasonable demand response compensation rates, as demand response resources also realize savings from avoiding the purchase of retail electricity, unlike “steel-in-the-ground” generators. The majority opinion stated: “Demand response – simply put – is part of the retail market. It involves retail customers, their decision whether to purchase at retail, and the levels of retail electricity consumption. ...A buyer is a buyer, but a reduction in consumption cannot be a ‘wholesale sale.’ FERC’s metaphysical distinction between price-responsive demand and incentive-based demand cannot solve its jurisdictional quandary.”

2008

2011

2014

2015



In response, FERC argued that they acted within jurisdiction set out by the FPA by allowing compensation for aggregated retail demand resources to participate in wholesale markets. Under this interpretation of the FPA, FERC would hold clear jurisdiction over rates in wholesale markets and interstate commerce. In a 2-1 split decision, however, the court panel disagreed with this argument and ruled that the FERC interpretation was an act of indirect regulation of retail markets. On May 23, 2014, the U.S. Court of Appeals for the D.C. Circuit Court issued a decision in EPSA v. FERC, vacating and remanding Order No. 745.

Supreme Court Appeal Critical Step in Settling Demand Response Jurisdictional Debate The future of demand response participation in wholesale and potentially other energy markets now rests on the Department of Justice’s (DOJ) appeal of the FERC Order 745 case in the Supreme Court. On January 15, 2015, the DOJ, on behalf of FERC, petitioned the Supreme Court for a writ of certiorari to review the U.S. Court of Appeals for the D.C. Circuit ruling. The DOJ petition reasoned that in invalidating FERC Order 745, the Appeals Court misinterpreted the FPA and misapplied basic principles of deference to agency interpretations of statutes. The petition stated that the Appeals Court’s analysis was based on an unfounded concern that Order 745 would permit FERC to regulate the retail electricity market and generation inputs like fuel and steel. It stated that demand response providers are actual and integral participants in wholesale markets and the effect of their participation on wholesale rates is far more immediate and direct, compared to the effect exerted by general retail consumption or compared to markets of generation inputs. The DOJ underscored the importance of Order 745 for the efficiency and reliability of modern electricity markets, for the following reasons:

Electricity prices – optimal demand response use in wholesale electricity markets, which cover two-thirds of U.S. electricity load, is likely to produce lower electricity prices

Reliability and resource adequacy – demand response enhances grid reliability and resource adequacy

Generators’ market power – direct demand response participation in wholesale markets mitigates market power of electricity suppliers as they have to compete with demand response resources and adjust their bidding strategy

The Supreme Court Order 745 review is still uncertain



Stakeholders to the Supreme Court Decision Extend Beyond Generators and Demand Response Providers

While direct stakeholders to Order 745 include power generators, demand response providers, aggregators, and suppliers, the indirect impacts of the rule affect a number of other entities, including trade associations, state regulatory commissions, publicly owned utilities, natural gas, distributed energy and advanced electricity, and electricity consumers.

Power Generators Broadly Oppose Equal Consideration of Demand Response in Organized Electricity Markets The plaintiff group in the lawsuit disputing Order 745 was led by the Electric Power Supply Association (EPSA) and other traditional power generation entities, stating that demand response is a retail, not a wholesale power product; and that sing the LMP rate structure is not “just and reasonable (Table 1).”

Table 1 - Plaintiff Opposition and DC District Court Justification to Vacate

Plaintiffs Filing Lawsuit Against FERC Plaintiff Challenge; D.C. District Court Justification to Vacate

Generators (Electric utilities)

Electric Power Supply Association (EPSA) American Public Power Association (APPA) Natural Rural Electric Cooperative Association (NRECA) Edison Electric Institute (EEI)

The Commission has no authority to draw retail customers into the wholesale markets by paying them not to make retail purchases

Demand response is a retail transaction subject to oversight by state utility commissions

Using LMP as the rate structure is “arbitrary and capricious” under the Administrative Procedure Act (APA)

D.C. District Court: “Ordering an ISO to compensate a consumer for reducing its demand is the same in substance and effect as issuing a credit. Thus, while it is true demand response can occur in two ways – through a response to either price change or incentive payments – nothing about the latter makes it “wholesale”

A buyer is a buyer, but a reduction in consumption cannot be a “wholesale sale”

Without boundaries, EPAct 2005 Sections 205 and 206 could “ostensibly authorize FERC to regulate any number of areas, including the steel, fuel, and labor markets”

FERC can regulate practices affecting the wholesale market under §§ 205 and 206, provided the Commission is not directly regulating a matter subject to state control, such as the retail market

Source: EnerKnol Data, Electric Power Supply Association v. Federal Energy Regulatory Commission, District of Columbia Circuit Court

Diverse Group of Stakeholders Say Demand Response in Wholesale Markets is Necessary for Electric Reliability On the other side of the debate, petitioners who have filed in support of appeal of the D.C. District Court ruling have included state consumer advocate offices public utility commission (PUCs), health and environmental



organizations, demand response aggregators, and several regional transmission organizations (RTOs) (Table 2). Petitioners argue that demand response in wholesale markets is essential for maintaining consistent cost and reliability across power markets.

Table 2 – Parties in Support of Appeal and Solicitor General Justification for Petition

Proponents of FERC Order 745 Filing Writ of Certiori and Briefs in Support of Appeal FERC Justification; Appeals for Writs of Certiorari

State consumer advocates’ offices: Delaware, District of Columbia, Maryland, New Jersey, Pennsylvania, West Virginia State Public Utility Commissions (PUCs): California, Maryland, Pennsylvania PUCs National and regional public health and environmental organizations: Conservation Law Foundation, Environmental Defense Fund, Environmental Law and Policy Center of the Midwest Natural Resources Defense Council, Sierra Club Demand response Aggregators: EnerNOC, EnergyConnect, Viridity Energy RTOs: PJM Industrial Customer Coalition, Coalition of MISO Transmission Customers Utilities: Consolidated Edison Company of New York (ConED) Northeast Utilities/Eversource Energy and affiliates

When retail consumers voluntarily participate in the wholesale market, they fall within the Commission’s exclusive jurisdiction to make rules for that market

Critically important environmental and economic benefits are distinct to demand response participation in FERC-regulated wholesale energy markets

The D.C. Circuit’s decision deprives states of policy discretion to pursue their preferred energy programs; under Order 745, state regulators decide whether to allow entities within their jurisdiction to participate in organized wholesale energy markets, while the D.C. Circuit’s ruling makes that decision for the state

According to the U.S. Attorney General Appeal for Writ of Certiorari, the D.C. Circuit “seriously misinterpreted the FPA and misapplied basic principles of deference to agency interpretations of statutes.”

The D.C. Circuit Court was unfounded in its concern that the rule could permit FERC to regulate other retail markets, like fuel and steel, because DR providers are “actual and integral participants in wholesale markets themselves…”and the effect of their participation on the wholesale rate is more immediate than other retail consumption or generation inputs

The D.C. Circuit Court decision raises questions of whether FERC has jurisdiction over any rules created by wholesale market operators to regulate DR participation, or whether it has authority to permit participation of DR providers in any wholesale markets, including capacity markets and natural gas regulation

Source: EnerKnol Data, Petition for Writ of Certiorari, Amicus Briefs, Briefs

The FERC Order 745 Decision Impacts Entities Across the Generation, Transmission/Distribution, and Consumption Value Chain Order 745 has had varying impact for different stakeholders, and the outcome of the Supreme Court decision will be equally diverse. The following provides a detailed breakdown of how the Order has impacted and will continue to affect different industry groups.

Generators: Order 745 Threatens Revenue “Steel-in-the ground” generators are in direct competition with demand response resources in meeting system load in times of high demand. Large-scale growth of demand response in organized electricity markets can threaten



generators’ revenue by replacing “peaker” plants built solely to meet peak system demand. For generation-owning companies that rely on increasing consumer electricity demand for continued revenue growth, demand response and other substitutes (such as distributed generation) pose a direct threat. In April 2014, the CEO of American Electric Power testified before the Senate Energy and Natural Resources Committee that the structure of the capacity markets was failing to attract a mix of new generating resources, particularly since “demand response continues to be paid similar capacity prices to steel-in-the-ground generation despite having rules and penalty provisions that are much less prescriptive.” The market was not sending signals to inspire new investment, which was putting reliability at risk when in conjunction with the high number of base-load unit retirements. Generators argue that the LMP method in Order 745 is not just and reasonable, since demand response resources do not have generation costs and are already receiving benefit by way of load reduction and savings on the electricity bill for that period. In its opposition to Order 745, EPSA and other opponents have also argued that demand response is not physically equivalent to generation, that the system can reliably perform without the resource, and that demand response does not provide the same amount of reliability benefits as generation because of their limited participation, penalty, and testing requirements.

Demand Response Providers: Order 745 Allows Consistent Compensation Across RTO Wholesale Markets Demand Response providers include manufacturing factories and commercial buildings that receive full market prices when they cut their demand usage. According to the Industrial Energy Consumers of America, the manufacturing industry consumes 26 percent of total U.S. electricity, and energy expenditures can make up 10 percent (paper production) to 85 percent (integrated steel production) of manufacturers’ operational costs. Due to this high level of consumption, energy prices can have a significant impact on operational costs. In periods of peak system demand and commensurately high energy prices, the ability to curtail load by interrupting operations is an important benefit to both manufacturers and grid reliability. Demand response has had direct impact on product engineering companies such as Alcoa, a global leader in metals engineering and manufacturing with a cumulative peak U.S. load of approximately 3,000 MW. Energy amounts to 40 percent of Alcoa’s aluminum operations costs. In its comments on the Order, Alcoa argues that because demand response deployment avoids external generation costs such as greenhouse gas emissions, the provider should be compensated at a more generous rate than the LMP would allocate. Demand response providers say that a consistent demand response compensation level is critical to increasing the resource across RTO wholesale markets. For many large, multi-region industrial companies, a consistent regulatory framework lowers barriers to demand response participation. This

Demand response poses a direct threat to generator peaker plant revenues Energy can be up to 85 percent of manufacturers’ operational costs



is due to the expertise needed to model the direct, opportunity, and risk factors to cost-effectively utilize demand response. They argue that a consistent compensation rate, such as the Order 745-mandated LMP, would allow large industrial organizations to more easily transfer and share expertise across various operational locations.

Demand Response Aggregators: Order 745 Ensures Competition in Wholesale Markets but Biggest Impact Would be an Extension to Capacity Markets Demand response aggregators, or curtailment service providers (CSPs), depend on favorable demand response policy to support their business model. They have largely supported the FERC Order for maintaining competition in wholesale markets. CSPs utilize software platforms to allow consumers – mostly commercial and industrial (C&I) – to curtail their load in response to reliability or price-based events, or provide other ancillary services such as short-term system balancing. This service plays an important role for grid reliability and potential peak load reduction, as not all C&I or high energy use customers have the technology, expertise, or individual load requirements to participate in organized electricity markets. An upheld Order 745 vacatur limited to wholesale energy markets would not significantly impact CSP company revenue, as their participation in this market is generally not substantial. However, a vacatur ruling extended to capacity markets would significantly impact CSP revenues. For example, EnerNOC, a leading CSP, derived the 45 percent ($174,303M) of its 2013 revenues from the PJM capacity market. Despite its somewhat limited direct wholesale market participation, EnerNOC stated in its petition for cert that without Order 745, “wholesale energy markets will not ‘function effectively’: Competition will be constrained; prices will be higher; and the important public health benefits from reducing reliance on dirty and inefficient generators will be lost.”

RTOs: Order 745 Needed for Wholesale Competition and Reliability but Impact Varies Across Market Structures RTOs are responsible for efficiently balancing electricity supply and demand at all times to maintain reliability, and demand response is a valuable asset in achieving this requirement. The wholesale LMP has created momentum for demand response programs, but participation has varied across RTOs. PJM Interconnection, the grid operator for 13 mid-Atlantic and New England states, has taken the greatest role in supporting demand response, while other regional independent system operators (ISOs)/Regional Transmission Organizations (RTOs) such as NYISO, ISO-NE, MISO, SPP, and CAISO have implemented demand response programs at varying levels. Both PJM and MISO advocacy groups were signatories to the U.S. Solicitor General Petition for Writ of Certiorari. From 2011 to 2012 (after Order 745 compliance) PJM increased the number of demand response market participants by 300 percent, while its MWh reductions increased more than 800 percent. Despite FERC finalizing Order 745 on March 11, 2011 and requiring tariff amendments by July 22, 2011, full Order 745 compliance and demand response participation in the organized wholesale energy markets has been

CSPs are affected by wholesale activity but revenues largely rely on capacity and retail markets



inconsistent. Detailed descriptions of each RTO’s demand response interactions is discussed later in this report.

PUCs: State Regulators Will Play Increased Role Under Order 745 Vacatur State Public Utility Commissions (PUCs) and Public Service Commissions (PSCs) regulate the retail rates utilities charge to their customers, including utility-led demand response incentive programs. These programs date back to before the advent of organized energy markets and will continue regardless of the outcome. For regions such as MISO and CAISO, utility-led demand response programs prevail as the primary market. State PUCs support FERC’s authority over demand response participation in wholesale electricity markets. The California PUC and Maryland PSC petitioned for a FERC Order 745 rehearing en banc in July 2014. They stated that demand response is an “integral wholesale service used to balance supply and demand,” and that Order 745 does not impair states’ jurisdiction over retail rates. Order 745 also allows states to opt out of allowing demand response to participate in their respective wholesale market; however, no state has yet exercised this right. Still, if the FERC Order 745 vacatur is upheld, state utility commissions will likely play an increased role in demand response markets as utilities are pushed to expand their programs. This scenario is supported by ever-increasing advanced metering infrastructure (AMI) deployments and software offerings that allow consumers to more closely and actively manage usage. An example of this scenario is already taking place in New York. On December 15, 2014, the New York Public Service Commission (PSC) ordered all state utilities to develop retail demand response programs and submit tariff revisions by March 15, 2015, for implementation this summer. Although this is a positive for industry, the freedom with which utilities design unique programs can create a barrier to demand response industry growth, as market participants will be challenged to rapidly and efficiently expand without a uniform compensation structure similar to that which Order 745 provides.

Indirect Stakeholders: Uncertainty from Order 745 Impacts Energy and Technology Markets and Cost of Electricity to Consumers The uncertainty of the Order 745 outcome – and the possibility that it could extend to impact capacity markets – impacts other markets, such as capacity and natural gas markets and demand response technologies, as well as consumer price. If Order 745 is extended to capacity markets, RTOs would have to seek additional supply from generators, including new natural gas turbines, with a number of further impacts. There would be substantial new investment in gas-fired generation, but also increased reliability concerns due to the immaturity of comprehensive natural gas infrastructure.

State PUC-regulated utility demand response programs would likely expand if Order 745 is vacated



In addition, the uncertainty impacts technology providers and continued investment in new demand response systems and appliances, including distributed energy and advanced electricity storage systems such as smart thermostats and smart appliances. Uncertainty in the FERC Order 745 decision could also delay continued progress in energy efficiency and demand response. However, a resolution of the court decision – either way – would likely mean that these companies could continue to be developed and prepared for future deployment. Finally, electricity consumers, particularly in the PJM region, could see electricity price increases under a vacated Order 745. This is because demand response resources provide market competition as a recognized system asset, and in their absence, fewer resources will be available to meet demand.



FERC Order 745 has had Varying Impact on Peak Reduction and Demand Response Enrollments across RTOs

Peak reduction and electricity costs across the seven U.S. RTOs would be varyingly impacted by an upheld Order 745 vacatur, based on market structure and current level of demand response participation in wholesale markets.

Peak Reduction: Demand Response has Increased Potential Peak Reduction in Both Retail and Wholesale Markets Demand Response is also termed as “negawatts” or generation of negative watts – a virtual term that has a cancellation effect on overall quantity of (peak) power generation. During times of peak electric demand, utilities have to resort to operating expensive “peaker” sources, which results in wholesale energy price increases. The marginal sources are also often among the highest polluting sources in a given fleet. When demand response resources participate in the wholesale energy markets by bidding specific, binding use reductions into day-ahead or real-time auctions, this flattens the load profile, removes or reduces the need to rely on costly peaker generation plants, and brings down electricity production costs and consumer prices. According to reported FERC data from 2008 to 2013, potential peak load reduction in RTOs from demand response programs increased by more than 200 percent since 2008, from 9,060 MW in potential peak load reduction in 2008 to 28,798 MW potential peak load reduction in 2013. This attests to the key role demand response resources play in potentially adjusting peak load in both retail and wholesale markets (Figure 2).

Potential Peak Load Reduction in RTOs (2008-2013)

Source: 2008-2013 FERC RTO Surveys, EnerKnol Data

9,060

20,533

26,346 28,798

-

5,000

10,000

15,000

20,000

25,000

30,000

35,000

2008 2010 2012 2013

Po

ten

tial

Pea

k Lo

ad R

edu

ctio

n (

MW

)

RTO reporting year



However, while the prior-year FERC data shows that the potential peak reduction from demand response has increased across all RTO/ISO markets, it does not conclude that the sum of these benefits were from demand response resource participation in wholesale markets. The data also shows participation from behind-the-meter programs. Consequently, Order 745 has direct impacts to potential peak load reduction in regions with heavily implemented demand response resources in wholesale markets, but it has varying impacts on regions with less wholesale participation or that are implementing utility-run load modifying resource programs, or both. For example, the two RTOs with highest potential peak reduction in 2013 were in PJM’s wholesale and capacity markets (9,901 MW, 6.3 percent from demand response resources), and MISO’s behind-the-meter utility-led demand response generation and load modifying programs (9,797 MW, 10.3 percent from demand response resources) (Table 3). FERC notes that reduced participation in NYISO, ISO-NE, and CAISO were due to tightened criteria for qualification, low capacity and energy prices, and a demand response resource view (in ISO-NE) that the value of participation did not outweigh participation requirements.

Table 3 – Potential Peak Reduction from U.S. ISO and RTO Demand Response Programs

RTO/ISO

2012 2013

Potential Peak

Reduction (MW)

Percent of Peak

Demand

Potential Peak

Reduction (MW)

Percent of Peak

Demand

CAISO 2,430 5.2% 2,180 4.8%

ERCOT 1,800 2.7% 1,950 2.9%

ISO-NE 2,769 10.7% 2,100 7.7%

MISO 7,197 7.3% 9,797 10.2%

NYISO 1,925 5.9% 1,307 3.8%

PJM 8,781 5.7% 9,901 6.3%

SPP 1,444 3.1% 1,563 3.5%

Total 26,346 5.6% 28,798 6.1%

Source: FERC Assessment of Demand Response and Advanced Metering (Dec. 2014)

Demand Response Enrollments: Energy Market Demand Response Enrollments Relatively Flat Across RTOs Despite FERC Order 745 compliance across most RTOs, demand response wholesale energy enrollments have not increased in all regions. Market barriers still exist beyond compensation levels. It is not often that day-ahead and real-time energy prices reach economic participation levels for demand response resources. Qualified large C&I customers must closely weigh the costs and benefits of market participation, which is often not feasible in the real-time market. Aggregators can be challenged by minimum resource requirements and technical barriers to participation in real-time markets. Also, unlike capacity markets, there is no guarantee of revenue for participating in

Potential peak reductions from demand response resources are primarily from capacity and retail commitments



the wholesale energy markets unless the resource clears or is dispatched in the market. These and other market and technical barriers have led to continued low wholesale energy market registration by demand response resources in recent years (Figure 3).

Figure 3 – Registered Wholesale Energy Market Demand Response

Source: Various RTOs, EnerKnol Data

PJM Region Leads in Demand Response Enrollments and Deployment The PJM Interconnection (PJM) RTO is the most well-developed regional demand response market in the United States. PJM covers all or parts of Delaware, Illinois, Indiana, Kentucky, Maryland, Michigan, New Jersey, North Carolina, Ohio, Pennsylvania, Tennessee, Virginia, West Virginia and the District of Columbia. The RTO has offered wholesale market demand response participation since 2002. PJM has shown distinct cost impacts from Order 745 and the incorporation of demand response resources into the wholesale market. Prior to FERC Order 745 implementation, from November 2008 through March 2012, PJM compensated wholesale demand response the LMP less the generation and transmission (G&T) price. During this 3.5-year term, demand response assets only generated $7.1 million of revenue from 166,276 MWh. For the first seven months after Order 745 implementation in April 2012, PJM reported that wholesale demand response resources generated $8.7 million in revenue from 133,466 MWh. Similar wholesale demand response revenues were earned in 2013 from 134,953 MWh. In 2014, wholesale demand response resources jumped to approximately $17.7 million in revenue over 143,700 MWh. The revenue increase was mostly due to nearly $7.7 million in January 2014 demand response revenues. These resources were mostly called to meet record winter peak demand on January 7. Some of the difference in PJM cost and enrollment pre and post Order 745 could also be due to the evolution of different PJM compensation and participation rules. Prior to Order 745, from 2002 to March 2012, PJM allowed

2014 PJM wholesale demand response revenues were largely from January cold-weather events



self-scheduled demand response. This enabled participants to simply reduce load for compensation at either the LMP less G&T (the retail price), or the full LMP when market prices exceeded $75/MWh. These resources were not dispatched by PJM and were not directly considered for LMP determination. Starting in November 2007, PJM reduced compensation to only the LMP less the G&T rate. Amendments to the customer baseline (CBL) methodology – an estimate of load if the resource did not take load reduction action (used to compensate the resource) – reduced individual participant reductions by 35-85 percent. In addition, PJM introduced more stringent reporting requirements to ensure load reductions were in response to wholesale prices, not part of normal operating conditions. This also reduced self-scheduled load reductions. The combination of lower compensation, less favorable load reduction calculations, more stringent reporting requirements, and the introduction of new demand response capacity market designs all reduced PJM’s economic demand response participation from 2007 to 2012 (Figure 4).

Figure 4 – Monthly Settled Economic Demand Response (Jan. 2007 - Oct. 2012)

Source: PJM

The implementation of FERC Order 745 (and PJM compliance) in March 2012 reinstated the LMP compensation level and eliminated self-scheduling. The market rule amendments shifted former self-scheduling resources to bid (and clear) in the day-ahead market. Although enrollments did not significantly increase after Order 745 compliance, high system demand during summer 2012 hot weather events (and commensurate high day-ahead and real-time prices) increased demand response utilization when compared to 2011.

MISO Region Has Shown Limited Direct Demand Response Participation in Energy Markets The Midcontinent ISO (MISO) covers all or portions of 16 states that are predominately regulated utility markets, and demand response is largely



limited to behind-the-meter generation. The region’s demand response capability was 9.8 GW in 2013, a 36 percent increase from 2012. The majority of these resources are load modifying resources (LMRs) or behind-the-meter generation (BTMG), which are under regulated utility control and do not set MISO market prices when dispatched. According to the MISO Internal Market Monitor, of a total of 19 qualified demand response resource (DRR) types I or II, only 13 units with 272 MW of capacity participated directly in MISO’s energy markets in 2013. All but three units provided only supplemental reserves. Alcoa’s 75 MW of DRR type II is the only resource able to bid and set the LMP. Approximately 86 percent (8.5 GW) of the 9.8 GW of MISO region demand response in 2013 existed as LMR or BTMG, which MISO does not directly control and cannot set energy prices to when it is called.

New England ISO Region Demand Response Challenged by Low Market Prices The New England Independent System Operator (ISO-NE) has offered a formal wholesale demand response program for more than a decade, but participation has been inconsistent. The ISO created two main categories of demand response resources: active and passive. Active demand response resources are dispatchable in the wholesale market in response to prices. These Real-Time Demand Response (RTDR) products are dispatched during an Operating Procedure 4 capacity deficiency forecast the day ahead or in the real-time market. Passive demand response resources are not dispatchable, but are emergency assets scheduled for use at pre-determined (non real-time) periods. Emergency demand response programs, in which the ISO notifies RTDRs within 30 minutes for use, require resources to be a minimum of 100 kW. Resources are compensated at the higher of the LMP or $500/MWh. The Transitional Price Responsive Demand (TPRD) program began in June 2012 and builds on the previous Price Responsive Demand and Day-Ahead Load Response Program (DALRP). The TPRD resource bids in the day-ahead market in response to forecast LMPs. This product complies with Order 745 and will remain in effect until June 1, 2017. At that time, new market rules that link capacity and wholesale demand response markets will go into effect. Participation in the DALRP program jumped in the summer of 2010, when reliability programs ended and allowed these resources to bid directly into the day-ahead market. During the summer and fall 2010 period, the majority of resources cleared in the Maine region. However, despite a spike in July 2011, real-time demand response participation has dropped. The drop in wholesale energy market demand response is likely due to a corresponding decrease in average LMPs caused, in part, by low natural gas prices. Despite seasonal spikes, ISO-NE LMPs have trended on average between $30-60/MWh, and regional wholesale market-enrolled demand response resources are not economically driven to participate at these prices. Since 2011, cleared demand response has been flat in the ISO-NE wholesale energy market (Figure 5).

Low natural gas prices have limited demand response growth in ISO-NE



Figure 5 – ISO-NE Demand Response MWh Interruptions (2007-2014)

Source: ISO-NE, EnerKnol Data

Demand Response is Key to System Reliability Through both Economic and Emergency Resources

Demand response is a key market resource in avoiding rolling blackouts at times of record peak load or extensive generator outages. Whether registered as an economic or emergency resource, demand response has provided significant system reliability benefits in recent years’ cold- and hot-weather events. On January 7, 2014, the PJM region experienced an extended cold-weather event (the “Polar Vortex”) which led to more than 40,000 MW (22 percent of total capacity) of forced generator outages and an all-time record winter peak of 141,846 MW at 7:00pm. Demand response resources were called twice during that day, first from 5:30 a.m. to 11:00 a.m., then from 4:00 p.m. to 6:16 p.m. In total, demand response resources provided more than 4,500 MW of relief over the two emergency events, helping the RTO to reliably meet the record peak demand. In addition to PJM, the NYISO called on 900 MW to meet demand during the January 7, 2014 cold-weather event. Demand response again provided relief in the eastern PJM region during January 22-24. A total of more than 2,200 MW of demand response was provided across four events during the three-day cold-weather period (Figure 6).



Figure 6 – January 2014 PJM Region Generator Outages

Source: PJM, EnerKnol Data

The northeast was not the only region hit by the Polar Vortex. On January 6, 2014, the severe winter storm set a new winter peak of 57,277 MW and threatened electric reliability in the Electric Reliability Council of Texas (ERCOT) region. The RTO was able to meet demand by deploying 496 MW of emergency demand response. The ISO-NE region also called upon demand response to meet system demand during the 2013-2014 winter. The ISO called on 21 MW of demand response for five events over the three-month December to February period, in addition to already participating resources. Recognizing the importance of demand response in meeting winter demand, ISO-NE added three resources totaling 14 MW to its 2014-2015 Winter Reliability Program. In addition to winter system reliability, PJM has called demand response resources to also meet peak summer demand. On September 11, 2013, PJM experienced a record September peak demand of 147,450 MW. On this day a maximum of 6,233 MW of demand response was dispatched around 5:00 p.m., helping the RTO to avoid isolated load shed events similar to the four experienced the prior day.



Order 745 Vacatur will have Varying Impact on Demand Response Under Different RTO Frameworks Based on Current Wholesale Market Participation

Demand response registration in organized wholesale energy markets has not increased across all RTOs, despite favorable mandated compensation under FERC Order 745. The impact of a vacatur would have correspondingly diverse effects. In regions with forward capacity markets such as PJM, ISO-NE, and NYISO, demand response resources are incentivized to commit due to guaranteed capacity payments in future delivery years. However, there is no guaranteed revenue for participation in wholesale energy markets. Because of this economic constraint, and the need for high day-ahead and real-time prices to warrant economical participation, demand response has not played a consistent role in organized wholesale energy markets (Table 4).

Table 4 – 2014 Demand Response Registration Across Different RTO Markets

RTO 2009 2010 2011 2012 2013 2014

PJM 2,487 1,726 2,042 2,300 2,334 2,933

ISO-NE 873 1,255 1,227 1,193 793 783

NYISO 331 331 37 37 37 16

MISO 111 - 75 71 75 75

Source: Various RTOs, EnerKnol Data

PJM Aims to Shift Demand Response to Alternate Program In response to increased emphasis on system reliability, PJM has proposed to shift demand response to agreements by load-serving entities (LSEs) to reduce capacity obligations. This new market design is encompassed in PJM’s Capacity Performance (CP) proposal submitted to FERC on December 12, 2014. PJM outlined in an October 6, 2014 demand response whitepaper that, depending on Order 745 outcomes, demand response may not receive direct wholesale market compensation in the future. Instead, PJM proposed its Price-Responsive Demand (PRD) program in which load-serving entities (LSEs) and other entities would react to nodal, not zonal (LMP) prices, and would simply pay for less load at energy market clearing prices, as opposed to being directly compensated for energy use reductions. PJM already permits PRD in its day-ahead energy market, in which LSEs stipulate a price at which they would curtail energy use. In the real-time market, a LSE can provide forecast PRD which PJM will enter into its regional dispatch models. Despite the proposed PRD programs, PJM wholesale demand response market participation is currently through the Economic Load Response and Day-Ahead Scheduling Reserve Market programs. A Supreme Court Order 745 vacatur review would be a prolonged process. PJM reserves the right to modify its CP proposal pending any outcome. PJM recognizes that not implementing a wholesale load reduction alternative would result in continued uncertainty with the case pending before the Supreme Court. This would include the possibility of affirmation, which may

PJM’s Capacity Performance requirements would challenge demand response participation



require re-examination of 2015 PJM forward capacity market auction (base residual auction) outcomes. Regardless of the Order 745 outcome, the future of demand response in PJM capacity markets rests with its CP proposal. The CP proposal would ultimately shift demand response to the LSEs and state jurisdiction, which would mitigate uncertainty in the case of an upheld Order 745 vacatur. The strict all-hours, multi-day CP availability requirements could eliminate demand response from PJM’s capacity market starting with the 2020-2021 delivery year.

ISO-NE Wholesale Demand Response Participation is Low, but New Capacity Market Design Aims to Increase Participation Regardless of the FERC Order 745 outcome, ISO-NE’s efforts to integrate demand response into its markets through defined performance and compensation measures will ensure stability for demand response resource providers going forward. This stability is also a positive factor for regional emissions, as committed (emissions-free) demand response resources will replace some generation commitments in future delivery periods. On January 9, 2015, FERC approved revisions to ISO-NE’s transmission, markets and service tariff, which was filed on October 31, 2014 (Docket No. ER15-257-000) to fully integrate demand response resources into its wholesale energy markets, including reserve markets. Revisions that became effective on January 12, 2015 ensured that the tariff rules were in place before market participants submitted offers for the ninth forward capacity auction (FCA 9), on February 2, 2015. Full integration of demand response resources into operating reserve and forward markets with comparable compensation and obligations is a key step for defining demand response’s future in the ISO-NE market. ISO-NE’s revisions will enable demand response resources to provide operating reserves. They will participate in the forward reserve market upon full integration into the energy markets in June 2017. They will enable more efficient co-optimization of resource dispatch. They will expand the available resource pool to supply energy and operating reserves in real-time and on a forward basis, supporting a more reliable electric system and increased market competition. In the interim, wholesale demand response in the ISO-NE market will continue through its Transitional Price Responsive Demand Response (TPRDR) product.

NYISO Region Demand Response Participation is Primarily at Retail Level The New York ISO (NYISO) is a deregulated, single-state ISO. It offers wholesale market demand response participation through its Day-Ahead Demand Response Program (DADRP). As of May 2014, there were 1,321 MW of demand response resources across all NYISO programs. Nearly 97 percent of the enrolled demand response resources are in the Installed Capacity/Special Case Resource (ICAP/SCR) program. Although this is a capacity market program, an Order 745 vacatur would likely impact resource energy market payments and program structure.

ISO-NE is also moving forward with market reform despite Order 745 uncertainty



NYSIO currently administers four statewide demand response programs:

Day-Ahead Demand Response Program (DADRP) allows load-serving entities (LSEs) or transmission owners (TOs) to offer load reductions in the day-ahead market as a supply resource. The minimum load reduction is 1 MW in aggregate by LSE and load zone, and the energy offer floor price is currently $75/MWh.

Demand-Side Ancillary Services Program (DSASP) allows demand resources to offer in the day-ahead and real-time market as operating reserves or frequency regulation service. The energy offer floor price is currently $75/MWh.

Installed Capacity/Special Case Resource (ICAP/SCR) offers demand resources (SCRs) with a minimum (aggregate) size of 100 kW the opportunity to offer unforced capacity (UCAP) into the installed capacity (ICAP) market. Responsible Interface Parties (RIPs) act as aggregators and the interfacing party between SCRs and NYISO. LSEs may also act as their own RIP.

Emergency Demand Response Program (EDRP) offers SCRs the opportunity to earn payments of $500/MWh or the LMP if called by NYISO to curtail load. Curtailment Service Providers (CSPs) are the interface between these resources and NYISO. Resources may be enrolled in either the EDRP or the ICAP/SCR program, but not both.

The NYISO also offers the Targeted Demand Response Program (TDRP) to New York City SCR and EDRP resources. As of October 2014, 16 MW were registered for the NYISO DADRP program, and there has not been any offers since 2010. This is likely, in part, due to FERC not accepting NYISO tariff revisions to comply with Order 745. On November 22, 2013, FERC rejected proposed NYISO tariff revisions because the provisions excluded demand response facilitated by behind-the-meter generation (BTMG) from participation in the DADRP, while permitting participation by similar demand response accomplished without the use of behind-the-meter generation. The Commission ordered NYISO to develop rules for BTMG demand response to reliably participate in its DADRP. NYISO compliance filings are currently pending FERC review (Docket No. EL13-74-000). If the Order 745 vacatur is upheld, NYISO’s DADRP may be terminated. DADRP termination would have a minimal market impact, as none of the 16 MW of enrolled resource have bid under this program since 2010. In addition, NYISO has not made significant market changes since their Order 745 compliance filing has yet to be approved. The EDRP program will also likely be terminated if the Order 745 vacatur is upheld. Resources previously participating in this program could be shifted to LSE-based retail programs. Similar to PJM, NYISO is considering various preliminary “backstop” designs for its capacity market demand response (ICAP/SCR) program if the Order 745 vacatur is upheld. Broadly, NYISO aims to minimize impacts continuing its administrative demand response oversight, but shift RIP-based resources to only LSE-based participation. Energy market demand response payments would likely be eliminated, but could be shifted to LSE tariffs or retail service

NYISO would likely shift demand response capacity program to utilities under Order 745 vacatur



agreements (which currently largely exist in the NY market). Demand response could also be treated as a credit to the providing LSE’s capacity requirement. Since it is unclear whether or not an upheld Order 745 vacatur would impact ancillary markets, the NYISO has not considered any backstop design for its DSASP. Due to the Order 745 uncertainty, NYISO has postponed market rule development for further demand response participation in wholesale energy markets. Despite the scale-back, NYISO introduced its ICAP/SRC backstop market designs to stakeholders on December 12, 2014, and will continue to work on the designs in 2015. In addition to the backstop designs, NYISO will also focus on further defining advance metering communication infrastructure to support real-time demand response communication.

MISO-Region Demand Response Limited by High Threshold and State Regulations The Midcontinent ISO (MISO) covers all or portions of 16 states, the majority of which are regulated utility markets. The region’s demand response capability was 9.8 GW in 2013, a 36 percent increase from 2012. The majority of these resources are load modifying resources (LMRs) or behind-the-meter generation (BTMG), which are under regulated utility control and do not set MISO market prices when dispatched. MISO recognizes five types of demand response resources: Capacity Resources (only resources that qualify for the wholesale and reserve markets):

Demand Response Resource (DRR) Type I – physical load interruption offered to the wholesale or reserve market by a load serving entity (LSE) or energy consumer. This resource is inflexible (zero or full response), and thus cannot set wholesale market prices, but can set ancillary market prices.

DRR Type II – LSE or energy consumer capable of supplying a range of wholesale or reserve energy through metered generation or controllable load (load reduction, not interruption), offered to the wholesale or reserve market in five-minute increments. Treated comparable to a generation resource.

Load Modifying Resources (LMRs) are required to be available for emergency energy:

Demand Resource (DR) – Interruptible load or direct control load management (and other resources) that can reduce demand during emergencies

Behind-the-Meter Generation (BTMG) – resources used to serve wholesale or retail load behind a commercial pricing node, and can sometimes deliver to load demands in the transmission provider region

Emergency Demand Response (EDR):

More than 85 percent of MISO demand response is under utility-led programs



The commitment and dispatch of the above resources during an emergency event. Required of DRR that qualify as Capacity Resources and LMR, but also available to resources not qualified for DRR or LMR status

According to the MISO Internal Market Monitor, of a total of 19 qualified DRR Types I or II resources, only 13 units with 272 MW of capacity participated directly in MISO’s energy markets in 2013. All but three units provided only supplemental reserves. Alcoa’s 75 MW is the only registered DRR type II resource. The majority – nearly 8.5 GW – of MISO region demand response in 2013 existed as LMR or BTMG, which MISO does not directly control and cannot set energy prices when it is called. To further improve wholesale market pricing, MISO aims to implement extended locational marginal pricing (ELMP) this spring. ELMP extends the LMP pricing calculation to include fast-start (within 10 minutes) and EDR resources, allowing them to set prices. By allowing these resources to set wholesale market prices, ELMP aims to minimize price spikes during shortages and improve market price efficiency. Implementing ELMP would better recognize fast-start and EDR resources into MISO wholesale market, and may incent development of new resources. Any FERC Order 745 decision would have limited impacts to the MISO region, as demand response market participation is largely limited to non-price-setting LMR and BTMG resources. If the Order 745 vacatur is upheld, the region may lose up to approximately 460 MW of qualified demand response resources. To participate in MISO wholesale and ancillary markets, demand response resources must be at least 5 MW. The combination of this high threshold with the fact that most MISO states do not allow demand response resource aggregation has caused limited non-EDR proliferation in the region. The North American Electric Reliability Corporation (NERC) in its 2014 Long-Term Reliability Assessment projects the MISO region will drop below its reference capacity reserve margin of 14.8 percent in 2016. This reserve margin drop is projected to continue through 2024 with 10.8 GW of capacity retiring, largely due to an aging fossil fuel-fired fleet pressured by EPA emissions regulations and economic factors. The lower reserve margin will require MISO to rely on non-generating resources such as EDR to avoid rolling blackouts in times of peak demand. If the region calls on the currently non price-setting EDR in future emergency events, the marginal value of energy will not be properly represented in the wholesale market. Implementation of the ELMP pricing mechanism may play a key role in future MISO market operations and efficiency.

California Wholesale Demand Response Markets Lack Participation Despite ISO Efforts California currently lacks large-scale demand response participation in its wholesale markets. This is despite allowing participation since 2010 through its



Proxy Demand Resource product; implementing its Reliability Demand Response Resource (RDRR) since May 2014; and listing demand response at the top of its energy resource loading order. According to CAISO’s latest Market Issues and Performance report, no RDRR were registered or available for dispatch in the ISO market during Q3 2014. As of January 14, 2015, California demand response participants consisted of six demand response providers, 17 LSEs, and 3 utility distribution companies. Similar to the NYISO region, the majority of demand response is administered through utility-led programs of Pacific Gas & Electric (PG&E), San Diego Gas & Electric (SDG&E), and Southern California Edison (SCE). CAISO has introduced two demand response products for participation in its wholesale market:

Proxy Demand Resource (PDR) bids into the CAISO market as supply and provides services such as energy, non-spin, residual commitment (RUC) in the economic day-ahead and real-time markets.

Reliability Demand Response Resource (RDRR) bids into the CAISO market as supply and is used for reliability purposes. RDRR only offers energy services and dispatches economic day-ahead and reliability real-time. The minimum load curtailment is 500kW per RDRR.

In 2012, the CPUC directed the implementation of Rule 24, which enables direct participation by demand response resources – including utilities and third-party aggregators – in the ISO wholesale market. In 2013, the ISO made a compliance filing as directed by FERC to make the RDRR tariff consistent with FERC Order No. 745. After initially rejecting the filing, FERC accepted the RDRR-related filing, effective May 1, 2014. Despite the approval, very little demand response has been integrated into the CAISO wholesale market to date. In an attempt to better incorporate demand response into its wholesale market, CAISO is working to “bifurcate” demand- and supply-side demand response resources. The bifurcation would more distinctly separate demand response resources and allow supply-side demand response to competitively bid into the wholesale market as a capacity or balancing resource. In addition, the ISO would be able to seek demand response resources for dispatch similar to generation assets. The process in still in its conceptual stages, and the ISO aims to implement to proposed framework in 2017. Due to this extended finalization timeline, Order 745 uncertainty is not deterring the ISO from moving forward. An upheld Order 745 vacatur would have low impact to the current CAISO wholesale demand response market, as there was less than 6 MW of registered proxy demand resource, and zero bids in 2013. The ISO working to reshape demand response participation in its wholesale market through its bifurcation process, which is projected for implementation in 2017. Due to this extended timeline, Order 745 litigation issues could be resolved, enabling the ISO to properly prepare for and implement any necessary changes prior to program finalization.



California ISO’s Supply Resource Demand Response Integration Working Group is currently exploring how to better incorporate demand response into all markets, regardless of the FERC Order 745 uncertainty. The ISO internal market monitor identified three factors inhibiting CAISO market demand response growth: limited use of the proxy demand resource program, the timing and quality of demand response data, and limited integration of available demand response data into ISO operations. To address these factors, the ISO is currently working with PG&E, SDG&E, and SCE on pilot programs to expand proxy demand resource participation.

SPP Demand Response is Almost Completely Under Retail Programs More than 95 percent of Southwest Power Pool (SPP) demand response is retail. As of April 2014, the SPP had only 48 MW of demand response resources registered for participation in its redesigned wholesale energy marketplace. The SPP covers all or parts of Arkansas, Kansas, Louisiana, Mississippi, Missouri, Nebraska, New Mexico, Oklahoma, and Texas. Over the previous five-plus years, the SPP has worked to transition its wholesale energy market from its Energy Imbalance Service (EIS) market to its Integrated Marketplace (IM). The IM became operational on March 1, 2014, and offers market participants a day-ahead, real-time, and reserve markets, similar to other well-established RTOs. The IM combined 16 separate load balancing authorities to a single platform. The previous EIS market only allowed generators to sell excess power to load-serving entities in real-time. The SPP has two wholesale demand response programs:

Dispatchable Demand Response is a controllable load (including behind-the-meter generation) able to reduce load on a 5-minute basis when directed by the RTO.

Block Demand Response is a controllable load (including that of an aggregator of retail customers) that is not dispatchable on a 5-minute basis, but able to reduce load on an hourly basis when directed by SPP.

Similar to the CAISO and MISO markets, the majority of SPP demand response capacity is through utility-led retail programs, not bidding demand response directly into the wholesale markets. The SPP Integrated Marketplace became operational less than one year ago. The RTO is still fine-tuning its demand response net benefits and system-wide cost allocation methodologies to comply with FERC Order 745. The initial methodologies were developed using former (EIS) market data. Pursuant to Order 745, FERC directed SPP to file by year-end 2014 an evaluation whether these methodologies were in compliance, based on new IM market data (Docket No. ER12-1179-016). However, due to the April 2014 Order 745 vacatur decision, SPP requested an extension of the demand response methodologies’ compliance assessment to 120 days after the Order 745 uncertainty is settled “to avoid unnecessary expenditures of money and resources.” FERC granted the request on November 21, 2014.

More than 95 percent of SPP demand response is under utility-led programs



More than 95 percent of SPP demand response is currently under utility-led retail programs. Because of this, an upheld FERC Order 745 vacatur would have minor near-term impacts on the SPP wholesale demand response market participants. However, as exemplified by the aforementioned Order 745 compliance assessment extension request, the SPP is delaying its evaluation of demand response net benefits and cost allocation methodologies. This delay may hinder SPP wholesale demand response market growth due to uncertain authority over these critical market designs. Demand response resources will likely continue to remain under utility-led retail programs as the SPP continues to finalize demand response program design in its new wholesale markets. In its 2014 long-term reliability assessment, the SPP projects a modest approximately 3.5 percent annual demand response resource growth through 2024.

ERCOT is Not Under FERC Jurisdiction but Still Implements Demand Response Although the Electric Reliability Council of Texas (ERCOT) is not under FERC Order 745 jurisdiction, the region is working to offer demand response in its wholesale energy market. ERCOT issued Nodal Protocol Revision Request (NPRR) 555 in July 2013 to allow demand response participation in its real-time (Security-Constrained Economic Dispatch [SCED]) market. NPRR 555 was approved in September 2013 and implemented in June 2014, allowing demand response customers to qualify as Aggregate Load Resources (ALRs) and bid into the real-time market. The ALRs must be capable of responding on a 5-minute basis and, if cleared, will set the LMP. ERCOT will initially offer the real-time demand response product to Load Serving Entities (LSEs), then expand the program to third-party aggregators. So far, no resources have qualified for the new SCED market program. Per its February 2015 State of the Grid Report, ERCOT aims to qualify its first of these new real-time demand response resources this summer. Despite the nascent real-time demand response market, ERCOT has more than 2,000 MW of registered emergency and ancillary market demand response resources. These resources, along with utility load management programs add to a potential maximum peak reduction of more than 4,000 MW or about six percent of ERCOT’s peak load (68,305 MW in August 2011).

Nearly all ERCOT demand response resources are ancillary and emergency



Demand Response Resources Could Still Thrive in Retail and Ancillary Markets if Order 745 is Vacated with Varying Impacts to Industry

While the impacts to consistent cost and reliability in wholesale markets of a vacatur are real and would be intensely felt by stakeholders in certain RTO regions, the greatest threat is the uncertainty in the interim period to capacity markets and to investments in demand response technology. In the absence of FERC regulation of demand response in wholesale markets, states, retail rate regulators, and individual utilities will continue to open opportunities for the resource to impact peak demand, electric costs, and technology industry investment. A Supreme Court review of the Order 745 case could result in redefining FERC jurisdiction over demand response and refining the demand response language in the FPA. If Order 745 is vacated, demand response participation in wholesale electricity markets could lose incentive, resulting in increased power generation and associated emissions. This would affect efficiency and generation reduction goals. In addition, in the absence of demand response participation, expensive peaking power plants would be sought to address peak demand, resulting in increased power prices in energy markets. In addition, if Order 745 extends to capacity markets, PJM and other RTOs could not count on these energy savings in meeting future power demand, and would have to seek supply bids from other generators. Still, the force of these impacts would vary by region, with the greatest impacts felt in the PJM region. Order 745 only directly impacts those regions regulated by FERC, and the initial direct daily market impacts of an upheld Order 745 vacatur would not be significant across all RTO regions. Although demand response is an important resource in times of peak demand and system stress, various minimum capacity, availability, and technical requirements have led to low penetration of consistent demand response participation in organized wholesale energy markets. The FERC Order 745 uncertainty will cause this trend to continue. In addition, unlike capacity markets, there is no guarantee of revenue for participating in the wholesale energy markets unless the resource clears or is dispatched in the market. If the Supreme Court vacates Order 745, individual states could assume the power that was lost to the federally regulated side of the markets. Demand response has been increasingly incorporated into electric system resource planning, particularly as utilities have an increased need to manage peak demand in the context of increasing infrastructure and resource costs. Demand response will continue to be an important asset for utilities open to further incorporating reliability resources. The New York Public Service Commission recently mandated – under the Reforming Energy Vision proceeding – all in-state utilities to create demand response programs for summer 2015 implementation. In addition, California utilities – under AB 327 –



must continue to develop a two-way, customer-engaged grid model into their long-term models. These efforts will further open opportunities for demand response-enabling companies, such as advanced metering infrastructure, behind-the-meter storage/generation, and smart thermostat companies to continue to work with aggregators to expand retail program growth.



Disclosures Section RESEARCH RISKS

Regulatory and Legislative agendas are subject to change. AUTHOR CERTIFICATION

By issuing this research report, Erin Carson as author of this research report, certifies that the recommendations and opinions expressed accurately reflect her personal views discussed herein and no part of the author’s compensation was, is, or will be, directly or indirectly, related to the specific recommendations or views expressed in this report. IMPORTANT DISCLOSURES

This report is for industry information only and we make no investment recommendations whatsoever with respect to any of the companies cited, mentioned, or discussed herein. EnerKnol, Inc. is not a broker-dealer or registered investment advisor. Information contained herein has been derived from sources believed to be reliable but is not guaranteed as to accuracy and does not purport to be a complete analysis of the company, industry or security involved in this report. This report is not to be construed as an offer to sell or a solicitation of an offer to buy any security or to engage in or refrain from engaging in any transaction. Opinions expressed are subject to change without notice. The information herein is for persons residing in the United States only and is not intended for any person in any other jurisdiction. This report has been prepared for the general use of the wholesale clients of the EnerKnol, Inc. and must not be copied, either in whole or in part, or distributed to any other person. If you are not the intended recipient you must not use or disclose the information in this report in any way. If you received it in error, please tell us immediately by return e-mail to [email protected] and delete the document. We do not guarantee the integrity of any e-mails or attached files and are not responsible for any changes made to them by any other person. In preparing this report, we did not take into account your investment objectives, financial situation or particular needs. Before making an investment decision on the basis of this (or any) report, you need to consider, with or without the assistance of an adviser, whether the advice is appropriate in light of your particular investment needs, objectives and financial circumstances. We accept no obligation to correct or update the information or opinions in it. No member of EnerKnol Inc. accepts any liability whatsoever for any direct, indirect, consequential or other loss arising from any use of this report and/or further communication in relation to this report. For additional information, please visit enerknol.com or contact management at (212) 537-4797. Copyright 2015 EnerKnol, Inc. All rights reserved. No part of this report may be redistributed or copied in any form without the prior written consent of EnerKnol, Inc.

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