Must States Step Up to Keep Demand Response Participating in Wholesale Markets? Part II

By Matthew Rose, Enerdynamics Instructor

In last week’s blog, we discussed the recent U.S. Court of Appeals decision that vacated FERC’s Order 745 concerning participation of demand response (DR) resources in 99681470wholesale markets. In that decision, the Court disagreed with FERC’s justification for compensating DR resources noting that “FERC’s new rule goes too far, encroaching on the state’s exclusive jurisdiction to regulate the retail market.”

This week, we are focusing on the implications to the Court’s decision.

Implications of the decision
The perceived impact of the Court of Appeals’ decision varies by party. FERC claims the ruling, if taken to the extreme, could potentially invalidate all DR participation at any compensation level in any wholesale market. The Maryland Public Service Commission and the Delaware Public Service Commission believe that if the ruling goes into effect it will have “significant adverse consequences” and may impact grid reliability and state statutory goals regarding peak load reduction.

Not all parties share the same dire view. Even some of the DR companies such as EnerNOC believe demand response is not going away and will remain a vital and important part of the country’s energy markets. The value of DR to consumers does not disappear as customers will continue to look for options to reduce energy costs and retain cost effectiveness for their businesses and residences.

What may change, however, are compensation levels, market rules, and regulation. Some experts believe this situation actually serves as an opportunity for all involved to collectively reboot the industry and establish a standardized set of rules that better meets everyone’s needs.

One of the intriguing elements of the Court of Appeals ruling was the determination that regulating DR falls under state purview since it is executed in the retail electric market. This sets up a situation where states can take the lead and establish consistent rules for demand response. This could include the creation of multi-state markets for DR.

Also many of the utilities operating in organized wholesale markets have established demand response tariffs in response to state mandates and other market considerations. There is at least a precedent for electric distribution utilities to step up and expand their existing programs.

Where do we go from here?
The response to the Court of Appeals’ decision has been swift. FERC made an appeal for the case to be re-heard in front of the full judiciary of the court instead of a three-judge panel. FERC is supported by a number of additional organizations requesting a re-hearing including the National Resources Defense Council; the Environmental Defense Fund; regional grid operators PJM and the California ISO; and various utility regulators and demand response aggregators.

PJM has joined FERC in seeking to reinstate FERC Order 745. PJM’s filing expresses its desire to maintain federal jurisdiction of demand response. By appealing for reinstatement, PJM preserves its options regarding relying on DR this summer. The RTO claims it has no practical alternative to replacing DR in the short term. For now, all demand response rules remain unchanged until such time that FERC issues a compliance order reflecting tariff changes. Ironically, PJM opposes FERC 745’s decision to mandate equal compensation for demand response but recognizes its importance to its operations.

It will be several weeks (at least) before the Court of Appeals decides whether to re-hear the case. The Court has a very limited history of agreeing to re-hear cases. If the Court declines, FERC could decide to take the matter to the U.S. Supreme Court.

Given the uncertainty of court appeals, there is a good chance that a final adjudication may be years away. In the meantime, it appears the states may need to step up to ensure that demand response remains a key wholesale supply resource.

References

  1. RTO Insider, PJM to Seek Rehearing on FERC Order 745. July 9, 2014.
  2. Utility Dive. Despite court setback, demand response is here to stay. Claire Cameron. July 17, 2014.
  3. Scott Hempling, Attorney at Law, C. Circuit Kills Demand Response Compensation: Now What? June 2014.
  4. NRDC Switchboard. D.C. Circuit: When It Comes to Demand Response, Please Think Twice, It’s Not Alright. July 9, 2014.
  5. Ener Comments on Circuit Court Decision on FERC Order 745, BOSTON, May 27, 2014.
  6. Forbes The Winners In FERC’s Demand Response Ruling: Batteries and Software, Not Utilities. May 24, 2014 @ 11:56AM.
  7. Pete Yost, Electric Light and Power. Court vacates FERC Order 745. May 27, 2014.
  8. Personal communications. Pete Langbein, PJM Interconnect, July 2014.
Posted in Electricity | Tagged , , | Leave a comment

Must States Step Up to Keep Demand Response Participating in Wholesale Markets? Part I

 By Matthew Rose, Enerdynamics Instructor

It’s been a busy few months in the nation’s capital with a number of notable decisions and policy changes that target the country’s electricity industry.US courthouse

Among the decisions causing great debate is the ruling from the United States Court of Appeals rescinding the Federal Energy Regulatory Commission’s (FERC) rules for demand response programs in organized wholesale markets. The concept of rewarding customers for strategically reducing consumption at various time periods for system reliability and economic benefits remains a work in progress, and it is coming under fire.

The general concept of demand response (DR) empowers customers to consciously reduce or change their consumption habits for reliability and economic benefits. By reducing demand, the grid’s need to secure new generation to meet load requirements is lessened and may provide a more cost-effective way of keeping the system in balance. There isn’t much debate around the general concept – but how demand response resources should be valued, priced, and regulated is controversial.

In this week’s article we discuss the FERC order that was rescinded; next week we will discuss implications of the Court’s decision.

FERC’s Role in Demand Response

FERC has actively promoted DR markets and rules for organized wholesale transmission organizations. Its efforts were initially evident in FERC Order 719, Wholesale Competition in Regions with Organized Electric Markets. The rule, passed in 2008, ordered operators in organized wholesale transmission markets to treat demand response bids from customers or aggregators on a comparable basis with conventional generator bids. It signaled the evolution of demand response as more than just a system reliability tool and began to position the resource as a broader economic option.

In an effort to provide greater detail, FERC issued Order 745 in March 2011. The Order came about after extensive debate and contention from various demand response stakeholders. A key outcome from the FERC order was the determination of how transmission organizations should value DR. The FERC ruled that DR had the same market value as a power plant and deserves to be commensurately compensated. According to FERC, DR resources should be paid the determined locational market price (LMP).

The FERC Order ended up in the U.S. Circuit Court as brought forward by the Electric Power Supply Association (EPSA) as petitioner. EPSA’s involvement reflects the view of many of the conventional generators who were finding it increasingly difficult to compete with demand response.

The U.S. Court of Appeals Decision

On May 23, the U.S. Court of Appeals for the D.C. circuit entirely vacated FERC’s Order 745. In a 2-1 decision, the Court disagreed with FERC’s justification for compensating demand response resources. In its decision, the Court noted that “FERC’s new rule goes too far, encroaching on the state’s exclusive jurisdiction to regulate the retail market.” The Court went on to say that FERC, by ordering compensation from demand response from retail customers, was overstepping its authority by regulating retail markets, (which is a power denied to FERC and reserved for the states).

The Court also argued that demand response is not actually a source of generation; it does not involve a direct sale to the wholesale market from consumers. Consumers participating in demand response were given preferential treatment by FERC, being paid full-market price (LMP) as well as saving the generation component of its retail rate. The Court indicated that this results in overpaying for the resource.

The EPSA position claims that the preferential treatment came at the expense of conventional generators who want to invest in new generation resources but lack the financial rationale or incentive (given the preference for DR resources). EPSA claimed policymakers were sending a signal to investors that you don’t need to build new generation – the load can be balanced using demand response resources.

It is important to note that the Court’s rescinding of FERC Order 745 does not disallow demand response resources from bidding in the market, but successful bidders will not receive the same compensation as resources bid by conventional generators.

Posted in Electricity | Tagged , , , , | 1 Comment

Solar and Distributed Generation: Utility Business Model Threat or Rate Design Problem?

By Bill Malcolm, Guest Author*

During the last two years, the utility industry has awoken to the role of solar and other forms of distributed generation and their impact on the utility business model. 488559339

At an Indiana Utilities Regulatory Commission forum, American Electric Power said the $18 million in solar subsidies annually in Arizona were shifting grid costs to other customers with solar not paying its fair share. Also this spring, one rating agency downgraded utilities over the distributed generation threat, noting that the cost of solar and storage for residential consumers of electricity is already competitive with the price of utility grid power in Hawaii. They predicted California, New York, and Arizona would be in a similar situation in a few years with other states soon to follow.

Some public service companies (PSCs) like Hawaii and New York are revamping their regulatory models. The New York PSC has proposed making utilities distribution system platform providers (the RTOs of the distribution system). Utilities would plan and operate the distribution grid – integrating distributed energy resources and providing a market where consumers can optimize their energy generation, management, and delivery options.

Not all are convinced solar is a huge game changer. An S&P spokesman said the matter was more a rate design issue (except in California and Hawaii). Similarly, a Williams Capital Group spokesman said the (utility industry) fundamentals had not changed.

Steeply inverted residential rates make solar particularly cost-effective in California. A former colleague put in solar on his rooftop in Palm Springs, and it keeps him in the (uber low) first tier of SCE’s inverted residential rate structure.

In Wisconsin, Madison Gas & Electric filed for a general rate case that included going to a $69/month fixed charge (from around $10 currently) by 2017 with a concomitant lowering of the variable energy charges in order to recover fixed costs up front and from all consumers including those who self-generate and don’t use much net power.

Other states are looking at imposing a monthly charge on solar users to recover grid costs that they say the facilities rely on for back up. Arizona allowed a $5 monthly fee for APS this year, and a new law in Oklahoma allows for a similar type charge (SB 1456). In Utah, the PSC is considering Rocky Mountain Power’s request for a $5-$6 monthly fee with a decision expected in late August. San Antonio is also considering such a charge.

In short, the solar movement appears to be driving, at a minimum, a second look at utility rate design and cost recovery mechanisms. And in some states, it’s driving a broader look at utility business models.

If you would like to learn more about these issues and how utilities are responding, join us in New York on October 6-7, 2014, for our class “Distributed Energy, Renewables, and Microgrids: How to Navigate the Utility Industry’s Biggest Threats.”

*About the Author
Bill Malcolm is a 37-year energy industry veteran who has worked for Seattle City Light, Pacific Power, PG&E, ANR Pipeline (now owned by TransCanada), and MISO. He currently is a freelance energy reporter and has a column in The Cruthirds Report (a Houston energy newsletter) on RTO and PSC matters. He holds a M.A. in economics from the University of Washington and a B.A. in economics from UC Santa Cruz. He also is a columnist in the Broad Ripple Gazette and has organized a new group, Hoosiers for Passenger Rail, in an attempt to save the daily Amtrak service from Indianapolis to Chicago.

Posted in Electricity, Renewables | Tagged , , , , | Leave a comment

A Look at PJM’s Capacity Auction Results

By Matthew Rose, Enerdynamics Instructor

Each year, the PJM Interconnection administers the Reliability Pricing Model (RPM) auction to ensure forecast electricity requirements for the PJM system three years in the future with prices established through competitive bidding. The auction reflects pricing from a range of available conventional supply sources: fossil fuel and nuclear plants competing with renewable energy, demand response (DR), and energy efficiency. The forward basis for the auction ensures long lead times for builders to complete asset construction or upgrades. This year’s auction concluded in May. Following is a look at results and how they caught many by surprise.

2017-2018 auction results

The just-completed auction procured 167,004 megawatts (MW), which includes a 19.7% reserve margin for the PJM RTO. The capacity clearing price for all resources throughout the entire RTO was $120 per megawatt-day. The exception is PSE&G‘s service area where prices came in at $215 per megawatt-day. The PSE&G location appears to be the only capacity-constrained area in the auction. This reflects a notable price increase over the prior year’s auction result and came as a surprise to many who had predicted lower prices.

The results also depict changes in the types of resources clearing the auction. As shown in Table 1, the auction includes a significant share of demand response resources as part of the cleared resource pool. A total of 10,975 MW of demand response was procured — a decrease of about 1,433 MW from last year’s auction.

However, there was a significant shift to the types of demand resources that have more flexibility and a greater contribution to reliability. There was an increase in PJM “annual” and “extended summer” demand resources clearing in this auction. This shift gives system operators more year-round flexibility when needed. PJM experienced the need for flexible demand response during recent extreme weather, both in September 2013 and January 2014. 

The shift to increased amounts of new natural gas-fired generation continues with roughly 4,800 MW of new combined-cycle generation clearing for the first time in this auction. Almost all of this cleared new capacity is located downstream of west-to-east transmission constraints or in areas with capacity needs.

Energy efficiency continues its growth trend in PJM’s capacity auctions. This year, a record 1,339 MW of energy efficiency was procured in the auction, an increase of 222 MW from last year’s auction.

The RTO estimate of $120 per megawatt-day continues the trend of widely divergent capacity prices over the past five years. As shown in the graph below, the cleared capacity price for 2017-2018 auction is dramatically higher than last year’s auction when it cleared at less than $60 per megawatt-day.

According to various financial forecasts and industry watchers there was a predisposed view that prices would remain depressed as a result of low natural gas prices and a slow economy with limited demand. The fact that the RTO price cleared $120 caught many by surprise.

We will have to wait until next year to see whether higher capacity prices are a trend or an anomaly.


 

References:

  • Bloomberg News, Electricity prices will rise to ensure U.S. power grid can meet long term demand, May 27, 2014PJM Press Release, PJM Capacity Market Secures New And Diverse Resources To Meet Future Electricity Demand, May 23, 2014
  • RTO Insider Capacity Prices Jump Following Rule Change, May 27, 2014
  • John Funk. PJM auction shows surge in gas-fired power plants on the way. Cleveland Plain Dealer, May 25, 2014
  • Julien-Dumoulin Smith, RPM Results The Power Trade Is Back. UBS Research Report, May 23, 2014
  • UBS Electric Utilities Global Research. Monitoring PJM’s Markets: A Discussion With the Market Monitor, June 2, 2014
  • UBS Electric Utilities Global Research. Lessons Learned From the Capacity Auction in PJM, June 2, 2014
  • PJM Interconnect. 2017/2018 RPM Base Residual Auction Results, May 23, 2014
Posted in Electricity | Tagged , , , , | Leave a comment

Gas Industry Must Make Changes to Reliably Serve the Electric Industry

by Bob Shively, Enerdynamics President and Lead Instructor 

The natural gas industry is on a long run of increasing sales to electric generators. Beginning with a wave of gas combined-cycle power plants built in the mid-1990s, gas usage by electric generators has doubled since 1997. 

In 2009 electric generation surpassed the industrial sector to become the largest gas customer segment. And the trend is likely to continue; the Energy Information Administration (EIA) forecasts that gas generation will make up nearly 60% of the new generation brought online in the next five years.[1]

But as growth continues, differences between how the electric and gas industries operate are becoming apparent and may become problematic if not addressed. These issues came to a head during and after the so-called Polar Vortex. Demand for heating gas shot up at the same time that electric systems dispatched gas-fired generation to meet rising electric demand. The result was skyrocketing gas prices that reached $120/MMBtu in some markets. In a few instances gas units were unable to run due to unavailability of supply.[2]

Gas generators and system operators attempting to dispatch gas generators discovered a number of disparities between the two industries’ business practices — disparities that at times caused difficulties. These include:

  • Pipelines and gas storage facilities are sized to fulfill firm contracts, not to meet projected loads. There is no centralized reliability planner for the gas system except at the local distribution company (LDC) level. So if generators don’t sign up for firm capacity on pipelines and/or storage, there may be no capacity available to serve their needs when everyone else is using the system.
  • Most gas business practices assume daily nominations with uniform hourly demand across the day. This is very different than electric scheduling, which is done hourly and even every five minutes during real-time scheduling. During most times this isn’t an issue as pipelines and LDCs have the flexibility to let generators take varying amounts of gas during the day. But during extreme conditions pipelines and LDCs may enforce tariff provisions that penalize customers for failing to take equal amounts each hour.
  • The gas scheduling day runs from 9 a.m. to 9 a.m. Central Time while the electric day runs from midnight to midnight. This results in generators needing to place gas nominations prior to knowing whether their units will be dispatched by the system operator.
  • The standard times for adjusting gas schedules during the operating day do not match well with typical times that electric system operators are ramping units to meet growing demand on their system.
  • Gas markets traditionally are open for trading only during the week, with weekend arrangements set up on Friday and treated as a two-day block.  This can clash with electric markets that function 24/7.
  • LDC tariff rules and system design practices are structured around the concept that large customers such as electric generators and industrial customers will be curtailed on peak demand days. This means that, on peak cold days when electric system operators are needing more supply to prevent electric shortages, LDCs may be preparing to curtail gas deliveries to any generators taking service off the LDC system.[3]

What’s next?

To deal with some of the scheduling issues, the Federal Energy Regulatory Commission (FERC) is attempting to work with the two industries to change gas rules.[4] But this is proving problematic as different stakeholders have very different viewpoints on what, if anything, should be done.[5]

Other issues must be handled through changes in contracting practices between gas market participants (including producers, marketers, pipelines, storage facilities, and LDCs) and electric generators. Many gas marketers as well as some pipelines and LDCs have expressed their desire to work with the electric industry to design new products that meet generators’ and system operators’ needs. If this can be managed in competitive business arrangements rather than through new regulatory rules, it is likely a win-win for all.

References:

[1] See http://www.eia.gov/electricity/annual/html/epa_04_05.html

[2] For a discussion of the issues on the PJM system, see http://www.ferc.gov/CalendarFiles/20140401084122-Kormos,%20PJM.pdf

[3] This can be a significant issue — for instance in PJM 49% of gas-fired generation is served off LDC systems.

[4] See http://www.ferc.gov/media/news-releases/2014/2014-1/03-20-14-M-1.asp#.U6SzJvldV8E

[5] See http://www.ferc.gov/legal/staff-reports/2014/06-19-14-gas-electric-cord-quarterly.pdf

 

Posted in Electricity, Natural Gas | Tagged , , , | Leave a comment

Distributed Energy and Shale Gas Among Key Topics of New Energy Seminars

by Enerdynamics Staff

Enerdynamics’ 2014 fall seminars are a good example of how we continually monitor industry change and adapt our product offerings to reflect such change. This year we have added two all-new seminars to our calendar, each of which tackles a significant trend that is shaping its respective industry. The new seminars are:

Distributed Energy, Renewables, and Microgrids:
How to Navigate the Utility Industry’s Biggest Threats
October 6-7, New York City

Given the surge in renewables, distributed resources (DR), and microgrids, many experts now say the traditional utility model is no longer sustainable. Some state entities like the California Public Utility Commission are already weaving DR, renewables, and microgrids into their future utility business models. Seminar participants will learn the technical, economic and regulatory details that define the threats and opportunities posed by DR, renewables, and microgrids and then will explore possible responses that can help successfully navigate an organization through them. Click for more details or to register for the October seminar.


Shale Gas and Natural Gas Liquids:
Has the Shale Revolution Made Natural Gas a Safe Bet?
October 8-9, New York City

Shale gas has already dramatically changed the fundamentals of the natural gas, electricity, and natural gas liquids (NGL) businesses. But how will its growing and evolving influence affect you and your business? And is the evolution secure enough to bet on natural gas far into the future? This seminar examines the technical, economic, environmental, and market details that will help prepare participants to identify and evaluate shale-related risks and opportunities. Click for more details or to register for the October seminar.

 As with every Enerdynamics seminar, these new seminars feature a casual, small group setting (no more than 30 attendees) and are designed with active participation in mind. Questions and discussion among attendees are highly encouraged. Attendees will participate in a number of individual and group exercises that provide a real-world perspective of the seminar’s core topics. Enerdynamics’ goal is to have every attendee leave its seminars with relevant and current information that can be applied immediately to his or her daily job.

For more information on other seminars or to have a seminar customized for your company and location, call 866-765-5432 or email jferrare@enerdynamics.com

Posted in Electricity, Energy Training, Natural Gas, Renewables | Tagged , , , , , | Leave a comment

Electric Vehicle Conference Highlights Automakers’ Newest Offerings

by Bill Malcolm*, guest author

Nationwide, growth of electric vehicles (EVs) is taking off. By 2025 it’s predicted there will be 3.5 million registered plug-in EVs (compared to the 215,000 on the road today). The Electric Drive Transportation Association’s (EDTA) annual conference was May 19-21 in Indianapolis and revealed some key developments and topics for discussion in the EV world.

A highlight of the conference was hearing from the various automakers about the new technologies and added services available to EV owners. These include:

  •  Nissan said its Leaf was the best-selling EV with 50,000 on U.S. roads today. It offers a charge card with free charging (restrictions apply) at many charging locations run by different companies. Nissan said 92% of Leaf households were new to the Nissan brand.
  • GM’s Chevy Volt can go gas-free for 38 miles and also has a gas tank. The daily charging cost is just $1.60 on average. Drivers average 900 miles between fill-ups. The Volt includes an OnStar Remote Link mobile application that alerts you when your charge is complete. GM said 84% of the charging is done at home, and 70% of the charging is “Level 1” (120 kV). The timing of when an EV is charged is also a hot topic. If EVs are charged in the middle of the night, for example, the vehicles could fill in the utility load valleys (i.e., at 3 a.m.). Utility programs are helping. GM said that in Michigan both major utilities ran a pilot program to incent customers to put 240 kV (Level 2 or faster) chargers in homes. Approximately 2,500 rebates per utility were available and they were all used up. 
  • Mitsubishi said EVs provided power after the Japanese earthquake. (This is known as vehicle-to-grid). 
  • Most exciting perhaps was the extended-range electric truck from VIA that gets 100 mpg, plugs in anywhere, and can export power to provide mobile emergency power to keep facilities on line at a job site or during an outage. This development is significant because it replaces a truck with relatively modest fuel economy (compared with an electric vehicle, which typically replaces a compact car that already gets decent fuel economy).

Also during the conference, Indianapolis Mayor Greg Ballard announced the city will change its fleet to plug-in hybrid EVs to save the city $8,000-$10,000 per year, per vehicle. Ballard also announced the new BlueIndy electric vehicle car share program in a partnership with Bollore Group of France. The cars can go 120 miles without being recharged. 

Note: This article was originally published in our Q2 issue of Energy Insider. Read the full article here including a discussion on what changes utility companies are making to help transition to a more EV-friendly future.

*About the author: Bill Malcolm is an Indianapolis-based energy and transit analyst who writes the Commission Corner and RTO Watch columns for The Cruthirds Report, a Houston-based energy newsletter. He has previously worked at PG&E, ANR Pipeline, and MISO. He can be reached at BillMalcolm@gmail.com.

Posted in Electricity | Tagged , , , | Leave a comment