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
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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

 

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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

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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.

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Utility Commissions Speak on the Future of the Utility: Microgrids in California, Part II

by Bob Shively, Enerdynamics President and Lead Instructor

Last week’s post on Energy Currents introduced discussion of a whitepaper written by the California Public Utilities Commission (CPUC) Policy and Planning Division titled Microgrids: A Regulatory Policy. In that Microgridpost we examined the CPUC staff’s vision for what microgrids will become and the benefits that may result. It was noted, however, that multiple regulatory and business barriers impede the development of microgrids.

In Part II of this discussion we explore what the CPUC paper has to say about such barriers.

 

Barriers to microgrid development
The CPUC paper notes numerous regulatory and business barriers to emergence of Advanced Microgrids.  These include:

  •  The legal definition of a “public utility” and an “electrical corporation”:  These definitions make it difficult or prohibitive for distributed energy resources (DER) within a microgrid to sell power directly to other customers since utility distribution companies are monopolies.
  • Interconnection rules: Distribution interconnection rules in California are currently not designed to recognize interconnection of a microgrid, meaning that all microgrids must currently be handled as special cases requiring approval of the distribution utility. This most likely means a costly distribution engineering interconnection study and also means that the utility is put in the role of “gatekeeper” in determining when microgrids are approved.
  • Concerns about islanding and other safety issues: Utilities are concerned about the safety of having portions of the distribution grid islanded and energized while the surrounding grid is experiencing an outage. This potentially could result in areas of the grid becoming energized without utility workers being aware of it. And under normal interconnected operations, failure of microgrid operators to run their system safely, reliably, or securely may negatively impact the wider distribution grid.
  • Rate issues: Current bundled rates include charges to cover transmission, distribution, and power procurement. While current regulation eliminates these costs for solar power net-metered customers, there is no similar mechanism for microgrid customers.  Instead, microgrid customers are likely required to pay standby and/or departing load charges. Under current rate structures there is no mechanism for microgrid customers to “net-out” or otherwise be paid for the benefits they provide to the system. Also, there are issues with equity for non-microgrid customers who may end up paying more fixed costs of the system as microgrids reduce utility revenues from customers located behind the microgrid.
  • Lack of mechanisms to encourage microgrid development in optimal locations: The value of microgrids to the greater distribution system is highly site specific. For instance, a microgrid in an optimal location might allow a utility to cost-effectively address congestion, grid balancing, or reliability issues without costly distribution upgrades. But no mechanism exists to identify such locations or to reward customers for locating microgrids in optimal locations.
  • Uncertain impacts on the utility revenue model: The current utility regulatory compact may not mesh well with development of microgrids. Utilities’ revenues may decline and/or utilities may be required to spend money upgrading the distribution system without certainty of revenue recovery. And development of microgrids may threaten utility monopoly control of the distribution grid.

The role of state regulation in microgrid development
The CPUC paper identified numerous ways that state regulators might adapt regulation to foster the development of microgrids. These include:

  • Requiring utilities to perform a comprehensive system survey identifying optimal microgrid locations and providing streamlined approvals for microgrids at these locations
  • Developing standardized interconnection rules
  • Transforming the role of utilities into a distribution system operator (DSO) focused on accepting and delivering power from behind the meter as well as from the bulk transmission grid
  • Establishing market mechanisms to collect and allocate revenues to compensate third parties for the benefits that microgrids provide
  • Developing procedures to certify third-party microgrid operators to ensure safety, reliability, security, and environmental compliance
  • Revamping regulations to allow utilities to own and/or operate microgrids

As stated in Part I of this discussion, the CPUC paper was prepared by the CPUC staff, and it is explicitly stated that the paper has neither been approved nor disapproved by the CPUC. So the CPUC may or may not decide to pursue some or all of the regulatory initiatives identified. However, it appears likely that the CPUC will closely consider what it needs to do to assist consumers in California from obtaining benefits of microgrids.

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Utility Commissions Speak on the Future of the Utility: Microgrids in California, Part I

by Bob Shively, Enerdynamics President and Lead Instructor

In May, we began exploring what state regulators are thinking about the future of the utility. We started by discussing the vision laid out by the Public Utilities Commission of binocularsHawaii.[1] This month we will explore a perspective on microgrids laid out by the Policy and Planning Division of the California Public Utilities Commission (CPUC).[2]

Unlike the vision from Hawaii, it should be noted that the CPUC paper was prepared by the CPUC staff, and it is explicitly stated that the paper has neither been approved nor disapproved by the CPUC. However, it is a good overview of many of the issues that regulators will need to consider in addressing development of microgrids.

What Is a Microgrid?

In defining a microgrid, the CPUC paper uses a definition from the U.S. Department of Energy:

“A group of interconnected loads and distributed energy resources (DER) with clearly defined electric boundaries that acts as a single controllable entity with respect to the grid [and can] connect and disconnect from the grid to enable it to operate in both grid-connected or island [disconnected from the grid] mode.”

So key aspects of a microgrid include:

  • Interconnected loads and DER
  • Defined electric boundaries
  • A single controllable entity
  • Ability to operate connected to the grid, or isolated from the grid

While under this definition a microgrid could serve a single customer, the CPUC paper focuses on what they call an Advanced Microgrid. This includes multiple customers, multiple DERs, resources interconnected on both the customer side and the grid side of the meter, capability to provide grid services, and use of existing distribution infrastructure as well as new dedicated distribution infrastructure.

According to a recent study by Sandia Labs, such Advanced Microgrids are currently evolving from <1 MW in size each to 2 to 10 MW. And in future years individual microgrid projects may become as large as 60 to 100 MW, which is equivalent in size to a small utility generator.[3]

A Simple Microgrid

microgrid diagram

 

The Benefits of Microgrids

The CPUC paper notes multiple potential benefits associated with microgrids:

  • Provision of high levels of reliability (the ability to avoid outages) and resilience (the ability to quickly recover from outages)
  • Management of local intermittency of renewable resources such as solar and wind
  • Provision of grid resources including dispatchable energy resources, ancillary services such as voltage support, local load shedding resources, and storage or load to absorb over-generation
  • Opportunities to avoid costly transmission or distribution upgrades
  • Financial benefits for customers

However, attainment of these benefits is not guaranteed as multiple regulatory and business barriers impede the development of microgrids. In next week’s blog we will explore what the CPUC paper has to say about these.

References:

[1] See http://blog.enerdynamics.com/2014/05/22/utility-commissions-speak-on-the-future-of-the-utility-a-new-type-of-regulation-for-hawaii/

[2] For a copy see: http://www.cpuc.ca.gov/NR/rdonlyres/01ECA296-5E7F-4C23-8570-1EFF2DC0F278/0/PPDMicrogridPaper414.pdf

[3] See http://nyssmartgrid.com/wp-content/uploads/The-Advanced-Microgrid_Integration-and-Interoperability-Final.pdf, p. 11

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What Exactly Will the EPA’s Clean Power Plan Do to Regulate Carbon Emissions?

by Bob Shively, Enerdynamics President and Lead Instructor

On June 2, 2014, the EPA released its Clean Power Plan proposal that, if implemented, willsun rising from smog for the first time regulate carbon dioxide (CO2) emissions from existing power plants at the U.S. federal level[1].  The proposal was released after many years of Congress failing to act on greenhouse gas regulations.

Reactions from various interest groups were predictable, ranging from dramatically negative to middle of the road to highly supportive. But most of the articles and opinion columns describe the proposed rule in a vague manner. And only a few make it clear that these are proposed regulations that are subject to comment and discussion before a proposed finalization date of June 2015. In simple terms, let’s look at what EPA is proposing[2].

The EPA proposed rule would do two things:

  1. Create state-by-state carbon emission goals: These goals are defined in terms of pounds of emissions per MWh of output and are based on each state’s historic generation mix. Thus goals for states with higher historic levels of carbon-based generation are set at less stringent levels than those for other states. The table from the EPA website[3] showing each state’s pound/MWh goal is at the end of this blog. If they wish, states are allowed to convert the rate-based goal (pounds of emissions/MWh) into a flat mass-based goal (pounds of emissions).
  2. Define a process for each state to develop plans to achieve the goals: Rather than defining power plant specific regulations or mandating how states must achieve their goals, the EPA proposed process is designed to be flexible to allow each state to develop its own program. States may develop their own individual plans or may work together to develop regional multi-state plans.

Plans are due June 2016, but some final plans can be delayed until June 2018. Although final goals are expected to be achieved by 2030, the plans must include interim goals for 2020-2029.  Plans should be designed to utilize the “best system of emission reductions” using a portfolio approach of multiple strategies. EPA expects that strategies will include four “building blocks.” These are improving operations at existing fossil power plants by improving power plant efficiency, increasing dispatch of lower emitting fossil units such as combined-cycle gas turbines, increasing dispatch of renewables and nuclear power, and use of demand-side energy efficiency programs that reduce the overall need for generation.

States may also utilize programs such as carbon trading mechanisms that allow regions to work across state lines to achieve shared reductions. Lastly, if states fail to submit a plan that is approved by EPA, then EPA can develop its own plan for those states.

Since this article is focused on what the rule says, we will save the topic of impacts of the proposed rules for a later date. Furthermore, no one can really say what the impacts will be since we don’t know how the market will respond. Nor do we know how the rule may be modified before it is finalized.

History tells us that costs of implementation will be real but will be a lot lower than the worst-case scenarios. Indeed, in the first 15 years of SO2 and NOx regulation under the Clean Air Act, inflation-adjusted electric rates fell by about 18% while SO2 emissions fell by over 30% and NOx emissions fell by over 40%. Some believe that carbon regulation is different since there is no market-ready emissions control technology that can be added to coal units, but I would caution against thinking that the electric industry cannot figure out how to reduce carbon emissions without bankrupting customers.

EPA State Goals:

State
2012
Emissions
(million metric tons)
2012 Energy Output
(TWh)
2012 Emission Rate
(Fossil, Renewable,
and 6% Nuclear)  (lbs/MWh)
2030 State Goal (lbs/MWh)
Alabama
68.56
104.64
1,444
1,059
Alaska
1.96
3.20
1,351
1,003
Arizona
36.71
55.69
1,453
702
Arkansas
36.23
48.70
1,640
910
California
43.73
138.04
698
537
Colorado
38.45
49.45
1,714
1,108
Connecticut
6.04
17.40
765
540
Delaware
4.36
7.79
1,234
841
Florida
107.60
197.60
1,200
740
Georgia
57.02
83.80
1,500
834
Hawaii
4.73
6.77
1,540
1,306
Idaho
0.64
4.15
339
228
Illinois
87.19
101.44
1,895
1,271
Indiana
91.78
105.23
1,923
1,531
Iowa
34.67
49.26
1,552
1,301
Kansas
31.16
35.41
1,940
1,499
Kentucky
82.89
84.69
2,158
1,763
Louisiana
44.52
66.97
1,466
883
Maine
1.63
8.21
437
378
Maryland
18.30
21.57
1,870
1,187
Massachusetts
11.91
28.40
925
576
Michigan
63.38
82.40
1,696
1,161
Minnesota
25.42
38.13
1,470
873
Mississippi
23.50
45.86
1,130
692
Missouri
70.93
79.64
1,963
1,544
Montana
16.26
15.97
2,245
1,771
Nebraska
24.64
27.04
2,009
1,479
Nevada
14.05
31.36
988
647
New Hampshire
4.21
10.26
905
486
New Jersey
11.83
27.98
932
531
New Mexico
15.73
21.87
1,586
1,048
New York
31.58
70.85
983
549
North Carolina
53.13
71.17
1,646
992
North Dakota
30.27
33.47
1,994
1,783
Ohio
92.86
110.65
1,850
1,338
Oklahoma
47.86
76.07
1,387
895
Oregon
6.96
21.40
717
372
Pennsylvania
105.83
151.46
1,540
1,052
Rhode Island
3.39
8.24
907
782
South Carolina
32.57
45.23
1,587
772
South Dakota
3.02
5.86
1,135
741
Tennessee
37.41
43.33
1,903
1,163
Texas
223.15
378.96
1,298
791
Utah
27.96
34.00
1,813
1,322
Virginia
24.83
42.20
1,297
810
Washington
6.68
19.30
763
215
West Virginia
65.61
71.64
2,019
1,620
Wisconsin
38.39
46.33
1,827
1,203
Wyoming
45.36
47.28
2,115
1,714

References:

[1] Some states including California and the Regional Greenhouse Gas Initiative (RGGI) states of Connecticut, Delaware, Maine, Maryland, Massachusetts, New Hampshire, New York, Rhode Island and Vermont already regulate CO2 emissions at the state level, and other states have implemented policies such as Colorado’s Clean-Air Clean Jobs Act to reduce emissions through state energy policies.

[2] To read details of the proposed rule, see the EPA document Carbon Pollution Emission Guidelines for Existing Stationary Sources: Electric Utility Generating Units available at http://www2.epa.gov/sites/production/files/2014-05/documents/20140602proposal-cleanpowerplan.pdf

[3] Available at http://www2.epa.gov/carbon-pollution-standards/where-you-live

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