What You Thought You Knew About the Electricity Business May Not Be True

by Bob Shively, Enerdynamics President and Lead Instructor 

The electric utility system has been relatively stable for a long time – longer than the careers of even the oldest in the business. That means it is easy to think that once you get a bit of experience and learning, you have things figured out. But lately, that assumption482469921 might be getting turned on its head. Here are few things that we’ve always “known” that may no longer be true.

  1. More renewable energy means less reliability
    Perhaps surprising to many, initial sets of data analyzing SAIDI (System Average Interruption Duration Index) indicates that Germany has maintained a high level of performance despite growing to more than 25% renewables in its power mix. More details.
  2. The utility business always changes very slowly

    Those of us who have been in the industry for a long time know that ideas frequently arise many years before they actually get implemented. It is simply part of the regulated way of doing business. So any discussions of the “utility of the future” must be just that, discussions about what might happen in another decade or so.  Except that regulators in Hawaii and New York are already holding proceedings that will likely result in radically different utility business models in the next few years. Listen to this NPR report for an example.

  3. The only way to economically store electricity is through hydro-pumped storage

    Yes, batteries and flywheels and other technologies have been around awhile, but other than for emergency backup, there just isn’t an economic case to be made for installing electric storage. In most cases that is still true today, but again, this might change soon. Tesla Motors is preparing to build a huge lithium ion battery factory in Nevada. Many believe they are significantly overbuilding for what is needed for car batteries (click here for an example). But this could lead to the price of batteries falling significantly as over-capacity floods the market. This is what happened to drive down the cost solar photovoltaic systems. And Tom Werner, CEO of SunPower recently stated “2014 for batteries feels a lot like 2003 in solar.”

There are other assumptions we might tackle in the future but this is a good start for one post. If you’d like to explore these and more, please join me in New York City, October 6-7, 2014,  for our Distributed Energy, Renewables and Microgrids seminar. And if you are interested hurry because the early bird discount that saves you $200 ends September 15.

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Supply, Demand, and the Weather: More Reasons for Low Natural Gas Prices

by Christina Nagy-McKenna, Enerdynamics Instructor

Our last post explored the unexpectedly robust increase in natural gas storage inventories after the severe winter of 2013-2014 and aggressive restoration’s roll in tamping down on the forward prices for natural gas.weather forecast

However, the higher-than-expected level of inventories is not the only reason that the market has been cautious about the upcoming fall and winter. Demand is sluggish among end users due to mild summer weather while natural gas supplies are growing with shale production in certain areas hitting all-time highs. This week’s discussion takes a closer look at these factors…

“Weather” or not
As high tech as the natural gas industry has become, there is one aspect of the business that the industry can neither escape nor influence: Customer demand is largely driven by the weather for non-industrial end users. The mild summer in parts of the U.S. this year has meant that power plants are burning less natural gas since end users are not using their air conditioning equipment as often as the industry would expect. For example:

  • For the week of August 13, the Energy Information Administration (EIA) reported that U.S. demand for natural gas had declined by .2% mostly due to the electric power sector decreasing its usage by 6.1% compared to the previous year.
  • The week of August 20, the EIA again reported a .2% decline in usage, as the power sector decreased its usage by 1.3% over the same week in 2013. Ironically, the EIA believes that some customers in the Pacific Northwest may have actually begun heating their homes that week due to the cold temperatures.

Shale leads supply increase
While demand has been stagnant this summer, supplies have grown. The data below shows the percentage changes of this past week as compared to the same week in 2013. While the data only represents one week, the results are consistent with the numbers the industry has seen all summer.

supply chart 1

Shale gas production continues to lead the supply increase. Marcellus area production hit an all-time high in July 2014 as it exceeded 15Bcf/d for the first time. Already the largest shale producing region in the U.S. with 40% of all shale production, Marcellus is expected to continue its growth. By September the EIA estimates that Marcellus will produce 15.8Bcf/d. And now, Marcellus has a fast-growing neighbor in eastern Ohio: the Utica Shale.

Utica region               Today in Energy, August 12, 2014, U.S. Energy Information Administration


As of August 12, 2014, EIA now includes Utica’s production in its monthly drilling productivity report. Utica earned this distinction by becoming one of the fastest growing production areas for natural gas in the U.S. The EIA estimates that Utica will produce 1.3Bcf/d of natural gas next month. Current production puts its growth rate on par with the Eagle Ford Region of Texas. Industry experts attribute Utica’s growth to a modest increase in the number of rigs in the area as well as increased production per well as producers have become much more efficient drilling in shale formations.

What it all means…maybe
All of these factors – increased supply, lower-than-expected demand due to cooler weather, and rapidly increasing storage reservoirs – add up to lower spot market and forward-looking prices as compared to what was expected by the industry following the harsh winter of 2013-2014. The table below shows spot market prices for the weeks ending August 6 and August 27, 2014, as well as September and October futures contracts for the same weeks. Even though we are three weeks closer to the beginning of the winter season, the numbers for each category has increased very modestly since the beginning of the month.

spot prices chart 1

Additionally, prices in the northeastern U.S. have traded below Henry Hub prices since the spring. The basis differential between these two regions has historically favored Henry Hub, however, this paradigm is changing as Marcellus shale gas production, increased gas processing, and greater gas transportation have changed the region profoundly. Eventually, as winter demand in the Northeast increases, the basis differential is expected to reverse, at least through the following winter.

As we wait to see how the market responds as the seasons move forward, the great unknown remains the weather. It is possible that despite the herculean effort to restore gas storage inventories, a cold winter could simply draw them down again and gas prices would increase substantially. If the winter is mild, it is possible that spot and forward market gains will be measured, but not grand. Until then, we expect to see more of what we have seen so far this summer – modest gains and losses for the next couple of weeks as long as temperature changes are slight, followed eventually by higher prices as the storage injection season closes and winter shows up on our doorsteps.



“Marcellus Shale Gas Production Hits New Milestone,” Cusick, Marie, August 5, 2014, State Impact Pennsylvania.

“Natural Gas Slides in Cool Weather,” Berthelsen, Christian, The Wall Street Journal, August 18, 2014.

“Natural Gas Weekly Update,” August 28, 2014, US Energy Information Administration.

“Natural Gas Weekly Update,” August 21, 2014, US Energy Information Administration.

“Natural Gas Weekly Update,” August 14, 2014, US Energy Information Administration.

“Natural Gas Weekly Update,” August 7, 2014, US Energy Information Administration.

“Natural Gas Weekly Update,” August 22, 2013, US Energy Information Administration.

“Northeast August Basis Cools While Autumn Refuses to Fall,” Bradley, David, NGI Forward Look, July 23, 2014.

“Summertime Living Isn’t Easy for Gas Bulls,” Denning, Liam, The Wall St. Journal, August 18, 2014

“Utica Production Surged in Last Two Years: EIA,” Ritenbaugh, Stephanie, Pittsburgh Post-Gazette.

“Why Natural Gas Was All Over the Place after the EIA Inventory Release,” Parts 1 and 2. Chamberlin, Alex, August 25, 2014, Market Realist.

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Mild Weather, Aggressive Storage Injections Keep Natural Gas Prices Low

by Christina Nagy-McKenna, Enerdynamics Instructor

Earlier this year many Americans broadened their vocabulary with a term that flanked the Northeast in record-low temperatures: the ‘polar vortex.’ Gas traders associated the termpolar vortex with higher natural gas prices. Gas storage owners associated the term with greater demand as they watched inventory levels dwindle to 857 Bcf, the lowest level since 2003 and approximately 55% lower than the five-year average.[1] Lastly, gas customers associated the term with bitter-cold conditions that drove them to heat their homes and businesses into April.

The polar vortex itself is a constant circulation of upper-level winds that encircle the North and South Poles. Under normal conditions, frigid air is contained at the poles by the constantly strong winds. If the winds slow down, however, cold air escapes, and in the case of the North Pole, the frosty jet stream heads south. Such distortions of the polar vortex occurred in early December 2013 and the first week of January 2014, and it brought with it arctic air from the North Pole.

For the natural gas industry, the record cold temperatures fanning out from the Northeast across to the Midwest and down to the Southeast brought a boon of price increases, high demand by customers, and a dramatic reduction in gas storage inventories. Reduced storage inventory pays dividends to the market, as the gas must be replaced in preparation for the following winter.

Storage levels were so depleted this past season that the Energy Information Administration forecast that storage customers would be unable to restore their inventories to pre-winter 2013-2014 levels. Thus the market was bullish that natural gas prices and forward-looking financial contracts would all increase strongly this fall and continue their upswing into the winter, especially on the East Coast.

2014 Gas Storage Inventories (Bcf)

2014 gas storage inventories

However, cooler than normal August temperatures, a warmer than normal fall forecast for the East Coast, higher than average storage injections, and robust gas production have conspired to keep both spot and forward-looking natural gas prices for the East Coast lower than expected, while the remainder of the country has seen only small increases. For example, spot prices as reported by NGI at Henry Hub, Chicago, and California were all flat for the past week. However, they were all relatively close to 2013 prices for the same time period.  The New York price, however, is vastly lower, as can be seen below.

 Comparison of 2013 and 2014 August Spot Market Prices

comparison of 2013 to 2014 August spot market prices

In the meantime, natural gas storage is filling up fast. Between the week ending April 25, 2014, and the week ending July 4, 2014, net injections into storage had reached 1.04 Tcf.[1]  Not since 2003 did storage inventories reach the trillion cubic foot level so quickly. The cooler than normal temperatures are making this rapid inventory acceleration possible as gas that normally would be used to generate power and run end-users’ air conditioners is instead flowing into storage fields.

The EIA is currently forecasting 3,463 Bcf as the final gas storage inventory ending October 31, 2014, the terminus of the injection season.[2] Thus, storage inventories will indeed be short of historical levels, but they will just reach 90%. It is also possible for storage injections to continue past November 1 as long as storage customers are not scheduling net withdrawals.

This week the impact of the storage injections on forward prices was very clear, as shortly after the EIA storage report was released for the week ending August 20, 2014, the NYMEX September natural gas futures contract fell to $3.81/MMBtu, a decline of 7 cents.[3]

Next week we will continue our look at the upcoming fall and winter seasons’ natural gas price forecasts with a focus on the impact of increased supply from both dry gas and shale gas.


[1] “Natural Gas Injection Season Continues on Pace for Record Refill,” U.S. Energy Information Administration, July 28, 2014.

[2] Ibid

[3] Natural Gas Weekly Update, August 20, 2014, US Energy Information Administration

“Northeast August Basis Cools While Autumn Refuses to Fall,” Bradley, David, NGI         Forward Look, July 23, 2014.

“Summertime Living Isn’t Easy for Gas Bulls,” Denning, Liam, The Wall St. Journal, August 18, 2014

“Natural Gas Slides in Cool Weather,” Berthelsen, Christian, The Wall St. Journal, August 18, 2014

“Frigid Air from the North Pole:  What’s This Polar Vortex?” Duke, Alan, CNN, January, 6, 2014.

“EIA Expects Working Gas Stocks Will Reach 3463 Bcf at the End of October,” Short-Term Energy Outlook Monthly Report, July 2014, US Energy Information Administration.

EIA Weekly Gas Storage Report for the Week Ending August 15, 2014, US Energy Information Administration

Natural Gas Weekly Update, August 21, 2014, US Energy Information Administration

Natural Gas Weekly Update, August 14, 2014, US Energy Information Administration

Natural Gas Weekly Update, August 22, 2013, US Energy Information Administration







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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.


  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.
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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.

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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.

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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.



  • 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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