ISOs/RTOs Operate in Secret, Take Care of their Own

Larry Shapiro at IEEFA has an excellent new post on the secretive cartels that control who can connect to the US electrical grid, how much we pay for our electricity, and who gets energy and who doesn’t.  Readers of The Power Line know how I feel about PJM Interconnection.

Here’s what Mr. Shapiro says:

A fact little known to most Americans is that the grid they rely on for electricity is controlled by quasi-public organizations whose lavishly paid executives and board members conduct business in deep secret.

Independent system operators, or ISOs, work almost entirely behind closed doors, even though their every action affects public electricity customers of all stripes—residential, business and public sector.

I call them quasi-public because so much of what they do so profoundly affects the utility-consuming public, even as their corporate structure and inner workings are shrouded in mystery. ISOs in effect are public agencies exempt from public scrutiny—and, as a sadly predictable result, quasi-public corporations gone wild.

A little background: ISOs run the electric grid region by region across the United States. Some cross state lines. Those include PJM (whose initials are derived from its footprint: Pennsylvania-New Jersey-Maryland) and MISO (Midcontinent Independent System Operator: 11 Midwestern states and part of Canada). Others, such as NYISO, the New York Independent System Operator, are confined to one state.

The Federal Energy Regulatory Commission (FERC) mandates that each ISO ensures that enough electricity is generated across the grid to avoid blackouts. FERC also charges each ISO with making sure electricity is fed into the grid at competitive prices and that the appropriate power-generation mix is in place.

Who knows, though, if any of this is happening?

Who knows, indeed.

Before Enron-backed laws were passed by the US Congress deregulating the US electrical system, all power companies were confined to operate within single states.  State regulators had direct access to all of the vertically integrated power companies they regulated.  Because these companies were monopolies and had no competitors, there was no reason for hiding this information from the public.

Now, claiming confidentiality of competitive secrets, power companies and RTOs/ISOs hide all their internal documents from public scrutiny.  Also, because all power company business is done in fragmented “markets” ISOs have grown huge bureaucracies of lawyers, engineers and paper shufflers to oversee the complex mess.

And as Mr. Shapiro points out, these bureaucrats don’t come cheap:

NYISO’s tax filings—which by law are public because the organization positions itself as a tax-exempt nonprofit—hint at just how well the people who control ISOs are compensated. According to the NYISO’s 2013 tax return, Stephen G. Whitley, its president and CEO, was paid $1,804,749 that year. I’m not saying Whitley didn’t deserve that much. His is specialized work and his average workweek was said to be 60 hours. It’s still a lot of money. The members of the NYISO’s part-time board of directors also did okay. For working a reported 12 to 16 hours per week, they took home from $55,167 to $156,500 in 2013. Nice work if you can get it.

Add to these very good personal payouts the fact that board members choose their board cronies—without public review—whenever there’s an opening, and you have a system that ensures perpetuation.

All these salaries are passed on to rate payers.

PJM Cartel Getting Cartelier

Remember this post, What Is PJM, back in 2009?  Here is the dictionary definition of a cartel that I provided in that post:

cartel -2 : a combination of independent commercial or industrial enterprises designed to limit competition or fix prices

Now, click on this link to RTO Insider’s new post “DOJ Probing Interconnection Process in Exelon-Pepco Merger”.  This story is about the US Justice Department’s anti-trust investigation of PJM.

RTO Insider starts with this great graphic:


So we see that if the Exelon/Pepco merger goes through, the holding companies that control the big generators in the MAAC interconnection queue will fall from five to four.

The Justice Department is investigating how holding companies in PJM’s MAAC sub-region (essentially the Mid-Atlantic states from NJ to MD) use their ownership of both transmission systems and generating plants to create difficulties for their competitors who are seeking to build new generation in the MAAC sub-region.  Transmission owners control the requirements for interconnection with new plants.  The big five (maybe soon to be big four) use this power to limit competition in the MAAC sub-region.

RTO Insider points to PJM Market Monitor Joe Bowring’s past objections to this situation:

Market Monitor Joe Bowring declined to comment yesterday on the department’s inquiry. But the Monitor has been recommending since 2013 that PJM outsource interconnection studies to an independent party to avoid potential conflicts of interest.

“Currently, these studies are performed by incumbent transmission owners under PJM’s direction. This creates potential conflicts of interest, particularly when transmission owners are vertically integrated and the owner of transmission also owns generation,” the Monitor said in the third-quarter report.

“There is also a potential conflict of interest when the transmission owner evaluates the interconnection requirements of new generation which is part of the same company,” the report added.

Go back and look at that definition of “cartel.” Did you catch the phrase “designed to limit competition”?  That’s what this is all about.

I think it is hilarious that Joe Bowring refers to these practices as “potential” conflicts of interest.  Potential?  They have been going on for years, ever since PJM and other regional transmission organizations arose from the ashes of deregulation, with FERC’s blessing.

Speaking of FERC, the Justice Department’s investigation began just five days after FERC announced that it approved the Exelon/Pepco merger.

In its Nov. 20 order, FERC indicated it did not have any anticompetitive concerns with the Pepco acquisition. (See FERC Approves Exelon-Pepco Merger.)

Dismissing concerns of market power, possible rate climbs and suppressed competition, the commission approved the pending acquisition without discussion. Its written decision made clear it didn’t see any market issues with the acquisition, in part because Pepco holds only a negligible amount of generation. “While the commission is aware that Exelon will be a member with more assets after the merger, there is nothing in the record of this proceeding to indicate Exelon will have excessive influence over the stakeholder process or the independence of PJM.”

In other words, FERC said, “Nothing to see here, just keep moving.”  The Justice Department apparently thought otherwise.

The Justice Department investigation is a big deal, and could throw a real monkey wrench in Exelon’s attempt to swallow Pepco.

This situation is the flip side of what happened in the PJM transmission line fiascos like PATH and TrAIL: PJM’s transmission planners colluded with big generators (AEP and FirstEnergy) to rig new transmission projects to serve those generators existing power plants.  Cartels are truly wonderful things, if you are a member of one.

Hats off to RTO Insider’s great coverage of more PJM fakery.

PJM Overreacting, Again

PJM Interconnection has again gone after a tack with a pile driver, in the words of reliability expert George Loehr.  In January 2014, PJM got caught short on capacity during a few cold snaps as coal piles froze and pipes burst at coal plants and natural gas providers broke contracts with gas power plants to sell on the higher profit heating markets.

Instead of simply dealing with capacity issues during winter peak, PJM’s bureaucrats decided to do a complete overhaul of their entire capacity system.  Remember that before the artificial “market” system created by deregulation, all capacity situations were handled by state PSCs which simply told the vertically integrated power companies within their jurisdictions how much reserve they needed and how much capacity investment they were allowed to pass on to their customers.  States controlled the whole shebang because power companies couldn’t operate outside state boundaries, except in rare cases.

Now that deregulation has ushered in the new era of energy speculation and artificial capacity markets, power companies use their positions in regional transmission organizations to jack up costs for their customers.  Bureaucracy, jargon and obfuscation are the tools that power companies to hide what is going on in their RTO cartels.

Whenever the PJM cartel wants to make a big change, it generates a smokescreen by inviting comments from “stakeholders.”  In the latest capacity market overhaul, 14 stakeholder lobbyist coalitions have formed to push various modifications to PJM’s proposal.

The coalitions give you a good picture of how the PJM cartel works.  RTO Insider has a good summary of the coalitions and their positions.  I won’t pick apart who stands where on all the issues.  You can do that for yourself.  I will say the positions are not surprising if you know anything about the backgrounds of the companies and organizations and agencies listed.

You should note that state public service commissions, which once controlled the capacity process, are now only one part of what is described as the “Consumer Coalition.” That gives you a good picture of how federal legislation in the 1980s and 1990s wrecked the old system.

The Consumer Coalition gets it right:

The group called the proposal “a far-reaching overhaul of the PJM capacity construct that is far too costly and not justified in its current form.”

“The Consumer Coalition believes the abrupt overhaul contemplated by the CP Updated Proposal, as currently constructed, will adversely affect consumers by sharply increasing the cost of capacity with questionable additional reliability benefits and further restricting demand-side participation. PJM staff has failed to show that such drastic changes are warranted or, if warranted, that these changes are the correct changes. Adding to the Consumer Coalition’s concerns is the extremely short timeframe that has greatly limited the opportunity for stakeholder review.”

The Transition Coalition echoes this point that the total overhaul of the PJM is too much, too fast, and for too high a price for customers:

The coalition said the proposal would impose $7.9 billion in additional costs to load for delivery years 2016/17 and 2017/18, providing a windfall to generators that cleared auctions for those years and already qualify as CP resources or have already taken steps to improve performance since the winter.

It said the proposal would violate FERC’s order on ISO-NE’s winter incentives, in which the commission said additional payments should not be made “to incent resources to make the same fuel procurement decisions they would have made, and been compensated for, absent the program.”

The coalition also said implementing all of the proposed changes in time for the 2015 Base Residual Auction was too rushed.

The group proposed spending $200 million to $600 million for winter-only improvements.

“PJM has not demonstrated that Capacity Performance would have a material impact on system operations during the Transition Delivery Years,” the group said. “PJM has not presented any evidence showing how paying more to resources that already have capacity obligations (many of which meet the Capacity Performance requirements) will translate into increased security in its control room.”

In addition to these objections, other coalitions point out that PJM’s plans would also eliminate a lot of renewable power, energy efficiency and demand management resources from PJM’s capacity markets.  Is this a coincidence?  Of course not.  The big nuke and coal generators that control PJM have finally found a crisis that they can use to their advantage to do what they have been trying to do for years.

Here is a graph from PJM’s own report on the capacity shortage during the first January 2014 cold spell:

screenshot-pjm com 2014-11-02 09-45-59 copyThis pattern was largely repeated on January 24 and January 28, when more cold weather hit the PJM region.

So the problem was with delivery of capacity by the coal and natural gas generators during a winter peak that PJM’s own report claims was a once in ten year occurrence.  Yet PJM wants to overhaul everything and give more bonuses to coal-fired generators, who already demonstrated they couldn’t make the grade.

And what about renewable power?  Here’s the answer to that one

Most directly, wind energy provided highly valuable electricity when PJM, the regional grid operator, needed it most. During the period of peak demand on Thursday evening [January 9], wind energy was providing PJM with 3,500 MW while electricity prices averaged more than $500 per MW hour (MWh), providing direct savings of $1.5 million to $2 million per hour.

While natural gas generation suffered a major collapse during the crisis, wind generated electricity provided a vital substitute for a lot of that missing capacity.

During these times of peak demand, wind energy was primarily displacing gas use at natural-gas fired power plants. Many areas in the eastern U.S. were at or near record natural gas prices due to weather-driven demand for natural gas for building heating as well as electricity generation. Because the natural gas price curve is also quite steep during times of peak demand, and because the market price applies to all transactions in the market, wind energy likely produced large savings for all natural gas users by driving down the price of natural gas. So even if you primarily use natural gas to heat your home (in addition to electricity to run your furnace fans) you can thank wind energy for helping to keep your heating bill low.

It is clear from the actual events of January 2014 that if power companies in PJM had been investing in the last five years in offshore wind power, instead of frantically chasing lower gas prices with new gas-fired generation, most of PJM’s capacity problems could have been avoided.

Instead providing real solutions for the real problems, the PJM cartel wants to pour more of our money into rigging PJM’s PIG rules to favor big generators that control the cartel.

Capacity Markets: Money for Nothing

The American Public Power Association has published its latest biennial report on the impacts of mandatory capacity markets.  This report is not a theoretical analysis.  It looks at individual projects built in 2013 and how they were financed.  Most of the 24 page report is appendices with tables describing the new generation plants built in 2013.  As in their 2012 report, APPA concludes that, particularly in terms of stimulating new generation in areas where it is needed, capacity markets run by RTOs have almost no impact on creating new generation.

As was found in the analysis of 2011 generation, almost all new capacity was constructed under a long-term contract or ownership. Just 2.4 percent of the new capacity was built for sale into a market, a number that includes new facilities for which no information could be found about the contracts. Moreover, when broken down geographically, only 6 percent of all capacity constructed in 2013 was built within the footprint of the RTOs with mandatory capacity markets.
APPA thus found that all of the electric industry’s claims about capacity markets stimulating new investment are just wrong.  Who are the members that control the RTOs?  The big boys in an RTO are the holding companies that own a lot of existing generation capacity.  They have designed the capacity markets not to help new competitors enter their markets.  The incumbent generators design the markets to line their own pockets.
Are the capacity markets the least-cost means to achieve reliability?
These constructs are costing consumers billions of dollars for little in return, for the following reasons:
Different resources have different costs.
In these markets, a 50-year old coal plant is paid the same amount per MW and for the same duration as is a brand new highly efficient combined-cycle natural gas plant as is an agreement by a factory to curtail load when needed. As a result, excess windfall revenue is paid to the older depreciated plants and the revenue stream is not stable enough to attract investors in new resources.  The bulk of revenue has been paid to existing plants.  In the PJM Interconnection (primarily covering Maryland, New Jersey, Pennsylvania, Virginia, West Virginia, Ohio, northern Illinois, and Delaware), $72 billion has been paid or will be paid by consumers to generators and other capacity providers. Yet over 90 percent of this revenue has gone to existing generation, although many older plants have paid off much of their fixed costs. Moreover, most of the new generation capacity that has been built was done so under utility ownership and long-term contracts, not as a result of capacity market payments.
Capacity markets do not ensure an appropriate mix of resource types.
Because the capacity markets do not distinguish between technology types or specific locations on the grid, critical needs are not addressed, including adequate flexible ramping capability to match the variability of renewable resources, reliability gaps created by retiring coal plants, the coordination of natural gas infrastructure and delivery with the significant expansion of natural gas generation. As a result, the RTOs often create systems of side payments to ensure reliability, such as direct payments through what are known as reliability-must-run agreements to coal plants to remain in place to ensure reliability.
Price signals are not effective.
If transmission congestion limits the ability of capacity in one area to deliver lower cost power to another zone, the more congested zones may have a higher price. The theory behind zonal price differentials is that higher prices will act as a “signal” for the development of new generation or transmission. But such higher prices are not effective signals because owners of generation have no financial interest in building new resources and lowering prices for their existing units; investors seek steady and predictable revenue flows, not fluctuating prices; and many other factors influence the decision to build, including land and transmission availability, local acceptance, and environmental rules. Transmission construction may alleviate these price differentials, meaning that consumer paid both for higher prices and for the cost of the transmission.
So APPA concludes that good old fashioned contracts between a seller and a buyer (bilateral contracts) and internal investment by power companies provide the long term financial stability that investors need to build power plants.  Capacity markets can never provide that kind of stability and assurance of cash flow.  All capacity markets do is provide a smokescreen for power companies to pick rate payer pockets, to the tune of $72 billion in PJM alone, according to the report.
Of course, generation capacity is largely a problem because of peaks in demand in most US RTOs.  The US electrical load is characterized by wide swings from normal base load to very short periods of very high load.  There are winter peaks, caused mainly by heating, and summer peaks, caused mainly by cooling.  But what if we tackled the capacity problem by tackling what causes it – the demand problem.  What if we did what the Danes did, and eliminated electric heating almost entirely by using gas combustion and “waste” heat form power plants and manufacturing businesses?  Then the winter peak goes away.
Summer peak is a little different, because that is caused by cooling, which is tied pretty tightly to electricity by air conditioning technology.  Winter peak could be eliminated entirely by shifting all electric heating systems to other heating sources.
Heating with electricity is also phenomenally inefficient.  Eliminating electric heat would eliminate the need for rate payers to pay for thousands of megawatts of generating capacity and transmission lines during times of even normal load.
But in the US, there is no planning across industries.  There is no attempt to reduce electrical use by shifting technologies from the electrical sector to the natural gas sector by expanding heating.  Using natural gas or biomass combustion for direct heating is much more efficient than burning gas or biomass in a power plant, even a highly efficient one, sending that electricity hundreds of miles and running it through a resistance coil in a furnace.  This lack of planning across sectors has also led to the absurd situation last winter in which large parts of the US were left with shortages of both electricity and natural gas for heating because so much electricity is now generated by natural gas power plants.
So capacity markets aren’t even the best way of planning capacity for peak load.  Here too, capacity markets are money for nothing.

PJM Unveils New Transmission Projects Under Order 1000

In 2013, PJM Interconnection replaced its goofy transmission “planning” process with a new process that conforms to FERC requirements spelled out in the Commission’s Order 1000.  Under its new process, instead of just picking transmission developers with very little transparency (as with TrAIL and PATH), PJM identifies reliability problems and then sets an annual deadline for project developers to propose solutions.

This year, PJM’s Transmission Expansion Advisory Committee received 106 project applications by its July 28 deadline.  RTO Insider has a good description of these projects.

Here is a map and list of those projects.  Note that none of them involve massive HV lines in WV.  PPL wants to get on the gravy train, though.

PJM Market Monitor Sees Exelon/PHI Merger as Threat to Power Markets

A recent story in industry journal SNL (subscription only) describes objections made by Joe Bowring, PJM Interconnection’s Market Monitor, to the Federal Energy Regulatory Commission about Exelon’s proposed purchase of PEPCO Holdings, Inc.

He said the move would eliminate a large independent transmission owner in PJM and place PHI’s assets under the control of a vertically integrated company. While the applicants said that should not be a concern since all the transmission assets involved will continue to be under PJM’s control after the transaction is consummated, Bowring said that alleged protection is “overstated.”

The monitor explained that PJM’s control over its members’ transmission facilities, while significant, is limited. Noting that participation in any RTO is voluntary, Bowring insisted that a large transmission owner can have significant leverage over the RTO in which it is a member because “like any organization, RTOs are concerned with protecting their size, scope and importance.”

“The greater the proportion of the RTO’s assets represented by the transmission owner, the greater the threat of exit to the RTO and the greater the potential influence of the transmission owner over the RTO governance and processes,” Bowring said.

In this case, Bowring said, a merged Exelon/PHI would account for 23.4% of transmission service credits collected from the PJM market. That much control would give the combined company “substantial and increased influence over decisions that directly relate to competition in PJM among developers of transmission projects.”

Specifically, Bowring predicted that a post-merger Exelon could use its responsibility to perform interconnection studies for generation to exert vertical market power to block potential wholesale competitors. He also said the consolidation of the ownership of transmission assets could create horizontal market power concerns because it “reduces the pool of companies that have the expertise to compete to build competitive transmission projects.”

Bowring’s objections all revolve around the point I have made many times on The Power Line – that PJM, and all other regional transmission organizations, is essentially a cartel designed to set prices and limit access to markets.

Power companies supported the so-called deregulation of US electricity in the 1980s and 1990s not to promote “free markets” but to shed themselves of unprofitable business structures and state regulation.  The growing number of mergers in the US electricity system today is focused on creating large, multi-state holding companies that once again control distribution, transmission and generation subsidiaries.  These holding companies, like AEP, FirstEnergy and Exelon, can now play off one market against another to exercise market power and maximize their profits.

Largely as a result of removing control of the bulk transmission system from state control, these holding companies used their leverage in the Cheney Administration to create a massive subsidy system based on radically expanded federal control of the planning and construction of high voltage transmission lines.  It is not surprising that transmission is the new gold mine for power company profits.  All of these subsidies are paid for by rate payers.

As Bowring points out, it is the control of both transmission and generation that gives the new holding companies their real market power in PJM.  PJM controls what new power plants are allowed to “interconnect” with the regional transmission system.  The RTO determines who wins and who loses, because without interconnection, a plant can’t sell its electricity.  And who controls PJM?  Its big holding company members who also own lots of obsolete and expensive generation.

Exelon has a particular problem.  It is one of the largest owners of nuclear power plants in the US.  It is even more difficult for nuclear power plants to ramp production up and down than it is for coal-fired plants.  Essentially, the nuclear dinosaurs must run all the time.  That means that they have to take whatever prices are available on the wholesale markets.  Increasingly, particularly with the growth of renewable power, which has zero fuel costs, there are times of day, particularly when wind farms are putting a lot of energy into the grid, when Exelon’s nuclear plants have to operate at a loss, because their operating costs are higher than the prices available to them in the market.

Stagnant demand, the growth of demand resources and the expansion of competition from solar, wind and more flexible natural gas plants force Exelon’s nuke plants to take major hits to their bottom lines.  PJM is on the verge of making big interconnection decisions for offshore wind farms.  If Exelon is allowed to merge with PHI and become a giant at the PJM cartel table, how enthusiastic do you think Exelon/PHI will be about letting large new offshore wind farms into its cozy PJM market?

Neither Exelon nor PEPCO Holdings controls any electric companies in WV, but their merger’s impact would raise WV rates through PJM’s cost recovery mechanisms.

Federal 7th Circuit Rejects FERC/PJM Non-Reform of Transmission Cost Allocation

Federal court cases drag on forever.  Remember the 7th Circuit Appeals Court decision in 2009 throwing out PJM’s FERC-approved recovery of costs from all PJM rate payers for transmission lines that benefit only eastern PJM customers?  In that decision, the 7th Circuit remanded the case to FERC, ordering FERC and PJM to fix their cost recovery scheme so that only people who benefit from transmission lines like PATH would pay for them.

In response, FERC held a “paper hearing” to respond to the 7th Circuit.  In March 2013, FERC issued an order which the Commission claimed responded to the 7th Circuit’s concerns.  Except it didn’t.  It was the same old recycled crap in a new wrapper.

Yesterday, the same three judge panel, including Judge Posner, issued an order throwing out FERC’s new fake plan.  The order contains an excellent summary of the case history.  Judge Posner has a clear and non-legalese writing style that is refreshing.  This case is very important, because it attacks the bedrock of FERC’s plan to hide the rate impacts of its high voltage transmission schemes behind its “postage stamp” cost allocation.  Here is what Judge Posner concluded:

To summarize, the lines at issue in this case are part of a regional grid that includes the western utilities. But the lines at issue are all located in PJM’s eastern region, primarily benefit that region, and should not be allowed to shift a grossly disproportionate share of their costs to western utilities on which the eastern projects will confer only future, speculative, and limited benefits.

The petitions for review (from the original plaintiffs) are granted and the matter onceagain remanded to the Commission (FERC) for new proceedings.

Judge Posner agrees with those of us who opposed PATH because we would be paying with our electric rates and our land for a line that only benefited people to the east of us.  FERC and PJM are playing games with the 7th Circuit court.  The Commission and the RTO need to pull up their big boy pants and get cost recovery right.

This 7th Circuit case only applies to PJM’s pre-2013 transmission projects, like the ones it pushed in Project Mountaineer.  PJM has already abandoned its past practice of forcing every rate payer in its system to pay for high voltage transmission lines.  In 2013, PJM adopted, and FERC approved, a system that is a hybrid of the old (still wrong) “postage stamp” system and a formula that requires costs to be born only by those who benefit from a project.  This new system is not what it needs to be, but it is much more realistic than the old boondoggle system that the 7th Circuit has now rejected twice.

If PJM cannot please the 7th Circuit, will the court require PJM and the transmission companies like PPL and PSEG (Susquehanna-Roseland) and FirstEnergy (TrAIL) to disgorge all their ill-gotten gains in rate payer refunds?  We’ll see.

Cost Recovery for Non-Transmission Alternatives, No Easy Answers

Last week, I attended a two-day seminar given by Scott Hempling, one of the most knowledgeable experts on the legal aspects of US grid management.  I have been trying to figure out how to work what I learned (and it was a lot) from Mr. Hempling into a post on The Power Line.  Then a friend sent me a link to this post by the great John Farrell, one of the US’s leading experts on decentralized power.  If you want to read a great overview of FERC’s failed transmission policies and the agency’s failed attempt to rectify them in the recent Order 1000, Mr. Farrell has it all in his post.

Readers of The Power Line are very familiar with the fact that in the 2005 Energy Policy Act, Congress and the Cheney Administration created game changing rate payer subsidies for the construction of new high voltage transmission lines.  FERC’s Order 1000 leaves those subsidies in place, despite the fact that electricity demand in the US has remained relatively constant since 2006 and there is no great crisis in bulk transmission infrastructure as a result.

In his post, Mr. Farrell, citing reasoning provided by Mr. Hempling, that it makes no sense to socialize high voltage transmission costs without also allowing regional cost recovery for alternatives that accomplish exactly the same things in terms of grid stability and support for innovation, but a much lower cost.  Of course, these alternatives to transmission, referred to in the lingo as “non-transmission alternatives” or NTAs, involve such techniques as energy efficiency investment and load shaving and demand management.  NTAs also include technologies for achieving efficiency improvement as well as decentralized, self-reliant generation and storage, particularly decentralized solar generation.  Here is Mr. Farrell’s point:

Unlike the rules for transmission lines, there is no regional process for cost recovery of non-transmission alternatives. In other words, the builder of a large and distributed solar project that serves the same needs as a regional transmission line has no certain method for recouping their costs, as they would with power lines.

There’s also no process for fairly allocating the regional costs of a non-transmission project as is done with a transmission line project. Consider this hypothetical example where the benefits of a $10 billion interstate transmission project could be served at half the cost by a $5 billion non-transmission alternative of distributed solar and energy storage. While the total ratepayer cost is $5 billion instead of $10 billion, a lack of regional cost allocation means that Illinois ratepayers would pay more for a project with the same regional benefits. And when that option comes before the Illinois Commerce Commission for “least cost” review, guess which wins?

Mr. Farrell goes on to cite three solutions proposed by Mr. Hempling and adds another one:

At stake is over $164 billion in transmission lines planned or under construction, with electric customers on the hook for that amount plus interest and guaranteed rates of return (with incentives!). How many of these projects were or will be approved without a meaningful look at cost-effective alternatives?

Change is needed. Now.

Utility regulation expert Scott Hempling offers three compelling amendments to existing policy, and I add a fourth:

  1. FERC’s Order 1000 must be amended to require regional transmission organizations (or the companies that make up an unorganized “region”) to examine “all feasible non-transmission alternatives.” This analysis must be done by developing internal staff expertise at the regional level or contracting with an independent entity (not a transmission company or its subsidiary) that is expert in non-transmission alternatives. (Scott discusses a further scenario in his essay, for the very techically minded). This overcomes the “empty room” problem illustrated earlier, where the current order requires only consideration of those proposals submitted in the process (presumably by a third party) and it meets the threshold of prudent transmission planning as required in federal regulation.
  2. FERC must reject any transmission company proposal for cost recovery without a reasonable investigation of alternatives. And “reasonable” should mean “an objective, regulator-reviewed process that identified and considered all plausible alternatives, and emerged from that process with the best benefit-cost ratio.”This is the key enforcement element.If FERC continues to approve cost recovery for transmission projects without proof of a robust and independent alternatives analysis, they are likely in violation of their charge to ensure reasonable and product costs.
  3. FERC must develop (potentially via an amendment to the Federal Power Act) a regional cost-allocation process that puts non-transmission projects on cost recovery parity with transmission.As illustrated above with the Midwestern comparison, lower cost non-transmission alternatives will lose to expensive transmission projects in state regulatory proceedings simply because they lack access to the same regional cost recovery option.
  4. State utility commissions should similarly reject any transmission line proposal, interstate or intrastate, that does not offer proof of a robust and independent alternatives analysis, and should build internal expertise to conduct such analysis. Citizens groups funded on $5 donations are often the only advocates for non-transmission proposals that can save electric customers billions of dollars over the financing life of power lines, up against entrenched monopolies with a shareholder interest in stringing wires. Public Utilities Commissions have a legal and moral obligation to stand up for cost-effective energy investments.

These policy changes don’t advantage distributed renewable energy or conservation or energy efficiency, but merely put it on a level playing field with profitable power line investments by transmission companies. They may give (modest) comfort to landowners that when utilities exercise eminent domain to use their land for new power lines, it’s only after robust and analysis of all cost-effective alternatives. Most importantly, they ensure that when we’re constructing a grid for the 21st century, for a majority clean energy system, that we’re doing it in the most cost-effective and prudent manner.

Oh, and it removes the decision over building power lines from the companies that make money doing it.

The last sentence refers to the problem I have pointed to many times in the past on The Power Line:

Who chooses whether a transmission or non-transmission proposal is best in the regional transmission plan? The regional transmission organization, made up of power line companies. How do they make their money? Building power lines. But there are several layers to this problem:

  1. Most transmission companies aren’t in the business of the transmission alternatives. In other words, to choose against transmission is to lose business.
  2. Even if they had capacity to build a non-transmission project, FERC incents transmission over alternatives by providing bonuses to a transmission provider’s rate of return for building power lines (2005 Energy Policy Act, FERC Order 679).

We only need to look at the name of PJM Interconnection’s committee that recommends new transmission projects to see this conflict of interest in action.  The committee could be called the Transmission Improvement Advisory Committee, if it truly considered cost/benefit and all alternatives available.  But that’s not the committee’s name.  PJM’s transmission committee is called the Transmission Expansion Advisory Committee, and it is made up primarily of voting members that are engaged in the bulk transmission business, including financial traders who stand the benefit the most from coast to coast energy trading.

As much as I admire Mr. Hempling’s work, and the power of his analysis of NTAs, I disagree with the first three solutions based on his work proposed in Mr. Farrell’s post.  I do not see expansion of regional cost recovery for NTAs as a solution.  It is a next step away from the kind of decentralized power that Mr. Farrell advocates for so brilliantly.  Mr. Farrell’s fourth solution is good, but it only works if a particularly PSC decides to do its job.

The fact is that the US had a decentralized regulatory regime until the power companies and energy traders blew it up by federalizing regulation in the 1990s under the guise of “deregulation.”  What happened was not deregulation at all.  We now have a haphazardly managed electric grid that is designed primarily to suit the business needs of modern day versions of electricity holding companies that almost destroyed the US electrical system in the 1930s.  This industry-driven deregulation has also substituted an expensive and opaque bureaucracy of RTOs full of lawyers, engineers, speculators, and other hangers on, for the system of state regulation which allowed for a measure of transparency and planning for local needs that served the US well for 60 years.

The old system based on state regulation was not perfect, and it should have been significantly transformed.  Efficiencies and markets could have been integrated into the state-base regulatory regime without doing significant damage to state regulation.  Regional cooperation could have been encouraged to grow from the bottom up instead of being imposed by FERC and Congress.

The fact is, as I know Mr. Hempling would agree, that US electricity policy is a total mess.  Some states are regulated, some aren’t.  RTOs don’t even have control of significant amounts of US geography.  FERC issues orders which are contested and voided by some federal circuit courts.  The new electricity holding company structure is adapting to this patchwork, as electric companies are fleeing the “free markets” they had screamed for in the 1990s to regulated states and the federal transmission programs that guarantee them bonus profits.

So, I disagree with Mr. Hempling and Mr. Farrell.  I can’t argue with the immediate logic of including non-transmission alternatives into regional cost recovery, if we are stuck with the current regime.  Real solutions to our current transmission mess lie elsewhere, however – by rebuilding our regulatory system from the bottom up, not by adding more FERC mandated cost recovery for non-transmission alternatives.  If we are really about decentralizing power and creating more self-reliant states, we need to vest state authorities with real power to make their own decisions.  It won’t be pretty, but it will be better than the current chaos that only serves to strengthen corporate control of our electrical system.

May 2014 Capacity Auction Shows that PJM Cartel Working as Planned

Last weekend, I posted about David Cay Johnson’s dissection of supply rigging in the recent PJM capacity auction.  RTO Insider has now published its detailed analysis of Exelon’s specific strategies.  UBS Securities, especially their main electricity industry analyst Julien Dumoulin-Smith, has also issued a report on the situation.

UBS identifies at least four companies that deliberately withheld capacity from the auction to create tighter supply and raise prices for all of their plants that did clear the auction.  UBS lists Exelon, NRG, Dynegy and FirstEnergy.

But who wins? Mostly EXC, NRG, FE, and DYN, but whole sector should benefit
Despite the lower MWs committed through the use of portfolio bidding, all four companies are among the biggest beneficiaries of the auction results. We suspect the entire sector will continue to benefit from the trade, however, more Eastern-oriented MAAC names could still be more muted in upside given the substantial announcement of new and converted gas-fired capacity.

The report also attributes “much” of this year’s big jump in the auction clearing price (from $59/MWday last year to $120/MWday this year) to market manipulation:

We attribute much of the ‘recovery’ in prices in the latest PJM capacity auction for 2017/18 to $120/MW-day (up from $59/MW-day last year) to a significant shift in bidding strategy, with ~9.7 GW of capacity opting not to clear. With no significant new EPA rules, we attribute much of the decline in generation to more aggressive bidding strategies, likely with EXC and NRG (the two largest generators in PJM) opting to bid in their portfolio at higher prices, given lower historic energy prices; bidding in these full costs (ACRs in PJM lingo) was discussed explicitly by EXC as part of its efforts to more rationally bid its nuclear port folio. Meanwhile, we suspect NRG has opted not to clear much of the EME Midwest Gen portfolio due to IL MPS standards, set to ratchet up for the portfolio in 2017 to yet a crucially tighter SO2 requirement. We also believe FE opted not to clear ~half of its capacity in the ATSI zone, continuing this theme.

RTO Insider notes that PJM’s captive “Market Monitor” Joe Bowring saw nothing wrong with the PIGS‘ new strategy to raise electric rates for all of us:

Market Monitor Joe Bowring said in an interview Friday that all generation offers were screened by his staff and PJM to ensure market power was mitigated by offer caps. That included a determination that no generator with market power could offer at a price higher than ACR less net energy revenue. “We do not believe market power was exercised in the capacity market,” Bowring said.

UBS noted that “the outcome is highly dependent on the initial assumption for where the auction would have come out at without any withholding. Lower baseline assumptions generally incentivize more withholding since less revenue is removed by the withheld assets (less risk in the strategy) while overall net uplift increases as well.”

“While outright strategic collusion is prohibited, participants may have been `telegraphing’ their intentions to each other more subtly in public comments from more than one company regarding potential retirements, seeking higher Avoided Cost Rates (ACR), etc.,” UBS said.

So Bowring thinks nothing is amiss, and UBS sees the PIGS continuing their new-found strategy in coming years.  Business as usual at the PJM cartel.

Exelon Games Recent PJM Capacity Auction, Rigged in Favor of Big Generators

Reporter and law professor David Cay Johnson has made a career of investigative reporting.  Today he published an excellent piece detailing how Exelon rigged the recent capacity auction in the PJM cartel to rake in lots of free money for itself.

The latest major electricity auction demonstrates yet again how the industry, with help from Wall Street financial engineers, is gaming power markets, forcing customers to pay higher prices. You would not know that, however, from most news reports mentioning the auction.

Absent disclosures by the secretive markets, investigation and reform, you should expect your monthly electricity bill to rise sharply in the next few years as electricity industry investors reap outsize profits.

Losing is winning

The auction last week was not for electricity itself, but for promises to maintain the capacity to generate power in future years. The so-called capacity auction was conducted by PJM, the electricity market in 11 states serving 61 million people from New Jersey to Illinois.

Exelon informed investors that two Illinois nuclear plants and one New Jersey plant filed losing bids. The bids for these plants were higher than bids filed by other power plants owned by Exelon and other companies to provide the amount of generating capacity that PJM says will be needed for the 12 months beginning June 1, 2017.

PJM is a secretive market that does not disclose bid details even after an auction. But a list of all Exelon plants in the PJM area indicates that the losing bids affected just 17 percent of its generating capacity.

The capacity market is a so-called single-price or clearing-price auction. The highest bid needed to ensure capacity wins, with all those who bid less also getting the highest price. Those who bid above that price, like the two Exelon nuclear plants, get nothing.

Exelon alerted stock traders to these losing bids. When the markets opened on Tuesday, its share price jumped up, closing at 3.6 percent higher than on the previous trading day.

Why would losing bids make the stock price go up?

Strange as it may seem, Exelon stands to make a lot more money because it made losing bids for about one-sixth of its generating capacity. The reason is that it will collect much bigger revenues on the 83 percent of its plants that filed winning bids. Therein lies one of the many problems with the electricity market rules.

Exelon will get almost exactly double the capacity market payments than if it had placed winning bids for its entire fleet of generating plants, utility rate consultant Paul Chernick estimates.

Read the article.  It provides a clear picture of how the creation of mysterious so-called markets in the deregulation era was designed, to a large extent by Enron executives, to line the pockets of big electricity generators and Wall Street speculators, all paid for by you and me on our electric bills.  Mr. Johnson also shows why capacity prices jump around so much from year to year with little connection to the real world, because they have far more to do with companies’ fraudulent strategies du jour than with maintaining real reliability on PJM’s system.

RTO Insider Has Excellent Overview of PJM Capacity Auction Results

This week’s RTO Insider has almost everything you need to know about the PJM capacity auction results for 2014.  Here is a link to their recent post.

The big news this year, in addition to the limits put on imported capacity and demand resources, is exactly what opponents of PATH and all the Project Mountaineer opponents said for the past ten years.

Six new combined-cycle plants cleared for the first time, all of them located east of the west-to-east transmission constraints or in other areas with capacity needs. In total, more than 5,900 MW of new entry cleared.

That’s what we told anyone who would listen.  PJM doesn’t need Project Mountaineer HV transmission to import coal-fired power to the East Coast, the East Coast needs to increase generation capacity in the “constrained” (PJM’s jargon, not ours) areas.  That’s exactly what has happened, leaving only one area in NJ with a higher capacity price than the rest of PJM.

PJM Releases Report on 2014 Capacity Auctions

Yesterday, PJM Interconnection released the results of its Reliability Pricing Model auctions for capacity for 2017-2018.  This time, you can believe me.

In the 2014 auctions, the overall capacity price doubled from about $59 per megawatt day to $120 per megawatt day.  This year’s results continue the year to year seesaw of capacity price trends.  It appears that while demand remains flat (and PJM’s optimistic demand projects have been revised downward continuously for years), three factors have contributed to reductions in supply of capacity offered in the auction: obsolete, expensive coal plant closures, new restrictions on demand resources offered in the market and limits on imported capacity allowed on the market.

Diversity of supply continues as renewable capacity and natural gas-fired power offered continued its steady rise.  Although demand resources declined from last year’s high, energy efficiency resources offered on this year’s market showed a continued increase.  The increase in diversity, both in source types and in location within PJM resulted in far fewer geographic disparities in capacity prices across PJM, as evidenced by this kind of smudgy graph from the report showing past price trends:

2014 RPM graphHere is PJM’s summary of this year’s results, from the report:

Summary of Results

The 2017/2018 Reliability Pricing Model (RPM) Base Residual Auction (BRA) cleared 167,003.7 MW of unforced capacity in the RTO representing a 20.1% reserve margin. When the Fixed Resource Requirement (FRR) load and resources are considered the reserve margin for the entire RTO is 19.7%.

Resource Clearing Prices (RCPs) for the 2017/2018 BRA are shown in Table 4. The RCP for Annual Capacity Resources (Generation, Annual DR and EE Resources) is $120/MW-day across the entire RTO except for the PSEG LDA where the Annual RCP is $215.00/MW-day. The PSEG is only locational constrained LDA in the 2017/2018 BRA as the capacity import levels are below the capacity import limit for all other modeled LDAs. The Annual RCP in the rest of RTO Region increased from $59.37/MW-day in the 2016/2017 BRA to $120.00/MW-day in 2017/2018 BRA. The Annual RCP in the MAAC region increased slightly from $119.13/MW-day in the 2016/2017 BRA to $120.00/MW-day in the 2017/2018 BRA; and the Annual RCP in the PSEG LDA decreased slightly from $219.00/MW-day in the 2016/2017 BRA to $215.00/MW-day in the 2017/2018 BRA.
The Maximum Limited DR Constraint for the overall RTO is a binding constraint in the auction resulting in a price decrement for Limited DR of $13.98/MW-day relative to the RCP of Extended Summer DR for resources located in the same LDA; and, additionally, the Maximum Sub-Annual DR Constraint for the PPL LDA is a binding constraint resulting in a price decrement for Extended Summer DR of $66.02/MW-day relative to the RCP of Annual Resources located in the PPL LDA.

The RCP for Limited DR, Extended Summer DR and Annual Resources located throughout the RTO except for the PSEG LDA and the PPL LDA is $106.02/MW-day, $120.00/MW-day and $120.00/MW-day, respectively. In the PSEG LDA, the RCP for Limited DR, Extended Summer DR and Annual Resources is $201.02/MW-day, $215.00/MW-day and $215.00/MW-day, respectively. In the PPL LDA, the RCP for Limited DR, Extended Summer DR and Annual Resources is $40.00/MW-day, $53.98/MW-day and $120/MW-day, respectively.

The total quantity of new generation capacity resources offered into the auction was 6,587.3 MW (UCAP) comprised of 6,128.1 MW of new generation units and 459.2 MW of uprates to existing generation units. The new generation includes facilities that were previously slated for deactivation, but were reactivated and are switching fuel types. The quantity of new generation capacity resources cleared was 6,267.3 MW (UCAP) comprised of 5,927.4 MW (UCAP) from new generation units and 339.9 MW from uprates to existing generation units.

PJM Capacity Auction Results Coming Friday

And boy did I blow it yesterday.  Writing a blog by yourself and trying to cram in posts around work and farm life is a dangerous combination.  Yesterday it caught up with me.  I was pressed for time, but I wanted to get a status report up on The Power Line about the recent PJM capacity auction.  In my quick research, up popped a report of the auction.  I ran with it.  It was last year’s report on last year’s auction, which I already covered last year, here.

While I work with no editor, I have lots of alert and helpful subscribers.  One of them notified me immediately that yesterday’s post was wrong.  But the email still went out to my subscribers and to my Facebook and Twitter accounts.

I have always been committed on The Power Line to good documentation and fact-based posts.  I hope I’m never embarrassed again as I was yesterday.  I have been assured that PJM is releasing the results of this year’s auction on Friday.  I’ll wait until then to report on this year’s auction.

2014 PJM Load Forecast Predicts 4.4% Increase in Demand – Really?

PJM is at it again.  The final version of the 2014 load forecast was published in February.  PJM is forecasting a 4.4% load increase in 2017.  The forecast covers the year three years in the future, because the load forecast serves as the basis for PJM’s capacity auctions held every May.  The main auction involves generation capacity for delivery three years in advance.  This year’s 2014 auction is for capacity to be provided in 2017.

As I pointed out in my comments about the draft forecast PJM published in December, PJM has never provided a load forecast that has proven to be accurate by actual experience.  Every year, PJM predicts peak load growth, and every year, they revise projections downward.  In past posts, I have shown samples of their load forecast graphs in which actual demand is flat or falling, yet PJM always projects future growth.  As actual figures fail to meet PJM’s predictions, PJM forecasters revise the next years forecast downward, but insist on growth rates that are still too high.  It’s been that way since I started covering PJM’s forecasts in 2010.

I guess it’s not surprising that PJM forecasters always err on the side of over-estimating future load.  Their job is to make sure there is enough electricity to serve their region three years in advance.  Before the capacity auctions every year, however, PJM adds a reserve margin to predicted load to ensure that level of caution.  If PJM forecasters are also including a safety margin in their load forecast, they should be explicit about that.  The RTO’s load forecasts are used for all kinds of planning beyond the capacity market.  They should be as accurate as any forecasts can be.

A big part of PJM’s problem is the load forecast’s reliance on Moody’s economic forecasts.  These forecasts of economic activity drive assumptions about predicted load.  Moody’s forecast is always upbeat.  A new upturn is always just around the corner, and the Moody’s forecast used in PJM’s 2014 predictions is no different, despite the stagnation that has characterized the US economy for the past 6 years.  Perhaps PJM should rethink its reliance on a company that throughout the 2000s gladly slapped AAA ratings on bogus securities backed by shaky mortgage loans.  But Moody’s rosy assumptions allow PJM to inflate load growth while maintaining the rationale that they were just listening to the “experts.”

This sentence, from the 2014 load forecast, has appeared in one form or another in every executive summary of every PJM load forecast I have read since 2010:

Revisions to historical economic data and the addition of another year of load experience to the model resulted in generally lower peak and energy forecasts in this year’s report, compared to the same year in last year’s report.

Yup.  Another year, another downward revision of load forecast, and another admission that PJM’s forecasting has failed again.

Atlantic Wind Connection No Longer a Wind Connection

Well, it’s happened.  Here’s what I said back in 2010

Business conspiracies like the PJM cartel are hard to maintain.  Economists will tell you that cartels are inherently unstable because eventually it becomes more profitable for one or more of the conspirators to be the first to break out of the cartel’s rules.  You can always gain a competitive advantage if you are the first company to break out while other cartel members sit around thinking how smart they are for cooking up their conspiracy.

For months, those of us who have been following PJM’s Project Mountaineer have been puzzling at the strange behavior we have been seeing from Project Mountaineer conspirators.

First, Dominion Virginia Power proposed an alternative to PATH that would eliminate the need for any new power lines and would use the TrAIL line to do it.

Then, Project Mountaineer co-conspirator PSE&G, the New Jersey utility that wants to build the Susquehanna-Roseland line, published a report last week attacking the idea of building transmission lines to the east coast to transport coal fired power.  I characterized this behavior as “schizophrenic” at the time.

Now, everything becomes clear with the announcement of the offshore backbone transmission project.  From — Virginia to New Jersey.

Bingo.  While AEP/Allegheny were tied up with their goofy “reliability” scam and trying to get their PATH project through state regulators and the federal EIS process, PSE&G and Dominion were, no doubt, quietly working with the offshore backbone investors to create a straight shot to the New York/New Jersey markets.  Project Mountaineer without the headaches, at sea level.

Now we have a story over at SNL:

An undersea transmission project that for years was pitched as an efficient way to move electricity from offshore wind farms in the Atlantic Ocean to load centers along the East Coast now is “essentially divorced” from the fate of the nascent industry, a project official said April 16.

Known as the Atlantic Wind Connection, the project originally was conceived as a high-voltage link between northern New Jersey and southern Virginia, with the first phase, dubbed the New Jersey Energy Link, starting off the Garden State’s coast …

“Right now we’re essentially divorced from offshore wind,” Mitchell said at an April 16 briefing hosted by the U.S. Energy Association in Washington, D.C. “So we and regulators and others have to look at this line in New Jersey … as an important link within the existing grid.”

While Mitchell pointed to the potential ratepayer savings the project could bring — “an illustration of the impact that congestion and free-flowing transmission can have on ratepayers,” he said — the pivot away from offshore wind does not seem insignificant given the project’s history.

When Google Inc., now an investor in the project, was debating whether to participate, the company wanted some assurance that the cable would not be used simply to “move relatively cheap power in Virginia that is largely generated with coal … up the coast and maybe all the way to New York,” Mitchell said.

Mitchell could not say when, or if, the cable would ever make its way down to Virginia, but the project’s owners are now “agnostic as to what power comes on that line. It’s just a line like a highway,” he said.

Google declined to comment. The company’s website describes the project as “a superhighway for clean energy transmission.”

While the focus of the Atlantic Wind Connection has shifted to relieving existing congestion in New Jersey, Mitchell emphasized that the infrastructure would be there should wind farms ever take root off New Jersey’s coast. The cable is not expected to be in place before at least 2017, he said.

So there you have it.  The same old tired argument for importing power to relieve NJ’s claimed “congestion.”  Unfortunately, that argument is long out of date.  Here is PJM’s own analysis from 2012.  And we know that NJ’s problems are not caused by a lack of transmission, but by active suppression of new local generation by PJM and FERC.

As we know, the congestion that power companies and grid operators like PJM talk about is not the actual congestion of electrons on power lines.  It is “economic congestion” created when there is not enough line capacity to feed into an area in times of high demand, and power must be supplied from other more expensive generators.  The difference between the cheapest power on the grid and the more expensive power that must be dispatched to meet peak demand in some areas is called “congestion cost.” But remember what grid expert Hyde Merrill said in the East Virginia TrAIL case:

Rate-payers do not pay “congestion costs.” “The effect of PJM’s real-time pricing mechanism is to raise prices – dramatically – when congestion occurs. This is intended to send a price signal to encourage more generation and demand side savings in congested areas. However, to protect ratepayers from huge price increases due to congestion, PJM created a hedging mechanism. PJM captures a portion of the congestion related price increase, which it calls “Congestion Costs.” PJM then rebates these increased costs to the ratepayers through the FTR [Financial Transmission Rights] mechanism… These are bookkeeping procedures carried out within the market accounting and billing system…. When [PJM witnesses] refer to congestion costs of $1.2 billion in a single year, for example, they are referring to ratepayer rebates, not to costs paid by ratepayers.” (See Merrill testimony.)

Testimony of Merrill and Sovacool from the TrAIL case before the Virginia State Corporation Commission can be found here:,341,0,44,html/SCC-Testimony.

So eliminating congestion costs with rate payer subsidized transmission projects, such as the newly “divorced from offshore wind” AWC, is just a complicated and expensive way of shifting the costs of the PJM/FERC campaign to suppress generation in congested NJ from power companies to rate payers.

AWC’s real problem is that US electricity demand is now flat or falling.  There is little room in the market right now for large amounts of any kind of new generation, including offshore wind.  The slack created by coal plant closures has been more than made up for with new gas-fired plants and land based wind farms.

Now the real purpose of the AWC, as we had suspected back in 2010, has now been revealed.  And it’s not about offshore wind power development.  It’s about keeping the coal/nuke base load plants going for a few more decades while rate payers foot the bill for unneeded high voltage transmission projects.  By the way, AWC already has a nifty 12.59% FERC approved guaranteed rate of return.