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.

New Testimony Filed in PATH Cost Recovery Cases at FERC

AEP and FirstEnergy want $121 million (and more) from all rate payers in PJM Interconnection to cover their stranded capital costs (the abandonment case) and operating costs (the formal challenges case) on the failed PATH transmission project.  Remember that this boondoggle was created by the Energy Policy Act, inspired by the Cheney administration, and passed by the Republican Congress in 2005.  The 2005 Energy Policy Act allowed certain anointed transmission projects to charge all their costs to rate payers, even if they were never built – a good deal for power companies, not so good for rate payers.  You can’t find a better example of money for nothing.

While I am still technically an intervenor in the PATH abandonment case at FERC, I am no longer an active participant.  Last Friday was the deadline for testimony by the remaining active participants in the cases: Keryn Newman and Ali Haverty in the formal challenge case and a group of state public service commissions and consumer advocates (with the conspicuous exception of the WV PSC) as well as the staff of FERC itself.

Pro se intervenor Keryn Newman filed testimony on behalf of herself and my neighbor Alison Haverty in their formal challenge to expenses charged by PATH to rate payers from 2009 to 2011.  As they have all along, Keryn and Ali maintained in their testimony that PATH charges for lobbying and fake front groups should be borne by AEP/FE shareholders and not PJM rate payers.  Here is a link to their testimony.

FERC staff analysts also filed their testimony last Friday.  Staff witness Jean Miller appeared to agree with Keryn and Ali that PATH had illegally charged rate payers for their PR and lobbying costs.  Keryn’s  and Ali’s challenges only covered the years 2009-2011.  Ms. Miller testified that PATH’s 2008 costs should also be refunded to rate payers.  Here is a link to Ms. Miller’s testimony.  FERC expert Craig Deters also filed testimony that fills out the evidence Ms. Miller presented.  Here is a link to his testimony.

Staff witness Robert Keyton attacked testimony provided earlier by AEP/FE concerning the return on equity and debt costs that they were proposing the charge rate payers.  Most of this discussion is pretty abstruse and, as Mr. Keyton himself points out, largely hypothetical, because the front companies for PATH created by AEP/FE never produced anything and never borrowed any money, and are now defunct.  Here is a link to Mr. Keyton’s testimony.

The state agencies also filed some excellent testimony by transmission expert Peter Lanzalotta.  Mr. Lanzalotta basically testified that the AEP/FE should have pulled the plug on PATH after the East Virginia State Corporation Commission rejected the companies’ claim that PATH was needed to resolve reliability problems on the PJM system.

The summary in the introduction to Mr. Lanzalotta’s testimony tells the tale:

Mr. Lanzalotta concludes that PATH’s recommendation to Virginia that PATH be allowed to proceed while waiting for the 2010 RTEP to determine the need for the Project was not prudent.

If PATH had successfully recommended that it would be prudent to suspend the Project at the beginning of 2010, at least a year earlier than it actually was, then the abandonment costs would have been about $29 million lower than they actually were.

Beyond PATH’s 2010 recommendation that it be allowed to proceed, the escalation of PATH’s costs from its inception through its multiple delays were in excess of typical transmission cost escalation over the same period. Based on the Handy Whitman Cost Trends for Electric Utility Construction, the amount of excessive spending on the PATH Project is estimated to be $4.3 million.

The reference to prudence is important, because FERC rules require that rate payers can only be charged with costs that were prudently incurred by the power company.  Mr. Lanzalotta is saying here that more than $30 million for which AEP/FE want to charge rate payers violates FERC rules, and must be paid only by AEP/FE shareholders.

This point has been made repeatedly throughout the case by me and by other intervenors.  Mr. Lanzalotta sums it up nicely.  You can see his testimony at this link.

Those of you who fought the PATH line in the WV PSC will appreciate the testimony of Randall Woolridge, on behalf of the state agencies.  Mr. Woolridge provides an analysis of the exorbitant legal costs for which AEP/FE are trying to charge rate payers.  The power companies had the gall to redact important information from the records they provided to the state agencies in discovery.  Mr. Woolridge states that his analysis was incomplete, because he only received the unredacted copies of lawyers’ records two days before his testimony was due.

The final hearing in this case, dockets ER09-1256 and ER12-2708, isn’t until March 24, 2015.  A final decision by the Commission is due on July 31, 2015.

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.

TrAILCo Has Too Much Capital — FirstEnergy Wants It

What a great way to start an article:

Insisting that the move will raise no risk of “corporate officials raiding corporate coffers for their personal financial benefit,” Trans-Allegheny Interstate Line Co. asked FERC to confirm that it can pay periodic dividends out of paid-in capital to its parent, FirstEnergy Transmission LLC, without violating the Federal Power Act.

That was part of outlaw FirstEnergy’s appeal to FERC to allow it to withdraw capital from its transmission subsidiary TrAILCo.  TRAILCo is filling up so fast with its extra-high rate payer subsidies from FERC for its obsolete transmission lines that failing FirstEnergy wants to get its hands on some of the loot.  Note also that the quote about corporate raiding was written by FirstEnergy’s own lawyers in the company’s FERC filing.

Back in 2001, Dick Cheney and Enron’s Kenny Lay whined in their secret energy task force report that the US transmission infrastructure was falling apart because there weren’t enough profit incentives in place for investors.  The Republican-controlled Congress obliged them in the 2005 Energy Policy Act by creating rate payer financed giveaways to high voltage bulk transmission owners. TrAILCo’s TrAIL line through PA, WV and East VA was one of those lines guaranteed extra high profits.

A new report has been released by The Power Line’s own Cathy Kunkel and Tom Sanzillo for the Institute for Energy Economics and Financial Analysis about FirstEnergy’s desperate attempts to rescue itself from a financial death spiral.  They document how FE is grabbing for all the subsidies it can get its hands on and how it is attempting to suck capital from its profitable subsidiaries to shore up its obsolete coal-fired and nuke plants.  TrAILCo is about the only profitable part of FirstEnergy right now, and they want to loot that subsidiary too.

FirstEnergy’s financial condition has deteriorated since it merged with Allegheny, and its key financial metrics are on a downward trajectory. Over the past three years, it has experienced declining revenues, declining net income, declining stock price, declining dividends, and rising debt. It has retired 4,769 MW of merchant coal plants and has booked impairments totaling $1.1 billion against the value of its coal plants from 2011 to 2013. To shore up its balance sheet, FirstEnergy has relied heavily on “one-time resources,” including proceeds from asset sales and short-term borrowings. FirstEnergy’s poor financial performance stems from the underlying condition that the company’s business – the sale of electricity – is performing poorly and not generating sufficient revenue to cover expenses.
The original quote cited above refers to paying dividends from paid-in capital.  There is no such thing as paying dividends from paid-in capital in standard accounting practice.  When you take capital out of a company, you are simply taking capital out of a company.  This has nothing to do with dividends, which are paid as a share of annual profit or net income.  FE is raiding TrAILCo, plain and simple.

Without the Cheney/Lay-inspired rate payer subsidies, TrAILCo would just be another of FE’s failing business ventures.  Thanks to the 2005 Energy Policy Act, FE doesn’t have to liquidate TrAILCo because the subsidiary is actually an asset that is earning them money, unlike their coal and nuke plants.  Now FE wants FERC to let them milk their cash cow dry.

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.

FE & AEP Attack Net Metering in OH

FirstEnergy and AEP, the holding companies that control most of the electricity systems in OH and WV, are pushing to prevent solar power producers from being paid for their contribution to PJM’s capacity needs in OH.  Using  OH’s regulatory system to underpay small producers would also allow the small producers’ energy at a discount and sell that energy at a profit to their own customers.

Here is an excellent account of the situation in OH.

The EcoWatch story also covers FE’s attempts at FERC to block the sale of demand resources in PJM’s capacity markets.

Meanwhile, on the federal level, FirstEnergy’s ongoing FERC challenge aims to exclude demand response from the results of May’s capacity auction for 2017-2018.

“We believe that removing these demand resources from the capacity market is going to provide vital compensation for essential physical assets like nuclear, coal, [and] gas base load plants,” Colafella said. “It’s going to help foster properly functioning capacity markets.”

“Demand response presents absolutely zero reliability concerns,” Sawmiller noted. “It won’t freeze like a coal plant did during the polar vortex. In addition, it’s incredibly cheap. This applies downward pressure to capacity prices, lowering electric bills for all customers.”

“If FirstEnergy is able to reduce the amount of demand response that goes into these auctions, it will raise prices for customers,” Sawmiller added.

“Having demand response bid in lowers the price for all the generators that bid in,” Kushler agreed. Conversely, keeping demand response out would raise the auction’s closing price. In Kushler’s view, FirstEnergy’s attempt to exclude it is yet another “classic conflict of interest.”

The coal burning power companies like to tout their “steel in ground” as the ultimate in reliability, but Dan Sawmiller is right, coal does not do well in cold weather. Here is PJM’s report on the electric generation industries last January. The report highlights the fact that on January 7, 34% of the forced generation loss was from coal-fired plants.

So the AEP/FE, Kochtopus, Republican rollback of sane OH energy policy continues.

While in WV’s regulated market AEP and FE are shifting power plants from unregulated subsidiaries onto captive WV rate payers to  protect profits, in OH, the holding companies are manipulating rules under which their regulated retail companies operate to jack up profits for their unregulated generation companies.  In both states, both holding companies are playing rate payers and PSCs for chumps.


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.

FERC Staff Issues Preliminary Report on Winter Gas/Electric Problems

This winter’s series of cold spells in the US placed a serious strain on the ability of US power companies to meet significant spikes in peak demand.  The situation was compounded, because, in the last ten years, power companies have expanded the use of natural gas to generate electricity.  In the past, there was little connection between natural gas deliverability and the electrical system.  Now, the two systems are closely connected.  During summer peak load, there are few problems.  In winter peak periods, however, demand for gas causes rises in gas prices and fills pipeline capacity for heating, crowding out gas for electrical generation.  This winter’s experience has demonstrated that power companies and grid managers need to pay much more attention to these developments.

The staff at the Federal Energy Regulatory Commission has issued a preliminary report outlining causes and impacts of this winter’s colder weather.

One particularly interesting feature has nothing to do with gas-fired generation.  It turns out that significant problems with coal-fired and nuclear powered generators contributed to this winter’s crisis.

Mechanical failures in generator systems, fuel deliverability and fuel handling problems in the extreme low temperatures experienced this winter led to high levels of forced generation outages. These levels contributed to the stressed conditions in the markets that lead to emergency actions and higher prices.

During the early January event, the RTOs estimate generation on forced outages and derates ranged from about 7 to 30% of the load on the peak day. Significant portions of those outages were related to fuel issues including gas curtailments, no fuel, oil delivery and frozen coal. For example, PJM estimates that about one quarter of the forced generation outages on January 7 were fuel related. In addition, 5,000 MW of combustion turbines failed to start when called.  During the latter January events, gas curtailments declined in PJM as did start failures for combustion turbines. However lack of fuel, oil delivery and frozen coal persisted in causing forced outages of 5,000 MW and 8,000 MW in late January. Similarly, MISO experienced a large volume of outages on January 7, about 20% of those were fuel related, and lower but still significant outages during the later January cold weather events. NYISO also experienced a high level of fuel and cold weather related outages on January 7, which declined significantly during the latter January and early February cold events. Although SPP lost generation on January 6 due to gas supply constraints, they experienced no weather related outages during the later January and early February cold weather events. ISO-NE experienced a lower level of forced generation outages on January 7 relative to other RTOs, however all of the outages were attributed to intraday natural gas procurement difficulties. ISO-NE experienced similar levels of outages on January 22 and 27 with under 15% attributed to fuel issues. However, as noted above, these forced outages did not cause the ISO or RTOs to drop firm load and overall, generator performance generally improved after the January 7 event.

So the electrical system’s problems weren’t just caused by not enough natural gas pipeline capacity for both heating and power generation.  The cold weather affected all fossil fuel generation.  We know from FirstEnergy’s recent investor call  that the company was forced to buy electricity on the spot market just when prices were at their highest because one of their biggest coal burning units was down and a 960 MW unit of the company’s Beaver Valley nuke plant was down during the coldest weather.  Big base load generators are reliable, except when they aren’t.  When big units are down, they leave huge holes in the electric grid.

As the FERC staff’s report points out, despite a very complex combination of causes and effects, overall, the system was able to cope with the large number of problems.  And there was one important resource that did not depend on fuel at all.

Demand response resources were activated to help manage the emergency.  PJM activated about 2,000 MW of demand response resources for several hours during the morning and evening peaks of January 7.  Over 2,500 MW of demand response resources were activated for several hours on January 23 and on January 28.  NYISO requested voluntary reduction from about 900 MW of its demand resources on January 7.  Demand resources were notified of possible deployment on January 28, but were not activated.  ISO-NE’s Winter Procurement Program provided 21 MW of demand response on five occasions during the winter. MISO didnot activate their demand response programs during the winter events.

Note that 2500 MW is almost equal to a big coal-burning plant, such as WV’s John Amos.

The other interesting part of the report has to do with a new cost that has been introduced into the electrical system by deregulation.  Five of the last pages of the 21 page report deal with attempts by FERC to detect manipulation of electricity markets during the times when supplies were tightest and prices were peaking.  In times of crisis, as Enron demonstrated clearly in its California criminality, the big banks and energy traders have opportunities to feast on everyone else’s problems.  This is a cost that did not exist when all power companies were confined to state boundaries and were all regulated by state regulators.  The pages on manipulation lack the detail and statistical description that staffers used in the rest of the report.  That’s because traders’ actions are hard to detect in the millisecond operation of trades and transfers in the real time electricity markets.  It is likely that very little of the fraud and manipulation by energy traders ever faces FERC enforcement action.

The FERC report is a quick read and gives you a good snapshot of the brave new world of electricity that we now inhabit.

PATH Abandonment Case Moving Forward Again at FERC

Over a year ago, AEP/FirstEnergy began the process of trying to “recover” what they claim is $120 million that PJM rate payers, including rate payers in WV, owe them for the stranded costs in their failed PATH transmission project.  Here is my main post on the case from December 2012.

Since then, FERC referred the case for settlement discussions.  Because I am an intervenor in the case, I was bound by FERC rules to keep information on those talks confidential.  Settlement talks broke down last month, so the case was referred to a hearing judge to begin the process of moving the case toward a full evidentiary hearing.  And now the case is back on the public record, so I can continue covering it.

Those of you who are interested in following the case can see the documents that have been, and will be, filed in the case by typing the case number, which is ER12-2708.  FERC’s system is a little goofy, because they have dockets and case numbers all over the place, and your entry in the proper field must be the exact docket number in their system, or you can’t retrieve anything.  Go to this page and enter “ER12-2708” into the field labeled “Docket Number” and hit the submit button at the bottom of the page.  That will call up all the documents that have been filed in the PATH abandonment cost case to date.

You should follow this case, because it will have a direct impact on your electric bill if you live in the PJM region, as I do.  We got only cost and harm from the PATH project, now, under the Cheney administration’s transmission subsidy program, AEP/FirstEnergy want us to pay even more.

WV Rate Payers, Along with PJM Rate Payers, Facing $80.5 Million Charge for MAPP Line

Keryn has the story here on the new transmission line costs that will be hitting WV rate payers’ bills over the next three years or so.

Readers of The Power Line will remember that the MAPP line, one of the four new transmission lines envisioned by PJM and FERC in their Project Mountaineer described here and here, was killed off by PJM in 2012 along with PATH.

Keryn reports that PEPCO Holdings, the owner of MAPP, has just reached a settlement to collect $80.5 million from PJM rate payers under the Cheney Administration’s transmission subsidy plan passed in the 2005 Energy Policy Act.  A similar case to recover stranded costs for PATH is still pending at FERC.

As Keryn points out, the settlement will leave large tracts of key real estate in PEPCO Holdings’ hands free and clear while the company walks away with an $80.7 million gift from rate payers for an unnecessary and ill-conceived project.

Highly Centralized Eastern Interconnect Showing More Signs of Brittleness in Cold

The Eastern Interconnect, the inter-connected grid system that ties together all of the US and Canada east of the Rockies, except for most of Texas, is showing all the danger signs of hyper-centralization and dependence on high voltage transmission.  Back in early January, the first big cold snap caused PJM Interconnection to set a new winter peak load record and resulted in appeals to customers to reduce their electrical use.

Now we have this account of the multiple stresses that this winter’s cold weather is putting on our brittle electric grid.

An unprecedented 50,000 megawatts of power plant outages occurred east of the Rockies during last week’s cold snap, which also badly crimped natural gas delivery systems in key pockets of the country, federal and industry watchdog officials reported Thursday in analyses that raise more questions about reliability of the U.S. power grid as it becomes increasingly dependent on gas-fired generation.

The startling power plant outage data-which far exceeded outages seen in previous winter cold waves-were revealed by the North American Electric Reliability Corp. (NERC), the nation grid reliability watchdog, at a Federal Energy Regulatory Commission meeting.

FERC staff said the severe weather also significantly disrupted gas delivery by interstate pipelines and local distribution companies, and that cold temperatures also crimped gas production in some areas, including the Marcellus Shale.

Generally, the NERC and FERC reports described a series of extraordinary actions by grid operators, gas and electric utilities and pipeline operators that avoided widespread cuts in gas or power supplies for customers.

The new dependence of US electrical generation on natural gas has raised new threats to both electrical and natural gas systems as each system becomes more dependent on the other.  The problem is especially dangerous at winter electrical peak, because natural gas is also used for direct home and business heating.  Demand for both gas and electricity is at its highest for both power sources at the same time in extremely cold weather.  Shortages of gas cause shortages of electricity.  We saw this clearly last winter in New England.

As The Energy Daily notes, this problem has spread to PJM this year.

FERC Commissioner Philip Moeller said “early numbers” suggest that 9,000 MW of capacity in PJM was unable to get sufficient gas during the cold snap. That is somewhat surprising because other regions of the country, namely New England, are thought to be more exposed to reliability problems due to a growing dependence on gas for both power generation and heating.

FERC staff said New England was spared problems during the cold snap because temperatures there were actually “well below their all time winter peak,” requiring no emergency procedures.

Centralization and fossil fuel dependence to not promote electrical system reliability.  But you already knew that because you read The Power Line.

FirstEnergy Busted by FERC – Caught with Merger Costs in TrAIL FERC Accounts

Back in 2011, Keryn Newman busted FirstEnergy for illegally charging PJM rate payers for costs associated with the Allegheny Energy merger.

Her discovery finally bore fruit last Friday when FERC ordered FirstEnergy to pay us all back for its scam.

Here’s how Keryn describes it over at StopPATH WV:

This has been a long time in coming, but FirstEnergy was ordered on Friday to “submit a detailed plan for implementing audit staff’s recommendations and correcting journal entries reflecting an approximate $1.2 million refund to affected customers from its transmission-only subsidiaries with formula rate recovery mechanisms, including Trans-Allegheny Interstate Line Company, Potomac-Appalachian Transmission Highline, LLC, and American Transmission System, Incorporated.”

The first time this problem reared its ugly head was during the July 2011 PATH Open Meeting to review its 2010 actual transmission revenue requirement.  At this phone “meeting” I notified PATH that I had found expenses of the Allegheny Energy/FirstEnergy merger in its PATH rates.

In September, FirstEnergy subsidiaries PATH and TrAILCo made entries to their quarterly FERC financial filings to effect a credit for amounts wrongly charged to ratepayers in violation of the company’s “hold harmless” guarantee to the Commission that it would not charge merger expenses to ratepayers except under certain circumstances.  Over a million dollars was credited, but because PATH and TrAILCo made the correction in the normal course of business, it did not credit ratepayers for interest on the amounts wrongly recovered.

So all of us PJM rate payers owe Keryn and Ali a big thank you for their hard work fighting FirstEnergy’s scams at FERC.

Manchin Serves Masters, Opposes Binz for FERC Chairman

David Gutman has a story in today’s Charleston Gazette reporting that Sen. Joe Manchin has publicly declared that he will oppose President Obama’s nominee for FERC chairman in the Senate confirmation process.  Manchin is a member of the closely divided Senate Energy and Natural Resources Committee.

Without Manchin’s support, Binz would need the vote of at least one Republican on the Senate Energy Committee — an unlikely proposition — in order to progress to a confirmation vote by the full Senate.

Mr. Gutman’s story is a little confusing, but that’s not surprising, because Manchin always talks out of all sides of his mouth at once.  He quotes Manchin as opposing Binz because:

  1. “Manchin said a main reason he would not support Binz is because of Binz’s past work in transforming Colorado’s coal-fired power plants to natural gas.”
  2. “He’s [Binz] ideologically in a position where he believes we should be moving more to a renewable market that’s not as reliable.”
  3. “I’m for an all-in policy,” Manchin said.

So Manchin is for his usual “all-in” blather, but he says Binz is bad because Binz pushed for the expansion of natural gas and renewable sources to produce electricity.  Doesn’t sound like “all-in” to me.  Sounds like Manchin is a coal industry enforcer, as usual.

My friends in the natural gas industry in WV should be appalled at Manchin’s open hostility to the use of natural gas to produce electricity.

Oh, Joe, about that reliability issue – if renewable power is so unreliable, why are major companies across the US unplugging from the coal-oriented electrical grid and generating their own electricity with solar and natural gas generation?  Here is that story from today’s Wall Street Journal.

From big-box retailers to high-tech manufacturers, more companies across the country are producing their own power. Since 2006, the number of electricity-generation units at commercial and industrial sites has more than quadrupled to roughly 40,000 from about 10,000, according to federal statistics.

Experts say the trend is gaining momentum, spurred by falling prices for solar panels and natural gas, as well as a fear that power outages caused by major storms will become more common.

And that is just the kind of reliable electrical system that Ron Binz has supported for years.

Mr. Manchin continues to stand in the way of electrical reliability and innovation.  He did enough of that in WV.  We’ll now see how the rest of the country likes it.