For now, PSNH’s Bow plant saves ratepayers millions

Charlie Arlinghaus

April 2, 2014

As originally published in the New Hampshire Union Leader

When it costs more to heat your house, your electricity is cheaper. Actually there isn’t a direct correlation between the two but cold weather – and we’ve had plenty of it – drives both dynamics. One utility-owned power plant in New Hampshire is something of a political football but is currently saving ratepayers well over $100 million this year.

The electric market in New England is all about gas. The electric market is not state specific but regional and our region comprises the six New England states. Whether a power plant is in New Hampshire or Rhode Island is immaterial. Power is sold into a regional market which doesn’t care which state the plant is in.

The lion’s share of electricity in New England comes from natural gas so gas is said to set the price. Every resource bids into the market a price at which they are willing to supply a set amount of power. The sources are then “stacked” from least to highest bid until the power need is reached. All accepted providers then get that “clearing price” regardless of what their individual bids were. Gas generally sets the price as the last accepted bid.

As gas prices declined dramatically from 2008 through 2012, this was generally good for power purchasers and prices improved. It also helped that 2012 was a mild winter with few price spikes.

That’s because winter heating also affects electricity prices. Gas plants rely, to a large extent, on gas being shipped here through a pipeline that has limited capacity. But in the winter that gas is also used for home heating. The colder the winter, the more gas is used. Home heating use generally has first priority so if heating usage is high there is little gas left for electricity and its price is high.

Last winter, wholesale electric prices tended to be $40 or $50/MWh with occasional price spikes. This winter prices are generally over $100/MWh and topped out at $260 one week in January.

That price pressure has severely hurt many smaller independent energy suppliers and forced most of us to pay a lot more this winter. The one exception is for the approximately two-thirds of the state that has PSNH as their utility. PSNH is the only utility that still owns some of their own power plants – think of them as half-deregulated.

Why does that matter? Much of their capacity, about two-thirds,  comes from one coal plant in Bow. That plant doesn’t sell to the open market. Instead it runs when it’s cheaper and doesn’t run when the outside market is cheaper. When the market is $40/MWh it doesn’t run. But this winter it has run almost non-stop.

This means that this plant and others owned by PSNH  have saved their customers $115 million so far this winter. How? When it’s cheaper to run the utility-owned plant, customers save the difference between cost to run and the amount it would have cost to buy the power. The week when power was $260, customers saved the difference between that price and the roughly $45/MWh to generate their own power.

In addition, those customers save some additional money because PSNH receives what are called forward capacity payments – payments made to generators throughout the region to try and assure plants stay open so the region has enough power. The payments from the most recent auction will probably generate ratepayers about $50 million.

A bill before the legislature would require PSNH to sell all its power plants. Divestiture, as this plan is called, would cost not save ratepayers. The $115 million in operating savings, the $50 million in forward capital payments would go away with little in return. Some would hope to avoid pollution control payments for the Bow plant but that hope is forlorn.

The legislature mandated the new equipment under the rules that the utility pay up front and then receive a guaranteed return on that capital investment. Whether that was a good deal or bad, it can hardly be cancelled after the fact. Government may not and should not deal with businesses that way.

The electricity market is different today than it was five years ago and will be different again in five years – almost certainly in ways the government isn’t good at predicting. Right now the market struggles in the winter because of too much reliance on a limited supply of gas and not enough diversity of fuel supplies.

Whether the half-deregulated structure is where we would start or where we will end up, it’s savings ratepayers close to $200 million right now.  Right now, that’s sensible.

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Public Utilities Commission is power mad

Grant Bosse

As originally published in the Concord Monitor

The intelligent and hard-working members and staff at the New Hampshire Public Utilities Commission are working hard to lower your electric rate. They’re from the government, and they’re here to help.

The PUC and the New Hampshire Legislature have been trying to reduce New Hampshire’s shockingly high utility bills for a while now and have even introduced a sliver of market competition into the bureaucratic, over regulated, micromanaged labyrinth of electric rates.

Last week, the PUC recommended Public Service Company of New Hampshire, the state’s largest electric utility and the only one to generate much of its own power, sell its remaining generation assets. The Merrimack Station coal plant in Bow is at the heart of the issue.

The PUC report claims that while PSNH, a wholly owned subsidiary of Northeast Utilities, has more than $600 million worth of power plants on its books, the actual value of those plants is closer to $200 million. That burden forces the PUC to set PSNH’s rate for power generation well above its competitors. And as large, industrial customers and eventually more and more homeowners switch to a different supplier, those extra costs are spread among a smaller and smaller base of customers, forcing rates higher and customers to seek other options. This is known as the Death Spiral.

With natural gas prices below coal for the first time in history, PSNH runs Merrimack Station only 20 percent of the time, buying most of its power from natural gas plants.

The PUC wants PSNH to get out of the power generation business entirely and become solely a distributor. PSNH would still own and maintain the power lines, but it would get all of its kilowatts from someone else. It would still charge the distribution fees that are currently on your bill.

PSNH agrees that the costs drive its rates above the market, but faults the PUC for failing to point out why its

assets are more expensive than they are worth. Here’s why: In 2006, the Legislature passed a sweeping mercury reduction law, which mandated that PSNH install a wet flue gas desulphurization system at Merrimack Station, known as a scrubber.

The scrubber removes sulfur and mercury from the plant’s smokestacks, greatly reducing pollution. It’s also incredibly expensive. In fact, the scrubber’s $422 million price tag accounts for the entire difference between the book value and market value of PSNH’s power plants.

When the Legislature mandated scrubber construction, it limited PSNH’s ability to recover the costs to customers who actually buy power from PSNH. If PSNH delivers someone else’s power to you, you’re not paying for it. In effect, the cost of the scrubber alone drives PSNH’s default service rate well above market value. If the company could recover scrubber costs from its distribution and transmission customers, its power charge would be quite competitive.

Etna Republican Jim Rubens fought PSNH’s effort to recover “stranded costs” from ratepayers following the initial move toward electric competition in the 1990s, and he’s opposed paying for the scrubber ever since. He says if the Legislature forces PSNH to sell off its power plants at a loss, it would lead to stranded costs, Round 2.

“If PSNH were to divest, they would probably claim that ratepayers would be force to pick up the differential,” Rubens explained. “The sale price will probably be lower than the net book value.”

Rubens argues that if the Legislature had removed the mandate to build the scrubber, while requiring PSNH to meet the lower mercury emissions on its own, the company would have had a choice to retrofit Merrimack Station with a scrubber, buy power from other sources, or come up with another approach, without passing on the costs of complying on ratepayers.

This week, PSNH came back to the PUC asking to lower its energy generation charge by almost a full penny, from 9.54 cents per kilowatt hour to 8.62. This would bring is closer to its competitors, which currently advertise rates from 7.89 to 8.69 cents. The company says that a winter spike in natural gas prices has subsided, lowering its costs to acquire power. Scrubber costs make up 0.98 cents in both rates.

“It’s clearly a response to the marketplace. They’re bleeding customers,” Rubens responds. He sees the request as a tactic admission that PSNH’s default service charge is not competitive.

The Legislature spends a lot of time complaining about the high cost of electricity, but every move it makes drives that cost higher. The Regional Greenhouse Gas Initiative, Renewable Portfolio Standards and a $400 million scrubber may be justifiable for many reasons, but they all make ratepayers pay for them one way or another.

The PUC report not only fails to mention why PSNH’s generation assets are so expensive, it also neglects to address how much ratepayers would be charged for the write-off if PSNH were forced to divest. It makes huge assumptions about the unstable and unpredictable natural gas markets years into the future to conclude that it’s not worth burning coal at Merrimack Station anymore.

The PUC recommendation is the latest example of well-meaning bureaucrats trying to micromanage us to lower electric rates. It hasn’t worked out well so far.

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Too Many Questions About the Required Sale of Power Plants

Charlie Arlinghaus

March 23, 2012

As originally publish in the New Hampshire Union Leader

Requiring the sale of PSNH’s generating assets has the potential to cost New Hampshire ratepayers millions of dollars without a corresponding benefit. There may or may not be a long term benefit from selling off plants but today, there are more questions than answers and the issue is poorly understood.

PSNH is the state’s largest regulated utility. It is the electric company for the majority of the state’s customers and the only one of the four which owns some of its own power generation. Electric companies are part private company and part quasi-state agency. While they are organized as private companies, they don’t set their own prices or essentially do anything without permission and oversight from the Public Utilities Commission.

The provision of electricity is seen as a public purpose like the roads. While the roads for cars are state owned, the roads for electricity – the power lines – are instead contracted out to a privately managed company with a state overseer.

The misnamed electric deregulation didn’t deregulate the industry as much as it broke the monopoly on the provision of electricity itself. The transmission lines, the roads if you will, are still a monopoly but the power itself can be purchased from a number of suppliers. In practice, there is competition for larger business customers but little or no competition for residential customers.

Currently, the legislature is considering a plan called divestiture which would require that PSNH sell off all of its power plants and purchase its power on the market instead of generating it itself.

The debate over the wisdom of this plan is essentially between other electric generating companies which might now sell PSNH power to replace the plants it will be forced to sell and PSNH which would like to keep its own plants and own employees.

The debate is not really between market forces on one side and regulators on the other. No one is suggesting PSNH become a market company. It will still be regulated by the Public Utilities Commission, it will not have the authority to set its own prices, it will merely not produce any power.

The debate is over whether or not owning the plants saves ratepayers money. The costs associated with the power plants have been part of the state’s rate structure. Ratepayers have been paying off the plants for decades and now own them, largely, like a car that you finally paid off. The major exception is the mercury scrubber the legislature required the company to build on its coal plant, the cost of which would have to be recovered if sold

Because the plants are largely paid for, the power produced by those assets costs less than the price on the open, New England-wide power market. For many years it was much cheaper and saved ratepayers millions of dollars a year. With currently low prices for natural gas, the price difference is less but the in-house power is still cheaper. In each year, including the most years of lower gas prices, the utility’s own captive power has saved customers money over buying on the open market.

That alone is not enough reason to keep the assets. Frankly, if the price of coal skyrocketed and natural gas dropped even more, the past wouldn’t matter, only the future. To some extent, the legislature must make some broad guesses about the longer term trends of prices before it acts. Today, the price difference is a small factor weighing against selling the assets but we probably need much more information to decide.

The second critical factor in the sale of assets is the potential sale itself. Would a sale result in a price that doesn’t recover our stranded costs? Or is there potential to make money and give ratepayers a windfall?

Sale proponents are optimistic but it’s hard to find reason for their optimism. There is more research to be done (which is true of so much about this issue) but recent transactions do not indicate much interest in the purchase of old coal plants. Given the uncertainty of both regulation and fuel prices, this seems sensible today but could change in the near future.

A sale four or five years ago would have cost ratepayers millions in extra charges for electricity. Have things changed enough to require PSNH to sell its assets today or would that sale cost us millions? The short answer is that we don’t have enough information.

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RGGI in New Hampshire: The First Two Years

In 2008, New Hampshire joined a ten-state regional compact designed to reduce greenhouse gas emissions through a cap-and-trade program on electric generation facilities. This report examines how that program has been implemented in New Hampshire over the past two years, how much revenue has been generated from the sale of carbon allowances, and how New Hampshire officials have spent that money.

BACKGROUND
The Regional Greenhouse Gas Initiative is an agreement among ten Northeastern and Mid-Atlantic states to limit carbon dioxide emissions through a mandatory cap-and-trade scheme applying to fossil-fueled power plants. It is administered through a non-profit corporation, RGGI Inc., which contracts with private companies to administer and monitor quarterly auctions. RGGI includes Connecticut, Delaware, Maine, Maryland, Massachusetts, New Hampshire, New Jersey, New York, Rhode Island, and Vermont….

 

Read the full report here:

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The Coming Electricity Shortage in New England and What We Can Do About it

In New Hampshire and all of New England, the biggest threat to economic development that no one knows about is a looming energy crisis but not the one you think of. Everyone talks about the rising cost of gasoline but we are quietly and rapidly running out of electricity and face the threat of rolling blackouts as soon as 2008. New England is producing enough electricity today but the electricity needs of consumers are growing and a thriving economy will make those needs grow even faster. In a few short years, the capacity of existing power plants will no longer be enough to meet demand. Because new plants (and many existing plants) are not economically viable under current structures, the building of new plants has dried up.

Current market structures aren’t working to provide New England enough electricity even to meet today’s demands. Because of market failures, regional and federal regulators have instituted a stopgap measure (Reliability Must Run contracts) to prevent plants from closing. However, that stopgap approach does nothing to provide for the future. To address market failures and try to provide for future energy needs, New England’s electric grid operator, ISO-New England, has a proposal to replace the current patching efforts and provide incentives for the additional capacity New England’s economy needs. It is known as the Locational Installed Capacity Proposal (LICAP) and it is before the Federal Energy Regulatory Commission.

The looming crisis threatens New Hampshire and all of New England’s economy and is based in the complicated markets that ensure businesses and consumers have the electricity we take for granted. The market structures in electricity are quite different from a classic marketplace. Electricity is not a marketed good like, say, tomatoes. A producer doesn’t open a stand selling his product inventory bit by bit to people who may use it that day or next week. Electricity, in general, can’t be stored and must be readily available, in stock, every minute. Flipping on a light switch or running industrial machinery is not a negotiated shopping decision that uses a can of tomatoes from the root cellar. Rather, the electricity must be available to all customers at all times whether they decide to use it or not.

In the six New England states, making sure the needed power is produced and available is the responsibility of the regional grid operator, ISO-NE (Independent Service Operator, New England). In essence, it is the responsibility of the grid operator to make sure sufficient power is available (“capacity”) and generated by plants to meet the expected demand. They also ensure the produced power is transmitted over the electric grid to suppliers like your local utility.i

For enough power to be available to serve the market, it must both be generated and also be able to be transmitted to the appropriate location. In general, New England must be able to produce as much power as it uses. New England imports a small amount of power, mostly from Quebec, and exports an insignificant amount of power to New York. Net imports accounted for only 3.7% of energy use.

However, even within New England, transmission constraints – essentially outdated infrastructure – make it difficult to move some excess power from where it is generated to the location that needs more supply.ii These constraints make the location of some power capacity within New England more important than others.

New England as a whole is running out of power and some regions already have. Although New England set two new records for power usage this summer, existing resources – if none cease operations – are enough to support current use. However, electricity usage is growing by about 500 MW each year, the production capacity of one good-sized power plant. The grid operator estimates “that New England will be short of capacity in the 2008-2010 timeframe depending on weather and economic conditions.”iii Hotter days demand greater power and a growing economy will accelerate the need for more power. Given that it takes 2 to 3 years to bring a new power plant online, the capacity shortage will occur just after a plant would begin operations if development began today. In addition, Southwestern Connecticut, the most serious problem zone in New England, will have a shortage earlier, perhaps as soon as next year. Already the grid operator has been forced to develop temporary contracts for power to ensure reliability.

Without enough electricity, the grid operator would be forced to institute rolling blackouts as a form of rationing. Businesses considering expanding in or moving to New Hampshire would almost certainly avoid the unreliability of rationed electricity. Consider trying to run a retail center or major industrial facility with periodic blackouts.

This electricity shortfall occurs as new investment in generation (supply) has dried up. A new power plant will take 2 to 3 years of development and hundreds of millions of dollars before it comes online. Investment decisions made from about 1996 through 2000 led to almost 10,000 MW of new capacity coming into the system from 1996 through 2003. The new plants were generally cleaner and more efficient than the plants they replaced and account for about 30% of the current total capacity. But after 2,786 MW came online in 2002 and 2,949 MW in 2003, only 588 MW came online in 2004. The investment decisions made from 1996 through 2000 produced the new plants but the inability to recover invested capital has stopped any significant new production for years. The grid operator, ISO-New England, notes that investment stopped after price caps were placed on the market in 2000.iv

An analysis in ISO-NE’s annual report graphically illustrates the problem. A power plant receives revenue from two main sources: energy sales (and related services) and the capacity payments made to keep them online and available. Those revenue sources must be enough to cover the operating costs of the plant including the capital investment that was needed to build the plant. According to ISO-NE, a hypothetical new combined cycle gas plant would only recover about 50% of the necessary costs in today’s markets.v In an analysis of “incentives to invest in new generating capacity,” MIT Professor Paul Jaskow cites similar studies from the mid-Atlantic states to conclude that “existing capacity pricing mechanisms do not appear to yield revenues that fill the net revenue gap.”vi If the market does not support an investment’s ability to recover its costs and generate a competitive return, the capital needed to build a plant will not be available. Hence the collapse of investment in new plants.

In short, New England is rapidly running out of capacity and the current payment structure doesn’t support the operating costs of the plants that generate power, new or old. Not only is new power not being developed but existing capacity is in trouble as well.

The current approach to keeping enough plants open to meet demand is best described as a patching operation, a stopgap measure designed only to triage an unsustainable system until a solution can be put in place. It addresses a critical short-term problem but is not a workable system for the future.

New England’s power system relies increasingly on a system of “Reliability-Must-Run (RMR)” contracts. The number of plants that would choose to stay open while working to fix the market is not enough to ensure reliability – that the system has enough electricity to meet the current needs of businesses and consumers. Under the RMR contracts, some power plants that can’t afford to stay open are told by the regulators they must remain open to ensure reliable energy capacity. In exchange, the plant is given larger payments that allow it to cover its operating costs. The existence of such contracts is an explicit admission that the current capacity market does not allow a power producer to be financially viable. RMR contracts began as the economics of power plants became apparent a few years ago. In 2004, RMR contracts doubled from $82 million to $165 million covering 2,342 MW. In the first part of 2005, the amount of capacity covered increased by 20% to 2,707 MW. An additional 4,625 MW are awaiting approval, a total that would more than triple the amount of capacity under reliability contracts.vii

So, under the current system, capacity payments don’t cover the operating costs of a new plant. Some plants – a larger and larger number – are given supplemental payments to keep them from closing. Others struggle economically under the inadequate capacity payment structure. Without a new structure, new power plants needed to address the growing demand won’t be built and the patchwork of plants operating under reliability contracts, already exploding, will continue to swell. The scope of reliability contracts has already grown from a few exceptions to a system with one group of producers operating under the RMR system and a second group, those who have not yet received RMR approval, being treated dramatically differently.

To meet the needs of electricity users, ensure the viability of power generation in New England, and replace the stopgap RMR system, ISO-New England proposed a new system called LICAP – Locational Installed Capacity.viii Essentially, the LICAP system increases capacity payments to improve the financial viability of plants but does so in a targeted way. Capacity payments are higher in areas with greater need than they are in areas with sufficient power. This market mechanism recognizes an economic reality: new generation is in greater demand and therefore more valuable in some areas like Southwest Connecticut that don’t have enough power than it is areas with a surplus of power, like Maine. For that reason, the new proposal also divides New England into five zones for this purpose: Southwest Connecticut, Rest of Connecticut, Northeast Massachusetts, Maine, and the rest of New England (including New Hampshire, Vermont, Rhode Island, and parts of Massachusetts).

In addition, plants are rewarded to the extent that they contribute to ensuring reliability – the ready availability of power. Just as needs are more critical in certain areas, there are also greater needs during certain times. Capacity payments are structured along a demand curve that reflects the realities of market needs at a given time.ix

Additionally, and importantly, actual energy revenues are deducted from capacity payments. Capacity payments are designed – like the current reliability agreements – to bridge the gap between energy revenue and operating costs. As revenues increase, those bridge payments ought to be smaller.

Shifting part of the generation cost of electricity into capacity and reliability should encourage a diversity of fuel sources reducing the economically risky reliance on any one source. A massive build up of gas plants when gas was inexpensive backfired as natural gas prices soared. A capacity incentive that cuts across fuel sources helps encourage a diversity of fuel sources (wind, nuclear, coal) limiting the economy’s exposure to spikes in any one fuel.

One objection to the plan is that while LICAP improves the economics of operating a plant, it does not guarantee new development. Well, of course not. No structure can force private investors to do anything. New structures can merely eliminate the obstacle that is preventing investment. Through RMR payments, we have recognized that the current capacity market payments prevent investment in new generation and forcing us to keep plants open through patchwork agreements. A new, economically viable system will keep some plants from closing and eliminate the barriers to new investment. Having a stable and secure revenue stream is the most important part of securing financing for plant construction.

The overall cost of the plan has been the subject of the most strident arguments. As the discussion of capacity markets has developed over the last two years, most observers have come to the conclusion that something must be done. The cost of doing nothing is incalculable.

Early estimates included claims by New Hampshire’s utility regulatory staff that costs could be as high as $10 billion over five years.x A year later those early estimates are seen as too high and uncorrected for existing expenditures and the growing RMR payments. ISO-New England has estimated the costs at $2.3 billion over five years after adding the cost of the new program and subtracting existing payments. A better study by the New England Power Generators Association details the increased cost of the program at $2.5 billion over five years after deducting current costs like the existing capacity program and current RMR payments.xi Even that estimate is probably too high as it maintains current RMR costs. As we’ve seen, stopgap RMR payments would increase dramatically in coming years if no changes were made.

The current system cannot and will not supply enough electricity to meet the needs of businesses and consumers. Demand is increasing and new plants cannot be built because the current market structure will not cover investors’ costs. Investors, being rational, will invest elsewhere. What’s more, current electricity is being propped up by an ever increasing series of stop gap payments being made to require plants to stay open because New England won’t have enough electricity without them – the literal meaning of reliability-must-run. The status quo is untenable and change is required.

1 This is a very simplified version of the complex operations performed by the regional transmission organizations. For a more comprehensive look at the services and obligations of ISO-NE, see their annual report: ISO New England 2004 Annual Markets Report, 15 July 2005, http://www.iso-ne.org/markets/mkt_anlys_rpts/annl_mkt_rpts/index.html.

2 There is a more detailed analysis of infrastructure problems in the ISO New England annual report. For a very accessible description of some of the economic costs and opportunities posed by transmission infrastructure see Dr. Lisa Shapiro, “Transmission Transition: Toward an Efficient Electricity Grid,” 2002 October (for publication in Energy User News but available on the web), http://www.gcglaw.com/resources/energy/transmission.html.

3 See ISO-NE Response Letter to the Connecticut Congressional Delegation on LICAP, 24 August 2005, http://www.iso-ne.com/pubs/pubcomm/corr/2005/ct_delegation_letter_8_24_05.pdf.

4 See The ISO-NE response letter to New England Governors on LICAP, 25 July 2005, http://www.iso-ne.com/pubs/
pubcomm/corr/2005/ne_governors_letter.pdf.

5 See ISO New England 2004 Annual Market Report, p. 111-112.

6 Paul L. Jaskow, “Markets for Power in the United States: An Interim Assessment,” 2005 August, forthcoming in The Energy Journal. http://econ-www.mit.edu/faculty/download_pdf.php?id=1219.

7 See ISO New England 2004 Annual Markets Report, p. 78-79.

8 The ISO proposal is based on principles outlined in Peter Cramton and Steven Stoft, “A Capacity Market that Makes Sense,” forthcoming 2005 August, Electricity Journal.

9 The details of a demand curve and the principles behind are described in great detail in Cramton and Stott’s paper. While the nuances of the curve are open to some discussion, they are beyond the scope of this explanation.

10 See comments of New Hampshire utility commissioners and Office of Consumer Advocate for example: http://www.oca.nh.gov/Docs/ISO%20press%20release%2011-9-04.pdf.

11 NEGPA Technical Bulletin: “Estimating the Cost of LICAP,” 19 July 2005.

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