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Maine’s Self Inflicted Wound: Central Maine Power Company

Let’s get this upfront right away: Central Maine Power Company (CMP) metrics and reputation for reliability and customer service are less than desirable.[i]  CMP has created such enmity among its customers that some legislators in Maine would rather forego reducing greenhouse gas emissions by blocking a vital CMP transmission line as well as attempting to take the utility over to form a “consumer-owned utility”. CMP operates i accordance with the rules it is given. Maine’s PUC and its legislature can fix this problem, and the easiest solution to fix this problem is in their hands: performance-based rates.

Rate Regulation

A bit of history first. Electric utilities began to be regulated as monopolies early in the early 1900’s and what evolved was what is now called “cost of service” regulation. Essentially a utility is allowed to charge an amount that recovers its allowable expenses as well as a fixed return on its investment. This model encouraged new investment by utilities to grow their systems while keeping rates down by limiting their profits. It worked quite well through the 1980’s, spurring economic growth throughout the country. Beginning in the ‘80s deregulation began, opening up competition at both the retail and wholesale level. Some utilities took advantage of this hybrid of deregulation and the cost-of-service (COS) model, such that misguided investments were made with the belief that they would automatically be recovered in rates, and at the same time, customer service and reliability began to drop in some areas. Several states began to enact “incentive-based ratemaking” or “performance-based ratemaking” to counter this problem.

Performance Based Ratemaking

Currently 16 states have some form of advanced PBR.

Source: Navigant Consulting

The basic differences between traditional regulation and PBR are shown in the table below.

Source: Advanced Energy Economy

Performance incentive mechanisms can be designed to assess safety and reliability, customer satisfaction, facilitating customer owned generation and adopting of energy efficiency programs.

Hawaii

Hawaii is the latest and most advanced version of PBR in the US. Hawaii’s implemented its version of PBR last June. It illustrates one way this approach can work to end the COS “spend money to make money” model.[ii] Hawaiian Electric Company is required to submit a 5-year plan that begins with fixed rates the first year and limits annual rate increases to three factors: inflation; unforeseen events; and a “productivity factor.” The productivity factor is based on how Hawaiian Electric does in terms of customer experience, utility performance and desired societal outcomes. See chart below.

Source: State of Hawaii Public Utility Commission

If Hawaiian Electric reduces its costs beneath the annual limits, it can keep the difference; if its costs exceed the limits it takes a loss.

Maine

Let’s go back to the J.D. Power study. 4 of the 6 utilities that scored above average in CMP’s category (East Large) all operate in states where some form of PBR exists. So what about Maine? Maine has no performance standards, none. Maine’s regulatory structure is an anachronism and follows last century’s cost of service model. Is it any wonder that CMP’s performance is as poor as it is?

Empty Excuses

You’ll here two major objections to fixing CMP with PBR: we tried it and it didn’t work; and the Hope Supreme Court decision prevents us from penalizing CMP. They are nonsense.

Maine experimented with a very rudimentary form of PBR twenty years ago. Poorly constructed and not having the advantage of today’s technology, it was deemed a failure.

A Supreme Court case, FERC v. Hope Natural Gas, is frequently cited by opponents of PBR as prohibiting a penalty on utilities that threatened a reasonable rate of return. Washington State, Virginia, Florida, and Minnesota have all successfully navigated the precedent of this case to implement PBR multi year rate plans.

Bottom Line

A long time ago while working for a utility, a friend quipped “The number one core competency of investor-owned utilities is to make sure no one changes the rules.” CMP behaves the way it does because that’s what the rules allow it to be, and it has been very successful making sure they do not change.

Change the rules and the behavior will change.

[i] https://www.jdpower.com/business/press-releases/2020-electric-utility-residential-customer-satisfaction-study. 

[ii] https://puc.hawaii.gov/wp-content/uploads/2019/05/PBR-Phase-1-DO-1-Page-Press-Release.05-23-2019.Final_.pdf

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Is personal responsibility overemphasized as a climate solution?

Watched a fascinating YouTube video on climate change and personal responsibility. It is well worth the 15 minutes or so to watch all the way through (URL at the end of this article) but if you don’t have the time, let me summarize it for you. In a nutshell, while taking personal responsibility for actions to mitigate greenhouse gas emissions (GHGE) is laudable, too much focus on individual actions can distract us from what really needs to happen.

But let’s take a step back and establish the context. Most people are aware that nearly everything we do to make our lives more comfortable – eat, wear clothes, drive vehicles, condition the air, using electricity, build buildings and roads – is destructive to the environment. We know that the big sources of GHGE are building heat, internal combustion engines, power plants. But many of us lack perspective on how much influence taking action on one front affects the other. Consider that the emissions resulting from making one new electric car is equivalent to that resulting from building 6 feet of roadway. So if we continue to build roads, switching to electric cars is not going to have a huge impact.

We need to also consider the sources of these emissions and the divide between rich and poor. Just having the richest nations cut back on their lifestyles is important, but the fact is that 63% of global GHGE comes from low to middle income countries. They are not living extravagantly, and, in actual fact, many are trying to simply escape poverty and become middle class. So, telling them to reduce emissions looks a lot like trying to keep them from improving their lot in life.  And telling countries to build solar and stop burning wood when they cannot meet basic needs doesn’t help. Consider this- a cheap and easy way for developing countries to build affordable housing is by using concrete. But concrete manufacture accounts for 8% of global GHG emissions. For some of these countries, more GHGE is a good thing.

Right now, the global population is nearly 8 billion and will exceed 10 billion by the end of this century. Animal based food production constitutes 57% of global GHGE, using 40% of the world’s habitable land. Eating less meat alone won’t stop climate change, but we can’t stop climate change without eating less meat.

Here’s where the personal responsibility discussion comes in. We’ve all heard the exhortations for everyone to do their part. Eat less meat, buy an electric vehicle, double glaze your windows, use heat pumps, turn off lights when not in use – the list goes on. We don’t appreciate the scale of the problem when this happens. During COVID most of the world’s population did many of these things, yet the total reduction in GHGE in 2020 was 7%.

The personal responsibility argument has been one of the most effective and sinister attempts to distract us from the reality of the situation. Few know that this argument about reducing your carbon footprint originated in 2005 when it was popularized by the oil producer, BP. The fact is that if a person eliminated all GHGE over a 70 year lifespan it would amount to 1 second of emissions from the global energy sector.

The best you can do is deal with the realities of the situation. You can promote your priorities through your behavior. If you choose to eat less meat or drive an electric vehicle and can afford to do so, great. But don’t do it because you feel guilty by not doing so. Do it because you will be doing your tiny, tiny part for systemic change we need.

What this means is that we need to appreciate the magnitude of this problem and focus on systemic change in technology development, politics, and the economy. Major investments and incentives in technological solutions are necessary. And as more people direct their purchasing to items that play a role in reducing GHGE, their costs will come down. Significant progress can be made by influencing those large levers in that system – politicians, technologists and industries – by people at the ballot box and by voting with their buying power.

So do your part with lifestyle changes AND make sure to elect the right people to pull the levers!

Kurtzgesagt YouTube video: https://www.youtube.com/watch?v=yiw6_JakZFc&t=318s

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Maine’s binary choice: achieve climate action goals or try to create “Consumer Owned Utility” (Update)

If you vote in person in Maine this year, you will likely be asked to sign a petition to put a referendum on the ballot to replace CMP and Emera with a “consumer owned utility.” Don’t be tempted.

Unable to make their case in the Legislature (twice), the proponents want to tap well-deserved outrage over the abysmal reliability and customer service of these utilities to get signatures on a petition to endrun the legislative process. They are making their argument using misrepresentations, half-truths and false promises, such as these five claims:

Claim 1: There will be $9 billion in savings

This assertion came from an “analysis” where a financial model was manipulated using incredulous assumptions. This model was created by London Economics International (LEI) as part of their analysis for the Maine Legislature. LEI’s original analysis came to no such conclusion. In their rebuttal to this manipulation of their model, LEI pointed out numerous and substantial errors in these changed assumptions. For example, nearly half of the savings comes from his unique interpretation – referred to as “gaming” by LEI – of Federal Energy Regulatory Commission (FERC) rules, whereby other utilities in New England would effectively subsidize Pine Tree Power.

The fact is that the advocates have never provided their own analysis or business case, and have no idea what this will cost to implement. They rely, instead on the simplistic claim that Pine Tree will have lower interest rates and that makes all the difference. It doesn’t. The fact is that anyone alledging to forecast a single number like $9 billion without also identifying what they believe the likelihood of achieving such savings is being intellectually dishonest.

Claim 2: Pine Tree Power would lower rates and increase reliability

This claim comes from a comparison of average rates and reliability of publicly owned utilities (excludes rural cooperatives) compared with investor owned utilities. Only 5 of the 2,100 utilities they used for comparison are as large as or larger than what Pine Tree Power would be: Salt River Project, Long Island Power Authority, Los Angeles Department of Water and Power, City of San Antonio, and the Sacramento Municipal Utility District. CMP and Emera are so bad, all of these have better reliability. The average rates of these 5 are more or less the same as the average of CMP and Emera. There are plenty of publicly owned utilities with much worse reliability and higher costs than CMP.

Claim 3: When Long Island Power Authority was created rates dropped 20%

Consumer rates did drop when New York took over Long Island Lighting Company and formed LIPA, but only because debt payments were postponed far enough into the future to lower rates artificially. LIPA is the only comparable takeover of an electric utility by a state — it took 13 years to finish, and after 23 years has not resulted in improved reliability or cheaper rates. Recently, out of desperation, LIPA hired a New Jersey investor-owned utility to run things.

Claim 4: COUs were first to reach 100% renewables

Customers do not have choice of supplier in any of the 6 utilities identified, whereas Pine Tree would be required to offer choice. Two of the utilities generate their own power which their customers must take. Pine Tree is not allowed by law to generate any electricity. But here’s the clincher. Four of them simply chose to buy renewables for their systems, and since their customers have no choice, they are “100% renewables.” That’s just contracting for power, and any utility can do it.

Claim 5: It can be done in a year or two.

Since 2000, more than 60 such utility takeovers have been attempted; 51 did not complete, and of the nine that did, two sold their systems back to the IOU. (CEA)

Bottom Line

What seems lost on the legislature is that CMP’s poor performance exists primarily because the regulatory structure and especially the Maine Public Utilities Commission have failed to do their job. Proper, modern, performance-based rate regulation, as practiced in other states, could solve this problem and do it expeditiously. In fact, here’s how: https://worthingtonsawtelle.com/maines-self-inflicted-wound-central-maine-power-company/

Attempting to take over CMP and Emera could last five to 10 years, slowing or halting the regulatory changes needed to bring the Maine distribution grid into the 21st Century and threatening the timely implementation of Maine’s decarbonization goals. And in the end, an attempted takeover could fail anyway. Maine does not have the time.

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The Clean Energy Corridor Clarified

You have seen the signs and the TV ads regarding the New England Clean Energy Corridor (NECEC), aka the transmission line from Quebec to just above Lewiston.

While the following goes into some detail about the Corridor, the bottom line to voters is simply this: by allowing the Corridor to operate, voting “NO” assures as much as a 15% immediate reduction in the carbon content of electricity delivered to New England customers. A YES vote assures a significant number of natural gas power plants, which emit carbon, will continue to operate.

We hope the information below will lead to an informed choice when voters decide this issue in November.

The delivered electricity does not go directly to Massachusetts.

When the power leaves the NECEC just north of Lewiston it enters the six-state New England Power Pool and is instantaneously blended with all the power in the system. It is pohysically impossible to inject power into the grid and have it go to one state or confine it to any state. There are no direct paths to Massachusetts or any other states; there are no state grids. It is all interconnected. Massachusetts residents are paying for that power and getting most of the environmental credit, but many people do not understand that in power grids, dollars do not flow with electrons.

One way to think of this system is to visualize a very large bathtub that has multiple faucets filling it and multiple drains emptying it. The tub is the grid, and grid operators must constantly match “water” coming in from power plants and other transmission lines with water draining (consumption) to keep the level of water perfectly level. The NECEC is just one more faucet, and when its water is released it blends with everything there. This “bathtub” is the six-state region of New England. There are no state “bathtubs.” When the power enters the bathtub in Lewiston, it is instantly blended with all the other power sources: NECEC power goes to every customer in New England.

Greenhouse gas content of New England grid electricity is reduced.

When this new NECEC faucet adds a huge amount of water into the tub, but no new drains are added, an equal amount of water (electricity) that had been pouring into the tub needs to be shut off. The operators turn off units, highest cost first. In the New England pool, the units displaced would all be natural gas fired plants.

These natural gas plants emit about 4.3 million tons of greenhouse gases. In 2019, the New England grid emitted 30 million tons; by displacing them with zero emissions electricity, the NECEC could lower greenhouse gas intensity by between 10% and 15%. Millions of dollars from natural gas power plant and pipeline operators are funding opposition to the line, as it represents a real threat.

The details of ISO-NE operations are described best here: https://www.iso-ne.com/about/what-we-do/three-roles/operating-grid, but briefly put, the operators are constantly trying to both monitor and forecast energy needs.

ISO-NE operations are described in more detail here https://www.iso-ne.com/about/what-we-do/three-roles/operating-grid, but briefly put, the operators are constantly trying to both monitor and forecast demand. They then dispatch generation, according to cost from low to high, to meet that demand. Since there is always some level of demand, many generators run 24/7.

At a capacity of 1.2 Gigawatts, NECEC will import 10.5 billion kilowatt hours (kWh) annually. ISO-NE consumption in 2019 was 97.8 billion kWh. Coming in all at once, and without reducing demand, an equal amount of generation will need to be turned off. The following chart shows which type of units were dispatched to meet that load last year.

Natural gas units are the ones that will be displaced.

There are 89 natural gas fired power plants in ISO-NE that operated in 2019. Their carbon emissions vary widely from plant to plant, irrespective of size. Not all these plants would necessarily shut down when the NECEC operates, because some are only used to meet a few hours of high peak demand. The top 85% largest units have an emissions average of .00056 tons/kWh. However, the system average for all of these plants, according to EPA data, is .0005 tons CO2 per kWh. The largest of these units (Lake Road in CT and Fore River in Mass) , emit .00043 and .00044 tons/kWh. Using the metrics from these two largest plants, the NECEC offsets 10 billion kWh, or about 4.3 million tons of CO2. The ISO-NE system emitted 30 million tons in 2019, so the NECEC would cause a 15% reduction.

Another analysis concluded that the minimum reduction would be 3 million tons, or about a 10 % reduction. https://www.energy.gov/sites/default/files/2020/10/f79/2020-2-14%20ATTACHMENT%20E%5B11727752v1%5D%20%282%29.PDF

Reducing Maine’s baseline carbon intensity for grid electricity is therefore between 10% and 15%

Maine ratepayers do get lower electricity costs.

Whenever electricity moves around the grid, the amount flowing depends on where the demand might be. Putting all this new capacity into the grid in Maine will reduce the amount of power flowing north, thereby reducing transmission costs for Maine ratepayers. According to the Maine Public Utility Commission, the NECEC will save customers power costs and other charges between $23 and $63 million annually for 20 years and the State will receive a benefits package of $258 million for a low-income customer benefits fund, a  rate relief fund, a broadband fund, a heat pump fund and funding for electric vehicle charging stations.

https://www.clf.org/wp-content/uploads/2019/02/2019-02-21-NECEC-Stipulation-2017-00232.pdf

These values do not include this addition: https://www.pressherald.com/2020/07/10/facing-referendum-cmp-corridor-backers-negotiate-258-million-incentive-package-for-mainers/

When Quebec Hydro exports this power, it will not replace it with fossil units.

           Hydro Quebec has the capacity to generate over 37 billion watts, of which 0.4 billion watts is fossil – less than 1%. This generation serves its domestic load, including exports and has enormous excess hydroelectric capacity. The NECEC export is about 1.2 billion watts. The New England grid is part of a larger network that includes New Brunswick, Quebec, Ontario and New York. Hydro Quebec adds 1.2 billion watts to its output and sends it to New England, where 1.2 billion watts of natural gas power is turned off. It is that simple.

The details

Hydro Quebec’s energy generation sources include the following (source: Canada Energy Regulator):

Data on surpluses: https://www.hydroquebec.com/data/achats-electricite-quebec/pdf/electricity-supply-plan-2020-2029.pdf

The pristine forest is not pristine and is not a huge loss of carbon absorbing trees.

Only 53 miles of the corridor is newly clear-cut, a 54-foot-wide swath. That stretch is commercially logged land, already crisscrossed with roads. The remainder of the line is already cut and will be slightly widened. This 53 miles of corridor is about 349 acres. Maine’s forests absorb about 2.5 to 4 metric tons of carbon per acre. That “lost” forest would have absorbed between 872 and 1,396 metric tons of carbon a year. When the NECEC operates, between 3 million and 4.5 million metric tons of carbon will not be emitted from natural gas power plants.

The tradeoff.

Replacing fossil fuels with decarbonized grid electricity is a key strategy to achieve Maine’s, and the region’s, climate goals. The NECEC is critical to effective climate action: it will substantially reduce the greenhouse gases now emitted by New England grid electricity. The tradeoff is a small price to pay for the enormous reduction in harmful emissions.

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Evaluation of Costs and Benefits of Combining CMP and Emera into the Maine Power Delivery Authority – a Summary

Last spring a bill (LD 1646) was presented in the Maine Legislature that sought to acquire the assets of Central Maine Power and Emera (Maine’s investor owned utilities – IOUs) in order to create the Maine Power Delivery Authority (MPDA), a quasi-governmental “consumer owned” transmission and distribution utility. (See blog article of May 14, 2019, “Maine wants to create a Power Authority: a bad idea”). The bill was held pending completion of an assessment of the costs and benefits of such an action, to be performed by a third party.  That assessment was released on February 14 and is summarized here. The most favorable reading of this analysis would conclude that the concept requires further analysis and that significant structural revision of the bill is necessary if it is to achieve any of its goals.  A less favorable conclusion is that converting Maine’s IOUs into a single government agency has very little likelihood of reducing costs or improving reliability.

The analysis, completed by London Economics International, created a “Status Quo Scenario” that assumes the current structure is maintained and an MPDA Scenario that assumes the takeover occurs as described in the bill: both scenarios use the same assumptions for load growth.  Rate payer impacts were then evaluated and compared under each scenario. In addition, the report considered the likely barriers to the MPDA Scenario; legal issues; and likely timing among other factors.

Impact on ratepayer costs

Under the MPDA Scenario, Maine ratepayers may face higher electric bills for at least the next 10 and perhaps as many as 22 years. After this initial period there is a possibility that rates would then see a savings over the Status Quo because the MPDA could have cheaper financing.

The maximum additional cost or savings to the ratepayer is no more than 5% over Status Quo.

Ratepayer savings vs tax revenue

The reduction in ratepayer bills will come partly from the tax exempt status of MPDA, foregoing paying local, state, and federal taxes.  The consequence, however, is that Maine taxpayers would lose this revenue, causing taxes to go up by a like amount or reduction in services.

The MPDA is to be operated by a for-profit third party contractor, most likely a subsidiary of another IOU. Part of the lower customer bills would come If their management fees are less than the current returns for the IOUs, the Status Quo tax revenues from these services would also decline.

Electric utility unions vs ratepayer bills

Lower electric bills also are achieved by lowering the cost of labor, however the bill retains all Maine based unionized employees, who will want to preserve job security and see higher compensation.

Transaction cost is the single biggest parameter

The cost of acquiring the utility assets is the single most important factor in determining what will happen to customer costs. The 10 year breakeven point for costs occurs if the utility assets are acquired at about 1.5 times net book value (NBV), about the same valuation as Emera’s current possible buyer is considering.  But if assets are valued at even 1.7 times NBV, the 22 year payback comes into play.

Establishing that valuation will not be easy and could end up in protracted litigation that exceeds 4 years. Both CMP and Emera made it clear in earlier testimony that they saw their valuation at 2 times NBV.

The study made a point of correcting several assumptions that were used to “sell” the idea. The bill as written would not:

  • Give control to ratepayers but rather to a board that does not solely represent their interests; in fact it reduces PUC control over rates
  • Reduce administrative and management costs of transmission and distribution
  • Provide financial benefits to local residents.
  • Guarantee improvements in reliability.

In fact, as to the last bullet, the study states “Based on empirical evidence from the US Energy Information Administration (“EIA”), the ownership structure of a utility (i.e., customer-owned utility such as a cooperative versus an investor-owned utility) is not a clear-cut predictor of performance.”

Conclusions

The report makes the following recommendations regarding LD 1646: reconsider or revise how it defines MPDA’s board structure; not reduce PUC control over rates; define the standards of service by the MPDA; resolve the purchase price before eminent domain is considered; reconsider the clauses relating to union labor; and revise language regarding local property taxes and sales tax. LEI also recommends several procedural changes and clarifications to the bill as well as further study of the

  • Tax issues
  • Future capital needs to improve the reliability of the transmission and distribution network
  • Develop optimized financing and capital structure of MPDA
  • Define procurement process for the contractor that is in synch with other recommendations and goals.

If this concept is to be legislated, the bill as currently proposed requires major rework and then only after several key topics are more thoroughly examined.  Trying to rush this bill through this shortened legislative session would be a disservice to the State of Maine and its ratepayers, who deserve a very level of care in the design and implementation of such a significant change in their electricity delivery system.

The full study is available here:

LEI-COU-ReportDownload
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Maine wants to take over its investor owned utilities: a bad idea

The following is testimony offered in opposition to Maine Bill LD 1646 “An Act To Restore Local Ownership and Control of Maine’s Power Delivery Systems.” This bill creates the Maine Power Delivery Authority by acquiring and operating all transmission and distribution systems in the State currently operated by the investor-owned transmission and distribution utilities known as Central Maine Power Company and Emera Maine.

Senator Lawrence, Representative Berry, members of the Joint Committee, my name is Gerry Runte. I am a constituent of Senator Lawrence and live in York.  Thank you for the opportunity to testify today in opposition to LD 1646.

LD 1646 is an attempt to cure several ailments currently afflicting Maine’s investor owned utilities (IOUs): high consumer rates; extraordinarily poor reliability; and operational strategies that are a barrier to the adoption of 21st century electric utility business models as well as to aggressive actions on mitigating greenhouse gas emissions.  They are all very real. The cure proposed by LD 1646, however, is very likely to be much worse than the illness.  Indeed, there are far more efficacious measures that can be taken.

LD 1646 is being rationalized using statistics that show one in seven customers of electric rate payers are served by consumer owned utilities (COUs); their average reliability is higher than investor owned utilities and their rates are, on average lower.  However intriguing, these statistics are very misleading and irrelevant to the situation at hand.

Portraying these metrics to claim that becoming a consumer owned utility results in lower cost and higher reliability is grossly misleading.  These statistics average values for over 2,000 utilities, masking the fact that many have metrics that are far worse than Maine’s IOUs. The average customer base of these utilities is about 24,000, far smaller and much less complex than the utility LD 1646 would create.  While their average cost of electricity is lower than the IOU average, many have significantly higher rates than CMP, including all of those with 1 million or more customers – the group most comparable to the entity LD 1646 wants to create.

The statistics are irrelevant because 98 % of these utilities began life as consumer owned utilities.  Their system design, infrastructure, costs and regulatory structure have evolved together as an integrated whole.  Taking over an investor owned utility’s territory – one designed, developed and operated under an entirely different structure – and converting it to a COU is extraordinarily rare and in all but one case, involved municipalities withdrawing from the territory of the incumbent investor owned.   “Municipalization” is rare for a reason: the costs can way overwhelm whatever benefits were assumed. Ask the District of Columbia or San Francisco about why they decided not to proceed. 

There is, however, one case that is relevant to LD 1646, where a state did take over a long-established IOU and converted it to a COU.  It is a case that merits a very careful look by the supporters of LD 1646 because it is the only point of comparison to what this bill intends to accomplish.  In 1998 the State of New York took over the Long Island Lighting Company (LILCO), an investor owned electric utility.  They spun off out the generation assets and sold a portion of the distribution and all its natural gas assets to Brooklyn Union Gas (forming Keyspan Energy). The remaining portion of the distribution company formed the Long Island Lighting Authority (LIPA).  LIPA serves 1.1 million customers, several hundred thousand more than CMP and Emera combined. Fifteen years after formation LIPA was one of the most expensive and most unreliable utilities in the US. After LIPA was decimated by Hurricane Sandy, the State of New York hired Public Service Electric and Gas (PSEG), a New Jersey investor owned utility, to take LIPA over and run it under contract.  Reliability has improved, but LIPA’s rates are still much higher than CMP or Emera.  PSEG is one of the top 5 most reliable utilities in the country.

Nonetheless, the issues with CMP and Emera remain, but there is a remedy that would be far more efficacious than creating a power authority.  CMP and Emera operate according to business plans that are specifically designed to maximize shareholder earnings under the rules established by the Public Utility Commission based on the concept of cost of service regulation. Cost of service regulation – the form of regulation that rewards capital investment with guaranteed returns – is nearly 100 years old and is the functional equivalent of rotary dial telephones in a digital age.  Cost of service regulation was designed to promote the rapid expansion of electric utility infrastructure under the monopoly utility model and get electricity to customers at the lowest cost.  It worked well, but it is now an anachronism, yet that is what drives the business plans and operational philosophy of these two IOUs.

Other jurisdictions have recognized this problem and have made major strides in promulgating 21st century regulatory frameworks that not only remold the IOUs approach to the business.  In some cases, IOUs have even become advocates of these measures, rather than constant obstacles to progress.  Innovative rate reform can take many forms, but its root is in the recognition of several key elements:

  • The grid is increasingly operated as a two-way network that will be integrating across sectors (e.g., electric vehicles)
  • Real time monitoring and data collection is available and useful to gauge performance
  • Heavy utilization of distributed generation as both a source and as a T&D asset
  • Demand side management is vital
  • Greenhouse gas emissions performance key metric
  • All costs are temporal and locational

The key to resolving Maine’s problems with its IOUs is to institute innovative rate reform and 21st century performance-based ratemaking (PBR).  This is not “PBR” as previously attempted in Maine. Those earlier attempts used metrics that failed to consider the locational aspects of cost and reliability, instead establishing standards that averaged entire service territories. It is not surprising they were ineffective because their data was so diluted. Instead of rewarding reliability in Portland and penalizing poor reliability in Farmington, something easily done with smart meters, old PBR averaged reliability across all areas resulting in a meaningless number.

Instead of embarking on a long and very costly attempt to take over the IOUs, one with questionable cost and benefits, the state would be far better served by immediately initiating a major effort to define a new electric utility regulatory policy and take steps to craft its own form of PBR.  The legislature has already begun to look at various elements of such a policy, such as beneficial electrification or non-wires alternatives, but they are scattered and disconnected.  A comprehensive policy that recognizes all these activities provides the proper coordination and context to get optimum results.

There is no one right way to do this but there is a large collection of examples across the country where innovative rate reform has been implemented and for which results are available.  One need only look at the initiatives taken in California, New York, Minnesota, Illinois, Iowa and Hawaii, among others.

I strongly oppose LD 1646 and urge the Joint Committee to reject this concept, instead seek to resolve our IOU problems by developing and implementing an innovative comprehensive 21st century rate regulatory policy and structure.

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Maine wants to promote beneficial electrification – it needs a regulatory reform roadmap

Note: the following is testimony regarding LD 1464 “An Act To Support Electrification of Certain Technologies for the Benefit of Maine Consumers and Utility Systems and the Environment” in the Maine Legislature. The Act would require the Efficiency Maine Trust to conduct a study regarding the barriers to beneficial electrification of the transportation and heating sectors in the State; and require the Public Utilities Commission to issue a request for proposals from utilities and entities that are not utilities to conduct a pilot program to support beneficial electrification of the transportation sector of the State.

Senator Lawrence, Representative Berry, members of the Joint Committee, my name is Gerry Runte. I am a constituent of Senator Lawrence and live in York.  Thank you for the opportunity to testify today in opposition to LD 1464.

“Beneficial electrification” is an essential step in the decarbonization of our economy and absolutely required to achieve anything close to the current goals for reducing greenhouse gas emissions. Removing barriers and promoting the electrification of most energy use, especially transportation and heating, when combined with increasing the mix of renewable sources of electricity must happen if we are to succeed.  And as we are increasingly aware, there is great urgency in taking action.  While LD 1464 has the right intent, I believe it might unnecessarily delay taking such actions.

There are a lot of things we already know without further study:

  • Significant growth in overall electricity demand for electrification of heating and transportation will prompt the need for added infrastructure. Growth in that demand is uncertain: the Brattle Group projects a doubling of demand by 2050;
  • NRDC has projected a more modest growth over today’s demand.
  • Both Brattle and NRDC rely on significant installations of renewable distributed generation, including behind the meter, and energy efficiency measures – they are a given under any scenario.
  • That said, demand growth greater than what we have recently experienced is inevitable if even modest GHG goals are to be achieved.  And this leads to another inevitability – electric utilities must be involved in getting this implemented.
  • Utilities could have a role in facilitating electric vehicle charging beyond just selling electricity to appliances
  • Increased demand reductions through end use appliance controls will be essential; major changes in utility distribution planning necessary, etc.

Regardless of the portfolio of steps taken to electrify, an efficient implementation must begin with regulatory reform that reshapes utility business models.  At one end of the spectrum of possible models would be an expansion of the scope of utility operations and services and at the other end, treating the distribution system as a neutral interface for services (both generation and demand reduction). In the latter case an independent distribution system operator would be created, similar to ISO-NE, but for the state’s distribution network. The IDSO would run demand reduction, promote distributed resources and review/approve utility integrated resource plans – sort of an expanded version of the NWA Coordinator as envisioned by LD 1181.

In a few states there are utilities who actually see this as a win-win for them: they are pushing for regulatory reforms that allows them to conduct major surgery on their business models. Unfortunately there are still a number of utilities that are unwilling or unable to see the opportunity here to do well by doing good and who interpret these new paradigms as threats to be countered.  For these recalcitrant utilities, the only effective strategy is to reform the regulatory structure so that it drives changes to utility business models.

I therefore recommend the Committee consider a study whose deliverable is a roadmap to regulatory reform. I believe such a study would be more appropriate – and get things going much faster – than the proposed study that will take over a year to identify what is already known.  That proposed study is most likely to conclude that what is needed is innovative regulatory reform and a program to achieve such reforms – a roadmap.

My recommendation of moving directly to the development of a roadmap does not preclude, and in fact, would require completion of an analysis not unlike what is described in the bill as its first step in laying the framework and context for the roadmap.

As to the proposed pilot- the concepts to be demonstrated are fine, but then what?  The bill is silent on what happens with the information generated. More importantly, the pilots ought to be defined by the study.  They are not concurrent exercises. If, instead, the study is reworked to be a regulatory reform roadmap, the pilots would be a logical step after that begins.  Either way, the pilots seem out of sequence and perhaps premature.

I should add that we are already out of step in the state with regard to electric vehicles.  We have Efficiency Maine Trust  constructing and subsidizing electric vehicle charging stations and state subsidies for the purchase of vehicles, yet nothing has been done to deal with a regulatory structure that hampers these programs.  DC fast charge stations incur absurd demand charges (rendering them totally uneconomic) because there is no electric vehicle charging tariffs to handle them so they are treated like any other MGS 3 phase customer.  Individual consumers who own vehicles and charge them at night do not have the benefit of time of use rates to reduce charging costs.

I urge you oppose LD 1464 as proposed but also consider redrafting legislation that is more expeditious and timely to identify and remove barriers to beneficial electrification.

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It’s Time for a Nonwires Alternative Coordinator for Maine

In 2009 Maine passed its Smart Grid Policy Act. One of its many provisions not implemented was the creation of a Nonwires Alternative Coordinator within the Public Utilities Commission. In 2017 the PUC chose to put this responsibility with the utilites themselves and asked them how they would do it. They have not yet answered. The following is testimony given in support of LD 1181, An Act to Reduce Electricity Costs Through Nonwires Alternatives, which would require the Coordinator be established immediately, but places the function within the Public Advocate’s office.

March 27, 2019

Senator Lawrence, Representative Berry, members of the Joint Committee, my name is Gerry Runte. I am a constituent of Senator Lawrence and live in York.  Thank you for the opportunity to testify today in support of LD 1181.

Advocacy for innovative rate regulatory structures that acknowledge and value the benefits of demand reduction and distributed generation, aka, Nonwires Alternatives, has occupied a major portion of my 44-year professional career, a career almost equally divided between senior management positions at investor owned electric utilities and at private firms in the alternative energy technology sector. Presently I operate a private consulting firm, Worthington Sawtelle LLC, assisting startups with their go-to-market strategies. I am also a senior consultant with CMG Consulting, a national firm specializing in smart grid and wholesale energy market development. I am here today as a private citizen and my comments do not represent the views of CMG Consulting.

Our electricity delivery systems have been rapidly evolving from the electric utility business models of the early 20th century when energy delivery was a one-way path from central generating stations to the end user. New technologies have and will continue to emerge that are transforming this model of energy delivery, one that looks much more like the multiple path connections of computer networks than the one-way pipelines of the past.   The best and most reliable and economical solution to serve new demand is no longer limited to the construction of more generation carried over more wire capacity: the optimum solution could include mitigating demand growth through efficiency and demand response programs, serving it with local distributed generation, energy storage, and managing the grid in real time.   

Consider distributed generation (DG). In addition to making electricity, DG can also be an important component of the electricity delivery system. DG can be used to enhance reliability, resiliency and efficiency, as well as maximize capital utilization.  The notion of local distributed generation benefiting distribution infrastructure is not a new concept. Pacific Gas & Electric’s research department identified a number of benefits to the distribution and transmission system in the late 1980’s and ultimately conducted a full-scale test by collocating a 500 kW solar array at their Kerman Substation to measure its benefits to their distribution infrastructure. The Kerman project demonstrated that the solar installation enhanced reliability through voltage support, reduced transformer maintenance by lowering required cooling at peak hours, deferred transmission capacity increases; offset peaking plant dispatch; deferred capital investments in substation upgrades; and enhanced system reliability by reducing capacity margins. While in the utility industry, I was involved with projects that used solar installations to prove similar benefits and large fuel cells to provide services to commercial users looking for significantly higher reliability and resiliency.

Yet where are we now, 26 years later? The benefits of Nonwires Alternatives have been quantified in detail in several utility systems and are well understood by the utilities themselves. Why, then, is distributed generation, not an integral component of transmission and distribution system planning options, except perhaps in California, Minnesota, District of Columbia, New York, and Massachusetts?

The answer is simple. Most electric utilities, including Maine’s two IOUs, operate within a regulatory structure that was designed to compensate monopolies delivering power in that one way, 20th century system I described earlier. This is a system purposely constructed to reward large capital investments in wires and large central generating stations to always be available to support economic growth. This system worked well for many years. Growth was met, electricity was abundant and available when needed to fuel the economy. But this system did not contemplate the rise of local generation or storage that could be discharged back into the system. Or technology with the ability to monitor, in real time, flows throughout the system or manage two-way power distribution. Utility business models are defined by the regulatory rules in which they operate. Investing capital in a new line or reinforcing an old one to meet growing peak demand is the only option in the playbook because that investment is recognized in rate base; buying locally generated electricity mitigate that peak would accomplish the same end, however the cost of buying that service is not recognized in rates and therefore that option has zero benefit to the utility because it is a benefit that it cannot value.

In addition to constraining utility planning to less optimum operation and costs, this regulatory structure has also limited the growth of distributed generation markets.  Yes, solar and wind have grown considerably in the last several years, but primarily as surrogates for large central generation using the old paradigm.  I can speak from experience that developers and marketers of distributed generation systems see additional markets for their products in those jurisdictions that are undergoing innovative regulatory reform.

There are many models that are currently in implementation or design to move utilities into 21st century regulatory structures that solve this problem.  Some states have instituted comprehensive rate regulatory reform which completely realign utility business models such that they can benefit from and value these new generation and communication technologies while lowering costs and increasing reliability. They are redesigning electricity delivery systems that are far more analogous to computer network that the old, one-way pipeline. Other states have instituted partial realignments through the creation of Distribution System Operators (NY) or a Distribution Power Authority (DC) who have jurisdiction over wired company plans and manage local market platforms that trade capacity, grid support and ancillary services, as well as demand reduction. In so doing, the utilities have been transformed from strong opponents to advocates of this new utility system paradigm because they have been able to alter their business models to take full advantage.

Change the rules and the business model will follow.

As you are aware, Maine began to address the design of a 21st century electricity system with its Smart Grid Policy Act in 2009. One element of that Act required the creation of a Nonwires Alternative Coordinator function within the Public Utilities Commission to ensure options using Nonwires Alternatives were given full consideration in system plans as an option, along with traditional wires investments. Unfortunately, the Nonwires Alternative Coordinator requirement was ignored for 8 years and then the function was effectively delegated to the IOU’s for implementation at some later date. Consequently, it appears that by abdicating this responsibility, the PUC is not a suitable governing body for the placement of the Nonwires Alternative Coordinator.

Make no mistake, changing the rules is no simple. Matter.  However, Maine can make up for lost time and begin the process of reforming how its electricity delivery system is regulated by taking this first step by establishing a Nonwires Alternative Coordinator. The Coordinator could be the source of guidance for the siting of new DG that optimize their enhancement of the distribution network. It could also pilot ways to incent utility leverage DG, with direct benefit to GHG reduction goals. This new office will be a win-win solution for both rate payers and IOU’s as Maine continues to advance its clean energy economy. The Public Advocate’s Office is a logical place from which the Coordinator to operate.

I urge your support and passage of LD 1181.

Thank you.

Gerry Runte

Managing Director

207.361.7143

[email protected]

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Climate Change Has Not Been Entirely Erased From US Government Priorities

The current administration has done its best to erase and ignore climate change as a growing threat to our economic and physical security. The topic has been removed from the EPA and other agency websites, as well as from the summary of the current National Defense Strategy (actual document is classified). Thus far, though, there is one holdout in government – the intelligence community. On February 13 the Senate select Committee on Intelligence received a briefing from several top members of the intelligence community. This was their annual World-Wide Threats briefing. The accompanying Statement for the Record by the Director of National Intelligence, Daniel Coats, provided much detail prior to the nearly 3-hour hearing. Even though oral discussion of the impacts of climate change on global threats to this country was absent in oral questioning, the written statement by Dan Coates, Director of National Intelligence, made it quite clear that climate has not been erased from their agenda.

In the Foreword of his statement, Coats lays out several drivers to threats, including the risk of interstate conflict; the threat of state and non-state weapons of mass destruction; slow economic growth and technology induced disruptions in job markets fueling populism; and  “challenges from urbanization and migration will persist, while the effects of air pollution, inadequate water, and climate change on human health and livelihood will become more noticeable.”

One of the eleven global threats outlined by Director Coats was “Environment and Climate Change.”  This section, in its entirety:

“The impacts of the long-term trends toward a warming climate, more air pollution, biodiversity loss, and water scarcity are likely to fuel economic and social discontent—and possibly upheaval—through 2018.The past 115 years have been the warmest period in the history of modern civilization, and the past few years have been the warmest years on record. Extreme weather events in a warmer world have the potential for greater impacts and can compound with other drivers to raise the risk of humanitarian disasters, conflict, water and food shortages, population migration, labor shortfalls, price shocks, and power outages. Research has not identified indicators of tipping points in climate-linked earth systems, suggesting a possibility of abrupt climate change.

  • Worsening air pollution from forest burning, agricultural waste incineration, urbanization, and rapid industrialization—with increasing public awareness—might drive protests against authorities, such as those recently in China, India, and Iran.
  • Accelerating biodiversity and species loss—driven by pollution, warming, unsustainable fishing, and acidifying oceans—will jeopardize vital ecosystems that support critical human systems. Recent estimates suggest that the current extinction rate is 100 to 1,000 times the natural extinction rate.
  • Water scarcity, compounded by gaps in cooperative management agreements for nearly half of the world’s international river basins, and new unilateral dam development are likely to heighten tension between countries.”

One area where the written statement is deficient is in failing to make any correlation between other threats and the issue of climate.  “Human displacement” is cited because of record high global displacements, raising the risk of disease outbreaks and political upheaval.  While much displacement is occurring because of conflict, displacement is also occurring as regions become less habitable due to the changing climate.  “Health” is another threat where climate change could be a major factor.  The document, however, is limited in its discussion, only addressing climatological patterns increasing the reach of mosquitos and ignoring its impact on the frequency and diversity of disease outbreaks worldwide.

Despite these deficiencies, it is somewhat reassuring to know there are still a few outposts of rational government operations.

 

 

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Rick Perry’s Coal and Nuclear Subsidy NOPR

UPDATE: On January 8 FERC rejected the DOE NOPR

https://www.utilitydive.com/news/ferc-rejects-doe-nopr-kicking-resilience-issue-to-grid-operators/514334/

At the end of September Energy Secretary Perry sent a request to the Federal Energy Regulatory Agency to initiate a Notice of Proposed Rule (NOPR) to create “Grid Resiliency Pricing.” Under the guise of increasing grid reliability and resilience, the Trump Administration is doing nothing more than radically increasing subsidies to uneconomic coal and nuclear generating plants. This is simply an effort to artificially create demand for coal and bail out owners of nuclear generating stations.

The Administration is proposing that “fuel secure” generating stations receive “full recovery of costs” and a “fair rate of return.”  “Fuel secure” is defined as any generating station that maintains a 90 day supply of fuel on site, but might as well say “coal and nuclear generating stations” because those are the only types that can meet the proposed rule criteria.

The NOPR acknowledges that these plants would not be economic under normal market pricing schemes and are therefore subject to premature retirement.

DOE wants coal and nuclear plants to operate under monopoly pricing within what is supposed to be a wholesale electricity free market. Think about that for a moment.  An unabashedly free market Administration wants to impose what amounts to socialized medicine for certain sectors of the economy.

The NOPR alleges that these plants are essential for grid reliability and resiliency because: coal and nuclear plants that would otherwise be retired enhance grid resiliency during extreme weather such as the Polar Vortex of 2014; providing grid resiliency is not valued in wholesale markets and should be; the North American Reliability Council (NERC) agrees with DOE; the DOE staff report on reliability (a failed attempt by the Administration to claim renewable resources were a detriment to grid reliability); and (most importantly) “Congress is concerned.”

Let’s take a look at some of these assertions.

First, the threat of fuel supply disruptions. I give you Exhibit A1:

In actual fact, the greatest threat to grid resiliency from extreme weather is the quality of the transmission and distribution system. A system whose efficiency and resilience contribution could be vastly improved with a much more aggressive implementation of new smart technology.

While NERC may agree in principle that grid resiliency should be valued, the ISO/RTO Council, the organization representing all of North American wholesale power grids, has filed comment that the FERC should not issue the rule for several reasons, including “the NOPR would undermine competitive markets and Is legally Infirm.”2

The authors of the DOE Reliability study offered a few other recommendations that did not end up in the report, including the fact that what constitutes grid resiliency and how all the factors that affect it (such as fuel security) are not well understood and merit considerable analysis before a valid pricing method can be determined.3

Finally, the most important reason for the NOPR needs to be understood and properly characterized.  The DOE document says “Congress is concerned,” referencing a letter from the House Science and Technology Committee, a committee controlled by an extremely partisan group that promotes the interests of fossil fuel industry and unabashedly rejects climate science.

These, however, are the reasons on principle that the NOPR should be withdrawn.  There’s that other factor of cost.  Energy Innovations, LLC, evaluated the costs of implementing the NOPR under four different interpretations of how the pricing could go4, from a conservative estimate that covers the shortfall in cost from wholesale value to operating costs to break even (Reading 1), through to an aggressive case that not only offers full cost recovery but full return on capital and full dispatch even if under normal conditions the unit would not be so dispatched (Reading 4). The following table shows how these 4 interpretations might impact customers in the four regions that would be affected. (PJM = Middle Atlantic, Ohio, VA; ISO-NE =New England; MISO = Midwest; NYISO= New York State)

Source: Energy Innovations, LLC

This NOPR has the potential to significantly increase customer cost and have a dampening effect on the economy for very questionable reasons.

Recommendations

There is a certain irony in this attempt to reregulate from an Adminstration bound and determined to unregulate everything. One can only conclude that this is a hastily cobbled approach to bailout coal and nuclear interests that have found themselves uneconomic in wholesale power markets relative to other technologies. The NOPR ought to be rejected on its face.

If a sincere attempt is to be made to examine the issue of grid resilience and reliability, a much more careful and comprehensive analysis ought to occur.  This analysis needs to give consideration to a number of factors that can affect reliability and new technologies that could enhance reliability and resilience in a much more cost effective manner.

In the absence of pricing methodologies, enormous improvements in resilience and reliability have yet to be obtained through the implementation of smart transmission and distribution technologies on all networks. Rather than burdening customers to simply prop up failing technologies, consider investments in new ones that provide long term solutions.

 

 

1 http://rhg.com/notes/the-real-electricity-reliability-crisis

2 Comments of the ISO/RTO Council on the September 28, 2017 Notice of Proposed Rulemaking by the Department of Energy

3 https://www.utilitydive.com/news/silverstein-if-id-written-the-doe-grid-study-recommendations/506274/

4 http://energyinnovation.org/wp-content/uploads/2017/10/20171021_Resilience-NOPR-Cost-Research-Note-FINAL.pdf