When Dynamic Pricing Meets Energy Storage

gathright

Will Gathright

Other states are targeting energy storage as an industry of the future but Virginia may have the most hospitable climate for it.

by James A. Bacon

Will Gathright was living in New York, where he had earned a Ph.D. from Renssalaer Polytechnic Institute, when he got fired up with the idea to use storage batteries to help business customers cut their electric bills. The idea was to buy electricity when it is cheap to charge the batteries, then draw down the batteries during periods of peak demand to offset consumption when electricity is expensive. For the business model to work, he needed to find a location where there was a wide differential in the cost of electricity.

Initially, he figured he might wind up in Hawaii, California or New York, states that are putting a high priority on energy storage. But after conducting a national search to see where his value proposition would fare best, Gathright moved to Northern Virginia.

“Virginia has the winning combination of three factors not present elsewhere in the country,” he explains. First, although Virginia’s peak-demand rates aren’t the highest in the country, they are relatively high. Second, while a few states have cheaper base rates, Virginia’s are significantly lower than the national average. The spread between low base rates and high demand charges creates a bigger potential for savings.

A third factor, Gathright says, is that Virginia electric utilities belong to PJM Interconnection, which manages the electric grid and wholesale markets for 60 million people in the Midwest and the Mid-Atlantic region. When his batteries aren’t helping shave a building’s peak demand charge, they can help PJM fine-tune short-term fluctuations in the supply and demand of electricity.

Welcome to the new world of electric load management. Power companies around the country are experimenting with novel rate structures that encourage customers to curtail their electricity consumption during periods of peak demand — typically summer afternoons when air conditioners are running flat-out. One of the most promising strategies for shifting electricity demand is energy storage, usually using batteries, and other states are targeting the sector as a strategic priority. California is requiring its utilities to purchase 1,325 megawatts of energy storage by 2020 and the state of New York state has invested $1.4 million in six battery and energy storage start-ups.

Gathright thinks Virginia may be the most promising location in the country to implement energy storage — not that the idea has gotten much attention here. What Virginia has done is experiment with dynamic pricing: using the price mechanism to encourage customers to shift electric consumption away from periods of peak demand when it is most costly to supply.

The results of Dominion Virginia Power’s dynamic pricing pilot program have been modest so far — positive enough to encourage Dominion to continue the project but not dramatic enough to persuade the company that a revolution in electric consumption is in the offing. But the outlook could change if entrepreneurs like Gathright figure out how to help customers capture the savings that the dynamic-pricing rate structures make possible.

With the encouragement of the State Corporation Commission, Dominion rolled out its dynamic pricing program in 2011, branding it as the Smart Pricing Plan. “The basic premise,” explains SCC spokesman Ken Schrad, “is that if customers are willing to modify behavior and use less electricity during high price periods, they will have the opportunity to save money, and the company in turn will be able to reduce the amount of energy it would otherwise have to generate or purchase during peak periods.”

The pilot was limited to 2,000 customers under a residential tariff and 1,000 small and midsized commercial customers under two commercial tariffs. Participation required having Advanced Metering Infrastructure (AMI) or Interval Data Recorder (IDR) meters that record energy usage every 30 minutes, thus allowing Dominion to measure consumption with greater precision.

Dominion provides customers at least 280 days a year with low-priced electric rates (“C” days), up to 30 days with high rates (“A” days), and the balance with medium rates (“B” days). Dominion communicates the classification to customers the day before to allow them to plan accordingly. Additionally, the company designates up to 25 five-hour blocks, or critical peak events, per year to commercial customers with two-hour notice. The rate differential for the critical peak hours could be literally dozens of times higher than the lowest rates.

For most customers, the jet savings have been minimal. Between October 2013 and October 2014, residential customers saved an average of $48 annually (3% of their electric bills), small commercial customers saved $92 annually (3%). However, larger customers saved $5,900 annually (14%), according to Dominion’s 2015 annual report on the program filed with the SCC.

As of July this year, 310 customers had unenrolled. Most drop-outs were due to customers moving to new addresses, but some customers said the program was too complicated or didn’t yield the savings they expected. The program did lead to some energy conservation — residential customers trimmed consumption 3.5% on high-cost days. But a large number of residential and commercial participants responding to a survey said they did not change their behavior at all.

Dominion has no plans to implement the experimental tariffs on a large scale, but the company is asking the SCC to extend the pilot, says David Botkins, director of media relations. “Who knows where the future might go? Dominion wants to be part of the solution.”

Extending the dynamic pricing pilot program may give entrepreneurs time to figure out how to make it appealing to a broader array of customers. One company, Wilmington, N.C.-based Utility Management Services (UMS), provides electricity auditing services and analysis on how companies can shave their gas electric bills. The company does not charge fees unless it identifies tangible savings. In its 2015 summer newsletter, the company said it had intervened in Dominion’s dynamic-pricing case before the SCC “to get fairer and more favorable rates for business customers in Virginia.” The company did not respond to a Bacon’s Rebellion request for details on its position.

Meanwhile, Gathright is working to get his own pilot project up and running in Alexandria. His company, Tumalow Energy Ingenuity, he says, is in the “start up” phase. The six-person team includes Gathright, who holds a Ph.D. in computational materials science; John Gathright, software architect, real-time controls expert and Will’s father; and four others. The company’s primary asset at this point is software that tells batteries when to charge and discharge electricity at the optimal time.

Gathright’s value proposition  is this: He will install a rack of batteries in the customer’s facility, charge the batteries on days/hours when the price of electricity is low and provide power when Dominion is charging top dollar during periods of critical peak demand. “I can install the batteries at no up-front cost,” he says. “The whole project is cash-flow positive from the very first minute. … People don’t know how to evaluate it. I do. The people who know the most are taking the risk.”

Here’s the kicker: Tumalow’s batteries also would tap into the PJM wholesale market. One of PJM’s jobs is to ensure that the electric grid for 60 million people in the Midwest and Mid-Atlantic functions smoothly, which means keeping the supply and demand of electricity on the grid in equilibrium. PJM has created a market for “frequency regulation,” which buys and sells electricity in five-minute increments. Even the most flexible power plants cannot ramp power up and down that quickly. Batteries are ideal. Because PJM runs this market year-round, Tumalow’s batteries can generate revenue year-round, not just when its customer needs to avoid paying critical-peak rates.

There is no way of knowing whether Gathright’s up-by-the-bootstraps venture will succeed. But it’s an example of the kind of creative, entrepreneurial thinking that’s being applied to the problem of electricity demand management. And if Gathright is right, Virginia is where the action is.

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69 responses to “When Dynamic Pricing Meets Energy Storage

  1. I’m a skeptic on the storage batteries in the same way that I feel that solar and wind are not a one-for-one replacement of fossil fuels which are many times more energy dense than wind/solar will ever be.

    Now, I don’t doubt for a minute that some day – we’ll see breakthroughs but right now – virtually every cell phone on the planet is required to be recharged every day and I’m quite sure folks would love to be able to go a week on a single charge!

    It will be a futile effort anyhow. There are two costs in providing electricity – the capital costs and the operational costs – and no matter what alternatives a person will use for operational – they’re still going to owe the capital costs – for the infrastructure that Dominion has had to build to provide “on-demand” 24/7 power.

    you can bet that if storage technologies become mature – that Dominion will be using it also!

  2. Jim, this is a very sophisticated post that a lot of people probably won’t read closely like they should. And if you keep this up you are going to be either a shill for Dominion or their worst nightmare, a well-informed electric industry critic. Keep it up!

    Here’s the thing: you’ve got a bunch of readers who know about renewable resources and distributed generation and some other fashionable topics like “getting off the grid,” but the economics of how the Grid ALREADY works, and the options available to those customers who want to take advantage of it, are astounding, and most customers with the capability of participating don’t have a clue how to get involved. PJM, which runs much of the most developed portion of the Grid (PJM is a federally-regulated “independent system operator” which dispatches all the generation and demand-side resources in the mid-Atlantic region including throughout Dominion’s territory), probably has the largest offering of markets and programs out there to buy power from anyone willing to sell it, and that includes everyone from the big integrated utilities, and independent generation-only companies, down to homeowners with rooftop solar and windmills, and curtailable loads who commit to back down a certain amount when told to. PJM will deal with these little generators and curtailables directly but the pricing is complex and changes minute by minute, and the communications burden can be substantial. Most of the small customers sell their output (or their commitment to reduce load) through aggregators, who are in the business of matching up the small customers who don’t want to bother with a lot of paperwork or complications, and the buyers like PJM. Some of those aggregators are the integrated utilities themselves: that’s what Dominion’s “dynamic pricing pilot program” is. Some other aggregators are little companies like Will Gathright’s — who could sell directly into PJM’s markets, but I suppose Gathright is aggregating business/institutional loads locally in NoVa for Dominion and Dominion in turn is packaging and reselling from multiple aggregators to PJM (and/or simply buying the aggregator’s net power for its own consumption).

    The way the Grid works, there are SEPARATE markets for several different electricity products in PJM. The biggest market is the instantaneous electric energy market, in which supply side and demand side resources (loads and generation and load-management resources) all get the locational marginal price offered at their location, varying minute-by-minute. The next biggest are the capacity markets, both long term and short term, which (I’m simplifying here) are where you sell commitments to deliver generation or “negative loads” (load under management including batteries) in the future. There is a lot of back-and-forth between PJM and its load management aggregators scheduling how much load to curtail the next day, or the next hour, or even shorter horizon, based on detailed forecasts of what is happening to loads in PJM due to the typical daily customer load cycle overlaid with the effects of temperature and weather across PJM’s 12-state area. It’s a complex iterative process: first PJM estimates likely prices for the next few days, and then as dispatchable resources fall into place and PJM makes better estimates of likely non-dispatchable resource availablilty like solar and wind, the rapid-on/off peaking-power resources and scarcer or pricier resources like load management are added. As Gathright noted, Dominion’s generation profile includes cheap baseload generation, but once its demand increases each day, Dominion has less of the mid-range cycling generation than they need for their own loads so they become net buyers in the PJM energy market fairly early in the day, and, as a utility trying to keep overall costs down for its customers, Dominion, more often than most utilities, may find that load management resources have become cheaper to buy than PJM’s highest-cost peaking power. That’s the opportunity Gathright has identified.

    In general, it’s only the commercial or institutional customers with power management staff on site who can handle all this back and forth with one of the bigger players like Dominion, let alone deal directly with PJM; the rest sign up with a power aggregator like Tumalow which, for the customer, removes much of the hassle. Moreover, PJM pays a price determined at the time of consumption; but most participants want to lock in some of the benefit up front, along with the commitment, months or a year in advance; the layers of aggregation spread and finance that prepayment risk. As you noted, Dominion has lost some participants because “some customers said the program was too complicated” — but if you’re running a military base or a hospital or shopping mall, you ought to have staff on site who can deal with all this to save money on the institution’s electric bill. Having a third party come in and explain it all and handle the paperwork and advance you up front cash to sign up and install batteries on your site to shave your peak load can be a win-win for everyone. By the way, LarryG is right, batteries generally are not ready for ‘prime time’ generally, but if anyone can find the right place to use them at current prices it’s an aggregator like Tumalow.

    While on this subject, let me put in a plug for a really terrific issue of Discover Magazine, the July/August 2015 issue, which has a long insert section called “Powering the Future” focusing on renewable resources promotion and Grid improvements in other countries (particularly Germany). It’s well written and anyone interested in this stuff should read it. I have only one criticism: the articles imply that two way power flows on the Grid are a major problem; but in my experience in the mid-Atlantic, that’s a complication but it’s not a serious roadblock to more widespread distributed generation, like rooftop solar.

    • Excellent response from Acbar. Thank you and Jim for bringing these issues to more people’s attention. There is a great deal of ignorance and confusion about how the energy system is evolving.

      It is exactly issues like this that are being ignored by the SCC and despite the current support by Dominion they might change their tune if it becomes widely adopted.

      To answer Larry’s question – Dominion will be using batteries either of their own or from third party aggregators as described in the article. Many hundreds of MW’s of utility scale batteries are being installed in the US right now. I don’t know how much in customer locations (Tesla’s Powerwall battery systems won’t be available until 2016). But they will be put in primarily to reduce costs and for some to provide a period of electrical backup. And the costs of batteries will continue to decline rapidly as technology improves and manufacturers scale up (Tesla’s Gigaplant).

      They make sense especially for Commercial and Industrial users. A big part of their bill is a demand charge which Dominion levies to cover the cost of having capacity available to cover the customer’s peak demand. Regardless of the monthly usage, the customer’s demand charge is based on their peak usage. So if they can use a battery to store energy during the off-peak time and discharge the battery to reduce their peak usage, then their demand charge will be less. This can save C & I users thousands of dollars per year.

      Residential users do not have a demand charge so the benefit is less. However, third-party providers such as SolarCity are well aware of the value of a rapidly dispatchable source for the wholesale markets. ISO/RTO’s such as PJM will pay a premium amount on the 5-minute power auction market for rapidly available energy at the peak (or for voltage regulation). Many third-party aggregators are looking to cash in on this market and simplify it for residential users (homeowners won’t have to do anything but sign up for the program and the aggregator will take care of the rest).

      Solar City is planning to include a Tesla PowerWall with residential solar installations. During peak solar PV production in the afternoon (which produces California’s famous “Duck Curve” slump in utility demand) some PV generated electricity will be diverted to the battery then extracted later in the evening as the sun goes down. This can be used by the homeowner or sold to the wholesale market to offset the highest priced generation used to meet the peak. They probably share the profits with the homeowner or use it to reduce the cost of the system. This is good for the customer, Solar City and the utility.

      Dominion benefits in the same way. Whenever the peak is reduced, they save money by not having to produce or buy expensive peaker generation. Their rates are based on an assumed percentage and cost for peak generation. When Dominion can reduce the amount or the cost of peak generation they get to keep the savings.

      The glitch for Dominion is if this gets too widespread (such as widespread residential solar) their overall revenues are reduced too much, not just their peak costs. That is why they are trying to discourage customer and third-party participation in the evolving energy system. They want to own it all themselves – all of the solar generation, the batteries for voltage and volt/VAR regulation, etc. – everything that will make them money.

      Their current Integrated Resource Plan indicates that they want to extend the 20th century central station, utility model for 30-40 years into the 21st century (including solar). Except the genie is already out of the bottle. Residents and businesses can add solar, energy efficiency measures and all sorts of things that will save them money right now (just not many know they can). Companies such as Amazon will continue to provide their own power at rates lower than Dominion can provide it to them. Costs of solar will continue to decline (probably by another 50% in the next 5-6 years). All of this will reduce Dominion’s energy sales (especially near the peak usage of the day where they make most of their money). Dominion is fighting this tooth and nail but it is the wave of the future. Postponing it will harm Virginia’s economy, perhaps irreparably. The SCC must set up a rate structure as other states have done which allow Dominion to prosper even as their energy sales decline. This causes rates to go up but customer bills decline. We must move in this direction now. Waiting for the SCC to get back in the game in 2022 will be too late.

      Dominion’s heavy reliance on gas-fired Combined Cycle generation will be a very poor match for the widespread use of renewable generation. These types of plants do not respond rapidly enough to variations in renewable generation. We could be spending a lot of money for plants that are expected to be used 70% of the time that might end up being used far less. Once they are built, the customers will keep paying for them regardless of the benefit they provide.

    • I’m still a novice at this, Acbar. I still have a lot to learn. But as you make clear, PJM is a critical player. I’m becoming increasingly convinced that it’s impossible to understand anything that Dominion Virginia Power without understanding how PJM runs the grid and operates wholesale markets.

  3. The challenge with the comments on this article is a narrow definition of the term “battery”. A broad definition of the term “battery” would include any means of storing energy for use later. By that definition there are a lot of grid-scale batteries in operation. Pumped hydro “batteries” are a way of storing energy generally using two lakes at different altitudes. This approach does not make sense for most fossil fuel electrical generation approaches since those generators can be fairly easily and safely started and stopped in conjunction with demand. This is not the case for nuclear plants which must operate continuously for safety and other reasons. Nor is it true for most alternate energy generation techniques which only generate electricity when the sun shines, the wind blows, etc. The basic concept relies on two lakes at different altitudes. Nuclear plants generate electricity 24 hours a day. During the day the electricity goes to the grid where it is consumed. At night the plant generates more electricity than is needed. The excess electricity is used to pump water from the lower lake to the higher lake. During the day, the water is allowed to flow from the higher lake to the lower lake over a hydroelectric generating station. Thus, electricity generated last night is stored and re-generated for the next day’s use.

    Interestingly for Bacon’s Rebellion, the largest hydro – pump battery in the world is claimed to be on the Virginia – West Virginia border.

    http://thinkprogress.org/climate/2013/08/27/2524501/hydro-pumped-storage-climate-change/

    • DonR

      Dominion owns about 1800 MW of the 3000 MW capacity of the pumped hydro storage facility in Bath Co. Virginia. It is useful for any type of generation that is low cost. When Dominion has widespread solar or wind generation they could also be used to pump water up to the upper reservoir since their energy is likely to cheaper than nuclear. The idea is to arbitrage the generation. Now they use nuclear generation at night since that is their current lowest cost source of generation. Then they release water from the upper reservoir during the day when they need more energy and the extra is typically generated from more expensive intermediate or peak load generators. The facility is about 70-80% efficient, so as long as the cost of energy used to pump the water up is at least 20 -30% cheaper than the cost of energy they would otherwise have to use during the peak – the facility saves them money. Lithium ion or other types of batteries would be used in the same way. They are more expensive per MW than pumped storage but they have a higher efficiency and typically do not involve any transmission losses that are associated with the pumped storage facility (another 10% energy loss).

      The distributed nature and rapid response of batteries also make them valuable for grid services such as voltage regulation and volt/VAR support – for which PJM will pay a premium.

    • That is very interesting…I had not been aware of the Bath Co. project, but I’ve been to the business end of Smith Mountain Lake. Between those two plants Virginia must presumably be close to national leadership on pumped storage.

      My household also participates in Dominion’s air conditioner shut/off plan where Dominion cuts out our A/C on hot afternoons if they need the peak power flow.

  4. Thanks for the fine article and terrific follow on commentary. Both spread around useful information, informed knowledge, and thoughtful opinion.

    In so doing, we learn much about what is happening in a highly specialized world that too often is invisible to us. So we know little about what is going on in that world that has great impact on our lives, however distant those activities may at first glance appear.

    Too often the technical nature of the story compounds the problem of its telling. This article and its commentary leap over the problem.

    So all this is great stuff. What a story. What an inspiring example! To take only one part of a whole raft of elements:

    Imagine how Will Gathright combines his fine education, his technological expertise, his entrepreneurial pluck, his small but nimble team (incl. his father), and all his partners and relationships to work on the front lines at the cutting edge of important problems and pregnant opportunities.

    Imagine how Will Gathright doing this work gains ever more insight, experience, skill, and capacity for achievement as he works within this wide circle of high quality players in his demanding, complex and dynamic field of expertise.

    Imagine how this wide variety of high quality players bring an array of talents, perspectives, capacities, and interests together and how Will helps to focus them more sharply and cooperatively on solving problems of mutual interest and benefit for all of them, while at the same time their success will serve the public good on a great number of important fronts.

    Imagine how, not only Will, but all the other players involved play many equally important rolls for the cumulative benefit of all players, including us the general public whose resultant gain can potentially be huge.

    Just imagine the scope and power and potential for gain that lies within this venture (however loosely it may be formed) about which Jim Bacon tells:

    How it brings or might bring Dominion Power, PJM Interconnection, Virginia State Corporation Commission, Renssalaer Polytechnic Institute, Tumalow Energy Ingenuity, and Utility Management Services (UMS), to name a few among many players, how it brings them all onto the same field to work in synergistic ways that together build and create the “know how”, capital, infrastructures, solutions and capacities to make real on the ground all that we all have the potential to gain here.

    This is the American System working at its best, making it day in and day out the best in the world as it combines all these incredible elements of real competence working freely and cooperatively for real achievements that can radical improve peoples lives. Instead of falsely claiming to do so.

    In these times when the corruption of our public and private institutions and culture seem rampant, this story has offers hope and real lessons.

    • “This is the American System working at its best.”

      I totally agree.

    • Your insightful comments are right to the point as usual. There are many innovative companies ready to contribute to making our energy use more convenient and less expensive, given the opportunity.

      Many other states are well on their way to revising their regulatory structures to encourage such development. Hundreds of millions of dollars of demonstration projects are underway and these new innovative companies are noticing which states make sense in which to do business. Virginia wants to attract more innovative companies and their skilled work forces. With military bases undergoing major energy restructuring and the server farms in Northern Virginia, we could be a perfect location for many enterprises.

      However, our regulatory model must evolve to encourage the kind of market based, third-party principles you and Jim are lauding. Any move in this direction, although good for the state and good for ratepayers, is harmful to Dominion’s revenue stream. New policies and rate categories must be developed to keep Dominion profitable with less revenue. It is cheaper for everyone if we use less energy to do the same or greater work. But we must give Dominion a way to become the Distribution Service Provider that is open to all customer choices. If we wait until 2022 to even begin the process, Dominion will have made investments that will weaken it financially in the long run and put the Virginia economy on the path to second tier status.

  5. More traditional stored battery technology is advancing rather quickly. Here is a story regarding a project to build the world’s largest “traditional” grid scale battery in California. The contract was awarded to AES, based in Arlington, VA. Mr. Bacon seems to have missed AES as a major technology company based in Virginia throughout his years of blogging. While AES certainly won’t ever have the economic impact on Virginia that a new meat pie store in Richmond will have (wink, wink), they are doing some interesting work:

    http://www.sandiegouniontribune.com/news/2014/dec/12/worlds-biggest-battery/

  6. Finally, there is work being done in the space between hydro pump energy storage and traditional batteries on steroids. A UK company – Isentropic, Ltd (Isentropic is the name for the process used to store energy by Isentropic, Ltd) is on the pursuit of such a technology.

    http://www.economist.com/blogs/babbage/2014/03/electricity-storage

    I would suggest that Gov. McAuliffe could do more for Virginia economic development by convincing Isentropic to establish an American operation in Virginia (perhaps in conjunction with Virginia Tech) than by handing out gigantic corporate subsidies to 20th century companies to relocate in Virginia.

    • I agree. Gathright has identified a unique economic development asset that Virginia possesses, without anyone in Virginia even realizing it. The state should seriously look into the energy storage sector, not just from a corporate recruitment perspective but a regulatory perspective. Can we fine-tune electric rate structures to make Virginia even more competitive in this area?

      • My view is that pump storage is pretty limited in that there are few sites to doit (you need a lot of “head” usually only found in mountainous terrain) and they flood a lot of land AND they actually end up using more power because it takes more power to pump it up than you gain by letting it generate coming down. It only really “works” if you have a base load plant running 24/7 and excess power available and energy use has peak demand periods during the day where the water can be released to generate.

        natural gas peaker plants can do the same job – better and cheaper.

        you’re actually using MORE energy to pump the water back up.

        • Larry,

          Natural gas peaker plants typically do not do the job “cheaper”, that is why it makes economic sense to develop pumped storage facilities, although finding an appropriate site and getting it approved can be difficult.

          Let’s say you use $50/MWh nuclear energy to pump water up to the higher reservoir and by the time it generates electricity on the way back down you have lost 20%. You now have power that costs $60 /MWh. This is considerably cheaper than peakers which often generate power in excess of $100/MWh (sometimes much more).

          • TomH, this is a nit but I don’t believe pumped storage is that efficient; I think you are quoting the losses in one direction, not net of both directions (up and down).

            Anyway, the point of pumped storage was, when a nuclear plant is on its “ON” and if the nuclear output is lower than the load in the middle of the night, that power literally has to be “dumped” if not used for something, however inefficient, since the most inefficient thing of all is to dump it. Now, in the 1970s there really were times when nuclear baseload output exceeded load most every night. DonR is right, a pumped storage plant is a kind of “battery” — and hydro is very useful for withdrawing the power just when you need it, very fast and with essentially no lead time. System operators like PJM love to have hydro available to fill in flexibly around the “blocky” power output of the larger fossil generating units; a run-of-the-river plant costs nothing for fuel and even pumped storage costs only its losses if you’re powering it with nuclear output that’s “free” because it would otherwise be dumped.

            That said, a hydro plant, especially a pumped storage hydro plant, was (and is) hugely capital intensive to build. Order-of-magnitude-comparable even to current battery costs! When some of the best new battery technology (like aluminum ion/carbon foam out of Stanford) gets out of the lab and into scaled up production we will see how much better the Grid could operate with readily available short term electricity storage! If Elon Musk can make the case for Grid batteries even using old-fashioned, expensive lithium ion tech, God bless him, but that is nothing like it should and will be with the vastly cheaper and safer ones yet to come.

            Meanwhile, I think LarryG is right, quickstart natural gas units are very efficient and useful right now. Moreover, if you look down the road 20 – 30 years or so, yes you may have new tech batteries and lots of solar and so forth, but you will still need baseload and cycling power off the Grid, and those efficient gas units built today will still be needed (perhaps less frequently, maybe much less frequently, but often enough they can’t be retired).

          • Acbar,

            I did some work on the first large-scale pumped storage facility built in the U.S. It was developed in Ludington Michigan in the early 1970’s, pumping water from Lake Michigan up to a reservoir on a bluff high above.. It was projected to be 75-80% efficient round trip. The Bath Co. plant was built in the 1980’s so it might be a bit more efficient. Here is a link that says those numbers are accurate:

            “The round-trip efficiency (electricity generated divided by the electricity used to pump water) of facilities with older designs may be lower than 60%, while a state-of-the-art PHS system may achieve over 80% efficiency.”

            http://people.duke.edu/~cy42/PHS.pdf
            Pumped Hydroelectric Storage Chi-Jen Yang Duke University, Durham, North Carolina

            It, and others like it in NY and elsewhere, were built exactly for the reason that you described. The flush of nuclear plant construction in the 1960’s and 1970’s created numerous units which could not easily cycle to meet load variations. Their capacity exceeded night time loads and it was expensive to wheel the power to far away regions. Regional transmission “power pools” were just coming into being. The development of pumped storage solved that problem, but required a large investment for the facility. They are typically written off in 30+ years and have very low maintenance costs. There should be a cost added to the cost of power for the use of the pumped storage facility. They have 50 -70 year life spans and after they are paid for have little ongoing expense other than the energy loss, so I don’t know what an appropriate cost add-on should be.

            Because they are a net generation loss (but real cost savers for peaks) Dominion does not discuss them in the IRP. I’m sure that because it is so large (3000 MW) the capital cost per MW of storage is far less than current battery technology (cost per MWh over 70 years would be a more accurate cost allocation).

            Sulfur based battery technology has advantages over lithium-ion for utility uses and has been used for several years, but they get hot and tend to catch on fire. A great deal of R&D is going on in the energy storage industry (not just batteries) and is yielding increasingly cost-competitive solutions that will open many options for a 21st century grid.

            I agree with you and Larry about the value of rapid start simple combustion turbine units to balance out variations in renewables. They will have value until they are replaced with much more responsive batteries (milliseconds versus minutes) which will also be easily distributed (which give them greater grid balancing value) and cheaper.

            Affordable storage turns the old central station paradigm on its head. That is why I was arguing that such an aggressive investment in base load combined-cycle units was a misguided choice since it runs contrary to this trend which will arrive in full force in the first 10 years of the life of these units. Then who pays for them to sit there? There are cheaper, more flexible ways to deal with the issues they are intended to solve. But it requires a change in mentality and regulatory structure.

      • Oddly, the best public policy for economic development of energy storage would be to increase the differential between peak and off-peak I assume. This would make energy storage more valuable and encourage more investment in Virginia. This would also reduce pollution since I assume that the peaking plants are less environmentally efficient than the standard plants (including the nukes).

        • DonR, the differential or spread between peak and off-peak energy market prices in PJM is pretty much typical of the whole eastern US; there’s not much to be gained by promoting peak shaving with batteries (or any other load management service) in Virginia specifically just to take advantage of the PJM market spread. But, DVP has retail rates based mainly on its own costs, not PJM’s market prices; specifically the demand charge under DVP’s business tariff reflects DVP’s current generation mix and has the spread that attracted Tumelow’s attention. That spread should decrease as DVP’s rates are updated to reflect generation additions and retirements and its changing purchased-power mix, so this looks to me like a temporary business opportunity, not a long term Virginia locational advantage.

  7. excellent discussion and yes I fess up on my own ignorance.. which I hope to reduce by reading these informed comments!

    re: ” Dominion’s heavy reliance on gas-fired Combined Cycle generation will be a very poor match for the widespread use of renewable generation. These types of plants do not respond rapidly enough to variations in renewable generation.”

    what would be better?

    re: PJM and Dominion – and the rural electric coops and 3rd party power generators

    I’m confused – perhaps badly.

    I simply do not understand the role of PJM relative to Dominion’s role in terms of not only dynamically shunting power to where it is needed in real time but in terms of deciding where reliability issues require infrastructure.

    • Nothing makes sense until we understand how PJM controls transmission, prioritizes generation, and creates wholesale markets.

    • It is a bit confusing because PJM has two roles. The first role is as the Regional Transmission Operator (RTO). In this role PJM is the organization that controls the use of and the makes the plans for developing the regional transmission network. The utilities, whether investor-owned or co-op, build, maintain and own the various transmission lines. They all work together to plan where new transmission is required to provide service to improve reliability and ease congestion on the system. PJM has the final say in the operation of the system and can heavily fine utilities who do not comply with their operating orders.

      PJM is also the Independent System Operator (ISO). In this role they establish and operate a regional energy market. Both for long-term capacity and for short-term energy markets (day ahead and 5-minute markets). They work with the utilities to make sure they have a set plan three years in advance to provide for their share of the PJM peak, including reserve margins. Utilities must have their own capacity or arrangements for purchased power to fulfill their share of the load. In Virginia, the SCC also does this with utilities through the IRP process, but the Virginia peak might not exactly correspond to the PJM peak.

      On a daily and 5-minute basis, PJM monitors the status of the multi-state region, including the transmission situation. On hot summer days with high current flows, transmission lines can sag and contact trees which can short out the line (this is what happened in the last major blackout). PJM can reroute power or ask that additional or alternative units be brought on line to improve reliability. When a utility purchases power from another source, PJM does the bookkeeping, billing and payments, including charges and payments for use of transmission services.

      In some states, generation is separated from transmission and distribution. Utilities own generating capacity using companies separate from their regulated transmission and distribution “wire” companies. These and other non-utility generators (NUG’s) comprise the “merchant generators” in those deregulated states in the PJM territory. Virginia started on this path but changed their mind (I think after the Enron/California debacle).

      The important point is that PJM calls the shots , guided by NERC and FERC regulations. The utilities that are members of PJM must play by the rules and meet their commitments. The good news is that for transmission that is used interstate, FERC usually allows a higher rate of return than is allowed by the SCC.

      Other systems like PJM operate throughout the U.S., although the Rockies present a barrier to development of a truly national grid. Parts of Canada are also tied in (we love that cheap hydro).

      • I should have added that the generation auction that PJM manages on a day-ahead and 5-minute basis is done on by using bids from the various power producers as to how much they will charge for their power. When the full capacity of a particular source is spoken for, the next least expensive source of generation is put up for bid. In this way PJM develops what they call their “Loading Order”. The utility power control centers are in constant communication with PJM. They offer what generation they have to put on the market, or they purchase what they need to maintain reserve margins. On peak days, the 5-minute auctions can get hectic and very expensive. Compared to base load power generated at say $50 per MWh, power generated from peakers can go for hundreds of dollars per MWh (over a $1000/MWh back in the bad old days in California).

        You can see why Demand Side Management schemes such as energy efficiency or peak load displacement programs can pay off for customers and utilities. All customers pay for expensive peaks in the rate base. If the peak expenses for the year exceed what was estimated in the rate base, the shareholders make up the difference or the utility files a new rate case.

        • so does Dominion have to get permission from PJM to fire up or ramp down a generation source?

          • At the time DRP operates the unit, yes it must get permission, and it must follow instructions while the unit is operating. That is what “under dispatch control” or “dispatchable” means. PJM does the dispatching.

            This is not so strange or difficult as it sounds. Dispatch of every group of generating units (a “system” or “grid”) is done in real-time to balance the loads on all the transmission connected to that group, out of a centralized control room with communications covering all the generators and transmission substations on that grid. Dominion has its own control center. Since the mid-20th century, most formerly stand-alone utilities like Dominion have connected to one another so they can buy and sell bulk power to each other, especially as some of them built nuclear units before others and the “lumpiness” of these big generation additions required a way to handle the temporary shortages and excesses. But when utilities with their own control centers connect, it is massively complicated because operating an alternating-current (a/c) Grid depends on coordinating the frequency curves of every part of the Grid. So, guess what, they typically build a control center to coordinate their control centers!

            PJM is one of the oldest regional control centers because the mid-Atlantic utilities up and down what is now Amtrak’s northeast corridor started coordinating their grids and their control centers in order to meet the needs of the Pennsylvania RR electrification projects after WWI. There was another one in NY, and another covered New England; and they even worked out ways so each regional control center could coordinate with the others. These worked out all the tricks to operate together on one frequency curve and, over the years, developed planning and operating staffs to handle it all, and even built jointly some big transmission lines and the communications infrastructure to make it possible. Now, having done that, it was an easy next step (and highly profitable) for these utilities not only to operate together but to buy and sell to one another. They developed all sorts of ways to do this, including (in PJM) an “implied” energy market where all the regions’ generation was dispatched cheapest first regardless of who owned it, power flowed where it flowed, and then, after-the-fact, they figured out who had actually bought how much from whom. You could participate in this club if you paid the price of admission: you had to bring to the table enough generation to meet your forecast peak load (plus reserves) — but it didn’t matter if it was the cheapest generation as long as it would run when needed.

            So now you see all the elements of the modern ISO (e.g. PJM) were in place decades ago: centralized system dispatch of generation on a regional scale, regional transmission planning and coordinated transmission investment, a real-time regional energy market, and a capacity (reliability) requirement to participate (with its own long-term capacity market). But only the utilities participated. This changed when independent generators began to crop up, either buying plants from the utilities or building new ones, in the 80s and 90s. FERC, which already regulated all this transmission and wholesale electricity stuff, demanded that the overarching regional system operators be spun off so they wouldn’t exert any bias over how they handled the independent generators. The utilities didn’t resist this transition because they wanted an unbiased independent system operator (ISO) operating the energy and capacity markets and making the regional transmission planning decisions.

            Under the resulting arrangement, the utilities continue to own, and make all the new investments in, transmission facilities, but transmission that affects Grid operations (which is most of it) must be planned and approved by PJM. Utilities and independents can own, and either can invest all it wants, at its financial risk, in whatever sort of new generation it wants to build. Many utilities in the eastern US sold or spun off their generation; others (including Dominion and Exelon and AEP and many others) kept theirs; but generating is really a separate business now from transmission.

            And then there’s distribution and retail sales. These State-regulated utility activities continue to take place through entities with assigned, fixed, exclusive service territories — be they coops or Dominion or Appalachian or whomever. They are essentially in a separate business also. [One thing the SCC and FERC have done is make Dominion and every other electric utility separate its costs on its books so that each part of this — generation, transmission, distribution, retail sales — is accounted for separately.]

            Bigger utilities like Dominion and AEP and APS that were not already in an ISO began to feel left out of all of this market activity, but it still took a regulatory nudge or two to get them beyond their autonomy issues. Anyway, to make a long story short, Dominion joined PJM in the ’90s, and by all accounts it has worked out well for all concerned. As a technical matter, what this meant was that Dominion’s control center became one of several under the dispatch control of the PJM control center. They already coordinated together; this simply formalized who called the shots. And, Dominion became a participant in the PJM markets rather than running its own.

            So, who’s interfacing with a startup power management firm like Tumalow? Well, the customer of course, because he’s the one trying to save money on his bill. And Dominion, because it’s Dominion’s retail sales to its customer that are being affected here. But also PJM, because load curtailments (“negative generation”) are a resource that’s traded in the wholesale energy market. As I said earlier, Tumalow could deal with PJM directly, but I don’t believe that’s its niche. Instead, I believe it packages “load management” commitments from customers to curtail load when called upon to do so, and Dominion pays the customer for this commitment (or Tumalow as its agent) based on its SCC-approved retail tariff “experimental rate,” and then exercises the rights it has purchased from Tumalow whenever and however it helps Dominion best in the PJM wholesale energy market.

            LarryG, does that help put this in perspective?

        • I realized that my comment might lead some to assume that utilities buy all of their power through the PJM marketplace. That is not true. Utilities can use their own generation capacity (at whatever the associated cost) or they can have direct contracts with other utilities or non-utility generators. For example, a utility might have a contract for solar or wind energy with a third-party through a Power Purchase Agreement (PPA) which specifies the price to be paid for the energy.

          If a utility expects to have excess capacity that is economically competitive, they can choose to bid it on the day-ahead or 5-minute spot market. They can also purchase power from the PJM market if the spot market price is cheaper than their next available owned unit. Prices depend on distance between the generator and the buyer and the costs and constraints of the transmission system – using something called Locational Marginal Pricing. It is a constant dance of optimization. But one that can be reasonably modeled. Today’s communication and computer technology makes the process much faster and easier. Back in the old days, some of the first uses of fax technology was to exchange information between power control centers.

      • PJM sounds like it trumps the SCC on some issues – for instance where transmission and even generation infrastructure and facilities go.

        • All members of PJM coordinate changes in generation and transmission use with PJM. PJM has the right to override any utility decision regarding the use of these assets.

          PJM requires utilities to plan and meet their obligations and gives them permission to proceed with their proposals. The SCC still must approve plans and construction requests for facilities sited solely in Virginia. So utilities have several hoops through which to jump.

        • Yes, but. TomH is correct, but let me address your statement “PJM sounds like it trumps the SCC on some issues” a little differently. PJM will try to solicit bids to get whatever generation and transmission is needed built in time to keep the Grid functioning. Planning an adequate Grid has devolved on PJM. But PJM doesn’t own basically a damned thing except computers and communications gear. It is an ISO and an RTO; it is an OPERATOR, not a rate regulator or a siting authority or a retail vendor of services.

          If you’re PJM and you need generation, you send up warnings about how high the capacity market price is going to go next year and thereafter if someone doesn’t get off their duff and build it; but you, PJM, don’t build it yourself. PJM’s tool to compel capacity to be built is that, the price of admission to the energy market is that energy buyers who are also retail sellers inside PJM must bring enough generating capacity (either owned or under contract) to meet their peak load, or they aren’t allowed to play. They can’t just lean on the PJM energy market without providing PJM with the resources to run that market.

          If you’re PJM and you want to get transmission built, you go first to the utility that’s located where you need the transmission and ask them to build it. They are usually way ahead of you looking to make that investment and will go to FERC and get an approved cost based rate increment for doing so. Actually, the PJM planning process is transparent and open to all bidders, so the invitation goes out and you see if there’s a group of utilities or even an independent entity out there that would be interested in coming in and building it. For example, National Grid, originally a British concern, owns a lot of transmission as well as regular utility assets in this country now. Usually the local utility has the advantage and sews up the deal, or at least a key role, because they know best how to handle the local siting and political issues.

          The FERC regulates transmission rates; but the State utility commission (e.g. the VSCC) has a critical role at a couple of levels. First, it must approve the siting of the transmission line in Virginia by issuing a “certificate of public convenience and necessity” (COPN). Under old fashioned COPN laws, if the local utility doesn’t build it, the outside will have to become qualified as a Virginia utility and go get VSCC permission, because only a Virginia electric utility can condemn land etc. in Virginia. [BTW, this contrasts sharply with natural gas regulation, where the COPN for a gas pipeline is issued by the FERC.]

          Second, Virginia subjects its electric utilities to an integrated resource planning process. It doesn’t follow that the SCC regulates the transmission rate that results, or that Dominion couldn’t buy future capacity resources under simple contract from third parties including out of state entities, but Dominion isn’t going to ignore the SCC’s role in Dominions overall financial planning to serve its customers by not talking about all its capital needs including the transmission and generation parts. On the contrary, Dominion wants to invest in these big assets, and wants SCC approval and buy-in for it to do so. Indeed the game in Virginia is rigged by the GA with Dominion’s full concurrance to get as much SCC buy-in as possible. Why not? DVP has to go to the SCC to get siting and eventually financing approval for all these assets anyway, so getting the SCC involved up front and across the board in the DRP process gets everyone on the same page, particularly politically, before DVP has to deal with any blind alleys!

      • Tom, I’m curious about this statement in your comment above:

        “The good news is that for transmission that is used interstate, FERC usually allows a higher rate of return than is allowed by the SCC.”

        I’m wondering why you think a higher ROE is necessary for transmission, which is virtually a risk free investment once built?

        Rates set by FERC for transmission (all of which is in interstate commerce, by the way) flow directly through to Virginia customers of DVP and Apco by virtue of Va. Code Section 56-585.1 A 4. The SCC no longer sets the ROE on any transmission facilities.

        • I meant that from a utility’s point of view. They get a bonus (a higher return) by going through an extra level of review.

          As a ratepayer or a citizen of a state, I would be concerned about guaranteeing such a high rate of return, especially during a prolonged stretch of low interest rates. There are no non-regulated businesses that are getting the guaranteed rates of return that utilities are getting nowadays. If they do get higher rates of return, it is because they are providing far more value to the customer.

          • Thanks for the response. Now I see what you were getting at. Interestingly, Virginia law requires DVP and Apco to belong to regional transmission organizations and both ultimately chose to join PJM. For agreeing to obey state law, the FERC has gratefully awarded them bonus returns on transmission projects in the amount of about 50 basis points. DVP’s FERC ROE is 13.5% Not too bad, eh?

    • what would be better?

      I depends on how far you look into the future and what you assume the portion of generation is provided by renewables. Some experts predict that 80% of our nation’s electric energy could be provided by renewables by 2050.

      Combined-cycle plants are not able to cycle up and down quickly enough to meet the variation in renewable generation. They are complex facilities and rapid changes in operation threaten the life span of important components. Simple combustion turbines cycle up and down within minutes and can match load variations more easily, but they are expensive because they are used only about 10% of the time so their capital cost is covered by just a short time of operation.

      Batteries respond in milliseconds, but are just beginning to be cost competitive. The co-op where I lived on Kauai’i is now 95% solar powered. They are ordering a large battery system so they can shut down their expensive diesel peakers and seldom use the combined-cycle plant that was built less than 15 years ago. Their rates are considerably higher than ours which allows this to be affordable for them now. But it is an example how rapidly our electrical generation picture is evolving. We are now making decisions about plants that will have a financial life of 36 years and an operating life of 40 – 50 years. We are not even discussing the ramifications of far cheaper options being available just a few years into their life spans.

      • The situation in Germany was not all that different than you describe when they began their “Energiewende” transformation of the German energy Grid through a massive promotion and investment in rooftop solar and offshore wind power. The Discover article I mentioned earlier discusses the history of that revolution, at http://discovermagazine.com/2015/july-aug/18-germany-bright-idea (you can’t download it all unless you are a subscriber). Appparently, after some early experiments they really got started under an aggressive new law in 2000, and now they are over 20% renewables in Germany. But it did not come without massive government subsidies and now they are at some very expensive forks-in-the-road.

        Personally I believe 80% renewables in the US is a pie-in-the-sky goal; I don’t think the increments beyond 20% they are now reaching for in Germany are going to come easily or without steepening political resistance — both to the subsidies themselves, and to the environmental impacts (think, Surry to Williamsburg James River Crossing, exponentially multiplied). Apparently many Germans would agree. But up to 20%? We could do that — and what followed if anything would be based on experience. Meanwhile, I don’t see any end to the Grid as we know it, or to retail electric service as we know it, at least for many decades. Adapted, yes; eliminated, no.

        • I don’t see 80% by 2050 as a goal necessarily. It is more like an economic probability. That would take you out past the date where all but the newest fossil units would be retired. No new nuclear units would be added during that period unless they found a way to reduce capital costs by at least 500%, so the world would be left with cheap, distributed renewable generation with appropriate storage serving a load less than today’s while supporting a much more vibrant economy. The distribution grid is the foundation for this future. Customers need an adaptable, two way grid which provides a multitude of choices, guided by an engaged, prosperous utility.

          None of this would require any great leaps in technology, although many great innovations are on the way which will speed this up. We have seen the computer industry and telecommunications industry transform themselves in a 15 year period. This transition, if not hindered, will occur even faster since it is a combination of energy, digital technology and communications.

          I think 20% penetration by renewables is reasonable by 2030. Many states have goals at that level or higher right now for 2030. But Dominion is planning with its aggressive solar plan to have maybe just 4% by that same time. The difficulty with such a position, is that Dominion seems to believe that by dragging their feet and erecting barriers using the GA and the SCC that they will benefit by extending the old regulatory model. By choosing this route they will have put the interests of their shareholders above the interests of their customers. When these two groups are set against one another, the company is in for trouble, regulated or not.

          As gas prices rise and utility bills increase, customers will vote with their pocketbook and invest in renewables and energy efficiency (or they will vote with their feet and move out of state). For every 1 -2 % increase in capacity from the use of renewables by customers, utility revenues can decline by up to 6 – 10%. If Dominion has ignored reality and instead kept the present rate structure and invested in long-term central station projects rather than in developing a robust grid as a platform for customer choice and third-party developers, they will embark on a long, slow decline. Partially used plants and lower revenues will require emergency rate relief which further drives away customers – and the spiral continues. Contrast this to innovative rate structures which send the right signals for customers and third-parties to invest in lowering energy use and developing distributed generation, while keeping the utility profitable. Rates might go up but bills will go down and the system becomes more reliable.

          The real challenge is to change the way we see things and to let go of old habits which no longer serve us.

  8. @Acbar – thank you – and you other guys also.

    It sounds like Dominion can be entrepreneurial and if I understand correctly – can sell excess power at higher rates via PJM to other states than the SCC will allow to Virginia rate-payers.

    What happens when DVP has to buy power from PJM and it exceeds the cost that the SCC will allow to be charged to Virginia rate-payers?

    • PJM is a multi-state wholesale market. The SCC sets retail rates for customers in Virginia. Customers are not charged based upon what type of generation was used to fulfill their load. When peakers are required, the cost of their operation is above the retail rates of customers. But their part-time use is factored into the overall costs used to develop the retail rates. If the need for expensive peak generation is less than is predicted in the rates, Dominion makes more money. If it is greater, due to extreme weather or other factors, Dominion makes less profit. They pass on less to the stockholders or file for rate relief to improve their profits.

      Many state regulatory agencies are looking at using more dynamic pricing signals (transactional pricing) to let the market (and customers) have more of a real-time decision-making role in how much and when energy is used. This would eventually replace more of the after-the-fact, slow to respond rate making process that has been the primary means of utility regulation for over a century. Both utilities and regulators are often reluctant to give up a system they know so well, even if it is becoming less and less effective at producing a low-cost energy system.

  9. here’s the categories on my REC bill looks like:

    Distribution Delivery
    Electricity Supply Service
    Power Cost Adjustment 12.85
    Virginia Consumption Tax 2.37
    County Tax 2.00

    what’s the power cost adjustment for?

    • Your REC bill? You are a coop customer, not served by DVP directly?

    • Larry,

      The power and fuel cost adjustments on utility bills adjust the bills monthly for changes in fuel costs or purchased power costs that are greater than the costs used to calculate the base rate. These are pass through costs. The utilities don’t make any profit on them. They came about to avoid the need for constant rate cases to keep the utilities up to date with constantly changing fuel prices (which also affect purchased power costs). They vary according to price changes and the amount of electricity you consume.

      But these adjustments also serve as an easy way for utilities to get what they want. For example, when the new Brunswick gas-fired Combine Cycle plant comes on line next year, Dominion will get a new rate rider to recover the cost of the new plant, plus a return to shareholders. Then as the price of natural gas goes up beyond the price they have in the base rate, they will get full recovery of those added expenses. Dominion gets a 10% return on a billion dollar investment and all of their expenses covered. The rate payer just keeps paying more for the same amount of electricity every year, with very little say in the matter – and the regulators say that they have done their job.

      • so .. if the fuel costs are passed through to the customers (which I’m not surprised)…

        then the costs that are fixed and not passed through are non-fuel costs …. what it costs to operate the grid, distribution, and generation and the capital costs (done with rate riders?).

        this is done utility-wide – ? i.e. all DVP rate payers will pay for the new gas plant?

        and DVP can then ALSO use that gas plant to generate power to be sold – at for-profit at higher rates to PJM?

        seems like other purchasers of DVP-generated power from PJM should also help pay for capital costs rather than just DVP ratepayers.

        you know this IS danged complicated and I bet that only very few folks mostly in the bowels of DVP and industry professionals know how it truly works – and the ratepayer and public are largely clueless.

        I don’t even see how a bureaucrat at the SCC could have enough knowledge and expertise to even analyze DVP financials..to determine what is a fair regulated price.

        • “Seems like other purchasers of DVP-generated power from PJM should also help pay for capital costs rather than just DVP ratepayers.”

          That is, in fact, the case for certain investments. If Dominion builds the Surry-Skiffe’s Creek transmission line, 50% of the cost will be shared across the PJM system. Likewise, when other utilities build transmission capacity, Dominion (and other Virginia power companies) pay a share. I think this applies to transmission lines only, but it shows you how complicated it all gets.

          That’s why I’ve been hesitant to single out Dominion for praise or blame on such things as renewables — I just don’t understand how the system works yet. I’m getting there, but there is a ways to go. The business was a lot simpler 10 years ago before Dominion joined PJM.

          • which leads us back to non-DVP players and renewable generators.

            can a non-DVP business sell renewable (or conventional) power at a guaranteed profit margin?

            😉

    • LarryG, this is what I found online:

      First, go to REC’s website at https://www.myrec.coop/content-documents/Schedule%20A.pdf. Schedule A page 2, incorporates by reference: https://www.myrec.coop/content-documents/Schedule%20PCA-1.pdf . Schedule PCA-1 pages 1 and 2 is what you are looking for, the list of variables is all significant but the big one is on page 2, the “EA” from ODEC. This reflects the varying cost of purchased power negotiated by ODEC (on behalf of its members) with several sources, including DVP, ODEC’s own generation, and the biggest variable, ODEC’s purchases from PJM.

    • Second, get ODEC’s tariff under which it supplies REC. ODEC does not post this on its website. To me this is a near-criminal omission for a customer-service-oriented public utility! However, there is a back-door way to get it, from the FERC. Go to: https://elibrary.ferc.gov/IDMWS/common/opennat.asp?fileID=13360851 Here you will find not only the most recent update of ODEC’s tariff but also a filing transmittal letter that does a reasonably good job of explaining how ODEC’s purchased power clause (REC’s “EA”) works. PJM’s energy market price plays a prominent role along with ODEC’s own generation. Also here is the FERC Staff’s extensive critique of the ODEC filing: https://elibrary.ferc.gov/IDMWS/common/OpenNat.asp?fileID=13646083 I don’t see a final FERC order issued in this docket, ER13-2483, yet, so ODEC’s revised tariff (although filed in 2013) may still not yet be approved, in which case the old one from 2011 is what’s still in effect and flowing through to you through REC’s retail rates.

      Finally, let me note that DVP has nothing to do with ODEC’s purchased power adjustment rate charged to REC. It’s all PJM and other ODEC purchases and ODEC-owned generation (some of which is sold into the PJM market). DVP only enters the picture as the transmission owner charging a transmission rate to ODEC for deliveries to ODEC customers like REC. I believe DVP also bills REC directly for some transmission services.

      • @Acbar – thanks for finding and sharing the documents which are more arcane than elucidatory but still a step forward!

        How would we know from who REC purchases power?

        Can they purchase it from any source like ODEC, PJM or DVP or other 3rd party providers?

        When they do that – HOW is that power DELIVERED?

        does someone put it into the grid and REC takes out of the grid the amount it bought or are there dedicated power lines to REC from ODEC or other providers?

        Finally – it seems pretty straight forward in terms of buying the power then passing that cost on to it’s ratepayers.. I assume they all pay according to their use and their pro-rata share such that if REC has to buy more power than normal – the “adjustment” is allocated out to each ratepayer in proportion to their use share?

        • LarryG, this is a good opportunity to review ratemaking basics so let the lecture continue! You ask:

          “How would we know from who REC purchases power?” Start with the electric retail tariff: that’s the “Schedule PCA-1” link I gave you. Here is the meat of it, in two parts: (1) “The projected total cost of purchased power for the applicable rate year from all sources, including costs associated with the Energy Adjustment part of the ODEC Tariff, that will be charged to Accounts 555 through 557.” plus (2) “ODEC’s Energy Adjustment rate from time to time, expressed in $ per kWh.” That means, in rate-speak, REC passes on through this Schedule PCA-1 certain costs assigned by the FERC accounting regulations (FERC writes these rules for all electric utilities) to unifirm system of accounts #s 555-557, which are in fact defined in the Code of Federal Regulations as purchased power costs — including, here specifically (but not exclusively) those p.p. costs incurred by ODEC, plus, a flow-through of ODEC’s own purchased power adjustment factor (ODEC Schedule EA). So this doesn’t definitively answer the question, does REC have any purchased power costs that REC assigns to accts. 555-557 other than those passed along by ODEC? You would have to ask REC to be certain — but I will go out on a limb and say I suspect not. That is because the way REC’s tariff is written, they enumerate all the other sources of cost specifically and I think this was just a catch-all in case REC ever decided to go around ODEC (which ODEC would be very upset to have happen!). In fact I believe REC’s agreement with ODEC is an exclusive wholesale power purchase arrangement that forbids REC to buy from anyone else, but you will have to read up on that arrangement in the documents under that other link, the ODEC tariff filed with FERC; Or you could ask REC to tell you.

          “Can they purchase it from any source like ODEC, PJM or DVP or other 3rd party providers?” Haven’t researched this for ODEC-REC but typically a coop’s wholesale power supply agreement is exclusive except that it doesn’t forbid the buyer from also buying small amounts from its own retail customers (i.e., D.G.). The answer is somewhere in those FERC documents, also.

          “When they do that – HOW is that power DELIVERED?” It reaches the REC system over transmission lines owned by many different utilities and operated by PJM. REC is the transmission customer here under the terms of PJM’s network transmission service tariff. However ODEC, as the supplier, is doing all the scheduling of its various contracted-for sources.

          “Does someone put it into the grid and REC takes out of the grid the amount it bought or are there dedicated power lines to REC from ODEC or other providers?” Neither. As a “network customer” of PJM, REC is entitled to withdraw from the PJM grid AS MUCH POWER AS IT REQUIRES for its load (this is called “requirements service”). So it is not limited to a specific amount. BUT (a big “but”), in order to be a network customer in PJM with retail load obligations, REC has to qualify under PJM’s tariff by providing PJM with the contract right to call on a supply of power equal to REC’s forecast annual peak load plus reserves. REC’s demonstration of this is its contract with ODEC.

          “Finally – it seems pretty straight forward in terms of buying the power then passing that cost on to it’s ratepayers. I assume they all pay according to their use and their pro-rata share such that if REC has to buy more power than normal – the “adjustment” is allocated out to each ratepayer in proportion to their use share?” Yes, that’s how I read the math of REC Schedule A, which is a per-kilowatthour charge. The adjustment flowing from Schedule PCA-1 adjusts the per-kWh charge under Schedule A. Note, under Schedule PCA-1 the total purchase power cost is reduced to a kWh adjustment by dividing by the “total projected kWh to be purchased in the applicable rate year” adjusted for losses.

  10. TomH, you say, ” Customers are not charged based upon what type of generation was used to fulfill their load. When peakers are required, the cost of their operation is above the retail rates of customers. ” This is true. And your are correct, we have to deal with “the after-the-fact, slow to respond rate making process that has been the primary means of utility regulation for over a century.” But we have averaged, levelized rates for residential customers for a reason: dynamic pricing is complicated as hell, confusing for the typical homeowner anyway, and only those computer-savvy techy nerds from NoVa will put up with it, let alone take advantage of it properly by changing their behavior!

    You said, “If the need for expensive peak generation is less than is predicted in the rates, Dominion makes more money.” Well, yes. But that’s a temporary ratemaking advantage that only applies until the SCC re-sets rates, and things won’t change so fast so steadily that DVP can count on it; in fact a hot summer can wipe out a year’s worth of that advantage in just a few days. Rates are based on averaged past experience and forecasts which are inherently averages.

    But so far we haven’t mentioned the influence of the grid. PJM DOES use dynamic pricing in its energy market. If DVP builds too many peakers it’s the PJM marketplace which dispatch them and will buy their output if they are the economic next-least-cost units in PJM to run. Except, of course, if every other utility out there has too many peakers also and the competitive dynamic price remains too low. My point is, it’s supply and demand across all of PJM that matters, not just in Va Pwr’s territory, and DVP — wearing its hat as a generation owner — has to build generation to make money in THAT market not from retail sales to its own customers.

    Now I am no fan of the SCC’s IRP process in VA because the utility has to come in and couch everything in terms of what’s best for the VA retail customer when that is in fact a reconstruction for regulatory purposes, not the way DVP actually looks at it, where forecasts of pan-mid-Atlantic/midwest/upper South market conditions drive the train.

    You add, “Both utilities and regulators are often reluctant to give up a system they know so well, even if it is becoming less and less effective at producing a low-cost energy system.” DVP may have its head stuck deep in the sand or up its anatomy, blind to the potential for distributed generation, but I very much doubt it; they are likely very alert to the risks of being caught with too much unusable generation and a declining demand curve; at the very least that debate is surely going on in there. Just looking at the facts as an outsider, I’d say it makes intuitive good sense for DVP to modernize its generation fleet with high-efficiency cycling (mid range) generation, like NGCC, and retiring those old coal units (inefficient and inflexible to operate and labor-intensive particularly when run infrequently, leaving aside their environmental profile), and keeping the nukes running as long as possible (because they are already paid for and now they make money hand-over-fist, and as long as they run you don’t have to pay the cost to decommission them), because all of the above will make them the most cash in the PJM energy market. As LarryG has noted here, DVP must pair off the potential for distributed generation with the kinds of generation that complement it; and guess what, that is exactly what they are doing! My understanding is, if you subtract all the old gen. they ought to be retiring all across PJM anyway, plus add on 20% or more for new customer-owned distributed generation, plus another 10% or so for new independent generation, you STILL have a market for those NGCC-type cycling units well beyond their planned useful life. Build the pipelines to supply them with the cheapest gas available and they remain even more competitive against the other, similar units being planned and built across PJM.

    Moreover DVP is dabbling in solar. I agree, they are open to criticism for trying too hard to push it on a central-plant rather than a distributed-generation (d.g.) basis, but at least they are on track to gain a lot of experience working with it. And as I’ve said before here, wind power in VA (particularly offshore) cannot be a winner unless someone committed up-front to the scaled-up infrastructure for a huge off-shore wind investment (platforms, transmission lines, on-shore O&M support facilities) gets involved, and that of course is the antithesis of small-scale distributed generation!

    Bottom line, the grid has to adapt to d.g. but it won’t be rendered obsolete by it; on the contrary, our task as d.g. supporters is the massive, massive job of educating the building industry and local politicians how to accommodate it, educating homeowners and consumers to want it, and educating the likes of DVP in how best to help promote it with capital-cost/installation subsidies (but without operating/payment subsidies, which I believe are ultimately counter-productive).

    • “But we have averaged, levelized rates for residential customers for a reason: dynamic pricing is complicated as hell, confusing for the typical homeowner anyway, and only those computer-savvy techy nerds from NoVa will put up with it, let alone take advantage of it properly by changing their behavior!”

      Yes. Lot’s to be done on this one. Dominion has only about 4% penetration of smart meters. And they aren’t that smart, they really only replace meter readers and service connections. They need to have two-way communication with no data drop-outs. The development of home energy networks with Google Nest thermostats, smart appliances and integrated heating, cooling and hot water systems will make things much simpler for homeowners to reduce energy usage, or at least move it off peak, with little need for their oversight. Dominion could work with third-party installers and provide on-bill payments to simplify the process and increase adoption. This is all under development and not too many years away. If Dominion doesn’t choose to make money in this market (especially on the PJM Demand Response market) and actively work to create rates to support it while maintaining their profitability – others such as Home Depot and Lowe’s or other independent aggregators will step in to do it and Dominion will only lose revenues with nothing to show for it. They are fighting this because they see it as a threat rather than an opportunity.

      “Except, of course, if every other utility out there has too many peakers also and the competitive dynamic price remains too low. My point is, it’s supply and demand across all of PJM that matters, not just in Va Pwr’s territory, and DVP — wearing its hat as a generation owner — has to build generation to make money in THAT market not from retail sales to its own customers.”

      Yes, I agree. Even though the SCC has backed away from their deregulation policies, both they and FERC have required that utilities change their bookkeeping so that generation, transmission, and distribution/retail expenses are dealt with separately, which effectively makes Dominion an independent generator in the PJM marketplace (plus the fact that they operate generation in multiple states). But they still get the bulk of their cost recovery and shareholder return through the rate making process I would guess.

      “Just looking at the facts as an outsider, I’d say it makes intuitive good sense for DVP to modernize its generation fleet with high-efficiency cycling (mid range) generation, like NGCC, and retiring those old coal units (inefficient and inflexible to operate and labor-intensive particularly when run infrequently.”

      Yes, I think even without the CPP, utilities would move forward with replacing old, inefficient coal plants with the new NGCC units, perhaps just not as fast. But with the CPP, they can ask to get paid more for the process. My dispute is with how much new capacity they are building and the underlying assumptions.

      My fundamental contention is that the first place every utility in the U.S. should be looking for new capacity is with energy efficiency. The average price of energy efficiency is 2.5 cents per KWh. This is less than half the price of the NGCC units, with no risk of fuel price increases. Everything gets cheaper when the load is smaller, transmission, distribution, new capacity additions, everything. This is so obvious – nobody sees it. Or those that do (the utilities) are threatened by the loss of revenue, which can be dealt with. California has done this successfully. California’s energy intensity (energy used per dollar of state GDP) is half of what we have in Virginia, and it has not increased since the 70’s. Tapping this market lowers customers, bills, builds vibrant new businesses in the state, avoids expensive new generating capacity, and can be done in a way where the utility can make money from the process and stay financially healthy. The DSM programs the SCC and Dominion are working on are extensions of programs that have been around for decades. And their customers don’t trust them so there is not widespread adoption of the programs (and it is not simple and easy enough for them).

      Imagine instead that there was an aggressive program to first work on state and local government buildings, including schools and street lighting. Basic changes using existing technology could reduce energy use on average by 20 – 40%. Deeper retrofits could save even more. Amazingly, spending more money on energy efficiency makes the cost/benefit even greater, because you break through the cost barrier by reducing the size of systems or by avoiding them entirely. This would save ratepayers money by reducing peaks and avoiding new capacity charges and they would also save as taxpayers (or gain more services).

      The next phase would be for Commercial and Industrial customers. Lowering their bills would make them more competitive and better employers. When the home energy systems have matured the homeowners would be next.

      “keeping the nukes running as long as possible (because they are already paid for and now they make money hand-over-fist, and as long as they run you don’t have to pay the cost to decommission them),”

      This one I am a little less certain about. Have the Surry and North Anna units all received their 20 year license renewals? Often to obtain an extension, steam generators and other safety related items must be upgraded and replaced in order to gain approval. This often makes them uneconomic generators. Five or six nuclear plants around the country have been closed or are scheduled to close because they cannot economically compete. I believe Dominion recently closed their Kewaunee nuclear plant because it was not cost competitive in the MISO marketplace.

      Fuel costs have always been a selling point for nuclear plants. Recent fuel reprocessing has kept costs low (while creating weapons grade material and creating a security risk). However, I have seen reports that up to 65% of the materials for nuclear fuel are now imported and fuel costs are rising. Dominion definitely wants to use the nukes for CPP purposes.

      Each utility was required during the life of their nuclear facilities to set aside money in a decommissioning fund so those expenses would be provided for. Some utilities are choosing not to renew for another 20 years so that they can gain access to the decommissioning funds. Apparently, the cash shows up on their balance sheets now, even though it would be spent over a number of years. This might bump up the stock price or make debt cheaper. Many issues are influencing nuclear plants. TVA might be bringing their Watts Bar Unit 2 online by the end of the year (or early 2016). Begun 40 years ago, stopped in 1998 (80% complete) for lack of demand, it is now coming in at $4.5 billion for 1150 MW. They also have a new 1000 MW NGCC unit coming online for just under a billion.

      “DVP must pair off the potential for distributed generation with the kinds of generation that complement it; and guess what, that is exactly what they are doing!”

      Yes, but the combined-cycle plants are not the complements, the peakers are. I believe they are proposing in the IRP to have 1000 MW of new peaking capacity for every 4000 MW of new solar.

      “you STILL have a market for those NGCC-type cycling units well beyond their planned useful life”

      This is one that I am very uncertain about. I am not convinced that they will have a market after their first 10 years of life, let alone 40 – 60 years out, for two reasons. First, fuel costs. In the IRP, Dominion is projecting the high fuel cost case to be 5% higher than the base case over the life of the plant. Really? When Australia rushed to use their natural gas for non-traditional uses such as burning it in power plants and exporting LNG, their prices for domestic natural gas increased 300 – 400%. Factories closed or switched back to coal. Homeowner’s utility rates soared. We are on that same path and Dominion is front and center with their Cove Point LNG facility.

      Independent experts predict that the output of affordable natural gas ($4 mcf) from the Marcellus will peak about 2018 – 2020. After that more gas will be available but at much higher prices. Improved technology always offers hope, but the productivity gains from technology peaked in the second half of last year and are now declining in the Marcellus. More than 1000 new wells must be drilled each year just to maintain production levels.

      Energy prices for NGCC units are approximately 50% capital costs and 50% fuel costs. If by 2025 – 2030 the fuel cost is 300% higher, will the Greensville plant scheduled to come on line in 2019 really be economically dispatched for baseload or high intermediate load service at prices 150% higher than currently projected? Then who pays? Especially when energy efficiency is available at $.02 – $.03 /kWh, wind at $.03, solar below $.05 /kWh. Storage will come on strong, because it is being held back by the low price of gas for peakers. The peaking units will be affected too, but not as much as the combined-cycle units since peaker’s energy prices are mostly in the capital cost.

      Second; a possible future carbon price. Although, natural gas-fired units release about ½ of the CO2 that coal units do, they still release a good deal of CO2. Eventually, a further reduction in CPP targets or other means of reducing carbon emissions will be added to the cost of natural gas generating units. This will further separate the cost of NGCC units from renewable alternatives which have no fuel costs and are carbon free.

      “Moreover DVP is dabbling in solar. I agree, they are open to criticism for trying too hard to push it on a central-plant rather than a distributed-generation (d.g.) basis, but at least they are on track to gain a lot of experience working with it.”

      Dominion has sold their entire portfolio of solar projects out West so that they can concentrate on developing solar projects in Virginia. They definitely are keeping the central station mindset though. Utility scale solar is shown to be cheaper than distributed solar. Some of this savings is due to scale, but most of it is due to transmission and substation costs related to connecting the facility to the grid have not been included in the solar project costs, so it is shown to have a disproportionate advantage over smaller distributed units. Dominion is avoiding this issue by locating its early large projects at its generating plant sites and using existing substations and transmission lines. Land costs are also not an issue since it is using plant property that is not available for other purposes anyway.

      But this negates one of the great advantages of solar – that it can be easily distributed. This contributes to grid reliability and resiliency, reduces transmission losses and lessens solar variability. There is no mention in the IRP of customer and third-party solar which could offset the need for new Dominion capacity. With the right policies and grid improvements, Dominion could unleash a flood of distributed energy projects in Virginia. They seem to have the attitude that if they don’t own it, it’s not a resource. Utilities in other states are considering generating sources owned by others in their long term plans.

      “wind power in VA (particularly offshore) cannot be a winner unless someone committed up-front to the scaled-up infrastructure for a huge off-shore wind investment”

      I agree. I would encourage Dominion not to spend any ratepayer money on the offshore project beyond what they have received in grants. Even with the shallow area offshore of Virginia an entire manufacturing infrastructure must be developed for the east coast before this becomes realistic. This should be done by federal research projects. Iberdrola the Spanish energy giant and wind turbine manufacturer which owns several New York utilities could pioneer this in the Great Lakes before it is rolled out in the ocean.

      The Virginia energy plan has identified 800 MW of onshore wind potential in the state. Although, I don’t know if I would be fond of seeing wind turbines sticking up above the Alleghenies, they would probably be more accepted there than along the highly populated eastern shore. And they would be close to the pumped storage plant.

      “Bottom line, the grid has to adapt to d.g. but it won’t be rendered obsolete by it; on the contrary, our task as d.g. supporters is the massive, massive job of educating the building industry and local politicians how to accommodate it, educating homeowners and consumers to want it, and educating the likes of DVP in how best to help promote it with capital-cost/installation subsidies (but without operating/payment subsidies, which I believe are ultimately counter-productive).”

      Hear, hear! I completely agree. The distribution grid is fundamental to a 21st century energy system. The utility responsible for it must be actively engaged and financially healthy. The Distribution Services Provider (as envisioned by NY REV) is the linchpin in making the new energy model function. You are exacting right – DVP and the SCC must be shown how transforming to this new way of managing energy in Virginia will keep DVP healthy, lower customer’s bills while increasing their choices, and provide a boost to the state economy. If people and politicians could see the potential of this they couldn’t help but support it. Currently, I think it is Dominion Resources fear that a decline in cash flow from DVP to its other subsidiaries will be a great disruption to its overall business plan. They are bright, determined people, but they see this industry through the lens of the 20th century. Anything new is perceived as a threat rather than an opportunity. Their 2015 IRP extends the 20th century business model 30 -40 years into the 21st century and pits the interest of their customers against the interests of their shareholders. This is not sustainable. I don’t have enough experience or knowledge of the SCC in Virginia to know if they have the independence or inclination to get this started on their own.

      • TomH, thank you for the detailed reply; I really don’t like to go on and on about such an arcane business as PJM is in, but you clearly understand it, and there are people out there like JB who are trying to get up to speed on it. I had a hand in creating PJM and I think it’s under-appreciated what they have accomplished and what they do today, all rather behind-the-scenes.

        It’s essential background for what Jim discusses here, but it’s only background, to the real focus of BR which is what the heck is going on in the VA SCC and its GA lobbying and the other critical State and local drivers of the Virginia economy. The problem is, today no-one can understand the VSCC or Dominion without understanding the FERC and PJM as well as a few basics about the electric industry itself in a time of rapid change. D.G. can and probably will be a large part of that change.

        You say, “Currently, I think it is Dominion Resources fear that a decline in cash flow from DVP to its other subsidiaries will be a great disruption to its overall business plan.” I’m sure there are some senior folks who work at DVP who feel that way. A big company with many thousands of employees has diverse opinions and generational divides even on the inside! But so far, I see no evidence of a DVP business plan other that “do what the public wants, provided we can make enough profit to finance what we have to do and keep our shareholders content doing it.” There is tension, but not necessarily conflict, in such a plan.

        BTW, I’m retired now and awaiting the end of two weeks of Noah’s Flood conditions on the lower Bay, and I’ve enjoyed this past couple of days’ writing distraction immensely, but normally I just like to read quietly what Jim has to post and make the occasional snide remark. Hope you can be more outspoken on a sustained basis.

        • Acbar,

          I was wondering where the excellent knowledge of PJM and general utility issues was coming from. Thank for your contributions, both to the discussion and to PJM. I believe that PJM is an excellent example of what can be done with collaboration guided by information and market principles. There is a chance that some of the lessons can be brought to the retail level. We will need technology to simplify things for customers (or their aggregators) and a Distribution Service Provider (utility) that is willing to share information and open access to a robust grid.

          I spent a number of years in utilities in two states and have great respect for the people who work in them. I was often confronted by people who thought utilities were the “bad guys”, which is not the case. They do tend to have a certain way of seeing things and often take time making a change, but that is usually guided by their responsibility for keeping the lights on for all those they serve.

          I appreciate the forum that Jim has provided and look forward to benefiting from the wisdom that you and others share. I am just one small voice trying to further the discussion of these issues. Decisions that we make in Virginia over the next few years will have long term consequences. These issues are too complex for most policy makers to take the time to deal with so they usually take their guidance from others. We need to find a way to simplify the issues so that Virginia citizens can step up and become responsible again for what happens in this state instead of expecting others to do it all for them.

  11. Jim Bacon:

    I had reservations about you decision to take some funding for BR from Dominion. Don’t get me wrong – as a hyper-capitalist I had no issue with you making a little money for all your hard work. I just wondered what would happen to the quality of the top notch product known as BaconsRebellion. My fears have been proven to be unfounded. The blog is notably better with the attention to energy and the attraction of many new, well informed readers (along with their astute

    • Thanks, Don, I’m glad to hear that your fears have been assuaged. I certainly agree that the caliber of discussion on the blog is top-flight. Thanks to our participants, we just may have the best open forum for the discussion of energy issues in Virginia today.

      This is how I always hoped the blog would work, with my journalism feeding great discussion, and then that discussion informing and prodding me to even better journalism.

  12. I concur with Don …. We are benefiting from some excellent commentary… where opinion is being backed up with more than just… opinion!

    much appreciated…

    though some of my more generalized opinions seem to be borne out…

    and one of the main ones is that essentially – what’s good for citizens and ratepayers may not be what DVP thinks is good for them especially when it comes to selling less electricity.

    Alas – I don’t see the SCC in the role of helping to find the sweet spot that benefits both but rather as a surrogate for DVP… though I might be convinced otherwise.

  13. TomH, one other thing demands more comment. You say, “My fundamental contention is that the first place every utility in the U.S. should be looking for new capacity is with energy efficiency.” I don’t disagree; but incidentally by saying that you raise a fundamental point about the scope of the electric utility enterprise. On the one hand, energy efficiency, viewed as a form of negative load growth, is a cheap way for an electric utility to meet demand (at least as long as the ‘low-hanging fruit’ is still there to grab). We should go for it.

    But on the other hand, the biggest arena for energy efficiency is in better home construction standards and retrofitting better home insulation. Telling the customer how to cut back on his own losses is one thing. Paying the customer to do so is more interventionist; and utilities aren’t always very good at designing such programs. Simply doing the work themselves gets even more problematic; paying the cost for contractors to go into low-income housing projects and re-doing the insulation can be popular, but is this what an electric utility ought to be doing, even if it’s cost effective for ratepayers to underwrite it? Lobbying to change local building codes to improve new construction standards is even more controversial.

    What I’m asking is, do we really want DVP or any other local electric utility to be so activist on energy efficiency? If so, and I think it’s a big “if,” the utility’s active intervention will come with a price: that is, we have to understand how to make energy efficiency a win-win for DVP also, and occasionally help them scope the problem and get political support for their fixes, not constantly stoke the anti-utility polarization we so often see.

    • Acbar,

      This is an excellent point. Asking a utility to aggressively promote energy efficiency often feels to them as if they are working against their own interest. This is partly a rate issue. Many states have decoupled rates so that utilities are not penalized by saving energy and lowering their revenues. California has the most experience with this. Even though this approach protects utilities’ profits from energy savings, it does not necessarily cure their desire to have a larger rate base and even greater returns.

      Vermont has recognized this conflict of interest and their energy efficiency programs are handled by a statewide non-profit. They probably have a higher cost of capital than a typical utility, but the overall success of the program might be greater. Perhaps, utilities could finance it and provide on-bill payment collection for the statewide organization to make it easier and cheaper.

      The building issue is a fundamental one. Those who develop housing or commercial buildings are often interested in the lowest initial cost so they can sell or rent the building quickly. Energy efficiency often gets little consideration. Architects and developers are not aware that a properly designed, highly efficient building can also have the lowest cost because it has smaller systems, motors, etc.

      We could push for better building codes, etc., but that usually involves multiple jurisdictions and is slow going. I prefer a simpler, more market based approach. A utility or other well-qualified authority could rate the energy use of a building, similar to an energy star rating for appliances. This would identify the typical annual cost of energy for the building, based on an identified rate which could be updated. Developers or landlords would pay the cost of the survey (or choose not to have one). Prospective residents or tenants could then make energy costs part of their purchase or rental decision. If a survey was not provided, that would tell them something and they could decide whether to take the risk.

      This would encourage people to be more energy aware, so buildings would become more efficient.

      • the issue of “voluntary” energy efficiency or mandated is an interesting one and one that probably has some partisan/philosophical aspects to it.

        we already have a fair number of organizations that “rate” energy use and promote higher levels of efficiency – LEED being the most visible to some.

        The EPA-mandated auto standards being ones that were and still are vociferously opposed and had the opponents prevailed – probably no question that we’d not have the level of efficiency that we have now. To a certain extent – you can credit govt – yes govt – with reducing oil imports as well as screwing up the underlying finances associated with fuel taxes!

        People are also familiar with the yellow energy labels which I think are no longer mandatory but certainly have guided us in our purchasing decisions on things like water heaters, fridges, and heat pumps.

        Clearly without the “influence” / “interference” of govt – to, at the least, require labelling of energy efficiency – we’d not be where we are right now. If you and I had no clue what the mileage was on a car or the energy use of a water heater or for that matter the “R” value of insulation, our purchasing decisions would be not near as easy or effective.

        I don’t think the “free market” really would, voluntarily, provide energy efficiency information without govt encouragement, mandates.

        and , oh sure, some companies would provide such “info” but if there were no govt rules – lies would be widespread… and customers, clueless.

        So, no.. I would not expect DVP to encourage energy conservation beyond the perfunctory PR efforts.. they now engage in.

        And the SCC, clearly has no interest in what role energy efficiency should play in ratepayer rates – either.

  14. re: interventionalist

    how about what any company would do – to adapt and evolve to disruptive changes?

    I’m still a skeptic of storage batteries and solar – short term – but what happens if solar and storage batteries leapfrog ahead quicker than thought – say – on the same scale that cell phones moved to smartphones? What has happened to the landline telephone business?

  15. I don’t want to “pollute” the discussion but I’m providing this to illustrate the role of the SCC in regulating ‘providers’ and HOW the SCC goes about deciding how much “profit” a company can make – almost irregardless of whether that company is providing competitive value.

    In other words, it APPEARS that the company presents their costs and the SCC then allows that company to tack on their profit – no matter whether their prices are in line with other providers – including govt – in that industry. I say “appears” because it’s not apparent that the SCC actually engages deciding if a given company is “efficient” in it’s operations much less if it is strategically positioning itself for future operations in changing markets.

    In other words – what is the role of the SCC and what is not?

    here’s the Article:

    ” Aqua Virginia customers may see increases”

    ” A recent report from the State Corporation Commission’s hearing examiner may herald rising costs for Aqua Virginia customers.
    In a Sept. 18 report filed by Howard P. Johnson Jr., the hearing examiner recommended that the SCC approve the majority of a proposed increase to Aqua’s revenues from water and wastewater services.
    Aqua Virginia initially filed an application in August 2014 with the SCC to raise its water rates between 14 percent and 15 percent and its sewer rates 4 percent to 5 percent—a combined revenue increase of $1.7 million statewide.
    Johnson’s recommendation approves $1.4 million in additional revenues, in increases of $986,909 for water services and $320,296 for wastewater services; an overall 9.25 percent return on equity for Aqua.”

    http://www.fredericksburg.com/news/local/caroline/aqua-virginia-customers-may-see-increases/article_44556d43-4e2b-5c78-9051-b1308fc23eee.html?showi=fbi

  16. I can explain the role of the SCC in setting rates. For investor-owned electric utilities DVP and Apco, the Commission is obligated to establish returns on equity and costs of capital, including return on equity, in the manner prescribed by Code of Virginia, Section 56-585.1 A 2. (For Aqua and other water and sewer companies, as well as for setting base rates for gas utilities, other Code requirements apply).

    The Code section that I have cited says that Commission “may use any methodology to determine such return…consistent with the public interest, but such return SHALL NOT BE SET LOWER than the average of the returns on common equity reported to the Securities and Exchange Commission for the three most recent annual periods..by not less than a majority of other investor-owned electric utilities in the peer group of the utility…” The “peer group” is also identified by statute to include investor-owned electric utilities that own and operate generation whose “principal operations are conducted in the southeastern United States east of the Mississippi River in either the states of West Virginia or Kentucky or in those states south of Virginia, excluding the state of Tennessee” and whose facilities are subject to regulation by a state utility regulatory commission, and who have “a bond rating assigned by Moody’s Investors Service of at least Baa[.]”

    From the peer group, the Commission is directed by statute to eliminate the two highest and the two lowest earned returns and then set the DVP or Apco return no lower than the return earned by a majority of the remaining companies. That generally is a group comprised of 12-13 utilities, mainly the Duke and Southern operating companies. So that sets the floor for the return and the upper end of the range of return can be no more than 300 basis points above the floor. DVP’s current allowed return is 10%, but in the biennial review just conducted evidence was introduced by DVP that it should be allowed a 10.75% ROE, which the Commission Staff and two other parties produced evidence that the return should be no higher than 9.5%. The Commission will issue an order in this case around November 1.

    In any ratemaking proceeding, the utility does not present its costs and the SCC allows it to “tack on their profit,” as Larry surmises above. Costs are audited by the Commission Staff CPAs and Staff economists determine what is the reasonable rate of return necessary to attract the capital needed by any utility to fund its operations. In the DVP biennial review case, for instance, the Staff and Company differed on the proper treatment of more than $100 million in costs. In this Aqua case that you provided a link to, the matter was heard by a Hearing Examiner who has issued a report of his findings. Parties in that case, including the Staff, have an opportunity to further contest any of the Examiner’s findings by filing what are called comments to the report. At some point, the Commission will enter a final order that will establish the proper level of recoverable costs plus the proper return the utility will have an opportunity (but not a guarantee) to recover via those rates in the upcoming year.

    If TomH and Acbar review this comment, I invite their views on whether the particular ratemaking process for DVP and Apco differs from the experience in the states that they are familiar with. Ratemaking for Aqua and the other non-electric companies I noted is fairly ordinary to any regulatory commission, in my understanding.

  17. Thanks, Rowinguy; I’d say it’s pretty standard. Which is to say, far from perfect, but it’s the result of a lot of regulatory experience with, and the widely-held conventions of, “cost plus” ratemaking.

    The one thing Virginia does is try to define the cost of equity determination and specifically the equity peer group; getting that far down into the weeds BY STATUTE is far from usual. Usually the statute simply says “thou shalt have just and reasonable rates” and leaves it up to the Commission and the courts to define j. and r. based on “expert” testimony. I seem to recall the VSCC went through a phase when they pushed the envelope nationally for low returns on equity, and this statute was the result of push-back. But the thing about ratemaking is, it’s like squeezing an amoeba, push in here and something pops out there — that is to say, the Commission always can find a way to get to the overall bottom line it thinks appropriate — so the regulated companies rarely win any advantage in the long run by such formulaic legislative tactics and they usually won’t risk antagonizing the Commission in the process of trying.

    LarryG surmises: “it APPEARS that the company presents their costs and the SCC then allows that company to tack on their profit – no matter whether their prices are in line with other providers.” I think fundamentally that is an accurate description of the methodology; but it omits the laborious process the SCC goes through, first to check out that presentation of historical costs, second to adjust those costs if not deemed representative of the future and to take account of major changes in operations and corporate structure coming up, third to divide up those costs so as to attribute a subset (including the right taxes) to the electric utility enterprise (both DVP and Apco are holding company structures) and within that to the VA electric “jurisdictional” customers subject to the rates being set — with all sorts of arcane rulings along the way about what is a “utility” vs “non-utility” expense and what is plant “in-service” vs “held for future use,” all in accordance with decades of Commission precedent and VA court decisions and precedent from elsewhere if there is any, and fourth, to add on an allowance for the future cost of new programs (like subsidizing renewables or energy efficiency). Then they “tack on the profit” which means allowing for the relatively fixed cost of existing debt plus the more speculative and contentious “cost of equity”: the rate of return deemed necessary to sustain the utility’s bond rating and to sell more stock at a reasonable price when it’s necessary to raise money, e.g. for new generation. That determination is based in part on what rate of return other utilities in a similar situation are being allowed.

    But ultimately, LarryG, all those little increments of cost + profit add up to this: if people in-the-know are happy with the utility service rendered (including the competitiveness of its rates vs the competition) and the politicians are not riled about something the utility did, it will get a reasonable return on a reasonably-determined cost of service; but if they aren’t, it won’t — THAT is where the real politics comes in and the real judgment takes place and there’s no statute ever written that could dictate that result. All that cost of service stuff merely applies objective standards to the ratemaking process so that both regulators and the utility can claim the result isn’t too arbitrary.

  18. Thank you, Jim B, for supplying such a forum for dissecting the past influence and future path of one of Virginia’s biggest economic and political drivers, the energy business. Clearly DVP is one of the biggest Virginia participants in that arena.

    Dominion, wearing the hat of a “public service company,” has a big “public service” role — indeed, obligation — to fulfill. They are not elected, not appointed, not government at all, yet they fulfill a public function with privileges (like a statutory monopoly and the right to condemn property) that only government generally enjoys. In exchange, their every move is regulated. Public service is an obligation, and the SCC is the guardian of that obligation. But the SCC needs the understanding and, occasionally, the support, if not the loud objection, and guidance of concerned public citizens, both in the SCC’s own proceedings and on their behalf at the GA.

    This forum helps. Let me echo TomH in saying, ” Decisions that we make in Virginia over the next few years will have long term consequences. These issues are too complex for most policy makers to take the time to deal with so they usually take their guidance from others. We need to find a way to simplify the issues so that Virginia citizens can step up and become responsible again for what happens in this state instead of expecting others to do it all for them.”

  19. re: ” if people in-the-know are happy with the utility service rendered (including the competitiveness of its rates vs the competition) and the politicians are not riled about something the utility did, it will get a reasonable return on a reasonably-determined cost of service; but if they aren’t, it won’t — THAT is where the real politics comes in ….”

    but not all people are happy with the current “arrangement” which makes it hard to install solar and not easy for 3rd party providers to enter the market but most of all – allows Dominion to NOT pursue policies that would encourage less consumption of electricity in general.

    In some respects – the SCC is acting like a COPN law – which discourages competition and innovation.

    We “tried” de-regulation and de-coupling but I’m not convinced that the reason they failed is that they were fatally flawed from the start.

    are we reaching a point where technology is available and would save energy – but it’s not being pursued/adopted – in essence because it disadvantages the utility especially in terms of profitability under the SCC “model” of regulation?

  20. re: ” These issues are too complex for most policy makers to take the time to deal with so they usually take their guidance from others. We need to find a way to simplify the issues so that Virginia citizens can step up and become responsible again for what happens in this state instead of expecting others to do it all for them”

    sort of an odd statement on it’s face but we know what is meant.

    I don’t blame VDP for looking out for its own interests and indeed acting in it’s own best interests – any/all companies would do that but we also know some companies move with the times and stay up with or even ahead of disruptive technologies while others do not – and those unique companies with monopoly advantages are probably more insulated from the market than is healthy for them or their customers.

    At that point – I DO think one of the important roles of an agency like the SCC is to NOT function as a protector of the market but rather an advocate for the customer because in doing that – they are likely acting in the best longer term interests of the monopoly business also.

    To not do that is to shift risk and liability for risk – to the customer – who will ultimately pay for bad decisions – rather than the investors.

    The ideal outcome here is for market disruption to be not only a benefit for ratepayers but a benefit for the business which – actually is in the best interest of the customer also.

    Acbar and others talk about the negative aspects of subsidies and I DO AGREE but protecting the business monopoly ALSO is a subsidy.

    I don’t expect the SCC to act as a surrogate CEO but at the same time – shielding DVP from market forces is above and beyond …. contradictory to their role to ALSO benefit the longer-term interests of the ratepayer – who should not be saddled with the costs of bad strategic business decisions.

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