Clean Energy Options and Economic Development

States looking for corporate investment should provide these clean energy options for commercial and industrial customers.

States looking for corporate investment should provide these clean energy options for commercial and industrial customers.

Half the Fortune 500 companies have committed to reducing greenhouse gas emissions, either through energy-efficiency or using more renewable energy. If states want to compete for their investment, they had better create regulatory environments that are friendlier toward solar and wind energy, contends a new report, the “Corporate Clean Energy Procurement Index.”

That doesn’t necessarily mean giving tax breaks to solar facilities or mandating Renewable Portfolio Standards. But it does mean reforming regulatory structures to make it easier for corporations to procure clean power, states the report, which was backed by the Retail Industry Leaders Association and the Information Technology Industry Council.

Despite relatively slow wind and solar development, Virginia scored 20th nationally for its clean energy options. Virginia made it into the middling ranks through its high score — No. 3 in the country — for the ability of companies to purchase green power through electric utilities. By contrast, the Old Dominion makes it difficult to obtain wind and solar power through third-party agreements or on-site deployment.

“The availability of retail choice is a critical factor for a state’s attractiveness to corporate and other large institutional buyers of RE (Renewable Energy),” states the report. “States that wish to gain the job creation and economic development benefits of corporate RE-powered facilities should encourage their policymakers and regulators to enable customer choice.

In broad terms, the report said that states should pursue five broad strategies for creating more clean energy options:

  1. Remove barriers to corporate deployment of both onsite and offsite renewable installations. “High fees or long processes for interconnection, high standby charges, and other roadblocks meant to discourage distributed generation must not be allowed.”
  2. Support the development of next-generation options to purchase renewable energy through utilities in regulated markets. “The green tariffs currently in existence are first-generation products and could be improved as companies and utilities gain more experience from them.”
  3. Expand energy choice options for commercial and industrial customers in regulated markets. “Policymakers could explicitly authorize third-party [power purchase agreements] and leases for distributed generation, enable community solar programs, and support corporate participation in them.”
  4. Ensure that an adequate market exists for purchasing renewables through both utilities and third-party programs. “States should not choose between setting up utility or third-party markets. Rather they should strive to do both.”
  5. Ensure that renewable energy in both regulated and deregulated markets can scale up rapidly. “Provide as much customer choice as possible, as soon as possible.”

On the positive side, Virginia allows companies to purchase renewable electricity through “green” tariffs, a special utility commission-approved rate structure that permits purchases of green electricity through the utility. The state also allows companies to cut deals directly with Dominion Virginia Power, as Amazon Web Services and Naval Station Norfolk have done. Appalachian Power has submitted a proposal to the State Corporation Commission to provide a green energy tariff.

Less positively, Virginia regulations are less hospitable to companies purchasing electricity through third parties, such as independent power producers, or companies that install their own solar panels and want to sell surplus power back into the grid.

Bacon’s bottom line: Once upon a time, the main “jobs” justification for renewable energy was that it created a lot of construction work. But solar panels require so little maintenance that the number of permanent jobs created is minimal. It is hard to sell renewable energy as a positive for economic-development on the basis of permanent jobs created.

But the rise of the retail and IT sectors as green energy consumers changes the debate. If Virginia wants to attract data centers, warehouses and big box stores, among other types of investment, it needs to provide a broader array of clean-energy options.

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38 responses to “Clean Energy Options and Economic Development

  1. ApCo is looking to set up a Green tariff so that it can avoid allowing PPA’s in its territory. Dominion has a Green Tariff and also hopes to own the large scale solar in its territory rather than create a level playing field for independents. In Virginia, green tariffs are higher than the normal retail rates. This is not attractive to new industries because they can get far lower rates through PPA’s.

    I can understand the utility’s reluctance to open up to lower cost competitors that reduce their revenues. That is why many states that have much higher penetrations of renewables have changed the rules to not allow renewable projects owned by the utilities to be in the rate base. This increases the cost, because ratepayers guarantee a profit to the utility, and reduces the opportunity for a free market to lower the cost. The least cost scenario is where utilities get paid for the use of the grid and corporations contract directly through independents (or non-regulated subsidiaries of utilities) using PPA’s.

    The jobs justification for renewables is in the manufacturing sector (not much for solar in Virginia but could be for wind) and in the installation of the units. This can provide steady long-term employment, especially for distributed units.

    The real economic benefit is the creation of a stable or declining-cost energy system to attract new business, especially those businesses interested in easy and inexpensive access to renewable sources. This is the opportunity for Virginia to revitalize and modernize its economy.

    • I would like to agree with you — but first I have to get over the hump on what is in your construct of a “PPA.” I still do not understand why a “Power Purchase Agreement” is required to accomplish what is essentially a generation equipment lease (other than to obfuscate, or hide entirely, the profit to the seller from the power sale component).

      • The PPA allows the developer to be responsible for all aspects of the operation of let’s say a solar facility and removes the burden from the actual purchaser of the power. The third-party developer can be responsible for the financing and application of the investment tax credits, which allows not-for-profit organizations such as governments, schools, hospitals, etc. to benefit from lower costs.

        If the facility is not located at the customer’s site, the developer can do the coordination with the utility and PJM. The customer is also charged only for the energy produced which is good for a variable resource.

        An equipment lease might result in a higher payment over a shorter duration contract. The developer would probably create a capital lease with a dollar buyout, that lasts the length of the depreciation period so they could capture the depreciation and have no recapture at the end of the contract.

        I see PPAs as the favored mechanism for commercial and industrial customers. Residential users would probably be better served by equipment leases or loans (if they can use all of the ITC).

      • Thanks, very helpful. I’ll grant you, the PPA is more than a lease, it has an O&M component, and it’s all-encompassing (i.e., no hassle, no loose ends) for the customer, which is what most business customers want.

        Presumably the customer buys the power from the developer at a negotiated fixed price that’s somewhere between what the developer expects the cost will run over the contract life (cap plus O&M less tax credits etc.) and what the customer saves from reduced purchases of production from the retail utility (full requirements less partial requirements service). Now if the utility is still getting paid its separate T&D and customer (bill/meter) charges the utility shouldn’t be too put-out other than conceptually, by the violation of its exclusive franchise.

        What if the developer simply planned from the get-go to sell the on-site-generated power to the grid operator’s wholesale markets and let the customer continue to buy nominal “full requirements” from the retail utility, while allowing the developer’s equipment on site? Presumably that won’t work because the wholesale markets, on average over time, pay the developer less than what the retail customer would have agreed to pay, leaving no benefit to share with the retail customer other than a green label. Utility-scale solar may be profitable even if sold at wholesale, but I’m presuming the inefficiencies of distributed generation make that impossible here (I’m leaving subsidies like net metering and avoided wires charges out of this discussion).

        But that begs the question, where did the margin in the PPA deal come from? I’m talking about the benefit that the developer and the customer negotiated how to divide between them, the benefit that is missing if the sale is to the wholesale markets. Was the sunk cost and the return built into the retail utility’s displaced production rate component really THAT high?

        Or is the PPA deal really dependent upon other cross-subsidies that haven’t been acknowledged in this discussion?

        • First, let me offer a disclaimer. I am not an expert in PPAs. I am trying to find time to get better educated and follow the two proceedings currently in front of the SCC.

          PPAs do not require any subsidies to make sense. Obviously, the solar market has benefitted from the ITC that was in force the past few years. But that will taper off soon and disappear completely by 2022 except for utility installations (they remain at 10%).

          Lazard’s latest LCOE figures show that even unsubsidized solar is lower than the LCOE for combined cycle units. Even though Dominion penalized solar by an arbitrary 40% so that its model would preferentially select gas plants, the IRP showed that the busbar costs were nearly the same.

          So the main advantage of a PPA going forward is that it is cheaper than the retail costs for the commercial and industrial customers. And the cost of new solar will keep getting cheaper while rates will keep going up because of fuel price increases.

          The main difference is the delta between wholesale and retail prices. That benefit is shared by the customer and the developer as you say.

          I happen to think this is the sweet spot for solar development. Medium scale distributed solar facilities located on already disturbed land uses, either on the customer’s premises or another suitable location nearby. These projects should not require any new transmission.

          You say these distributed units are less “efficient” than utility-scale solar. I’m not as convinced because the utility-scale plants require transmission and the smaller scale commercial installations do not. Leaving the cost of this transmission out of the cost calculation for utility-scale solar distorts their cost advantage in my opinion.

          The soft costs (marketing, financing, site assessment, design, etc.) do take up a larger portion of the total project costs for smaller units than they do for larger facilities, however. The grid reliability and resiliency advantages of distributed units are not factored into the projects but should be considered in planning an appropriate mix of distributed and utility-scale solar facilities, in my opinion.

          So where does this leave the utilities? Under our current rules – out of luck. All of the advantages to the customer (lower costs) and to developers and the economy (new jobs) are counterbalanced by the loss of revenues to utilities unless they own it all. Then we are still saddled with the central station hub and spoke model, just with a new type of generation. And we will miss out of the benefits of transitioning to a network model for our energy system.

          Until we change the rules for utilities they will have plenty of incentive to obstruct or at least slow down the speed at which these lower cost options can proliferate (shown by the current prohibition of PPAs in Dominion and APCo service territories).

          I’m sure there are many details left to work out to balance all of the interests, but we should start the conversation before Virginia falls too far behind. Other states are several years ahead of us in working this out.

          • TomH, I asked, “But that begs the question, where did the margin in the PPA deal come from? I’m talking about the benefit that the developer and the customer negotiated how to divide between them, the benefit that is missing if the sale is to the wholesale markets. Was the sunk cost and the return built into the retail utility’s displaced production rate component really THAT high?” And you answer, “The main difference is the delta between wholesale and retail prices. That benefit is shared by the customer and the developer as you say.” I’m quoting this to be sure I’ve understood you right and we are talking apples-to-apples. Because DVPs retail price at issue here has these components when unbundled: 1. A production (generation / power purchase) charge, 2. A transmission charge, 3. A distribution charge, 4. A customer (billing and metering) charge, and 5. Several fixed or variable riders adjusting 1-4 above (mainly 1) filed by DVP to avoid reopening regulatory scrutiny of the total retail charge. Now, can we agree to take 2 through 4 out of this discussion (the customer will pay these anyway)? Then, the difference between the wholesale market price (including RECs, renewable energy credits) payable to sellers of solar energy in PJM, and DVP’s retail production charge per kWh (including relevant production-related riders), is the delta that I believe is at stake here.

            Now, if DVPs retail costs are accurately allocated among these unbundled components, which the SCC surely requires, that delta we’re taking about should consist of 1. DVPs markup on its cost of production for return on investment, adjusted for 2. whatever difference there is (+ or -) between DVPs own cost of production and the cost if it bought all its power from PJM. Right?

            And if that’s all there is, I just don’t see how there’s enough dollars in that delta to support the PPA business model.

          • On the subject of efficiency, I was thinking mainly of those soft costs (the paperwork, the O&M). Plus my understanding is, the typical homeowner/small business site is rarely optimally oriented and rarely incorporates a mechanical collector adjustment for sun angle. The collectors themselves are usually just as efficient converting sunlight to kWh regardless of installation size. You bring up an interesting efficiency consideration re transmission cost: if distributed generation actually allows the utility to avoid transmission investment then that saving should be recognized. I can foresee argument over how much transmission cost is really avoided, however, due to DG customers’ full reliance on the grid (including its transmission elements) after sunset (and the daily peak load in the mid-Atlantic is usually around or after suppertime, not midday). If the argument is that DG doesn’t incur or impose system losses like grid-based generation by virtue of being closer to the load, I accept that in principle more kWh make it from a customer’s rooftop to his load in a DG situation; that’s an increased efficiency. But I don’t know how much of an offsetting loss of efficiency there is in adapting the distribution system to accommodate two-way power flow. There’s also some loss of efficiency in the reconfiguration of the grid as a whole to predominantly a cycling (nighttime only) rather than a baseload supplier of electricity — but that would apply to all solar not just DG.

        • First, let me offer a disclaimer. I am not an expert in PPAs. I am trying to find time to get better educated and follow the two proceedings currently in front of the SCC.

          PPAs do not require any subsidies to make sense. Obviously, the solar market has benefitted from the ITC that was in force the past few years. But that will taper off soon and disappear completely by 2022 except for utility installations (they remain at 10%).

          Lazard’s latest LCOE figures show that even unsubsidized solar is lower than the LCOE for combined cycle units. Even though Dominion penalized solar by an arbitrary 40% so that its model would preferentially select gas plants, the IRP showed that the busbar costs were nearly the same.

          So the main advantage of a PPA going forward is that it is cheaper than the retail costs for the commercial and industrial customers. And the cost of new solar will keep getting cheaper while rates will keep going up because of fuel price increases.

          The main difference is the delta between wholesale and retail prices. That benefit is shared by the customer and the developer as you say.

          I happen to think this is the sweet spot for solar development. Medium scale distributed solar facilities located on already disturbed land uses, either on the customer’s premises or another suitable location nearby. These projects should not require any new transmission.

          You say these distributed units are less “efficient” than utility-scale solar. I’m not as convinced because the utility-scale plants require transmission and the smaller scale commercial installations do not. Leaving the cost of this transmission out of the cost calculation for utility-scale solar distorts their cost advantage in my opinion.

          The soft costs (marketing, financing, site assessment, design, etc.) do take up a larger portion of the total project costs for smaller units than they do for larger facilities, however. The grid reliability and resiliency advantages of distributed units are not factored into the projects but should be considered in planning an appropriate mix of distributed and utility-scale solar facilities, in my opinion.

          So where does this leave the utilities? Under our current rules – out of luck. All of the advantages to the customer (lower costs) and to developers and the economy (new jobs) are counterbalanced by the loss of revenues to utilities unless they own it all. Then we are still saddled with the central station hub and spoke model, just with a new type of generation. And we will miss out of the benefits of transitioning to a network model for our energy system.

          Until we change the rules for utilities they will have plenty of incentive to obstruct or at least slow down the speed at which these lower cost options can proliferate (shown by the current prohibition of PPAs in Dominion and APCo service territories).

          I’m sure there are many details left to work out to balance all of the interests, but we should start the conversation before Virginia falls too far behind. Other states are several years ahead of us in working this out.

          • The other thing is the upfront cost of equipment. Contracting with a 3rd party lets the homeowner get the equipment without the upfront cost – and the 3rd party recovers their cost by amortization over time of payments from the customer, sales to the utility and profit on the transactions – Not unlike the up-front cost to provide electric or phone or cable service to a new home.

            Imagine if customers – to get electric service – had to pay up-front for the infrastructure needed to get electricity from the existing power lines to their home! Ditto cable or phone.

            When you think about it this way -you can see that Dominion would see this as a competitor not only taking their sales..but poaching their infrastructure and why should they agree to anything that would essentially took away the customer who was helping to pay for that infrastructure in their bills?

            From a business point of view..it’s not about whether they like solar or not – it’s about their business and business model and how to charge not only for electric service but infrastructure they invested in and have to recover the cost of to remain viable.

            It’s basically a competitor taking one of their customers but still requiring Dominion to provide “back-up” service that will not be enough for them to recover their infrastructure investment costs.

            Dominion likes gas..3rd party likes solar.. Dominion wants to keep the customers.. 3rd party wants to take them.

            It’s akin to taxi drivers not wanting to have the game changed to accommodate Uber .. or the car dealers from Tesla direct sales.

            And it’s not dissimilar to the idea that gas taxes need to pay not only for new roads but operation and maintenance while most who pay gas taxes think once a road is “bought” that from then on it ought to be “free”.

            Many cost-for-service are one fee but it incorporates not only the “service” but the other hard/fixed (overhead) costs to provide the service.

            water/sewer is another example where they DO charge up-front for the hookup – the “availability” fees which are often in the range of 10-20K … which get incorporated a an expense in the building of the house – and becomes part of the mortgage.

            but for folks with existing homes that want to hook up to water/sewer – that hookup-fee has to be paid. Some water/sewer authorities now provide rate “plans” where the hook-up fee cost is incorporated as part of the monthly fee – essentially a loan – where the water/sewer folks are gradually recovering the cost of the infrastructure not upfront but over time. What that means is that when they need to expand the system -then THEY have to go borrow money because they didn’t collect upfront hookup fees.

            So this is the part that needs to be looked at and potentially modified if you want Dominion on board with 3rd party solar.

            I think….. pending what TomH and Acbar and others might have to say.

            remember when Ma Bell got broke up – and that same issue of investment in infrastructure versus cost of providing service OVER that prior-built/paid-for -infrastructure had to be resolved if you were going to allow different phone providers – use that infrastructure provided by ma Bell originally?

            I wonder if this issue has ever really been dealt with as a way forward for 3rd party solar?

  2. we’re basically blocking knowledge companies from coming here , bringing their workers and customers..

    How ironic with all this talk about bad regulation hurting the economy and here it is staring us in the face!

  3. Virginia wants and needs 21st century companies and those companies need millennial workers as well as their business selling to millennials.

    Millennials believe in the reality of Climate Change and do want electricity to come from less polluting sources that are not harming the planet.

    81 Major Corporations–Including Google, Facebook, Coca Cola, General Motors–Sign WH Pledge to Back Global Climate Change Deal

    they read like a who’s who of major companies .

    these companies customers and employees want them to deal with Climate Change…

    these are the companies that are acting to install energy conservation measures as well as DON’T want coal-based power or even gas if it is determine to be a potent contributor to Global Warming.

    Virginia has to be “business friendly” if they want to attract them and we desperately need to do that.. we are on a down spiral as our workforce is increasingly lower-income workers doing service work.

    “Business Friendly” means that Companies that want to come here – can directly buy solar electricity – at a reasonable price yet Virginia persists in policies that make solar hard to do and expensive because that’s what Dominion Power wants.

    At some point, Virginia needs to decide if satisfying Dominion is worth the loss of other companies.. Dominion is one of the better utilities in the country – no question – and they do deserve fair treatment in the Va economy but should their needs essentially be so prioritized as to harm our economic development, our share of the 21st century economy?

    We’ll soon be arguing about transgender bathrooms, abortion, and other social issues… we’ll also be confronting a huge budget deficit – which is a direct result of the loss of higher paid workers. In other words, we have a low unemployment rate and a robust economy – in theory – but that economy is not delivering the revenues needed to pay our bills.

    we need to stop screwing around with social conservatives causes and get our head out of our ___ and deal with our workforce skills needs as well as do more than just talk about “business friendly” .. we need to BE business friendly.

    what will our elected be doing in Richmond this month? I am already seeing a continuation of the rancid and divisive politics..rather than people working to get Virginia into the 21st Century economy.

    • Re, ““Business Friendly” means that Companies that want to come here – can directly buy solar electricity – at a reasonable price.” I believe they can buy “all renewables” power (not necessarily purely solar), under REC’s or DVP’s tariff, or they can generate their own solar power on their premises, or they can generate solar power elsewhere and sell it to PJM and use that revenue and those renewables credits to offset their costs. What else do you think “business friendly” requires?.

      • what else ? what they can’t do now per your conversation with Tom?

        Why did Amazon and others not do what you say they could do and instead went with 3rd party outside the state then Dominion buys it?

        • For the record, Amazon’s solar purchases were from a large-scale solar plant IN Virginia, in Accomack County. The third party developer later, as I recall, sold the plant to Dominion.

  4. One comment, Jim, is that what you characterize as “Virginia regulations” being “less hospitable to companies purchasing electricity through third parties” are not regulations, but Virginia statutes, enacted by the General
    Assembly. The Legislature has been very hospitable to protecting utility fiefdoms. Some of this is understandable, they have to provide service to all in their territories, not just these knowledge companies, many of whom are here already and very happy. Just ask Amazon how they like having DVP customers pay for their 230 kV transmission service line!

  5. I am thinking the best thing Virginia can do to attract business is to keep electric costs lower. Electric costs are quite high NJ and north thru New England, so those states are more or less opting out of economic growth potential to Virginia’s gain. I have always favored smaller distributed power (eg: nat gas cogen at the “plant”) and yes state regulators often try to discourage that in favor of large centralized power plants. Of course, keeping elec costs lower eliminates some of the drive for distributed power, which is often pursued as a way to keep costs down, when utility elect costs are too high. If a business wants to pay more for renewable elec, I’d let them but not heavily subsidized (by the State – Fed subsidies good enough).

    • I agree, TBill, but the best way to stabilize the increase in electricity rates is to move to energy efficiency and renewables. These technologies are cost competitive with the conventional methods now, with no fuel cost increases. If you need dispatchable power the CHP (cogeneration) plants are a great idea because you can meet heating and cooling loads too with the waste heat. These smaller units are more expensive on a wholesale basis compared to the big new combined cycle plants but would be cheaper than retail rates for commercial and industrial customers. They would need natural gas, so they would be on an increasing fuel cost curve just as they would be as a utility customer, but their cost of energy would be lower.

      Distributed generation offers many benefits to the grid and to customers. Offices, universities, hospitals, businesses and industries can set up local microgrids to island themselves from utility outages and install various forms of self-generation behind the meter. More will choose to do this if the utilities do not get with the program or erect obstacles to third-party PPAs. This customer defection to providing more of their own energy will shift more of the burden for paying for the power lines and utility overheads to the customers who cannot make such adjustments and contribute to the utility’s downward spiral. In Virginia, the utilities might seek protection from these methods using the GA, which would be a huge setback to Virginia as a good place to do business.

    • well.. why are so many high tech companies out in California when they could come to Va with cheaper power?

      • Rates are higher in California than in Virginia, but their bills are about the same or lower than ours.

        California creates twice the number of units of GDP (actually GSP) for each unit of electricity used as we do here in Virginia. Plus they have access to venture capital, highly skilled workers, an excellent and still relatively low-cost state educational system. Lot’s of benefits that we don’t have here yet.

  6. One of the groups that represent exactly what you are talking about Larry is the RE 100. This is a coalition of leading global companies that have committed to providing energy for their corporate activities entirely from renewable sources in the next 15-25 years. They will be locating in areas that provide easy and affordable access to these new technologies.

    I have been trying to make the case that moving towards energy efficiency and renewables is an economic development and job creation issue, but the energy industry has successfully marginalized these new technologies as “environmental” issues so it is hard to get economic develop people and ordinary citizens to recognize that these are the technologies that will actually take them in the direction that they are hoping natural gas will.

    It is hard to see well-meaning people in the Chesapeake and Hampton Roads area spend so much effort attracting new industrial prospects that are based on 20th-century technology. The fertilizer plants, gas-fired power plants, etc., that need a low-cost source of natural gas to be profitable, all look attractive today. But Dominion’s own forecasts show that the price of natural gas will be 3-4 times higher in 10-15 years than what we have experienced the last few years. These facilities, which are not huge job producers, will likely experience a boom-bust cycle that will leave the area with little long-term employment. That is what Australia experienced when they embarked on the same path.

    In the utility business, we always thought at least 10-15 years down the road. Longer for major projects. It was almost like reverse dog years; 10-15 years ahead was like 1-2 years. But the advent of utility holding companies has changed that. These companies, although they own utilities, are not in the utility business. They are not regulated and they operate like any other corporation: they maximize shareholder value. Wall Street’s move from investors to speculators has riveted everyone’s attention on short-term gains. In times of low yields on traditional low-risk investments such as CDs and Treasury securities, people have sought out the historically safe, but higher yields, of utility securities.

    During periods of low interest rates, utility stocks have always done well, because they are capital intensive industries. As load growth slowed, the utility holding companies sought new ways to increase revenues. A dozen US utility holding companies have gotten into the gas pipeline-building business because of the extraordinary yields. In an era of 2% Treasury yields, FERC has authorized (without any explanation) 14-15% returns on gas pipeline projects. Intelligent executives see that projects that yield 50% higher returns than power plants and transmission lines are an attractive place to invest.

    If they desired (as occurred with the Transco connection to Brunswick and Greensville), the utility holding companies could find lower cost ways of supplying natural gas to their power plants. But they are driven by the need for increasing revenues. This also causes them to dismiss energy efficiency and renewable projects because, under the current rules, these projects reduce their revenues. To protect the shareholders, the utility holding companies have shifted the risk of these projects to the ratepayers.

    The state economy and the ratepayers would better off if we could find a way for the utilities to prosper without placing such huge bets on the future price of natural gas. We forget that natural gas sold for over $13 (6 times higher than today) just 8 years ago. For years, up until 1989, natural gas was prohibited for use in new power plants. Greater acceptance of the new technologies would serve both the utilities and the people of Virginia better.

    • Tom, I thank you for your thoughts.. informative and insightful as usual and I agree about finding a way for Dominion to prosper from the disruptive changes that are ongoing and will ultimately prevail anyhow.

      and as far as gas getting scarce and expensive -I think that just accelerates the demand-side innovations.

      • Higher fuel prices will encourage more energy efficiency and demand-side management. However, once the gas-fired plants and pipelines are built, someone has to pay for them. Ratepayers will pay more for them per unit of use if the assets are not used as much as was projected when they were approved.

        If the pipelines carry less gas than is needed to pay for them FERC allows the owners to apply for rate increases. The ratepayers bear the risk of overbuilding and poor planning no matter how prudent they are with their own energy use.

        • if costs go up for ratepayers and demand-side technologies have advanced and become even more cost-effective – what keeps consumption for going down as the costs on the electric bill go up?

          I would expect consumption to decline as price increases, no?

          so at some point, Dominion will seek “relief” and it will appear on bills as something like “Capital costs recovery”?

          I look at states where the cost of electricity is HIGH and consumption is lower than other states.

          I think what has happened to fuel efficiency in cars – to the point where the gas tax no longer is sufficient to pay for infrastructure is inevitable for electricity also.

          Dominion had hold it back – for a while – but the market has a way of overcoming regulation and monopolies.

          It’s a bit incongruous for Jim to vociferously argue here in BR – AGAINST regulations that hinder innovation and market forces for everything from Uber to COPN then not have a similar theme for Dominion and solar/renewables and instead argue that solar/renewables have “issues” that essentially support Dominion’s stance to not only not do more itself but to prevent the market from providing the best options for consumers.

          This is a case – where, like the hairdressing regulations and the car dealer regulations and taxi regulations – they are not to protect the consumer but rather to protect the industry – and actually harm consumers – often referred to by the same folks who hate bad regulation as “crony capitalism”.

          It is hard to believe that there are virtually no demand-side technologies that Dominion could not adopt and deploy – because the SCC won’t let them – on the grounds that it has insufficient ROI…

          My own provider REC has, for years offered demand-side water heater controls and more recently – programmable internet thermostats AND apparently do allow solar with net metering…

          ” Net metering allows REC Members to interconnect approved renewable generation systems to the electrical distribution system and to generate some of their own electricity. The output of the renewable generation system offsets the electricity that would have been delivered by REC. Common examples of net metering installations include solar panels on a home or a wind turbine at a school.

          These installations are connected on the member’s side (the usage side) of the meter. The meter will rotate forward to measure electricity being used from the grid, and it will reverse when the customer generates excess electricity (thereby “exporting” electricity to the electric grid). The sum, or “net,” of the forward and reverse rotation is the volume of electricity (kWh) to be billed or credited to the monthly bill.”

          http://www.myrec.coop/res/save-energy/net-metering.cfm

          so my provider REC is presumably under the control of the SCC also but there are no “Dominion-like” restrictions on solar?

          How can that be?

          Why don’t we have THAT discussion here on BR rather than ones where it is “explained” why Dominion can’t offer the same to it’s customers?

          something is rotten in Denmark – as they say..

          • Dominion does have net metering for solar. But there is a cap as to how much can be installed in their system. Net metering has been helpful to get residential solar off the ground, but it is a relatively crude tool. A Value of Solar Tariff does a better job of incorporating the costs and benefits of solar but does not exist in Virginia.

            Your other comments apply to what is known in the industry as the “Utility Death Spiral”. This concept includes the desire for customers for energy efficiency and self-generation (solar) that reduces their purchases from the utility. When the utility receives fewer revenues the burden of recovering costs for transmission, distribution and other utility expenses falls more greatly on the remaining customers. This encourages them to seek relief by cutting their energy use or generating some of their load with less expensive options (on-premises solar). And so the self-reinforcing cycle continues, hence the “death spiral”.

            Making it difficult to do this through company policies or state-wide regulations can postpone the effects of this. But this harms the state economy as energy costs rise and residents and businesses go elsewhere to find lower costs and have more freedom of choice.

            That is why I am recommending that we deal with this now before a harmful pattern is deeply established and we have a big hole to dig out of.

            Your co-op is not as sensitive to this as Dominion because they probably purchase most of their power wholesale, rather than generate it themselves. Not owning their own plants makes it less important to them to pay for these existing assets, so they have less need to protect against lower revenues.

            The demand side management tools such as the water heater controls shift the load rather than lower usage, but it is a valuable tool to postpone the need for more capacity and it lowers the costs to ratepayers by lowering the peak usage. We need to use a variety of techniques to optimize our energy system.

  7. The VSCC staff needs to establish a special group (separated staff) to represent the interests of residential and small business customers in proceedings examining fundamental changes in electric regulatory policies. In a time of major technological and market changes, I agree regulatory policies designed for a different time may well need to be changed. But 40 years in regulatory law have persuaded me that small, unrepresented customers can get screwed big-time with changes in policy.

    For example, back in the 1980s then Iowa Power was a summer peak electric company. In recognition of that fact, the utility proposed, and the state regulatory agency approved, a winter-only discount for all electric homes. The rate structure helped Iowa Power have a more balanced load year round and protected a large number of consumers (me included) who could not get access to natural gas. The gas company would not expand its service area to many of the homes built between 1978-1983.

    Anyway, some “moronic” legislators, including mine, who did not understand either utility regulation or economics introduced legislation to outlaw the winter-only discount. I sent him a wealth of information demonstrating value to the now-illegal rate structure, but was told this just couldn’t be true. Luckily for me, I transferred from Des Moines to Washington before the next winter’s heating bills arrived.

    But the bottom line is: someone from the staff needs to represent consumers before the VSCC.

    • TMT,

      I agree wholeheartedly! In the states where I worked in the electric & gas utility business, it was one of the primary missions of the state regulators to balance the needs of utility shareholders with the needs of the ratepayers.

      I have been unpleasantly surprised to see that the same balance is not achieved here in Virginia. I know from firsthand experience that utilities prefer to have their plans approved without much opposition. But getting their current plans approved will not be healthy for the utilities in the long run either.

      I spoke with the SCC Commissioners and the AG’s Office of Consumer Protection about the ACP adding hundreds of millions of dollars to utility bills each year compared to using existing alternatives. They said, “that is a FERC issue”. I reminded them that FERC pays no attention to the effect that these projects have on ratepayers. “Who is representing the interests of the ratepayers?”, I asked.

      I testified in Dominion’s 2016 IRP hearing that by following our current course, we would create a situation in 10 years that will be bad for both the ratepayers and the utilities. That we needed to work together to create a better system that benefits all parties. It seemed that it was the first time that they had heard that viewpoint, so it is a lot to expect that they could grasp it right away. But no person from the regulatory staff asked me what I meant by possible harm to the ratepayers.

      I believe the regulators have felt the lash of the GA in the past and are cautious about how far they reach to protect the ratepayers. What I have attempted to point out is that we now have technologies available that can benefit the ratepayers and with the proper adjustments, utilities too. We should spend our time collaborating to find the best ways to do this rather than picking winners and losers with future disastrous results.

      • I thought the Virginia AG participated in VSCC proceedings in the same role as the “People’s Counsel” or such in other States, on behalf of small utility customers; and also there’s a long-standing group of commercial customers participating as the “Committee for Fair Utility Rates” or something like that — doesn’t this address your concerns, TMT and TH? Not that the AG’s office necessarily does a good job of it today, but I seem to recall that current SCC Commissioner Dmitri got his start working in both those pro-consumer roles.

        • The Virginia AG’s staff has made a useful contribution to some of the SCC proceedings that I have read about. I am not familiar with the “Committee for Fair Utility Rates”. I’ll have to check them out.

          I was just remarking that I did not sense the same ratepayer focus from the SCC that I have observed in other states. But to be fair, I am a relatively new observer and have only reviewed a few of the recent decisions.

          During the 20th century, the regulators felt they had to balance the two positions, ratepayer vs. shareholder. What I am trying to get across is that in this century we have an opportunity to align the two positions. But it requires utilities to assume a different role and to get paid in a different way, but ultimately both the shareholders and ratepayers can benefit from the same choices.

        • We agree on that strategic goal; perhaps some different tactics and certainly you have more involvement. BTW, I hope you will turn part of your IRP comments (which I’ve read in full) into a guest post here someday. As for the CFUR, I know they entered an appearance in the IRP case, among many others, but did not present testimony for some reason.

  8. speaking of expensive .. do ya’ll know how they heat homes in a lot of canada that does have electricity -…since heat pumps are near their limits of practicality?

  9. Note Canada’s price

    • Canada’s electricity used to be mostly from hydro, the cheapest conventional source of supply. Now it includes nuclear and other conventional sources so the price has gone up, but still cheaper than the U.S. where the national average rate is about 12 cents /kWh.

  10. I thought it was still mostly hydro … didn’t know they had nukes.

    but if you want to talk about powerlines – they’ve got them!

    ” High-voltage transmission, a solution perfected by Hydro-Québec

    When moving large volumes of electricity, it’s better to increase voltage instead of current intensity (amperage), in order to reduce energy losses and limit the total cost of transmission (building additional power lines, for example). A large portion of the power generated by Hydro-Québec is transmitted using 735-kV lines. Without these high-voltage lines, the landscape would be cluttered with towers. One 735-kV line is equal to four 315-kV lines, the next voltage level down.

    In fact, Hydro-Québec is a pioneer in high-voltage power transmission: it developed the world’s first commercial 735-kV line, as well as the earliest equipment designed for that voltage.”

    and now 1000 kv

  11. Net Metering is IN the Va Code – it’s actually reference on my providers website – REC as the enabling legislation that allows REC to offer net metering to residential consumers:

    § 56-594 Net energy metering provisions

    http://law.lis.virginia.gov/vacode/title56/chapter23/section56-594/

  12. well. .my last post has been languishing in moderation hell.. so let’s me try to get it to appear because I’d like to hear from TomH and Acbar:

    Net Metering is IN the Va Code – it’s actually reference on my providers website – REC as the enabling legislation that allows REC to offer net metering to residential consumers:

    § 56-594 Net energy metering provisions

    note in the REC graphic below over on the right side where they essentially repeat what they say for the accompanying narrative:

    ” The meter will rotate forward to measure electricity being used from the grid, and it will reverse when the customer generates excess electricity (thereby “exporting” electricity to the electric grid). The sum, or “net,” of the forward and reverse rotation is the volume of electricity (kWh) to be billed or credited to the monthly bill.

    so my question is – Can Dominion customers do this also and that capability has been misunderstood in our conversations?

    or not… ???

  13. Yes, Dominion has a net metering tariff. Theirs does not pay the retail price for electricity exported to the grid as yours seems to do. Dominion net metering customers have a smart meter installed that measures the amount going to the grid and credits the customer at a special wholesale price. Any electricity used is billed at the regular retail rate. So it is not “net” in the same sense as your tariff is. They also have a cap on how many can use net metering (it’s 1% of their system load, I think).

    As I have mentioned before, a Value of Solar tariff more accurately accounts for the costs and benefits of solar on the system. Such a tariff would incentivize solar development in the places where it has the most value to the grid (lowering congestion, providing more local generation, etc.).

  14. HydroQuebec is the big transmission builder, to go along with their big construction of hydroelectric power stations, and they built them to transmit massive amounts of this power to the US for cash; back at the time, pre-shale gas and with high world oil prices this made economic sense. You quote from their website, “One 735-kV line is equal to four 315-kV lines, the next voltage level down.” Yes, it’s true, the current-carrying capability of a wire goes up exponentially with voltage.

    This quote is talking about alternating current transmission, and refers to one of the two sets of standard extra-high-voltages in common use: Canada employs the sequence 69kV-315k-725k (1::3::2, also commonly used in the US midwest), whereas the more common sequence in the eastern US (including DVP’s system) is 69kV-230k-500k (1::2::2). The highest voltages employed in the east are mainly 500 kV. Also, HydroQuebec (HQ) has built a large (500kV) direct current transmission system from James Bay where the a/c output of several hydro plants is converted to d/c and sent to New England where the current is re-converted to a/c. Direct current generally is less susceptible to solar disturbances and has lower losses at a given current level.

    Re net metering, as TomH points out, the REC tariff offers “true” net metering (distributed generation runs the customer’s meter backwards, or equivalent). DVP offers a bastardized version, which isn’t “net” at all but from DVP’s point of view recognizes that the customer imposes the same cost to connect to the grid whether he relies on grid power all or only part time (i.e., the credit is only for the production component of DVP’s retail rate, not for the transmission/distribution or billing/metering components. I think in concept DVP’s approach is fair as far as it goes, given the way we quantify costs today. DVP’s credit for distributed solar generation is also very close to what the customer would get if he sold the power to PJM’s wholesale markets, which he is entitled to do if he wants to; so this is a way for DVP to meet the competition. TomH also brings up the “Value of Solar” tariff, which tries to quantify and give additional credit to the customer for the presumed benefit of substituting renewable-resource for fossil-fueled power. I think in concept “Value of Solar” is also fair as far as it goes, which is to say, not very far, today, given our government’s failure to mandate or set a value on reduced carbon emissions (including, set up a carbon tax and trade system to quantify that value). Without a government standard the Value of Solar concept bogs down in application, because of the huge differences of opinion over what that credit ought to be, and because it’s not a cost to the utility but to society generally (and therefore, if the utility pays a credit for it, somebody has to reimburse the utility — who will do so and on what basis?).

  15. Acbar, thanks for your excellent summary.

    As I recall, the Value of Solar Tariff adopted in Austin, Texas was composed mostly of considering the cost of grid improvements to integrate the new solar production and the benefits of reducing local distribution and transmission congestion, greater reliability and resiliency in the grid due to the presence of local generation and some other factors that I do not recall. I don’t remember any economic consideration for no carbon emissions, but there could have been.

    They reviewed different regions in their service territory and the values changed depending on the local conditions, but the addition of solar always had a positive economic contribution to the grid, contrary to the many arguments against net-metering. Using this comprehensive evaluation removes any question about cross-subsidies.

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