Dominion’s IRP Approved, With High Costs Detailed

Source: SCC Staff summary.

The State Corporation Commission today approved Dominion Energy Virginia’s Integrated Resource Plan, laying out possible investment combinations to keep the power flowing in its territory over the next fifteen years.  It also laid out the costs, in excess of $18 billion of investments plus interest plus profit margin to be paid by future customers.

The Commission added the standard caveat that individual decisions to build new generation, energy storage or transmission still must come to the SCC for the regular review.  In some cases the judges will have full discretion to approve or reject proposals, but the General Assembly (at Dominion’s suggestion) has also dictated in state law outcomes for several expensive choices. 

Fully $6 billion of those future investments were dictated by Senate Bill 966 in 2018, which I have named the Ratepayer Bill Transformation Act.

The approved plan (read the SCC press release here and the full opinion here) is basically the second one provided by the utility, following the SCC’s rejection last year of the initial document.  This new document includes a low-cost option, with far less new spending, which the SCC then used as a baseline to highlight the higher cost of the various alternatives.

After filing the amended plan, the utility briefed investors on its capital plans and those plans did not line up with the filed IRP.  So the SCC demanded more detail on those, with the results sparking a Bacon’s Rebellion report a few weeks ago (here).  All the various possible costs coming to ratepayers are discussed in the opinion.

The order does include a long list of requirements for any future filings, which in Dominion’s case is not far off:  they must use the load forecasts prepared by the independent PJM Interconnect regional transmission organization, model the costs of any carbon taxes or regulations, and consider using power purchase agreements for solar generation instead of company-owned projects.

Other media will cover this so the following are just key excerpts from the text:

…As detailed below, the instant IRP, while it meets the minimum legal and regulatory requirements, may significantly understate the costs facing Dominion’s customers.

This understatement of future customer costs is particularly acute given that Dominion’s IRP does not include – appropriately – the multi-billion dollar costs of the statutorily mandated coal-ash removal passed by the 2019 General Assembly and signed by the Governor, which Dominion will collect from customers through a rate adjustment clause (“RAC”), as well as other environmental costs, also eligible for RAC recovery. Further, Dominion is planning to spend several billion dollars (described below) on transmission and distribution projects not included in the 2018 IRP, most if not all of which will also be eligible for RAC recovery.

In sum, we approve Dominion’s IRP as legally sufficient, and we recognize the appropriateness of spending on capital projects when need is proven by factual evidence in actual cases. We do not, however, express approval in this Final Order of the magnitude or specifics of Dominion’s future spending plans, the costs of which will significantly impact millions of residential and business customers in the monthly bills they must pay for power….

 The least-cost plan is a valid benchmark against which to gauge the incremental costs of these public policies and investment goals.

As amended as required by the Commission’s December 2018 Order, the Company’s least-cost plan includes substantially fewer new plants to be built and is significantly less expensive for customers. For example, the Company’s amended least-cost plan calls for more than 5,000 fewer megawatts (“MW”) of new resources over 15 years, compared to the originally-filed least-cost plan, a reduction of more than 50 percent.  The amended plan is also nearly $8 billion less expensive over 15 years on a net present value (“NPV”) basis, compared to the originally-filed least-cost plan….

The facts show that, compared to the least-cost plan, the various provisions of Senate Bill 966 will cost customers the following on an NPV basis:

  • With respect to the Company’s distribution line undergrounding program, called its Strategic Undergrounding Program (“SUP”), the incremental NPV cost is approximately $1.4 billion compared to the least-cost plan.
  • With respect to the Company’s plan for electric distribution Grid Transformation projects, the incremental NPV cost is approximately $2.2 billion compared to the least-cost plan.
  • Together, the incremental NPV costs of deploying 5,000 MW of solar photovoltaic (“PV”) resources, a 30 MW battery storage pilot and the 12 MW Coastal Virginia Offshore Wind demonstration project, is approximately $1.5 billion compared to the least-cost plan.
  • In total, if implemented, the provisions contained in Senate Bill 966 are almost $6 billion more expensive than the least-cost plan on an NPV cost basis.

The order then details the $12 billion in investments Dominion touted to investors but did not include in its filing with the SCC.

  • Additional investment of $1.5 billion in Company-build solar PV investment not included in any plan contained in the amended 2018 IRP and $3.7 billion more solar investment compared to the least-cost plan.
  • Additional investment of $0.8 billion in offshore wind investment not included in any plan contained in the amended 2018 IRP and $1.1 billion more wind investment compared to the least-cost plan.
  • An additional $1 billion in investment in a Pumped Storage Facility not included in any plan in the amended 2018 IRP.
  • Continued investment in nuclear relicensing in the amount of $1.2 billion.

The investor presentation also had substantially higher figures for some the investments which were described in the IRP, bring up the total.  Finally, the SCC pointed to additional expenses not included in either the IRP or investor slides that will eventually be added to customer bills, the largest of which will be the new storage and disposal plans for its piles of coal ash.

The SCC summary of what the General Assembly has done to the regulatory process, and ultimately to consumer costs, should be a campaign issue for the November elections.  Most of the legislation involved, however, had broad bipartisan support.  It would have to be a challenger vs. incumbent dynamic, with leaders of both parties hoping the issue just goes away.

 

 

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18 responses to “Dominion’s IRP Approved, With High Costs Detailed

  1. Agree. Virginia is doing a poor job of regulating by legislation. We should elect people who will fix that problem and let the SCC do its job without interference. The SCC has a long track record of doing a good job of balancing rater payer and industry goals. However, the 2007 and 2018 legislation has upset that balance, giving industry too much. Citizens need to understand this and should demand change!

  2. so is there an IRP for Virginia? What is the IRP for the parts of Virginia that are outside of Dominion’s service areas?

    Over and Over – we sort of treat Dominion as “Virginia”and while they are a significant portion of Virginia – they are not all of Virginia.

    So what is the role of the SCC for the rest of Virginia?

    I think the average Virginian knows almost nothing about the role of the SCC with respect to their electricity in Virginia.

    I get my electricity from Rappahannock Electric Cooperative and I try to understand when Steve talks about Dominion and the SCC role how that affects REC …. and no joy!

    I WOULD PREFER that REC buy cheap solar electricity from PGM during the day and then buy as cheap gas they can at night but it appears that REC has signed a long-term agreement with ODEC to buy power from them – UNLIKE NOVEC which appears to buy all of it’s power from PGM.

    One wonders why, even Dominion would not generate or buy solar power when solar was available and only use gas when they had to – that, THAT would be the LOW COST option!

    • “So is there an IRP for Virginia? What is the IRP for the parts of Virginia that are outside of Dominion’s service areas?” Larry, every “public utility” in Virginia has to file an IRP every May 1 under Virginia law. That includes every electric utility selling at retail and owned by investors (stockholders), like APCO, Dominion, Delmarva Power, and so forth. Co-ops are included in the definition of a public utility for most purposes (see Va Code § 56-265.1) but somebody added “investor-owned” to the separate definition for IRP purposes (see Va Code § 56-597); so they end up exempted from the IRP requirement.

      In theory co-ops shouldn’t be exempted. But, think about it: REC doesn’t own or plan to build generation; instead REC buys from ODEC and others, including from DOM. So, REC’s IRP wouldn’t tell you much even if it existed. If REC was weighing alternatives to ODEC purchases then maybe there might be something for the SCC to look at, to approve or reject; but not if REC simply continues the same old pattern of contract purchases every year. The principal beneficiary of this exemption is probably ODEC, which doesn’t have to defend its procurement practices annually to its coop customers like it would under an IRP.

      • IRPs are only filed by the investor-owned utilities in Virginia. At the time all this dereg-rereg mess started, there were 5 such companies. Delmarva Power and Potomac Edison have since exited the market, turning their service territories over to the adjacent electric cooperatives (A&N Coop for the former and Shenandoah and Rappahannock for the latter). Old Dominion Power, the affiliate of Kentucky Utilities that operates in the far west end of the state, has lately been exempted. Going forward, IRPs will be filed only by Dominion and Apco.

  3. This Final Order is quite an improvement over the proposed IRP presented by Dominion back in May, 2018. It incorporates by reference the SCC’s order of December 7, 2018 in the IRP docket, which may be found here: http://www.scc.virginia.gov/docketsearch/DOCS/4d5g01!.PDF That earlier order includes the directive to use PJM’s load forecast for the Dominion Zone of PJM, scaled down to the Dominion LSE (retail) load (because Dominion also sells at wholesale to other entities located within its PJM Zone, notably a number of retail electric co-operatives and municipal systems). And it directs Dominion not to include in its “least-cost plan” certain costs that Dominion would like to include but cannot say are unavoidable, and to include certain potential cost savings it would like to ignore (like customer energy savings and self-generation) saying:

    “Forcing in higher-cost resources and excluding other lower-cost resources results in a more expensive least-cost plan. While there may be appropriate or defensible reasons, including review of various potential state and federal carbon restrictions for Dominion to include the scenarios it chose for the IRP, omitting a true least-cost plan does not provide the analysis needed to assess the incremental cost of various options, for Commission analysis, and for statutorily required reporting to the General Assembly.”

    Conceptually, this is an absolutely essential clarification and the SCC is to be applauded for insisting on it. I have one remaining criticism: the two orders taken together do NOT directly address the buy-from-PJM-markets versus build option. If the build option turns out to be a “higher cost resource” and buying from other utilities or independent generators through the PJM capacity and energy marketplaces is a “lower cost resource,” then the buy option is implicitly mandated by these orders — but the Commission, and we, will never know — unless Dominion’s next IRP includes an evaluation of wholesale capacity and energy market purchases as least cost alternatives to the build option. I would urge the SCC to make that evaluation of wholesale market alternatives an explicit requirement of the next IRP.

    It’s also useful to point out that a lot of costs mandated by the GA are not included in the IRP, which therefore understates Dominion’s future rate increases dramatically. Citing Dominion’s own presentation to Wall Street investors, the Commission says, “the cost of Dominion’s investment plans is substantially higher than even the highest cost scenario contained in its amended 2018 IRP.”

    This face of the SCC is more like the watchdog for ratepayers we expect, and need, to have in Virginia.

  4. Larry, Appalachian Power also files regular IRPs, but since the coops don’t have major capital expenditures, are not building massive power plants or similar facilities, no need for such a process with them. It’s mainly a capital plan and as noted the coops buy (for the most part) under contract or from PJM.

  5. Well no , Co-ops don’t generate power usually but they obviously buy power from those that do – and have capital costs – which, in turn, customers pay – whether it’s embedded in the cost of purchased power or broken out as a separate cost.

    But if Dom’s capital costs (plus guaranteed ROI) makes electricity more costly than if a Co-Op could buy it cheaper from PGM…………

    In other words – it sorta looks like the SCC is okay with Dom charging more for electricity than it would cost from PJM/independent generators.

    That aspect of the SCC’s role strikes me as NOT looking out for ratepayers as much as they are agreeing that DOm is allowed not have to compete in PJM on price.

    But what restricts the Co-ops from seeking the lowest price from PJM and what role does the SCC have in that regard?

    • Larry, see my answer above to your question. Nothing restricts coops from seeking the lowest price either from ODEC or PJM. An annual IRP filing with the SCC simply isn’t mandated for co-ops. But I don’t believe there is anything preventing the SCC from reviewing a co-ops’ retail rates or the costs which lie behind them, at any time, on customer complaint or on the Commission’s own initiative.

    • Correction: I said “nothing restricts coops” but there is something: the co-ops’ own contracts with ODEC may restrict how much shopping around elsewhere they can do. You may recall that NOVEC had a big feud with ODEC and ultimately complained to the FERC (which regulates wholesale electricity contracts), terminated its contract with ODEC, and withdrew from ODEC; NOVEC now buys entirely from PJM, I think. I don’t know all the history there but you can look it up on Google.

    • The coops buy ALL their power from Old Dominion Electric Cooperative, which is a generation cooperative owned by its member cooperatives (which includes 9 coops in Virginia, 1 in Maryland and 1 in Delaware). ODEC, in turn, owns electric generation capacity in Virginia and in Maryland. Any other power it needs to serve its members’ loads ODEC purchases from PJM. The member cooperatives are not permitted by their contracts to purchase directly from the PJM market or any other supplier. The SCC can neither mandate nor reject the contractual terms under which the member cooperatives purchase power from ODEC.

  6. “It sorta looks like the SCC is okay with Dom charging more for electricity than it would cost from PJM/independent generators.” I wouldn’t go so far as to say “okay with” it but the SCC isn’t even asking. The Commission should make Dominion show that it can supply its own retail customers at lower cost by building and ratebasing and operating its own generation as opposed to buying in the PJM markets.

    Interestingly, the IRP law says,
    Ҥ 56-599. Integrated resource plan required.
    “A. Each electric utility shall file an updated integrated resource plan . . . by May 1, in each year immediately preceding the year the utility is subject to a triennial review filing. . . . Each integrated resource plan shall consider options for maintaining and enhancing rate stability, energy independence, economic development including retention and expansion of energy-intensive industries, and service reliability.
    “B. In preparing an integrated resource plan, each electric utility shall systematically evaluate, and may propose:
    1. Entering into short-term and long-term electric power purchase contracts;
    2. Owning and operating electric power generation facilities;
    3. Building new generation facilities;
    4. Relying on purchases from the short term or spot markets
    ;
    5. Making investments in demand-side resources, including energy efficiency and demand-side management services . . . ..”

    The way that italicized portion reads, it’s pretty clear that a utility subject to the IRP requirement is expected under the law to “systematically evaluate” its options whether to purchase power or to build and generate power for itself. The SCC has to decide how to enforce that requirement.

  7. Thanks Acbar. If NOVEC can cancel a purchase agreement with ODEC – what keeps the other RECs from doing that also?

    I would suspect the ONE thing that would give the RECs pause is what happens if they go to PJM for power and it does not have any…

    And I’m quite sure Dominion and AEP and others would be more than willing to offer – for a price.

    But PJM is a market – and prospective independent power plant investors have no ROI guarantees so it’s entirely possible that – depending on the power plant – that their capital and operating costs are not- competitive and they lose money – in which case the investors will bail.

    PJM cannot “force” new investment – but somewhere in the bowels of Wall Street – there are folks who seem to know if a new power plant is a “good” investment or else no investors would appear.

    It’s easy to see from an investor point of view that Dominion is a “safe” investment – got a guaranteed profit.

    • “I would suspect the ONE thing that would give the RECs pause is what happens if they go to PJM for power and it does not have any…” Of course. PJM requires that any LSE (load serving entity, which includes co-ops) depending on the PJM energy market for its requirements must first, a year in advance, commit enough “installed capacity” to PJM’s operational control to equal the LSE’s forecast coincident peak load plus reserves. That’s a lot of jargon but what it means as a practical matter is, there is a vibrant PJM capacity market where the LSEs buy capacity contracts from generators to satisfy this PJM requirement. Usually they buy the bulk of it 3-5 years in advance and then fine-tune the amount as they get closer to 1 year in advance. Capacity futures are low in PJM these days; that means there is more capacity than demand in the forecast for the next several years. And long range projections, such as those that underlie Dominion’s Virginia IRP, show that the oversupply of capacity in PJM is very likely to continue. That is why TomH and I and others have been saying for some time now, the PJM marketplace is reliable and demonstrably will stay that way.

      Dominion’s retail arm, its LSE, satisfies this PJM capacity requirement with its own generation, just as REC relies on ODEC to satisfy its capacity requirement. Of course DOM has that option; but it begs the question what if the Dominion generation committed to Dominion load is costing that load more than what capacity contracts purchased in the PJM capacity market would cost. That’s the question NOVEC asked about ODEC and apparently NOVEC chose to go to the PJM capacity market instead. E.g.: https://www.novec.com/About_NOVEC/News_Release/nr08182008.cfm
      http://newsmanager.commpartners.com/novec/issues/2010-02-01/index.html

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