More than 100 megawatts of projects hang in the balance in the state.

In 2016, Virginia’s solar industry could grow more than 1,000 percent compared with 2015 — a 750 percent increase over all the solar ever deployed in the state.

As you digest the Paris climate COP 21 agreement – 195 countries reach agreement to hold temperature increase to below 2 degrees Celsius – how will we achieve this ambitious agreement? Clearly we need to dramatically expand clean energy. As we discuss in GreenTech Media, the Virginia Solar Market is poised for such growth.

Advanced Energy Economy’s market report found the global market for advanced energy technologies reached $1.3 trillion in 2014 and conservatively estimated a $200 billion market in the U.S. The U.S. advanced energy market is bigger than the airline industry and equal to pharmaceuticals.

Virginia’s regulators and policymakers will soon make decisions about the state’s energy market structure that will determine whether we participate in the new energy economy and see enormous growth in solar — or not. In our opinion, a vibrant, competitive market creates the best opportunity for Virginia to compete. As discussed below, Dominion’s attempt at novel new pricing for utility-owned may finally allow for this market structure.

The upside, 300 MWs plus of Virginia Solar in 2016?

There are currently 25 to 30 MWs of solar generation installed in Virginia. The amount of solar energy available in the state of Virginia could increase fifteen-fold in the coming year. Here’s what we see:

Dominion Resources controlled Solar

Dominion’s regulated and unregulated businesses may deploy close to 200MWs in 2016.

Dominion has sought the Commission’s approval to own three solar projects totaling 56 MWs (the Dominion 56)
Dominion has reported that they are negotiating an additional 47 MWs of solar Power Purchase Agreements[1] (the Market 47).
In addition to these 103 MWs, Dominion’s unregulated business bought the 80 MW Amazon project developed by Community Energy.
Finally, Dominion may add a few additional MW’s of solar through their Solar Partnership and Solar Purchase programs.

Non-Dominion Solar

In addition to the Dominion-controlled projects, an additional 50 to 80 MWs of planned Virginia solar has been announced.

Old Dominion Electric Cooperative (ODEC)[2] recently announced they had contracted 30 MWs through Power Purchase Agreements which is expected to be built in 2016.
Appalachian Power Company (APCO), typically reluctant to engage in solar markets, has issued an RFP for 10MWs to be interconnected by the end of 2017.[3]
Finally, the Council for Independent Colleges (CICV) has issued a Request for Proposal for 38 MWs of which at least ten MWs can reasonably be constructed in 2016. [4]

Additional Potential

There are several hundred additional MWs listed in the PJM queue that may be built in 2016. These projects will require a buyer for their energy and direct sales may be difficult.[5]
There may exist projects seeking to interconnect into the distribution systems of, Dominion, APCO, ODEC or the retail electric cooperatives.[6] These projects may not show up in the PJM queue, but again they will need a buyer for their energy.

The downside, 120 MWs?

Currently, many large-scale projects are not subject to the SCC’s decision-making authority (for example, the Amazon, ODEC and CICV projects). These projects total 120 MWs in 2016, a 600% increase over 2015. These projects are likely to be built because there are willing buyers and sellers – a competitive market free of the public utility regulatory process. .

If the SCC were to deny the Dominion 56, Dominion would have little incentive to enter into the PPA contracts with the Market 47. As discussed below, if they cannot earn a return on the Dominion 56 MWs, they have little or no incentive to buy power from the Market 47.

If Dominion walks away from the Market 47, these projects will need to find other buyers. These direct transactions are involved and Virginia’s lacks the policy support for these direct to energy consumer transactions. Hence, the SCC will most likely determine the fate for both the Market 47 and the Dominion 56.

Is a Market Index for Setting Utility Rates the Key to the Future?

In my opinion, the future of the Virginia solar market depends on the ability for non-utility owned solar to set a market price for utility-owned solar. The role of the Market 47 is the key to this market price index.

To understand why Dominion is pursuing PPA contracts with the Market 47, one needs to understand why the Market 47 PPAs are essential to Dominion’s ownership of and return on investment for the Dominion 56.

First, we need to look at how the price for solar power is currently set in Virginia and why prices are currently higher than they should be. The utilities and regulators set prices through “rate normalization” rules. These rules result in prices that are 20% higher for the customer if the regulated utility owns the solar as compared to solar power purchased through a PPA. There are two reasons for this:

Accounting rules for tax incentives. The federal government requires Dominion spread out the federal tax incentives over the life of the project. In contrast, a third-party PPA will sell the power based on when the owner receives the federal tax incentives.[7] Under rate normalization, the rate payer loses the present value of the tax credits – a 20% increased cost to ratepayer over twenty years.[8]
Different costs of capital. In addition to rate normalization, Jon Wellinghoff and James Tong[9] have argued that the utility’s cost of capital will be greater than the competitive market cost of capital, again making the cost of utility-generated power higher than that of power generated by competitive generators.

Second, the Commission denied Dominion’s application to construct, own and operate the Remington 20 MW solar plant.[10] The Commission denied this Dominion project for lacking adequate market data on third-party, market alternatives. The Commission’s decision makes clear that future Dominion applications to own large scale solar will require significantly improved market data. Such information is only available when third party sources of solar power are allowed to compete unimpeded in the marketplace.

Third, Dominion may have found a way to address the Commission’s concerns about market-based pricing data – which would enable it to build and profit from its planned 56 MW of solar power. This solution depends on establishing a market price index for solar energy. (In the 2015 session, the General Assembly determined that the Virginia regulated utilities “may propose a rate adjustment clause based on a market index in lieu of a cost of service model for such [solar] facility.”) Dominion is utilizing the proposed pricing from the Market 47, to establish a market-based price for the Dominion 56. Since Dominion is setting the cost to the ratepayer-based on the price for the Market 47,[11] the SCC may find that third-party market alternatives were appropriately considered. Further, the Commission may find that the Dominion 56 provides the lowest cost to ratepayer because it is equal to the market price. Hence, the Market 47 may allow Dominion to build and profit from its own 56 MW of solar generation.

Without the Market 47 PPAs and this market-based pricing information, the SCC would likely deny the Dominion 56 MW. The Commission would use the same rational as they used in denying Dominion’s 20 MW Remington solar project.

In addition to requesting that the SCC approve this market index approach, Dominion has petitioned the IRS to allow this approach by exempting the Dominion 56 from rate normalization or cost-based regulation. As Dominion stated in their testimony, “… the Company sought IRS confirmation through the PLR[12] that a RAC revenue requirement for the Projects’ output that is designed using a market index (in lieu of a COS[13] model) does not constitute cost-based regulation …” If the IRS fails to provide Dominion a Public Letter Ruling allowing Dominion to utilize the market index approach, the Dominion 56 would presumably need to go through a new Commission CPCN / RAC case. Hence, the Dominion 56 will not be built in 2016, and I would bet against the Market 47.

If successful, Dominion will create a new rate setting / cost recovery approach for utility-owned solar. Further, they will likely create a need for a competitive market. Hence, Dominion may have created a market structure that requires a competitive market to exist alongside the ownership of solar systems by the regulated utility. Success for this market-based pricing approach will benefit not only the competitive solar industry but also customers if you believe that competitive markets drive down the price, innovate, and create value. A competitive market will enable Virginia to compete for the trillions in the clean, advanced energy markets.

[1] A power purchase agreement (PPA) is a contract between two parties, one which generates electricity (the seller) and one which is looking to purchase electricity (the buyer).

[2] ODEC Awards Solar Project Contracts Totaling 30 MW. (November 11, 2015). Retrieved from http://www.odec.com/wp-content/uploads/ODEC-Awards-Solar-Power-Contracts.pdf

[3] https://www.appalachianpower.com/b2b/rfp/2015SolarEnergy/

[4] http://my.solarroadmap.com/ahj/smp-icv/view

[5] In Virginia, the ability to sell directly to an end user likely requires a contract utilizing the PJM transmission grid. Only very large energy customers transact using the wholesale transmission grid. While the market is small for these types of transactions, industry scuttlebutt indicates that numerous transactions are being conducted directly between solar developers and energy users.

[6] The local distribution utilities could enter into purchase agreements with these projects or purchase these projects. In my opinion, the Virginia code creates ambiguity whether renewable energy can be sold over the distribution grid– the regulated public utilities have stated the code does not allow such transactions. Regardless of legality, this transaction would require the cooperation of the distribution utility which is not likely given their stated opposition to these transactions.

[7] Solar projects essentially immediately receive the 30% federal Investment Tax Credit and receive the federal accelerated depreciation over five years

[8] 20% is the difference in the calculated Net Present Value of the costs to the ratepayer assuming a 30% ITC, 5 year MACRS, and utility weighted average costs of capital equal to 7.3% (10% return for the equity and 7% cost of debt).

[9] Utility Dive, Tong & Wellinghoff: Should utilities be allowed to rate base solar? Should we even be asking this question? By James Tong & Jon Wellinghoff | May 11, 2015

[10] The SCC denied Dominion’s application for a CPCN and RAC for their 20MW Remington solar project stating the following. “Based on the record developed in this case, we find that the record does not demonstrate that the Company considered and weighed alternative options, including third-party market alternatives, during the selection process for the Remington Solar Facility, as required by Code § 56-585.1 A 6. Nor do we find that Dominion has established that the costs of the Facility proposed to be paid by consumers would be reasonable or prudent, based on the record.”

[11] Dominion netted the estimated market value for the renewable energy credits (RECs)[11] from the PPA pricing to set the cost to the rate payer. (Extrapolating from the data provided in the Dominion 56 CPCN and RAC testimonies, the Market 47 appear to have offered an average of $73.86 per MWH escalated at 2.5% per year for twenty years – Dominion rates will recover $55.66 per MWh for the power and they estimate that they will sell the SRECs for $18.20 per MWh.)

[12] A private letter ruling, or PLR, is a written statement issued to a taxpayer that interprets and applies tax laws to the taxpayer’s represented set of facts. A PLR is issued in response to a written request submitted by a taxpayer.

[13] In Cost of Service regulation, the regulator determines the Revenue Requirement Requirement—i.e., the “cost of service”—that reflects the total that reflects amount that must be collected in rates for the utility to recover its costs and earn a reasonable return.