Virginia Regulatory Town Hall
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8/24/18  4:48 pm
Commenter: Will Cleveland, Southern Environmental Law Center

Southern Environmental Law Center comments for Governor Ralph Northam’s 2018 Virginia Energy Plan

August 24, 2018

John Warren

Director, Virginia Department of Mines, Minerals and Energy

Washington Building

1100 Bank Street, 8th floor

Richmond, Virginia 23219


Subject: Southern Environmental Law Center comments for Governor Ralph Northam’s 2018 Virginia Energy Plan


Director Warren,


Please accept the Southern Environmental Law Center’s Comments Governor Ralph Northam’s 2018 Virginia Energy Plan. If you have any questions, please don’t hesitate to contact me.


Best regards,

Will Cleveland






IRP Reform

Traditionally, Virginia’s Integrated Resource Planning (“IRP”) process under Va. Code  § 56-599 has focused almost entirely on dispatchable, supply-side resources. Focusing solely on supply-side resource planning is not sufficient anymore. The current approach fails to properly evaluate, value, and strategically deploy a number of resource types, particularly (1) energy efficiency, (2) utility-scale renewables, (3) distributed energy resources (“DERs”), and (4) battery storage. The current IRP process also completely fails to address certain areas where utilities incur multi-billion dollar, multi-decade costs expenses. For instance, in 2018, the General Assembly passed the Virginia Grid Transformation and Security Act (“GTSA”), paving the way for Virginia utilities to sink billions of dollars into “long-term electric distribution grid planning and proposed electric distribution grid transformation projects.” Va. Code § 56-599(B)(10).

Dominion’s proposed 2018 IRP fails to meet the requirements of Virginia law because it fails to perform a comprehensive and systematic evaluation of resource options of all kinds and because it fails to systematically evaluate long-term electric distribution grid planning and proposed electric distribution grid transformation projects. Rather than using its 2018 IRP to set important priorities for subsequent grid transformation plans, Dominion developed the 2018 IRP and its subsequently filed its Grid Transformation Plan (Case No. PUR-2018-00100) in a parallel, but uncoordinated and un-integrated fashion. Dominion’s proposed 2018 IRP fails to adequately inform the grid transformation planning process and valuable time has been lost.

The IRP process also fundamentally fails to evaluate certain non-generation investments that nevertheless commit customers to many decades of expense. For instance, Dominion has committed its customers to paying an additional $2.5 billion – $3 billion for firm capacity on the Dominion-owned Atlantic Coast Pipeline, yet Dominion has admitted never to have studied as part of its IRP process whether it even needs that capacity to meet its service obligations.[1] Long-term natural gas pipeline capacity contracts are a massive expense completely integral to the viability, and wisdom, of operating natural gas-fired power plants, but the IRP process wholly ignores that aspect of resource planning.

The General Assembly should pass legislation requiring that before an electric utility may build a supply side resource or commit its customers to a long-term, multi-billion dollar pipeline capacity contract, it must first demonstrate by modeling in its IRP that it has utilized all lower cost possibilities, specifically using demand-side management (DSM).  DSM includes policies to increase distributed generation, battery storage and energy efficiency, which will lower customers’ consumption and ultimately lower customers’ bills.

In addition, the Commission should direct electric utilities to synchronize and coordinate their IRP and Grid Transformation Planning efforts so that each IRP serves as a strategic foundation plan guiding the development and updating of long-term (10-year) grid transformation plans under the GTSA. Dominion and APCo will start preparing their next IRPs in two years, which provides more than enough time to completely revisit their IRP plan development process to ensure compliance with the law and Commission direction. In the future, the Commission should not approve any future grid transformation filings pursuant to the GTSA if they are not first included in an IRP.

Battery Storage

            Battery storage by itself, or combined with renewable energy, can effectively incorporate more renewable resources and reduce customers’ peak demand. Not only should an IRP evaluate the full range of battery storage uses, but the General Assembly should enact legislation incentivizing battery storage and increasing deployment.

The 2018 state budget item 117-C includes funding for a two-year study by VSEDA and DMME to determine whether or not future legislation in the form of regulatory reforms and incentives will prove fruitful in encouraging emerging energy storage capacity in the Commonwealth. This is a great first step to address battery storage. The study should consider recent legislation in Maryland, New Jersey, California and Nevada, which creates a 30% tax credit for residents purchasing an energy storage device. In addition, the electric utilities in Virginia could follow the lead from other utilities and offer a one-time rebate on the purchase and installation of a household battery system, up to a certain dollar threshold per household.[2]

            In 2017 California, New Jersey and Maryland each passed bills creating a 30% tax credit for energy storage devices.[3] The bill in Maryland called for a 30% tax credit for the deployment of energy storage technologies from 2018-20122, the credit is capped at $5,000 for residential storage projects and $75,000 for commercial projects with an overall cap on credits awarded of $750,000 per year.[4] In Nevada, state legislators passed legislation in 2017 (SB 204) requiring regulators to examine whether to require utilities to purchase more battery resources on behalf of their customers and establish biennial targets for certain utilities to procure energy storage systems under certain circumstances.[5]  

Offshore Wind

            The offshore wind demonstration project proposed by Dominion is a necessary first step to obtain data necessary to make Virginia a hub for offshore wind. In addition, a state agency should build on the data obtained from the demonstration and DMME’s supply chain roadmap to further develop a state Offshore Wind Master Plan.

            Offshore wind presents a great opportunity for Virginia. A DMME study found that locating offshore wind construction and manufacturing activities in Virginia would create over 1,500 direct jobs. Several Virginia-based studies indicate that full development of the Commonwealth’s offshore wind could create between 10,000 and 14,000 jobs.[6] Locating any part of the offshore wind supply chain in Virginia will mean millions in capital investment as well as bringing a large ecosystem of co-located suppliers. Given the size of the offshore wind components, every major component must be constructed and transported on the water and these components will be manufactured near offshore wind farms. Many studies point to the Hampton Roads area as a superior industry hub.  With deep-water ports free of barriers (i.e. bridges), home to the world’s largest shipbuilding industry, and a large veteran workforce, Hampton Roads could easily become a national center for renewable energy development.  

            Once developed, prices for offshore wind have fallen rapidly. Orsted’s Hornsea Project Two, located in the UK, recently won a bid with one of the lowest prices for offshore wind ever at 57.5GBP/MWh (~$76/MWh). Thanks to technological advances, the U.S is likely to see a similar, if not faster, price drop compared to Europe where prices have dropped significantly.[7]

            In addition to being cost competitive in the near future, offshore wind helps protect Virginia’s fuel mix against price fluctuations and helps meet the state’s carbon reduction goal.

The Governor and other elected officials should consider and support legislative measures that prompt Dominion to expedite the development of the larger commercial lease area and the launch of an offshore wind industry in Virginia.  Potential legislation includes re-establishment of the Virginia Offshore Wind Development Authority (VOWDA) as an entity vested with the authority to issue bonds supporting investment in Virginia’s ports. 

Distributed Generation

            Nationwide, “the solar workforce increased by 168% in the past seven years, from about 93,000 jobs in 2010 to over 250,000 jobs in 2017,”[8] but distributed generation remains a vastly under-deployed resource in Virginia. Several reasons exist for this under-deployment:

  • 1% cap on net metering per utility
  • Standby charges for residential systems above 20 kW
  • Significant legal uncertainty regarding availability of power purchase agreements as a financing mechanism

Although it is a frequently-used talking point, there is literally no Virginia-based evidence that net metering customers pose a threat to grid reliability nor is there any evidence supporting the narrative that utilities are under-recovering their costs because of net metering customers. In fact, Virginia’s investor-owned utilities routinely collect far more revenue than necessary. In 2015 and 2016 alone, the SCC estimates that Dominion collected between $327.8 million and $705.2 million above their authorize rate of return.[9] Likewise, between 2014 and 2016, Appalachian Power over-earned between $93.6 million and $98.9 million.[10]

The GTSA may create space for rate designs more innovative than traditional net metering, but the necessary technology is not yet widely available. The more prudent path is to remove the current barriers to wide-spread distributed generation, which in turn allows more customers to access rooftop solar and grows a job-intensive, Virginia-based industry. As the utilities deploy smart meters and other emerging technology under SB 966, the data collected can then be used to evaluate grid reliability at higher DG penetrations and also consider alternative rate designs. In the short term, however, the solution is simply to legislatively remove the market barriers identified above.

Green Tariffs

Currently, Virginia law provides very narrow exceptions to the monopoly utiliy model. One such is the “green tariff” provision of Va. Code 56-577 A 5, which allows customers to purchase 100 percent renewable energy from a licensed competitive service provider, as long as the customer’s utility does not offer an SCC-approved 100% renewable energy tariff. Although there are no such SCC-approved utility tariffs, the threat such tariff pose to third party providers’ ability to build and sustain a business model in Virginia has effectively killed such an industry. Customers should have as much access to renewable energy as possible, so the simple legislative solution is to allow customers to shop for 100% renewable energy from third parties regardless of what products their utility offers.

Utility Scale Solar

Utility-scale solar is clearly a low-cost, zero-carbon energy resource, and the Commonwealth needs more of it. That being said, utility scale solar requires large tracts of land, and, where practicable, the Commonwealth should explore regulatory and financial incentives to drive solar developers away from prime agricultural farmland towards alternative sites such as abandoned mine lands, brownfields sites, landfills, and parking lot canopies. These alternative locations, coupled with increased access to data regarding interconnection costs, congestion needs, and other grid operational data, will better inform developer about how to prioritize site development. The administration should also promulgate best practices guidelines and model zoning ordinances how best to locate and permit these facilities.

Energy Efficiency

As discussed above, the utilities’ IRPs fail to properly evaluate demand side management programs, and comprehensive IRP reform is necessary to achieve that. Additionally, Virginia should change its regulatory landscape to prioritize energy efficiency by requiring a utility to prove it has identified and deployed all cost-effective, achievable energy efficiency before proposing new supply-side resources. Energy efficiency reform should also address the fact that while utilities may legally seek lost revenue recovery, in practice, that has never happened. As a result, the current regulatory landscape creates a strong financial disincentive for utilities to pursue robust efficiency programs. The law and applicable regulations should align energy efficiency goals and utility financial interests, either through revenue decoupling or other performance incentives.


The proposed carbon regulation under Executive Directive 11 is a great first step towards reducing Virginia’s greenhouse gas emissions. While that regulation is unquestionably valid in its own right, legislation authorizing the administration to formally join the Regional Greenhouse Gas Initiative (“RGGI”) or some other inter-state carbon compact will provide additional benefits. First, it will protect the regulation from future unilateral regulatory rollbacks. Second, it will remove the undesirable possibility of utility windfall profits by allowing the state to participate directly in the allowance auction, which in turn provides a large fund of revenue the state can direct towards energy efficiency programs to simultaneously lower customers’ bills and their carbon footprints, sea level rise mitigation efforts, and other related efforts.


[1] Virginia Electric and Power Company - Integrated Resource Plan filing for 2018 pursuant to Va. Code § 56-597 et seq., Case No. PUR-2018-00065, Direct Testimony of Gregory M. Lander at 48:20-21 through 49:1-10.






[7] See


[9] Status Report: Implementation of the Virginia Electric Utility Regulation Act Pursuant to § 56-596 B of the Code

of Virginia (Sept. 1, 2016) (“2016 Report”) at 6 (; Status Report: Implementation of the Virginia Electric Utility Regulation Act Pursuant to § 56-596 B of the Code of Virginia (Sept. 1, 2017) (“2017 Report”) at 6-7 (

[10] 2016 Report at 7-8; 2017 Report at 9.

CommentID: 66682