RD118 - Annual Executive Summary of the Interim Activity and Work of the Commission on Electric Utility Regulation, 2017 Interim
The Commission on Electric Utility Regulation (the Commission) is established pursuant to Chapter 31 (§ 30-201 et seq.) of Title 30 of the Code of Virginia. The Commission is charged with:
• Monitoring the work of the State Corporation Commission (SCC) in implementing the Virginia Electric Utility Regulation Act (§ 56-576 et seq.);
• Examining generation, transmission, and distribution systems reliability concerns;
• Establishing one or more subcommittees for any purpose within the scope of the duties prescribed to the Commission; and
• Reporting annually with such recommendations as may be appropriate for legislative and administrative consideration in order to maintain reliable service in the Commonwealth while preserving the Commonwealth's position as a low-cost electricity market.
The Commission is authorized to have 10 legislative members, of whom four are members of the Senate and six are members of the House of Delegates. Senator Thomas K. Norment, Jr., serves as the Commission's chairman. The other Senate members are Senators L. Louise Lucas, Richard L. Saslaw, and Frank W. Wagner. The Commission currently has four House of Delegates members: Delegates Terry G. Kilgore, Timothy D. Hugo, Kenneth R. Plum, and Matthew James. As of the convening of the 2018 Session of the General Assembly, the Commission has two vacancies, resulting from the election losses by Delegates Jackson H. Miller and Ronald A. Villanueva.
Staffing was provided by Hobie Lehman from the Office of the Clerk of the Senate and Frank Munyan from the Division of Legislative Services.
This executive summary of the interim activity and work of the Commission is submitted pursuant to § 30-207 of the Code of Virginia and is provided in lieu of an annual report.
The Commission met on August 2, 2017, and December 4, 2017. Issues addressed at its two meetings include the following:
1. Dominion Energy Report
At the August 2, 2017, meeting, Mark O. Webb, Senior Vice President - Corporate Affairs and Chief Legal Officer at Dominion Energy, outlined four key elements of providing reliable electric service: generation, transmission, distribution, and customers. Mr. Webb stated that the implicit goals of the 2007 reregulation legislation were to incentivize utilities to invest in generation facilities in Virginia and to maintain low electricity rates. He observed that the reregulation legislation was successful in incentivizing new generation within the Commonwealth, even after the 2008 recession unsettled capital markets.
Dominion Energy cited the following as successes resulting from the reregulation legislation:
• The construction of five large-scale generation facilities in Virginia, including natural gas-fueled power stations in Brunswick, Warren, Buckingham, and Greensville Counties, as well as biomass conversions at other facilities;
• More than 73,000 construction-related jobs and 730 permanent new jobs;
• Over $11.5 billion in economic activity supported by construction of these facilities; and
• Investments of $2.8 billion resulting from environmental policy changes.
Other results attributed to the reregulation legislation include a 26 percent reduction in reliance on out-of-state energy purchases and a 20 percent reduction in carbon emissions, both of which have occurred since 2008. Between 2007 and 2016, the percentage of Dominion Energy's electricity sourced from coal has fallen from 35 percent to 25 percent, and the percentage purchased on the wholesale market has fallen from 26 percent to 8 percent. Over that same period, the percentage of Dominion Energy's electricity sourced from natural gas has increased from 6 percent to 30 percent, and the percentage sourced from zero carbon (including nuclear) and renewable sources has increased from 29 percent to 34 percent.
Mr. Webb also lauded the enactment of Senate Bill 1349 in 2015. This measure, patroned by Senator Frank Wagner, suspended biennial reviews by the State Corporation Commission (SCC) of the rates, terms, and conditions for any service of Virginia's two largest investor-owned electric utilities during a transitional period. The legislation, per Mr. Webb, addressed uncertainties posed by the proposed federal Clean Power Plan and other environmental regulations. He credited Senate Bill 1349 with unleashing solar energy development. He noted that since the passage of Senate Bill 1349, Dominion Energy has absorbed about $500 million in costs. In response to a question posed by Senator Norment, he elaborated that the bulk of these costs ($400 million) involved closing legacy coal ash ponds. Of the balance, $85 million was attributed to elevated fuel costs tied to the polar vortex and $25 million to repairing storm damage, most of which was caused by Hurricane Matthew.
Mr. Webb reported that the reregulation legislation and Senate Bill 1349 have succeeded in providing low rates for Dominion Energy's customers. As of January 1, 2017, the annualized rate for residential customers, based on 1,000 kWh of usage per month, of 11.6 cents/kWh is lower than the Virginia average rate of 12.4 cents, the national average rate of 13.4 cents, and the average of the rates of states participating in the Regional Greenhouse Gas Initiative (RGGI) of 17.4 cents. As of the same date, the annualized rate for an industrial customer with 1,000 kW demand and 650,000 kWh of usage per month was 5.7 cents/kWh. The corresponding industrial rates were 6.6 cents for customers in Virginia's peer group of southeast states and 7.5 cents in CNBC's "Top Ten States for Business: 2017." The national average was 8.1 cents, and the average of the rates of states participating in RGGI was 11 cents. Of the states in CNBC's "Top Ten States for Business: 2017," Virginia's industrial rate was the lowest.
Senate Bill 1349 was credited with contributing greatly to solar energy development in Virginia, which now consists of 443 MW in operation or under construction. Mr. Web cited the increase in the acreage of solar projects from 138 acres before the bill's enactment to over 4,683 acres today. Dominion Energy is purchasing energy from 143 projects owned by third parties. Dominion Energy was characterized as a leader in partnering for solar energy projects.
Another aspect of Senate Bill 1349 was its directive for bill assistance and weatherization. A $42 million incremental program has been funded by the utility's shareholders and not by its customers. An innovative program with the Department for Aging and Rehabilitative Services and the Department of Veterans Services pairs energy vouchers and housing vouchers. Since the EnergyShare program has expanded, 26,575 families and individuals have received bill assistance and 16,224 homes have been weatherized.
In conclusion, Mr. Webb identified several areas of challenges. First, to guard against fuel volatility and risks, he advocated fuel diversity, resource planning, and preparation for effects of carbon regulation. He also endorsed ensuring that rates stay competitive when compared to those of other states and continuing to make energy independence a top priority amid regulatory uncertainty. Second, facing the challenges posed by the greening of the grid will require preparing the energy grid for a two-way flow of electricity, incorporating additional energy storage, and improving energy efficiency by providing customers with additional information. A smart grid is viewed as both more environmentally friendly and more resilient than the existing system. Other challenges to Dominion Energy include reducing the number of outages, improving the speed at which power is restored, undergrounding the most outage-prone distribution lines, and addressing needs for both physical security and cybersecurity.
2. APCO Report
Ronald J. Jefferson, Manager of External Affairs for Appalachian Power Company (APCO), began his remarks at the August 2, 2017, meeting by observing that APCO is experiencing flat load growth in its Virginia service territory. He attributed this in part to flat or declining population levels and noted that about 90 percent of its half million customers are residential. APCO recognizes the need to bring industrial load back to its territory.
Mr. Jefferson reported that APCO's rates have remained stable since 2010. While there has been some fluctuation, its residential rate was 11.56 cents/kWh in January 2010 and 11.69 cents/kWh in July 2017. This period of stable rates followed a period of rising rates. In 2005, the company's rate was around six cents/kWh. Mr. Jefferson attributed the rate stability since 2010 to the 2007 reregulation legislation, which has allowed the recovery of certain costs through rate adjustment clauses, which have been mitigated by lower fuel costs. Looking forward, he does not envision any "large spends," and he sees continued rate stability.
APCO's residential rates produce a monthly average bill, based on usage of 1,000 kWh, of $115.41. This figure compares favorably to the Virginia average ($123.73), the national average ($133.99), and the East Coast average ($149.50). Mr. Jefferson noted that APCO's commercial rate of 6.1 cents/kWh is very close to Dominion Energy's rate of 5.7 cents/kWh.
APCO has adopted a different strategy from Dominion Energy's strategy with respect to renewable power by focusing investment on wind power rather than solar energy. Mr. Jefferson explained this course by noting that APCO is a winter-peaking utility, while Dominion Energy is a summer-peaking utility. This difference is largely due to the absence of natural gas distribution in much of APCO's territory, which has resulted in more residential use of electricity for home heating, and to the fact that the housing stock in APCO's territory tends not to be as well insulated. As a result, APCO's peak demand times are winter mornings when customers turn up the heat upon waking, while Dominion Energy's peak demand times tend to be summer afternoons when customers crank up air conditioning upon arriving home from work.
Mr. Jefferson discussed his utility's integrated resource plan's anticipated fuel capacity mix, which he characterized as planning for a clean-energy future. From 2017 to 2031, the percentage of capacity derived from coal is forecast to decline from 61 percent to 51 percent, and the percentage of capacity derived from natural gas is forecast to decline from 19 percent to 11 percent. Over the same period, the percentage of capacity derived from wind and solar resources is forecast to increase from five percent to 25 percent. A review of APCO's fuel energy mix, which illustrates the power sources actually used to provide electricity, shows that the share of the utility's power provided by coal and natural gas will decline over the period from 93 percent to 80 percent, and the share of the utility's power provided by wind and solar resources will increase from four percent to 18 percent.
While the utility has adequate capacity, Mr. Jefferson explained, its ability to meet its capacity requirement is due in part to PJM Interconnection's requirement that utilities be able to meet their summer peak demand. Because APCO is a winter-peaking utility, it can meet its summer peak demand while being a little "energy short" in some winter months. The utility is meeting this shortfall by investing in wind and solar power. Its transitioning to greener generation makes sense to the company from an energy perspective. Mr. Jefferson noted that APCO has obtained regulatory approval to construct the Bluff Point wind project. This 120 MW project, together with wind projects at Hardin (175 MW) and Beech Ridge (50 MW), for which approvals are pending, will get the utility to a total of 720 MW of wind power. With respect to solar, APCO has issued a request for proposals and expects to make an announcement of its results soon.
Other major investments by APCO include investments in the transmission grid. The Cloverdale transmission project, which involved an investment of $250 million, is complete. Mr. Jefferson also described the company's use of the option for local approval of transmission lines of 138 kV on a project in Henry County that has allowed an industrial development "megasite" to qualify as a Tier 5 site.
3. Clean Power Plan
At the Commission's December 4, 2017, meeting, David Paylor, Director of the Department of Environmental Quality (DEQ), provided an overview of developments related to efforts to regulate emissions of carbon dioxide (CO2) from electric power generation facilities. At the federal level, the Environmental Protection Agency's proposed Clean Power Plan regulations are on hold. At the state level, DEQ was directed by Governor McAuliffe's Executive Directive 11 (ED-11) dated May 16, 2017, to develop a proposed regulation for consideration by the Air Pollution Control Board (APCB) to abate, control, or limit CO2 emissions from electric power facilities.
ED-11 requires that the proposed regulation include provisions to ensure that the Commonwealth's regulation is trading-ready to allow for the use of market-based mechanisms and the trading of CO2 allowances through a multi-state trading program. ED-11 also directs that the proposed regulation establish abatement mechanisms providing for a corresponding level of stringency to limits on CO2 emissions imposed in other states with such limits.
The only such existing multi-state trading program is the Regional Greenhouse Gas Initiative (RGGI), a program covering fossil-fuel-fired electric generating units in nine northeast and mid-Atlantic states. Under the program, RGGI, Inc., conducts quarterly auctions at which the generating units, called "covered sources," purchase allowances in quarterly auctions. The revenues generated from the sale of the allowances are returned to member states.
Mr. Paylor noted that on May 12, 2017, the Attorney General issued an opinion that concluded that the APCB is legally authorized to regulate greenhouse gases (GHG). Per the opinion, the APCB "has the authority to establish a statewide cap on GHG emissions for all new and existing fossil fuel electric generating plants as a means of abating and controlling such emissions."
On November 16, 2017, the APCB approved the release of the proposed regulation for public comment. The proposed regulation will undergo executive review, publication in the Virginia Register, a 60-day public comment period, and at least one public hearing before it can become effective. Mr. Paylor stated that he did not believe the regulation would take effect until 2019.
The proposed regulation is based on the RGGI's August 2017 model rule with modifications to have it operate as a Virginia rule with additional provisions and modifications, including a provision for an allocation of "conditional allowances" to covered sources with required consignment to RGGI auctions. Under the proposal, the carbon cap-and-trade program would commence in 2020 and electric generating units that have a capacity of 25 MW or more and that use fossil fuel for 10 percent or more of their total fuel mix (called CO2 budget sources) would be required to hold a CO2 allowance for every ton of CO2 emitted during a control period. Industrial units are exempted from the proposed regulation. Starting in 2020, there would be 33 or 34 million CO2 allowances, with the number declining at about three percent per year each year thereafter until 2030. As a result, if the initial CO2 base budget for 2020 is 34 million allowances, in 2030 the number of allowances will have fallen to 23.8 million.
The proposed CO2 regulation calls for 95 percent of the allowances in a year to be conditionally allocated to the CO2 budget sources. These conditional allowances are required to be consigned to the RGGI quarterly auctions. The CO2 budget sources are required to purchase compliance allowances at the RGGI auctions. Under the scheme, each CO2 budget source will be compensated for the conditional allowances that it consigned to auction, with the level of compensation being set on the basis of the auction clearing price. Revenue received by CO2 budget sources that are owned by regulated electric utilities will flow to ratepayers pursuant to State Corporation Commission (SCC) requirements. The remaining five percent of the allowances in a year will be allocated to the Department of Mines, Minerals and Energy to assist the DEQ in abating and controlling CO2 and other air pollutants.
Mr. Paylor provided the Commission with the results of modeling that projects the effects of Virginia's participation in RGGI. Over the period 2017-2031, the average monthly electric utility bill for a residential Virginia customer (stated in 2015 dollars) is projected to be $181.61 under the proposed regulation, which exceeds the reference case projection of $181.42 by 19 cents, or 0.7 percent. Under the same assumptions, the average bill over the period for a commercial customer would be 0.9 percent higher and for an industrial customer would be 1.1 percent higher.
4. Post-Hurricane Restorations of Electric Power
Chris Eisenbrey, Senior Director of Business Continuity and Operations at the Washington, D.C.-based Edison Electric Institute (EEI), recounted the experiences of the electric utility industry in coping with two major storms that struck the United States in 2017: Hurricanes Harvey and Irma. Mr. Eisenbrey's remarks centered on the concept that investments in the electrical grid, including smart-grid technologies, improved the ability of utilities to respond to service outages during these major storms.
With regard to Hurricane Harvey, which made landfall in Texas in August 2017, CenterPoint Energy benefitted from the deployment of an advanced metering system (AMS) and a smart grid that included distribution automation devices such as intelligent grid switches. These technologies allowed CenterPoint Energy to isolate problems on the electrical grid quickly and restore service to customers. Smart meters increased efficiency during the storm by providing for the use of real-time analytics to assess, monitor, and resolve cases.
With regard to Hurricane Irma, which made landfall in Florida in September 2017, Florida Power & Light's response to storm damage benefitted from the utility's investment in its electrical grid. Smart meters and intelligent devices, including automated feeder switches, automated lateral switches, fault current indicators, and diagnostic centers, allowed the utility to respond to outages more quickly by locating the specific areas affected by outages. Since 2006, Florida Power & Light has invested nearly $3 billion in its electrical grid, deployed more than 4.9 million smart meters, and installed more than 83,000 intelligent devices.
Mr. Eisenbrey closed with the observation that investing in a robust, flexible, dynamic, and secure electrical grid is a multi-billion-dollar, multi-year effort. He cited the electric utility industry's significant investments to harden the electrical grid and to make the energy infrastructure more resilient. The investor-owned electric utilities that are members of EEI invested an estimated $52.8 billion in the electrical grid's transmission and distribution infrastructure in 2016. In response to a question posed by Senator Wagner, Mr. Eisenbrey agreed that an element of increasing a system's resiliency includes undergrounding lines, as it is best to avoid damage to the infrastructure in the first place.
5. Cybersecurity Issues for Power Suppliers
The Honorable Karen Jackson, Secretary of Technology, cautioned the Commission at its December 4, 2017, meeting about the threat to the electric power grid posed by cyber hackers. Hackers, who are going after the underpinnings of the economy, are not only individuals; many nations, including China, Russia, Iran, and North Korea, have developed cyberespionage divisions. She cautioned that there are not enough funds or qualified people to deal with the nation-states that are threatening systems in this country. It is difficult, she noted, for any one company to mount a defense against actions by nation-states.
An area of increasing concern is the Internet of Things (IOT), which refers to appliances, automobiles, and other items that do not need to be connected to the Internet to be affected by cybersecurity concerns. One example is the risk that malware may be implanted in devices before they are purchased by a consumer. Adding items to the network increases the number of points of vulnerability. The advent of the IOT places electric utilities in the unenviable position of guarding the grid while devices that are not manufactured to be secure are added to the grid, increasing the risk of malware introduction. Efforts are underway to examine supply chains in order to search for risks posed by digital chips and other items in the IOT.
6. Status of Electric Generation, Rates, and Related Issues Since 2007
Kimberly Pate, Director of the SCC's Division of Utility Accounting and Finance, reported at the December 4, 2017, meeting on changes to bills of customers of Appalachian Power Company (APCO) and Dominion Energy Virginia (DEV) over the period July 1, 2007, through July 1, 2017. For a typical residential customer of APCO using 1,000 kWh monthly, the bill increased by $48.64, or 73 percent, from $66.61 to $115.25. The bill for such a customer of DEV increased by $26.61, or 29 percent, from $90.59 to $117.20, over that period.
A customer's monthly bill consists of the following parts: the cost of fuel and purchased power (fuel rate); rate adjustment clauses (RACs); and base rates. Over the same 10-year period, the fuel rate for the above-referenced typical residential customer of APCO increased 75 percent (from $13.12 to $23.01), and for such a customer of DEV increased seven percent (from $22.32 to $23.83).
Over the same 10-year period, the RACs for the above-referenced typical residential customer of APCO increased from $1.84 to $14.84, and for such a customer of DEV increased from zero to $18.07.
Over the same 10-year period, the base rate for the above-referenced typical residential customer of APCO increased 50 percent (from $51.65 to $77.40), and for such a customer of DEV increased 10 percent (from $68.27 to $75.30).
Ms. Pate outlined the changes in each utility's generation mix over the decade. APCO's data reflects a large increase in power generated from natural gas (from zero to 14 percent) and wind (from zero to three percent) and a decline (from 75 percent to 69 percent) in the portion of its energy generated from coal. DEV's generation mix also changed over the decade, with the percentage of its power generated from natural gas jumping from six percent to 31 percent. DEV saw drops in the percentage of its power generated from coal (from 36 percent to 25 percent) and in the percentage purchased from non-utility generators and the PJM market (from 27 percent to nine percent). The shift to natural gas can be attributed to the decline in the price of natural gas that followed the advent of the "shale revolution" starting in 2008.
Ms. Pate then presented data that reflected the earned return on equity (ROE), as determined in Commission proceedings through 2013 and pursuant to information filings provided since the implementation of the freeze on biennial reviews enacted by Senate Bill 1349 in 2015. APCO's earned ROE based on the 2016 informational filing, was 11.09 percent and DEV's earned ROE, based on the 2016 informational filing, was 12.87 percent.
The SCC's presentation concluded by identifying the potential effects of a reduction in the federal corporate income tax rate from 35 percent to 20 percent. Such a reduction would result in base rate tax savings of $165 million annually for DEV and $80 million annually for APCO. Ms. Pate noted that these tax savings would remain with shareholders during the base rate freeze.
7. Dominion Energy's Response
At the December 4, 2017, meeting, Mr. Webb posited that DEV needs to modernize its electric grid. Achieving the goal of grid modernization would address voltage fluctuations, knowing the source of an outage, incorporating two-way flows of energy, and adjusting to the use of electric vehicles. He conceded that DEV's system does not have the same capabilities that allowed Florida Power & Light to respond as well as it did to Hurricane Irma. He also agreed with Secretary Jackson regarding the threats to the grid posed by cyber-attacks.
Mr. Webb stated that his utility could address these challenges while keeping rates low and that the General Assembly may wish to adopt a reinvestment model under which excess earnings are reinvested in modernizing and transforming the electricity grid. Doing so, he acknowledged, would mean lifting the freeze on SCC reviews enacted by Senate Bill 1349 in 2015. He asserted that the draft APCB regulation to regulate CO2 emissions provides the clarity needed to move away from the freeze. Under the proposal presented by Mr. Webb, rate reviews would be conducted in a manner that allows a utility with sufficient overearnings to absorb the costs of investments in new technology and grid modernization in base rates, rather than requiring the utility to issue credits to customers or reduce rates as a result of its overearnings while recovering those investments through a rate adjustment clause.
8. Appalachian Power Company's Response
At the December 4, 2017, meeting, Mr. Jefferson described the economic development benefits of two new ALCO projects in Roanoke by a sister company. He told the members that APCO's recent fuel factor case resulted in a reduction in a residential customer's fuel rate from 2.301 cents/kWh to 2.169 cents/kWh. Other recent APCO developments include (i) the installation at its Byllesby Hydro facility of a four-megawatt battery for grid support and (ii) the deployment of 53,700 advanced meters in 2017 and plans to deploy another 132,000 in 2018.
9. Cooperative Electric Utilities' Response
Andrew Vehorn, Director of Government Affairs for Virginia's electric cooperatives, provided background information at the December 4, 2017, meeting on the 13 distribution cooperatives and one generation and transmission cooperative (ODEC) that serve customers in the Commonwealth. With regard to the proposed CO2 regulation, Mr. Vehorn expressed concern with its effect on cooperatives' members' power costs over the long run and noted that it would affect three cooperative-owned facilities in the Commonwealth. He noted that ODEC operates in Maryland, which is a member of RGGI, and asserted that the RGGI program has resulted in increased costs for ODEC and increased wholesale prices.
Additional information regarding the Commission's activities is available through its website at http://dls.virginia.gov/commissions/eur.htm.