Back in spring of 2013 President Obama presented his vision for a U.S. Climate Action Plan at a speech at Georgetown University. The White House describes this plan as “a series of executive actions” to be implemented through regulations issued by the U.S. Environmental Protection Agency (EPA). The first action under the President’s climate plan was the development of carbon emissions standards for new power plants. The next step was taken in June 2014 when the EPA proposed their Clean Power Plan, additional carbon emissions regulations for existing power plants based on authority granted under 111 (d) of the Clean Air Act. There is an unreconciled difference in the versions of the law passed by the Senate and the House and the Clean Air Act may or may not contain this authority (depending on which version of the law prevails in a court challenge), also there is question if EPA can mandate consumer behavior which is incorporated in the mandates of the Clean Power Plan.
Nonetheless, the Commonwealth must move forward with compliance because it is a multi-year process. The EPA expects to publish the final Clean Power Plan rule in June 2015. State-specific compliance plans are due to the EPA for review and approval in June 2016, or slightly later depending on the compliance and planning approach taken by the state. Mandated compliance with the interim CO2 emissions reductions begin in 2020 and continue until 2030 when the requirement for a 30% reduction of CO2 emissions from 2005 levels is to be achieved. However, the 2005 baseline has nothing to do with the mandated future CO2 emission rate targets. In the proposed regulations, 2012 is the actual baseline year chosen by the EPA to calculate the interim and final CO2 goals for each state. Also, the cap is based on assumptions for total emissions; there will be significantly more people in the U.S. in 2030 assumptions on where they will live and how much power they use may not be accurate.
The Whitehouse and EPA policy strategists point out a similarity between the carbon control regulations and the regulations to control acid rain several decades ago. However SO2 (the source of the acid rain) was allocated under a one-step calculation. This proposed EPA CO2 regulation uses a seven step process, shown in a 54 column spreadsheet; and is supplemented by the output of an Integrated Planning Model simulation, implementation of a mandated renewable energy program and an a consumer energy efficiency or demand-side management program in each state.
EPA proposed that the states have flexibility in developing their compliance plans saying that the states may choose to change from a CO2 emissions rate based compliance approach and establish a mass-based (total CO2 tonnage) cap that can be used in a regional trading program (like the RGGI program currently used by nine northeastern states). Though EPA seems to be heavily pushing the adoption of a regional carbon trading program, Virginia’s CO2 state compliance plan must be submitted to EPA by June 2016 and it would take several more years to implement such a program. Virginia would need to identify state trading partners, pass enabling legislation in Virginia (as would be required in the other states), sign multi-state MOU’s, establish trading rules and compliance testing within the state trading group, and obtain EPA approval (and possibly Congressional approval of the interstate compact). Because of these timing obstacles, the use of a regional trading program for initial compliance with the EPA Clean Power Plan regulations may not be possible. However, the report recommends that Virginia begin to explore the use of this option as soon as possible.
Within the Virginia Energy Plan 6 compliance scenarios were developed with the input of the Virginia Department of Environmental Quality, the Virginia Department of Mines, Minerals and Energy, the State Corporation Commission, and the report consulting team to determine whether Virginia could comply with the proposed EPA Clean Power Plan. Compliance scenarios were defined using changes to the electric generation mix. A detailed model evaluating, at each generating unit in Virginia, fixed and variable operating cost, fuel cost, CO2 emissions, and location in the grid for stability and reliability of power was developed. Additionally, natural gas-fired units could not be place just anywhere, they need an adequate fuel supply.
Four of the scenarios allowed Virginia to meet the requirements of the EPA Clean Power Plan. All four of the successful scenarios include major increases in the use of natural gas fueled electrical generation and a need for expansion of the existing natural gas pipeline network into the Commonwealth. Here is the reason for Governor McAuliffe’s support of a gas pipeline. It is needed to meet the EPA Clean Power Plan CO2 emission targets within the time and technology constraints. The simple truth is that coal emits 2,268 lbs. of CO2 per Megawatt hour while the natural gas fired turbines emits 903 lbs. of CO2 per Megawatt hour. Virginia is currently at 1,438 lbs. of CO2 emitted per megawatt hour of electricity generated and we need to be at 991 lbs. of CO2 per megawatt hour in 2020 and 810 lbs. of CO2 per megawatt hour of electricity generated in 2030 to be in compliance with the EPA Clean Power Plan.
All of the successful scenarios represent a net loss of employment in the Commonwealth. Though there are increases in “green jobs” for installing renewable energy and energy efficiency programs, it is not nearly enough to make up for the loss of employment in the coal sector. Virginia accounted for 4.5% of U.S. coal production east of the Mississippi River in 2012. The jobs at the seaport at Norfolk is America's largest coal export facility are expected to be unaffected.
The electricity generated in Virginia represents only about 64% of the electricity used in Virginia. In 2012 coal provided approximately 21% of the electric power in Virginia. In 2012, the four operating nuclear generating units provided about 27.4 million megawatt hours of an approximately 109 million megawatt hours of electricity used in the Commonwealth. A new nuclear generating unit is being considered by Dominion Power at the North Anna plant and would provide an additional 10.3 million megawatt hours of CO2 emission-free power once at full operation, allowing in state nuclear to provide almost 40% of total generation. The inclusion of more nuclear generation in Virginia’s portfolio will significantly alter the energy mix in the long term, decreasing the needed contribution from natural gas, but it can take more than a decade to design, obtain approvals, license and built a nuclear plant.
The EPA Clean Power Plan also requires new renewable energy generation, energy efficiency and demand side management. All the successful the compliance scenarios will require expansion of renewable energy incentive programs. Virginia has less solar power than our neighbors. Though we have net metering there is no solar carve out under the Renewable Portfolio Goal. In addition in 2012, the legislature amended the net metering law to allow utilities to charge stand-by fees to residential net metering customers to charge for transmission and distribution infrastructure. Residential consumers with a system capacity greater than 10 kilowatts must now pay $2.79 a kilowatt in monthly distribution standby charges and $1.40 kilowatt in monthly transmission standby charges. Non-residential consumers with grid connected renewable generation are exempt from these additional charges. Some believe that the standby charges are a disincentive, but most residential installation are smaller than 10 kilowatts.
As of June 2014, the total net metered capacity of solar photovoltaic systems in Virginia was just over 12 megawatts. This is far less than in neighboring Maryland, with 158 megawatts (MEA, 2014), and North Carolina with 592 megawatts. Currently, Virginia law does not allow a third party to install and own a renewable energy facility on a utility customer’s property and sell the utility customer the power produced. To make solar leasing viable, there has to be enabling legislation and financial incentives. At one time, Virginia citizens could sell their solar RECs, also known as SRECs, in North Carolina, Maryland, Pennsylvania and Washington, DC, to help electric utilities in those states and the District meet their renewable portfolio mandates. However, at this time, Maryland and the District of Columbia no longer allow out-of-state SRECs, and the SREC markets in Pennsylvania and North Carolina are oversupplied and the SRECs are almost worthless. The federal tax credit vanishes in 2016 and without additional financial incentives solar power is too expensive to compete.
There are numerous semiconductor technologies used to manufacture PV products. PV is an evolving technology, with incremental efficiency gains each year. As technology and manufacturing methods improve, costs continue to come down. When PV was first used commercially to power satellites in the 1950s a 1 watt cell cost $300. In 2013, residential system prices fell to an average $4.59/watt, non-residential prices fell to an average $3.57/Watt, and utility scale systems fell to an average $1.96/Watt. We are still pretty far from solar PV being cost-competitive; so the Virginia legislature will have to develop financial incentives to meet the requirements of the EPA Clean Power Plan. The same type of programs will be necessary to meet the “demand management” requirements of the Clean Power Plan rules.