Public Comments 9VAC5-140 6010-6430 “Regulations for Emission Trading Programs”, Department of Environmental Quality published in the Virginia Register of Regulations Vol. 34ISS.10, January 8, 2018

            The following comments are offered on the above referenced proposed regulation, and the key issues are summarized here:

1)  Based on the Constitution of Virginia, DEQ does not have the authority to impose the proposed regulation without legislative action.  A bill to provide that authority has failed in committee.

2) After a decade, the Regional Greenhouse Gas Initiative has failed to reduce carbon dioxide emissions, or to stimulate energy efficiency, and renewable energy.   Virginia power companies have done a slightly better job of reducing emissions than the neighboring RGGI states of Maryland and Delaware who share membership in the PJM Regional Transmission Organization.

3) Participation in the RGGI program will provide no benefits as it will not reduce emissions, but will add between $0.7 and $1.4 billion in cost to electric bills.

4) The State Corporation Commission has already approved 5.4 gigawatts of new natural gas electric generation projects to more than replace 2.2 gigawatts expected to retire to maintain electric grid reliability.  Carbon dioxide emissions will total about 39 million tons by 2020, way beyond the initial 33 to 34 million tons proposed.

5) The proposed 2030 emissions target of 23 to 24 million tons is significantly below the 29 million ton target set by the EPA Clean Power Plan.  We note starting at 39 million tons, and reducing the emissions target 3% a year would meet the CPP target.

1. The regulation is illegal as it requires a Bill be passed by the Virginia General Assembly authorizing the collection of taxes or fees, and appropriation of spending

            The regulation requires electric generators in Virginia to purchase allowances to emit carbon dioxide in cap-and-trade program known as the Regional Greenhouse Gas Initiative (RGGI).  These allowances are equivalent to permit or license fees.  In addition, the regulation delegates 5% of the allowance proceeds to the Department Mines Minerals and Energy to be spent on carbon dioxide reduction projects.

The Constitution of Virginia – 1971 specifies;

“Article IV, Section 11.  Enactment of laws.

No law shall be enacted except by bill.  A bill may originate in either house, may be approved or rejected by the other, or may be amended by either, with the concurrence of the other.

No bill which creates or establishes a new office, or which creates, continues, or revives a debt or charge, or which makes, continues, or revives any appropriation of public or trust money or property, or which releases, discharges, or commutes any claim or demand of the Commonwealth, or which imposes, continues, or revives a tax, shall be passed except by the affirmative vote of a majority of all the members elected to each house, the name of each member voting and how he voted to be recorded in the journal

Article X, Section 7.  Collection and disposition of State revenues. 

All taxes, licenses, and other revenues of the Commonwealth shall be collected by its proper officers and paid into the State treasury.  No money shall be paid out of the State treasury except in pursuance of appropriations made by law; and no such appropriation shall be made which is payable more than two years and six months after the end of the session of the General Assembly at which the law is enacted authorizing the same.”

            The Constitution clearly establishes authority to raise and spend money to the General Assembly, not the DEQ.  Furthermore, the proposed regulation adopts the RGGI, Inc. Model Rule.  The Model Rule was devised as model legislation which has been adopted by the General Assemblies of all ten states that have participated in the Regional Greenhouse Gas Initiative.

            The Virginia General Assembly has made its position very clear as opposing adopting a carbon dioxide cap-and-trade program without legislative approval.  Both the Senate and the House of Delegates have passed HB1270 resolving no carbon dioxide cap-and-trade program shall be adopted without a Bill authorizing it.  In addition, the Senate Agriculture, Conservation and Natural Resources Committee rejected SB 696, which would establish cap-and-trade in Virginia and bring the state’s carbon emissions regulations into compliance with the RGGI model rule.

            The proposed regulation will not withstand a legal challenge.

2. The RGGI program has not worked to reduce carbon dioxide emissions

            There is a decade of experience of RGGI’s impacts.  Carbon dioxide emissions fell just as fast in states with similar energy policies except for RGGI as they did in RGGI states according to a study published in the Cato Journal, Volume 38, winter 2018 issue titled, “A Review of the Regional Greenhouse Gas Initiative”.  This is the only independent, peer reviewed study of the RGGI program available. Lower natural gas prices, and EPA regulations encouraged fuel switching from coal to natural gas between 2007 and 2015.  This resulted in a 16 percentage point reduction in coal-fired electric generation, and a corresponding increase in natural gas generation of about 10 percentage points in both RGGI and non-RGGI states. 

The same report shows non-RGGI states added generation from wind, and solar power at over twice the rate as RGGI states (5.5 percentage points compared to 2.3%).  Non-RGGI states also saw a faster rate of improvement in Energy Intensity, a measure of energy efficiency (11.5% compared to 9.6%).  RGGI, Inc. claims allowance revenue was invested in energy efficiency, and wind and solar power, but the actual comparison results show no significant impact of the investments.

Compare non-RGGI Virginia to the combined results in neighboring RGGI states of Maryland and Delaware.  All three are in the PJM Interconnection Regional Transmission Organization.  The extra costs of RGGI allowances discouraged electric generation in Delaware and Maryland where electricity imports grew 42% since 2005, while Virginia imports decreased 34% (Table 1). 

Table 1: Electric Demand vs. Generation in millions of MWh

	Delaware + Maryland	Virginia
2005 Demand	79.6	108.8
2005 In-State Generation	60.8	78.9
2005 Import	18.8	29.9
2005 % Imports	23.6%	27.5%
2016 Demand	72.6	112.3
2016 In-State Generation	45.9	92.6
2016 Imports	26.7	19.7
2016 % Imports	36.7%	17.5%
2005 to 2016 % Change in Imports	42%	(34%)

Source: US Energy Information Agency Electric Power Annual State Data

Note: The Virginia SCC does not count out of state generation owned by

Investor owned utilities in VA as imports, but EIA does

In other words the RGGI states simply exported electric generation and emissions to other states.  Adjusting for those exported emissions, emissions rates per person fell 38.6% in Virginia since 2005 compared to a combined 37.1% for Maryland and Delaware (Table 2).

Table 2: Carbon Dioxide Emissions in millions of tons

	Delaware + Maryland	Virginia
2005 In State Emissions	40.6	48.2
2005 Out of State Emissions	12.1	19.3
2005 Total Emissions	52.7	67.5
2005 Population	6,443,912	7,567,465
2005 Tons of CO2 per person	8.25	8.92
2016 In State Emissions	22.9	36.6
2016 Out of State Emissions	13.3	9.6
2016 Total Emissions	36.2	46.1
2016 Population	6,977,450	8,414,380
2016 Tons of CO2 per person	5.19	5.48
2005 to 2016 % Change in Emission Rate	(37.1%)	(38.6%)

Sources: US Energy Information Agency Electric Power Annual State Data,

US Census, PJM Systems Mix (0.646 tons MWh in 2005, 0.496 in 2016)

Importing more power from other states is not the only form of emission “leakage”.  RGGI allowance costs added to already high regional electric bills. The combined pricing impact resulted in a 12 percent drop in goods production and a 34 percent drop in the production of energy intensive goods (think lost high paying blue collar jobs).  Comparison states increased goods production by 20 percent and only lost 5 percent of energy intensive manufacturing according to the Cato Journal report. 

The extra costs of RGGI allowances have turned coal-fired plants from base load providers to intermittent suppliers by dramatically lowering operating hours.  Expected increases in RGGI emission allowance cost will soon have the same impact on natural gas-fired power plants.  Ramping power plants up and down has dropped efficiency 18.5% which results in more emissions, not less, and further raises electricity costs  61% of Virginia power generation comes from coal and natural gas according to the US EIA.

 

A national target of 28% lower emissions from power plants by 2025, and 32% by 2032 from a 2005 base established in the Environmental Protection Agency “Clean Power Plan”, will be met without planned taxes, or fees on carbon dioxide emissions.  Over the most recent twelve months power plant emissions have already fallen 27% nationally according to the U.S. Energy Information Agency Electric Power Monthly.  The US is leading the world in reducing emissions.  Since 2005 the US has reduced carbon dioxide emissions twice as fast as the rest of the developed world combined.

Clearly RGGI has not had the expected impact of lowering carbon dioxide emissions!

3. The proposed regulation will likely have no benefits and add $0.7 to $1.4 billion to electric bills

            The benefits calculated in the Economic Impact Analysis of the proposed regulation assumed the regulation would lower carbon dioxide emissions along with reducing oxides of sulfur and nitrogen as a by-product.  As shown above, a decade of experience with RGGI in other states has shown no added reduction in carbon dioxide or air pollutant emissions from the RGGI program, therefore there can be no monetized benefits from the proposed regulation.

            To calculate the costs of the proposed regulation an estimate of tons of annual emissions through 2030 is needed, along with an estimate of how many allowances will be available (each allowance covers one ton of emissions), and an estimate of the future price of allowances.  Fortunately, the proposed regulation provides the last two items.

            The Virginia State Corporation Commission (SCC) regulates utilities.  The SCC files an annual summary report of what is going on with regulated utilities, the “Status Report 2017: Implementation of the Virginia Electric Utility Regulation Act”.   The state’s two largest investor owned electric utilities Virginia Electric Power Division of Dominion Energy Virginia (67% of customers), and Appalachian Power Company Division of America Electric Power (14.5% of customers) file annual Integrated Resource Plans (IRP) which forecasts future demand, supply, and pricing.  Based on these documents there are planned retirements between 2017 and 2026 of 1731 MW of oil and coal-fired capacity, and 440 MW of natural gas capacity.  Between 2017 and 2019 5413 MW of new natural gas-fired capacity has already been approved by the SCC. 

Natural gas emits about half the carbon dioxide for each MWh of power generated.   The retirements could be considered as offsetting emissions from 4280 MW of new natural gas capacity.  That leaves a net increase of 1132 MW of new natural gas capacity.  If that new capacity operates 5000 hours a year it will generate about 2.5 million tons of added carbon dioxide. 

There are several confounding factors.  The new power plants should yield less expensive power and could run more hours than the older replaced plants, meaning even higher emissions.  Some of the retiring power plants will continue to operate after the new plants start up meaning higher emissions.  Both Appalachian Power and Dominion own out of state power plants, and could shift generation out of state meaning lower Virginia emissions, but global emissions would remain the same.  The RGGI states review the program every three years and have worked to raise the allowance price each time, so it is likely allowance prices will rise in the future.  All of these factors will be ignored in favor of a conservative emission forecast adding 2.5 million tons to the 36.6 million tons emitted in 2016, for a total of 39.1 million tons in 2020.

The proposed regulation commits 5% of allowances for sale by the Department Mines Minerals and Energy with the allowance revenue to be spent on carbon dioxide reduction projects.  The Economic Impact Analysis in the proposed regulation forecasts an allowance price very close to the proposed Emissions Containment Reserve (ECR) trigger price which subtracts allowances offered in an auction if the price goes below the trigger price.  Our analysis will use the ECR trigger price as the forecast price.  An upper range would use the Cost Cap Reserve (CCR) trigger price which runs about twice the ECR trigger price.  If the CCR trigger price is exceeded extra allowances are added to the auction.  From 2013 to 2015 the CCR acted as a price signal in the auctions.

      The forecasted cost from Table 3 assumes power companies chose to simply meet the proposed regulation by buying the emission allowances they need to comply to maintain electric grid reliability.  The alternative is to write off premature closing of existing power plants, while paying premium prices for new zero, or low emission generation sources.  This is especially likely as Dominion expects demand to grow 24% by 2030, and will need the capacity.  The SCC currently allows utilities to pass on the cost of meeting environmental requirements and would likely allow the pass through of allowance costs.  This is the strategy Rhode Island followed as they were generating essentially all the electric power needed with natural gas-fired generators in 2007, and have never reduced emissions.  There is no penalty, other than allowance cost, if a state misses its RGGI target.

Table 3: Forecasted cost impact of the proposed regulation

Year	Emissions MM Tons of CO2	Emission Caps MM Tons of CO2	MM Allowances	Allowance Price - $	MM $ Cost
2020	39.1	32.3	6.8	6.00	40.8
2021	39.1	31,3	7.8	6.00	46.8
2022	39.1	30.4	8.7	6.42	55.9
2023	39.1	29.4	9.7	6.87	66.6
2024	39.1	28.4	10.7	7.35	78.6
2025	39.1	27.5	11.6	7.86	91.2
2026	39.1	26.5	12.6	8.42	106.1
2027	39.1	25.5	13.6	9.00	122.4
2028	39.1	24.5	14.6	9.63	140.6
2029	39.1	23.6	15.5	10.31	159.8
2030	39.1	22.6	16.5	11.03	182.0
Total Cost					$1091
NPV					$674

Note: 7% deflator for NPV calculation as recommended by US Office of Management & Budget

            The total Net Present Value cost through 2030 of the proposed regulation is $674 million with no offsetting benefits.  The cost would be twice that high if the CCR trigger price sends the expected price signal to the auctions, so the range of cost is $0.7 to $1.4 billion.  In 2030, the program will add $182 million, or about $20 a year to residential electric bills.  Industrial bills could easily rise by over $100,000 a year.  The proposed regulation is all pain, no gain!