Author: rogercaiazza

I am a meteorologist (BS and MS degrees), was certified as a consulting meteorologist and have worked in the air quality industry for over 40 years. I author two blogs. Environmental staff in any industry have to be pragmatic balancing risks and benefits and (https://pragmaticenvironmentalistofnewyork.blog/) reflects that outlook. The second blog addresses the New York State Reforming the Energy Vision initiative (https://reformingtheenergyvisioninconvenienttruths.wordpress.com). Any of my comments on the web or posts on my blogs are my opinion only. In no way do they reflect the position of any of my past employers or any company I was associated with.

Part 242 Comments – Background and Rationale for Revisions

For the past month or so I have been preparing comments on the New York State Department of Environmental Conservation (DEC)  proposed revisions to their Part 242 CO2 Budget Trading Program rule.  This post summarizes my Part 242 Comments addressing the background for the rule revisions and rationale used for significant rule changes.  There is a second post that addresses the Regulatory Impact Statement for the proposed rule changes.

I submitted comments because I want my family to be able to afford to continue to live in New York State.  The proposed rule is consistent with the Climate Leadership and Community Protection Act (“Climate Act”) that will necessarily affect the price of energy in New York and based on results elsewhere I believe those costs will ultimately be unacceptable.  I have written a series of posts on the feasibility, implications and consequences of the law.  I am a retired electric utility meteorologist with nearly 40 years of experience analyzing the effects of emissions on the environment.  The opinions expressed in this post do not reflect the position of any of my previous employers or any other company I have been associated with, these comments are mine alone.

Introduction

The proposed revisions to Part 242 primarily implement Regional Greenhouse Gas Initiative (RGGI) program changes set forth in the updated RGGI Model Rule.  There are several substantive changes.

The proposed Program revisions will cap regional CO2 emissions at approximately 75 million tons annually beginning in 2021 and decrease the cap by 2.275 million tons annually. There are changes to the Cost Containment Reserve (CCR) that modify the CCR trigger price and the maximum amount of CCR allowances available at auction each year. This feature puts a limit on the upper bound of costs and the proposed program revisions create an Emissions Containment Reserve (ECR), that will put a lower bound on costs.  Simply put if the price gets too high allowances are added and if the price gets too low allowances are subtracted.

The rule also includes a provision for a Third Adjustment for Banked Allowances that will adjust the budget for 100 percent of the pre-2021 vintage allowances held by market participants as of the end of 2020, that are in excess of the total quantity of 2018, 2019, and 2020 emissions. This provision is included to prevent a large allowance bank.  If the allowance bank is larger than the fourth control period emissions then they will adjust the size of the cap.

Comment Overview

For the most part the DEC proposed revisions simply implement the RGGI Model Rule and as such there is little chance for meaningful change based on comments received.  Nonetheless, because there are issues with a couple of the proposed revisions and the Regulatory Impact Statement that provides justification of the changes, I spent quite a bit of time developing comments.  The revised rule proposes to expand applicability under Part 242 to capture certain units that serve an electricity generator with a nameplate capacity equal to or greater than 15 MW and I show that the rationale used to justify this change is incorrect. RGGI recently released a guidance document that includes a schedule for the calculation of the third adjustment for banked allowances that I believe inappropriately ensures an adjustment of the allowance bank.  Finally, one of the purported benefits of this regulation is that New York’s climate leadership will entice other jurisdictions to emulate New York by setting an example.  However, the justification for these revisions provides New York citizens insufficient evidence to support the proposed changes and sets a poor example for others to follow.

 There were three components to the comments I submitted and I will discuss one in this post.  I addressed three underlying suppositions driving the proposed revisions: that RGGI has been a success and deserves to be revised, that expanding the applicability of the program to generating units greater than 15 MW but less than 25 MW is warranted, and that a binding cap is an appropriate goal.  There was a section with specific comments on the text of the regulation but I will not discuss those comments in a blog post.  A second post discusses the claims in the Regulatory Impact Statement (RIS) that were used to justify the proposed actions.

RGGI Success

The underlying premise of the proposed actions is that the Regional Greenhouse Gas Initiative has been an unqualified success and deserves to be expanded and revised.  Sprinkled throughout the RIS are statements such as: “contributing to a 50% reduction in CO2 from affected power plants in New York, it is estimated that the RGGI program provided $1.7 billion in avoided public health costs in New York by reducing associated air pollutants”.   My comments on this topic were based primarily on the many posts that I have done on RGGI.  Rather than re-hash all the background information available in my previous posts I will simply summarize the key points.

The “RGGI is a success” statements are based on a naïve comparison of emissions before and after RGGI program implementation.  I compared CO2 emissions in the nine-state RGGI region for a baseline period (2006-2008) before the start of RGGI to annual emissions since.  The total emissions have decreased from an annual average baseline of over 127 million tons prior to the program to just under 75 million tons in 2018.  This represents a 40% decrease for the RGGI region as a whole as compared to a 50% reduction in New York State CO2 emissions.  However, it is important to evaluate why the emissions decreased.  When you compare emissions by the primary fuel type burned it is obvious that emissions reductions from coal and oil generating are the primary reason why the emissions decreased.  Note that both coal and oil emissions have dropped over 80% since the baseline.  Natural gas increased but not nearly as much.

Ultimately, the only reductions from RGGI that can be directly traced to the program are the reductions that result from direct investments of the RGGI auction proceeds. Information necessary to evaluate the performance of the RGGI investments is provided in the RGGI annual Investments of Proceeds update.  In order to determine reduction efficiency, I had to sum the values in the previous reports because the most recent report only reported lifetime benefits.  In order to account for future emission reductions against historical levels the annual reduction parameter must be used.  The Accumulated Annual Regional Greenhouse Gas Initiative Benefits table lists the sum of the annual avoided CO2 emissions generated by the RGGI investments from three previous reports.  The total of the annual reductions is 2,818,775 tons while the difference between the baseline of 2006 to 2008 compared to 2017 emissions is 59,508,436 tons.  The RGGI investments are only directly responsible for less than 5% of the total observed reductions!

Expanded Applicability

The proposed revisions expand applicability under Part 242 to capture certain units that serve an electricity generator with a nameplate capacity equal to or greater than 15 megawatts (MW).  The only rationale provided is that “New York stakeholders raised concerns during the extensive outreach efforts that the cost of complying with RGGI might result in increased operation at units not subject to the regulatory provisions of Part 242, particularly at smaller units below the existing 25 megawatt (MW) applicability threshold”.

Sadly, New York State energy and environmental policy is more about optics than scientific facts.  In order to describe this proposal based on facts I believe that, at a minimum, there would be a list of affected units, an estimate of their emissions, and an evaluation of the stakeholder concern that they might run more in the future.  There is no listing of affected units and obviously no estimate of emissions.  My best guess is that there will be 69 affected units.  I estimated that emissions averaged 126,843 tons over a five-year period and that in the highest year the CO2 emissions were 163,042 tons.  That represents about a half a percent of the total NYS emissions. The rationale is not based on a quantified estimate just a “feeling” that it might happen.  In fact, elsewhere the document itself in the RIS Model Rule Policy Case Program Design Assumption description suggests that these units will run less.  The modeling results compare two cases and in the Reference Case New York is a net importer of 2,709 GWh in 2031 but New York imports more in the Model Rule Policy Case due to lower in-state generation from gas units backing off”, my emphasis added in bold.  Furthermore, the DEC promulgated rules late last year that will result in the retirement of most of these units anyway.

Binding Cap

The RIS mentions a binding cap with respect to two aspects of the proposed rule.  During the last program review the RGGI states decided to set the regional emissions cap in 2021 to 75,147,784 tons and then reduce it by 2.275 million tons per year thereafter, resulting in a total 30 percent reduction in the regional cap from 2020 to 2030.  In addition, the RGGI states included a budget adjustment for banked allowances if the allowance bank exceeded the total quantity of 2018, 2019, and 2020 emissions at the end of the fourth control period. The RIS claims this will “help create a binding cap”.

My interpretation of a cap and trade “binding cap” is that it requires emission reductions from affected sources as a result of the control program itself and not because of other factors.  During the program review process, environmental stakeholders insisted that a “binding cap” was necessary despite significant reductions.  In this instance I think there are considerations that make that a poor choice.  This topic is important enough to warrant its own post but I will briefly address my concerns here.

There is an important difference between cap and trade programs for SO2 and nitrogen oxides (NOx) emissions and cap and invest programs for GHG emissions.  In particular, there are add-on control options for SO2 and NOx whereas there isn’t any cost-effective option for CO2.  As a result, affected sources could directly control their SO2 and NOx compliance and, more importantly, the cap limit can be set based on technologically available control performance.  In RGGI and other GHG emissions programs, there are limited direct options for the affected sources and, going forward especially, compliance is  going to have to rely on indirect reductions, i.e., someone will have to build a zero-emitting plant that displaces enough output from a fossil plant so that enough allowances are available to cover the affected source requirements.  As a result, the ultimate control strategy for an emissions marketing CO2 control program is to run less and hope power is available from somebody else.

Future emission limits are based on past RGGI success but I have shown that most of the success was the result of fuel switching to a lower priced fuel.  A recent report from the Department of Energy’s Lawrence Berkeley National Laboratory, “The Impact of Wind, Solar, and Other Factors on Wholesale Power Prices: An Historical Analysis—2008 through 2017,” confirms  that emission prices have been a minor factor in wholesale electric price changes in the NYISO.  The factors that affect wholesale electric prices determine the change in costs of production which in turn govern how much a particular unit operates.  During the ten-year period of the study “falling natural gas prices were the dominant driver of overall market-wide average price drops, reducing average annual wholesale prices by $7–$53 per megawatt-hour (MWh) over the last decade”.   Note that in Figure ES-1 Impact of Wind, Solar, and Other Factors on Wholesale Power Prices from that document that the $53 per MWh reduction was for the NYISO.

There is a limit to fuel switching, New York has closed all its coal-fired power plants and I believe the fuel-oil fired power plants cannot reduce emissions any more without shutting down.  While there are still opportunities elsewhere in RGGI the fact is that there is a limit to this option.  Combine this with the fact that past RGGI investments have not been particularly effective (only responsible for 5% of the observed reductions) that means that a binding cap will be inevitable.  While there are mechanisms that are supposed to address the risk that affected sources will be unable to obtain allowances to run and have to shut down, the concern that this is uncharted territory and has risks to reliability remains.

Third Adjustment to the Allowance Bank

The RGGI model rule includes a Third Adjustment for Banked Allowances that will adjust the budget for 100 percent of the pre-2021 vintage allowances held by market participants as of the end of 2020, that are in excess of the total quantity of 2018, 2019, and 2020 emissions. That translates to: if the allowance bank is larger than the fourth control period emissions then they will adjust the size of the cap.  This provision is included to prevent a large allowance bank going forward and is directly related to the binding cap arguments.

The clear intent of the adjustment was that there should be a limit on the size of the allowance bank going forward in 2021 based on the status after the emissions through the end of 2020 were surrendered.   On April 20, 2020 RGGI quietly posted  a guidance document, RGGI Compliance: CO2 Budget Source Fact Sheet (“Fact Sheet”), that sets a schedule  in the “dates to remember” section that states the final true-up of allowance surrender for fourth control period emissions will occur on April 2, 2021.  Using that schedule, the comparison of fourth control period emissions and the allowance bank occurs before reconciliation thus ensuring the third allowance bank adjustment.

The rationale for the timeline necessary to compare the fourth control period emissions to the allowance bank on April 2, 2021 ignores reality.  According to the Fact Sheet, the states need 31 days to ensure compliance for each CO2 budget source.  The compliance test compares the certified number of allowances submitted by each affected source against the certified number of tons emitted for each CO2 budget source.  Given that the Potomac Economics Report on the Secondary Market for RGGI CO2 Allowances for Q1 2020 released on March 13, 2020 included the allowances that were deducted for 2019 interim compliance based on the March 1, 2020 compliance certification submittals there is every reason to expect that there is a report that lists the emissions and allowances so that this comparison is a trivial effort.  This mismatch in dates will artificially reduce the allowances available for auction in 2021 (and beyond) and is not consistent with the discussions surrounding banked allowance adjustments during the public review of the Model Rule.

Conclusion

I recently listened to the June 24 meeting of the New York Climate Action Council Policy in which New York’s climate leaders repeatedly expounded on the importance of science driving New York policy.  However, as the implementation of this regulation shows, it is more about rhetoric than science.  In this regulation, smaller combustion sources are to be regulated.  The hypothesis is that they will be regulated because they will run more but there is no evidence provided why that might be the case.  In fact, they don’t even describe which units will be affected and how much they emit.  If science was the driving factor the hypothesis for each rule change would be tested to prove the case for the proposed action.

Indian Point Replacement Power – Even Worse than I Thought

In April 2017 Governor Cuomo announced the closure of the Indian Point Energy Center by April 2021 and last week I updated my analysis of the effect on New York’s energy grid.  Robert Bryce, writing on the Real Clear Energy blog recently wrote about an aspect of New York wind development that I did not know about that is important relative to the replacement of Indian Point power.

In my previous blog post I noted that there has been no renewable capacity added since the announcement that Indian Point would be closed.  I believe that is a result of detailed permitting requirements that include environmental and public health impact analyses, studies regarding environmental justice and public safety, and consideration of local laws. I concluded that in the past 12 months wind projects totaling nearly 1,300 MW have been permitted and will show up as power that I presumed could be claimed for use as replacement for Indian Point.

Mr. Bryce notes that siting renewable energy projects is precipitating land-use battles that are not only about property rights and home rule but also devolve into issues with geography and class.  What was news to me was that he explains how New York is becoming “a wind-energy plantation for New England” with massive projects proposed in the state’s poorest counties.  In particular, he describes one project:

“The 126-megawatt Cassadaga Wind Project is now being built in Chautauqua County, New York’s westernmost county. The project includes 37 turbines, each standing about 500 feet high, spread over 40,000 acres (62 square miles). The project is owned by Innogy, a subsidiary of the Essen, German-based utility E.On.”

On January 18, 2018 the New York Department of Public Service published the Order Granting Certificate of Environmental Compatibility and Public Need, With Conditions which approves the application to build the facility.  Buried in this document is the following: “the output of the Facility is contracted for out-of-state purchase”.  Mr. Bryce explains that generation will be credited toward renewable goals in Massachusetts, Connecticut and Rhode Island.  He notes that in an email:

“a spokesperson for Innogy confirmed that the buyer of the power to be produced by Cassadaga ‘is a group of seven New England utilities procured through the New England Clean Energy request for proposals’ in 2016. How will the juice from New York get to New England? It won’t. Instead, the Innogy spokesperson told me that the energy produced by the turbines at Cassadaga ‘will be used to serve local energy requirements in areas surrounding the project. Export to areas outside New York would require dedicated point-to-point transmission lines’.”

As a result, the Cassadaga Wind Farm cannot be considered as part of the renewable energy that will replace the emissions-free energy produced by Indian Point.

Mr. Bryce also reviewed data published by the Department of Energy and the New England Power Pool to look the overall picture.  He found that “of the nearly 4 million megawatt-hours of wind energy produced in New York in 2018, the state exported 1.2 million megawatt-hours, or 30 percent, to New England. When the Cassadaga wind project begins operating, it will likely add another 364,000 megawatt-hours per year in renewable-energy credits to that export total”.  That means even existing renewables are unavailable to replace Indian Point electric energy.

In April 2020, Governor Cuomo initiated and rammed through the legislature the Accelerated Renewable Energy Growth and Community Benefit Act (AREGCBA) as part of the 2020-21 state budget.  This legislation is intended to ensure that renewable generation is sited in a “timely and cost-effective manner”.  It does this by preventing local communities to enact rules on renewable energy facilities or prevent them from being built.  The so-called “community benefit” portion of this provides a  Host Community Benefit that “can take the form of a bill discount or credit, or a compensatory or environmental benefit for the impacted electric utility customers”.  In my opinion, this means that the State will provide hush money payoffs to bribe those customers in the community where the renewable energy is being proposed who are not directly impacted by the renewable development to override the rights of community members who are directly impacted.

I am troubled by the entire paragraph in the Cassadaga permit application approval Order Granting Certificate of Environmental Compatibility and Public Need, With Conditions that notes that the output of the facility will be credited out-of-state:

“As the Examiners demonstrated, the goals of the State Energy Plan are not restricted to renewable electricity consumed within the state, but are also oriented toward national and international goals of reducing carbon and transforming the energy industry. For that reason, the Examiners’ finding was not changed by the fact that the output of the Facility is contracted for out-ofstate purchase. This conclusion is bolstered by the decision of the Appellate Decision in a previous Article X proceeding that production of electricity within the state is beneficial irrespective of the contract path of the output. No party took exception to the RD’s proposed findings and determinations on this issue, and we adopt them.”

As egregious as the community benefit payola scam is, the thought that the rationale used to justify renewable energy development, even if the power is not to be used in New York, could lead to a situation where the community benefit payments are paid by New York ratepayers for facilities that benefit out-of-state interests is mind-blowing.  My biggest concern about New York’s aspirational climate targets is the cost so adding costs to New Yorkers for projects that will not help meet those targets is completely unacceptable.

With respect to Indian Point replacement power, the fact that there are New York renewable facilities that should not be counted towards replacement underscores the short-sighted innumerate decision for closure.  The closure of Indian Point was not coordinated with implementation of renewable energy to replace it.  It is not clear how many renewable energy facilities operate this way because the wind energy owners consider it business confidential so the numbers are not readily available.  Finally, note that the lack of transparency also means that it is entirely possible that the renewable energy credits are being double-counted with more than one jurisdiction claiming the benefits.

Indian Point Closure Update – May 2020

In April 2017 Governor Cuomo announced the closure of the Indian Point Energy Center by April 2021. According to the Governor “the aging 2,000 megawatt nuclear power plant, located 25 miles north of New York City, has presented numerous threats to the safety of over 20 million residents and the environmental health of the area”.  In April 2020 Indian Point 2 was shutdown.  This post updates some of my previous posts on this subject.

This is a follow-up to five previous posts published between January 2017 and March 2018 on Indian Point replacement power.  The first and a subsequent update considered New York State projects that had been permitted to see if there was replacement power in the pipeline that could replace its output.  I also analyzed whether renewables and energy efficiency were a realistic alternative and concluded that approach was unlikely to succeed. I also looked at a proposal from the New York Battery and Energy Storage Technology Consortiums to use energy storage as a potential replacement for Indian Point.  I concluded that would also not likely succeed.  Finally, I reviewed the New York Independent System Operator (NYISO) response to the question about the replacement power needed to replace Indian Point’s output. 

In July 2019, at a press conference announcing the Climate Leadership and Community Protection Act (“Climate Act”) Cuomo said “The environment and climate change are the most critically important policy priorities we face – they literally will determine the future – or the lack thereof.”  Indian Point 2 (1,299 MW nameplate capacity) has an in-service date of August 1973 and Indian Point 3 (1,012 MW nameplate capacity) was placed in service in April 1976.  The 2020 NYISO Gold Book notes that the 2020 summer capability of the two units is 2,067 MW. The owner, Entergy Nuclear Operations Inc., had applied for renewal of the operating licenses in April 2007, seeking an additional 20 years of operation beyond the original expiration dates of 2013 and 2015. The Nuclear Regulatory Commission renewed the operating licenses for the Indian Point nuclear power plant, Unit 2 and Unit 3, on Sept. 17, 2018 so the units would have been able to run until 2033 and 2035, respectively.  However, under the settlement between Entergy and the state of New York announced a settlement under which Entergy closed Unit 2 by April 30, 2020 and will permanently close Unit 3 by April 30, 2021. 

New York Control Area Energy Production

In order to fully grasp the innumeracy of shutting down 2,0067 MW of CO2-emission free generation at the same time the Climate Act legislates that electricity generation in 2040 will not include any fossil-fired power, we need to look at the energy production numbers in New York.  In the following table I have extracted the energy production by fuel type numbers from the NYISO Gold Book and combined that with the operating data from Indian Point 2 and 3.

NYISO Gold Book Figure III-3:  NYCA Energy Production (GWh) by Fuel Type

  2016 2017 2018 2019
Generator Fuel Types Production Production Production Production
Gas 7,787 6,697 7,594 7,273
Oil 136 74 152 104
Gas & Oil 52,450 44,135 47,526 44,068
Coal 1,493 567 692 425
Nuclear 41,638 42,175 43,003 44,788
Pumped Storage 836 795 811 583
Hydro 26,314 29,554 29,045 30,141
Wind 3,943 4,219 3,985 4,454
Other 2,881 2,919 2,729 2,648
Solar 54 47 49 52
Total 137,532 131,183 135,585 134,536
         
Indian Point 2 6,050 8,352 8,001 8,352
Indian Point 3 9,076 6,953 8,334 8,343

While it is clear by the energy production numbers that Indian Point has a significant contribution to the state’s power production the percentages make the point even better.  The two units generated approximately 12% of all the power produced over the last four years.

NYISO Gold Book NYCA Energy Production (%) by Fuel Type

  2016 2017 2018 2019
Generator Fuel Types Production Production Production Production
Gas 5.7% 5.1% 5.6% 5.4%
Oil 0.1% 0.1% 0.1% 0.1%
Gas & Oil 38.1% 33.6% 35.1% 32.8%
Coal 1.1% 0.4% 0.5% 0.3%
Nuclear 30.3% 32.1% 31.7% 33.3%
Pumped Storage 0.6% 0.6% 0.6% 0.4%
Hydro 19.1% 22.5% 21.4% 22.4%
Wind 2.9% 3.2% 2.9% 3.3%
Other 2.1% 2.2% 2.0% 2.0%
Solar 0.0% 0.0% 0.0% 0.0%
         
Indian Point 2 4.4% 6.4% 5.9% 6.2%
Indian Point 3 6.6% 5.3% 6.1% 6.2%

New York Climate Act Energy Production Targets

The Regulatory Impact Statement for the New York Department of Environmental Conservation (DEC) proposed revisions to 6 NYCRR Part 242, “CO2 Budget Trading Program” states the following:

“Finally, the primary objective of the State’s clean energy and energy storage commitments are to combat climate change, reduce air pollution, and ensure a reliable and diverse low carbon energy supply. In January 2019 as part of the State of the State, Governor Cuomo announced the most aggressive clean energy targets in the nation under New York’s Green New Deal – a nation leading clean energy and jobs agenda. This includes a significant increase of the New York’s Clean Energy Standard where the share of the State’s electricity coming from renewable resources will go from 50 percent to 70 percent by 2030. This will be supported by several critical components:

Quadrupling New York’s offshore wind target to 9,000 megawatts by 2035, up from 2,400 megawatts by 2030.

Doubling distributed solar deployment to 6,000 megawatts by 2025, up from 3,000 megawatts by 2023.

Deploying 3,000 megawatts of energy storage.

More than doubling new large-scale land-based wind and solar resources through the Clean Energy Standard.”

Two of the critical components, offshore wind (9,000 MW) and distributed solar deployment (6,000 MW) total 12,933 more MW than Indian Point 2 and 3.  Assuming an offshore wind capacity factor of 42.5% and fixed-tilt PV solar capacity factor of 20%, then the energy produced by these components could total 33,507 GWh for offshore wind and 10,512 GWh for the distributed solar.  While that all sounds good, there are issues.  For starters, given the alleged urgency for implementing emission reductions for the Climate Act, I would think that timing the closedown until after replacement power was at least permitted would have been appropriate.  More importantly, the problem is not as much the power, it is the energy produced that is of concern as shown below.

Future Energy System Implications

Power is the rate work is performed and is described in MW while energy is the amount of work performed measured in MWh.  The Climate Act  includes a provision to outlaw the use of fossil fuels for electric generation by 2040 and another provision to reduce all fossil fuel emissions to 85% of 1990 levels by 2050 despite not having come up with a plan to change the electric system to meet the energy requirements.  I maintain that it is absolutely necessary to use historical wind and solar insolation data to determine the resources available to meet expected load when transportation and heating are electrified.  My particular concern is the inevitable winter peak periods.

In one analysis I found that there were two no wind energy output periods on 3-4 January 2018 during an intense cold snap when electric load is high as shown in the New York Off-Shore Wind Generation Estimate for 9000 MW CLCPA Off-Shore Target table.  I was surprised to see that the wind resource went to zero during a high load period not only when the winds were light on January 3 but also when a deep low pressure developed and the wind speeds exceeded 25 m/s on the very next day.  The wind generation estimate table lists the output from a single 10.2 MW wind turbine, 80 turbines in the Equinor proposed offshore wind facility and for all 9,000 MW of Cuomo’s CLCPA target for off-shore wind.  It is important to note that adding even more wind turbines still does not preclude the need for substantial energy storage.  While all the New York off-shore wind resource may not go to zero simultaneously that resource is going to be highly correlated across the available area so they all will track closely.  Keep in mind that this example winter peak period occurs at the time that solar energy is very much reduced due to length of the day, angle of the sun and potential snow covering panels.

I followed up on that analysis with an attempt to estimate how much energy storage would be required for this example winter peak.  One of the unmentioned difficulties with Li-Ion battery storage is that they can only be operated over a limited range to get them to last ten years, i.e., they must use active thermal management and cycle the battery within a restricted 54% operating range.   As shown in the Combined Energy Storage Capacity and Cost With Storage 54% Limitation table, in order to meet the 2040 no fossil-fuel requirement I estimate that the price of energy storage alone will  be $96.0 billion, and, because they still only have a lifetime of ten years they will have to be replaced in 2050 at an estimated additional cost of $80.4 billion.  The expected cost of the batteries needed for just energy storage is the sum or $176.3 billion.  

One of the critical components mentioned above is to deploy 3,000 megawatts of energy storage.  It is very frustrating that many of the forecasts for energy storage just list the power capacity.  It makes a huge difference when trying to figure out how well the energy storage will be able to handle the peak load forecasts in an all-renewable energy system.  In the absence of that information, I assumed that the 3,000 MW will have four hours of storage or 12,000 MWh.  In the example given above I estimated that much more energy storage capacity and energy would be needed – 40,926 MW with energy potential of 278,519 MWh in 2040 and 30,556 MW of battery storage with 236,667 MWh of energy potential in 2050.  The critical point is that the overview estimates to date apparently only look at annual numbers.  In order to keep the electric power on when society needs it most, winter peak load analyses have to be done. 

That is not all, unfortunately.  In an earlier post on Indian Point I pointed out I originally thought the only energy storage issue was building enough batteries to store the renewable energy for when it is needed. 

Not surprisingly, it turns out that it is more complicated than that.  PG&E recently reported on the results of a battery storage demonstration project that described how their batteries were used on the grid. The project participated in the day ahead energy market which is used to procure the majority of supply to meet that day’s predicted electric load.  The California ISO also has a real-time energy market and the battery system provided services for short-term fluctuations from the day ahead forecast.  In addition to the energy market, batteries can be used for the ancillary services of frequency regulation and spinning reserves.  Finally, the report notes that it takes more energy to charge the batteries than battery discharges.  Also note that the energy storage association has a longer list of battery technology applications.  Until such time that New York proves that renewable energy and energy storage can keep the power on when it is needed most I think we are headed blindly to a bad ending.

Capacity Change Reality

Previously (here and here), I considered New York State projects that had been permitted to see if there was replacement power in the pipeline that could replace its output.  The NYISO Gold Book also documents changes in the changes of capacity of New York generating sources since the announcement of the closure plan.  I extracted data from the Gold Books since 2017 when Cuomo announced the closure of Indian Point to see how the market has reacted to the loss of Indian Point’s carbon-free generation.  I list the 2017 and 2020 summer capacity for each generator fuel type taken directly from the Gold Book.  There are four types of changes listed in these data: deactivations when a unit is retired, additions and uprates when a new unit is added or existing unit is modified to increase capacity, reclassifications when a unit’s fuel type is changed, and ratings changes which occur based on performance testing.   The biggest change over the last three years has been the addition of new combustion turbines totaling 1,868 MW. 

NYISO Gold Book Table II-1a: 2017 to 2020 Summary of Changes in Summer Capacity (MW)

Generator 2017   Additions Reclassi- Ratings 2020
Fuel Types Capacity Deactivations & Uprates fications Changes Capacity
Gas 3,588 -4 1,124 23 -5 4,725
Oil 2,499 -33 0 0 -50 2,416
Gas & Oil 18,529 -274 744 0 231 19,230
Coal 1,011 -291 0 -23 -21 676
Nuclear 5,375 0 0 0 16 5,391
Pumped Storage 1,407 0 0 0 0 1,407
Hydro 4,251 0 0 0 -4 4,247
Wind 1,740 0 0 0 -1 1,739
Other 378 -25 0 0 5 359
Total 38,778 -627 1,868 0 171 40,191

Note that there has been no renewable capacity added over this period.  I believe that is a result of detailed permitting requirements that include environmental and public health impact analyses, studies regarding environmental justice and public safety, and consideration of local laws. In April 2020, NYS passed the Accelerated Renewable Energy Growth and Community Benefit Act (AREGCBA) as part of the 2020-21 state budget.  This legislation is intended to ensure that renewable generation is sited in a “timely and cost-effective manner”.   In any event, in the past 12 months wind projects totaling nearly 1,300 MW have been permitted and will show up on this table once construction is complete. 

Importantly, those who say that the closure of Indian Point won’t increase fossil-fired emissions are mistaken.  Because the fuel costs of existing renewable projects are essentially zero all the output of existing projects is already spoken for and no increased output to respond to Indian Point closure is possible.  Replacement renewable replacement power has to be new sources.  Nuclear and hydro are normally lower cost sources than fossil fuel sources.  As a result, the only source left source left to replace Indian Point’s lost energy are fossil plants.

The NYISO recent full 2020 summer assessment notes that despite a 506 MW decrease of the capacity margin surplus for baseline peak weather conditions, there is margin above the baseline plus needed operating reserves.  However, if extreme weather conditions occur there is no capacity margin surplus and the system may have to rely on emergency operating procedures to provide relief.  The presentation notes that 2,273 MW have been deactivated this year but that 1,177 MW of natural gas fired power has been added.  It appears that the closure of Indian Point 2 should not affect reliability this summer unless there are extraordinary conditions.

Conclusion

Governor Cuomo said “The environment and climate change are the most critically important policy priorities we face – they literally will determine the future – or the lack thereof.”  Nonetheless the hypocritical implementation of his policies suggests that there are other factors driving these initiatives.  The closure of Indian Point was not coordinated with implementation of renewable energy to replace it.  I am positive that this will result in increased CO2 emissions for some part of the more than a decade useful life of these units that has been short-circuited.  In this instance, the alleged environmental impacts of Indian Point were more of a concern than climate change.  On the other hand, there is no requirement for a cumulative environmental impact of all the renewable energy resources needed by the Climate Act.  (By the way, that is a moot point until the State actually comes up with the plan to convert the electric system completely away from fossil fuels.)  Compounding the risk that the environmental impacts of the Climate Act could be worse than the averted climate change impacts is the AREGCBA law that now circumvents the requirements for detailed site-specific requirements for environmental and public health studies now in place.  So, on one hand, environmental risks trump climate change risks but on the other hand climate change risks overrule the obvious need to consider environmental impacts of massive wind, solar, and transmission deployment.

Finally, the State will undoubtedly claim that it will be cheaper to use offshore wind, distributed solar deployment, and doubling new large-scale land-based wind and solar resources through the Clean Energy Standard than building new fossil-fired generation to replace electric energy from Indian Point 2 and 3.  However, the fact is that the renewable resources come with a hidden price tag because of the necessity of including energy storage for the periods when intermittent wind and solar are unavailable and grid services because diffuse wind and solar require transmission support.  Not only are there significant cost financial implications, the fact that no jurisdiction anywhere has successfully implemented an electric system with such a high dependency upon renewables without becoming dependent upon adjoining electric systems for support, should give the State sufficient incentive to re-consider the ambitious schedule for the aspirational targets of the Climate Act until proper feasibility and cumulative environmental impact analyses have been completed.

Carbon Free New York May 26 2020 Letter to the Governor

“Carbon Free New York” is a coalition of organizations who believe “implementing the NYISO carbon pricing proposal in a timely and efficient manner and incorporating the cost of carbon into the electricity sector, New York will align its wholesale electricity markets with its public policy objectives to decarbonize the electricity sector as set forth in the Climate Leadership Community Protection Act (CLCPA)”.  Under the heading of not letting any crisis go to waste they recently sent a letter to NY Forward Advisory Board and Governor Cuomo on Carbon Pricing For COVID-19 Economic Recovery Efforts linking the COVID pandemic and the climate change crisis and suggesting that the NYISO carbon pricing proposal will “give New York a tool to kickstart its health and economic recovery efforts”.  I disagree.  I previously explained that this coalition does not understand the ramifications of carbon pricing,

I first became involved with pollution trading programs nearly 30 years ago and have been involved in the Regional Greenhouse Gas Initiative (RGGI) carbon pricing program since it was being developed in 2003.  During that time, I analyzed effects of these programs on operations and was responsible for compliance planning and reporting.  I write about the issues related to the energy and environmental interface from the viewpoint of staff people who have to deal with implementing these programs.  I have followed the New York State Independent System Operator (NYISO) carbon pricing initiative since its inception and my work on that program is the primary basis for this summary.  I am retired now and these comments represent my personal opinions only.

Health impact link

According to the letter:

Our most vulnerable populations, such as seniors and low-income communities of color, are already disproportionately affected by climate-influenced health issues and face the most exposure to dirty air due to their proximity to fossil fuel power plants. Now, these underlying respiratory issues have allowed COVID to impact these very people with pre-existing health conditions the hardest, showing just how important reducing pollution and improving air quality are to protecting public health, especially in times of crisis. In addition to protecting public health and addressing the disastrous and irrevocable effects of climate change, we also need solutions to reboot New York’s economy in the aftermath of COVID with more than 1.9 million New Yorkers having to file for unemployment insurance claims, according to the state Labor Department.

I believe the claim that there is a link between air pollution and COVID is based on a nationwide study from Harvard T.H. Chan School of Public Health that claims that people with COVID-19 who live in U.S. regions with high levels of air pollution are more likely to die from the disease than people who live in less polluted areas.  However, the paper was not peer-reviewed and the initial claim that people in areas with high levels of pollution are 15% more likely to die was clarified on April 24: “We have revised our finding as that an increase of 1 μg/m3 in PM2.5 is associated with an 8% increase in the COVID-19 death rate.”  I recently looked at PM2.5 data in New York City and found that the latest available three-year average (2016-2018) at the Botanical Garden site in New York City is 8.1 µg/m3 which represents a 38% decrease since 2005-2007 and is 85% lower than the average of the last three years of Chinese PM2.5 annual average data.  If the Harvard health impact effects model is correct it should show significant differences in mortality between China and New York City.  Until then I am unimpressed.

Investments

The letter makes the claim that NYISO’s carbon policy will be efficient:

The attendant goals of the CLCPA are more important than ever as we begin the process of preparing for a post-COVID-19 economic recovery. NYISO’s carbon pricing plan advances these objectives by providing New York with an essential tool to restart the economy and build it back cleaner and stronger than ever. Pricing the social cost of carbon within New York’s electricity markets will align our environmental and public health interests––while simultaneously jump-starting the economy at a very timely moment.

In tandem with New York’s broad CLCPA implementation, NYISO’s carbon pricing proposal will support investments in green jobs and accelerate the build-out of renewable energy infrastructure, putting thousands back to work while safeguarding the health of our environment. At a time when the state has limited resources, carbon pricing offers a consistent mechanism to incentivize carbon-free energy production and clean energy job creation and business growth. Leveraging the power of markets, NYISO’s carbon pricing proposal ensures the most efficient utilization of public resources to achieve the CLCPA goals.

In my previous post on Carbon Free New York I showed that New York’s investments are anything but efficient.  Historical results show that making investments at a cost per ton less than the social cost of carbon metric that is supposed to estimate the future damage cost impacts of a ton of CO2 emitted today is difficult even when the tax proceeds are directly invested.  According to the letter, the NYISO carbon pricing proposal will “charge those who produce carbon-intensive electricity and reward those who produce carbon-free electricity”.  In other words, reductions in carbon-intensive electricity will occur indirectly.  Moreover, rewarding the coalition members for their carbon-free electricity is another term for a windfall profit on top of all the other subsidies they already receive.

Reality

The letter justifies the need for bold leadership by making the following claim:

New York accounts for one out of every 230 tons of energy-related carbon dioxide (CO2) emitted anywhere in the world. With the CLCPA’s mandate to achieve carbon-free electricity by 2040, 70 percent renewable generation by 2030 and a net-zero carbon economy by 2050, incorporating the social cost of carbon into New York’s energy markets is the most efficient and affordable approach to reaching these goals, while protecting public health and rebuilding the state’s green economy. This is a moment for bold leadership.

Frankly, that number caught my attention because it seemed like a bigger fraction that I expected.  I checked out the data and found that the number was reasonable -my estimates were that New York has an even bigger contribution.  However, there is more to the story.  The New York State Energy Development Authority (NYSERDA) Greenhouse Gas Inventory 1990-2016 report contains a detailed inventory of historical greenhouse gas emission data from 1990-2016 for New York State’s energy and non-energy sectors.  I found global energy sector CO2 emissions data for 1990 to 2019 at the International Energy Agency (IEA). In the New York Energy-Related CO2 Emissions Relative to the World’s CO2 Emissions table I combined NYSERDA data and IEA for common years to estimate how New York emissions were accounted for since 1990.  The NYSERDA summary lists energy-related GHG emissions that include CH4 and N2O.  In order to directly compare with the IEA CO2 data, I assumed that the fraction of CO2 in the total GHG emissions would equal the average of the 2015 and 2016 data I had on hand.  EIA lists their data in Gt and NYSERDA in MMt.  I list the EIA data for two categories, advanced economies and the rest of the world and then total them and covert to MMt.  The NYS tons out of every global ton simply is the Global total divided by the NYS total.  In 2016 this methodology predicts that in 2016 New York accounted for one out of every 191 tons of energy-related CO2 emitted anywhere in the world.  Close enough to the letter’s number for this application.

There are two aspects of the trend of the energy-related CO2 emissions numbers that have to be addressed.  Between 1990 and 2016 NYS emissions dropped 17%, global advanced economies emissions increased 3%, global rest of the world economies emissions increased 124%, and global total energy-related CO2 emissions increased 57%.  Clearly world-wide emissions are increasing because many countries are using more energy.  While some may decry that, the fact is that World Bank World Development Indicators over this time frame show that the world has become healthier and wealthier. The World Development Indicators table lists selected parameters. The world mortality rate, for children under five dropped from 93.2 to 38.6 (per 1,000 live births) between 1990 and 2018.  The life expectancy at birth increased from 58.1 to 61.2 total years between 1990 and 2018.  The world’s PM2.5 mean annual exposure dropped 1.1 (µg/m3) between 1990 and 2017.  Finally, the world’s gross domestic product increased from $8.8 billion to $31 billion.

The trend in New York State emission sources is another aspect of note.  Table A-1. GHG Emissions by Sector, in Patterns and Trends – New York State Energy Profiles: 2002-2016,  lists emission reductions from 1990 to 2016.  Overall GHG emissions have dropped 18.5%, 37.9 MMt.  Four sectors have reduced emissions: the residential sector is down 9.8% or 3.4 MMt, the commercial sector is down 22.2% or 5.9 MMt, the industrial sector is down 48.9% or 9.8 MMt and electric generation is down 56% or 35.3 MMt.  On the other hand, transportation has increased 24.2% or 14.4 MMt and imported electricity has increased 120% albeit only 2.1 MMt.

The letter claims “this is a time for bold leadership”.  I believe that the industrial emissions have gone down because manufacturing in New York is shutting down and in my previous post on this coalition I explained that electric sector emissions have gone down mainly because of fuel switching to natural gas.  State “leadership” had nothing to do with historical reductions and it can be argued relative to natural gas that they occurred despite Cuomo’s “leadership”.  Natural gas became the cheaper fuel alternative because of fracking technological improvements but the State has banned that technology.

 Conclusion

I believe that there is a tendency for those who do not have a strong case to argue louder.   In my first post  I charitably argued that the coalition just did not understand carbon pricing.  The hyperbole and exaggerations in this letter suggest that they are aware that the case for a carbon pricing scheme in a single sector in a limited area is tenuous at best, despite the attractiveness of the theory.  This letter raises the ante and invokes a tenuous link between the real problem of COVID-19 and the NYISO carbon pricing proposal.

The fact is that New York State is in trouble because of the economic consequences of the COVID-19 response and it is not clear we can afford the cost of this program.  The proposed carbon pricing scheme increases the cost of electricity by incorporating the social cost of carbon.  Generators who emit carbon dioxide will pay that cost and those revenues are supposed to be returned to consumers.  However, the carbon price will increase the prices paid to the members of the Carbon Free New York coalition and that money will not be returned to the consumer.  It is supposed to “support investments in green jobs and accelerate the build-out of renewable energy infrastructure, putting thousands back to work while safeguarding the health of our environment”.  Cynic that I am, I doubt that much of the additional profits made by the coalition will actually be invested as they claim.

My work has shown that carbon pricing proposals have practical limitations and that if you want to reduce emissions direct investments are more effective.  Nothing in the letter or on the Carbon Free New York website prove otherwise.

 

 

Carbon Free New York

I have to give credit to the supporters for NYISO carbon pricing proposal.  They are pulling out all the stops.  The latest is a coalition of like-minding organizations named “Carbon Free New York” who believe “implementing the NYISO carbon pricing proposal in a timely and efficient manner and incorporating the cost of carbon into the electricity sector, New York will align its wholesale electricity markets with its public policy objectives to decarbonize the electricity sector as set forth in the Climate Leadership Community Protection Act (CLCPA)”.  I seriously doubt that any of these organizations really understand the ramifications of carbon pricing.

I first became involved with pollution trading programs nearly 30 years ago and have been involved in the Regional Greenhouse Gas Initiative (RGGI) carbon pricing program since it was being developed in 2003.  During that time, I analyzed effects of these programs on operations and was responsible for compliance planning and reporting.  I write about the issues related to the energy and environmental interface from the viewpoint of staff people who have to deal with implementing these programs.  I have followed the New York State Independent System Operator (NYISO) carbon pricing initiative since its inception and my work on that program is the primary basis for this summary.

 Carbon Pricing

In a post at Watts Up With That, Carbon Pricing is a Practical Dead End,  I noted that carbon pricing proponents have convinced themselves that somehow this is different than a tax but, in my experience working with affected sources, it is treated just like a tax.  As a result, the over-riding problem with carbon pricing is that it is a regressive tax.  In that article, I described a number of other practical reasons that cap-and-invest carbon pricing or any variation thereof will not work as theorized: leakage, revenues over time, theory vs. reality, market signal inefficiency, control options, total costs of alternatives, and implementation logistics.  In addition, The Regulatory Analysis Project (RAP) recently completed a study for Vermont, Economic Benefits and Energy Savings through Low-Cost Carbon Management, that raises additional relevant concerns about carbon pricing implementation.

Because the primary focus of Carbon Free New York is the NYISO carbon pricing initiative I think it is appropriate to consider the cost-effectiveness of New York’s carbon reduction investments to date.  The Social Cost of Carbon (SCC) is supposed to represent the future cost impact to society of a ton of CO2 emitted today.  Therefore, it is entirely fair to use it as a metric to determine if the investments made from carbon pricing income are cost effectively reducing CO2.  I believe that the NYISO will base their carbon pricing on a $50 global social cost of carbon at a 3% discount rate so that is the cost benefit effectiveness threshold metric I will use.

The fundamental assumption for any carbon pricing program is that the proceeds can be invested effectively.  However, the observed results for New York’s experience in RGGI suggests that this may not be the case.  The New York State Energy Research and Development Authority (NYSERDA) report New York’s RGGI-Funded Programs Status Report – Semiannual Report through December 31, 2018 (“Status Report”) describes how New York invested the proceeds from the RGGI auctions.  The NYSERDA RGGI Status Report Table 2 – Ranked Cost Benefit Ratio Data table lists all the programs in the NYSERDA report ranked by the annual cost benefit ratio with just that parameter.  It lists 19 programs with associated CO2 reduction benefits and another 18 programs with no claimed CO2 reductions.  None of the 19 programs with CO2 reduction benefits meets the $50 SCC metric for cost effective investments.  Clearly the 18 programs with no claimed reductions would not be able to meet the metric either.

New York’s Existing Carbon Pricing Program

Advocates for carbon pricing programs often point to the success of RGGI, New York’s existing carbon pricing program.  I looked into those claims in an article published at Whats Up with That  and in a more detailed article on this website.

RGGI supporters who claim it is successful point to emission reductions of 40 to 50%.  However, when I looked at the changes in generation mix it is obvious that emissions reductions from coal and oil generating are the primary reason why the emissions decreased.  Both coal and oil emissions have dropped over 80% since the beginning of the program.  I believe that the fuel switch from coal and oil to natural gas occurred because natural gas was the cheaper fuel and had very little to do with RGGI because the CO2 allowance cost adder to the plant’s operating costs was relatively small.   There is no evidence that any affected source in RGGI installed add-on controls to reduce their CO2 emissions.  The only other option at a power plant is to become more efficient and burn less fuel.  However, because fuel costs are the biggest driver for operational costs that means efficiency projects to reduce fuel use means have always been considered by these sources.   Because the cost adder of the RGGI carbon price was relatively small I do not believe that any affected source installed an efficiency project as part of its RGGI compliance strategy.

As a result, the only reductions from RGGI that can be traced to the program are the reductions that result from direct investments of the RGGI auction proceeds. Information necessary to evaluate the performance of the RGGI investments is provided in the RGGI annual Investments of Proceeds update.  In order to determine reduction efficiency, I had to sum the values in the previous reports because the most recent report only reported lifetime benefits.  In order to account for future emission reductions against historical levels the annual reduction parameter must be used.  The Accumulated Annual Regional Greenhouse Gas Initiative Benefits table lists the sum of the annual avoided CO2 emissions generated by the RGGI investments from three previous reports.  The total of the annual reductions is 2,818,775 tons while the difference between the baseline of 2006 to 2008 compared to 2017 emissions is 59,508,436 tons.  The RGGI investments are only directly responsible for less than 5% of the total observed reductions!

Conclusion

While I do not dispute that the theory of a comprehensive, global carbon pricing may be a great mechanism for reducing GHG emissions, advocates for the programs overlook logistical and practical concerns when plans for limited area, one-sector pricing schemes are proposed.  Trying to force fit this global theory into just the New York electricity market is an extraordinarily difficult problem.  As proposed, the NYISO carbon pricing proposal will likely result in power leakage where energy and emissions are not reduced but simply shift emissions associated with power production out of the state within the inter-connected electric grid.

Advocates for carbon pricing schemes also assume that the investments from the proceeds are worthwhile, but I have found that is not the case. The indirect price signal appears to be too weak to cause meaningful reductions.  Investment decisions also matter.  The Regulatory Analysis Project (RAP) study: Economic Benefits and Energy Savings through Low-Cost Carbon Management notes that “Many advocates of carbon pricing begin with the proposition that the main point is to charge for carbon emissions “appropriately” and that carbon reductions will surely follow in the most efficient manner. While carbon pricing is a useful tool in the fight against climate change, there is now substantial experience to suggest that wise use of the resulting carbon revenues is equally important, or even more important, if the goal is to actually reduce emissions at the lowest reasonable cost.”

PM2.5 Health Impacts in New York City

In the last several days I have been drafting a review of  the PEAK Coalition report entitled: “Dirty Energy, Big Money” and today I was working on the air quality health impacts section.  I also noticed today that the usual suspects are claiming links between air pollution and Covid-19 susceptibility. In this post I will explain how I could be convinced that the reports underlying presumption that inhalable particulates have dire health impacts is correct.

I am a retired electric utility meteorologist with nearly 40 years-experience analyzing the effects of air quality and meteorology on electric operations.  I have been reviewed health impact claims throughout my career.  This background served me well preparing this post.  The opinions expressed in this post do not reflect the position of any of my previous employers or any other company I have been associated with, these comments are mine alone.

Background

Health impacts associated with inhalable particulates, also known as PM2.5 because it refers to airborne particles with a diameter of 2.5 micrometers or less, turn out to be the primary rationale for all the recent EPA air quality emission reductions cost-benefit analyses.  For example, EPA’s air toxics emission limits were cost effective not because of direct impacts of mercury and other heavy metals but because the control systems for those pollutants would have decreased PM2.5 concentrations and led to alleged health improvements.

Steve Milloy’s Scare Pollution: Why and How to Fix the EPA explains the problems with those health impact claims.  Milloy points out that no one has proven a biological explanation why the inhaled particles will cause fatal inflammation.  The alleged relationship is based on epidemiological statistical evaluation of air quality and health impact data.  The basic problem is that there are many confounding factors known to cause the observed health impacts and trying to tease air quality impacts out of the mix is difficult to prove.

It gets worse.  The studies that are the basis for the alleged air quality health impacts were at relatively high ambient concentrations.  Make no mistake that air pollution can be a very bad thing but the levels of pollution in the United States that clearly caused health impacts occurred many years ago and included a mix of pollutants not found anywhere in this country today.  It gets worse because the dose-health impact relationship is being extrapolated using the linear no-threshold model which has been used to estimate the dose response for radiation health impacts.  The concept is that there is no threshold below which there is no effect.  However, in my opinion and others, extrapolating measurements and responses at high levels down to levels near the level of detection is an unwarranted presumption.  Nonetheless, advocates for ever lower air quality improvements routinely claim health impacts behave the same way.

Public Health Impacts

The primary public health reference in the PEAK Coalition report I am reviewing was the New York City Department of Health and Mental Hygiene’s (DOHMH) Air Pollution and the Health of New Yorkers report.  The PEAK coalition description of air quality public health impacts quotes the conclusion from the DOHMOH report: “Each year, PM2.5 pollution in [New York City] causes more than 3,000 deaths, 2,000 hospital admissions for lung and heart conditions, and approximately 6,000 emergency department visits for asthma in children and adults.”  These conclusions are for average air pollution levels in New York City as a whole over the period 2005-2007.

The DOHMOH report specified four scenarios for comparisons (DOHMOH Figure 4) and calculated health events that it attributed to citywide PM2.5 (DOHMOH Table 5).  Based on their results the report notes that:

Even a feasible, modest reduction (10%) in PM2.5 concentrations could prevent more than 300 premature deaths, 200 hospital admissions and 600 emergency department visits. Achieving the PlaNYC goal of “cleanest air of any big city” would result in even more substantial public health benefits.

It is important to note how air quality has improved since the time of this analysis.  The NYS DEC air quality monitoring system has operated a PM2.5 monitor at the Botanical Garden in New York city since 1999 so I compared the data from that site for the same period as this analysis relative to the most recent data available (Data from Figure 4. Baseline annual average PM2.5 levels in New York City). The Botanical Garden site had an annual average PM2.5 level of 13 µg/m3 for the same period as the report’s 13.9 µg/m3 “current conditions” city-wide average (my estimate based on their graph).  The important thing to note is that the latest available average (2016-2018) for a comparable three-year average at the Botanical Garden is 8.1 µg/m3 which represents a 38% decrease.  That is substantially lower than the PlaNYC goal of “cleanest air of any big city” scenario at an estimated city-wide average of 10.9 µg/m3.

Note that in DOHMOH Table 5 the annual health events for the 10% reduction and “cleanest” city scenarios are shown as changes not as the total number of events listed for the current levels scenario.  My modified table (Modified Table 5. Annual health events attributable to citywide PM2 5 level) converts those estimates to totals so that the numbers are directly comparable.  I excluded the confidence interval information because I don’t know how to convert them in this instance.

I confirmed that the DOHMOH analysis used a linear no-threshold health impact analysis and used their relationship to estimate the effect of the observed air quality reduction. I tested the linear hypothesis by scaling the “current level” scenario number of events to the proportion of the PM 2.5 concentrations (the last row in the table) for the “current level” and the other two scenarios.  My estimated health impacts were all within 1% which proves that the DOHMOH analysis relied on a linear no-threshold approach.  As a result, that means that I could estimate the health impact improvements due to the observed reductions in PM2.5 as shown in the last three columns in the modified table.  I estimate that the observed reduction in PM2.5 concentrations prevented nearly 1,300 premature deaths, 800 hospital admissions and 2400 emergency department visits.

Conclusion

In order to convince me that the PM2.5 health impacts claimed by MOHDOH and many others are correct I need to see confirmation with observed data.  The DOHMOH report claims that in 2005-2007 that PM2.5 concentrations led to, for example, 3,200 premature mortality events.  I have no idea how that number compares to observed values for this parameter or the others included.  I estimate that for the observed reductions in measured PM2.5 the number of premature mortality events would be reduced 1,296 events down to 1,904 events.

The first question for the health experts is whether the change from 2005-2007 to 2016-2018 of 1,296 events could be observed against natural variations or is that number within the normally expected variation.  If not then my hope for verification is not possible but more importantly it also means that the gloom and doom stories of significant health impacts are base on nothing more than insignificant statistical noise that is not really observable.  If those data are greater than expected natural variation, then it would be possible to document improvements in these alleged health impacts due to the 38% decrease in PM2.5.  If that is the case, then I stand corrected.

Here is the thing though.  The percentage of people with asthma in the United States from 2001 to 2018 is not showing a decrease at the same time ambient levels of all air pollutants are going down substantially.  While correlation does not necessarily mean causation, no correlation with a purported cause indicates a bet on a dead horse.  Therefore, I am not holding my breath that the data will show the purported benefits.

CLCPA NYS Wind Energy Resource

New York has established energy policy based on conceptions that do not hold up to numerate scrutiny.  This post addresses the idea that New York wind energy can reliably power the electric system and in tandem with solar energy can replace existing generating resources.  In order for the statewide wind energy resource to be considered a reliable source the distribution of wind energy must not include significant periods with low power output.

In the summer of 2019 the Governor Cuomo and the New York State Legislature passed the Climate Leadership and Community Protection Act (CLCPA) which was described as the most ambitious and comprehensive climate and clean energy legislation in the country when Cuomo signed the legislation.  The Citizens Budget Commission developed an overview of the CLCPA targets in Green in Perspective: 6 Facts to Help New Yorkers Understand the Climate Leadership and Community Protection Act.

The legislation requires 70% of the generation supplying New York to be renewable in 2030, statewide emissions of greenhouse gas emissions are to be reduced to 60% of 1990 emissions and elimination of fossil-fired electricity production altogether by 2040.  Unfortunately, the politicians that passed this law never bothered to figure out how it could be done.  I have written a series of posts on the feasibility, implications and consequences of this aspect of the law based on evaluation of data.  This post addresses the wind energy resource of New York.

Approach

I used two sources of data from New York Independent System Operator (NYISO).  For an overview I used the annual report that presents load and capacity data including historical and forecast seasonal peak demand, energy usage, and existing and proposed generation and transmission facilities.  The Load and Capacity Date Report or Gold Book is a featured report in the NYISO document library.  This post and a summary I posted in April 2019 use data in Table III-2 Existing Generating Facilities from those reports to describe the annual wind energy resources available.  I used the 2019 wind date from the April 2020 Gold book in this analysis.  Note that in 2019 all wind energy came from on-shore facilities.

The NYISO Real-Time Dashboard includes a window for the real-time fuel mix that includes the amount of wind generation being generated in the state.  The window also includes a link to historical data.  I downloaded data from June 2018 through September 2019, sorted out the wind production numbers, and then calculated hourly averages.  I use Statgraphics Centurion software from StatPoint Technologies, Inc. to do my statistical analyses and in this case I loaded the hourly data and calculated frequency distribution statistics.

Results

The New York State Wind Facility Status table lists 2019 wind data from the NYISO 2020 Gold Book for all the New York wind energy facilities.  The NYISO table provides the name plate ratings and 2019 net energy produced.  In 2018 there were 1,982 MW of wind energy nameplate capacity that generated 3,985 GWh of electrical energy for a state-wide annual capacity factor of 24.5%.  Note that there is a wide variation of capacity factors, that the highest is 37.4%.  All the capacity factors greater than 30% are from more recent larger turbines. The Chateaugay Wind Power facility and the Jericho Rise Wind Farm are in the same general area so I expect that the wind resource would be similar.  In 2019 the Chateaugay capacity factor was 21.1% and the Jericho Rise capacity factor was 33.4%.  I believe the main reason for the difference is the size of the turbines – the blade tip height for Jericho Rise is 18.5m (60.7 ft) higher than at Chateaugay. The Chateaugay turbines have a hub height of 80m and a rotor diameter of 77m while the Jericho Rise turbines have a hub height of 80m and a rotor diameter of 114m.  Overall, New York wind facilities only provide a quarter of their name plate capacity.

Another wind-resource issue is the distribution of the hourly output.  The NYS Hourly Wind Frequency Statistics June 2018 through September 2019 document lists frequency distribution data for sixteen months of operations in New York.  The histogram of wind output categories shows that low output is more frequent than high output.  The frequency tabulation for wind table shows that there were 25 hours when none of the 24 wind facilities in the state produced any power and that 36% of the time less than 200 MW per hour was produced.  The probability plot graphically shows the skewed distribution and the percentiles indicate that half the time hourly wind output is less than 324 MW.

If New York has to rely on renewable energy in the future it is important to know the frequency distribution of wind at night.  I addressed this by simply looking only at four hours either side of midnight.  The NYS Night Hourly Wind Frequency Statistics June 2018 through September 2019 document lists the same statistics for this limited data set.  While there are only a couple of hours with no wind output and the frequency of hours with output less than 200 MW was down to 31% there still is a significant number of hours when the lack of solar and low wind output.  That means that energy storage is going to be absolutely necessary.

Another aspect of concern is the duration of low wind periods.  I used the same data format as the wind frequency statistics but only included 2018 data to determine how long light periods lasted – a critical parameter when it comes time to try to rely on wind energy to provide reliable power.  I calculated the length of time the total NYS wind energy resource failed to exceed various thresholds from 100 MW to 600 MW.  The 2018 Total NYS Wind Energy Light Wind Energy Periodss table lists the longest calm periods for each threshold.  For example, the longest period when less than 100 MW of the state’s total wind capacity of 1,982 MW was 58 hours ending on 9/13/2018 at 1800.  In the second section of the table frequencies are listed.  There were 12 periods when less than 100 MW of wind capacity was available for 24 hours, 5 periods for 36 hours, and one period of 48 hours.

Conclusions

Annual capacity factors average 25%.  All the turbines with capacity factors greater than 30% are using turbines that with tip heights greater than 425 ft.  Although that improves performance it also means that there are greater environmental impacts.  I believe we cannot expect much improvement for future on-shore wind development simply because I assume that the best locations have already been developed.

The distribution of hourly wind output was a mild surprise to me because  I did not think it would be as bad as it is.  Advocates for renewable power maintain that it is possible to address the problem of calm winds at one location by simply adding facilities in other locations so that somewhere the wind will be blowing.  If that were the case using New York resources the hourly distribution would not show that 5% of the time the total wind energy production for the entire state was less than 20 MW.  Furthermore, I suspect that even expanding the location of wind facilities to off-shore New York and adjoining jurisdictions is not going to significantly reduce the number of hours when wind resources are going to have to be supported by significant amounts of energy storage.

The fact that night time wind generation also shows significant hours with low levels exacerbates the need for energy storage.  In an earlier post I estimated how much energy storage would be needed for one example period.  These results reinforce my position that New York State has to do a comprehensive analysis of the availability of renewable resources to determine a strategy for meeting demand with an all-renewable system.  Until that is complete we are only guessing whether the ambitious goals of the CLCPA can be met much less how much this is all going to cost.

My Additional Comments on NESE Pipeline Alternatives

The Northeast Supply Enhancement (NESE) pipeline is a proposed pipeline to bring natural gas to New York City and Long Island.  This post documents additional comments I have submitted in a New York Department of Public Service proceeding related to denial of service requests by National Grid in New York City and Long Island which is associated with the project.

In NESE Pipeline Alternatives for National Grid I included an overview of the proceeding and described my comments.  Since then I submitted three additional comments addressing particular aspects of comments submitted by others.  Opponents of the pipeline alternative that claim that additional energy efficiency efforts can eliminate the need for a pipeline. The Eastern Environmental Law Center submitted a report to the docket by Synapse Energy Economics entitled “Assessment of National Grid’s Long-Term Capacity Report: Natural gas capacity needs and alternatives” on April 14, 2020.  Several commenters suggested that “climate realities” mean that the current criteria for the coldest day can be revised.

Energy Efficiency Performance Comments

I do not dispute that the theory that investments in energy efficiency will reduce the need for additional generating resources is a good idea because there is no benign way to generate electricity.  Nor do I dispute that New York has a good energy efficiency record.  However, I don’t think that past performance is necessarily an indicator of future results simply because the easiest and most effective, aka low hanging fruit, energy efficiency projects have already been implemented.  Any future reductions will not be as cheap or effective.

The comments I submitted attempted to determine how well the existing energy efficiency programs have been doing.  Supporters of increased energy efficiency claim that energy growth is decreasing and increased investments will reduce growth even more.  There is a fundamental problem when evaluating energy efficiency, namely it is difficult to compare different time periods because energy use is not just a function of how efficiently it is used but also varies because of weather, the economy. and number of customers.  In order to address that I used the average natural gas use per customer averaged over the latest five-year period of data compared to the previous five years of data.  I found that residential, commercial, and industrial use per customer all went up over the ten-year period for the state as a whole and residential and commercial use per customer went up in New York City and Long Island.

I concluded that in order to justify National Grid’s high-demand (80% of future efficiency targets) and a low-demand scenario (100% of future efficiency targets) bounds to their analysis and the feasibility of the no-infrastructure project option for incremental energy efficiency that the fact that energy use per customer has been going up has to be reconciled.  If the Public Service Commission ultimately requires National Grid to include the incremental energy efficiency project as part of the solution, then it is up to them to show why the future results will differ from the recent past.

Synapse Report Comments

The Eastern Environmental Law Center submitted a report to the docket by Synapse Energy Economics entitled “Assessment of National Grid’s Long-Term Capacity Report: Natural gas capacity needs and alternatives” on April 14, 2020.  The report concludes: the supply gap most likely does not exist, National Grid has multiple cost-effective demand-side options to meet any foreseeable need, and National Grid’s analysis of long-term capacity options is not compatible with New York’s climate change policies.

The comments on the supply gap primarily addressed purported problems with the worst case (design day) which I address below.  They also complained that National Grid should try to maintain the number of customers who are willing and able to shift from natural gas to other sources of energy.  This disregards the fact that the most used alternative source is fuel oil which New York City is in the middle of prohibiting so they cannot keep those customers.

The Synapse report claims that National Grid has multiple cost-effective demand-side options to meet any foreseeable need including energy efficiency, demand response, and alternative energy systems such as heat pumps. As described previously there are issues with energy efficiency that Synapse ignores.  Demand response advocates assume that the load shifting opportunities available in the summer will also be available in the winter.  I argued that when 85% of your load is heating and the diurnal heating load cycle does not vary as much as the summer cooling cycle, how can you shift the load?  As a result, I believe that a demand response should not be considered a viable alternative to a proven technology for winter heating.  Alternative heating systems are electrified systems.  Air source heat pumps are touted as a viable alternative to natural gas furnace but when the temperature drops below 20° Fahrenheit there simply is not enough energy available for this technology to work.  Ground source heat pumps don’t have that problem but are difficult to retrofit anywhere and have siting demands that are likely not achievable in New York City.

The Synapse report concludes that National Grid’s analysis of long-term capacity options is not compatible with New York’s climate change policies.  In a rational world New York’s plan to implement the Climate Leadership and Community Protection Act would be available to determine compatibility but there is no plan now and one will not be available for several years.  Because the timing for the state plan is incompatible with the needs of this project and the State has yet to show that an electric system that relies only on non-fossil fueled sources can meet that peak load condition I concluded that National Grid cannot afford to wait to integrate their plan with the CLCPA plan.

Design Day Criteria Comments

I submitted this comment because other comments submitted recommend changing the design day criteria and downplay future energy needs during the worst-case cold weather periods based on “climate realities”.  I showed that when you look beyond the superficial and mis-represented IPCC science it becomes clear that climate model results and even the current observed trend of local temperatures are no reason to conclude that warmer temperatures are inevitable.  Poorly understood natural variation is as likely to be the primary driver of temperature as GHG concentrations.  Unfortunately, natural variation and climate modeling estimates of the future are very uncertain.  Therefore, I argued that it is inappropriate to change the design day criteria and that using the entire period of record for temperatures to determine the design day is the most appropriate approach.

Conclusion

“It is hard to imagine a more stupid or more dangerous way of making decisions than by putting those decisions in the hands of people who pay no price for being wrong”, Thomas Sowell.

Unfortunately, New York State energy policy appears to be driven by the mis-informed and innumerate squeaky wheels who respond to the request for comments with a veritable flood of responses.  Moreover, the bullying tactics of the Governor coupled with his micro-management of all decisions to cater to the aforementioned squeaky wheels that represent a political base he apparently counts on means that professional opinions of all companies in the state and agency staff are not considered.  Sowell’s comment portends bad things happening for New York energy policy in general and this proceeding in particular.

In my comments I showed that the fact that cold snaps are dangerous to health requires a plan that ensures adequate energy is available is necessary.  The theory that energy efficiency, demand response and electrification can actually provide the energy necessary should be considered relative to the real world.  Coupling those aspirational efforts with a lack of understanding about climate and climate change projections are a recipe for unanticipated problems and unintended consequences.

I urged the Public Service Commission to choose the Northeast Supply Enhancement pipeline and the other pipeline distribute infrastructure projects based on my evaluation of the alternatives. The other proposed solutions are based on theory and not proven results.  I believe it is in the best interests of New York to implement a proven technology solution for current and future heating requirements as soon as possible. 

RGGI Leakage

In November 2019 the Regional Greenhouse Gas Initiative (RGGI) released their annual RGGI electricity marketing report.  I have not been following this annual report but have been looking at emissions leakage and realized that it is supposed to address RGGI leakage.

I have been involved in the RGGI program process since its inception.  I blog about the details of the RGGI program because very few seem to want to provide any criticisms of the program. The opinions expressed in this post do not reflect the position of any of my previous employers or any other company I have been associated with, these comments are mine alone.

Emissions Leakage

Emissions leakage refers to the situation where a pollution reduction policy simply moves the pollution around geographically rather than actually reducing it.  Ideally if you want to solve global warming with a carbon price then you want to apply it to all sectors across the globe so that it cannot occur.  In general, I don’t think a global carbon pricing scheme is ever going to happen because of the tradeoff between the benefits which are all long term versus the costs which are mostly short term.  I don’t see how anyone could ever come up with a pricing scheme that equitably addresses the gulf between the energy abundant “haves” and those who don’t have access to reliable energy such that “have nots” will be willing to pay more (as carbon taxes) as they catch up with those who have abundant energy.

 

Despite this potential problem, carbon pricing schemes including the RGGI cap and auction program have been implemented in small jurisdictions.  When RGGI was being developed emissions leakage was a big concern.  In March 2007, the Emissions Leakage Staff Working Group submitted a report: Potential Emissions Leakage and the Regional Greenhouse Gas Initiative (RGGI): Evaluating Market Dynamics, Monitoring Options, and Possible Mitigation Mechanisms.  The report noted that “Under a “middle-of-the-road” scenario, cumulative emissions leakage was estimated at 27% of net CO2 emissions reductions through 2015” but “Projected emissions leakage is predominantly in the form of a shift in the location of new natural gas-fired power plant builds, rather than decreased utilization of existing plants”. In an independent analysis, Kolodziej and Wing (2008) used theoretical and numerical general equilibrium models to evaluate potential leakage and concluded that “Although RGGI’s economic impacts are small, they induce substantial increases in power exports from unconstrained states which result in emission leakage rates of more than 50%”.

The 2007 Emissions Leakage Staff Working Group report recommended that “for the purpose of quantifying and determining the extent of potential emissions leakage, ensuring that leakage does not undermine the emissions reductions achieved by the program, and supporting RGGI’s goals of monitoring emissions leakage, it is essential to be able to track and verify the environmental attributes associated with all the power being generated and used within the RGGI region, as well as the environmental attributes of power generated in adjoining regions”.  The emissions page in the allowance tracking category of the RGGI website notes “As part of RGGI’s program design process, the participating states determined that regular reports would be made to monitor and track power generation serving load in the RGGI region, as well as the emissions associated with that generation.”

RGGI Leakage

I believe that the RGGI electricity marketing reports represent the commitment to track leakage.  They summarize data for electricity generation, net electricity imports, and related carbon dioxide (CO2) emissions for the states in RGGI.  One metric presented could “provide a preliminary or potential indication of emissions leakage, or a lack thereof”.  However, there is a caveat: “because this report does not establish the causes of observed trends, it should be emphasized that this report does not provide indicators of CO2 emissions leakage”.

The most recent report, CO2 Emissions from Electricity Generation and Imports in the Regional Greenhouse Gas Initiative: 2017 Monitoring Report, states that:

Annual average net electricity imports into the nine-state RGGI region increased by 22.2 million MWh, or 39.6 percent, during the 2015 to 2017 annual average compared to the 2006 to 2008 base period. CO2 emissions related to these net electricity imports decreased by 2.3 million short tons, or 9.1 percent, during this period, indicating a reduction in the average CO2 emission rate of the electric generation supplying these imports of 317.0 lb CO2/MWh, a reduction of 35.0 percent.

Compared to the annual average during the 2006 to 2008 base period, 2017 electric generation from RGGI generation decreased by 54.6 million MWh, or 31.7 percent, and CO2 emissions from RGGI generation decreased by 73.9 million short tons of CO2, or 53.4 percent. The CO2 emission rate of RGGI electric generation decreased by 509.4 lb CO2/MWh, a reduction of 31.7 percent.

One could easily assume that at least some of the observed decrease in generation within the RGGI states was caused by the increased imports. In the worst case 22.2 million MWh of the observed decrease in the 2017 54.6 million MWh electric generation decrease from RGGI generation could be caused by leakage.  However, in order to make that assumption you have to presume that the RGGI effect on prices was the only driver of imports.  I have found analyses that claim RGGI’s effect on emissions ranged from 17% and 24% but because the cost adder of the RGGI carbon price was relatively small I do not believe that the RGGI price drove affected source control decisions.  As a result, I believe that the only reductions from RGGI that can be traced to the program are the reductions that result from direct investments of the RGGI auction proceeds.  Therefore, RGGI investments are only directly responsible for less than 5% of the total observed reductions.  As a result, that suggests that the change in imports wasn’t primarily caused by RGGI but other factors so leakage is not an issue at this time.

However, there could be big changes to RGGI compliance coming.  Because the allowance cap is decreasing and the share of banked allowances owned by investors is increasing, I believe that there will be a significant price increase in the next several years.  Moreover, there are few opportunities left for fuel switching left at RGGI-affected sources and that has been the primary cause for the observed emissions reductions to date.  That will put additional pressure on RGGI region prices.  As a result, leakage may become an issue soon.  One caveat is that New Jersey joined the program in 2020 and Virginia will join soon thereafter and that could defer these issues down the road.

Conclusion

I have to comment on one disappointing aspect of the RGGI monitoring reports.  Leakage was a major stakeholder concern going into the program and I believe that this report was intended to address that concern.  However, the report notes that “because this report does not establish the causes of observed trends, it should be emphasized that this report does not provide indicators of CO2 emissions leakage”.  With all due respect, I think the report should actually make its best estimate of CO2 emissions leakage because it is a potential problem.  However, if the report showed that leakage was a problem, then that would be embarrassing if not a flaw in RGGI.  As a result, it is not surprising that the report ducks the issue.

I conclude that to this point leakage has not been an issue. However, the lack of leakage is because fuel switching reduced emissions without raising prices.  When fuel switching no longer becomes an option, I expect that the costs to reduce emissions will create a boundary price differential that will lead to RGGI leakage.  Unless the addition of New Jersey and Virginia create opportunities for cost-effective reductions then RGGI leakage will become a problem in the next several years.

Acadia Center RGGI 10-Year Review

The Acadia Center recently released “The Regional Greenhouse Gas Initiative: Ten Years in Review”.  According to the report “The country’s first program designed to reduce climate change-causing pollution from power plants has provided a wealth of lessons to be incorporated into the next generation of climate policies, from successes to build on to opportunities for improvement”.  This post compares the claims of success for the Regional Greenhouse Gas Initiative (RGGI) against reality.

I have been involved in the RGGI program process since its inception.  I blog about the details of the RGGI program because very few seem to want to provide any criticisms of the program. The opinions expressed in this post do not reflect the position of any of my previous employers or any other company I have been associated with, these comments are mine alone.

Background

RGGI is a market-based program to reduce greenhouse gas emissions. It is a cooperative effort among the states of Connecticut, Delaware, Maine, Maryland, Massachusetts, New Hampshire, New York, Rhode Island, and Vermont to cap and reduce CO2 emissions from the power sector.  This program is a prototype for “cap and dividend” pollution control programs. RGGI holds quarterly auctions for CO2 allowances.  Affected sources purchase the allowances they think they will need to operate and surrender them to RGGI every three years at the end of the compliance period.  The proceeds are used to fund investments throughout the region.

The Acadia report analyzes data since the launch of the program. Their analysis claims that “CO2 emissions from power plants in the RGGI states have fallen 90% faster than in the rest of country, while economic growth in the RGGI states has outpaced the rest of the country by 31%. The program has also driven substantial reductions in harmful co-pollutants, making the region’s air cleaner and its people healthier.”

As I will show below this report is fundamentally flawed because it attributes all the reductions in CO2 emissions and air quality improvements to the RGGI program.  In reality fuel switching is the primary cause of the reductions.  When the savings that RGGI claims as benefits due to investments from the auction proceeds are evaluated, they are a small fraction of the observed reductions.

RGGI Ten Years in Review Emissions Reduction Claim

The Acadia report states:

States participating in RGGI have seen a steep decline in CO2 emissions from power plants over the last 10 years. Since 2008, the year before the program launched, RGGI emissions have fallen from 133 million short tons of CO2 to 70 million tons in 2018, shown in Figure 1. The impressive electric sector emission reductions achieved in RGGI states over that time period have outpaced reductions in the rest of the country by a staggering 90%. While the RGGI program has not been the sole factor behind the region’s rapid electric sector decarbonization, earlier analysis[1] shows that it has been a key driver—and accelerator—of emission reductions from power plants.

I do not dispute the observed reduction values but the claim that the RGGI program has been a key driver or accelerator, whatever that means, is bogus.  The referenced paper by Murray and Maniloff does not indicate that the majority of the reductions are due to RGGI and I think their estimate of 24% is an unlikely upper bound.  There are two ways to determine how much RGGI itself has contributed to the observed reductions and both show even lower estimates of the RGGI effect on emissions.

The Murray and Maniloff analysis referenced shows the region’s emissions would have been “24 percent higher without the program, accounting for about half of the region’s emissions reductions during that time”.  The econometric modeling used in their analysis assumes that compliance with the program is made more efficient by an allowance acquisition program that resembles commodities markets.  In reality, based on my experience in the utility allowance trading business and discussions with my peers, the vast majority of companies and possibly all companies treat allowance acquisition as simply a tax.  Allowances are purchased in the auctions or on the secondary market based on short-term compliance needs.  The over-riding concern is compliance.  I am not familiar enough with econometric modeling to say how this affects the results but I believe they do.

In my opinion the Murray and Maniloff analysis assumed that companies would do things to reduce their CO2 emissions rather than just buying allowances as a tax.  However, the only thing that they could do is to improve combustion efficiency to use less fuel.  Fuel costs are the over-riding driver for operating costs so plants have already looked into this and probably made the efficiency changes that they could afford so there were few opportunities left to become more efficient.  In addition, EPA’s New Source Review program can penalize old facilities that make efficiency improvements because they are concerned that they those improvements could extend the life of a higher emitting facility.  Based on my experience and discussions with colleagues in the industry affected generating units did not do anything to control emissions for RGGI.  More importantly when this analysis observed facilities shutting down, they claimed that was due to RGGI.  In fact, all the facilities that I am familiar would have shut down even if RGGI were not in effect.  For all these reasons I do not accept this reference as credible evidence for RGGI success.

The first way to determine why emissions dropped over this period is to evaluate the emissions data.  I queried the database at EPA Clean Air Markets Division data and maps  and downloaded emissions, load and heat rate data for the nine RGGI states for the years 2000-2018.  In order to determine what fuel was used I had to use these data instead of the data in the RGGI system because the EPA data includes fuel type information.  This means that there are differences in the annual totals because the EPA data set has more units in it.  Prior to the start of RGGI I had to ask for data from “all programs” and for consistency kept that constraint even after the start of RGGI.

The RGGI Nine-State EPA Clean Air Markets Division Annual Emissions Data by Primary Fuel Type table lists load and CO2 mass data from 2006 to 2018.  In order to establish a baseline, I used the average of the three years prior to the start of the program.  The CO2 mass and load from coal-fired units went down over 80% from the baseline to 2018.  The RGGI states have a relatively high concentration of residual oil-fired units and load and CO2 mass went down nearly as much.  Diesel and other oil-fired units went down over 50%.  On the other hand, natural gas firing loads went up 35% and CO2 mass went up 43%.  Because natural gas firing has much lower CO2 per MWhr emission rates the total CO2 mass went down 41% from my baseline to 2018.  Because fuel prices are the primary driver of unit operations and because the RGGI allowance price was relatively small in comparison to the fuel price differential of natural gas relative to coal and oil I conclude that the primary driver of RGGI region CO2 emission reductions was fuel switching not RGGI.

The second way to determine the effect of RGGI is to use RGGI’s own information.  The Investment of RGGI Proceeds in 2017 report tracks the investment of the RGGI proceeds and the benefits of these investments throughout the region. I recently calculated that the total annual reductions since the start of the program were: 4,014,410 MWh of electricity use avoided, 9,824,199 MMBtu of fossil fuel use avoided, and 2,818,775 short tons of CO2 emissions avoided.  The total reduction in load from the baseline until 2018 is 51,098,013 MWh so the direct investments of RGGI auction proceeds were responsible for 7.9% of the observed reduction in load.  The total reduction in CO2 from the baseline until 2018 is 52,202,198 tons so the direct investments of RGGI auction proceeds were responsible for only 5.4% of the observed emissions reduction.

Clearly the Acadia report claim that the RGGI program has been a key driver of emission reductions from power plants is wishful thinking and not supported by the data.

RGGI Ten Years in Review – Aligning the RGGI Cap with Current Emissions

Because historical emissions have been less than the cap on emissions, the Acadia report calls for program reforms including a more stringent cap, more constraints on the allowance supply, and adjustments to eliminate the allowance surplus.  The report notes that “To be most effective, the RGGI cap needs to more closely reflect the new, lower-carbon reality of the region’s electric sector and the science-based GHG reduction targets adopted by the RGGI states.”

There is one facet of the cap and trade pollution control theory that is neglected with these recommendations.  In order to be effective, the affected sources must have options to reduce their emissions.  In general, with any GHG market-based program the sources affected by the rule don’t have options.  As noted above there are no real options for a power plant to reduce its emissions.  Theoretically a power plant could develop its own non-CO2 emitting generating units but the reality, especially in a non-regulated state, is that fossil-fired power plants have little incentive to pursue those options.  Most importantly, non-regulated generators have no obligation to serve.  In my opinion they will simply operate as long as they can make a profit or have the allowances available to operate then shut down.

The most important limitation to market-based cap programs is the cap limit.  If there are no other operations then affected facilities will just operate less or shut down entirely.  In their naïveté the Acadia report authors support a strict cap that actually constrains CO2 emissions.  The problem is that CO2 emissions represent generated power.  If the facilities cannot emit CO2 then they cannot produce power.  At some point the apparent preference of environmentalists for wind and solar resources will require grid services support to support the transmission grid because those resources are diffuse and energy storage because those resources are intermittent.  No cost studies that claim wind and solar are approaching the cost of natural gas generation include those integration costs.  If the trajectory of emission reductions does not account for that reality then I predict there will be big problems.

RGGI Ten Years in Review – Economic Trends and Electricity Prices

The Acadia report claims that RGGI has “generated significant economic benefits” by investing auction proceeds in “energy efficiency, renewable energy, and other consumer programs that increase economic activity in participating states.”  They also claim that “The RGGI states have managed to rapidly reduce CO2 emissions without impeding economic growth” and that the “average retail electricity prices have dropped since RGGI took effect”.

The Investment of RGGI Proceeds in 2017 report released in October 2019 tracks the investment of the RGGI proceeds and the benefits of these investments throughout the region. According to the report, the lifetime benefits of RGGI energy efficiency investments made in 2017 includes energy bill savings of over $1.4 billion on an investment of $315.6 million which qualifies as significant economic benefits.  However, RGGI is supposed to be a CO2 reduction program and what are the lessons to be incorporated into the next generation of climate policies from RGGI.  Sadly, from the standpoint of an efficient CO2 reduction program I don’t think you can call RGGI a success.  From the start of the program in 2009 through 2017 RGGI has invested $2,527,635,414 and reduced CO2 2,818775 tons annually which results in $897 per ton of CO2 reduced.

I will not debate the claims that RGGI rapidly reduced CO2 emissions without affecting economic growth and that retail electricity prices dropped.  However, as shown earlier the RGGI reductions had little to do with RGGI itself and much more to fuel switching to cheaper natural gas.  It seems to me that these claims then should be more to do with fuel switching than RGGI itself.

Conclusion

The Acadia report concludes:

RGGI has successfully demonstrated the viability of a market-based program to reduce CO2 emissions from the power sector while generating benefits for participating states. RGGI’s experience has disproven the concerns most frequently associated with capping emissions from the power sector. Emissions have declined rapidly, far more dramatically than projected, without stifling economic growth. RGGI’s reinvestment model has benefited the regional economy and increased employment while accelerating deployment of renewable energy and funding energy efficiency programs. The region’s residents now pay lower electricity prices than before the program began and breathe cleaner air.

I don’t think that RGGI has disproven any capping emissions concerns.  In fact, I think it is more likely that as RGGI increases the stringency on its cap at the same time that fuel switching options are used up that we will see what happens when a market-based control program has a restrictive cap.  Given that affected sources only have the option to not run when allowances are not available, I do not think this will end well.

By RGGI’s own numbers despite the apparent value of the energy efficiency investments the fact is that as a CO2 control program the results are expensive, far exceeding any regulatory social cost of carbon value.  If society is to depend upon RGGI investments as the control program to drive emissions reductions on the order of the Green New Deal then enormous costs are inevitable.

[1] Brian Murray and Peter Maniloff, Why Have Greenhouse Emissions in RGGI States Declined? An Econometric Attribution to Economic, Energy Market, and Policy Factors, Duke Nicholas Institute, August 2015. Available at: https://nicholasinstitute.duke.edu/environment/publications/why-have-greenhouse-emissions-rggi-states-declined-econometric-attribution-economic