There are now at least three major transmission system operators with studies showing regional Clean Power Plan (CPP) compliance strategies will be more cost-effective than state-by-state compliances.
A new preliminary study from the Southwest Power Pool (SPP) confirms the findings of both the PJM Interconnection and the Midwest Intercontinental System Operator (MISO).
“For a state-by-state compliance approach, the capital investment cost and energy production cost totaled about $3.3 billion per year,” explained SPP Engineering VP Lanny Nickell. “The total capital investment cost and energy production cost for a regional approach is about $2.4 billion. It is almost a 40% savings associated with complying on a regional basis.”
As with other analysis produced before the final plan’s release, SPP’s Clean Power Plan Compliance Assessment – State-by-State was for the draft plan’s emissions reduction target for 2030. The final plan raised the target from 30% to 32% and extended the timeline to 2032.
“Compliance with the Clean Power Plan is best facilitated through SPP’s regional transmission planning process and energy market administration,” Nickell said after the final plan’s release.
Using scenarios that included an assumed $45 per ton carbon cost adder, “we tried to provide an indicative analysis that would be useful to the state agencies charged with developing compliance plans,” Nickell said.
If anything, the disruptive changes in the U.S. generation fleet that will come from the final version of the CPP are likely to be even more eased by regional compliance.
“SPP expects that state-by state compliance plans will be more costly and will present more uncertainty and complexities,” the analysis reports. They are likely to find it “extremely challenging and not without risk.”
A regional approach, on the other hand, “would be more cost effective and less disruptive than a state-by-state approach and may provide mutually beneficial opportunities that are not available within state boundaries,” SPP’s analysis concludes.
Analyses from other regional transmission operators (RTOs) concurred with what the SPP found.
“There are fewer low-cost options available within state boundaries than across the entire region,” PJM’s March 2 Economic Analysis of the EPA Clean Power Plan Proposal reports.
“Under regional compliance modeling, a lower-cost set of resources can be dispatched,” PJM’s website explains of the study. “Under the state-level compliance modeling approach, coal resources in states that face a price on carbon dioxide emissions are financially worse off with lower output and higher running costs.”
“Regional compliance options save approximately $3 billion annually compared to subregional compliance,” MISO’s September 2014 GHG Regulation Impact Analysis reports. It assumes a $38 per ton price on emissions and calculates that a regional level approach would have a $702 billion, 20-year Net Present Value for total system costs. It calculates that a sub-regional, or state-by-state, approach would have a $730 billion price tag.
The $28 billion dollars in difference, spread over the ten years from 2020 to 2030 that the draft CPP targeted, comes out to just under $3 billion per year. The higher number is because MISO is a larger system that SPP.
The new study
SPP members initially called on its Staff to do a reliability impact assessment of the draft CPP, Nickell explained. The essential finding was that additional infrastructure, including generation, electric transmission, and natural gas pipelines, would be necessary to comply without compromising system reliability.
“Of those three types of needed infrastructure, the longest lead time would be for electric transmission, which would take up to almost nine years,” Nickell said.
The new analysis of the comparative costs of the two CPP compliance options is based only on the cost of necessary generation retirements and development. It does not assess the costs for new transmission or new pipelines.
But, Nickell explained, generation is generally the most expensive of the three types of needed infrastructure, which makes the analysis strongly indicative if not comprehensive.
SPP is doing a comprehensive transmission study and forecast, he added. What is already clear is the infrastructure put in place by SPP over the last 10 years and what is planned for the next 10 years will already support a regional approach.
“It allows ratepayers in western Arkansas and western Missouri and in eastern Kansas and eastern Oklahoma to benefit from the less expensive wind generation assets in western Kansas and in the panhandles of Oklahoma and Texas, for instance.”
The analysis assumed the need to use more of the region’s wind and natural gas resources although, Nickell said, “that is not the only way to comply and may not be the best way to comply.”
A related assumption was that states choosing to comply on their own would likely have to develop new generation and new transmission that SPP already has. They would incur greater costs that would be spread over a smaller rate base. And it would take them longer, putting them in jeopardy of missing benchmarks.
“Though the infrastructure needed with a regional approach is not zero, we believe it will require less additional infrastructure than a state-by-state approach,” Nickell said. “That’s why the 40% higher cost estimate for state-by-state compliance is pretty generous.”
SPP’s assessments show regional compliance does not require all states to meet their emissions reductions requirements because of the “inter-state exchange of economic resources, emissions, and abatements,” the analysis explains. “Carbon emissions in six of the 11 SPP states evaluated exceeded the individual SPP-calculated state emissions goals.”
State-by-state compliance scenarios incorporating the $45 per ton carbon cost adder required “additional coal retirements, conventional generation additions, and renewable wind generation additions in the SPP states with emissions in excess of their goals.”
The necessary 5.5 GW of new wind would cost a projected $14 billion. Another 4 GW of natural gas capacity would add $2.9 billion. “Including production cost, this equates to $3.3 billion per year in additional costs to comply with the CPP on a state-by-state basis.”
“Those numbers are simply indicative,” Nickell said. “We are not recommending a recipe for compliance. This is to give state agencies enough information so they would have a fairly good idea of what the difference is between the two compliance approaches, assuming all else is equal.”
“Studies to determine transmission needs generally take 12 months to 18 months,” Nickell said. “We are currently working on a transmission expansion plan but it won’t be finished until January 2017.”
That is why, given the timelines in the Clean Power Plan, “it is critical that transmission be a part of the discussion about how to comply,” ITC Transmission U.S. Grid Development VP Dan Oginsky explained.
The changes in the generation fleet will add new, more diverse, and more variable resources. The most efficient solutions for integrating them may come through transmission planning, Oginsky said. “That is why transmission needs to be a part of the conversation from the start.”
Transmission projects don’t get held up “because engineers can’t engineer them and because our permitting and construction people don’t get things done,” Oginsky said. “What slows things down is the regulatory process.”
A recent controversy at SPP illustrates the complexity of transmission planning.
The RTO was implementing a new transmission planning process, in compliance with FERC Order 1000, Nickell said. It cut in half the time SPP staff was allotted to analyze the cost of a proposed project compared to estimates made by transmission-owning utilities.
Staff cost estimates for eight project proposals, which had been used to win board approvals, came back from their transmission-owning member utilities with refined cost estimates between 60% and 209% higher, provoking reaction from the SPP board.
One SPP board member was especially irate until the circumstances were clarified. In the end, staff accepted the refined cost estimates and is reconsidering its recommendations. They will be presented again to the board in October or January.
“That is the planning process,” Nickell explained. “Once the board approves a project, we issue a notification to construct. The recipient, the transmission-owning utility, has 90 days to give SPP a refined cost estimate."
Once the revised estimates are approved, SPP will accept the commitment of the transmission-owning utilities. "The next steps, generally the detailed engineering and design work, the permitting activities with regulators, and other preliminary processes, then can begin,” Nickell said.
This demonstrates why new transmission infrastructure can take up to nine years to build, Nickell said. “But if we didn’t go through all these diligence measures, we would not be certain. When the utilities go before their regulators, they can know the projects are necessary and cost-effective."
Uncertainty and the Clean Power Plan
The Clean Power Plan is going to have a huge impact, Oginsky said. The legal challenges add uncertainty but stakeholders need to start scenario planning.
“If you get all the pieces on the table, you can start arranging them in the way that is most cost-effective and efficient and fitting together a more diverse generation fleet and a grid strong enough to accommodate it,” Oginsky said. “There are discussions going on at the RTOs, at the states, and in the generation and transmission industries, but they are not yet getting traction.”
As those discussions translate into planning, transmission must be engaged. “We need a strong transmission grid across the country that is strong and flexible enough to handle all the uncertainties facing us, including the CPP, the changing generation fleet, and changes in how consumers obtain and use electricity.”