The Southwest Power Pool is undertaking a yearlong review of its governance, transmission cost allocation and planning philosophies to accommodate dramatic changes in the wholesale power market and electric utility industry over the past decade.
"We have not done the 'check-and-adjust' on where we've been and where we need to be," said Rob Janssen, vice president of Dogwood Energy LLC, the operator of a natural gas-fired plant in Cass County, Mo., owned by a number of parties including Missouri and Kansas municipal utilities. "The problems that are cropping up are being addressed in silos."
Various stakeholder groups have tried to reach agreement on issues on a piecemeal basis, but "they haven't been getting results," Janssen said.
Janssen is part of a team established by SPP earlier this year to consider issues related to transmission planning, transmission cost allocation and markets.
The 16-member group, known as the Holistic Integrated Tariff Team, or HITT, was set up in March and includes representatives from SPP's board, Regional State Committee, senior staff, investor-owned utilities, cooperatives and independent power producers.
The effort is similar to one the grid operator began in December 2008, when SPP created the Synergistic Planning Project Team. That initiative resulted in SPP's "Highway/Byway" cost allocation methodology for new transmission upgrades, which would result from a new integrated transmission planning process.
In the Highway/Byway cost allocation process, which went into effect in 2010, projects rated at more than 300 kV — the Highway category — are 100% allocated across the SPP footprint on a load-ratio-share basis, known as a "postage-stamp" approach. Projects rated between 100 kV and 300 kV — the Byway category — are funded 67% at the local zone and 33% on a postage-stamp basis. Projects rated less than 100-kV are 100% funded locally.
The load ratio share is usually considered the average of each customer's hourly loads that coincide with the customer zone's monthly peak loads during the previous calendar year. Grandfathered agreements may adjust these calculations.
In general, network upgrades directed for construction by SPP from 2005 to 2010 were funded similarly to the "Byway" category, with 67% paid by the local zone and 33% paid on a postage-stamp basis.
Expansion and change
But in the past 10 years, SPP has seen some dramatic changes:
* The grid operator's footprint expanded from covering all or parts of six states, mainly in Kansas, Oklahoma and the Texas Panhandle, to covering all or parts of 14 states in the central United States and incorporating utilities such as Basin Electric Power Cooperative.
* The grid operator's market activity expanded from a real-time energy imbalance market to an "Integrated Marketplace" with a co-optimized day-ahead market for power and ancillary services and a transmission congestion rights market, similar to financial transmission rights.
* The SPP board of directors approved and market participants completed construction of about $6.3 billion in transmission projects across the expanded footprint and have approved another $2.9 billion to be done by 2022.
* The region's power generation mix has shifted from 66% coal-fired in 2008 to 44% as of October 2017, according to S&P Global Market Intelligence data. Over the same time period, wind energy's share grew from 2% to 25%.
Judging by generation developers' plans, that trend away from conventional generation toward renewables is likely to continue.
As of September, SPP had 76,396 MW of generation in the interconnection study queue for development, including 70% wind, 25% solar, 4% storage and less than 1% natural gas-fired.
The latest SPP Fast Facts document lists 87,086 MW of nameplate capacity as of the beginning of 2018, and the record peak load was 50,622 MW on July 21, 2016.
"From the beginning, the goal was to have a robust transmission grid that could deal with all the changes we could see coming," Dogwood's Janssen said. "Seeing less congestion on the grid was a sign that we had a robust transmission system."
Paul Suskie, SPP's executive vice president and general counsel, who serves as HITT's staff secretary, previously served on the Regional State Committee, representing the Arkansas Public Service Commission, when it approved the Highway/Byway cost allocation methodology. Highway/Byway was advocated in part as a way to help states meet their renewable portfolio standards by encouraging the development and transmission of wind power across the region, he said. The proposal had a rationale of "build it, and they will come."
"Well, we built the system, and they came, and they came, and they came," Suskie said.
SPP has also made efforts to further expand its footprint to the Western U.S. but failed to persuade the Mountain West Transmission Group to join SPP. Nevertheless, much of the Western Area Power Administration's balancing authorities agreed in September to use SPP as their reliability coordinator beginning in late 2019.
At that time, Western Power Trading Forum Executive Director Scott Miller said that "RC selection has been used by some as a stalking horse for market platform choices," but added that "it remains to be seen" whether it represents "a trend towards something beyond RC services or one dot on a plot line that is yet to be drawn."
The HITT group is to provide high-level recommendations in April 2019 to the SPP board regarding transmission and market issues. From there, any recommendations would make their way through SPP's stakeholder process before heading to the Federal Energy Regulatory Commission for approval.
If changes do come out of this process, they will not happen overnight. It was more than a year from the board's April 2009 adoption of the Synergistic Planning Project Team report and FERC's June 2010 approval of the Highway/Byway cost allocation scheme.
Brett Leopold, a HITT member and president of ITC Great Plains LLC, a unit of transmission developer ITC Holdings Corp. that has built several 345-kV lines in the SPP region, said, "We are at a point in SPP where the existing rules for planning, cost allocation and the market are facing pressure and need to be adapted for the existing conditions and for years ahead."
Leopold cited FERC's Order 1000 as an issue that has created unintended consequences in SPP's transmission planning. Finalized in 2011, FERC Order 1000 eliminated transmission system owners' right of first refusal regarding new transmission facilities selected in a regional transmission plan for purposes of cost allocation and allowed the use of competitive bidding for such projects.
"[The] implementation of FERC Order 1000 has contributed to an environment that has increasingly resulted in the planning of piecemeal, shorter-term solutions to problems and the construction of more low-voltage reliability transmission upgrades, rather than high-voltage backbone upgrades," Leopold said in an email.
During a HITT meeting in August, Al Tamimi, vice president for transmission planning and policy at western Kansas cooperative Sunflower Electric Power Corp. Inc., said that when Highway/Byway was established transmission projects were developed mainly based on changes in loads or changes in "designated resources" — generators designated to serve specific loads.
But since 2010, loads have stagnated while renewable generation — primarily wind — has proliferated, mainly in the sparsely populated rural west part of SPP, which includes Sunflower's member cooperatives, Tamimi said in his written presentation.
Upgrades required to serve these new wind farms have primarily been categorized in the midrange Byway rating, so local zones have had to pay 67% of their costs, despite the fact that local zones neither need nor benefit from such generation, Tamimi said.
During November's HITT meeting, stakeholders discussed several alternatives for allocating transmission costs, including the following:
* Instituting a zonal access charge for generation.
* Adjusting the percentages that operate in the Highway/Byway categories so that the SPP footprint as a whole bears more of the costs for midsize projects.
* Reconfiguring the 19 transmission utility zones into six subregions, so that locally assigned costs are spread over a wider group of customers.
ITC's Leopold said he thinks some form of Highway/Byway cost allocation method should continue as the primary means, but "new resources and transmission buildout benefits the entirety of the SPP footprint, and costs could better reflect those benefits in some situations."
"Since upgrades are often driven by additional resources coming online, we believe there is a balance between allocating more costs to these generators while acknowledging that everyone in the region benefits from new transmission," Leopold said.
What is happening in SPP is not unique among regional transmission organizations, said Keith Collins, who oversees SPP's Market Monitoring Unit, or MMU.
"All the RTO regions are in some fashion dealing with renewable integration challenges," he said in an interview.
Collins on Oct. 23 presented to the team recommendations the MMU thinks can help improve market outcomes and help the system continue to integrate renewables. One way to do this is to increase flexibility, perhaps by developing a ramping product like those seen in the Midcontinent ISO and California ISO. SPP must also find ways to improve market efficiency, something needed to help resolve an increase of negative pricing seen in the last few years, Collins said.
"Renewable resources are frequently underbidding their expected [available] value in the day-ahead market," Collins said. "Only 82% of what is available in real-time was offered day-ahead."
Whereas wind generation operators may wish to avoid offering power that becomes unavailable during real-time, the wind forecast error averages about 5%, Collins said.
This situation can result in big price divergence — usually lower and possibly negative real-time prices — and higher uplift payments to pay virtual transactions.
Possible solutions to wind farms' underbidding their expected next-day production can be found in other parts of the country, Collins said. ISO New England requires renewable resources to offer up to their forecast amount in the day-ahead market. The California ISO, meanwhile, provides transparency on underscheduling so virtual transactions can fill the gap.
While not indicating a favorite approach, Collins said the gap between wind's offerings in the day-ahead and real-time markets "is causing efficiency issues, and there are potential solutions."
The MMU also recommended that the grid operator change its assumptions of when generators will retire. The grid operator, as part of its transmission planning process, has historically assumed that generators will retire after 60 years.
But, in reality, retirement averages are quicker. The Economic Studies Working Group has already updated the 2020 transmission plan to use lower retirement ages of 56 years for coal and 50 years for natural gas.
Outlook for change
Shari Feist Albrecht, chair of the Kansas Corporation Commission, a member of SPP's Regional State Committee and part of the HITT team, said with the proliferation of wind, the anticipated retirement of coal generation and the likelihood that energy storage will develop within the region, cost allocation, transmission planning and market design will face pressure for reform.
"I hope the HITT process produces a long-term vision for optimizing delivery of electricity both within and outside the footprint that benefits all stakeholders at a price that reasonably recovers the costs of providing transmission service," she said in an email.
Like the broader SPP footprint, Kansas has seen its share of change in the last decade.
The generation mix in Kansas has changed from 72.9% coal, 18.2% nuclear, 4.8% gas and 3.8% wind in 2008 to 38.1% coal, 20.9% nuclear, 4.2% gas and 36.5% wind in 2017. From 2005 to 2015, Kansas had significant transmission development with expenditures of about $1.2 billion. Earlier in 2018, the state's two largest investor-owned electric utilities merged into a new company, Evergy Inc.
Dogwood Energy's Janssen said that reaching consensus about the nature of SPP's challenges "has been tricky."
"Personally, I think we're making good progress in getting the issues on the table and having people step back and take a look at the big picture," Janssen said. "To some degree, if we don't make changes, we are stuck with very few projects getting built, going forward. … I suspect we will see some change. Could that change be significant? It could be. … [But] it could be that we can get a trade-off on some smaller issues and get everybody satisfied without making a major change."
Regardless of the result of the HITT initiative, Janssen sees little prospect for rising power prices.
"Whatever we get in the future, coming out of the HITT process, I hope that it continues to make SPP a good place for a good economy, just in the place we are," Janssen said. "Prices are still low, and probably will stay that way. … I don't know how what we are doing now will change prices."
Mark Watson is a reporter for S&P Global Platts which, like S&P Global Market Intelligence, is owned by S&P Global Inc.