SPP, Mountain West in Agreement over Allocating Existing Facilities
TULSA, Okla. — SPP COO Carl Monroe told the Markets and Operations Policy Committee last week that allocating costs for existing transmission facilities would not be an issue should the Mountain West Transmission Group be successful in its quest for RTO membership.
Mountain West doesn’t expect to pay for SPP’s facilities “past or present,” Monroe said, and SPP is “thinking similarly.”
“We have a current situation within SPP where we’re not sharing costs of the upgrades across the Eastern and Western Interconnections,” he said. “There’s already a situation in the SPP Tariff that, through contract, load in the West doesn’t pay for Eastern upgrades. That makes sense, because they don’t get any electric benefits out of that.”
SPP and Mountain West are also trying to determine whether to operate as a single market or two separate markets. There are currently four DC ties between SPP and Mountain West facilities, with a total capacity of 710 MW. Mountain West’s membership would place all seven U.S. ties between the Eastern and Western Interconnections under SPP’s Tariff.
“We’re talking with vendors, technical staff and outside experts to see whether it’s possible to operate a market over DC ties,” Monroe said.
Monroe was unable to answer several questions from members, citing confidentiality issues. However, he welcomed stakeholders to participate in the Strategic Planning Committee’s executive sessions, where discussions on Mountain West’s potential membership will take place. (Members will have to sign non-disclosure agreements to participate.)
Monroe and Tri-State Generation and Transmission Association’s Mary Ann Zehr said Mountain West hopes to determine whether to continue pursuing membership before July. The two entities would begin drafting revisions to governing documents shortly thereafter, with the intention of getting SPP board signoff in January 2018.
SPP and Mountain West officials both participated in an informational forum before the Colorado Public Utilities Commission on March 28. (See Mountain West, SPP Tout RTO Membership to Colo. PUC.)
Members OK Removing SPS Line from 2017 ITP10
The MOPC overwhelmingly agreed with staff’s recommendation to remove a Southwestern Public Service 345-kV line from the 2017 Integrated Transmission Planning’s 10-year assessment. The vote was opposed only by independent transmission companies ITC Holdings and Hunt Transmission, with Golden Spread Electric Cooperative and South Central MCN abstaining.
The MOPC and SPP’s board directed staff in January to further evaluate the Texas Panhandle project following pushback from SPS, which said it was “the wrong time” for the line. (See “Board Sends $144M Tx Project Back for Re-evaluation,” SPP Board of Directors/Members Committee Briefs.)
Staff’s further evaluation and modeling changes revealed a 6.5% decrease in the SPP region’s adjusted production costs savings, and a third-party review using more detailed routing assumptions lengthened the project from 90 miles to 109 and increased the $144 million cost estimate to $173 million.
In March, SPS parent Xcel Energy announced it would add 1,230 MW of new wind energy north of the proposed project in Texas and New Mexico. Load forecasts south of the constraint also indicated an 800-MW reduction in load, further reducing its need. The transmission line would run southwest of Amarillo to an SPS power plant being evaluated for continued operation.
“It’s a balancing act. We have to get it right,” said Engineering Vice President Lanny Nickell, responding to comments about the additional modeling and studies. “We’ve probably done more analysis on this single ITP10 than we’ve done on any number of studies cumulatively. … We need to get better at interpreting these results.”
“I look at planning as a core fundamental of the RTO,” said MOPC Vice Chair Todd Fridley of Transource Energy. “If we can’t do that well and have these fits and starts, we’re not getting the job done.
“Major input changes at the end of the planning process makes this determination more difficult. Everyone wants to build the right projects, but we must also maintain the integrity of the planning process so that everyone has confidence that we are delivering customer value,” Fridley said.
ITC Holdings’ Alan Myers, who chairs the Economic Studies Working Group that brought forward the staff recommendation, reminded members that SPP’s new transmission planning process will include accountability mechanisms designed to promote timely data exchanges, reviews and approvals. (See “SPC, MOPC Approve Improvements to SPP’s Tx Planning Process,” SPP Strategic Planning Committee Briefs.)
“One of the core tenets in the new process is more stakeholder discipline,” he said. “There will be some bright lines about when we need to have your data in. What we have here is a little more unprecedented.”
“What SPP did was go back and do a fair assessment with the stakeholders that were involved,” said Bill Grant, director of strategic planning for SPS. “This evaluation is showing that, yes, if we had 8 [GW] of wind, transmission has to be built.”
MWG Closing out MMU’s Recommendations
The Market Working Group took another step toward closing the 2014 State of the Market Report’s nine proposed market changes by securing approval of a revision request that removes the day-ahead must-offer requirement.
The change request, MRR125, came out of the Market Monitoring Unit’s recommendations to improve the Integrated Marketplace and was designed to run in parallel with revisions to physical withholding rules. The MOPC declined to take up the revision request in July to allow for further discussion on the rules. (See “MOPC Defers Action on Must-Offer Rule,” SPP Markets and Operations Policy Committee Briefs.)
Working group Chair Richard Ross of American Electric Power said the group spent considerable time since then discussing the issue. In February, it rejected a revision request that would revise the physical withholding rules to include a penalty for noncompliance. The MMU has appealed that decision and plans to bring it up at the July MOPC meeting.
“The conclusion was a preference to stay with current monitoring activities,” Ross said. “It’s important you realize whether these provisions are in or out, you’re still subject to physical withholding” prohibitions.”
MMU Director Alan McQueen was asked if the unit agreed with the MWG’s conclusion.
“We think the market has the right incentives,” McQueen said. “[MRR125] doesn’t eliminate concerns around potential cases of physical or economic withholding in the market. We think the rules can be improved, but we don’t think the day-ahead must-offer significantly contributes to that.”
MOPC Chair Paul Malone, with the Nebraska Public Power District, asked McQueen whether he had any concerns over “after-the-fact” market power.
“[Market participants] may not know when they have local market power,” McQueen said, “but generally, from experience, MPs should be able to discern when they’re likely to have market power.”
“The [MWG’s] concern was there may be particular conditions on the grid, like transmission outages, planned and unplanned, where a unit may find itself in a situation where it has market power,” Ross said. “The concern on MPs’ part was we may not be as smart as the MMU staff thinks we are.”
Ross said eight of the nine 2014 recommendations are closed, though McQueen disagreed.
“Richard represents the MWG, I represent the MMU,” he said.
McQueen took the opposing side when the MOPC then considered MRR214, which would allow market participants to add a 10% buffer to mitigated offers.
The MWG said the 10% buffer added to the mitigation offer will give MPs more margin for error when submitting their mitigated offer curve. The group also said the change would improve price formation in SPP’s markets by removing a penalizing feature that may be suppressing offered prices today.
“Mitigation and economic withholding are trying to keep the market at competitive levels when there is the presence of market power,” McQueen said. “Are we accomplishing that? Are we improving that? Are we making it better? Is this making sure the market stays competitive during those periods when mitigation actually goes into effect?
“What’s being proposed is inconsistent with what we’ve seen in other markets and what’s been approved by FERC,” he said.
“This came across because of a discussion at the Board of Directors,” said Golden Spread Electric Cooperative’s Mike Wise, who sits on the Members Committee and chairs the Strategic Planning Committee. “Many MPs have encouraged us to do this. They’re not recovering their short-term marginal costs.”
“This needs more work,” said Lincoln Electric System’s Dennis Florom. “I don’t see staff supporting it, I don’t see the MMU supporting it. We’re going to have our own members and the MMU fighting at FERC, which is embarrassing to me.”
The committee sent the revision request on to the board for its approval next week, with seven members opposing and five abstaining.
Separately, Ross recommended the committee reject RR201, which would have provided market participants a mechanism to settle day-ahead market errors without repricing and re-clearing the entire market.
“The challenge folks encountered was if we do that without resettling the whole market, you’re just throwing it in a bucket and spreading it across the whole market,” he said.
The MOPC agreed, though two members opposed and another dozen or so abstained.
Another change (MRR209) that would have expanded resources’ “status options” to include start-up/shut-down and testing was rejected on a roll-call vote, with 61% of the members opposed.
SPP staff said the change would “result in a clearer understanding” of why a resource may not be following dispatch instructions. However, it drew opposition from members who couldn’t balance the revision’s minimal benefits with its estimated $22,000 cost when operators will continue follow-up phone calls for reliability reasons.
The committee also approved MRR203, which adds a “last-chance” second set of auction revenue rights nominations in the monthly ARR process, where any source-to-sink path can be nominated.
MOPC Endorses Re-evaluation of Basin Electric Project
The MOPC endorsed Basin Electric Power Cooperative’s request for an expedited re-evaluation of a 345-kV project in northwestern North Dakota. The project — replacing a 33-mile, 115-kV line at an estimated cost of $52.3 million — was approved last July for a notification to construct with conditions (NTC-C) out of the 2016 Near-Term assessment. (See “First Competitive Tx Project Pulled; ND 345-kV Line Approved,” SPP Board of Directors and Members Committee Briefs.)
Basin Electric had projected 2.5% load growth in the nearby Bakken shale play in making its earlier request, but updated load forecasts from its member companies have revised that number downward. It asked for the expedited assessment to confirm the timing of construction and associated financial expenditures.
“We’re still seeing load increases in that area, just not at the rate we anticipated,” said Jason Doerr of Basin Electric member Northwest Iowa Power Cooperative. “It’s still Basin Electric’s belief that this load will continue to grow at a rate that’s significantly less. Next year, wherever the economy goes, we’ll have another load forecast to provide SPP.”
SPP’s Jason Davis said the project could eventually fall under FERC Order 1000, but until then, “We want to take a step back, see what needs and issues still exist going forward.”
Another project did proceed as a potential seams project, with the MOPC’s approval of a 50-MVAR reactor at a 345-kV substation near Springfield, Mo. The Seams Steering Committee and Transmission Working Group both recommended the project’s approval out of the regional-review process. The project was identified last year in a joint study with Associated Electric Cooperative Inc.
The MOPC also approved the TWG’s 2017 ITPNT, which includes 16 reliability projects at a combined cost of approximately $60 million, and its scope for the 2018 ITPNT. Both motions passed unanimously.
Cost Allocation Review Cycle Could Extend to 6 Years
The MOPC approved a task force’s unanimous recommendation and an accompanying revision request that future regional cost allocation reviews (RCARs) be conducted at least once every six years, doubling the previous three-year timeline.
The Regional Allocation Review Task Force said extending the timeline would save SPP manpower and consulting costs, noting the most recent RCAR showed an increase in benefit-to-cost ratios and only one entity below the threshold. Ross, the RARTF’s vice chair, pointed out the Tariff still allows members to seek relief for an out-of-cycle RCAR at any time from the board, MOPC or Regional State Committee.
“It’s not a trivial task. We’re spending well over $400,000 to produce the reports,” Ross said. “It is quite literally a single-word change.”
The motion was opposed by the City of Springfield, whose transmission zone in southwestern Missouri was found to be deficient by RCAR II, and several other smaller entities. The Morgan project — a new 345/161-kV transformer at AECI’s Morgan substation and an uprate of a connecting 161-kV line at an estimated $9.2 million — was approved out of the 2017 ITP10 in January as a remedy to Springfield’s deficiency, and was recommended for regional funding by the MOPC last week. However, the project is contingent on reaching an agreement with AECI, which would not see reliability benefits from a potential seams project that sits within its service area.
Jeff Knottek, director of transmission planning and compliance for Springfield utilities, said if the Morgan project doesn’t provide the city with a remedy, it didn’t want to wait another six years.
“We’re still technically a harmed entity through two RCARs,” said Knottek, who abstained from the vote. “We haven’t climbed out of the hole yet, and [Morgan] could fall on its face. Under a worst-case scenario, in six more years we could be sitting [at a negative number].”
Changes Proposed for Revision Process
SPP staff introduced potential changes to the revision-request process for technical documents that don’t require MOPC approval.
Staff said NERC reliability standard IRO-010-2, which requires the reliability coordinator (RC) to maintain documentation of data specific to its responsibilities, and a recent revision request that would create RC and balancing authority data as an appendix to the operating criteria, created a need to manage other documents not a part of the current process.
While the revision process for technical documents would not require MOPC approval before being enforced, the committee would still hear appeals from members. Written reports on the changes would be provided in the MOPC’s background materials, and members could request discussion on the changes if they’re not part of the working groups responsible for the documents.
Staff said the revised process would better meet NERC requirements and proposed starting with reliability data specifications and the communication protocols. Other documents that could fall into the process include the Integrated Transmission Planning manual, the balancing authority’s emergency operations plan, the SPP Reliability Coordinator Area’s restoration plan and other technical handbooks and guides.
Several stakeholders, primarily from smaller members, expressed concerns over losing visibility into changes.
“Letting [the documents pass] out of the primary working group … how would we know they have passed?” asked ITC Holdings’ Marguerite Wagner. “How would we keep track of that?”
“As the organization gets bigger and bigger in geography and more members, I’m not comfortable with this,” said Chairman Malone, referring to extending the process to other SPP documents. “In our organization, we try to have someone plugged in to every working group, but not everyone can do that. I’m just not comfortable with it yet.”
Monroe said the primary working groups and staff would be responsible for notifying all parties of pending changes, and that some of the more technical revisions would be included on the MOPC consent agenda. He also said he had heard support for giving the working groups the ability to approve technical documents, rather than send them to the MOPC.
Staff said it will return with a formal proposal for the committee’s July meeting.
Org Chairs also may See Changes
Paul Suskie, SPP’s legal counsel and corporate secretary, shared the Corporate Governance Committee’s proposed bylaw change for organizational group chair and vice chair selections.
Under the changes, group chairs would be nominated by the committee and appointed by the board to a term that coincides with the board chair’s two-year term. Vice chairs are elected by the groups’ members, with their terms now coinciding with the group chairs’. The MOPC vice chair would be elected by the board.
Should there be a vacancy at the chair level, the vice chair would become the interim chair until a replacement is appointed by the board to fill out the remainder of the term.
The working group leadership’s terms would be staggered to expire in even or odd years. Committees reporting to the board would have their leadership’s terms match that of the board chair. This doesn’t apply to those committees advising the board, such as the Regional State Committee and the Cost Allocation Working Group.
Upon board approval, the bylaw changes would be filed with FERC for its approval.
MOPC Approves Doubling Credit Allowance to $50M
SPP will join its RTO/ISO brethren in adopting a $50 million unsecured credit allowance should the board next week approve a revision request raising its current cap from $25 million.
SPP is the last of the RTOs without a $50 million allowance cap. CPWG-RR218 calls for raising the allowance to reduce the costs of capital for utilities, while exposing SPP’s customers to “minimal additional credit default risk.”
FERC Order 741 allowed RTOs and ISOs to grant up to $50 million in unsecured credit, a limit most grid operators have adopted.
The Credit Practices Working Group’s revision was pulled from the consent agenda over concerns that SPP was planning to raise its cap just to match other RTOs. However, staff said SPP’s transmission congestion rights market, with its collateral requirements, highlighted the need to revisit the cap.
Staff estimated the increase would affect about 15 credit customers. The revision was approved unanimously by the MOPC.
Twelve other revision requests also passed unanimously as part of the consent agenda:
- BPWG-RR207: Aligns the business practices with the Integrated Marketplace’s tag-denial criteria.
- MWG-RR200: Allows bilateral settlement statements (BSS) at a withdrawal point to be included in the overcollected losses calculation. Capping the BSS at the maximum amount of the real-time withdrawal minus any amount of grandfathered agreements or any federal service exemptions will diminish the dilution at a generation or hub settlement location.
- MWG-RR205: Allows the implementation of the combined-resource option changes by including the minimum regulation-capacity operating limit, and adds resource offer parameters that can be changed daily for a jointly owned resource’s minimum physical capacity and physical-regulation capacity operating limits.
- MWG-RR216: Reinstates Tariff language omitted from RR173 and filed at FERC last year related to eligibility of multi-configuration resources for regulation-up or regulation-down service.
- MWG-RR217: Removes Tariff language related to violation relaxation limits to make the section consistent with a compliance filing to FERC’s Order 825 on shortage pricing.
- MWG-RR219: Ensures language in SPP’s Tariff meets FERC requirements for enhanced combined cycle units.
- ORWG-RR213: Creates a new appendix to the SPP Operating Criteria that defines how the SPP reliability coordinator will operate voltage stability limited system constraints, as recommended by the Wind Integration Study.
- RTWG-RR208: Implements the Transmission Planning Improvement Task Force’s white paper for new regional planning processes by replacing current planning schedules with an annual transmission-expansion plan, creating a standardized scope; establishing a common planning model for use across the various planning processes; and creating a staff/stakeholder accountability program. (See “SPC, MOPC Approve Improvements to SPP’s Tx Planning Process,” SPP Strategic Planning Committee Briefs.)
- RTWG-RR211: Establishes an additional criterion for competitive projects, requiring that the total competitive segments for a transmission project cost meet or exceed $3 million.
- TWG-RR224: Aligns the existing criteria with NERC’s new definition of special protection schemes as remedial action schemes, and cleans up planning-criteria language coinciding with changes made to the operating-horizon system operating limits methodology.
- TWG-RR215 and TWG-RR186: Eliminates redundant requirements.
– Tom Kleckner