Page 1311 – RTO Insider

March 21, 2017

PJM Markets and Reliability and Members Committees Preview

Below is a summary of the issues scheduled to be brought to a vote at the Markets and Reliability and Members committees Thursday. Each item is listed by agenda number, description and projected time of discussion, followed by a summary of the issue and links to prior coverage in RTO Insider.

RTO Insider will be in Wilmington, Del., covering the discussions and votes. See next Tuesday’s newsletter for a full report.

Markets and Reliability Committee

2. PJM Manuals (9:10-9:25)

Members will be asked to endorse the following proposed manual changes:

A. Manual 13: Emergency Operations. Revisions developed in response to new NERC standards.

B. Manual 37: Reliability Coordination. Revisions developed in response to new NERC standards.

C. Manual 1: Control Center and Data Exchange Requirements. Revisions developed in response to new NERC standards.

3. FERC Order 825 – Shortage Pricing (9:25-9:45)

Members will be asked to endorse the proposed shortage pricing and operating reserve demand curve solution and associated manual revisions. (See “Order 825 Implementation Moves Forward,” PJM Market Implementation Committee Briefs.)

4. Draft Pseudo-Tie Agreements (9:45-10:05)

Members will be asked to endorse a pro forma pseudo-tie agreement and a reimbursement agreement for pseudo-ties into PJM, along with related Tariff and Operating Agreement revisions. (See PJM to Tighten Pseudo-Tie Rules Despite Stakeholder Pushback.)

5. Cost Development Manual Revisions (10:05-10:35)

Members will be asked to endorse revisions to Manual 15 and the Operating Agreement regarding hourly offers and fuel-cost policies. (See PJM Fuel-Cost Policy Changes to Take Effect in May.)

6. Opportunity Cost Calculation (10:35-10:50)

Members will be asked to endorse a proposed problem statement and issue charge by Bob O’Connell of Panda Power Funds regarding calculation of opportunity costs for units with less than three years of historical LMPs. The initiative would evaluate whether the opportunity cost calculator included in PJM’s Markets Gateway produces the same results as that used by the Independent Market Monitor, Monitoring Analytics. It also would consider updating the calculators to reflect the nonperformance penalties under Capacity Performance. (See “Stakeholders Deny Replacement Capacity Initiative; Consider Other Incremental Auction Changes,” PJM Markets and Reliability and Members Committees Briefs.)

7. Modeling Generation Senior Task Force (MGSTF) (10:50-11:00)

Members will be asked to endorse a draft charter for the MGSTF, an outgrowth of the Combined Cycle Owners User Group, which concluded that a more detailed generator model for combined cycle units might also be applicable to other steam units. The task force will consider expanding the model used by PJM to improve the ability to represent components of all generation types.

8. Incremental Auction Senior Task Force (IASTF) (11:00-11:10)

Members will be asked to endorse a draft charter for the IASTF, which will consider changes to the Incremental Auction process and structure, excess capacity sales, and PJM participation in the auctions.

9. Replacement Capacity (11:10-11:40)

Members will be asked to endorse a revised version of a previously rejected problem statement and issue charge regarding procurement of replacement capacity in Reliability Pricing Model Incremental Auctions. (See “Stakeholders Deny Replacement Capacity Initiative; Consider Other Incremental Auction Changes,” PJM Markets and Reliability and Members Committees Briefs.)

Members Committee

There are no items up for endorsement.

— Rory D. Sweeney

March 21, 2017

Ott Seeks ‘Resilience’; Clark Handicaps ZECs

By Rich Heidorn Jr.

CARY, N.C. — PJM CEO Andy Ott said last week the RTO will look for ways to incorporate “resilience” in its markets and system operations, providing hints at a white paper it will release later this month on the issue.

coalition for clean coal electricity andy ott tony clark — Clark | © *RTO Insider*

Speaking at the RTO Insider/SAS ISO Summit last week, Ott said the initiative was sparked by fuel security concerns — the risks of sabotage or cyberattacks on grid assets or gas pipelines — and a desire to recognize the reliability value of baseload nuclear and coal plants struggling to compete in the PJM market. Later in the panel discussion, former FERC Commissioner Tony Clark — participating via phone after snow canceled his flight from D.C. — forecast how the commission and the courts may rule on zero-emission credits that provide additional revenues to nuclear plants.

Ott said one possible shift in PJM would be changing contingency plans from replacing the largest single generator to ones that consider the loss of a gas pipeline supplying multiple generators.

“All the generation connected in a certain section of that pipeline could go off very quickly if it loses pressure because of an explosion or some event. Maybe we should be operating to the loss of that and look at that operational risk inside the market and price that in so the units that didn’t have that kind of fuel security risk would be worth more money,” Ott said. “That would help, of course, the resources that are less dependent on just-in-time fuel” such as nuclear and coal. Ott also said PJM will seek to become more “dynamic” in its management of operations.

Concern over Pipelines, Transmission Corridor

“One obvious [example] is to look at the way we deploy synchronized reserves or operating reserves and expand the contingency set that you’re looking at to include pipeline contingencies. … Or if you have a transmission corridor that you’re very worried about — potentially include that as part of your constraint set. So when you’re dispatching generation or deploying demand response, you’re essentially recognizing that double contingency or triple contingency as part of operations in certain circumstances. Not 8,760 hours [per year] but when you think that vulnerability exists, you can price it in.”

It also could mean system restoration plans becoming less dependent on individual transmission lines or fuel sources, Ott said.

Ott did not offer details on how fuel security would be priced into the markets. The RTO has already taken steps to address reliability concerns with its Capacity Performance rules, which increased penalties for nonperformance and rewards for overproduction during emergencies.

Coal Group Petitions PJM, MISO

On Friday, meanwhile, the American Coalition for Clean Coal Electricity (ACCCE) sent Ott a letter calling on PJM to take steps to prevent further retirements of coal-fired generation and “take into account the likelihood of changes to federal environmental policies.”

“We are confident the new administration will withdraw or rewrite environmental regulations that are causing, or could cause, more coal retirements,” ACCCE CEO Paul Bailey wrote. “These rules include the Clean Power Plan, Coal Combustion Residuals, Effluent Limitations Guidelines, Cross State Air Pollution Rule and Regional Haze.”

Bailey said the Capacity Performance rules were helpful but insufficient. “We do not think these changes go far enough in recognizing the advantages of baseload coal-fired generation. In particular, the changes have not led to higher capacity prices that are necessary to keep coal plants from prematurely retiring,” he wrote.

ACCCE says 121 coal-fired generators totaling 20.1 GW have retired in PJM, most because of environmental regulations, and another 28 plants (8.9 GW) have announced plans to shut down.

The group also sent a letter to MISO CEO John Bear asking the RTO to change rules “to ensure the reliability attributes of coal-fired generation … are properly valued.” MISO has lost 103 coal-fired generators (8 GW), with another 45 retirements (10.5 GW) pending.

Former Commissioner: FERC May Reject ZECs

Former Commissioner Clark, now a senior adviser at Wilkinson Barker Knauer, said zero-emission credits approved for nuclear plants in New York and Illinois — and under consideration in Connecticut and other states — may be rejected by FERC or the courts because of their impact on wholesale market prices. (See related story, Connecticut Moves Closer to Equating Nuclear with Renewables.)

Clark called ZECs the third iteration of states’ efforts to build or preserve generation within their borders. Last April, the Supreme Court rejected Maryland’s contract-for-differences with the developer of a combined cycle unit, saying that by tying the contract to PJM capacity prices, the state had violated federal jurisdiction.

In May, American Electric Power and FirstEnergy withdrew power purchase agreements that Ohio regulators had approved with their unregulated generation after FERC indicated it would review the deals for violations of affiliate abuse rules. “The merchant generators basically did a very surgical strike in [their] filing at FERC” in requesting the affiliate review, Clark said.

With ZECs, “the states … have really gotten craftier about how they can [preserve at-risk generators],” said Clark, noting that they were designed to be similar to state renewable energy credits (RECs).

“Merchant generators have … said these RECs are an out-of-market subsidy [that] distort prices. And the commission has said, ‘OK, theoretically we understand what you’re saying.’ But there wasn’t enough provable harm for the commission to really do anything about it,” Clark said. The RECs “were either conceptual at the time of the challenge … or it was a small enough part of the market … that it didn’t seem like it was a big enough issue that the commission could act on. So effectively the commission could punt on that issue.

“Now if you’re talking about certain regions of the country where nuclear units are 20%, 30% of the market, or if you’re talking about other out-of-market interventions like in the Northeast — you’ve heard about long-term power contracts … with Canadian hydro — that might be 30% of the state’s energy needs.

“Well that does have a very material impact on the market themselves, so that will be a challenge for the commission to see if this is a zero-sum game, or the commission will have to declare in some ways these things federally jurisdictional and carve the states out. Or is there a way to thread the needle? That’s what each of the ISOs that’s dealing with this is doing.

“Here’s where it will get to be very tricky for the commission,” Clark concluded. “I’m not sure exactly how it will end up dealing with it.”

March 21, 2017

IRC: Renewables’ Future Depends on Grid’s Ability to ‘Accommodate’

By Tom Kleckner

North America’s independent grid operators released a report Thursday that concludes the “ongoing effectiveness” of renewable technologies will depend directly upon the electric system’s ability to “accommodate them.”

The ISO/RTO Council (IRC)’s report, “Emerging Technologies: How ISOs and RTOs can create a more nimble, robust bulk electricity system,” concludes the future of the North American power grid depends on effectively adding renewables, the accuracy and availability of data from behind-the-meter resources and coordinating these distributed energy resources at the grid-operator level to preserve reliability.

The report captures the results of a study conducted by the IRC’s Emerging Technologies Task Force (ETTF), which was formed in 2015 to review the deployment of new technologies and identify where that deployment intersects with operational and policy considerations.

IRC renewables nick brown — “Technology precedes policy,” says SPP CEO Nick Brown, chair of the ISO/RTO Council. | © *RTO Insider*

The report notes more than 80% of North America’s wind and solar capacity lies in regions served by IRC members. These technologies face a serious challenge, the report said — the electric system itself.

SPP CEO Nick Brown, the IRC’s current chair, noted grid operators from different geographic regions “overlap … in their thinking” of the role emerging technologies will play.

Technology Precedes Policy

“Here’s the challenge: Technology always precedes policy,” Brown said during a panel discussion last week at the RTO Insider/SAS ISO Summit. “And as technology presents things, then we have to understand how to manage them [through] appropriate policies.”

The IRC is an affiliation of nine nonprofit grid operators that serve two-thirds of electricity consumers in the U.S. and more than half in Canada.

“Any time the IRC speaks with strong consensus on a matter like it has done here, I hope our industry takes notice,” Brown said in a news release.

“Each of the IRC member organizations is unique,” said ETTF Chair Edward Arlitt, of Ontario’s Independent Electricity System Operator. “One ISO or RTO may have greater solar capacity in their region, another may be farther along in their handling of DERs, and all of us have regulatory and operational constraints unique to the provinces, states and regions in which we serve.”

The task force used a straw poll to determine that handling emerging technologies was the highest-ranked priority among IRC members.

‘Imperatives’

The task force’s research produced what it called imperatives necessary to ensure the grid’s continued reliability and efficiency as the penetration of emerging technologies increases:

Manage the variability of supply and increasing levels of renewable integration enabled by emerging technologies. Is there enough “cohesive innovation” happening to integrate renewable generation, grid-scale energy storage and microgrids’ disparate components into the Bulk Electric System?

The IRC said while it is agnostic to specific technologies that may facilitate renewable integration, it supports policies that “accommodate emerging renewable integration technologies” and pursuing “continentwide consensus” on how much integration will be achieved through regional or interregional trade.

IRC renewables ceo nick brown — Computer-modeled load profiles for CAISO under various future scenarios of 20%-50% PV penetration.

The report recommends avoiding committing too early to specific technologies and calls for a “suitable policy environment” to ensure new technologies and approaches continue to be developed, tested and applied to renewable integration.

Address the IRC members’ lack of consistent, reliable, DER-related data as the grid becomes more distributed and less predictable.

The report says the lack of consistent and reliable data — such as between SCADA systems and new phasor measurement units (PMU) — should not constrain “situational-awareness arrangements” across transmission/distribution connections. It also says RTOs should have access to basic, static DER data series in their service territories. The task force said location, size and technological capabilities are examples of data needed to manage an increasingly distributed system.

The task force recommended developing an operations data framework flexible enough to handle local differences in DER penetrations.

Noting FERC’s November 2016 Notice of Proposed Rulemaking, which would require wholesale markets to accommodate energy storage and DER, the IRC suggests a formalized framework to help RTOs “harness the capabilities and manage the risks” of intermittent DER growth. (See FERC Rule Would Boost Energy Storage, DER.)

The task force recommends jurisdictions with distribution system operators (DSO) conform to standards that allow safe interaction between DSOs, non-utility entities and the Bulk Electric System. It said it supports policies that ensure if distribution-level variability poses risk to system reliability, RTOs have “appropriate authority” over DERs or mitigate their impact on the grid.

March 21, 2017

PJM, SPP Chiefs Share Frustration with Order 1000

By Rich Heidorn Jr.

CARY, N.C. — PJM CEO Andy Ott and SPP CEO Nick Brown said last week that FERC Order 1000 is causing their staffs headaches while doing little to encourage transmission development.

PJM SPP FERC Order 1000 — Nick Brown | © *Cassondra Wilson, SAS Institute Inc.*

“I think the driver behind Order 1000 was to get more people wanting to invest in transmission,” Ott told the RTO Insider/SAS ISO Summit last week, where he appeared on a panel with Brown and former FERC Commissioner Tony Clark, who participated via phone after snow canceled his flight from D.C. “We haven’t had any shortage of [interest]. In fact, everyone wants to invest in transmission because it’s a pretty safe investment. [Order 1000] was almost like a solution in search of a problem. … It’s actually creating more challenges to investment.”

“It created more overhead and more uncertainty at a time when we didn’t need more overheard in order to invest in transmission,” said Brown. “I am thankful that we completed the vast majority of our transmission buildout in a pre-Order 1000 environment.”

Ott said enforcing cost caps on competitive projects and allocating costs for them are tasks that RTOs are ill-equipped to handle. “We’re not a regulator,” he said.

Clark, who joined the commission after the order was issued in 2011, said the intent of the initiative was good, noting that it has pushed regions to conduct joint planning.

“The concern that I always had … is that there is so much process built into Order 1000,” each step of which becomes an opportunity for litigation and delay, Clark said.

“What you end up with is just what Andy and Nick were talking about, which is actually less investment happening than would otherwise happen organically on its own because you’re doing so much to meet the burdens of the process in Order 1000 that you’re sort of losing the forest for the trees.”

Clark said it’s too soon to determine whether the order will be successful in introducing competition into transmission development. “Incumbents have so many natural advantages in terms of building large infrastructure projects within their footprint that I don’t know that that’s something you can regulate away. Nor should we necessarily try to.”

March 21, 2017

Q4 Revenues up 7% for Top 30; Net Income Drops

By Rich Heidorn Jr.

Companies in the RTO Insider Top 30 reported revenues of more than $75 billion in the fourth quarter of 2016, a 7% increase over a year earlier, as all but five companies saw topline growth.

FirstEnergy, Public Service Enterprise Group, NextEra Energy and NRG Energy all reported revenue drops in the fourth quarter while Consolidated Edison was flat.

Similarly, all but five companies were profitable in the quarter. The exceptions were FirstEnergy (a $5.8 billion loss) Entergy ($1.8 billion), NRG ($987 million), Duke Energy ($222 million) and PSEG ($98 million). But the losses were so large they swamped their peers’ earnings, resulting in a cumulative loss of $2.62 billion for the quarter.

FirstEnergy reported a loss of $6.2 billion for the entire year, largely because of asset impairment and plant exit costs related to its decision to leave competitive generation by mid-2018. The company is seeking subsidies for its Davis-Besse and Perry nuclear plants in Ohio to make them attractive to buyers. (See FirstEnergy Seeking ZECs to Aid Sale of Ohio Nukes.)

Despite the fourth-quarter loss, Entergy, which also is exiting merchant nuclear generation, earned $1.27 billion for the year ($7.11/share), beating Zacks’ consensus estimate of $6.83/share. (See Entergy Beats Expectations Despite 80% Drop in Earnings.)

Avangrid’s 29% jump in Q4 revenues and more than doubling of net income reflected the first full year of operations including UIL Holdings, which it acquired in December 2015.

Edison International earned $377 million in the fourth quarter, versus a $50 million loss a year earlier. In February, its Southern California Edison unit joined with other investor-owned utilities in proposing spending $1 billion on transportation electrification. SoCalEd plans to spend $573 million, including pilot projects for electric transit buses and electrification of cargo handling equipment at the Port of Long Beach.

Edison CEO Pedro Pizarro said the company has “scaled back business development” at Edison Transmission because of “limited FERC Order 1000 opportunities in our target markets.” The company will continue its role in the Grid Assurance initiative to pool inventory and develop best practices to support transmission system reliability.

Dominion earned $457 million for the fourth quarter, a 28% jump, thanks to its acquisition of Questar, which added 56 Bcf of gas storage and 3,400 miles of gas transmission to its assets. Due in part to the acquisition, the company announced last month it was rebranding and replacing “Resources” with “Energy” in its name. The company now does business in 18 states. (See Dominion Resources Changing Name to Dominion Energy.)

The company could see a boost to earnings if Connecticut lawmakers approve legislation providing additional revenues for its Millstone nuclear plant. (See related story, Connecticut Moves Closer to Equating Nuclear with Renewables.)

Company	Market Cap ($ billions)	Revenue Q4 2016 ($ billions)	% change vs. 2015	Net income Q4 2016 ($ millions)	% change vs. 2015
NRG Energy	$3.87	$2.53	-16%	($987.00)	NA
NextEra Energy	$55.91	$3.70	-9%	$966.00	91%
Public Service Enterprise Group	$22.15	$2.09	-8%	($98.00)	NA
FirstEnergy	$13.70	$3.38	-5%	($5,796.00)	NA
Consolidated Edison	$21.63	$2.71	0%	$206.00	17%
Berkshire Hathaway Energy	NA	$4.17	1%	$483.00	1%
Pinnacle West Capital	$8.66	$0.74	1%	$53.25	29%
Great Plains Energy	$5.89	$0.58	2%	$98.00	328%
PPL	$23.14	$1.83	3%	$465.00	17%
Ameren	$12.73	$1.36	4%	$32.00	10%
American Electric Power	$30.96	$3.79	5%	$373.40	-20%
Eversource Energy	$18.65	$1.78	5%	$231.10	26%
Entergy	$13.11	$2.65	6%	($1,765.54)	NA
Xcel Energy	$20.64	$2.79	6%	$227.48	9%
WEC Energy Group	$18.51	$1.96	6%	$194.70	8%
Alliant Energy	$8.63	$0.80	8%	$65.20	78%
Sempra Energy	$25.18	$2.91	8%	$379.00	3%
CMS Energy	$11.62	$1.64	9%	$77.00	-27%
Calpine	$4.10	$1.58	10%	$24.00	NA
Westar Energy	$7.99	$0.61	11%	$53.94	37%
PG&E	$33.86	$4.71	13%	$696.00	404%
Duke Energy	$54.33	$4.82	14%	($227.00)	NA
DTE Energy	$17.68	$2.87	16%	$131.00	64%
Centerpoint Energy	$10.61	$2.08	16%	$101.00	NA
Exelon	$32.79	$7.87	18%	$204.00	-34%
Nisource Inc	$7.15	$1.30	18%	$88.80	49%
OGE Energy	$6.68	$0.53	19%	$57.90	97%
Dominion Energy	$48.10	$3.09	21%	$457.00	28%
Edison International	$23.46	$2.88	23%	$377.00	NA
Avangrid	$11.70	$1.49	29%	$207.00	116%
Total		$75.23	7%	$(2,625)	-35%

NOTE: No % change is listed for net income if either the current quarter or previous year was a loss.

March 20, 2017

MISO, PJM Find Value in CPP Study, Despite Rule’s Likely Demise

By Amanda Durish Cook

CARMEL, Ind. — EPA’s Clean Power Plan may be undone by the Trump administration, but MISO and PJM officials say their recently completed study on the rule yielded some valuable insights nonetheless.

“The CPP provides a good stress test to illustrate not only the value of interregional coordination but state coordination, as new policies and/or regulations are considered,” the RTOs opined in the study, which was released last week.

The study examined Michigan, Indiana, Illinois and Kentucky — states on the RTOs’ seam — and focused on transmission congestion, generation mix, production costs and economic trading.

PJM Net Exporter

Coal retirements and new combined cycle gas additions would make PJM a net exporter of power to MISO by 2030 because PJM’s gas additions “are located much closer to shale formations and thus have a lower fuel delivery basis and lower operating cost than the MISO resources,” according to the study. Over the last five years, the net scheduled interchange between the two regions has varied, with each at times being a net seller.

EPA trump clean power plan — Map shows MISO-PJM seams with states in both RTOs framed in brown | *MISO, PJM*

The study also found that transmission congestion costs would rise by between $1.1 billion and $1.8 billion between 2025 and 2030 if the CPP is enforced. The increase is owed to higher fuel prices and load, new generation constructed without transmission reinforcements, outages and policy decisions that shift the locations of the most economic sources of generation.

It projects LMPs would be between $54 and $70/MWh by 2030, with MISO having a slighter higher LMP than PJM under all CPP scenarios.

The report identified three variables — natural gas prices, the geographic scope of emissions trading and how much energy efficiency can count toward compliance — as “key drivers” and used them as sensitivities in the study.

Gas Price Impact

The analysis agreed with previous CPP studies by the RTOs that concluded that the cost of natural gas would be the biggest single determinant in the cost of compliance. “The price of natural gas has by far the biggest impact,” MISO Senior Policy Studies Engineer Jordan Bakke said at a March 15 Planning Advisory Committee meeting. (See MISO: Coal Retirements, Gas Prices, Flexibility Key to CPP Compliance Costs and PJM: Regional Plan Cuts Costs, but Gas Prices are Wild Card for CPP Compliance.)

The study found that standardizing state energy efficiency measurement and verification rules would allow commoditization of credits across broader markets, helping to offset deployment costs. “Non-similar state policies can drive significant economic distortions along the MISO-PJM seam and exacerbate transmission cost impacts,” the report said. “Conversely, the ability to transact fungible products amongst states results in greater market efficiency.”

Both RTOs used previous analyses for the study, MISO bringing its 2017 Transmission Expansion Plan policy regulations future and PJM supplying its September 2016 CPP study. The earlier studies showed that state emissions credit trading resulted in “lower costs, fewer generation retirements and more efficient generation investment.”

MISO and PJM began the study six months ago, after the CPP was stayed by the Supreme Court but before Trump’s election. “The political landscape was a lot different a year ago,” Bakke acknowledged. “But we still find value in this entire exercise.”

Bakke said the analysis would only be used for informational purposes at this point and would not influence MTEP 18 futures. He also said the study could become a template for future cross-RTO policy analyses.

The study is the first policy-focused study MISO has ever completed with another RTO, according to Bakke. “I think this helped open the lines of communication,” he said.

Both MISO and PJM said the study should not be viewed as a recommendation for complying with the CPP. “However, states, utilities and other entities can consider the observations made from this analysis within the specific context of the CPP or in a broader context as they consider other policy goals that can influence already dynamic economic interactions in electric markets,” they wrote.

March 20, 2017

MISO’s Competitive Tx Evaluation Costs $1.3 Million

CARMEL, Ind. — MISO spent $1.3 million to evaluate construction bids in its first competitive transmission process, including administrative costs for issuing the request for proposals and drafting a post-selection report.

The work was funded entirely by the 11 developers that submitted proposals. Brian Pedersen, senior manager of competitive transmission, said MISO required a $100,000 deposit from each of the 11 developers to fund the cost of Duff-Coleman bid evaluation, but the RTO had to bill each of them another $21,000 to make up for all evaluation costs.

Stakeholders asked how the process could be streamlined to reduce costs.

“There aren’t a whole lot of economies to scale, since we still have to evaluate everything,” Pederson said at the March 15 Planning Advisory Committee meeting.

The RTO and stakeholders would discuss evaluation criteria and process transparency during the April meeting of the new Competitive Transmission Task Team, he said. May’s meeting will focus on possible improvements to MISO’s developer qualification process.

MISO competitive transmission — | *MISO*

Pederson also said MISO will publicly post information from Republic Transmission’s first quarterly report on the Duff-Coleman project sometime during the second quarter. (See LS Power Unit Wins MISO’s First Competitive Project.)

— Amanda Durish Cook

March 20, 2017

Changes to Put CAISO Market Monitor Under Full Board Oversight

By Robert Mullin

CAISO’s Board of Governors last week approved a measure investing the board with complete oversight authority over the grid operator’s internal Market Monitor.

The change comes in response to FERC’s recommendations in a 2016 audit report that found that SPP executives had “inappropriate” involvement in the oversight of that RTO’s internal Market Monitoring Unit. (See FERC Calls for Changes to Protect SPP Market Monitoring Unit Independence.)

caiso market monitor board of governors — Collanton | © *RTO Insider*

“This is our response to FERC guidance on oversight of the Department of Market Monitoring,” Roger Collanton, CAISO general counsel, said during a March 15 meeting of the board. “In particular, [we’re] giving the board more direct oversight over the administrative functions of market monitoring in order to enhance the appearance and, in fact, the independence for market monitoring.”

CAISO’s Tariff currently outlines a “dual” reporting structure in which the department is subject to direct board oversight for its “core” monitoring responsibilities, while at the same time reporting to the ISO’s CEO for administrative purposes, which include budgeting and staffing matters.

The new arrangement calls for the establishment of an Oversight Committee to be staffed by governors Ashutosh Bhagwat and Angelina Galiteva. It will be charged with overseeing the department’s administration and operations, including determining staffing levels and compensation, setting departmental goals, approving budgets and ensuring that the ISO is providing adequate corporate support. The committee will operate under a newly created charter.

“The arrangement will still allow for the Department of Market Monitoring staff, as well as the director, to communicate directly with the [full] board as they need,” said Greg Fisher, senior counsel with the ISO. “However, the Oversight Committee will be something that they can reach out to for various issues.”

Fisher said the proposed changes arose out of a review of the recommendations from FERC’s audit of SPP, discussions with FERC staff currently auditing the ISO and consultation with DMM Director Eric Hildebrandt.

“I just want to emphasize that we’re very supportive of this,” Hildebrandt said. “We’re looking forward to working with the Oversight Committee, but as [Fisher] mentioned, this is really just to bring our organization in line with what FERC identified as best practices based on some other ISOs.”

Hildebrandt went on to laud CAISO CEO Steve Berberich for supporting the Monitor’s independence and for “always” having provided the necessary resources and staffing for the department. Hildebrandt called the prospect of direct engagement with the CEO and the Oversight Committee “the best of both worlds.”

“I support these [changes] under one condition, and that’s that I can continue to have that kind of relationship with [Berberich] and interface with him,” Hildebrandt said. “I think that’s very helpful in just our working as an internal Market Monitor.”

“The charter is designed with that type of flexibility in mind, so that the Oversight Committee has full ability to delegate responsibility as it sees fit to management, as well as anticipating that same type of collaboration and interaction with management,” Collanton said.

March 20, 2017

Board Approves CAISO Small TO Generator Interconnection Plan

By Robert Mullin

CAISO’s Board of Governors last week approved a proposal designed to prevent smaller transmission owners from footing the costs for network upgrades needed to interconnect generation serving load outside of their service territories.

generator interconnection plan caiso — Valley Electric Association serves about 18,000 customers in a sparsely populated region along the California-Nevada border. | *VEA*

The plan was the product of seven months of work by CAISO staff and stakeholders to address a situation facing Valley Electric Association — one that could also apply to other small utilities that join the ISO in the future. (See CAISO Issues Final Proposal for Small TO Interconnection Costs.)

Valley Electric, a Nevada-based cooperative serving about 18,000 electric customers in a sparsely populated area along the California-Nevada border, has recently been targeted as a promising site for developing solar projects intended to help California achieve its 50% by 2030 renewable portfolio standard.

Avoiding Rate Shock

“This proposal addresses the rate shock that would happen for a small [TO] and would have de minimis impact on larger [TOs],” Stephen Rutty, CAISO’s director of grid assets, told the board during its March 15 meeting.

Rutty pointed out that only a handful of CAISO stakeholders opposed the proposal, which would require the ISO to determine on a case-by-case basis whether a candidate TO could be allowed to fold low-voltage generator interconnection costs into high-voltage transmission revenue requirements, thereby spreading costs among the ISO’s entire ratepayer base. San Diego Gas and Electric demurred, citing a concern that CAISO’s solution did not meet FERC cost allocation rules.

The proposal requires that an eligible TO be very small relative to others (with a gross load of 2 million MWh or less), located in a renewable resource-rich area gaining “elevated” interest for generator procurements and not in need of the new interconnecting generation to meet an RPS.

CAISO has estimated that a single $10 million network upgrade required by new generation would increase Valley Electric’s combined high- and low-voltage transmission access charge (TAC) by nearly 14%.

“However, if they are allowed, under this proposal, to put it into their high-voltage TAC, their increase would be about 0.04%, and the rest of the [participating TOs] would see a very similar de minimis impact,” Rutty said.

150 MW New Generation vs. 130 MW Load

Valley Electric representative Josh Weber, an attorney with Davison Van Cleve, sought to provide some additional context for the board.

“Valley’s peak load, out there in the desert when the air conditioners are all running and it’s 114 degrees outside, is somewhere around 130 MW,” Weber said, adding that the cooperative is currently negotiating about 150 MW worth of generator interconnection agreements. Those deals alone could incur $6 million to $9 million in upgrade costs for the 138-kV lines that would be subject to the proposed rule.

“So that means that the generation that Valley is working hard to interconnect is much, much more than Valley’s entire peak load,” Weber said. “I think that kind of speaks to the magnitude of the cost shift that we’re talking about here.”

Speaking on behalf of the Large-scale Solar Association, California Wind Energy Association and Independent Energy Producers Association, attorney Joe Karp offered his support for the proposal.

“Several options were considered, and this option is a narrowly tailored option that addresses a unique issue,” Karp said. “We believe the solution here is consistent with general FERC and [CAISO] policy on allocating infrastructure and upgrade costs.”

Catherine Hackney, director of state legislative policy for Southern California Edison, provided an additional endorsement, saying her utility appreciated the ISO’s efforts to narrow the proposal to fit Valley Electric’s circumstances.

Cost Allocation Concerns

SoCalEd’s neighbor to the south, however, took a contrary position.

“San Diego Gas and Electric agrees with just about everybody that something needs to be done, but I think the solution here that’s been identified is, frankly, inconsistent with FERC’s policy on cost allocation,” said Jan Strack, SDG&E’s manager of transmission planning.

FERC has been “pretty clear” that costs for transmission projects should follow benefits, Strack said.

“Instead, what we have in this proposal is a one-off kind of allocation mechanism where the size of the entity suddenly takes on great weight,” he said. “Nowhere in FERC’s cost allocation principles do I see any principle that size matters.”

Strack said the ISO still needs to determine the best way to establish a linkage between benefits and costs of transmission projects.

“I think until that exercise has been gone through, it will be very premature to go forward with this one-off, unprincipled approach to allocating transmission costs just on the basis of the size of the entity,” he said.

Strack contended that all electricity users benefit from the reduced carbon emissions and lower prices fostered by new renewable generation.

“Pretty much everybody realizes benefits from these connections, so to divide this up between low- and high- [voltage] — even in the way the ISO is proposing here — is a mistake, and I don’t think it’s going to survive a test at FERC,” Strack said.

“Size was not the only criteria here,” countered Keith Casey, CAISO vice president for market and infrastructure development. “The other piece of that was that [Valley Electric] did not have an RPS [and] did not benefit from renewables connecting to its system.”

Casey agreed that FERC’s principles require costs to follow benefits, but he said that Valley Electric’s lack of benefits from the new generation would provide a “principled” argument to FERC.

He also contended that FERC must in this case consider the issue of “just and reasonable” rates.

“Imposing that cost on a small number of customers when you’re looking at a 14% increase in just one year — we think there’s an issue there around the just and reasonableness of that,” Casey said.

March 20, 2017

MISO-SPP Coordinated Study Yields 1 Possible Project – For Now

By Amanda Durish Cook

CARMEL, Ind. — Preliminary results of MISO and SPP’s 2016 coordinated system study are in, and the RTOs say one South Dakota project has potential even though it fails MISO’s $5 million interregional cost threshold.

Davey Lopez, MISO advisor of planning coordination and strategy, said the project — the Split Rock-Lawrence 115-kV circuit into Sioux Falls, S.D. — costs $4.56 million but is still a strong contender at a 4.79 benefit-cost ratio. The RTOs would split the benefit of the transmission project at 56% for MISO and 44% for SPP.

“This project still shows high potential to be an interregional project. … Both MISO and SPP are open to removing that hurdle,” Lopez said of MISO’s threshold. MISO won FERC approval to shed its $5 million cost minimum and 345-kV limit with PJM last year in favor of no cost floor and a 100-kV threshold. But the commission said the order did not apply to the MISO-SPP process. (See FERC Signals Bulk of NIPSCO Order Work Complete.)

The RTOs looked at seven needs for the coordinated study: two shared tie-lines, one MISO project and four SPP projects. Three of the seven possible projects are unlikely to move forward, MISO stakeholders learned at a March 15 Planning Advisory Committee meeting.

MISO’s Planning Advisory Committee Meeting | © *RTO Insider*

Three other projects passed joint operating agreement cost and benefit tests, but the RTOs still have reservations:

The $8 million Lyon County 345/115-kV transformer in South Dakota has a 1.14 B/C ratio and could be split 8% to MISO and 92% SPP according to regional benefit. However, MISO and SPP say those preliminary results are “highly dependent” on solar expansion in the area and said more analysis is needed before recommendation.
The $8.3 million Crosstown-Blue Valley 161-kV line in Missouri has a 3.34 B/C ratio and could be portioned 32% to MISO and 68% to SPP. SPP staff is currently evaluating whether its own solution could be more cost-effective, and MISO says that to pursue the project, it would have to revise its cost allocation process because the line is below 345 kV.
The $25 million New Brookline-James River 345-kV line and new 345/161-kV James River transformer in Missouri has a 2.06 B/C ratio and could be divided 19% to MISO and 81% to SPP. But SPP is again examining its own regional solution and MISO is testing its own regional criteria because the project is located wholly outside of MISO and because MISO’s adjusted production cost is not in synch with SPP’s.

PAC Chair Cynthia Crane said the RTOs’ mismatched adjusted production cost calculations seem to be driving a lot of MISO’s cost allocation issues.

Lopez said both RTOs will make efforts in the future to align their adjusted production cost calculation. He also said the study’s sub-345-kV projects must be regionally approved on a case-by-case basis because of the 345-kV prerequisite.

The remaining three projects in the coordinated study either failed the 5% minimum regional cost benefit percentage or the $5 million project floor. In all three cases, either MISO or SPP will continue to evaluate the projects in their own regional processes.

More testing is needed to come up with a final list of projects, Lopez said.

The RTOs will finalize the coordinated study’s findings and publish a report in late April. At that time, the Interregional Planning Stakeholder Advisory Committee will vote on which recommended projects might proceed. The MISO side of the IPSAC vote will be conducted through the PAC.

MISO still maintains that the coordinated study will influence a longer-term joint study between the RTOs in 2017, although it’s unclear when they will work together on future interregional projects. Stakeholders learned earlier this month that a comprehensive MISO-SPP joint study is unlikely to occur in 2017. (See “Long Odds for 2nd MISO-SPP Joint Study,” SPP Briefs.)

The coordinated study was originally meant to focus on needs along SPP’s Integrated System in North Dakota, South Dakota and Iowa, and some stakeholders were doubtful that any projects would materialize. (See MISO-SPP Study Scope Finalized; Stakeholders Doubtful Projects will Result.) Last year, the IPSAC identified an initial list of high priority seams efforts for the study.