Page 1284 – RTO Insider

August 15, 2017

Q2 Good Collectively for Top 30, but Only Half Post Gains

By Peter Key

The RTO Insider Top 30 collectively had a good second quarter, but nearly half the companies turned in worse bottom-line performances than a year ago.

The Top 30’s total income rose 18.1% to $5.9 billion on an 8.2% increase in revenue to $75.4 billion. In all, 26 companies were profitable in the quarter, but only 16 saw their income rise from a year earlier. Eleven posted income declines, one — Great Plains Energy — swung to a loss, and two saw their losses increase.

Sempra Energy posted the largest percentage increase in net income, earning $248 million in the quarter, up from only $27 million the year prior.

On an adjusted basis, Sempra’s earnings increased to $276 million from $200 million the year before. Excluded from the calculations for the last quarter were a $47 million impairment of Sempra Mexico’s Termoeléctrica de Mexicali assets and $28 million in recoveries related to a permanent release of pipeline capacity. Also excluded were $123 million in losses from the release of pipeline capacity at Sempra LNG & Midstream and about $60 million in deductions related to a 2016 rate case at its California utilities.

earnings RTO Insider Q2 2017 — | *Company Filings*

Pacific Gas and Electric posted the second largest percentage increase in net income, nearly doubling profits to $406 million. In its earnings press release, the company attributed the gain to two rate cases.

NextEra Energy had the third largest percentage increase at 47%, as its net income rose to $793 million. CEO Jim Robo attributed the gain primarily to new investments at the company’s Florida Power & Light and NextEra Energy Resources subsidiaries.

Company	Market Cap ($ billions)	Revenue Q2 2017 ($ billions)	% change vs. 2016	Net income Q2 2017 ($ millions)	% change vs. 2016
Alliant Energy Corp	$9.6	$0.77	13.23%	$94.30	12.40%
Ameren Corp	$14.1	$1.54	7.78%	$193.00	31.29%
American Electric Power Co Inc	$34.7	$3.58	-8.13%	$375.00	-25.31%
Avangrid	$14.4	$1.33	-7.51%	$120.00	17.65%
Berkshire Hathaway Energy Co	NA	$4.55	10.51%	$574.00	7.09%
Calpine Corp	$5.0	$2.08	79.04%	$(216.00)	NA
Centerpoint Energy Inc	$12.4	$2.14	36.15%	$135.00	NA
CMS Energy Corp	$13.3	$1.45	5.69%	$92.00	-25.81%
Consolidated Edison Inc	$25.3	$2.63	-5.76%	$175.00	-24.57%
Dominion Resources Inc	$49.7	$2.81	8.28%	$390.00	-13.72%
DTE Energy Co	$19.4	$2.86	26.22%	$177.00	16.45%
Duke Energy Corp	$60.0	$5.56	6.56%	$686.00	34.77%
Edison International	$25.9	$2.97	6.77%	$278.00	-0.71%
Entergy Corp	$13.7	$2.62	6.33%	$409.92	-27.74%
Eversource Energy	$19.6	$1.76	-0.25%	$230.75	13.31%
Exelon Corp	$36.0	$7.62	10.32%	$80.00	-70.04%
FirstEnergy Corp	$14.3	$3.31	-2.71%	$174.00	NA
Great Plains Energy Inc	$6.7	$0.68	1.76%	$(22.10)	NA
NextEra Energy Inc	$69.1	$4.40	13.77%	$793.00	46.85%
NiSource Inc	$8.6	$0.99	10.37%	$(44.40)	NA
NRG Energy Inc.	$7.8	$2.70	20.15%	$(626.00)	NA
OGE Energy Corp.	$7.1	$0.59	6.35%	$104.80	46.57%
PG&E Corp.	$35.4	$4.25	1.94%	$406.00	97.09%
Pinnacle West Capital Corp	$9.9	$0.94	3.19%	$167.44	38.03%
PPL Corp	$26.4	$1.73	-3.36%	$292.00	-39.54%
Public Service Enterprise Group Inc	$23.0	$2.13	11.97%	$109.00	-41.71%
Sempra Energy	$29.0	$2.53	17.49%	$248.00	818.52%
Wec Energy Group	$20.1	$1.63	1.84%	$199.10	9.76%
Westar Energy Inc	$7.2	$0.61	-1.95%	$72.07	-0.38%
Xcel Energy Inc	$24.5	$2.66	8.78%	$227.26	15.48%

Totals		$75.4	8.24%	$5,894	18.56%

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

All wasn’t tangerines and cream for NextEra during the quarter, however, as the company had its attempt to acquire Oncor rebuffed a third and final time by Texas regulators. (See NextEra Seeks $275M Fee for Failed Oncor Bid.)

FirstEnergy posted the largest earnings gain in dollars during the quarter, rebounding from a loss of $1.1 billion in the second quarter of 2016 to post a net income of $174 million. Despite the improvement, CEO Chuck Jones declared during the company’s earnings call that he thinks the “country is heading for a disaster” because of its heavy reliance on natural gas for power generation. (See FirstEnergy CEO Says Country Heading for Natural Gas ‘Disaster.’) FirstEnergy’s large loss last year was because of the closure of five uneconomic coal plants; it says it is getting out of the competitive generation business.

NRG Energy lost the most money ($626 million) in the quarter and saw its loss increase the most ($433 million). It actually earned $93 million from continuing operations, however, and in its earnings conference call, CEO Mauricio Gutierrez expressed optimism about the lawsuits against the zero-emission credit programs in New York and Illinois in which the company is a plaintiff, even though both were dismissed last month. Appeals are pending. (See NRG CEO Hopeful About ZEC Suits, Company Future.)

Calpine posted the second largest loss, $216 million, after losing $29 million in the second quarter of last year. The Houston-based merchant generator had an adjusted profit of $419 million in the quarter, and Bloomberg reported that it was in talks to be acquired. (See Q2 2017 Earnings Briefs.)

Exelon, which stands to benefit from the ZEC programs if they are upheld, posted the largest decrease in net income, dropping 70% to $80 million, because of a $250 million loss from its generation division. (See Exelon Confident on ZECs; Will Seek PJM Changes.)

August 14, 2017

ERCOT Board of Directors Briefs: Aug. 8, 2017

Rising natural gas prices will likely mean an end to ERCOT’s all-time low energy prices, according to the Independent Market Monitor’s midyear review of the Texas grid operator’s market.

ERCOT board of directors natural gas prices — IMM Director Beth Garza | © *RTO Insider*

IMM Director Beth Garza told the ERCOT Board of Directors last week that real-time prices are up almost 40% over the first half of 2016, averaging $28.50/MWh, compared to $20.41/MWh during the same time last year.

The load-weighted average for all of 2016 was $24.62/MWh — the lowest ever since the nodal market’s implementation in late 2010. (See “IMM Year in Review: Low Prices, Windy, Lots of RUC,” ERCOT Board of Directors Briefs.)

Garza said the rise in prices is linked to a corresponding increase in gas prices, which have gone from less than $1.70/MMBtu in early 2016 — “The lowest gas prices I’ve certainly seen in my career,” Garza said — to pennies shy of $3/MMBtu this month. Gas prices averaged $2.45/MMBtu in ERCOT last year.

The Energy Information Administration has attributed the rising prices to an increase in exports to Canada and Mexico. The Mexican energy market in recent years has been replacing coal- and oil-fueled generation with natural gas.

The increasing cost of gas has also resulted in a decrease of its use for generation. Gas accounted for 35% of ERCOT’s fuel generation during the first half of the year, down from 44% for all 2016. Coal and wind sources have picked up the slack, increasing to 32% and 21%, respectively, through June, up from 29% and 15% last year.

Garza also noted that price spreads between ERCOT’s cheapest (West) and most expensive (Houston) zones have been increasing as well, from a $4 spread in the first half of last year ($18 to $22/MWh) to $11 through June 2017 ($23 to $34/MWh), because of increased congestion. ERCOT’s top 10 constraints have accumulated approximately $375 million in congestion costs, more than halfway to last year’s total of about $500 million.

“So, [there is] more frequent, more costly congestion going along with those higher prices,” Garza said in summation.

Much of that congestion occurs in the Houston zone. A constraint on a path that imports energy from the north has incurred more than $90 million in costs through the first six months, almost double its $49 million in congestion costs for all of 2016.

The Houston Import Project, a $590 million project scheduled to be completed by summer 2018, is expected to resolve much of the congestion. In the meantime, however, lines being taken out of service to enable construction of new facilities has exacerbated the problem, Garza said.

“I think that’s what we’re seeing this year,” she said.

ERCOT CEO Bill Magness said higher-than-expected congestion in the day-ahead market also resulted in a surplus in the congestion revenue rights (CRR) balancing account. The unexpected balance resulted in a $24.2 million credit to load in June.

Gas Production Affects Texas Grid

Todd Staples, president of the Texas Oil & Gas Association, said fracking and improved technologies that have reduced the cost of natural gas have also made the U.S. the largest producer of natural gas in the world.

Natural gas production has grown almost 30% since 2010, Staples said, with Texas leading all states by accounting for more than 27% of U.S. marketed natural gas production in 2015. The Lone Star State also has 90 Tcf of proven natural gas reserves, 26% of the nation’s total.

“Low-cost natural gas is the reason you’re seeing billions of dollars of capital investment in Texas for today and the long haul,” Staples said. “This capacity is the reason you see the strength of continued planned investment and development in Texas. This infrastructure, what we have in place today and what is planned for the future, is the reason we think we’ll have this continued growth.”

Much of the production takes place in the Permian Basin of West Texas. Staples said he expects “the Permian will be active no matter the highs and lows of the investment market.”

Warren Lasher, ERCOT’s senior director of system planning, said natural gas production, consumption and exports are causing localized growth in electric demand. He pointed to the natural gas extraction in the Permian Basin but also noted industrial demand near Houston and the several LNG facilities being built on the Gulf of Mexico.

“We’re working with providers in the area to ensure we’re meeting their demand,” Lasher said.

He said ERCOT is beginning a study to ensure the existing pipeline capacity can meet demand, given recent changes to both the natural gas system and the ISO’s grid. A 2012 assessment of the Texas region’s natural gas infrastructure found the existing pipeline capacity was sufficient to meet demand, even with the expected growth of natural gas generation capacity.

Recent staff planning studies have not identified any single points of disruption on the natural gas system that would have a significant impact on ERCOT generation capacity, Lasher said.

“It’s not an issue now,” he said, “because there’s so much pipeline capacity in Texas.”

ERCOT on Track to Finish 2017 $5M Under Budget

Magness said the ISO is projecting a $4.5 million favorable variance in net revenues at year’s end, based on current balances and the load forecast for the remainder of 2017. A $3.1 million savings in interest expenses for project funding is $3.1 million under budget because of minimal use of revolving lines of credit.

July’s record-breaking demand helped ERCOT erase $1.3 million of a $2.1 million unfavorable variance in system administration fees. The Texas grid has yet to break 70 GW this summer, “but there’s a lot of August yet,” Magness said.

Staff has forecasted a peak demand of 72.9 GW this summer, which would break last August’s record peak of 71.1 GW. (See Texas Heat Leads to more ERCOT Demand Records.)

While Texas has sufficient capacity to meet demand, more is on the way. Magness said ERCOT had received 306 active generation interconnection requests totaling 67.6 GW — including 30.2 GW of wind generation — at the end of June. The ISO had 19.3 GW of wind capacity in commercial operation as of July 1.

Magness also said the Aug. 21 solar eclipse will have a “likely minimal” impact on the ERCOT region, with much of it in North Texas. Ancillary services and the solar forecast will address the expected effects, he said.

However, the April 8, 2024, eclipse’s line will pass over the middle of Texas. “So that’s something to look forward to,” Magness said.

Board OKS 2 Revision Requests, SCR

The board’s unanimously approved consent agenda included two nodal protocol revision requests (NPRRs) and a system change request (SCR):

NPRR822: Designates the procedure for identifying resource nodes as an “other binding document” instead of a “business practice manual.” It also adjusts the process for handling a retired resource’s nodes by allowing ERCOT to convert CRRs at that node to a different, nearby settlement point.
NPRR833: Adjusts NPRR827’s language to account for the base-case model when ERCOT implements the long-term, automated change affecting point-to-point (PTP) obligation bid clearing. The NPRR updates the day-ahead market optimization engine to address situations where a contingency disconnects a resource node. The engine will pick up the PTP megawatts and distribute them to other nodes, instead of ignoring them in contingency analyses if that PTP sources or sinks at the disconnected point.
SCR792: Allows ERCOT to send consecutive clock-minute average exceedances of balancing authority area control error limits to appropriate entities, and creates a situational awareness display in the information system’s public area showing the exceedances.

— Tom Kleckner

August 14, 2017

SPP Briefs: Week of Aug. 15, 2017

NERC will host a webinar Aug. 25 to help the current members of SPP’s Regional Entity (RE) transition to new compliance authorities.

SPP said last month it would dissolve its RE, addressing NERC and FERC concerns about the RTO’s dual roles as a grid operator and reliability coordinator. Pending approval by the two regulatory bodies, the SPP RE will cease to exist by the end of 2018. (See SPP to Dissolve Regional Entity.)

The SPP RE’s trustees sent a letter to its members Friday, advising them that NERC will issue a formal announcement about the webinar “shortly.”

The trustees said NERC will “improve the quality of the information you are receiving” by managing the transition process going forward. The letter alludes to “confusion and perhaps inconsistent information flowing between you and the other regional entities involved in this transition.”

NERC is working with the 120 registered entities within the SPP footprint to transfer to other REs. It has asked the entities to select a new RE by Sept. 29. All changes must be approved by NERC’s independent Board of Trustees, then filed with FERC for its approval.

Committee Recommends Interregional Project Approval

The Seams Steering Committee last week recommended that SPP’s Economic Studies Working Group (ESWG) approve an interregional project with MISO in South Dakota, following a regional review.

The project, which loops a Split Rock-Lawrence 115-kV circuit into Sioux Falls to relieve congestion on the Lawrence-Sioux Falls 115-kV line, has been endorsed by the RTOs’ Interregional Planning Stakeholder Advisory Committee. The project is shared by the Western Area Power Administration in SPP and Xcel Energy in MISO. (See “Interregional Project Begins Regional Review,” SPP SSC Briefs: June 14, 2017.)

MISO would pay 81.48% of the project’s estimated $6.15 million in engineering and construction costs, with SPP covering the remainder.

Staff said the scope of the ESWG regional review was amended to evaluate opening the 115-kV line between Sioux Falls and Lawrence. However, staff’s analysis found that option did not provide SPP with positive benefits across all sensitivities and could potentially create congestion on different constraints in the area.

The SSC refrained from voting on the project during its Aug. 9 meeting and will wait until the ESWG conducts its vote when it meets this week in Denver.

The SSC and ESWG are directing the regional review. They plan to make a final recommendation to the Markets and Operations Policy Committee in October.

Staff Addressing Historical Congestion on MISO Seam

The SSC also discussed staff’s early draft of a business practice to address historical market-to-market (M2M) congestion on the SPP-MISO seam.

flowgates SPP Regional Entity NERC — | *SPP*

Staff’s proposal, based on SPP’s business practice for non-FERC Order 1000 seams projects, would create a new project type for small, low-cost interregional upgrades with short lead times. These targeted market efficiency projects (TMEPs) would address locations with consistent congestion limiting the ability of lower-cost generation to reach load.

The TMEPs’ benefit determination method would avoid complicated production cost models and simulations, significantly reducing the analysis period and potentially allowing faster project implementation.

Stakeholders noted transmission owners could simply undertake the projects themselves as sponsored projects and suggested aligning the study timeline with the integrated transmission planning process or joint coordinated system plan, as MISO has done.

Staff said it would develop a list of the top 10 flowgates that could potentially qualify for TMEP treatment.

M2M Payments Reverse in MISO’s Favor

Continuing a summer trend seen since SPP and MISO began their M2M process in March 2015, payments between the two RTOs reversed themselves in June, with SPP paying its neighbor almost $644,774 for congestion on flowgates between the two.

Temporary flowgates accounted for most of the congestion, binding for 315 hours. That resulted in almost $1.1 million in M2M settlement charges to SPP, balanced somewhat by $453,321.84 in its favor for 190 hours in binding on permanent flowgates.

SPP has collected $21.7 million in M2M settlements from MISO, with much of that coming during the winter and shoulder months. MISO has collected payments during summer months, although in minimal amounts.

— Tom Kleckner

August 14, 2017

CAISO Launches Generator Interconnection Effort

By Jason Fordney

CAISO said it will kick off an initiative to refine its generation interconnection process later this year as part of an ongoing effort to accommodate renewables and keep its rules updated.

The grid operator is in the beginning stages of its Interconnection Process Enhancements 2018 program but wants to hear from stakeholders about what its scope should be. CAISO spokesman Steven Greenlee told RTO Insider that the enhancements are part of an open interconnection initiative that began in 2013. The initiative in the past has led to minor but useful modifications in the generator interconnection process, and is meant to ensure the process reflects current grid conditions and that rules are updated appropriately.

“It’s not that we have found anything major and are looking to broaden the scope; it’s just an opportunity for stakeholders to bring up things that may need tweaking or exploring more,” Greenlee said.

CAISO interconnection process — CAISO is in Beginning Phases of Interconnection Changes | *First Solar Desert Sunlight Plant Source: Wikimedia*

CAISO said that a future market notice will outline a schedule for the new enhancements, leading up to filing at FERC. In a January 2016 update filed with the commission, the ISO said its “overriding goal has been to tailor its procedures to promote California’s energy goals while ensuring that they continue to be grounded in principles of cost-causation, fairness and non-discrimination.”

The state’s renewable portfolio standard and rapid changes in generation development make it increasingly important to have an efficient interconnection queue process. As a single-state ISO, CAISO must adhere to a more unified set of policy goals compared with other ISOs and RTOs across the country — specifically, the State Legislature setting aggressive renewable generation goals to combat climate change.

Generators Must Comply With CAISO Rules to Interconnect to the Electric Grid | *PG&E Moss Island Plant Source: Wikimedia*

Generation developers that want to connect to the CAISO grid must submit an interconnection request that triggers an ISO interconnection study. One of the most significant problems with the process is that many projects sit in the queue for up to a decade after slowing or stopping their progress. While some of the delays are outside the developer’s control, they can result in the holding of capacity, transmission, deliverability and bus positions that hinder other projects.

In March 2016, FERC approved 10 changes to the interconnection process, including new timelines for projects in the queue. Last year CAISO had 44 projects in its queue — representing 17% of the total — with commercial operation dates more than seven years from their interconnection requests.

The ISO is seeking comments on the scope of the new initiative by Aug. 30.

August 14, 2017

NYISO Study Sees Little Cost Impact from Carbon Charge

By Michael Kuser

A $40/ton carbon charge in New York state would have “a relatively small impact” on customer costs, ranging from a −1% to +2% change in total customer electric bills, according to an analysis released by NYISO and the state Department of Public Service on Friday.

The much-anticipated report by the Brattle Group on pricing carbon into generation offers and reflecting it in energy clearing prices was prompted by the Public Service Commission’s decision to subsidize upstate nuclear plants through zero-emission credits (ZECs). Fossil fuel generators would incur a penalty based on their level of carbon emissions.

The study is meant to develop an approach to value carbon in the wholesale energy market as an instrument of state policy while “providing appropriate price signals to incentivize investment and maintain grid reliability,” NYISO CEO Brad Jones and PSC Chairman John B. Rhodes said in the preface.

Costs and Benefits

Although average wholesale energy prices would increase under a $40/ton carbon adder, about 50% of the cost could be offset by returning carbon revenues to customers; another 18% by reduced prices for renewable energy credits and ZECs; and an additional 23% by “dynamic effects on investment signals,” the report said.

While more economic gains from the program would go to producers than to consumers, customer costs would not rise significantly, the report said. A supplemental carbon charge would increase wholesale electric energy prices beyond the rises prompted by New York’s Clean Energy Standard and the Regional Greenhouse Gas Initiative. However, “returning carbon revenues to customers and other factors would offset most of the customer cost impact. The exact magnitudes are uncertain, but the net impact on customer costs remains relatively small under all assumptions considered.”

The $40/ton adder would reduce CO₂ emissions by 2.6 million tons per year, or 8% of today’s emissions, by incentivizing cost-effective market responses not available through the CES and RGGI alone — and the analysts said the estimate of CO₂ emission reduction “is probably conservatively low.”

Gavin Donohue, CEO of the Independent Power Producers of New York, lauded the report in a statement: “Incorporating the value of carbon into the marketplace ultimately benefits ratepayers and demonstrates that private investment is best for the continued success of New York’s energy markets. Though this process is only in the early stages, what we accomplish here could be a model on the national stage.”

In a blog post, Jackson Morris of the National Resources Defense Council said, “The concept of a carbon adder is laudable and worth exploring. And it has clear potential to cut carbon pollution — but only if the state and NYISO get the design right and, in the process, avoid some important legal and policy pitfalls.”

The report concludes by suggesting topics of further study. For example, market design affects carbon charges, and different designs create new models of revenue allocation and border adjustment. Also implied are potential refinements “to REC and ZEC procurement for allocating the risk of future changes in carbon prices between customers and suppliers,” the report said.

NYISO and the DPS will hold a conference on Sept. 6 to solicit stakeholder feedback on the reasonableness of modeling assumptions, especially their dynamic effects. The report said that although New York has no specific emissions reduction target for the electricity sector, the state’s commitment to reducing carbon emissions from power generation “is expressed monetarily in its ZEC payments to upstate nuclear plants … starting at $43/ton CO₂ today and rising to $65/ton by 2029.”

The ZECs are part of the CES, which mandates reducing greenhouse gas emissions by 40% by 2030, from a 1990 baseline, and by 80% by 2050. It also calls for renewables to meet 50% of the state’s energy needs by 2030.

ZEC Challenges

The Electric Power Supply Association and several of its members had filed suit against New York’s ZEC program, claiming that it intruded on FERC’s authority over interstate electricity sales. A federal judge in New York on July 25 dismissed all claims in the suit, finding the state’s ZEC program constitutional. Earlier in July another federal judge had dismissed similar challenges to Illinois’ program. (See New York ZEC Suit Dismissed.) EPSA has appealed the Illinois ruling and plans to challenge the New York dismissal as well.

Jones previewed the Brattle report in May at a FERC technical conference devoted to the issue of reconciling public policy and wholesale electricity markets in New England, New York and PJM, and also at a congressional energy hearing in July. He said New York hoped to implement the plan in the markets within three years. (See RTOs to Congress: Don’t Lose Faith in Markets.)

PJM also is considering a similar mechanism, while New England has rejected carbon pricing as impractical and overly expensive. (See ISO-NE Two-Tier Auction Proposal Gets FERC Airing.)

Some stakeholders who oppose NYISO’s carbon pricing plan have already questioned the current market design, particularly regarding capacity markets. Before and after the technical conference in May, FERC asked for comment on five potential paths toward harmonizing public policies and wholesale electricity markets, including the path chosen by New York. (See We Read 79 FERC Comments so You Don’t Have to.)

Economist James F. Wilson said the commission should eventually phase out the capacity constructs or convert them to voluntary mechanisms. Cliff Hamal, managing director of Navigant Economics, said “the most fundamental assumption” underlying capacity markets — setting capacity prices based on the cost of building new gas-fired generation — may no longer be valid.

August 11, 2017

Ameren Illinois Criticized for Lowered Energy Efficiency Goals

By Amanda Durish Cook

Environmental and consumer activists Wednesday accused Ameren Illinois of attempting to bypass energy efficiency targets set by the state’s new clean energy law.

The Illinois Clean Jobs Coalition, with Illinois Rep. Elaine Nekritz and representatives from the Citizens Utility Board (CUB) and Natural Resources Defense Council (NRDC), held an Aug. 9 teleconference to criticize Ameren for setting low energy efficiency goals and urge state regulators to reject the utility’s plan. CUB, NRDC and the Environmental Defense Fund filed joint testimony opposing Ameren’s plan, which also attracted criticism from many others (17-0311).

According to a July report from the NRDC, both Commonwealth Edison and Ameren filed their initial four-year energy efficiency plans with the Illinois Commerce Commission, but Ameren’s plan contained lower energy efficiency goals than required by the Future Energy Jobs Act, which includes performance-based incentives that reward utilities for surpassing efficiency targets and penalize them if they fall short. (See Illinois Lawmakers Clear Nuke Subsidy.)

“It’s important to understand that everyone benefits from energy efficiency,” said CUB Executive Director Dave Kolata, who asserted that Ameren provided no evidence, as required, for not being able to meet the goals.

“In essence, they filed a bloated and inefficient plan” by claiming energy efficiency is more expensive, Kolata said. While the NRDC says ComEd’s portfolio meets the new law’s four-year target of 11.8% savings, Ameren Illinois’ plan “does not meet any of its statutory cumulative annual persisting savings targets — all of which were lower than ComEd’s — over the four-year period.”

Under the law, ComEd and Ameren are required to achieve 21.5% and 16%, respectively, in cumulative annual savings through 2030 ― figures that both utilities had to sign-off on, according to Nekritz, chief sponsor of the law.

By 2021, Ameren should meet a 9.8% cumulative persistent annual savings, but the utility is planning for 8.24% savings. If Ameren’s plan is allowed, the utility could gain $36 million in incentives while failing to abide by the law’s requirements, the groups said.

Ameren Illinois President Richard J. Mark vehemently rejected the allegation. “They state that Ameren is seeking a $36 million bonus if we achieve lower goals. This is a false statement. In the unlikely event that Ameren earned the ‘maximum bonus,’ it would amount to approximately $1.3 million in the first year of the plan and $10.1 million in total during the four-year plan.”

Mark noted that the filed plan only covers the next four years and is not an indication that the company won’t reach the 16% target by 2030.

Nekritz said Ameren should not be allowed to “exploit a loophole” and pointed out that Ameren was already given a lower standard in the law than ComEd.

“Just a short seven months later, Ameren is already backing away from their weak commitment. … Ameren broke their word,” Nekritz said. She said while Chicago and Northern Illinois will benefit from electricity savings, Central and Southern Illinois will lose out from Ameren “lowering the goalposts.”

Josh Mogerman, NRDC media director, said the law could add 7,000 jobs annually, boosting the state’s economy by $700 million per year. “Every time I go home to my parent’s in Springfield and see that old refrigerator running in the garage, I’m reminded that there are opportunities all over the state. … Come on, Ameren, don’t let down your customers,” Mogerman said.

Ameren said its plan is tailored to serve its more sparsely populated customer base. “ComEd serves 3.8 million customers within a territory spanning only 11,400 square miles, or 333 customers per square mile. Ameren Illinois serves 1.2 million electric customers in a service territory that covers 43,700 square miles, or 27.5 customers per square mile,” Mark said in a statement to RTO Insider. “There is significantly less energy saving potential in the Ameren Illinois service territory.”

Ameren energy efficiency — Ameren Illinois Service Territory | *Ameren Illinois*

Mark said that Ameren’s plan calls for $112 million in spending annually on low-income programs for the next four years — the maximum allowed under the law. “We’re focusing on assisting moderate- to low-income customers who pay for energy efficiency programs every month and deserve the opportunity to receive the benefits,” Mark said.

The ICC could decide on Ameren’s proposal as soon as early fall.

August 11, 2017

Court Blocks NYPSC Order Barring ESCO Contracts

By Michael Kuser

A New York appellate judge on Wednesday blocked the Public Service Commission from limiting energy service companies’ (ESCOs) ability to contract with low-income people in the state.

The temporary restraining order from Justice Christine Clark, of the Appellate Division’s Third Judicial Department, continues the legal see-sawing on the commission’s efforts to protect poor New Yorkers from paying excessive rates for electricity.

The restraining order will remain in effect pending the court’s ruling on a motion to stay a July 5 state Supreme Court order. Clark ordered the PSC to appear at a show cause hearing on Aug. 23. (New York’s Supreme Court is the trial-level court in the state, with the Appellate Division hearing appeals of its decisions. The state’s highest court is the Court of Appeals.)

Robert Abrams Building for Law and Justice, home of the New York Appellate Division Third Judicial Department | *New York Supreme Court*

Craig Goodman, president of the National Energy Marketers Association, said that Wednesday’s ruling paved “the way for appellate review of the PSC’s efforts before they are implemented. We look forward to participating in the process to gather real data and analysis that can drive policy to achieve New York’s energy goals as opposed to restricting consumer choice based on unsupported claims and faulty numbers.”

“We look forward to the opportunity to be heard by the Appellate Division justices as New York continues to protect consumers and ratepayers from paying too much for their electric and gas service,” PSC spokesman James Denn responded in a statement.

NYPSC energy service companies ESCOs — PSC Chair John B. Rhodes | © *RTO Insider*

On June 30, Supreme Court Justice Henry Zwack ruled that the PSC has “the very broadest of powers” to regulate ESCOs and utility rates, especially when seeking to prevent the overcharging of low-income customers, dismissing a case filed against the commission by NEMA and three ESCOs, as well as a similar suit by the Retail Energy Supply Association. (See Court Backs NYPSC on Regulating Retail Sales.)

The PSC on Aug. 2 had rebuffed a trade group seeking to head off upcoming evidentiary hearings related to the commission’s ongoing investigation of ESCOs. (See NYPSC Pushes Ahead with ESCO Investigation.)

August 11, 2017

MISO Bolsters Case for External Resource Zones

By Amanda Durish Cook

CARMEL, Ind. — Market participants remain skeptical of a MISO plan to integrate external resource zones into its annual capacity auction, employing single clearing prices for each balancing authority, even as the RTO is introducing changes and speaking one-on-one with stakeholders about the proposal.

MISO Executive Director of Strategy Shawn McFarlane has initiated about “20-odd” conversations with stakeholders to explain the proposal and hear suggestions after last month’s stakeholder motion to delay its implementation. Market participants instead favor a more immediate capacity transfer rights proposal that would give equal treatment to long-term supply arrangements involving both external and internal planning resources. MISO is under no obligation to honor the July motion. (See MISO Members: Court Rebuff May Reduce External Zone Chances.)

“Our reaction was, ‘Let’s go have some conversations with people one-on-one,’” McFarlane said during an Aug. 9 Resource Adequacy Subcommittee meeting. “We probably understand some concerns that we didn’t understand before.”

The RTO plans to make final modifications at the Sept. 13 RASC meeting and continue stakeholder outreach, he said.

“The bottom line is we’re still not where we’d like to be in terms of stakeholder alignment,” he added.

MISO has changed its original proposal in an attempt to address some stakeholder questions, including about how it will treat border external resources and how excess auction revenues will be doled out to external resources with historical capacity arrangements.

The proposal now says that an external resource bordering the RTO that qualifies in more than one local resource zone must designate its zone two years in advance of a capacity auction and keep that designation and its associated pricing for two years.

MISO external resource zones — Rauch | © *RTO Insider*

“That’s not something we expect to see a lot of. MISO doesn’t have a lot of border resources,” said Laura Rauch, MISO manager of resource adequacy coordination.

For external resource zones that connect to more than one MISO local resource zone and require a blended price, shift factors will be calculated annually and posted in the second quarter ahead of next year’s auction, Rauch said.

MISO is also proposing to scrap a pecking-order approach to distributing excess auction proceeds to historical capacity arrangements to cover generation-to-load price separation. Under the plan, agreements initiated before the impending creation of external resource zones and resources impacted by zonal boundary changes will be just as eligible for credits as older, grandfathered contracts made before the start of the MISO capacity market.

Indianapolis Power and Light’s Ted Leffler asked if essentially all external resources are eligible to receive historical supply arrangement credits as a refund for price separation, what was the point of external pricing at all?

MISO will distribute revenues only to “long-term and consistently used” agreements, Rauch answered. The goal of external zone pricing will be the same as the Planning Resource Auction overall: to minimize total system costs, she said.

Last month, stakeholders warned MISO officials that if there isn’t consensus on the proposal, a recent appellate court ruling banning FERC’s suggested changes on PJM’s 2013 minimum offer price rule could adversely impact the commission’s ability to approve the changes.

August 11, 2017

FERC Conditionally OKs MISO’s Pseudo-tie Pro Forma

By Amanda Durish Cook

FERC staff on Wednesday accepted MISO’s pro forma pseudo-tie agreement with a warning that a full-strength commission could in the future reject the proposal.

MISO’s accepted filing fleshed out details in response to multiple questions posed by FERC staff in May regarding the original proposed agreement.

Still, FERC staff said the updated agreement could still be found to be discriminatory by the commission and is subject to refunds (ER17-1061). (See FERC Seeks More Details on MISO Pseudo-Tie Proposal.) The pro forma became retroactively effective March 15.

In answer to FERC staff’s question about the extent of MISO’s coordination with PJM in developing the agreement, the RTO said the two RTOs engaged in ongoing discussions through MISO’s Pseudo-Tie Issues Task Team “over several months in 2016 and restarted again in first quarter of 2017.”

“These discussions are continuing today,” the RTO noted.

MISO PJM FERC pseudo-tie — MISO’s Kevin Vannoy (left) and PJM’s Tim Horger discuss pseudo-ties in May at a MISO-PJM Joint Common Market meeting | © *RTO Insider*

MISO also cited the RTOs’ recent, twin filings to alter their joint operating agreement to better manage pseudo-tied resources. (See “MISO and PJM File JOA Pseudo-Tie Rules,” MISO Reliability Subcommittee Briefs: Aug. 3, 2017.)

The RTO also defended its stance on excluding PJM as a signatory on the pro forma, contending that the agreement should be strictly between MISO and the market participant.

“While the agreement is between the market participant and MISO, the relevant RTOs will coordinate to ensure that the pseudo-tie is implemented safely and reliably and in a manner consistent with applicable regulatory requirements,” the RTO said.

MISO’s filing clarified that it will pull the plug on a pseudo-tie upon termination of an agreement or a lapse in firm transmission service without identical service replacement. The RTO also vowed that it worked with PJM to arrive at a practice of terminating new and existing pseudo-ties when a market-to-market flowgate is not within a 2% generator-to-load distribution factor within either MISO or a neighboring market. The RTO said it would revisit that value with PJM as needed.

Additionally, MISO told FERC that it does not intend to retain operational responsibility of a pseudo-tied resource, saying that the attaining balancing authority is responsible for the dispatch and operational control.

The mandatory agreement requires pseudo-tie owners to provide congestion, settlement, deployment and load data to MISO and maintain firm transmission service from the source to the sink for the life of the pseudo-tie. It also makes pseudo-ties subject to the approval of transmission providers and stipulates that pseudo-tie owners must register as the RTO’s market participants and provide six months’ notice to terminate the agreement.

MISO also retains “final authority to establish and enforce protocols” for any pseudo-ties and “make all final determinations whether to implement or terminate” them, according to the agreement. Additionally, the RTO can suspend the pseudo-tie if it determines that a pseudo-tie owner has failed to provide necessary data.

FERC staff’s measured approval of the pro forma comes after MISO asked FERC to convene a pseudo-tie technical conference to clear up several lingering issues industry-wide. (See MISO Asks FERC for Pseudo-Tie Technical Conference.)

August 11, 2017

NEPOOL Markets Committee Briefs

ISO-NE on Tuesday advanced the idea of excluding competitive new resources from functioning as demand in a proposed “substitution” capacity auction, which is designed to enable generators with retirement bids that cleared in a primary Forward Capacity Auction to transfer their obligations to subsidized resources that did not clear because of the must-offer price rule.

The grid operator proposed the exclusion to help keep Forward Capacity Market prices competitive and maintain its “cash for clunkers” framework for retiring aging fossil fuel generators.

ISO-NE NEPOOL markets committee — Real-Time Marginal Units by Fuel Type | *ISO-NE*

ISO-NE economist Christopher Geissler presented the RTO’s conceptual approach to Competitive Auctions with Sponsored Policy Resources (CASPR) to the New England Power Pool Markets Committee, which met Aug. 8-10 at Cape Neddick, Maine.

CASPR is designed to accommodate the entry of “sponsored” resources — such as resources mandated by a renewable portfolio standard or other state policy — into the FCM over time, while maintaining competitively based capacity prices for other resources. The RTO’s latest proposal comes in response to stakeholders concerned that sponsored policy resources could unfairly reduce primary FCA prices and crowd out competitive generation. (See Public Power Skeptical of ISO-NE Two-Tier Capacity Auction.)

Part of the grid operator’s Integrating Markets and Public Policy (IMAPP) initiative, the latest proposal is intended to head off stakeholder concerns about competitive resources “walking down the demand curve” of the FCA by ensuring that the substitution auction coordinates entry of sponsored resources and exit of older generators.

To limit the potential ability of public entities to reduce consumer costs by sponsoring lower-cost (e.g., combined cycle/combustion turbine) resources, stakeholders had suggested imposing additional restrictions on the types of capacity eligible to participate as supply or requiring additional documentation to show that the resource was being built to meet a public policy need.

ISO-NE said it does not plan to propose rules that would require the RTO to evaluate whether a sponsored resource meets public policy needs. The grid operator said its two-tier auction proposal “incents the continued participation of competitive new resources in the FCM, when market conditions allow.”

IMM: Spring 2017 Energy Costs up on Gas Prices

Higher natural gas prices drove ISO-NE wholesale market costs up 26% this spring compared with a year earlier, to $1.3 billion.

ISO-NE Director of Market Monitoring and Compliance Robert Laurita presented the Internal Market Monitor’s Spring 2017 Quarterly Markets Report, attributing most of the gas price increase to March, when gas prices jumped 127% from the same month in 2016 because of significantly colder temperatures.

Gas prices averaged $3.59/MMBtu, up 54% compared with spring 2016, which saw unusually low prices because of increased production, above-average storage and low heating demand during the winter. Spring 2017 gas prices were 18% below 2015 levels.

Hourly electricity demand averaged 12,853 MW, comparable to last spring because of similar weather conditions, the report said. March was unseasonably cold, while April and May saw slight reductions in load compared to the same months in the previous year.

Day-ahead and real-time energy market prices at the New England Hub averaged $30.78/MWh and $31.92/MWh, respectively, up 32% and 44% from last spring. Energy prices continued to closely track underlying natural gas prices. The positive deviation in real-time prices for the period was driven by several days with high loads and unit outages during early April, as well as two days in mid-May when high temperatures resulted in higher loads than forecasted. In addition, several units experienced forced outages.

Northern Discounts

Energy prices among the load zones deviated only in Maine, New Hampshire and Vermont, which had lower average prices than the hub. These discounts were the largest — in both dollar and percentage terms — over the two-and-a-half-year period assessed by the Market Monitor. Discounts from the hub ranged from 6% in Vermont to 16% in Maine.

The report attributed the differentials to the prevalence of renewable generators in those export-constrained areas, as well as “various planned and unplanned line reductions or outages during the period that further reduced the transmission capability available to export power to the rest of the system.” The discounts were “less pronounced” in the day-ahead market.

Real-time reserve payments for the season totaled $8.9 million, well more than last spring’s total of $700,000 and 33% above the 2015 total of $6.7 million. This spring’s payments primarily accrued over May 18-19, which accounted for 54% ($4.8 million) of the credits. Those two days saw the grid operator frequently redispatch generation to maintain reserves. Deficiencies several times triggered the reserve constraint penalty factors for 10-minute spinning reserves and 30-minute operating reserves.

FCA Payments Stable

Spring 2017 coincided with the last three months of the commitment period associated with FCA 7, in which the NEMA-Boston zone cleared at $15/kW-month for new resources and $6.66/kW-month for existing resources, while Rest-of-Pool cleared at the floor price of $3.15/kW-month. Capacity payments for the season totaled $287 million and were within 1% of spring 2016 payments. Peak energy rent adjustments remained relatively high at $26 million because of the high real-time energy prices occurring in August 2016.

ISO-NE in April held the forward reserve auction for the summer 2017 delivery period, which saw supply offers exceed the requirements for both the 30-minute operating reserve and 10-minute non-spinning reserve, with no pivotal suppliers. The clearing prices for offline 30- and 10-minute reserves for the control area were $1,000/MW-month and $2,000/MW-month, respectively. Summer 2016 10- and 30-minute reserves cleared at $2,000/MW-month and $2,498/MW-month, respectively. Of the three local reserve zones, only NEMA/Boston had a different price than the control area. Because of inadequate supply (meaning all suppliers were pivotal suppliers), the 30-minute reserve price for NEMA/Boston was set to the auction’s offer price cap of $9,000/MW-month, the same outcome as the summer 2016 auction.

— Michael Kuser