MISO is recommending two of three Michigan projects requested for expedited review be approved before its 2017 Transmission Expansion Plan.
METC Project Map | MISO
The RTO recommended that transmission developer Michigan Electric Transmission Co. (METC), an ITC Holdings subsidiary, move ahead with a new $12 million, 120-kV substation and 2 miles of new double-circuit 120-kV structures in east Michigan, and a new $6.6 million, 120-kV station to serve 5 MW of new DTE Energy load in southeast Michigan.
In submitting the request, METC had argued that waiting until December 2017 to get regular MTEP approval did not allow enough time to support the projects’ early 2018 planned in-service dates. (See “Four Expedited Review Projects Under MISO Inspection,” MISO Planning Advisory Committee Briefs.)
After an independent study and a Technical Study Task Force review, MISO agreed.
A third project, a 138-kV station to serve 35 MW of new Consumers Energy load in western Michigan, was withdrawn from expedited review after Consumers delayed the needed in-service date to Jan. 1, 2020, because of a request from the load customer. The project will move into the normal MTEP 17 cycle for evaluation.
NEW BRUNSWICK, N.J. — A panel of experts discussing New Jersey’s energy future agreed Wednesday that the Garden State has made great strides on installing renewable generation resources but differed on whether the progress is sustainable.
“We’re at where we thought we’d be in 2028 [on the state’s renewable portfolio standard], but at a substantial cost,” said Stefanie Brand, the director of New Jersey’s Division of Rate Counsel.
A study commissioned by the rate counsel found that the state’s current solar RPS will cost ratepayers $5.2 billion through 2028 (net present value). A bill proposed last year would ramp up the state’s RPS faster, adding another $276 million (NPV) in costs, the advocate told legislators last year.
Steven Gabel of Gabel Associates, an industry consulting firm, pointed to the “saw-tooth” nature of the clearing prices from recent PJM Base Residual Auctions to argue that the RTO’s price signals “aren’t doing the job” to incentivize generation development. The grid operator’s implementation of Capacity Performance was a “titanic event” to increase reliability, Gabel said, yet clearing prices in the auctions since then have provided ambiguous signals.
Aggregating winter and summer resources won’t solve the issues, either, he said, because the payments go to the resource that gets used instead of being distributed to both.
The discussion was hosted by Rutgers University’s Center for Energy, Economic & Environmental Policy, part of the Edward J. Bloustein School of Planning and Public Policy.
Andrew Hendry, the president of the New Jersey Utilities Association, prognosticated on the state’s potential return to the Regional Greenhouse Gas Initiative following the 2017 gubernatorial election. Republican Gov. Chris Christie pulled the state from RGGI in 2011.
“I think it’s very likely that if a Democrat wins, we’re going to be back in RGGI,” he said.
Gabel said state Sen. Bob Smith, a Democrat who chairs the Environment and Energy Committee, has a “big appetite” and “pent-up demand” for energy reform in the state.
He said state policy has not changed much from the state’s 1980s-era energy plan. “For 32 years, we’ve been talking about it,” he said. “We have to turn this around. … For me, the needle points more toward ‘let the market sort this out.’”
Brand was skeptical of a market-driven focus, saying that’s why the state’s solar renewable energy credits (SRECs) are being sold for $250 when they’re much cheaper in other states. Solar developers are receiving “windfall profits” because “we’re over-incenting,” she said.
New Jersey has the second highest subsidies for rooftop solar, behind California, she said. By comparison, North Carolina and Arizona are growing solar capacity but with subsidies that are “more in line” with other states.
“The fact is I don’t think we need $250 SRECs,” she said. “I don’t buy it. … We get less solar, not more.”
Gabel said that’s what the market will bear. “We moved away from an administrative structure for SRECs to a market.”
Brand cautioned that it won’t be long before ratepayers can’t afford to purchase electricity. “Our prices are high and they’re very volatile,” she said. “Not all good things deserve a subsidy.”
She included nuclear in that, noting that PJM’s analysis on Artificial Island’s three reactors found that Delaware stands to receive the most benefit from planned transmission upgrades for the nuclear complex. “Much of the electricity that comes out of these plants doesn’t go to New Jersey,” she said. “Before we subsidize these plants, we have to figure out if we’re subsidizing Delaware.”
The Garden State remains heavily dependent upon its nuclear fleet, receiving 56% of its power from such sources, she acknowledged. “I don’t think we’ll see any offshore wind in the immediate short term,” she added.
Hendry said that data analytics will be an important part of the state’s energy future, but Brand argued that advanced meters aren’t helping consumers. “The primary benefit you get in advanced meters is lost jobs” because companies need to employ less people as meter readers, she said.
“We cannot afford to give everybody net metering” because it reduces the number of customers who pay for social-benefit charges, like low-income subsidies, she said. “We have to make sure everybody has access to heat, electricity. … Everybody has to pay their own way.”
She also questioned the FERC-approved rate adder utilities get for joining PJM: “At this point, it’s a free 50 basis points.”
Pacific Gas and Electric will continue to be a “critical partner” in California’s efforts to meet its ambitious greenhouse gas reduction goals despite “uncertainty at the federal level,” the company’s top executive said last week.
The company’s key area of focus in that effort: capitalizing on the electrification of transportation as the state strives to put 1.5 million electric vehicles on the road by 2025.
PG&E is positioning itself to capitalize on California’s push to reduce greenhouse gas emissions through increased adoption of electric vehicles. | City of Pasadena
“With the transportation sector accounting for about 40% of California’s greenhouse gas emissions, we expect to play a significant role in helping the state address these emissions by investing in the infrastructure necessary to enable electric vehicle adoption,” PG&E CEO Tony Earley said during a Feb. 16 call to discuss fourth-quarter earnings.
The utility earned $692 million during the fourth quarter of 2016, compared with $134 million during the same period a year earlier. Full-year earnings came in at $1.39 billion, up 60% from the previous year. Operating revenues for the year increased 5% to nearly $17.67 billion on rising electric (+2%) and natural gas sales (+20%), largely the result of rate increases over the previous year. The company also booked an additional $325 million in out-of-period gas revenues based on a 2016 California Public Utilities Commission decision related to a previous under-collection of gas transmission fees.
Earley noted that the PUC in December authorized PG&E to spend $130 million over the next three years to build the infrastructure to support about 7,500 automobile charging stations. The company last month filed an additional request to lay out $250 million to support the charging of medium- and heavy-duty vehicles, such as transit buses.
“We are confident in our ability to execute on a strong growth plan through continued investments in upgrading and modernizing our system, as we help the state achieve its clean energy goals,” said PG&E electric division President Geisha Williams, who will assume the company’s top spot later this year upon Earley’s retirement.
PG&E’s electric transmission business is coming under pressure from slow load growth across the state, which has reduced the need for new transmission projects, according to CFO Jason Wells.
But the company said the reduction in incremental transmission projects should be offset by spending to interconnect new utility-scale renewable projects developed to meet California’s 50% by 2030 renewable portfolio standard — helping to keep 2018 and 2019 outlays equal to current levels.
Wells roughly quantified how the increased use of electric vehicles could help the utility counter the trend of decreasing retail loads stemming from energy efficiency measures and the wider adoption of rooftop solar. A plug-in electric car consumes about half the electricity of an average household.
“So you can think of for every two electric vehicles we add to the system, essentially we’re offsetting the decline that we see from distributed generation,” Wells said.
Based on state agency estimates, the utility expects to have about 600,000 electric vehicles and 150,000 charging stations within its service area by 2025, Wells added. There are currently about 5,000 public chargers in the region.
Williams said PG&E should be somewhat buffered from the expected statewide growth of community choice aggregators (CCAs), which directly draw customers away from the state’s three investor-owned utilities.
“Our service area is made up of many small municipalities and counties,” Williams said. “So, in our case, we think that that transition to higher levels of CCA adoption are going to take a little bit longer.”
But PG&E is still preparing for that potential shift by maintaining a “flexible” energy portfolio, according to Williams. The utility procures more than half of its energy supplies from third parties under long-term agreements, 40% of which represent output the company is under no obligation to take after 2021.
“So, we believe, we’ve got the triggers that we need to be able to meet the load over time,” Williams said.
Below is a summary of the issues scheduled to be brought to a vote at the Markets and Reliability and Members committees meetings 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 (9:10-9:30)
Members will be asked to endorse the following proposed manual changes:
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. Transmission Substation Equipment in FERC Order 1000 (9:50-10:05)
Members will be asked to endorse proposed a Regional Transmission Expansion Plan process changes related to the treatment of transmission substation equipment under FERC Order 1000, and associated Operating Agreement revisions. (See “Endorsements Sail Through by acclamation,” PJM Planning Committee and TEAC Briefs.)
5. Draft Pseudo-Tie Agreements (10:05-10:20)
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 “Committee Endorsements,” PJM Operating Committee Briefs.)
6. Replacement Capacity (10:20-10:40)
Members will be asked to endorse a proposed problem statement and issue charge regarding procurement of replacement capacity in the Incremental Auctions. (See “PJM Has No Objection to IMM’s ‘Paper Capacity’ Report,” PJM Market Implementation Committee Briefs.)
Members Committee
Consent Agenda (1:20-1:25)
Members will be asked to endorse:
B. Tariff, Operating Agreement and Reliability Assurance Agreement revisions to clean up definitions.
C. Revisions to the PJM Tariff regarding operating parameters.
1. Transmission Substation Equipment in FERC Order 1000 (1:25-1:45)
Members will be asked to endorse changes to RTEP processes. See MRC item 4, above.
2. Energy Market Uplift Senior Task Force (EMUSTF) (1:45-2:15)
NEW ORLEANS — Two consultants on either side of MISO’s rejected capacity auction redesign faced off in a post-mortem debate at the Gulf Coast Power Association’s MISO South Regional Conference last week.
Kathleen Spees, a principal adviser at The Brattle Group who endorsed MISO’s forward auction design for the RTO’s retail-choice areas and worked on a simulation analysis for the RTO, said some of MISO’s design elements could be revised to win FERC approval. But Independent Market Monitor David Patton pressed for a reconsideration of the hybrid prompt proposal he designed with the RTO last year.
The rejected auction proposal was an attempt to provide investment price signals to incent generation in retail choice areas in southern Illinois and Michigan. (See FERC Rejects MISO’s 3-Year Forward Auction Proposal.)
Spees, who joked that she and Patton should have come dressed as Hillary Clinton and Donald Trump for the debate, said FERC’s unusually short order lacked commission guidance on how MISO’s proposal could be salvaged. The order was among more than 60 the commission issued in the last week before losing its quorum with the resignation of former Chairman Norman Bay.
“I think that leaves many of us scratching our heads about what to do next,” Spees said at the Feb. 16 conference. She said she thought a compromise could be reached over how far into the future the auction is held and suggested that, in a new proposal, MISO keep a sloped demand curve for its retail-choice areas while regulated utilities maintain vertically integrated statuses.
Patton said MISO “dodged a bullet” with the rejection. “You operate the system as a whole. You can’t pretend that 10% of your footprint operates separately,” he said.
The Monitor continued to advocate for his own proposal, which would apply a sloped demand curve to deregulated areas and produce separate clearing prices for retail-choice and regulated load.
Spees said MISO’s proposal failed because it did not maintain an integrated market or contain a transmission allocation plan between two markets. “MISO has a uniquely challenging situation where there are two business models in conflict,” she said. There is “a not-so-small-it-can’t-be-ignored portion of the system that relies on market signals.”
Patton said current rules only buoy regulated utilities, which continue to expand generation even when wholesale prices don’t support construction.
“We exist in an environment where only a regulated market can afford to build anything,” he said. “We’ve designed a capacity market in MISO that doesn’t set efficient prices; it sets inefficiently low prices, especially in MISO South.”
Patton said while he monitors both prompt and forward markets, he prefers a prompt design. He said while it’s “nifty” for future resources to be able to sell capacity, an owner of a plant with a 30-year lifespan won’t usually make decisions on the viability of their generation based on clearing prices in year one.
Spees, however, said a three-year forward auction provides more of an opportunity for supply and demand to reach equilibrium and avoid “boom and bust” cycles with volatile clearing prices. However, she said accurate load forecasting in a three-year market presents a challenge. “In my view, we’ve seen both prompt and forward markets do well…They both can be workable constructs,” she said.
The two were in agreement in opposing MISO’s adoption of New England’s Pay-for-Performance capacity bonuses and penalties. PJM adopted similar rules in its Capacity Performance construct. Patton said he preferred incentives to stay in the energy market. (See FERC Defends PJM Capacity Performance Model Before DC Circuit.)
“If it ever hits on days where no one is expecting it, it can cost people a heck of a lot of money,” Patton said, adding that unpredictable load is not the fault of the generator.
Spees also said performance incentives belong in the energy market, not the capacity market. However, she said there is no MISO enforcement for capacity underperformance, and she said the penalty should be “something north” of $0/MW-day.
Water levels behind the FERC-regulated Oroville Dam have continued to decline in recent days, falling to nearly 50 feet below the height of a severely damaged emergency spillway, according to the California Department of Water Resources (CDWR), the dam’s operator.
On Feb. 12, local officials ordered the evacuation of about 188,000 residents after the erosion of a hillside beneath the dam’s emergency spillway threatened to flood areas near the Northern California town of Oroville, located about 75 miles north of Sacramento. CDWR was required to use that spillway for the first time since the dam’s completion nearly 50 years ago after heavy flows out of the reservoir tore a massive hole in the concrete lining of the main spillway.
Residents have since been allowed to return to their homes but face the potential for another evacuation if weather conditions once again destabilize the ground around the dam.
Criticism for FERC, California Agency
The spillway failure has generated criticism of both CDWR and FERC for their failure to heed previous warnings by three environmental groups who — during the dam’s 2005 FERC relicensing proceeding — requested that the state pave the hillside below the emergency spillway to avoid the kind of erosion experienced earlier this month.
CDWR and the commission rejected the request, with a FERC engineer writing that the emergency spillway could safely handle 350,000 cubic feet of water per second (cfs). The flow was only 6,000 to 12,000 cfs when the spillway was damaged, according to a report from the Bay Area News Group.
Outflows are outpacing flows into the reservoir despite stormy conditions, and CDWR said it will continue to prioritize bringing the depth of the reservoir to a target level of 895 feet. The agency said Feb. 20 that it had increased outflows from 55,000 cfs to 60,000 cfs in anticipation of increased inflows from recent rains.
“As runoff flows into the reservoir, water levels will likely fluctuate but will remain within acceptable and typical depths during times of storm activity,” the agency said in a Feb. 19 incident update.
CDWR said work crews continued to place rock and cement slurry into the areas affected by erosion, as ordered by FERC in a letter Feb. 13. In addition to ordering emergency repairs, FERC also ordered the state to convene an independent board of consultants to review current conditions and risk-reduction measures and to later conduct a forensic analysis to determine the cause of the failure.
“We have people there 24/7 from our San Francisco office as well as our Washington, D.C., office working with state officials … to protect public safety,” acting Chairman Cheryl LaFleur said in remarks at the winter meeting of the National Association of Regulatory Utility Commissioners on Feb. 14.
Rainy Winter
After years of drought, the region has experienced unusually high levels of precipitation this winter, which has filled the reservoir to capacity and left the lake’s elevation at about 900 feet above sea level. Snowpack in the Sierra Nevada mountains currently stands at about 175% of normal ahead of the spring melt, which tends to peak at the beginning of April, sending additional flows into the lake.
The 770-foot-high Oroville Dam in Butte County is the tallest in the U.S. and impounds one of California’s largest manmade lakes, a key source of water for farms in the state’s Central Valley and residents in Southern California, hundreds of miles to the south.
The dam’s Edward Hyatt and Thermalito generating facilities, which have a combined 933 MW capacity, remain offline, and three 230-kV transmission line segments in the area under CAISO control have been de-energized. The ISO said it had reoptimized its dispatch system to maintain reliability while continuing to meet demand within its balancing authority area.
“The loss of the Edward Hyatt power plant at Oroville dam is handled as we do with all generator outages,” the ISO told RTO Insider. “The outage, as well as the line outages, do not threaten grid reliability.”
County Seeks FERC Help
Officials from Butte County last week urged FERC to order CDWR to immediately establish its own public safety program to relieve the county of the “severe strain” on its “limited resources” (P-2100).
The county asked that the CDWR be ordered to provide law enforcement and other personnel needed to ensure public safety in the face of threats attributable to the dam, “including not just flood hazards but also fire, crime and other emergency services.”
Those personnel “should have the capacity to organize and implement all necessary public safety measures to prevent death from a failure of the dam spillways, including the orderly evacuation of the hundreds of thousands of people from the area downstream of the dam,” the county said in its Feb. 15 filing.
The filing also called out FERC for its failure to address Butte County’s previous entreaties, including a 2009 complaint in which the county argued that CDWR was in violation of its federal license for not contributing to covering the costs of ensuring adequate public safety at the Oroville site.
The commission rebuffed that complaint, and later denied the county a rehearing, after determining that the dam was in good condition and that the county had not pointed to any direct license violations.
“Because the commission has refused to order DWR to do what DWR is legally and morally obligated to do, and what other similarly situated licensees have done, Butte County has no choice but to request the commission to exercise its authority … to order DWR to take actions to effect its obligations as a Federal Power Act licensee, to protect public health, safety and welfare,” the county said.
WASHINGTON — A recent survey of state cybersecurity practices provided some surprising results, New Jersey Board of Public Utilities President Richard Mroz told the National Association of Regulatory Utility Commissioners’ winter meeting last week.
“We found most of the states actually do have a fusion center of some sort, so states are taking that seriously,” Mroz said, referring to locations at which state agencies share intelligence on security threats. “On the other hand we hear … from our colleagues that they don’t know what the best [cybersecurity] practices are — what’s working elsewhere.”
Mroz is chairman of NARUC’s Critical Infrastructure Committee, which sent the survey last year to the 34 states that are members of the committee; 19 had responded as of January. The committee is now seeking responses from the remaining states, including those not on the panel. The results will be included in what NARUC intends as a “living” catalog of information about state regulators’ efforts on critical infrastructure resilience. The survey is also referenced in the latest edition of NARUC’s cybersecurity primer, which was released Jan. 31.
Also speaking on the NARUC General Session panel Tuesday was former Sen. Rick Santorum (R-Pa.), who expressed concern over the shortage of cybersecurity personnel and their lack of preparation for “war.”
“These are people who went to school for computer service or a whole variety of other things and they’re the people who are our quote ‘war fighters.’ They’re not trained as war fighters … and yet they’re in the middle of a battle,” said Santorum, an unsuccessful presidential candidate in 2012 and 2016.
“So they don’t take the approach of ‘How do we comprehensively deal with this problem?’ … We seem to be saying just ‘How do we defend ourselves?’ instead of ‘How do we really put a strategy together to attack the enemy to make sure they aren’t attacking us?’
“I’m not too sure we want corporations out there attacking those who might attack them, but I think we have to start thinking about innovative ways in which to deter people from coming at us,” he added.
In conversations with former colleagues on Capitol Hill, Santorum said, he has proposed “retasking” the National Guard for a cyberdefense role. “We need these people to be out across America to be almost like a Minute Man type of operation to be able to respond to some of these threats we have.”
Jonathon Monken, PJM’s senior director of system resiliency and strategic coordination, a West Point graduate and former director of the Illinois State Police, responded that officials need to “de-conflict … the lanes of effort” by clearly defining roles and responsibilities to determine “who’s best suited to do what.”
Monken said the electric industry also needs to improve the security of its tools.
“Recognizing the fact that our systems are interconnected. Our [information technology] configurations are very, very similar. They’re not identical. It’s not if you breach one that you get access to everybody. But it’s not like there’s that many different [energy management system] providers out there. It’s just a handful of system types and the architectures are very similar.”
Separately, acting FERC Chairman Cheryl LaFleur talked about the importance of collaboration between government and industry and of not relying on just meeting NERC’s standards on critical infrastructure protection.
“While mandatory standards are important, the cyber challenges are evolving so quickly, you can’t really regulate your way out of it. You can’t do a standard fast enough for some new piece of malware or ransomware that comes along,” she said. “The non-mandatory piece is becoming more and more important.”
WASHINGTON — Choices made by customers on issues ranging from carbon dioxide to technology could rank alongside decisions made by policymakers in shaping the future of the grid, RTO officials said last week.
McCoy | Smartwires
This was a recurring theme during a Feb. 16 briefing by WIRES, the House Grid Innovation Caucus, the National Electrical Manufacturers Association (NEMA) and the Environmental and Energy Study Institute (EESI). “Unlike ever before, the electric customers are actively participating in the industry,” said Adriann McCoy, a vice president of Smart Wires, which makes advanced power flow control technology. The growing clout of end users is reflected in rooftop solar, plug-in electric vehicles and consumers’ purchasing of renewable power from alternative suppliers, she said.
“Anytime consumers start playing more actively in a market,” it brings about innovation, McCoy said.
Coal plant retirements, such as the recently announced plans to close the Navajo power plant in Arizona, will require that electricity be moved from other sources, McCoy said. The utility owners of the Navajo plant said Feb. 13 that they don’t plan to operate the facility beyond December 2019.
Speakers said people’s choice about where their power is coming from is driving the transmission system. This includes decisions favoring renewable energy and less-carbon-emitting sources.
“The planning is only slightly less complicated than the engineering” these days, said former FERC Chairman Jim Hoecker, counsel to WIRES. “It’s a challenging time, it’s a transformative time, for the electricity business.”
At the same time, a robust transmission system will save consumers billions every year in avoided power disruptions, Hoecker said. “That’s not pocket change,” he added.
Moeller | MISO
MISO Executive Vice President Clair Moeller said it is resilience and the need to move power from new low-carbon resources that is driving new transmission. “There is essentially no load growth in the nation,” he said. “My job at MISO is mostly about planning,” Moeller said. Sometimes “you get cheaper electricity from your next-door neighbor,” rather than from the generating unit in your own area, Moeller said.
Congress in 1992 said it wanted to see more electric competition, said Craig Glazer, PJM vice president for federal government policy. But even since the Energy Policy Act of 1992, lawmakers still engage in picking winners and losers, Glazer said.
The wind production tax credits and state bailouts of struggling nuclear plants can make things complicated, Glazer said. But Glazer cautioned against too much market tinkering, noting that the goal of competition was to shift risk from ratepayers to shareholders.
Ross | SPP
Innovation happens quickly, but “Congress doesn’t move very fast,” said former U.S. Rep. Mike Ross, senior vice president for government affairs at SPP. Congress needs to ensure its laws “don’t get in the way” of innovation, Ross said.
Many panelists said while the concept of regional planning is popular in the abstract, it often runs into roadblocks in the real world. For example, states are all over the board on issues like renewable mandates, Moeller said.
“States have not wanted to relinquish their regulatory authority over utility operations. This is a tremendous burden to interstate commerce,” Hoecker said.
“We want to make sure this [electric transmission issue] is front and center … that people know how important this is,” said Rep. Jerry McNerney (D-Calif.), who co-chairs the House Grid Innovation Caucus along with Rep. Bob Latta (R-Ohio).
NEW ORLEANS — Three years after the region’s integration, MISO South, with its plentiful gas generation, constrained interface into the North and capacity for severe weather, still doesn’t feel fully “in” the RTO, speakers told the Gulf Coast Power Association’s MISO South Regional Conference on Thursday.
Jennifer Vosburg, president of Louisiana generating at NRG Energy, said MISO’s North-South transfer constraint under the RTO’s settlement with SPP limits South’s participation in North. “It’s a challenge to how competitive MISO South continues to be,” Vosburg said.
“The drive to integrate into MISO was, ‘We’re going to be fully in MISO,’” Vosburg said. “We’re proud that the Planning Resource Auction limit is 600 MW more this year. That’s not fully integrated … MISO South is not on the same playing field as MISO North.”
Multiple panelists said the constrained North-South interface has exacerbated an “illiquidity” issue in MISO South.
Plentiful capacity in South is unable to help shortage conditions in North, Vosburg said, and South will remain isolated until it can fully participate in the market. She added that since integration, it is often easier to sell in the PJM capacity market than participate in MISO’s capacity market.
Vosburg said MISO’s once-thriving independent power producers have become “a lonely table.”
Paul Zimmering, an attorney at Stone Pigman who has represented the Louisiana Public Service Commission, said the North-South transfer limit should have been examined by MISO much earlier than its currently underway footprint diversity study. “This is 2017, and we were hoping this would have been looked at earlier. We thought that we would get an evaluation earlier on, but it’s happening now and it’s great,” Zimmering said.
However, Zimmering said MISO is doing a good job through its Transmission Expansion Plan playing catch-up on other transmission projects in the Entergy territory that were ignored prior to the incorporation of MISO South. He said 86% of Public Utility Regulatory Policies Act qualifying facilities in South now participate in the MISO market.
“One MISO is a goal, and I don’t think we’re there just yet,” he added.
Zimmering also said regulation challenges exist in MISO South, where states — Louisiana, Texas and Arkansas — are located in both SPP and MISO. “There are a lot of — I wouldn’t call them divided loyalties — but different interests to look out for,” he said.
MISO President and CEO John Bear pointed out the $2.3 billion in transmission investment since MISO South’s addition in 2014 and said the RTO has created almost $2.5 billion in total savings over the region’s three years of existence.
The value “is real and it’s happening, and I think it’s a really good story,” Bear said.
Although the region hasn’t experienced a hurricane since integration, operations have withstood significant weather events, Bear said: tornados in northern Arkansas in 2014; a Texas dam at risk because of heavy rains in 2015; flooding in eastern Texas and Louisiana; and persistent regionwide heat in 2016.
Matt Brown, vice president of federal policy at Entergy, said MISO’s footprint-wide climate differences are a benefit to MISO South, allowing lower planning reserve margins. Brown said Entergy operating companies saved about $412 million in 2014 and 2015 after joining the RTO. Transmission investment in MISO South has doubled from $359 million in MTEP 14 to $886 million in MTEP 16.
Jim Schott, vice president of transmission for Entergy Louisiana, said the company has noticed that the RTO can better identify congestion for future projects and has sounder congestion management practices, decreasing instances of transmission loading relief (TLR).
“Since December of 2013, TLR and [local area procedures] have hardly been uttered once,” Brown said.
Schott also said MISO membership means Entergy plans projects further in advance to fit into the annual MTEP schedule.
He also made a case for allocating costs of economic transmission upgrades to benefiting local resource zones alone. The RTO is considering changing cost allocation for economic projects in time for 2018, when costs can be shared with MISO South. “Benefits generally flow to some region, and the region should bear those costs,” he said. (See MISO Stakeholders Propose Changes to Market Efficiency Cost Allocation Process.)
Ted Kuhn, consultant at Customized Energy Solutions, said integration has brought pricing transparency — and added bureaucracy — to MISO South. “It takes time to get things through a larger process. It takes time to know which stakeholder meetings to go to, which person to talk to. It’s a process that will kill you if you don’t know it,” he said.
SPP Seam and MISO South
Laurie Dunham, vice president and manager of regional planning for Duke-American Transmission Co., said SPP and MISO need better coordination of the models in their joint studies. She urged stakeholders to get involved in interregional planning meetings.
Dunham said large-scale transmission projects aren’t always needed to resolve reliability issues, and, in some cases, the addition of “2 to 5 miles of line and a reactor” eliminates a problem.
Patrick Clarey, a FERC attorney adviser, noted that SPP is facing challenges with greater wind penetration. MISO and SPP’s possible overlay study, designed to last through 2019, could produce transmission projects to solve SPP’s problem, he said. (See related story, SPP Eyes 75% Wind Penetration Levels.)
Ted Thomas, chairman of the Arkansas Public Service Commission, said his state is in a good position — for now.
“It’s easy to be in my position when gas prices are low. Our utilities aren’t stirred up, our customers are satisfied, the legislature is calm,” Thomas said. However, he added, “if the last three weeks are any indication of the next three years, administrations will change, federal policies will zig-zag … and the consumer needs to be protected throughout.”
MISO South and the Climate
Thomas said the electric industry’s long 30- to 40-year capital cycles create a high risk of stranded costs. He said with Arkansas, Texas and Louisiana’s low-cost energy when compared to California’s prices, MISO South can wait to implement more expensive and experimental carbon-reduction measures.
“We can’t stick our heads in the sand. But we can wait and see. We don’t have to take the risk that the high-cost states take,” Thomas said. “I know that carbon is a long-term problem, and I question if we have a solution. I know that some states have a political appetite to reduce carbon, but I also know that Arkansas, and I suspect Louisiana, aren’t those places,” Thomas said. He added that even if Arkansas eliminated carbon emissions by 2018, it would not be enough to impact global temperature rise.
Other panelists maintain that MISO South is ripe for increased renewable penetration and more energy efficiency programs.
Siobhan Foley, the City of New Orleans’ FUSE Executive Fellow for Climate Action, said solar has come down dramatically in price and now is viable in terms of cost. She said MISO South can reduce carbon through several smaller solar projects. “It really is about smaller wedges and more of them, sharing and distributing in different ways,” Foley said.
Dunham said that the Clean Power Plan’s uncertain future should not stop the adoption of renewables and storage. “I don’t think it’s ever ‘pencils down.’ We need to be always modifying and adapting,” she said.
Low Rates, High Bills
Some officials think MISO South could do with more energy efficiency programs to reduce the region’s high energy consumption.
“We have low rates, but we have really high bills,” said Logan Atkinson Burke, CEO of consumer advocate Alliance for Affordable Energy. She said Entergy New Orleans customers have among the highest energy use rates in the country. Mississippi, Alabama and Louisiana rank among the worst in the country in available energy efficiency programs.
Thomas said energy efficiency programs can help defer “big decisions” and capital expenses by keeping demand low.
Jeff Baudier, chief development officer of Louisiana-based Cleco Holdings, said the company’s addition of a heat recovery steam generator to the Cabot coal plant in the St. Mary Parish in Franklin, La., will add 50 MW of capacity with no additional emissions. The project is expected to be in service in the first quarter of 2018.
Ted Romaine, director of origination for renewable generation developer Invenergy, said commercial and industrial customers, especially Internet companies like Google, Amazon and Facebook, are increasingly making off-site renewable energy deals such as virtual power purchase agreements.
“This is a market that’s really picked up steam in the last few years. … We see more buyers come into the market, and interest continues to grow. This isn’t a Silicon Valley-exclusive market,” Romaine said.
ERCOT, SPP and PJM lead in corporate off-site renewable deals with a 77% share of the U.S. and Mexico, Romaine said. He said although MISO doesn’t have any such contracts, it will in the future. He expects more than 20 first-time corporate renewable buyers nationwide in 2017. He added that vertically integrated MISO South utilities might bend to pressure from big energy users such as Google to create green tariffs — renewable energy purchasing programs — even if they have no legal obligation to do so. He said there is “strong potential” for solar-based virtual power purchase agreements in MISO South.
“If we don’t start recognizing that multinational corporations have sustainability agendas, they’re going to go somewhere else,” Baudier said.
PPL’s earnings from ongoing operations rose 11% to $1.67 billion last year, boosted by a 39% jump in the fourth quarter as the company benefited from a strong performance by its utilities and gains on currency hedges.
Reported earnings more than doubled to $1.9 billion ($2.79/share) for the year, compared with $682 million ($1.01/share) in 2015, which included a $921 million loss from discontinued operations, primarily the spinoff of its competitive supply business to Talen Energy.
PPL workers raising an osprey nesting platform at Owl Creek Reservoir near Tamaqua, Pa. | PPL
The company’s results exceeded the high end of its 2016 reported earnings forecast range of $2.55 to $2.70/share.
Reported fourth-quarter earnings were $465 million ($0.68/share), compared with $399 million ($0.59/share) in 2015. Eliminating special items, fourth-quarter earnings from ongoing operations were $409 million ($0.60/share) versus $294 million ($0.43/share) a year earlier.
CEO William Spence said the company made $3 billion in infrastructure investments last year and plans an additional $16 billion over the next five. “We are confident in our ability to deliver our projected 5 to 6% compound annual earnings growth range from 2017 to 2020 even if the exchange rate declines well below current levels,” Spence said in a statement.
The company announced that it is increasing its quarterly common stock dividend from 38 cents/share to 39.5 cents/share, payable to shareowners of record as of March 10. The increase is PPL’s 15th in 16 years.
