Carmel, Ind. — MISO has adequate capacity to meet summer demand, though there’s a good chance the RTO will dip into its load-modifying resources, officials said at a summer readiness workshop last week.
MISO officials reported 148.8 GW of capacity to meet a projected demand of 125.9 GW, giving it an 18.2% reserve margin, well above its 15.2% requirement. Compared with last year’s summer forecast, available capacity declined by 1.5 GW, while the load forecast decreased by 1.4 GW.
Probabilities
MISO said there is a 72% probability it will need to deploy some of its 9.5 GW of load-modifying resources, but only a 10% chance it will use all of them and have to tap operating reserves.
There is a 4.3% probability that MISO will deplete operating reserves and be forced to order load shedding, Vice President of System Operations Todd Ramey said.
Ramey said that even when MISO declares a capacity emergency, 10,000 MW are still available for use. “Emergency doesn’t mean imminent load shed,” he said. Unit retirements that reduced capacity create “a new operating reality” for the RTO, he added.
MISO is close to completing its 2016 Coordinated Seasonal Assessment for summer, which identifies potential stressors to the transmission system. “For this summer, we didn’t see any outstanding issues,” MISO transmission planning engineer Carlos Bandak said. MISO’s full analysis is due by end of the month.
Gas Inventory High
Phil Van Schaack, MISO electric-gas operations coordinator, said there was a record 2,480 Bcf of natural gas in storage at the beginning of April, a 60% rise over last year’s end-of-winter inventory.
Van Schaack also noted natural gas prices in the New York Mercantile Exchange hit lows in March not seen since 1999, at $1.64/MMBtu. He said the oversupplied market, coupled with forecasts of a warmer-than-normal summer, could result in “significant power burns, longer runs and higher capacity [factors for] gas units, similar to the summer of 2012.”
Emergency Offer Floors
MISO has established new emergency offer floors to combat depressed emergency prices. Michael Robinson, the RTO’s principal adviser for market design, said depressed emergency prices occur because offer prices for emergency resources either aren’t available or are cheaper than an economic resource dispatched prior to the emergency declaration.
Now, when a maximum generation emergency warning is issued, the pricing floor is set at the highest available economic offer. After a maximum generation emergency event is declared, the pricing floor moves up to the highest available economic and emergency offer.
Hurricane Readiness
MISO has assembled a hurricane readiness team to identify inadequacies in contingency plans for MISO South, which enters the Atlantic hurricane season next month.
“We hope to focus on communication coordination limitations,” project leader Van Schaack said. “We’ve had mild hurricane seasons since the integration of MISO South. We want to make sure we are educated on how to prepare.”
A 485,000-pound Exelon Generation wind turbine that toppled in February “basically shook itself apart” after a mechanism meant to control its speed failed, according to a company investigation.
All three cylinders of the pitch system in the eight-year-old Vestas V82 1.65-MW turbine in Oliver Township, Mich., suffered oil leaks, according to an investigation by Exelon. The failed pitch system, and 45-mph winds, pushed the blades to rotate at 18 rpm, far more than the 14.4 rpm nominal speed. Nobody was injured, but the $1.5 million turbine was destroyed when it fell to the ground.
All of the other turbines of that model were inspected, and none showed problems with more than one cylinder. It is the only recorded instance of a catastrophic failure of the Danish-designed turbine, officials said.
Duke Energy will build a 21-MW combined heat and power plant at Duke University that will cut the university’s carbon emissions by 25%. The natural gas-fired plant will fuel a turbine that will turn a generator, and the waste heat will be captured to produce steam for buildings. The project still needs approval from the North Carolina Utilities Commission.
It will be the company’s first foray into heat plants in the Carolinas. The university will sign a 35-year operations contract with the utility.
Talen Energy will pay more than $1 million to agencies in Pennsylvania, Delaware and New Jersey to settle a claim stemming from a 2005 fly ash spill at its Martins Creek Power Plant on the Delaware River.
Under the ownership of Talen’s predecessor company, PPL, a containment basin burst, spilling about 100 million gallons of fly ash and water into local fields, Oughoughton Creek and the Delaware River.
The Martins Creek coal-fired units stopped running in 2007, and the plant was converted to natural gas.
Six Energy Companies Launch Grid Assurance Sparing Program
Six energy companies have launched Grid Assurance, a company providing shared transmission parts inventory to restore service during emergency outages more quickly.
American Electric Power, Berkshire Hathaway Energy, Duke Energy, Edison International, Eversource Energy and Great Plains Energy worked together over a year to form the independent company this month. Kansas City Power & Light Senior Vice President Michael Deggendorf was named Grid Assurance CEO.
Grid Assurance is a subscription-based service open to transmission providers where large transformers, circuit breakers and other system components are stored in warehouses around the U.S., available for quick dispatch in case of a catastrophic event.
The Wisconsin Public Service Commission last week approved American Transmission Co.’s reorganization plan that will allow the company to more easily take on transmission work in other states.
Under the plan, the Wisconsin-based ATC will create a separate holding company specifically for out-of-state investments. The company still needs approval from the Illinois Commerce Commission, whose decision is expected later this year.
ATC spokeswoman Anne Spaltholz said the company is focusing on a string of potential Midwestern projects, in addition to possibly building a line to connect a Wyoming wind farm to California. ATC is also eyeing the formation of a separate transmission utility in Alaska.
NORTH FALMOUTH, Mass. — It all comes back to pipelines.
Discussions about New England’s energy future invariably end up focused on the outsized role natural gas plays in the region’s power mix, and how that aligns or runs counter to various policy goals. Also debated is who should pay for pipeline build-outs.
A discussion at the 23rd Annual New England Energy Conference on Wednesday, presented by the Northeast Energy and Commerce Association and the Connecticut Power and Energy Society, was no different.
Most speakers agreed that some pipeline capacity is needed (though environmental groups, energy efficiency advocates and LNG suppliers dispute that premise).
The discussion came three weeks after the suspension of the Northeast Energy Direct pipeline and amid ongoing controversy over whether regulators should allow electric ratepayer support for the proposed Access Northeast project. (See Kinder Morgan Board Suspends Work on Northeast Energy Direct Pipeline.)
Dan Dolan, president of the New England Power Generators Association, said new generation clearing in recent Forward Capacity Auctions show the market has responded to the region’s needs. Smaller gas infrastructure projects shows that contractual commitments from distribution customers are increasing supply without electric ratepayer support, he added.
“We look through any public policy proposal through the prism of subsidies. Given that rubric, no, we don’t support” Access Northeast, Dolan said. “As we see contracts, that [demonstrates what] should be built, but I don’t think we need to gold-plate the system.”
Not so, according to Camilo Serna, vice president of strategic planning and policy for Eversource Energy, who disputed the subsidy characterization. “The alternative is that the [electric] customers will be paying more in the winter,” he said.
Eversource, which is a partner in Access Northeast, predicts consumer electricity costs will drop by $1 billion to $2 billion annually with increased natural gas supply.
“The market hasn’t been able to deliver that infrastructure. The generators don’t have the incentive to commit [to pipeline contracts]. I don’t think it’s gold-plating if you see that we really haven’t made any gas infrastructure investments for 20 years,” Serna said.
Whether the investment falls on pipeline developers or electric ratepayers will be resolved for Massachusetts by the state’s Supreme Judicial Court. Arguments were held recently on an order by the state’s Department of Public Utilities allowing pipeline cost recovery. The order was challenged by Massachusetts Attorney General Maura Healey.
“We don’t think it’s legal. It’s not consistent with the [state] restructuring act, which was to take ratepayers out of the business of investing in large infrastructure projects and put the risk on private investors,” said Rebecca Tepper, deputy chief of the attorney general’s energy and environmental bureau.
“We get very nervous about making big infrastructure decisions on the backs of ratepayers based on something that happened two winters ago when the circumstances today are entirely different,” she added.
Although ISO-NE is project-neutral, it says more pipeline capacity is necessary for stable and affordable electricity, as nearly half of New England’s supply comes from gas-fired generation, a share that is expected to increase.
“We still see natural gas as one of our primary challenges,” said Anne George, vice president, external affairs and communications for ISO-NE. “We see demand for it to continue to grow and we have not built any pipeline infrastructure to support that growth.”
Omaha Public Power District is recommending that its Fort Calhoun Nuclear Generating Station end operations by the end of 2016 and begin the decommissioning process.
Fort Calhoun Nuclear Generating Station Omaha PPD
CEO Tim Burke told OPPD’s Board of Directors on May 12 that an economic analysis concluded that Fort Calhoun “is not financially sustainable.”
“The analysis considered market conditions, economies of scale and the proposed Clean Power Plan,” Burke said in a statement.
The board is expected to vote on the recommendation at its June 16 meeting.
At 478.1 MW, the Fort Calhoun plant is the smallest nuclear unit in North America, lacking economies of scale. It is located on the Missouri River in eastern Nebraska and became operational in 1973. In 2003, the Nuclear Regulatory Commission extended its operating license through 2033.
The plant was surrounded by flood waters in 2011, when the reactor was idled for a scheduled refueling. Safety and security violations discovered after the flooding prevented it from returning to service until December 2013, following more than $140 million in repairs.
It has been managed since 2012 by Exelon Nuclear Partners. When operational, it provides 30% of OPPD’s net generation.
Burke said the decision was a difficult one and was “not reflective of employee or Exelon performance.”
“OPPD would make every effort to absorb as many employees as possible into other areas of the district, based on qualifications and open positions,” Burke said. “Retraining would be made available in cases where there would be strong potential for success.”
OPPD serves more than 310,000 customers in southeastern Nebraska. It has 3,080 MW of generating capacity, with two baseload coal-fired plants, one fueled by landfill gas and three peaking plants. It also purchases output from several wind farms.
The utility said it will consider constructing or purchasing additional gas, wind and solar generation “as necessary.”
SANTA MONICA, Calif. — California’s second-largest publicly owned utility is “not buying anything other than solar right now,” said Arlen Orchard, CEO of Sacramento Municipal Utility District (SMUD).
Orchard’s comment reflected prevailing opinion at the Infocast California Energy Summit last week: Solar is the generation of choice now in California — and its role will only grow.
For SMUD, the decision to go with solar is a financial one. Despite historically low natural gas prices, California’s environmental mandates — such as emissions caps and a ban on once-through cooling — make investment in even the most efficient new gas-fired generation less attractive than solar, even in the resource-constrained Los Angeles basin.
“It sounds like for a lot of reasons, building more gas-fired generation in L.A. is not going to happen,” said Charles Adamson, principal manager with Southern California Edison, also pointing out the political unpopularity of building new gas generation in the state.
In Northern California, the alternatives to solar are other — more expensive — renewable resources. “Geothermal has benefits, but it’s coming in at twice the cost of solar,” Orchard said.
“Solar was once the most expensive — now it’s the lowest cost,” said Jan Smutny-Jones, CEO of the Independent Energy Producers Association, whose membership includes gas-fired and renewable merchant generators.
Declining solar costs are attracting the interest of more than just traditional utilities, according to Mark Fillinger, director of project development for First Solar.
California’s investor-owned utilities have effectively met the state’s 33% by 2020 renewable portfolio standard. Fillinger said his company is now seeing a “huge shift” in demand from those customers to large “direct access” commercial and industrial clients who choose to purchase power from an independent electricity supplier rather than a regulated utility.
No Thanks to ‘All of the Above’
Another growing customer segment: community-choice aggregators that sell directly to retail customers.
“I think we’re going to see an explosion of demand from community choice — and large commercial and industrial,” Fillinger said. “The thing to consider is that they’re just interested in cost,” rather than seeking a mix of resources.
“We’ve been challenged by our own success in the utility-scale business,” he said, noting that many solar manufacturers have not survived competition. “It’s been a brutal battle, but the benefits are flowing through to the customers.”
Arne Olson, a partner with Energy+Environmental Economics, said “solar saturation” will become California’s biggest challenge as the state moves toward fulfilling its 50% RPS by 2030. By then, his firm predicts, the state will have brought on a total of 15 to 20 GW of utility-scale solar — and an equivalent amount of wind and geothermal resources. Add to that another 12 to 21 GW of rooftop solar, he said.
“Duck curve” graph illustrates CAISO’s yearly forecasts for net load – which is total system load minus output from solar resources. The ISO hit the 2020 forecast in April, increasing the likelihood of oversupply that will require curtailments.
“This is an awful lot of solar,” Olson said, given that CAISO load is projected to peak at about 52 GW. “It is such a dominant factor; it reminds me of how hydro dominates the Northwest.”
And just like the hydro-heavy, wind-rich region to the north, California will increasingly confront instances when its green power sources will produce more electricity than needed.
“Curtailment of solar is going to become commonplace,” Olson said.
Still, California does have time to prepare through efforts such as broader regional coordination and adoption of time-of-use rates.
“Part of the good news is that the curtailment story isn’t really happening today — it’s out into the future,” Olson said.
That future might loom closer than expected, according to Greg Cook, director of market and infrastructure policy for CAISO.
Cook pointed to one sobering data point: CAISO reached its 2020 forecasted “net load” level (system load minus solar output) four years early on April 24. This effect is represented by the “duck curve,” a regular subject of jokes among California industry participants.
“I guess you could say the duck has landed,” Cook said.
Widespread adoption of behind-the-meter rooftop solar has accelerated the deepening of the curve. The ISO estimates that about 5,000 MW of BTM solar is already online across the state — a figure Cook said is likely an underestimate. The California Energy Commission projects that BTM generation will account for about 12.2 GW of output by 2026.
“This is coming online much faster than forecast,” Cook said.
ALBANY, N.Y. — New York’s proposed Clean Energy Standard was the main topic of discussion at the Independent Power Producers of New York’s annual spring conference last week, with speakers debating the program’s costs, the role of nuclear and Canadian hydropower, and whether the goal of 50% renewable power by 2030 will be met through markets or power purchase agreements.
Former EPA Deputy Administrator Bob Perciasepe, now president of the Center for Climate and Energy Solutions, said the CES (Case 15-E-0302) “has the potential to be much more comprehensive than a renewable portfolio standard.”
“This is a profoundly more efficient approach in the long haul,” he said.
Cost Concerns
But Couch White attorney Kevin Lang, who represents industrial customers, said New York can’t afford a program that would increase the state’s already high utility rates.
“We don’t really think very highly of the Clean Energy Standard,” he said. “We’re extremely concerned about it.”
According to the Energy Information Administration, New York’s electric rates are 10th highest among U.S. states, at 13.63 cents/kWh in February.
New York set a new windpower record on Jan. 19th, generating 1,571 MW at 5 p.m. — 9% of the state’s electric generation and 90% of the 1,746 MW of installed wind capacity.
Lang said large industrial customers with high load factors are already paying more in system benefit charges to fund public policy initiatives than for their power. He noted that CES cost estimates released last month by the Public Service Commission — which suggested the program would increase residential bills by no more than 1% and large commercial and industrials by no more than 1.4% — don’t include the cost of transmission. (See NYPSC: Minimal Cost to Meet 50% Renewable Goal.)
“What we’re doing is we’re driving business out of New York,” he said.
Lang said the program threatens to undo the benefits of retail competition. “Utilities divested generation so that [consumers] didn’t carry the risk. … Now we’re coming back with the [zero emission credits] and we’re saying, now all the risk is back on consumers.”
The PSC, he said, failed to learn from its mistakes decades ago when it signed long-term power contracts based on the assumption that oil would hit $100/barrel. “Customers paid billions and billions of dollars of above-market costs. One utility [Niagara Mohawk] almost went bankrupt.”
The current CES cost projections, he said, “are no better than any other cost projections.”
State Sen. Joseph Griffo, chairman of the Senate Committee on Energy and Telecommunications, also said he found the cost of the program “particularly concerning.”
Role of Canadian Hydro
“I support a market-based approach that correctly and fairly values carbon-free generation in all asset classes,” Griffo said. “I do not support energy policy that ultimately leaves us overly reliant on Canadian government-owned and subsidized hydro at the expense of New York’s generating assets and jobs.”
But NYISO CEO Brad Jones said the state may need 1,000 to 2,000 MW of additional Canadian hydro to meet the target because of limits on the grid’s ability to absorb wind power.
Jones said it would take 15,000 MW of wind alone to meet the CES goal — more than double the 8,000 MW a 2010 ISO study said the state’s grid could reliably handle. Jones said the study would be updated.
“Unless that [maximum wind] number changes, we’ve got a gap to fill, and that gap is rather significant,” he said. “We believe you must have some hydro in that overall mix to meet 50[%] by [20]30.”
Indian Point
Speakers also discussed the state’s “nuclear bridge,” a proposal that would allow nuclear plants to generate revenue through zero emission credits (ZECs), similar to renewable energy credits (RECs) earned by wind and solar generators.
Indian Point Nuclear Power Plant Source: Wikipedia
Gov. Andrew Cuomo would exclude Entergy’s Indian Point nuclear plant in Westchester County — which he wants to see closed because of its proximity to New York City — from the program. (See Plan Would Pay NY Nuclear Plants for Zero Emissions.)
But Assemblywoman Amy Paulin, chairman of the Assembly Committee on Energy and a Westchester resident, said she doesn’t support closing the plant, noting that it provides 25% of the electricity in the Hudson Valley. “I don’t think that a proposal that excluded Indian Point will prevail,” she said.
She and Perciasepe said the loss of Indian Point also would set back efforts to reduce carbon emissions.
“We cannot achieve the deep mid-century reductions we’re going to need to make globally or in the United States without continuing to rely on all the zero-emitting sources for electricity we can conjure up, including the ones we currently have,” Perciasepe said. “So that includes hydro. That includes nuclear. We must nurture and keep those things going; otherwise we just dig a deeper hole.”
Susan Tierney, senior advisor for the Analysis Group, also voiced her support for Indian Point, saying energy prices would rise without the plant’s 2,069 MW.
Tierney, who was hired by Entergy to review the CES plan, described changes she said would make it “more efficient, cost-effective and fair.”
In addition to insisting on a role for Indian Point, Tierney’s program would create a “clean energy credit” that would provide a revenue stream for generators tied inversely to their carbon intensity. That means fossil fuel plants could earn credits by improving their emissions profile through heat-rate enhancements. Because removing a pound of CO2 now is equivalent to doing so later, she says, CECs could be banked, providing stability in CEC pricing.
Transmission Needs
Jones said any resource mix that achieves the CES goal will require substantial new transmission. Most solar developers he has spoken to are planning on siting in western New York, far from the largest loads in New York City and Long Island, he said.
“It is a daunting challenge. Not only do we have to address the resource side, but we have to add the ability to move the power around our system. And we have to do so quicker than we’ve done in the past.”
One positive: “The environmentalists want the renewables so much they’re OK with … not opposing the transmission,” he said.
FERC Chairman Norman Bay, who gave the keynote speech, pledged his support in that effort. “If transmission is needed for economic, reliability or public policy reasons, it should be built,” he said. “I would be pleased to work with NYISO and its stakeholders to provide any assistance that I can to help build out transmission within NYISO.”
Markets or PPAs?
One recurring flashpoint was whether the CES will be market-driven or be accomplished through power purchase agreements. Another is whether utilities will be permitted to own generation resources to take advantage of their lower costs of capital.
Scott Weiner, the Department of Public Service’s deputy for markets and innovation, assured the audience that the PSC and its staff support competitive markets but acknowledged that a staff white paper “left open the door a crack” for utility ownership. Staff said it “disagreed with IPPNY and others who suggest that allowing any level of utility ownership at all will necessarily expose consumers to greater price risk or chill the development of competitive markets.”
“There may be situations where utility-owned generation would be appropriate,” Weiner said, adding, “I can assure you there is no conclusion yet, certainly not at the commission level and not at the staff level.”
Jones noted that the ISO has filed comments opposing both PPAs and utility-owned generation.
“You have my commitment, you have my staff’s commitment, that we will be the supporters of markets. You will see us stand up for markets,” he said.
“Our position on PPAs is similar to our position on utility-owned generation: We don’t think we should head down that pathway.”
Generation developers and transmission operators squared off Friday at a FERC technical conference on interconnection procedures, with developers voicing frustration about delays and a lack of clarity in the processes.
Kelly
Transmission operators pushed back, arguing that high numbers of interconnection requests in small geographical areas create congestion and delay their ability to efficiently review projects.
The conference was prompted by the American Wind Energy Association, which requested that FERC make regulatory and policy changes to interconnection procedures that it argued are outdated, “unduly discriminatory and unreasonable” (RM16-12, RM15-21).
Paul Kelly, director of federal regulatory policy for Northern Indiana Public Service Co., spoke on behalf of MISO transmission owners. He said that risk should be balanced between developers and owners.
“There’s a difference between improving a process and driving efficiencies versus shifting risks onto different parties,” he said. “There are inherent risks for certain business activities, and there can’t be a guaranteed insurance policy.”
Alan McBride, director of transmission strategy and services at ISO-NE, gave Maine as an example of a small region that has experienced a large number of requests. “The problem we do have is in a specific part of the system that is already at its performance limits, we have a significant number of interconnection requests, pretty much exclusively for renewable interconnection,” he said.
The situation is further complicated, transmission operators explained, when projects drop out during the review process, causing a restudy and reshuffling of the queue.
Location, Location, Location
Gosselin
Developers defended their concentration of requests, saying wind farms’ profitability is dependent on location.
“It matters tremendously in terms of the overall cost per unit of production,” said Dean Gosselin, NextEra Energy’s vice president of business management. “The more windy it is, the lower the cost. Price matters in the marketplace, so clustering usually happens because of that.”
Transmission operators were unified in assuring that they are working on solutions to the delays, but they argued that “speculative” projects are clogging the queue. Developers said all projects can be viable until they’ve gone through studies and received accurate information about the cost and timing of the interconnection.
Omar Martino, director of transmission for EDF Renewable Energy, argued that a 12-month target for completion of studies would solve the issue. He said interconnection customers crowd into the queue “because they understand they will not be able to do anything for the next five to six years.”
Rick Vail, PacifiCorp’s vice president of transmission, said one of the biggest concerns is the time and effort needed to restudy when higher-queue projects drop out.
“A majority of the generation in our system is hundreds, if not many hundreds, of miles away from a load center. So you certainly have different areas where you have transmission constraints, but those also continue to be the areas where developers are requesting to connect to the system,” he said. “A lot of the requests we get seem to [be] a fishing expedition of trying to determine where in the transmission system is the most appropriate place to attach generators.”
Tim Aliff, MISO’s director of reliability planning, said “one size does not fit all for the interconnection queue process,” pointing out, for example, that each of the states in MISO has its own renewable portfolio, which requires flexibility with interconnection requests.
Developer Requests
Developers said more transparency would help them determine the viability of their projects before they apply.
“Better access to cases, both economic cases and the transmissions cases. Better understanding of assumptions, more accurate assumptions in cases. Pretty much any information that can help us make a better decision,” said Jennifer Ayers-Brasher, director of transmission and market analysis for E.ON Climate & Renewables NA. “We feel there should be more commonality across the board.”
They also requested a limit on the number of performance markers projects must meet to stay in the queue. “Introducing more milestones introduces more uncertainty,” Martino said. “Introducing more uncertainty introduces the likelihood of a cascading effect with the cost estimates and schedules because projects affect each other.”
Steven Naumann, Exelon’s vice president of transmission and NERC policy, took a holistic perspective on congestion, saying the entire process needs to be overhauled to forecast and address issues in advance. “There needs to be a serious look at how congestion is dealt with in the interconnection process up front. That is a coordination issue.”
He called for processes to handle risk-inclined developers who don’t want to pay for upgrades that aren’t mandatory even if it affects the reliability of the interconnection. “You’ve got to deal with this fundamental … disconnect between the ‘I will take my chances’ and the big energy market, which doesn’t recognize ‘I will take my chances.’ … This is not an incremental fix. This is something major that has to be set up upfront and done right and thought about how it’s going to be done.”
Balancing Accuracy and Speed
Dobbins
Throughout the conference, developers pushed for both greater accuracy in estimates and faster delivery of results. MISO’s Aliff said the situation is a tradeoff: Transmission operators can’t provide the requested level of accuracy until later phases of the study, but they can’t start the studies earlier because they don’t know which projects will drop out. He said he wasn’t aware of any projects that withdrew because the process was taking too long.
At CAISO, it’s a two-phase process that takes two years, said Stephen Rutty, the ISO’s director of grid assets.
NextEra’s Gosselin said developers need to know about the overloaded transmission elements that need to be upgraded. “We have a saying in our world of development, which is ‘time kills all projects.’ The longer it takes, the more unlikely it is the project will be valid and go to fruition,” he said.
ISO-NE’s McBride said preparing construction estimates is a time-consuming process. “It takes weeks, if not months. [It] involves site surveys and getting bids from equipment suppliers and those kinds of endeavors.”
“One of the responsibilities as a transmission provider is to make sure we’re not passing on some of the costs to the connected generation, especially if it’s not required for load service,” Vail said.
At PJM, cost also plays into the timeliness of studies, explained David Egan, the RTO’s manager of interconnection projects. Egan said PJM found through its stakeholder process that generators preferred having upgrade costs “socialized” between all of the projects in the queue that caused it, not just leaving the last one to pay.
“The problem is that now you have to wait for the queue to close to be able to study everyone,” Egan said. “Where before, the smaller generators could have been moved along quicker … now you are bundled together. It is a clash of cost-sharing versus timeliness, at least on the smaller distributed generators.”
Connection Disputes
FERC staff asked about the prevalence of disputes between developers and transmission owners.
Kelly said the parties often work with the RTO, but he noted that there are dispute-resolution procedures available inside the interconnection processes.
Aliff said that MISO doesn’t see many disputes, but when they occur, the RTO plays an important role. “The fact that we don’t have a dog in the fight is a reason we should play a part,” he said. “We are making sure the reliability of the system is maintained. … If you start allowing individual interconnection customers to deviate from planning standards, you end up with a previous customer built to a level that a later customer did not build to … which could have a reliability impact down the road. Also, from an efficiency standpoint, building substations that have future ability to expand may be a cheaper alternative down the road for all other customers.”
That didn’t sit well with Gosselin, who described an incident in which NextEra and the transmission owner had different cost estimates because the owner expected the generator to prepare land for the owner’s potential future expansion. “There is a gap in expectations right there. … When we are building it, we are building it for us and only us and our future,” he said. “Ultimately, we resolved that piece of it fairly simply by saying we will option the rights for the land for them if want to expand in the future, and it’s their cost, not ours.”
Estimating Inconsistencies
Developers acknowledged that estimate overruns are rare but can be devastating when they happen.
“We have had several epic fails where the actual costs came in multiples of what the estimate was,” Gosselin said. “If we make a decision and that changes it significantly on subsequent restudies, we have either made a bad decision or we got lucky. Neither are good.”
“I have to say, they are rare, but they do happen,” Martino said. “On one particular occasion, we saw cost deviations of almost 100%.”
Energy Storage
In the final panel of the day, participants discussed energy storage.
“It’s a very creative market right now,” Rutty said. “Lots to look forward to.”
Transmission operators said they need a way to control how much power each resource is withdrawing to store or injecting into the grid. “What we would want is that they would install a power relay to limit the output,” Egan said. “The problem you have is, if you … exceed the thermal capabilities we’ve studied, you could cause damage.”
Developers urged regulators to look at storage differently and not try to wedge it into an existing group.
“Storage is very much its own asset class that touches just about every other asset class that hits the grid,” said John Fernandes, the director of policy and market development for RES Americas. “Let’s stop talking about storage as generation storage, storage as negative gen. I get it, but those are still dangerous semantics. … If we really want to be able to accommodate storage at a large scale five or 10 years from now, those rules need to start going into place now.”
SANTA MONICA, Calif. — Dawn Wilson, director of environmental policy and affairs at Southern California Edison, said the company was disappointed with the Supreme Court’s stay of EPA’s Clean Power Plan in February.
“We are specifically engaged with a coalition of energy sector entities that are engaged in litigation in support of the plan,” she said during a panel discussion on the potential impact of the rule on California and the West at the Infocast California Energy Summit.
Ray Williams, director of long-term energy policy for Pacific Gas and Electric, said his company also supported the EPA plan.
“Basically, we say we’re a utility in the business of assembling a clean portfolio,” Williams said. “This is — from a business perspective — something that is doable.”
Travis Kavulla, vice chairman of the Montana Public Service Commission and president of the National Association of Regulatory Utility Commissioners, brought an inland West perspective to the discussion. Montana’s attorney general joined the lawsuit against the regulations, although the state’s governor and Department of Environmental Quality are preparing for implementation.
Kavulla contended that the Clean Power Plan differs from previous federal air quality regulations by going beyond the “fence line” of the power plant to impose requirements on entire states.
“You have a de facto renewables mandate for the entire nation,” Kavulla said.
Kavulla also pointed out the economic impact of the rule on his state and region.
“Montana, Wyoming and Utah have entire communities built around big central coal stations,” he said. “These are influential but also tied to livelihood. We’re looking to understand what the transition [away from coal] may look like.”
Amber Mahone, director of climate policy analysis at Energy+Environmental Economics, pointed to the other forces working against coal, including regional haze rules and low natural gas prices.
“The writing is on the wall,” Mahone said. “It’s not a question of if — it’s when these plants retire.”
“We have to believe as a society that we won’t unabatedly burn coal,” she said.
“What’s surprising is the number of big events that have occurred here in just the past year,” said Boston Pacific founder and director Craig Roach, who presented the report to the board last month.
The firm’s sixth annual report for SPP focuses on “broad market and regulatory events” that could significantly impact its markets or require the board’s attention:
The shale gas “revolution”;
EPA policies;
Federal-state jurisdiction disputes;
Challenges to the utility business model;
Industry consolidation; and
Electric vehicles.
Shale Gas Risk Narrowed
Roach cited as one “big event” EPA’s June 2015 draft assessment, which found no evidence that fracking was having a “widespread, systemic impact on drinking water resources.”
The report represented a “significant narrowing of risk” for shale gas supplies, Roach said. “The question is whether that abundance will continue in the future.”
Assuming continued technological advances, Boston Pacific believes it will, noting U.S. Energy Information Administration forecasts that shale gas production in the continental U.S. will increase by 73% by 2040, accounting for 55% of total U.S. natural gas production.
Gas is important to SPP, Roach said, because gas-fired power often sets the price in the RTO’s energy markets and because the flexibility of combined cycle power plants complements intermittent wind and solar generation.
Boston Pacific categorized the risks facing gas supplies as “above-ground” (regulatory) and “underground” (extraction). In other words, Roach asked: “Is the gas there? Can it be recovered at a reasonable cost?”
EPA’s ‘Environmental Campaign’
A second big event, Roach said, was the Supreme Court’s February stay of the Clean Power Plan. The report refers to EPA’s “continued environmental campaign,” saying it has “pushed along multiple fronts to drive the electricity business to reduce a broad range of air pollution emissions and other environmental impacts.”
Boston Pacific said the high court’s stay gives SPP’s board, members and states an opportunity to “collaborate” on their views. “The SPP markets have been, and will continue to be, the path to cost-effective reductions in carbon dioxide emissions,” the report says.
Based on the court’s January ruling upholding FERC’s jurisdiction over demand response compensation, Roach said he expected the court to support the state’s contract-for-differences with Competitive Power Ventures’ combined cycle plant.
“If the Supreme Court took the same principles as it did in the [DR] ruling … it would have reversed the lower court and restored state rights,” he said. “The Supreme Court did nothing like that. It said, ‘We’re going to rule very narrowly.’”
The report says the Maryland decision could result in state programs being “pre-empted under similar reasoning.”
Distributed Resources
Boston Pacific Managing Director Vincent Musco said the company hasn’t changed its view on the impact of distributed energy resources on the utility business model. “Consistent with the past, we see no evidence” that DER will displace the grid and centralized generation, he said.
The report notes that residential rooftop solar is much more expensive than utility-scale solar. “If costs alone drove technology choice, utility-scale would win,” it said. “Notably, utilities have made considerable investments in utility-scale solar and wind resources and are projected to continue to do so.”
Transmission Costs
The report points to customer pushback over growing transmission costs, citing complaints challenging the earnings of SPP members American Electric Power and Westar Energy.
Calling for “substantial grid investment,” the report says the challenge will be allocating expansion projects in a manner “considered fair.”
Industry Consolidation
The one new topic added in this year’s report is industry consolidation, which it said is being driven by the search for “growth and increasing operational efficiency through scale.”
The report says the number of investor-owned utilities has dropped by 52% over the last two decades, from 100 in 1994 to 48 in 2014. Average market capitalization has increased from $9.4 billion in 2004 to $16.2 billion in 2014 (measured in 2014 dollars).
“If there are fewer competitors, that can impact the competitiveness of the market,” Musco said. “It can affect governance, with fewer people around the table and fewer and [weaker] voices.”
Electric and gas utilities tried to convince FERC at a technical conference last week that targeted release of natural gas capacity to generators would alleviate supply constraints and help lower prices.
Other participants said the proposal is premature, ill-defined, discriminatory and interferes with the wholesale power market.
The May 9 conference was scheduled in response to Algonquin Gas Transmission’s petition asking FERC to allow exemptions from its capacity release bidding requirements (RP16-618).
The proposed changes to the company’s tariff would permit “prearranged releases” of firm capacity to utilities or generation owners. The company is one of the partners in the proposed Access Northeast pipeline that would expand capacity by 900,000 dekatherms per day into New England. (See FERC to Consider Electric Utility Purchases of Gas Pipeline Capacity.)
Electric distribution companies in Maine, New Hampshire, Massachusetts, Connecticut and Rhode Island have asked state regulators to approve cost recovery from their ratepayers for access to expanded pipelines.
Richard Kruse vice president, regulatory for Algonquin’s parent, Spectra Energy, told FERC the region is vulnerable to gas and electric price volatility.
“Every time this issue comes up, the rest of the country says ‘New England needs to get its act together,’” he said. The market has not solved the issue. “We have not seen generators sign up for pipeline capacity. We’ve held multiple open seasons and it has not materialized.”
Generators have commitments for about 80,000 dekatherms per day of firm capacity, but Kruse said that has dropped in recent years.
“We thought this would create a clear line of sight between the cost causation to the customer and the benefit [through lower electric rates],” said James Daly, vice president of energy supply for Eversource Energy, another partner in Access Northeast.
Algonquin said its waiver request is consistent with FERC policy exempting releases for state-regulated retail access programs from bidding requirements.
But critics said programs to benefit the electric distributors don’t yet exist.
“To a suspicious mind, any program that any state asserts would advance reliability would fall under the ambit of the program,” said former FERC Chairman Joseph Kelliher, now vice president for federal regulatory affairs at NextEra Energy. “Here the commission would be writing a blank check to the states that any program you stick the reliability label on would be permitted.”
Kruse said Algonquin would welcome guidance from the commission.
Phil Van Schaack, MISO electric-gas operations coordinator, said there was a record 2,480 Bcf of natural gas in storage at the beginning of April, a 60% rise over last year’s end-of-winter inventory.
All three cylinders of the pitch system in the eight-year-old Vestas V82 1.65-MW turbine in Oliver Township, Mich., suffered oil leaks, according to an investigation by Exelon. The failed pitch system, and 45-mph winds, pushed the blades to rotate at 18 rpm, far more than the 14.4 rpm nominal speed. Nobody was injured, but the $1.5 million turbine was destroyed when it fell to the ground.
Riverstone Holdings, Talen Energy’s largest shareholder at 35%, reportedly is leading an effort to take the independent power producer private.
Duke Energy will build a 21-MW combined heat and power plant at Duke University that will cut the university’s carbon emissions by 25%. The natural gas-fired plant will fuel a turbine that will turn a generator, and the waste heat will be captured to produce steam for buildings. The project still needs approval from the North Carolina Utilities Commission.
Talen Energy will pay more than $1 million to agencies in Pennsylvania, Delaware and New Jersey to settle a claim stemming from a 2005 fly ash spill at its Martins Creek Power Plant on the Delaware River.
Six energy companies have launched Grid Assurance, a company providing shared transmission parts inventory to restore service during emergency outages more quickly.
The Wisconsin Public Service Commission last week approved American Transmission Co.’s reorganization plan that will allow the company to more easily take on transmission work in other states.
Other participants said the proposal is premature, ill-defined, discriminatory and interferes with the wholesale power market.