Canadian pipeline giant Enbridge is buying American pipeline company Spectra Energy in a $28 billion deal that will create North America’s largest energy infrastructure company.
Enbridge, which specializes in pipelines moving crude oil, will be moving into the natural gas transportation business with the all-stock transaction. Enbridge said in its news release that the acquisition will allow it to diversify both regionally and operationally.
The deal will give Enbridge a continent-wide system of natural gas, gas-liquid and crude oil pipelines, as well as terminals, gas distribution operations and a stable of wind, solar and geothermal generation.
Source: Enbridge
“Over the last two years, we’ve been focused on identifying opportunities that would extend and diversify our asset base and sources of growth beyond 2019,” Enbridge CEO Al Monaco said. “We are accomplishing that goal by combining with the premier natural gas infrastructure company to create a true North American and global energy infrastructure leader.”
11.5% Premium
Monaco will remain at the helm of the combined companies. Spectra CEO Greg Ebel will move over to serve as non-executive chairman of the Enbridge board. “The combination of Enbridge and Spectra Energy creates what we believe will be the best, most diversified energy infrastructure company in North America, if not the world,” Ebel said.
Spectra shareholders will get Enbridge shares valued at about $40.33 each, a premium of about 11.5% from Spectra’s closing price Friday. At closing, which the companies expect to be completed by the first quarter of 2017, Enbridge shareholders will hold about 57% of the new company, and Spectra shareholders will hold 43%. Headquarters of the new company will be in Calgary.
The deal comes at a time when natural gas producers and transporters are struggling with low commodity prices even as they are constructing large numbers of new pipelines and extending older ones to accommodate the increased production from shale gas plays. Existing pipelines are especially valuable, considering the costs and regulatory hurdles facing new pipeline construction.
Setbacks
Both Spectra and Enbridge have recently had setbacks in pipeline construction projects. The Massachusetts Supreme Judicial Court ruled that power utilities that would become customers of the Spectra-proposed Access Northeast in New York and New England cannot pass on additional construction costs to customers. In June, a Canadian court blocked Enbridge’s proposed Northern Gateway oil pipeline that was to run from Alberta — home of Canada’s tar sands fields — to terminals on the Pacific Coast.
Enbridge’s 450-acre Superior Terminal at Superior, Wisconsin Source: Enbridge
And just days ago, Enbridge announced it was suspending pursuit of regulatory approval for its proposed $2.6 billion Sandpiper pipeline in Minnesota, citing a drop in projected crude oil production in South Dakota and shifting of customer capacity needs to the Dakota Access line.
The Dakota project is garnering notice because of protests from the Standing Rock Sioux Tribe, which is blocking access to a construction site near the border between the Dakotas. The tribe has filed a lawsuit against the U.S. Army Corps of Engineers for approving the pipeline crossing the Missouri River upstream from the tribe’s reservation. The suit claims that the pipeline threatens both the tribe’s drinking water source and its sacred lands.
Fires — possibly arson — caused an estimated $1 million in damage to Dakota Access construction equipment in Iowa last month.
Spectra is not Enbridge’s first acquisition of the summer. Last month, it announced that it and Marathon Petroleum were investing in Dakota Access, with the two companies acquiring 49% equity interest in the Bakken Pipeline System from Energy Transfer and Sunoco Logistics. Enbridge put up $1.5 billion for its 37% share of the 1,168-mile, $3.78 billion pipeline, which is to run from North Dakota to terminals in Illinois.
IRVING, Texas — SPP’s two newest stakeholder groups are taking a look at the future, while also stepping almost a decade into the past to resolve the sticky issue of Tariff Attachment Z2.
The Z2 Task Force last week began its work overseeing waiver requests from entities billed for sponsored transmission upgrades dating back to 2008. Meanwhile, at Gulf Coast Power Association’s third annual SPP Regional Conference last week, Strategic Planning Committee Chairman Mike Wise said that his committee has formally launched the Export Pricing Task Force, which will study how SPP can maximize its ample renewable resources.
The latter group’s charter charges it with evaluating “mechanisms to establish equitable and not unduly discriminatory prices for exports and imports of electricity.” SPP has more than 22,000 MW of renewable resources in its interconnection queue, a luxury considering the RTO’s low load growth and ample reserve margins — but a tantalizing energy source for other markets.
“The question is, how do you get this renewable energy outside SPP to those areas that really need it, and how do you price for it?” said Wise, senior vice president of commercial operations and transmission for Golden Spread Electric Cooperative. “The majority of transmission for the good of the load in the footprint has been approved for building or is in construction right now.”
To illustrate his point, Wise said he compared the population growth over the past 25 years in SPP’s 10 largest cities with that of the Dallas-Fort Worth area. He said SPP’s cities have grown by 2.2 million, while the DFW area has added 3.3 million new residents during that same time.
“Our load growth is on zero, or barely north of zero, with an abundance of natural resources coming in,” Wise said.
Asked if the task force would work with other RTOs, Wise told RTO Insider, “We don’t know yet.”
The task force, which has yet to meet, will focus for the time being on recommending rates that can recover the costs of incremental transmission needed for exports and imports.
The group will evaluate Tariff and FERC rules on pricing transactions across seams and the “business case” for exports. It is scheduled to sunset by July 2017.
Joining Wise on the task force are SPP Director Graham Edwards and members Wes Berger (Southwestern Public Service), Blaine Erhardt (Basin Electric Power Cooperative), Dennis Florom (Lincoln Electric System), Greg McAuley (Oklahoma Gas & Electric), John Olsen (Westar Energy) and Richard Ross (American Electric Power).
The group will address the equity concerns of the so-called Group B members, whose requests to escape direct assignments for upgrades totaling $42.6 million were rejected by the MOPC in July. The five Group B members said the charges should be allocated to the base plan and included in regional and zonal charges under SPP’s Tariff.
The task force also will consider the $113 million in upgrade costs assigned to entities that did not request waivers (Group C).
“We’re actually talking about less than 10% of the overall cost of credits in the waivers,” said task force Chair Denise Buffington, corporate counsel for Kansas City Power and Light. “Hopefully, everyone can see the long-term benefits of a solution everyone can live with.”
Following the October presentations, the task force will evaluate the existing Z2 process and recommend how to compensate upgrade sponsors in the future. It could also be asked to evaluate and recommend improvements to the Tariff attachment going forward.
The task force includes Meena Thomas, a senior market economist with the Public Utility Commission of Texas and the only non-SPP member on the 15-person group. Thomas is also a member of the regulatory-driven Cost Allocation Working Group, whose members are not allowed to serve on other working groups. That exception doesn’t apply to task forces.
“To the extent I can consult with CAWG members in advance, I’ll be voting as a CAWG member,” Thomas said. “Otherwise, I’m voting as a representative of Texas.”
Wisconsin regulators began considering electric competition in 1994 but closed the docket in 2000, deciding not to implement retail choice. Now, with the state’s rates the highest in the Midwest, some big power users are calling for another look.
Wisconsin’s large manufacturers are asking state regulators to grant them retail choice, warning that high power prices may otherwise cripple the state’s economic growth. Companies and manufacturing groups filed comments with the Wisconsin Public Service Commission in response to the PSC’s Strategic Energy Assessment (SEA) 2022, a biennial report finalized late last month that forecasts Wisconsin’s power needs six years into the future (5‐ES‐108).
The 70-page report notes that Wisconsin electric rates are the highest among Midwestern states and higher than the national average. In 2015, average industrial rates in the state were 7.77 cents/kWh, versus 6.86 cents/kWh for the Midwest and 6.89 cents/kWh for the U.S. Across all electric use, Wisconsin residents and businesses pay an average 10.93 cents/kWh, compared to the Midwest’s average of 9.66 cents/kWh and the national average of 10.42 cents/kWh.
In a joint comment, the Wisconsin Paper Council and the Wisconsin Industrial Energy Group, which represents more than 30 large industrial ratepayers, said “energy and capacity are not available at reasonable prices in Wisconsin.”
“This trend is of grave concern and results in more industrial load being at risk of expanding or relocating in states with greater market access and/or much lower rates. Action needs to be taken now to prevent the situation from deteriorating further,” the groups said.
The manufacturing advocates also proposed a hybrid solution as an alternative to total retail choice. It calls for competitive bidding on transmission and generation construction projects, incentive-based demand response programs and real-time pricing for all utilities.
Charter Steel, whose Saukville, Wis., manufacturing facility is the largest single-site customer of We Energies, said the utility’s “above-market” rate increases are to blame for the “largest percentage increase in electric rates of any state in the nation” from 1997-2015. The PSC’s assessment did not contain that claim, but the report notes that in the late 1990s, Wisconsin entered a two-decade electric construction boom and utilities “are now recovering associated construction costs in rates.”
Charter blames “a massive level of excess electric generating capacity” from WE for the hikes and says that electricity expenses are higher than labor costs at its Saukville plant. The company said the state should open a retail market for at least the largest electric customers.
“Every lapsed year with the status quo is an unnecessary tax on southeast Wisconsin electric users measured in hundreds of millions of dollars,” Charter wrote.
The Retail Energy Supply Association, a trade group of competitive retail electric and natural gas marketers active in nearby Michigan and Illinois, echoed Charter in comments, calling for a “well structured” competitive market.
RESA spokesman Bryan Lee said the Wisconsin veto of market restructuring can be contrasted with Illinois’ outcome.
“In the late 90s, when just about every state in the country was considering the failure of monopoly regulation and introducing competition, Wisconsin was the leading state. In those days, Wisconsin was the low-cost state. The regulators said Wisconsin was low-cost and decided against it while the then-high-cost state of Illinois decided to adopt it. To make a long story short, it’s a tale of two states. The states have flipped: Illinois is one of the least-cost states and Wisconsin is one of the highest cost states.”
Lee said it is a “disservice” not to have retail choice. “There’s no question that competition works,” he said. “We use competition in every other segment in our economy.”
The Wisconsin PSC opened generic docket 05-EI-114 in 1994 to collect stakeholder comments on the issue and created a 22-member advisory panel to explore the issue. By 1996, a PSC report to the state legislature suggested that competition could be introduced in Wisconsin as soon as 2001. However, the commission’s 2002 SEA concluded that “the competitive market is not providing a reliable source of capacity at a reasonable price.”
The Illinois Energy Professionals Association, an organization of consultants to industrial, commercial, government and aggregated residential electricity customers, filed comments saying the Wisconsin PSC should consider retail choice as their state had, saying it can reduce rate increases.
The group said retail choice results in more accurate and timely price signals. The regulated format “is inherently incapable of responding to prevailing conditions that are distinctly different from those for which the regulated vertical monopoly was originally designed,” it wrote.
A spokesman for Wisconsin’s Department of Agriculture, Trade and Consumer Protection said the department had no position on the matter.
Legislation Required
Jeffrey Ripp, an administrator of the Wisconsin PSC’s Division of Energy Regulation, said it would require legislative approval to switch to deregulation, even if it was recommended by the PSC. “There isn’t a whole lot we can do because we do what the Legislature tells us to do,” Ripp said.
In the SEA, the commission said it “continues to investigate ways to mitigate electric rate increases to ensure Wisconsin remains competitive in a global marketplace.” The report also said the PSC is considering allowing generators to sell excess capacity into the MISO markets.
The Citizens Utility Board (CUB), a consumer group, urged the PSC to allow utilities to sell excess capacity elsewhere. “For ratepayers to receive value from their investment, the commission and utilities must prioritize decreasing retail rates through cost control in rate cases and other measures, and utilities with existing and forecast excess capacity and energy must work to monetize this surplus through market sales, the revenues of which are returned to ratepayers through the ratemaking process.”
The CUB said the PSC’s main focus going forward should be cost control, “decreasing rate levels whenever possible.”
‘Little Evidence’
Not everyone buys the idea that retail choice results in lower prices. A study released earlier this year by Christensen Associates Energy Consulting for the Electric Markets Research Foundation concluded, “Nearly two decades later, there is little evidence that retail choice has yielded any significant benefits.”
The study also cited a lack of demand elasticity, saying customers’ short-term response to electricity prices was small and that customers’ willingness to be curtailed was “even smaller.”
According to the study, 14 states and D.C. currently allow retail choice, while eight states have since suspended or rescinded it.
Sarah Barry, executive director of Wisconsin energy consumer group Customers First Coalition, said her organization opposes deregulation efforts. Barry said rates for average consumers in deregulated states are about “30% higher than states with traditional utility regulation.”
“Wisconsin addressed this issue in the late 1990s and has successfully avoided the pitfalls of deregulation that customers in many states like Texas, California, Illinois and Michigan have faced and continue to face,” Barry said.
MISO plans to file a waiver with FERC on its winter energy offer cap policy while it waits for the commission to work out whether a soft cap will replace the current $1,000/MWh hard cap, RTO officials told the Market Subcommittee last week.
The waiver, to be filed Sept. 30, is the same approach used in the last two winters since natural gas prices spiked and drove energy offers above the cap during the polar vortex in early 2014. Cost-based offers above $1,000/MWh will be verified by MISO’s Independent Market Monitor, and the costs above the cap can be recovered via the RTO’s Revenue Sufficient Guarantee payments.
Chuck Hansen, of MISO’s market evaluation design group, said it was unlikely that offers would climb above $1,000/MWh from Dec. 1 to April 30, the length of MISO’s requested waiver. “Given the current low prices and the improved understanding of gas and electric coordination, it seems remote that offers will exceed the cap this winter,” he said.
MISO said it continues to wait on FERC before filing revised Tariff language and new Business Practices Manuals. “Until that point, we’ll just repeat the approach we’ve used over the last two winters,” Hansen said. Last year, MISO said it would have a permanent offer cap solution worked out in time for the 2016/17 season. (See MISO: No Change to Energy Offer Cap this Winter.)
In January, the commission proposed that offers in all RTOs be capped at the higher of $1,000/MWh or an RTO-verified cost-based offer. (See FERC Proposes Uniform Offer Cap Across All RTOs.)
MISO Developing Make-Whole Payments for Pseudo-Tie Units
John Weissenborn, MISO’s director of market services, said the RTO is seeking to develop a market mechanism to make pseudo-tie units whole when they contribute to local reliability needs.
“We’ll start investigating approaches for compensation and cost allocations for commitments of certain pseudo-tie units,” Weissenborn said.
Weissenborn said MISO doesn’t have any provisions in its Tariff to determine appropriate compensation of make-whole payments to pseudo-tie units. “So we really need to think about an appropriate level of compensation for the commitment,” he told stakeholders.
MISO says offline pseudo-ties can be used to relieve congestion, particularly at market-to-market coordinated flowgates. MISO’s research will include commitments outside of market-to-market congestion, Weissenborn said.
“We haven’t really faced this issue to date, but it’s a possibility and something we need to look at,” Weissenborn said.
MISO is in preliminary discussions with PJM on how to coordinate the effort. Weissenborn said he would return later in the year to the Market Subcommittee with a draft approach.
American Electric Power’s Kent Feliks said the issue would open up “a very large can of worms” and asked if there would be cost responsibilities when pseudo-tie units don’t meet commitments. Weissenborn responded that MISO would have to further define the issue before drafting a mechanism.
CAISO last week launched an initiative to develop a greenhouse gas accounting system suitable for an expanded ISO.
The challenge for the ISO is to strike a balance between the requirements for California’s load-serving entities, which face increasingly stringent GHG emission limits under the state’s cap-and-trade program, and the needs of out-of-state utilities not subject to that mandate.
CAISO is seeking to determine how it can modify its market dispatch process under a regionalized footprint to ensure that energy transactions serving load in California reflect GHG compliance costs, while at the same time allowing deliveries outside the state to exclude any emissions component.
“As the ISO explores a transition from a predominantly single-state balancing authority area to a multistate balancing authority area, the ISO will need to model and identify market flows between market nodes subject to GHG compliance and nodes that are not subject to GHG compliance,” CAISO said in an issue paper.
Before expanding into other Western states, CAISO must develop a GHG accounting system that enables the ISO market to track and price emissions from all participating resources (such as the Jim Bridger plant shown above) while allowing bids from out-of-state generators to exclude GHG costs when not serving California demand Photo Source: PacifiCorp
At present, all energy serving ISO load regardless of its geographical source is subject to cap-and-trade. Internal and external generators alike embed their GHG compliance costs within their day-ahead and real-time market bids, including start-up and minimum load costs. During market runs, the ISO’s market software selects from among those bids to determine the least-cost dispatch to cover all load.
In other words, the energy cost component of the market’s LMP, which is the same for all nodes within the ISO, always reflects a GHG compliance cost.
Complications
While that works for a California-only market, it becomes problematic for an expanded ISO in which LSEs in other states would effectively be forced to pay a premium for compliance with rules that do not apply to them.
CAISO is seeking a way to extract the GHG compliance cost from energy bids by resources serving load outside California while retaining it for in-state loads within the state, all within a single market run.
Because California thermal generators must include a GHG cost in their bids regardless of the location of the sink, however, the only deliveries excluded from the cost will be those in which both source and sink are outside the state.
Another complication is that CAISO currently uses e-Tags to track GHG compliance obligations for energy imported into California. But as the ISO absorbs neighboring balancing authority areas, it will discontinue tagging of transfers from those areas as what were once considered imports become internal ISO transactions.
The Western Energy Imbalance Market (EIM) could provide a model for an expanded ISO, with some limitations.
Rather than embedding GHG costs within energy bids, the EIM allows a participating resource to submit a secondary “GHG adder” — in addition to the bid — to signal its willingness to deliver power into California. If the adder is set to zero, the resource’s output is ineligible for delivery into the ISO but can still serve load in other balancing areas.
“The ISO designed the [EIM] so that the GHG compliance costs will not affect the price in an EIM balancing authority area when load is met from generation external to the ISO,” CAISO said.
Leakage
But California’s Air Resources Board (ARB), which oversees the cap-and-trade program, has expressed worry that the EIM’s dispatch model is inadvertently facilitating carbon “leakage.”
Leakage occurs when the emissions program logs a reduction, despite the fact that no actual decrease in atmospheric GHGs has occurred because of a secondary dispatch: The model attributes balancing energy from a low-emitting out-of-state resource to CAISO, while not accounting for the dispatch of a higher emitting resource serving external demand that would have been covered by the first resource absent the EIM. (See CAISO, ARB to Address Imbalance Market Carbon Leakage.)
CAISO has acknowledged ARB’s concerns and is working with the agency to address the problem. The ISO also wants the board to consider the counteracting effect of atmospheric emissions reductions that occur when the EIM displaces out-of-state thermal generation with renewable exports from California, an approach that could inform GHG accounting in an expanded ISO.
The ISO’s effort to address the GHG accounting is taking shape amid uncertainty about the adoption of cap-and-trade in the West at large. Any design has to be “mindful of the potential need to support multiple GHG trading programs” in the region, the ISO said.
“As more trading models are supported, the complexity will increase and transparency will decrease, which is very likely to lead to a less efficient achievement of carbon reduction goals,” CAISO said, adding that it seeks input that “can foster regional cooperation.”
CAISO will discuss the issue paper during a stakeholder call today. Written comments on the initiative are due by Sept. 20.
All storage resources wanting to qualify as capacity should register as behind-the-meter for the 2017/18 planning year, MISO said at last week’s two-day Resource Adequacy Subcommittee meeting.
The AES Corporation partnered with Indianapolis Power and Light to open the first battery storage facility in MISO in June.
Manager of Resource Adequacy John Harmon said the requirement is a way to accredit storage resources using MISO’s existing framework for load-modifying resources while the RTO develops more comprehensive definitions for storage.
MISO said it is attempting to “clarify the framework” for allowing storage that can provide four hours of continuous energy to offer capacity while also participating as Stored Energy Resource (SER) in the regulation market.
Harmon said more discussion is needed for qualifying storage resources that do not wish to be classified as behind-the-meter. MISO also has yet to develop procedures to support sustained power from storage resources, Harmon said.
“We worked through that [research and development] process and found it would not be feasible for registration in time for the 2017/18 planning year,” Harmon said.
In preparation for next year’s auction, MISO is proposing to certify the capability of storage as capacity based on data from the Generating Availability Data System. Class or fleet averages will be used for storage with less than 12 months of GADS data.
The RTO is asking stakeholders this week for input on incorporating storage using the existing qualification process.
Kent Feliks, manager of regulatory and RTO policy at American Electric Power, asked how many storage resources are going to be able to register as capacity in the near future.
“It’s pretty small. It’s probably less than 100 MW, and that’s being generous,” Harmon said.
Consumers Energy’s Jeff Beattie asked how many megawatts of storage are currently in the interconnection queue.
“I can’t answer that, but I do hear interest from individual market participants. From what I see, we’re at the early stages. That’s why we have rules dealing in the short term and are talking about developing solutions to get ahead of this as much as we can,” Harmon said.
RASC to Take Up Gas-Electric Coordination
Renuka Chatterjee, MISO executive director of resource adequacy and transmission access planning, told the RASC to send ideas and comments on a plan to improve gas-electric coordination.
Chatterjee also said the RASC would probably take over management of MISO’s winter fuel survey, which was previously handled by the now-closed Electric and Natural Gas Coordination Task Force.
IRVING, Texas — SPP’s transmission buildout, interregional processes, new generation resources and cyber threats highlighted the Gulf Coast Power Association’s third annual SPP Regional Conference on Sept. 1. Here’s a summary of what the more than 150 attendees heard.
Three influential SPP stakeholders debated the merits of FERC’s Order 1000’s competitive transmission process and just how much more transmission needs to be built, after more than $9.7 billion in upgrades since 2004.
“As one who serves members, we know transmission has to be built to get the energy out, but we don’t want it built on the backs of the consumers of SPP,” said Mike Wise, chair of the RTO’s Strategic Planning Committee and senior vice president of commercial operations and transmission for Golden Spread Electric Cooperative. “Transmission is an inter-generational asset. The stuff we’ve built is providing those dividends. The question is how do you get transmission built and paid for by those who are really benefiting from it.”
“Is the current transmission funding method working? Yes,” said GridLiance COO Noman Williams, who chairs SPP’s Markets and Operations Policy Committee. SPP’s “highway/byway regional cost [sharing] allocates the cost for future transmission facilities based on voltage level. What we’re seeing is pockets of load growth and load shifting. Ultimately, we’re going to see additional build in SPP. If you look at the age of the infrastructure in SPP … there’s a lot of old stuff.
“So will there be a need to have additional transmission built? I’d say yes, if that’s the goal,” Williams said. “The real frontier for transmission in SPP the next 10 to 15 years is at the seams. How do you deal with that, and how do you get energy to the seam?”
Former Missouri Public Service Commissioner Steve Gaw, SPP policy director for The Wind Coalition, said Order 1000 is not yet providing needed solutions to interregional planning. “Order 1000 really needs to be strengthened so we are … implementing [interregional] transmission in the best interest of consumers, the same way we do it regionally.
“I think it should be a top priority for FERC to work on that issue. I think it’s already clear there’s a substantial problem with the order,” Gaw said. “There are significant questions about what type of upgrades will be necessary, and whether or not we can ever get those paid for in the [generation interconnection] process we have now. We need a mechanism to try and figure out whether there’s another way to do this.”
Wise agreed with Gaw, saying the RTOs could use some help from above in building interregional projects.
“There’s a little bit of transmission that needs to be built for load pockets, but I think the projects that need to be built are across the regions,” Wise said. “We need some sort of national directive for getting transmission built across regions. Is Order 1000 the right way to do this? Quite possibly, but we need a federal directive and federal help to get these interregional projects built.”
Williams said competitive transmission is off to a slow start in SPP, contrasting the withdrawal of the RTO’s only awarded project with the ability of PJM and CAISO to approve competitive projects. “We recognize we can do it better and we can do it cheaper,” he said. “We devoted a fair amount of cost to participating in that process, but in the end, we didn’t build a project that didn’t need to be built.”
“The caution I have for Steve and Noman is the load has to pay for this. We need to make sure the [transmission] projects show a real cost-to-benefit,” Wise said. “We do not want to build transmission that benefits the load if the load isn’t going to pay for it.”
Wise said wind generation enabled by transmission had produced economic development in his company’s footprint. “Golden Spread landowners … they love to have these wind farms built on their land,” he said. “It’s generating huge amounts of money for them. We want to encourage this.”
As chair of SPP’s Seams Steering Committee since its creation in 2010, Paul Malone is well aware of the difficulty the RTO has had in developing interregional projects with MISO.
“We’ve hit a wall when it comes to building interregional transmission,” said Malone, transmission compliance and planning manager for the Nebraska Public Power District. “We’ve built a lot of transmission in the SPP footprint, but we’re having difficulty of finding solutions that cross the borders.”
Alan Myers, director of regional planning for ITC Holdings, lamented the lack of infrastructure across the RTO seams, saying it’s a nationwide problem.
“People have been saying we need some sort of a national policy and vision for some of those things, but we don’t have it,” he said. “That doesn’t mean we can’t stop asking for it. We need a national view to provide correct signals. Each RTO serves their own masters and interests, but sometimes, you need another view to close those gaps.
“One of the things we’ve consistently done as an industry is undervalue transmission construction. … If a project is good across the seams, does it really matter if it’s a low-voltage project? Can’t it just be a good project? How about we start talking about beneficial projects, rather than reliability, economic and policy projects?”
Merchant transmission projects have their own difficulties, said Jonathan Abebe, manager of engineering and transmission for Clean Line Energy Partners. Two of the company’s six proposed projects focused on delivering wind energy from the Great Plains to the seaboards, the Grain Belt Express Clean Line and the Plains & Eastern Clean Line, begin in SPP’s footprint.
“Some projects are more challenging than others, specifically the financing,” Abebe said. “We cross multiple states, so we need approval in multiple states. It’s much easier to make the case for the line in states where wind is being built and where it’s being delivered. Some of issues we’ve had are in the fly-by states that are not getting the wind.
“A lot of these RTOs are used to approving projects coming in front of them. There’s not a process for RTOs to study merchant projects, which causes regulators difficulties in approving them.”
Former MISO CEO Graham Edwards (2006-2009), an SPP director since January, gave the keynote address, urging RTOs to remember their end consumers and to continue to improve interregional processes.
“We need to demonstrate value, and we need to communicate the value,” he said. “We haven’t been very good about communicating the benefit we bring to the … residential and industrial consumers that are on your systems.”
Edwards also said the difficulties SPP and MISO have had in approving interregional projects is partly because of criteria that discount lower-voltage transmission lines.
“The lower-voltage projects need some attention, in my opinion. Interregional planning has some merit to it. … I think the RTOs can, and should, get together and better implement those processes across the seams,” he said.
Renewables, Storage Growing but ‘There’s Still Life’ in Coal
With the Clean Power Plan looming and cheap gas having replaced coal as the dominant generation source, it probably shouldn’t come as a surprise that SPP’s generation interconnection queue does not include a single megawatt of coal.
It does list 22,000 MW of wind and 2,800 MW of solar. The queue also lists 700 MW of gas-fired generation.
Tenaska Power Service’s Courtney Mehan, director of SPP origination, called the CPP “the elephant in the room.”
“Some speculate 2 [GW] of coal retirements as a result of the Clean Power Plan. That overhanging [regulation] and cost is going to drive most of these coal retirements, but there’s still life in these plants.”
Noting a NERC forecast from December that SPP won’t dip below its 13.6% reserve margin until 2024, Mehan said, “Without these kinds of reserve margins, without significant retirements, you aren’t going to see a push to build” non-renewable generation.
Bill Grant, director of strategic planning for Xcel Energy’s interests in New Mexico and Texas, said declining water tables are making it difficult to site new thermal generators that require cooling.
“What are your options?” he asked, before referencing another speaker’s comment on plant maintenance. “Maybe it’s the old utility concept of putting duct tape on the [existing] plant and keeping it going for 50 years.”
Or maybe it’s wind energy, which has provided nearly half of SPP’s total generation at times in 2016. (See “Integrated Marketplace Adds Participants, Wind Energy,” SPP RSC Briefs.)
Grant, who chaired SPP’s first wind integration study, recalled its analysis assumed 13 GW of available wind energy.
“Well, guess what? We’re there. We’re taking that much wind energy right now,” he said. “I think we’ve overcome some of the concerns and myths and operational impediments to do that.”
Ben Lowe, director of policy and market development for energy storage provider Alevo USA, said grid-scale storage, with its ability to integrate renewable energy, and provide voltage and ramping support and frequency regulation, makes it “the grid’s Swiss Army knife.”
“Storage makes the grid more efficient, and its costs are only coming down,” he said. “We’re pretty optimistic about what the future holds.”
Members of SPP’s Market Working Group said it has been successful even though it has not produced a large number of new products.
The group is “extremely open. Sometimes, I feel like maybe it’s too much discussion,” said Robert Safuto, director of SPP market intelligence for Customized Energy Solutions. “I think it’s better to lean towards what SPP does. Anyone can show up or listen in and offer an opinion. Other markets I deal with are not like that.”
“I feel like coming into the market, we had a voice right away with the major decisions going on,” said Valerie Weigel, manager of marketing financial analytics for Basin Electric Power Cooperative, which joined SPP last October. “We’ve brought our concerns forward and we’ve been heard.”
Cliff Franklin, a senior regulatory specialist with Westar Energy, said the MWG has discussed only one possible new market offering, a ramping product “that isn’t something you bid or offer or clear in the market.”
“It’s more of an opportunity-cost kind of a thing,” Franklin explained. “Here’s the theory: You allow slower-ramping units to start up in the morning and save your faster units for when you really need them. Why do this? If we can manage ramp better, we might reduce the amount of headroom, which reduces production costs.”
“It’s hard to build a business case around market design or a market element, like battery storage,” said Kevin Galke, a structure and pricing analyst with The Energy Authority. “I don’t think you really want to be the last person to bring a product to market, but I applaud SPP for learning from what others are doing to make a full functioning and operating market.”
Cybersecurity Experts: not if, but when Grid is Attacked
A pair of cybersecurity experts had dire warnings for the audience and suggestions on the protective actions utilities can take.
“A lot of things you’re doing now is [Internet Protocol]-based,” said former Secret Service agent Steven Bullitt, vice president of cyber forensics and investigation for NTT Security, a subsidiary of Nippon Telegraph and Telephone. “I always say you’re either a victim of opportunity or a victim of choice. You’re mostly victims of choice, because you have aging systems and are moving into IP-based solutions, which exposes you to the Internet.
“You’re going to see more attacks in this industry. Other companies may just lose data, but if they hit you, that’s going to have severe consequences.”
Bullitt recalled attending a conference last October, where he was joined by former National Security Agency directors Gen. Keith Alexander and Gen. Michael Hayden. “Gen. Alexander said we’re experiencing the greatest transfer of wealth in our history. He said our intellectual property is being stolen by China and Russia. Gen. Hayden said, ‘Folks, the cavalry is not coming. If you think the government is going to step in, it’s not. You’re on your own.’”
“One thing we know is, it’s not if we’re going to have a cyberattack on the grid, but when,” said former FERC Chairman Curt Hébert, a partner with Brunini, Grantham, Grower & Hewes. “We know this threat has evolved and it’s not standing still. That means we can’t stand still, either. It’s going to be expensive, and I hate that, but it’s necessary so that we can protect our systems.”
Jim Eckelberger, chair of SPP’s Board of Directors, closed the conference with a look 20 years into the future. He predicted “really sophisticated gas plants” will replace all coal plants and that SPP’s 14-state footprint will have so much renewable energy it may not need fossil-fueled generation.
“The Southwest Power Pool is one of those places where green energy is immensely abundant. … It’s the cheapest energy source anywhere in the United States, besides hydro,” he said.
Unlike some of the other speakers, Eckelberger said he isn’t seeking a national energy policy to guide the way forward. “The president is responsible for federal matters, but governors, not presidents, are in charge of what happens in the land mass. … I think the federal government is pretty useless in this process.”
Arizona Public Service and Puget Sound Energy have met the milestones to participate in the CAISO-run Western Energy Imbalance Market and will begin trading in the market on Oct. 1.
“For APS and PSE, the bulk of the work is behind us,” Janet Morris, CAISO’s program management office director, told the EIM’s governing body during an Aug. 30 meeting.
The ISO last year developed a series of readiness criteria to ensure that new EIM participants are prepared to link up with the market.
Among the requirements: executing necessary agreements, establishing forecasting and balanced scheduling capabilities, producing accurate market settlements, and exchanging sufficient data to allow the ISO to monitor market performance.
The implementation process takes about 18 months and requires a new participant to integrate its network model — essentially a detailed blueprint of the balancing authority area’s operations — with that of the ISO. The process culminates in two months of market simulation, in which the participant operates in real conditions without transactions becoming financially binding. (See Arizona Public Service, Puget Sound Energy Enter EIM Testing Phase.)
Morris pointed out that the go-live date for APS and PSE will coincide with a significant update to the EIM’s market software. All participants, including existing members PacifiCorp and NV Energy, are required to “validate” the new market features. In the future, CAISO plans to schedule new member implementations for spring in order to avoid overlap with fall software releases.
“What’s one or two of the top things you learned from implementations to help others out there” planning to join the EIM? asked governing body member John Prescott.
“I think one of the first challenges in the early part of implementation is organizational change management,” Morris said, referring to the need for utility staff to adapt to the EIM’s operational practices. Those participants “need to understand how all the data fed into the market influences the market’s outcomes.”
Later in the implementation, new participants come to recognize the need for the two months of parallel testing, Morris added.
Governing body member Carl Linvill wondered if new participants have realized any “side benefits” from integrating their network models with the ISO.
“I think there’s a lot of benefits of having that visibility [into another balancing authority area] to enhance reliability,” Morris said. “That’s absolutely another benefit besides those coming out of the market.”
Morris told the governing body that Portland General Electric is on track to join the EIM in October 2017 after completing a scheduling coordinator agreement, identifying all participating resources in its area and providing a full network model ready for CAISO integration.
Idaho Power is also on schedule for an April 2018 start-up. An implementation agreement has been approved by FERC, and the utility plans to file for approval with the Idaho Public Utilities Commission by the end of summer. The company expects to export its network model to the ISO late next month.
Circling back to the upcoming APS and PSE implementation, governing body member Valerie Fong pointed out that it will be the first in which two utilities are integrated into the EIM on the same day — and at opposite ends of the Western Interconnection.
“We’re confident, but with that confidence we rely on a very robust support plan,” Morris said. “We plan for the worst and expect the best.”
Numerous stakeholders have called for rehearing of New York’s Clean Energy Standard, raising objections over the subsidy for nuclear power, the elimination of support for some legacy renewable energy plants and the potential loss of renewable energy credits (REC) to adjoining states (15-E-0302).
Most of the requests were filed shortly before the mid-week deadline following the New York Public Service Commission’s Aug. 1 order approving the standard. (See New York Adopts Clean Energy Standard, Nuclear Subsidy.)
The CES is designed to support the state goal of 50% renewables by 2030, with nuclear power seen as a bridge until renewable energy facilities are built at scale.
Nuclear Subsidy Under Attack
The most controversial part of the order created a new “Tier 3” subsidy — zero emission credits (ZECs) — for nuclear power. Critics say the program would cost more than $7 billion over its 12-year lifespan. Without ZECs, nuclear owners said their plants would close, and state officials said carbon reduction goals could not be met.
The Alliance for a Green Economy and a coalition of environmental, anti-nuclear groups and elected officials objected to the subsidy as counter to the goals in the state Energy Plan and the Reforming the Energy Vision initiative.
“The PSC has failed to demonstrate that imposing exorbitant surcharges which inure solely to the benefit of nuclear operator(s) is in the public interest and consistent with existing statute and policy,” the coalition wrote.
Canadian Hydro’s Complaint
Canadian hydropower developer HQ Energy Services said additional resources from Quebec would not be credited for their environmental attributes. “For reasons unexplained, the CES order excludes significant amounts of hydroelectric power, including incremental hydroelectric power relying on new storage impoundment, from inclusion in the CES Tier 1 solicitation and REC process,” it wrote.
Tier 1 establishes the obligation of load-serving entities to invest in new renewable energy resources with an in-service date of Jan. 1, 2015, or later.
Tier 2 in the order is limited to run-of-river hydroelectric facilities of 5 MW or less, wind farms and biomass direct combustion plants that were operating before Jan. 1, 2003.
PSC staff had advocated splitting legacy renewables into two groups: Tier 2a for those resources able to sell their attributes in other states; and Tier 2b, for those unable to sell attributes because of their age or other restrictions imposed by neighboring states.
The order said splitting the “maintenance tier” for existing renewable energy resources was premature. Facilities eligible for these payments would have to demonstrate they would likely close because of their unprofitability without additional support from the state.
“It is very possible that New York will have to replace the clean attributes of existing facilities that are sold in Massachusetts with clean attributes from new facilities at a higher cost to meet the 50-by-30 goal,” IPPNY wrote. (See Massachusetts Bill Boosts Offshore Wind, Canadian Hydro.)
Likewise, Transmission Developers Inc. seeks rehearing because of this “change in circumstances” since the order was adopted. “Such an initiative by a neighboring state very well could have the effect of siphoning off a significant portion of the renewable energy supply that would otherwise be available to New York state,” it wrote.
Procedural Complaint
The Public Utility Law Project alleged the compressed schedule under which the PSC considered ZECs violated the State Administrative Procedure Act (SAPA). The group contends the law requires 45 days for public comment instead of the 10 that the PSC allowed after the staff proposal that included ZECs was released in early July.
“Nowhere in SAPA, however, is there authorization for ‘add-on’ rules or rules resulting from the ‘logical outgrowth’ of the process since the issuance of a prior notice that did not cover the changes contemplated,” PULP wrote.
Last month, small hydropower owner Ampersand Hydro filed a complaint with the PSC, seeking inclusion in the ZEC tier as a non-emitting resource. (See Hydro Owner Wants in on New York Nuke Subsidy.) A similar request was made last week by Energy Ottawa.
Exelon also sought clarification to protect ZEC payments to its R.E. Ginna and Nine Mile Point nuclear plants in the event its proposed acquisition of the FitzPatrick plant falls through. (See FitzPatrick Sale Filed with New York Regulators.)
The New England Power Pool (NEPOOL) is considering redesigning its market rules to align them with the region’s efforts to reduce carbon emissions from the generation sector.
Gordon Source: PSEG
The first of six scheduled stakeholder meetings on the Integrating Markets and Public Policy (IMAPP) process was held Aug. 11.
The goal is to provide guidance to ISO-NE on how wholesale markets could be adapted to meet the public policy goals of the New England states. The group hopes to complete its work by the RTO’s annual meeting Dec. 2 with market rule changes filed with FERC beginning next year.
NEPOOL, created in 1971, has more than 440 members (with about 260 voting members), including utilities, independent power producers, marketers, load aggregators, end users and demand response providers.
RTO Insider recently spoke to its chairman, Joel S. Gordon, whose day job is director of market policy at Public Service Enterprise Group’s PSEG Power Connecticut unit. The interview has been edited for clarity.
New England has usually had an active public policy agenda related to energy, but this is a rather different way to approach this topic. So, why now?
“If you look at the New England states, there has been a rather large consensus that the environmental objectives that the individual states have are all heading in the same direction. The states have different means to achieve them, but they are all part of the Regional Greenhouse Gas Initiative, and some of them have even more aggressive targets than RGGI.
“They have outlined means to achieve [decarbonization] through mandates for aggressive carbon reduction and renewable energy goals, so in order to meet those targets that have been legislatively mandated, they needed to take some actions that are outside of the market.
“Right now, the markets, as we’ve designed them, are not designed to drive the [decarbonization] of the generation fleet. It is designed to find the most efficient set of resources and to meet a reliability need, which has been the mission of NEPOOL and ISO-NE throughout the entirety of their existence.
“The recognition of our members has been that over the last couple of years, as we’ve seen more programs come out of the states, we’ve recognized that the markets were not really not going to give them what they needed, so the states took these out-of-market actions. [IMAPP] is a recognition that the states have legitimate public policy goals, so the markets should be designed to help achieve those public policy goals.”
“From the states’ perspective, the markets weren’t moving fast enough to get them where they needed to be and that’s where these big RFPs come from, and the Massachusetts legislation. Our goal at NEPOOL and for the region is to create a competitive market signal to get the states what they need so they don’t have to act on their own. If we’re successful, the markets on their own will find the most cost-effective means in meeting those state objectives.”
In remarks to stakeholders, you said, “No other RTO has done this before.” Are you optimistic that you can meet these challenges, or is it a bit frightening that New England is out there a bit alone, perhaps the first region trying to integrate markets to this extent with public policy?
“I’m incredibly optimistic that we can find solutions to the problems that we face, the challenges before us. That’s what NEPOOL is really good at as a stakeholder organization. We have six different governing sections that look at our industry from all different perspectives. This is what the IMAPP initiative is, reaching out to the members as they try to find solutions to the challenges.
“I’m also optimistic that the states have encouraged us to do this. They recognized that in [the multistate requests for clean energy] that there’s potential in what the markets have developed. But recognizing they have objectives mandated in their legislation, we can provide a pathway to achieving their objectives using the discipline of competitive markets.”
You seem to have a pretty aggressive schedule in what seems to be a large task ahead of you. Are you confident you will have a consensus document to present to ISO-NE in December?
“The process that we’ve set up [six meetings over four months] is an aggressive schedule. But it’s also important that we put ourselves in that schedule so when we start out in 2017, that we’ll be in a position to respond to the mandates that are out there legislatively. They have carbon reduction goals, so we have to start the process sooner, rather than later, to go to a market-based solution. It also provides the states with an opportunity to see what NEPOOL is doing. They may see there is less pressure for them to act if they see what we’re doing. Really, it’s our first step. I think we’ll be able to get to a high-level framework document by December.
“We hopefully will have a framework for a suite of solutions that would achieve a set of objectives, then we would get into the traditional NEPOOL process that works with ISO-NE and begins to analyze how it would work with the market rules. Then we would begin to work that into the Tariff revisions that would implement it.”
Do you see this process being informative for other RTOs, or do you see New England’s situation as unique?
“We are looking to the other regions as well to understand other concepts that are out there that may help to achieve our goals, which are somewhat unique to New England. We see some of this discussion in PJM in their Grid 20/20 process. [See PJM’s Grid 20/20 Ponders Mixing Public Policy, Competitive Markets.] But integrating public policy is not part of their mandate. In New England, we are fortunate in there are six states and they’re pretty much aligned, as opposed to [PJM’s] 13 states [which are not].”
Would it lead to inefficient market outcomes if rules that go into effect 10 years from now run counter to commitments that states make now through long-term power purchase agreements?
“Timing is going to be a challenge, there’s no question. We’ve talked about two timelines that we need to deal with [10-year goals and 30-year goals for emission reductions.] … I think we’re going to have to work on integrating the short-term and the long-term. I’m not sure how that happens. That’s one of the things that this process is going to have to deal with.”
