Conceding that much of the 2016 construction season has been lost due to regulatory delays, the developers of the Constitution Pipeline say the project will be delayed by nearly a year (CP13-499).
The pipeline, which is intended to deliver shale gas from Pennsylvania into the New York and New England markets, is now projected to begin service in the second half of 2017. The developers had proposed operation of the 124-mile pipeline in the fourth quarter of this year.
FERC did not act on the developer’s request to cut trees in New York before March 31, so that window has closed. (See Constitution Again Seeks Tree-Felling Permission in NY.) Constitution is required to cut trees between Nov. 1 and March 31 to comply with U.S. Fish and Wildlife Service recommendations to mitigate impacts on migratory birds and the northern long-eared bat. FERC did not grant permission in New York but did allow those operations in Pennsylvania, which have been completed.
“The March 2, 2016, target date for receipt of written authorization has passed and, as a consequence, Constitution will not be able to complete the required tree felling within the deadline established by the United States Fish and Wildlife Service,” the company wrote in a letter to FERC. “The renewed request for written authorization to conduct tree felling set out in the Feb. 25 letter, accordingly, is now moot and no longer needed. Constitution will file a new request for the necessary authorization at the appropriate time.”
New York Attorney General Eric Schneiderman had opposed the operation, saying FERC should not allow tree felling without a Section 401 permit under the federal Clean Water Act, to be issued by state environmental officials.
Constitution spokesman Chris Stockton said the New York Department of Environmental Conservation has until April 29 to render its decision. He added that construction in Pennsylvania will continue and some activities in New York away from stream crossings would proceed.
FERC will hold a two-day technical conference to review its transmission policies, an initiative that may result in refinements to its Order 1000 rules on competition and its 2006 order offering incentives to developers.
Chairman Norman Bay announced Thursday that the commissioners will lead a technical conference on competitive transmission development processes June 27-28. Bay said the conference will look at issues including the use of cost containment provisions and the relationship of FERC incentives to competitive development (AD16-18).
Bay made the announcement after a staff presentation on the results of a data-gathering initiative to measure the effectiveness of Order 1000 and other transmission initiatives. (See related story, FERC Transmission Metrics Report IDs Potential Underinvestment.)
The technical conference also makes good on a promise the commission made in an order Thursday rejecting ITC Grid Development’s request that FERC bar transmission rate reductions in Order 1000 solicitations (EL15-86).
ITC’s petition for a declaratory order asked that the commission rule that winning bids subject to binding revenue requirements be deemed just and reasonable and treated similar to a “black box settlement.” It also sought a FERC ruling that such bids are entitled to Mobile-Sierra protection, meaning they cannot be changed as a result of a complaint unless it harms the public interest.
ITC said it plans to compete for transmission projects in SPP, MISO and potentially other areas with bids that include a projected annual transmission revenue requirement. It said the protection it sought would function similar to an abandoned plant incentive, which ensures developers recover their costs when projects are canceled due to events beyond their control.
‘Asymmetrical Risk’
Absent such protection, ITC said, developers will face an “asymmetrical risk.” The company said both MISO and SPP are requiring binding cost caps that leave developers liable for cost overruns. But if the developer is able to reduce costs, its savings could be negated as a result of a Federal Power Act Section 206 complaint.
The company’s petition attracted dozens of interventions from incumbent transmission owners, regulators, trade groups and industrial electric customers.
FERC sided with commenters who said ITC’s request should be considered as part of a broader rulemaking.
“ITC’s petition highlights important policy issues related to the potential benefits of cost containment proposals in the context of competitive transmission development. However, a petition for declaratory order is not the appropriate means for addressing these issues,” the commission ruled.
NextEra Request
The commission said the technical conference will be the forum for discussing the issues raised by ITC and by NextEra Energy Transmission West in a request it filed last year seeking transmission rate incentives for projects in CAISO. The commission responded to NextEra’s request in a January order that granted its request in part and set the company’s base return on equity request for settlement judge procedures (ER15-2239).
That order also promised a technical conference, which it said would consider how risks associated with cost containment proposals relate to the “first expectation” set forth in its 2012 policy statement, Promoting Transmission Investment Through Pricing Reform (RM11-26).
“The commission explained in the policy statement that an applicant seeking an incentive ROE would need to demonstrate that the proposed project faces risks and challenges that are not either already accounted for in the applicant’s base ROE or addressed through risk-reducing incentives.”
The order also said the conference would look at how risks assumed by developers submitting cost-capped bids relate to in the policy statement’s expectation that an applicant seeking an ROE incentive based on a project’s risks and challenges “demonstrate that it is taking appropriate steps and using appropriate mechanisms to minimize its risks during project development.”
Anecdotal Evidence, Rising Rates
Commissioner Tony Clark said stakeholders have told him “‘In this particular region we’re seeing this and we think it works well and we’re seeing this in other regions and we don’t think it works quite as well.’ So it’s just time to do an analysis of that in less an anecdotal way and more of a systematic way to see if there’s lessons that have been learned.”
Commissioner Colette Honorable said she also has been hearing from stakeholders about ways to improve transmission planning and cost allocation processes. “Goodness knows we have work to do there,” she said, citing interregional planning as “the tougher [nut] to crack.”
The failure of grid operators to agree on any interregional transmission projects has been a disappointment to developers and wind power advocates.
Honorable also called for the commission to balance the need for additional transmission against costs. “When I first began as [an Arkansas Public Service] commissioner in ’07, I think transmission costs were on average no more than 10% of a consumer’s bill,” she said. “I’m hearing now it’s as much as 20% in some areas.”
FERC last week granted SPP’s request to resettle past bills outside of the 365-day limit in its Tariff (ER16-636).
SPP asked to waive the time limit, citing software-design flaws and the commission’s timing in accepting previous Tariff changes. FERC said it granted SPP’s request because “the underlying error was made in good faith” and the fix caused no “undesirable consequences.”
The problem dates back to the launch of the RTO’s Integrated Marketplace in March 2014. SPP said between March 1 and May 2014, software and/or input errors forced it to recalculate LMPs and market clearing prices in the real-time balancing market. The RTO said a second software error affected settlements for 15 operating days in 2014, and a third error resulted in it undercharging market participants for reliability unit commitment make-whole payment distribution charges.
SPP said some of the errors were discovered more than a year after the operating day. The RTO said software developers could not correct the design flaws in time to adjust all the required market settlements within the 365-day window prescribed in Tariff Attachment AE.
All told, the resettlements represent more than $53,000 in underpayments or overpayments.
Paul Hibbard, vice president of The Analysis Group, expressed concern about New England’s ability to meet its carbon-reduction goals if nuclear plants continue to leave the generation fleet and are only replaced by natural gas. Entergy’s 680-MW Pilgrim plant may retire as early as next year.
“The scary part here is that Pilgrim is the smallest of the nuclear generation within New England [behind Seabrook and Millstone] and all of them continue to be economically stressed,” he said. “How do we let this resource mix evolve in a way that’s going to help meet the states’ carbon reduction requirements?”
As gas plants race to replace retiring coal and nuclear generation, “The question we are being asked is ‘are we in an overbuild situation?’” said Paul Flemming, director, power and gas services for ESAI Power. The question is “especially [relevant] in PJM, but also to some extent in New England.”
Dan Allegretti, vice president of energy policy for Exelon, said that although expanding the Regional Greenhouse Gas Initiative would create more liquidity and increase efficiency, it also faces challenges. “There are legal problems, there are political problems … so the discussion should really center around being trading-ready. So rather than join the compact, I think there’s going to be a future for RGGI to expand … with the other states who have adopted a similar mass-based program for Clean Power Plan compliance.”
David Littell, a principal with the Regulatory Assistance Project, said states’ conflicting rules on clean energy resources are hurting investment.
“Fixing this Balkanized [renewable portfolio standard] system would be beneficial to the whole region. It just makes no sense for everybody starting a [legislative] season going for changes in what qualifies in each state,” he said. “That’s not sending an investment signal that the commercial community can respond to.”
David Alward, Canada’s consul general to New England, addressed fears that large hydropower imports would crowd out smaller solar and wind projects. “In 2014, Canada supplied 13.2% of New England’s electricity, mostly from hydro … this is third behind natural gas and nuclear. It’s hardly oversized.”
“Even though administrations have changed, from Democratic Gov. [Deval Patrick] in Massachusetts to Republican Gov. [Charlie Baker], the commitment to bring in more imports has stayed the same,” said Josh Bagnato, vice president of project development for Transmission Developers Inc. The company has proposed projects to import Canadian hydropower under Lake Champlain into Vermont and New York.
Aleksandar Mitreski, a senior director of regulatory affairs for Brookfield Renewable Energy, warned that power imports into New England don’t have firm contracts. “So … if Quebec or New York or New England has a reliability constraint, they may cut those transactions because they have no requirement to deliver,” he said.
Greg Cunningham, vice president of clean energy and climate change for the Conservation Law Foundation, explained why his group opposes the Massachusetts Department of Public Utilities’ decision to allow electric distribution companies to negotiate supply contracts with natural gas pipeline operators and pass costs to electric ratepayers.
“There are concerns that we have, both from a public policy and legal approach … if it’s going to involve any cross-border interaction between Marcellus shale natural gas and Canada. This is unprecedented — literally never before been done in this country, let alone this region,” he said. “This could result in an overbuild of natural gas that will undermine our public policy goals, the principal of which is our climate goals.”
American Transmission Systems Inc. (ATSI) Worker in Bucket Truck (Source: ATSI)
The commission denied ATSI’s request to rehear two 2011 orders in which it ruled that the company was not entitled to recover exit fees and legacy transmission costs that it incurred because it had not shown that the benefits of its move justified the costs (ER11-2814, ER11-3279).
ATSI, which joined MISO in October 2003, won FERC approval to move to PJM in December 2009.
The commission said that a decision to join an RTO for the first time may involve different motivations than a decision to switch RTOs later.
“The RTO realignment was a voluntary decision by ATSI to change from one RTO to another. While ATSI is correct that the commission has permitted transmission owners to recover the costs of joining an RTO, the commission has permitted such recovery because joining an RTO provides benefits to the transmission owner’s customers through more efficient dispatch of generation as well as more efficient utilization of the larger transmission system,” FERC said.
“The choice to change RTOs does not necessarily provide comparable benefits to the customers because they already enjoy these efficiency benefits in the RTO to which they belong. Moreover, transmission owners may choose to change RTOs based on factors unrelated to customer benefits, such as the benefits to their affiliated generation from differing market rules used by the RTOs,” it added.
FERC on Thursday approved a settlement on financial terms for three transmission projects intended as contingencies for the potential closure of the Indian Point nuclear power plant in New York (ER15-572).
Indian Point Nuclear Power Plant (Source: Wikipedia)
Joining in the partial settlement were the state Public Service Commission, the Department of State Utility Intervention Unit, the New York Power Authority, New York City, the New York Association of Public Power, the Municipal Electric Utilities Association of New York and about 60 industrial, commercial and institutional energy consumers.
The commission judged the settlement, which was uncontested, as “fair and reasonable and in the public interest.”
It provides a total ROE of 10% for the TOTS projects, below the 10.6% base ROE the transmission owners originally sought. The agreement leaves intact the 50-basis-point adder granted by FERC, for costs up to $228 million.
Still pending in the docket are issues relating to the alternating current transmission projects that were first discussed in the state’s plans to address transmission needs in the New York City area. Those AC projects were split off by the New York Public Service Commission and settlement negotiations for them will resume in the coming months. (See NYPSC Directs NYISO to Seek Tx Bids.)
FERC Office of Enforcement staff said last week that the presence of flaws in the CAISO market is irrelevant to their market manipulation case against ETRACOM and principal trader Michael Rosenberg.
FERC accused the company of submitting uneconomic virtual supply transactions at the New Melones intertie at the CAISO border to affect power prices and benefit its congestion revenue rights in a scheme that allegedly generated $315,000 in profits in 2011.
In their reply to the allegations last month, the company said “staff has no basis for claiming that ETRACOM defeated or obstructed a well-functioning market,” because of market design flaws and software pricing and modeling errors that scrambled trading at the intertie. (See “Traders to Seek De Novo Review in CAISO Manipulation Case,” Federal Briefs.)
Staff rejected ETRACOM’s “market flaw defenses,” saying the commission’s definition of fraud as including actions “for the purpose of impairing, obstructing or defeating a well-functioning market” does not absolve the company (IN16-2).
“Staff construes the use of ‘well-functioning market’ to refer to any commission jurisdictional market operating under a tariff that the commission has found to be just and reasonable and not, as respondents suggest, a qualitative limit on the reach of the Anti-Manipulation Rule to only those commission jurisdictional markets without flaws,” staff said.
“Indeed, not only is there no perfect market, but even a well-functioning market can have flaws and be susceptible to manipulation. Otherwise, no claim for manipulation could exist because any market susceptible to manipulation could, by implication, be considered not ‘well-functioning.’”
In a press release, ETRACOM attorneys Robert Fleishman and Paul Varnado challenged what they called staff’s “cursory dismissal” of the design flaws. “The alleged harms would not have occurred but for the phantom congestion caused by these flaws,” they said.
The federal government on Wednesday designated about 127 square miles off Long Island as a wind energy area that could produce as much as 900 MW of power for New York.
The area designated by the Interior Department’s Bureau of Ocean Energy Management, about 11 miles south of Long Island, comprises 81,130 acres.
The announcement — which came a day after Interior withdrew plans to allow oil drilling off Virginia, North Carolina, South Carolina and Georgia — was cheered by environmentalists.
“The offshore wind industry is critical to the ultimate success of Gov. [Andrew] Cuomo’s call for the generation of 50% of New York’s energy from renewable sources by 2030,” said Anne Reynolds, executive director of the Alliance for Clean Energy New York. (See Cuomo: 50% Renewables by 2030, Keep Nukes Going.)
Offshore wind also is crucial to the U.S. Energy Department’s “wind vision,” which set a goal of capturing a 20% share of U.S. electricity production by 2030 (including 22 GW of offshore wind) and 35% by 2050 (with 86 GW of offshore wind).
BOEM has already issued 11 commercial wind energy leases off the Atlantic coast, but development of them has been slowed by high costs and local opposition.
Projects off New Jersey also have stalled, although state legislators are trying to revive them.
Deepwater Wind began work last July on the first demonstration project in the country, a 30-MW project off Rhode Island’s Block Island. The project, which had to withstand court and regulatory challenges to its above-market contracts with local distribution company National Grid, could go into service as soon as this year. (See FERC Won’t Investigate Offshore Wind Contract.)
Shallow Waters
If the U.S. is to enter the offshore wind industry, it will likely happen first on the Atlantic. The coastline’s shallow waters are similar to those in Europe, which has been building utility-scale offshore wind for more than a decade.
More than a quarter of the U.S. wind capacity in shallow water — depths of 30 meters or less — is along New Jersey, Delaware, Maryland, Virginia and North Carolina. The Mid-Atlantic region has almost 300 GW of potential wind capacity in shallow waters, more than enough to supply all of the region’s power needs. (See PJM States Seek ‘First Mover’ Status.)
2011 Proposal
The creation of the New York Wind Energy Area was prompted by a 2011 proposal by the New York Power Authority on behalf of itself, the Long Island Power Authority and Consolidated Edison. The NYPA proposal estimated a cost of $2 billion to $4 billion for up to 200 turbines generating about 700 MW.
BOEM, which oversees development of the nation’s energy resources on the Outer Continental Shelf, responded by issuing a notice in 2013 to determine if other developers were interested in the area. After issuing an environmental assessment, possibly by the end of this year, BOEM could move forward to offer leases under competitive bidding.
Five companies, Fishermen’s Energy, Energy Management, Deepwater Wind, EDF Renewable Energy and Sea Breeze Energy, have expressed interest in developing the site. Deepwater Wind is reportedly considering a Brooklyn waterfront site as a staging ground for the project.
The New York site is attractive to prospective developers for several reasons. New York City Mayor Bill de Blasio issued a request for information last year to identify new renewable energy generation capacity, with a goal of powering 100% of city government operations with renewables.
“Given the site’s proximity to load centers in New York and Long Island, it has the potential to be a very desirable location,” Thomas Brostrom, of Denmark-based Dong Energy A/S, the world’s largest offshore wind developer, told Bloomberg.
At the EUCI US/Canada Cross-Border Power Summit in Boston last week, Dennis Duffy, vice president of regulatory affairs for Cape Wind Associates, cited a New York study that showed onshore wind capacity factors in the state were only 10% during peak hours for electric use, while offshore wind reached 40%.
University of Delaware professor Willett Kempton has estimated the New York wind area is large enough to generate as much as 900 MW. His estimate is based on the use of 6- or 8-MW turbines, rather than the 3.6-MW turbines in the NYPA proposal.
Larger Turbines, Higher Costs
Offshore wind turbines are larger and thus generate more power than land-based turbines. But offshore turbines, which must be robust enough to withstand salt water and hurricane-force winds, are more expensive and also have higher operations and maintenance and financing costs.
The Energy Information Administration says the levelized cost of energy from offshore wind is $197/MWh (2013$), more than double the $74/MWh for onshore wind and the $73/MWh for natural gas advanced combined cycle plants. (EIA’s figures exclude any savings from government incentives.)
In Europe, which has about 90% of the 8.8 GW of offshore wind installed worldwide through 2014, the resource has benefited from government subsidies.
Patrick Woodcock, director of the Maine Governor’s Energy Office, told the EUCI conference that the New England states made a mistake by each trying to establish a foothold for the nascent offshore wind industry.
“What we really should have been doing is collaborating from the start. It never really made a lot of sense that one project, one group of utility ratepayers, would be the only class of ratepayers to bear the … huge burden for a demonstration project, when the dividends for bringing a new technology to the region is [shared] across the entire Northeast.”
Cape Wind Prospects Revived?
Cape Wind, a 130-turbine, 468-MW project planned for Nantucket Sound, is still trying to obtain financing after losing its PPAs with National Grid and NSTAR in January 2015. The utilities said the developers failed to meet deadlines to secure financing and begin construction by the end of 2014.
Duffy said Cape Wind’s hopes have been revived unexpectedly by a Massachusetts proposal to import Canadian hydropower under long-term contracts. Prospects for offshore wind and hydropower, he said, are “joined at the hip.”
“Sometimes politics makes strange bedfellows, but the future of both large imports of Canadian hydropower and offshore wind in New England depend largely upon Massachusetts legislation,” he said. An omnibus energy bill in the legislature is likely to include both.
A report released last week by the University of Delaware predicted that a commitment by Massachusetts to develop 2,000 MW, and anticipated technological advances, will lower previously projected costs by as much as 55% by 2029.
Newer wind farms would rely on larger, more efficient turbines than the older turbines for which Cape Wind is permitted.
Block Island turbine installations Source: Deepwater Wind
The study says costs for the first installations in a 2,000-MW commitment would be about 16.2 cents/kWh and that costs could drop to a “very competitive” 10.8 cents/kWh by the project’s completion. By comparison, the Block Island project has a PPA with National Grid that includes a fixed price of 24.4 cents/kWh with an annual 3.5% escalator.
“The key is making a firm commitment to scale so the market can do its work,” said Kempton, the study’s lead author. “By providing market visibility — the state’s commitment to a pipeline of projects over a set period — the offshore wind industry in the U.S. can deliver energy costs on the kind of downward trajectory seen in Europe.”
Renewed Hopes for NJ Project
Legislators in New Jersey, meanwhile, may have improved the prospects of a demonstration project near Atlantic City that has been blocked by the state Board of Public Utilities.
The New Jersey General Assembly last week voted 53-21 to approve legislation that would require the BPU to reopen a 30-day period for Fishermen’s Energy to resubmit an application for the five-turbine, 25-MW project. The bill cleared the state Senate on Feb. 11 by a 23-11 vote.
Gov. Chris Christie vetoed a similar bill in January by not taking action.
Fishermen’s Energy CEO Chris Wissemann said the legislation “cannot be ignored” by the governor this time around. He said Fishermen’s has secured federal funding from the Energy Department and switched to Siemens turbines, rather than the previously proposed Chinese windmills.
MISO received its first expedited project review request since replacing its former out-of-cycle review process, Senior Manager of Transmission Expansion Planning Thompson Adu told the Planning Advisory Committee on March 16.
Michigan Electric Transmission is seeking accelerated consideration to construct two 138-kV feeds to a new substation in Coldwater, Mich., with an in-service target of April 2017. The company said the upgrade is needed to serve 83 MW of load, including 33 MVA of new industrial and commercial load.
The company maintains that waiting until December for 2016 MISO Transmission Expansion Plan approval would not give the project enough time to meet the in-service date requested by its customers.
Transmission Planning BPM Advances to full PAC
The Planning Subcommittee has approved MISO’s Transmission Planning Business Practices Manual 020, moving the document to the PAC for consideration.
Matthew Tackett, a MISO principal adviser, said the BPM language was modified to include NERC transmission planning standards and Order 1000 cost-sharing provisions. Tackett said additional text also addressed the NERC MOD-032 standard, which establishes reliability planning modeling data requirements and reporting procedures.
Tackett said the edits do not represent policy changes.
“As the planning process evolves over time, it makes sense to incrementally make these changes,” Tackett said.
MISO’s second round of stakeholder input on the BPM yielded fewer comments, indicating consensus is near, Tackett said. The changes have been vetted through three PSC meetings, and MISO said it was not aware of unresolved issues or dissenting opinions from stakeholders. (See “Expedited Review Process Nears Approval with ‘Good Consensus,’” MISO Planning Subcommittee Briefs.)
Tackett submitted the nearly finalized language for a third round of comments through April 11.
Attachment Y Tariff Filing Moved Back Again
A proposed MISO Tariff revision requiring generation resources to submit Attachment Y notices at least 26 weeks prior to a planned suspension or retirement has been delayed by another month.
Joe Reddoch of MISO’s System Support Resource Planning Group said short intervals between meetings precluded a planned filing with FERC later this month, following another postponement in February. (See “Attachment Y Adjustments Put on Hold for a Month,” MISO Planning Advisory Committee Briefs.)
The Tariff revisions also stipulate that generators provide written notification when canceling or changing notices, as well as requiring owners rescinding an approved Attachment Y to re-enter the generator interconnection process. Additionally, MISO wants to relax confidentiality provisions surrounding Attachment Y information after a retirement date has passed.
Reddoch said MISO was not attempting to “overhaul” the system support resource program with the changes. He asked stakeholders to provide feedback by April 16 to facilitate a FERC filing late next month.
Twenty-two Heartland Consumers Power District customers will transfer their obligations to purchase energy and capacity from qualifying facilities while assuming Heartland’s duty to sell power to the QFs under a FERC order last week (EL16-1).
The commission granted a requested waiver of Public Utilities Regulatory Policies Act (PURPA) obligations for 22 Heartland customers while denying relief to six other customers — Truman, Minn., and the South Dakota cities of Howard, Aurora, Sioux Falls, McLaughlin and Tyndall — that did not agree to adopt Heartland’s QF-interconnection policy.
FERC found Heartland’s request for the 22 customers appropriate because the “QFs will retain the same ability to sell power and receive backup power as is currently the case. … Thus strict adherence to … regulations, under these circumstances, is not necessary to encourage QFs.”
The Truman Public Utilities Commission objected to Heartland’s request, saying the utility has “no authority to require Truman to adopt the [QF-interconnection] policy or any other policy.” It also pointed out Heartland does not yet have any QFs on its system.
Heartland said that because it acquires the bulk power resources to meet its customers’ loads, it is better suited to purchase energy offered from QFs.
Conversely, the company said, it is more appropriate for its customers to provide interconnection service required by QFs because the customers provide retail electric services. Heartland said South Dakota law does not allow it to sell electricity at retail prices.
It said its waiver request was intended “to clearly define the responsibilities for purchases from QFs, and sales to QFs, in accordance with statutory and contractual obligations.”
The commission also said one of the 22 customers, the city of Volga, S.D., must provide supplementary power, backup power, maintenance power and interruptible power to a South Dakota Soybean Processors cogeneration facility that is not yet operational.
The pipeline, which is intended to deliver shale gas from Pennsylvania into the New York and New England markets, is now projected to begin service in the second half of 2017. The developers had proposed operation of the 124-mile pipeline in the fourth quarter of this year.
The area designated by the Interior Department’s 
