FERC on Thursday proposed to include solid oxide fuel cells (SOFCs), a technology commercialized in the last decade, as qualifying cogeneration facilities under the Public Utility Regulatory Policies Act of 1978 (RM21-2, RM20-20).
The commission’s Notice of Proposed Rulemaking would amend its regulations to add the on-site reformation process of SOFCs as “useful thermal energy output” under PURPA.
FERC issued the proposal in response to a petition from SOFC manufacturer Bloom Energy in August. The company said it was not seeking to force electric utilities to buy its output at avoided-cost rates. Rather, it wants to take advantage of PURPA’s provisions reducing barriers to entry for new technologies, including exemptions from regulation under the Public Utility Holding Company Act of 2005, exemptions from some Federal Power Act provisions governing rates and financial organization, and access to interconnection.
“It is in Bloom’s commercial interest to sell to willing buyers, be they commercial customers, electric utilities or others,” said the company, which said it has about 600 installed systems, averaging 600 kW each.
Bloom Box energy servers using solid oxide fuel cells | Bloom Energy
In response to Congress’ 2005 PURPA amendments, FERC adopted the “fundamental use test,” which narrowed the facilities that can invoke a utility’s must-purchase obligation to include only cogeneration facilities for which at least 50% of their “electrical, thermal, chemical and mechanical output” is used for industrial, commercial or institutional purposes, and not intended fundamentally for sale to an electric utility.
Under that test, “even though a Bloom installation would satisfy the proposed definition of ‘useful thermal energy output,’ it would meet the other requirements for certification … only if it did not seek to sell at avoided-costs rates,” the company said.
Bloom did not respond to a request for comment on how PURPA status could aid its technology, which it has sold to tech companies such as Apple, AT&T and PayPal to provide backup power for data centers.
The company, which has never generated a profit in 19 years of operation, disclosed early this year that it would be restating its prior four years’ financial statements to reduce revenue by $192.1 million through Sept. 30, 2019. In an article in February, Forbes reported that the company had raised $1.7 billion of capital, “some of which was raised on the back of false statements.”
Power Without Combustion
Hydrogen-rich fuel enters the anode side of the fuel cell, attracting oxygen ions from the cathode side. The resulting electrochemical reaction produces electricity, plus heat and steam that is used to continue the reformation of natural gas into fuel. | Bloom Energy
Fuel cells convert the chemical energy in hydrogen directly to electrical energy without combustion. SOFCs use a solid oxide ceramic material as their electrolyte — a substance that produces an electrically conducting solution — unlike fuel cells that use platinum or other precious metals. The electrolyte oxidizes hydrogen, converting it to water vapor (H2O) while producing electricity.
SOFC systems that take in natural gas generate hydrogen and electricity by using the steam to reform, or separate, the methane (CH4). “As a consequence, hydrogen-rich fuel enters the anode side of the fuel cell. Simultaneously, ambient air enters the cathode side of the fuel cell,” the company explained. “The hydrogen on the anode attracts oxygen ions from the cathode. The resulting electrochemical reaction produces electricity, plus the heat and steam that is used to continue the reformation of natural gas into fuel.”
Innovation Anticipated
The commission noted that in enacting PURPA, Congress did not limit its definition of cogeneration to the combined heat and power technologies in existence at the time. “Due to innovation and development in the last decade, solid oxide fuel cell systems with integrated natural gas reformation equipment are now a viable option for efficient electric energy cogeneration, furthering PURPA’s goal of encouraging the innovation and development of cogeneration facilities,” it said.
SOFCs can reform multiple fuel types, such as propane or gasoline, to produce their hydrogen fuel. The fuel cells contemplated by FERC’s proposal specifically reform methane on-site.
“If the natural gas reformation equipment were instead located off-site, then waste heat (in the form of steam) from the electricity production by the solid oxide fuel cell would not be available to aid the reformation process to fuel the cell,” the commission said. “In this off-site reformation scenario, we would expect the external reformation process to require additional natural gas to be burned to create steam so that the remainder of the input natural gas could be reformed into hydrogen. This would be inefficient, and inconsistent with Congress’s goal in enacting PURPA.”
Supporters, Opponents
SOFC systems that take in natural gas generate hydrogen and electricity by using the steam to reform, or separate, the methane (CH4). | Bloom Energy
The Edison Electric Institute opposed Bloom’s petition, arguing that the language of PURPA stipulates that the byproduct energy from cogeneration QFs “must be primarily used for industrial, commercial heating or cooling purposes.”
Meanwhile, Democratic Sens. Dianne Feinstein (Calif.), Chris Coons (Del.) and Sheldon Whitehouse (R.I.) wrote in support of the petition. “To meet our clean energy goals, reduce risks of climate-induced disasters and create microgrid-enabled systems, a host of new energy efficient technologies are needed,” they wrote. “If combined heat and power meets the broad standards of a qualifying facility, we believe it is only appropriate that newer, more modern technologies, such as fuel cells, be designated as qualifying facilities as well.”
Comments on the NOPR are due 30 days from its publication in the Federal Register.
According to the Department of Energy, 95% of the hydrogen produced in the U.S. is made by natural gas reforming in large central plants. It is mostly used for industrial purposes, such as refining petroleum, treating metals, producing fertilizer and processing foods, according to FERC. When the carbon that is emitted from the methane reformation process is captured and stored, the hydrogen produced is called “blue hydrogen.”
Last month, DOE announced $34 million in funding for 12 small-scale SOFC projects.
SPP stakeholders last week endorsed a 10-year assessment of reliability and economic transmission projects that will likely continue to struggle to stay abreast of wind energy development.
“Actual wind in the ground outstrips our projections almost every time,” ITC Holdings’ Alan Myers, who chairs the Economic Studies Working Group responsible for the study, said during the Markets and Operations Policy Committee meeting, held Oct. 13 to 14.
The 2020 Integrated Transmission Planning (ITP) study comprises 54 projects at an estimated cost of $532 million, with a projected 4.0- to 5.2-to-1 benefit-to-cost ratio. The portfolio includes 92 miles of 345-kV transmission lines and 141 miles of rebuilt high-voltage infrastructure.
The two-year assessment’s business-as-usual reference case future projects 26 GW of wind energy by 2025 and 28 GW by 2030. The more aggressive “emerging technologies” future foresees 30 GW of wind by 2025 and 33 GW by 2030.
Meanwhile, SPP had 26.7 GW of registered wind capacity as of Sept. 1 and expects to have 29.7 GW in service by 2022.
“We are getting better. The projections for this study are a little further out,” Myers said. “You can draw the conclusion that we could have added more wind than we did.”
“If you look at ITPs in the past, most of the [reference case] Year 10 assumptions came to reality in two years,” SPP Director of System Planning Casey Cathey said. “Our wind assumptions … are becoming a reality a lot faster than Year 10.”
Casey called the ITP portfolio “fairly strong,” citing its B/C ratio. The study also took into account fossil fuel retirements and a 4- to 9-GW increase in solar generation.
The ITP assessment drew the usual criticism from transmission owners wary of building more 40-year facilities on top of the $10 billion or so in recently constructed SPP infrastructure.
“One of the questions we’ve asked for a long time is at what point do you quit building? At what point do you quit asking customers to be paying for these facilities?” Oklahoma Gas & Electric’s Greg McAuley asked. “We question the long-term viability of those benefits. We have no idea what the industry will look like in 40 years, much less in 10 years. The right transmission needs to be built. It’s these economic projects that we have the most concern about because those costs don’t go away.”
“These 40-year investments we’re making are actually fixed costs to the customers,” Golden Spread Electric Cooperative’s Mike Wise said. “SPP is showing variable costs with the B/C ratios. We’re trying to say the fixed costs are substantially risky because 40 years of fixed costs reduce some variable costs. Enough is enough. You can go broke to save money.”
The TOs approved the ITP study by a 12-2 margin, with three abstentions, as the measure passed with 88% overall approval.
Wind energy’s growth in the SPP footprint continues to outpace projections. | SPP
Center Stage for Electric Storage Proposals
Members began to address the footprint’s growing wave of energy storage resources (ESRs) by endorsing six recommendations from a white paper calling for SPP to capitalize on ESRs’ flexibility, reliability and economic benefits by developing cost-recovery mechanisms and determining whether they are used as generation and/or transmission assets. (See SPP Planning Approach to Battery Storage.)
“And many more to come,” said Evergy’s Allen Klassen, chair of the Operating Reliability Working Group (ORWG), referencing the document’s 37 proposals.
The ORWG worked with the Supply Adequacy Working Group (SAWG) in agreeing with the white paper’s recommendation to support use of the available effective load-carrying capability (ELCC) for ESR accreditation. The groups also urged adopting a four-hour minimum duration for capacity accreditation and no additional real-time ESR availability criteria.
Both recommendations passed unanimously. However, the two groups were unable to agree on the number of ESRs that can be aggregated in a resource adequacy portfolio. The ORWG recommended a maximum ESR participation limitation for each load-responsible entity, based on load and resource capacity calculations, while the SAWG argued against a participation limit “at this time.”
“We don’t feel the need to take action right now until we see the penetration and how batteries are used,” said Golden Spread’s Natasha Henderson, the SAWG’s chair. “We just don’t think we have the data to know what that limit is right now.”
SPP COO Lanny Nickell said staff will work on a scope document for a task force that further studies the issue related to FERCOrder 2222. Staff have already suggested a name for the task force: The 2×4.
Separately, the SAWG produced a white paper proposing a methodology for prioritizing and allocating the available ELCC from capacity-qualifying ESRs in SPP. The group contracted an outside consultant to analyze an ESR’s capacity credit on the SPP system using ELCC and capacity value and two dispatch strategies: preserving reliability and economic arbitrage. The study also evaluated the capacity credit of batteries using two-, four-, six- and eight-hour equipment.
The MOPC also approved a Market Working Group (MWG) proposal for modeling and controlling ESRs’ hybrid configurations, passing the measure against a single opposing vote.
The MWG and other stakeholders and staff chose a market storage resource (MSR) model among three other alternatives. The MSR market-registration model was created for FERC Order 841, which directed RTOs and ISOs to eliminate barriers to ESR participation in their markets. The model allows generating and storage resources to be represented as a single resource in the market model with one set of offers.
“To the market, it looks like one resource,” SPP’s Gary Cate said. “The less resources the market-clearing engine has in its matrix, the less time it takes to solve. This model could apply more broadly to anything that has storage.”
The ESRs will still be modeled separately for reliability purposes, with offer parameters consisting of all those associated with MSRs. A single offer curve would be submitted, but SPP said this could prove challenging for mitigated offer-curve development because the generating costs represent a blended opportunity cost of injecting and/or self-charging. Staff said the MSR option will allow market participants to manage the co-located resources’ interactions as long as their total injection or withdrawal meet the combined dispatch.
Cate said SPP has looked at how other RTOs are addressing battery storage “because everyone is going through this at the same time.” (See RTOs/ISOs File FERC Order 841 Compliance Plans.)
The committee also endorsed:
the Regional Tariff Working Group (RTWG) and MWG’s recommendation that transmission-only ESRs should not pay transmission service and/or ancillary charges related to their charging activity. Stakeholders said this would put ESRs on the same level with other transmission assets providing similar services for which they do not pay service charges.
An ORWG white paper that urges development of a policy requiring fast-responding ESR owners and operators to clearly define the resource’s ramping capability during the registration process; the definition of acceptable response-rate ranges for each ancillary service and ensure coordination of energy deployment across all participating resources; and governing policies that require resources to perform within their registered capability as dispatched by SPP. The MWG will take the lead on the work.
Interconnection Improvements
A cross-functional MOPC stakeholder group directed to develop policies creating a balance between energy resource interconnection service (ERIS), network resource interconnection service (NRIS), generator-interconnection products and long-term firm transmission service secured approval for a 72-page white paper and a recommendation to replace NRIS with a new capacity resource interconnection service (CRIS).
The NRIS/ERIS Deliverability Task Force (NEDTF) said CRIS would add deliverability to the existing NRIS product and provide a clearer distinction between the two services.
CRIS provides capacity deliverability from a single resource to any load within a control area, balancing authority or other designated region that contains more than a single load. NRIS provides the interconnection customer with a sufficient interconnection that allows the generator to qualify as a designated network resource on the transmission provider’s system without additional network upgrades.
NEDTF Chair Rob Janssen, with Dogwood Energy, said the task force, which evolved from a Holistic Integrated Tariff Team (HITT) recommendation, engaged with several other working groups, gaining generally favorable feedback. He said there was general agreement that larger deliverability areas are preferable.
The NEDTF received a little bit more pushback on its proposal to tighten thresholds for mitigating ERIS system impacts, picking up on work by a previous task force. The proposed revision request would address stakeholder conclusions that too many unmitigated constraints lead to undesirable effects in the SPP market.
Committee members expressed concern over the $400,000 cost, but staff noted most congestion studies require building a generation and portfolio modeling system. In the end, the MOPC gave the threshold-tightening recommendation against just four opposing votes.
Members also endorsed the NEDTF’s white paper, which Janssen said would “lay the foundation” for whatever work will follow.
More White Papers Approved
The MOPC overwhelmingly signed off on several white papers related to the HITT’s recommendations:
the Transmission Work Group’s paper documenting modifications to Tariff Attachment AQ limiting its application to new load, revisions to loads and load retirements that need to be addressed outside of the ITP because of timing or some other “significant” reason. The paper, approved unanimously, was produced to increase transparency and shorten the turnaround time to facilitate load growth.
a joint report from the ORWG and MWG demonstrating the economic benefits of topology optimization by using existing transmission assets to increase grid flexibility and efficiency. According to the report, while transmission elements are traditionally viewed as static elements, their topology reconfigurations may provide a means to reliably reroute power around congested facilities without causing additional burden on the system.
The ORWG and MWG also produced a second white paper on economic outage coordination that was part of the consent agenda. The paper explored other RTOs’ outage coordination processes and criteria thresholds before concluding SPP will need to invest time and money fully integrating and streamlining the process to take full advantage of the economic benefits.
Staff will use the white papers to develop policy and Tariff language to implement the changes.
$91M Increase for NPPD’s R-Project
Members approved a nearly $91 million increase for Nebraska Public Power District’s R-Project, raising the controversial 345-kV initiative’s price tag to $463.4 million. The measure passed with 83.5% approval.
NPPD warned the Project Cost Working Group in September that it expected the project to be out of bandwidth in the near term. The publicly owned utility has already sunk $100 million into the project and said its original estimate “significantly underestimated” the environmental cost, which was based on typical environmental tasks in previous efforts.
The project comprises 225 miles of 345-kV transmission line running through the environmentally sensitive Nebraska Sandhills and two new substations. It was approved as part of the ITP 10-year assessment in 2012 and received a notification to construct with conditions the following year.
In June, a federal district judge revoked a federal permit that would have allowed NPPD to kill or severely disturb the endangered American burying beetle during construction. The utility has said the ruling will delay but not stop the project, which has a 2024 in-service date.
Several TOs called for the project to be suspended and re-evaluated over cost concerns. That motion failed with only 30% approval.
“Is this still the right project?” asked Bill Grant, of Xcel Energy’s Southwestern Public Service. “This has been re-baselined several times, and I have huge concerns we’re not doing our due diligence. I have to ask whether this project is prudent or not.”
“This is a significant overrun here, and it’s been going on for a long time. At some point, we have to take another look at it,” McAuley said. “That’s why those of us who build transmission are very cautious. There’s always uncertainty. You can wind up in this situation four or five years down the road, but it’s too late. Customers are already paying for it.”
SPP staff said several generator interconnection agreements are dependent on the project, which has been framed as enabling renewable power, reducing congestion and strengthening system reliability.
“We have to continue to honor the [transmission] service in those agreements,” said Antoine Lucas, SPP’s vice president of engineering.
“The assumptions on this line going in are not the same as they were years ago,” said Advanced Power Alliance’s Steve Gaw, noting the project was originally approved as a reliability solution. “To evaluate and further delay this project has the potential to significantly increase costs.”
Carias Governs Last Meeting as Chair
MOPC members honored their chair, NextEra Energy Resources’ Holly Carias, with a virtual happy hour following the end of her two-year term and treated her to a parade of compliments.
“I couldn’t have done it without the entire membership. We had some challenges with COVID, but I think we responded pretty well,” she said. The full committee met virtually three times during the year, aided by staff’s development of an efficient e-voting system.
SPP COO Lanny Nickell, the committee’s staff secretary, noted that it will soon complete a structural reorganization of its stakeholder groups, an effort that began shortly after Carias took the gavel in January 2019.
“Holly led the group with poise and tact,” SPP Board of Directors Chairman Larry Altenbaumer said.
Evergy’s Denise Buffington, who served as Carias’ vice chair, shared an Albert Einstein quote translated from the original German: “Life is like riding a bicycle. To keep your balance, you must keep moving.”
Carias will continue as MOPC chair until November. She is leaving NextEra for Avangrid Renewables, where she will be vice president of origination. Buffington will serve as acting chair for the remainder of the term, which ends Dec. 31.
“We’re not [an SPP] member, but hopefully we will be soon,” Carias said.
Avangrid Renewables is a subsidiary of Spain’s Iberdrola Group, a renewable energy pioneer with more than 32 GW of projects spread across a dozen countries. Portland, Ore.-based Avangrid has more than 7.3 GW of wind and solar generation in more than 20 states.
Some Byway Costs to be Allocated Regionally
The MOPC endorsed the RTWG’s recommendation to implement previously approved language that creates a narrow process through which costs for transmission projects between 100 and 300 kV primarily used to move power out of the local transmission pricing zones can be fully allocated prospectively on a regionwide basis.
TOs opposed the measure (RTWG RR422) over what they said was a shift of byway cost responsibility from wind-rich areas to others. The change cleared TOs by 10-5 but enjoyed a 31-7 approval from transmission users in gaining an overall approval of 72.12%.
The MOPC’s consent agenda, which passed unanimously, included nine additional revision requests:
ESWG RR403: updates the ITP manual language to support current capabilities, as software revisions prevent building models on historic time periods.
MWG RR420: adds clarifying language to ensure SPP’s fast-start pricing practices are in FERC compliance. (See “Directs Further Compliance Filing on Fast-start Resources,” FERC OKs 2 Changes from SPP’s HITT Work.)
MWG RR421: removes registration provisions requiring energy storage resources to provide certification that its participation in the market is not precluded by the relevant electric retail regulatory authority, as required to FERC to be in compliance. (See RTOs Move Closer to Full Order 841 Implementation.)
MWG RR425: adjusts the day-ahead make-whole payment charge type’s calculations and changes the real-time out-of-merit charge type and the reliability unit commitment make-whole payment calculations.
PCWG RR415: clarifies and updates existing language in Business Practice 7060 (Notification to Construct and Project Cost-Estimating Processes).
RTWG RR423: removes expired or terminated grandfathered agreements from a Tariff attachment’s index and updates any termination dates that have changed or any changes in buying or selling party terminology.
SAWG RR412: allows both new and upgraded capacity from existing generators to be treated equally in qualifying as accredited capacity during the first peak season that each is available, thereby preserving the members’ expected generation investment value.
TWG/ESWG RR427: removes some of the detailed project proposal form’s requirements to reduce its size and scope.
Staff RR416: brings more accurate reporting and communication of RRs. Clarifies when an RR exploder is required to be used; requires summaries and notices of FERC rulings on RRs; and adds a section that documents the purpose of what is to be included in the RR master list.
The consent agenda also included approval of a $14.67 million increase above the $32.46 million original estimate for Empire District and Evergy Kansas Central’s 161-kV rebuild in eastern Kansas; an additional 161/69-kV transformer for Apex Clean Energy’s Jayhawk Wind project in eastern Kansas; scope revisions for the MOPC’s reorganized stakeholder groups; and the 2019-2020 annual violation relaxation limits report.
Transmission owners, regulators and stakeholders face a massive task in planning for new transmission as they attempt to modernize the grid and prepare for an influx of renewable resources.
That was the key takeaway of a panel at last week’s Energy Bar Association annual Fall Conference entitled “Looking into the Transmission Crystal Ball: What are the biggest issues facing the transmission industry in the next five years?”
A diverse cross-section of stakeholders from around the country working in various aspects of the energy industry quizzed a panel of transmission experts on their outlook for the grid.
Jason Stanek, Maryland PSC | Energy Bar Association
Jason Stanek, chairman of the Maryland Public Service Commission, said transmission assets built to meet delivery needs almost 100 years ago are reaching the end of their useful life and are being slated for replacement. At the same time, states like Maryland are advancing clean energy policies like offshore wind that will require transmission upgrades.
Stanek said the delivery systems were originally planned under an “umbrella approach” that considered the “interplay of regulatory policies and customer needs in a just and reasonable manner.” Planning for grid upgrades has become more complicated now that transmission planning today is primarily the responsibility of RTOs and ISOs, along with the growing state-federal conflict over energy and environmental policies, Stanek said.
In his question to the panelists, Stanek asked how regulators and stakeholders can “reopen the umbrella” to have coordinated and cost-effective transmission planning to achieve a clean energy future.
Beth Emery, GridLiance | Energy Bar Association
Beth Emery, senior vice president and general counsel for GridLiance, said she is seeing major pushback from RTO/ISO stakeholders over what some claim to be “the spiraling cost of transmission.” Emery said most of the current costs for transmission are tied up in reliability projects, in which cost-benefit analyses are not typically done, adding to the skepticism about costs.
Unless stakeholders, including state regulators, have open and transparent access to what projects are being proposed, planning estimates and the actual costs, Emery said, it will be difficult to convince ratepayers that the transmission projects have value.
Emery said FERC’s push toward forward-looking transmission formula rates seems to have made the transparency problem even worse, encouraging new transmission builds but making it even less clear on the costs.
GridLiance has a published white paper proposing FERC require RTOs to collect and publish consistent data on transmission investment, Emery said, which some RTOs already do, but the information can be difficult to find.
“It’s almost impossible for customers to get useful project-by-project information in the formula rate protocol process,” Emery said. “I think TOs need to be able to plan and make prudent decisions for local reliability, and they absolutely need to maintain their existing assets. But plans should be transparent and costs discoverable.”
Valerie Teeter, senior manager of federal regulatory affairs at Exelon, said Stanek’s question addressed an important trend. In states that have restructured transmission planning, Teeter said, there has been a move away from integrated resource planning between utilities and the states to determine the needed resources to meet environmental goals and the role transmission will play.
Valerie Teeter, Exelon | Energy Bar Association
Teeter said broader regional planning creates some “disconnects” between the utilities and states, with utilities waiting to see what projects get into the generation interconnection queue. She encouraged state regulators to think about how they could play more of a role in planning because they have the clearest vision of state energy goals.
“States have clean energy goals; they have ideas of what they want their future to look like,” Teeter said. “They understand the resource mix they’re hoping to see to lead them to their clean energy future.”
Lisa McAlister, senior vice president and general counsel for American Municipal Power, said customers are experiencing “sticker shock” as TOs continue to replace aging infrastructure across the country. McAlister agreed that greater transparency in the planning process and rate structures would help customers better understand the projects and help TOs better justify the projects that are most cost-effective.
McAlister said efforts currently underway in PJM, ISO-NE and CAISO by TOs to remove projects from the regional transmission planning processes and make themselves solely responsible for planning will “balkanize the transmission grid,” increasing costs and customer complaints.
“That’s going to make achieving a clean energy future more challenging,” McAlister said.
5-year Discussion
John Moura, NERC director of reliability assessment, said he views the changing resource mix as one of the most important reliability issues to tackle over the next decade. Moura said industry-supported studies have determined that an extra-high-voltage network from Wyoming to Ohio will be needed to achieve carbon-reduction goals.
Moura asked how to start difficult conversations about transmission among stakeholders in the next five years.
Lisa McAlister, AMP | Energy Bar Association
Customer demand is driving the development of renewable resources and carbon pricing, McAlister said, and having discussions with a focus on meeting mandated or voluntary objectives, whether carbon-reduction goals or planning for the grid of the future, will require a coordinated approach between consumers, load-serving entities, distribution and transmission utilities, the RTOs, FERC and Congress.
“Now, more than ever, we need to develop a collaborative and a consensus-based approach to building transmission that spans multiple states to connect these renewable resources to the load pockets,” McAlister said. “The most effective pathway forward will be through the RTOs because they have the most comprehensive information regarding new generation and the interconnection queue, congestion and other market data.”
Emery said stakeholders involved in the planning process understand the steps needed to be taken to build a consensus, but reaching that consensus is difficult. Consensus is built by making people comfortable and helping them understand the costs of projects and what the benefits will be once they are completed, she said.
She said she believes federal legislative action is needed to make interregional planning successful and that states will not be able to do the necessary planning without a prompt from Congress. There must also be a mechanism for everyone involved in the planning process to benefit in some way, she said.
Emery pointed to the creation of the interstate highway system as a federal model to strive toward.
“We need to figure out how we take that model and apply it in the context of transmission where there’s a cooperation between the federal government and the state governments and all the consumers because people see both local and national benefits from what we’re doing,” Emery said.
Federal Policies
Rob Gramlich, president of Grid Strategies, said modeling shows the need for larger regional and interregional transmission, but the regulatory structure is not in place to effectively facilitate for planning. Gramlich said FERC Orders 890, 2000 and 1000 all attempted to address some of the regional transmission planning, but a gap exists between what needs to be done and where the process currently stands.
Gramlich asked how policies can be put in place through FERC or Congress to make regional and interregional planning happen more often and more smoothly.
Jennifer Curran, MISO’s vice president of system planning, said when the conversation of interregional planning comes up in the RTO, there are three conditions that take precedent in transmission building: “policy consensus, robust business case and fair cost allocation.”
Curran said policy consensus does not mean all stakeholders are pursuing the same goals, but it does mean that stakeholders have decided transmission is a way to help meet renewable goals and bridge the diversity among state goals. She said her expectation is that a federal policy to provide for regional and interregional transmission planning would have to be “pretty extreme” because many states will want to go faster in the planning process, while others would continue to be resistant to change.
“If we can get to a place where everybody understands transmission is part of the answer, then I think that’s helpful,” Curran said.
FERC has allowed MISO to avoid eight years of resettlement work on certain manual dispatches dating back to early 2009.
The commission last week did not act on MISO’s longstanding Tariff violation. The grid operator may have miscalculated on some make-whole payments to resources that were manually dispatched from January 2009 to May 2018 (ER18-1611).
Commissioner James Danly concurred with the decision while castigating FERC’s multiple other waiver approvals.
MISO said that during a 2018 quality check, it discovered that its settlement system was not technically handling manual redispatch as outlined in its Tariff. It said its software was setting dispatch instructions to a specific level, rather than a range of acceptable dispatch levels as described in the Tariff. The RTO also said its software was checking for economic dispatch statuses in both the day-ahead and real-time markets, when its Tariff does not require such a check for economic status in the day-ahead market.
The financial fallout from the eight-year inconsistency totaled just $1.6 million, or $200,000 annually, MISO said. The grid operator said manual redispatch was necessary in a little more than 1% of all make-whole payment hours since 2009.
MISO also said its Independent Market Monitor did not find any generators “intentionally making inflexible offers … to gain excess margins from the system during intervals that a resource was manually redispatched.”
MISO control room | MISO
FERC said that while the discrepancy amounted to a nearly decadelong Tariff violation, the amounts were too small to be reopened, calling resettlement counter to public interest.
“We agree with MISO that, based on the circumstances here, market resettlement and refunds are not an appropriate remedy,” FERC said. “We are persuaded that, to the extent resettlement of the market transactions at issue would be feasible, requiring such resettlement and associated refunds could create inequitable results by unfairly punishing market participants that followed MISO manual redispatch instructions and could undermine confidence in market outcomes.”
The commission cited its “broad authority” to determine remedies for Tariff violations. It also said that because it was not directing resettlement or refunds, it was not required to address MISO’s waiver of its Tariff during the discrepancy.
Danly said he agreed with the decision, unlike the nine waiver approvals issued during FERC’s open meeting Thursday. He said that in this instance, FERC did not exceed its legal authority by granting a backdated waiver that could violate the filed-rate doctrine and rules prohibiting retroactive ratemaking. Instead, he said, the commission confirmed the violation between settlement software and Tariff language and disregarded the request for waiver.
“I agree with this holding. In my view, this is the approach we should take in all situations where a utility has violated its own tariff,” Danly said, noting MISO’s “relatively small error and the extreme difficulty in resettling bills back to 2009 support this decision.”
Danly also said FERC should have first denied MISO’s waiver request, then made the finding that the RTO violated its Tariff to keep the commission’s decision-making process uniform and orderly.
In a 142-page ruling Thursday, FERC partly affirmed an administrative law judge’s decision on Pacific Gas and Electric’s proposed increases to its transmission rates, reversing the judge on the utility’s cost of long-term debt and other issues (ER16-2320).
The commission directed further briefing on PG&E’s return on equity and told the utility to recalculate its tariff rates based on the ROE and other factors.
PG&E filed its 18th revised transmission owner tariff in July 2016, which was followed by numerous objections. After an evidentiary hearing, the judge ruled in October 2018 on 11 disputed categories including ROE, capital structure and depreciation rates.
The judge found PG&E’s forecasted cost of long-term debt to be unreasonable, ordering it be reduced, and lowered its ROE from a proposed 10.4% to 9.13%, which the company said was too low and objecting parties said was too high.
A panel at last week’s Energy Bar Association annual Fall Conference examining FERC’s response to the D.C. Circuit of Appeals’ Allegheny Defense Project v. FERC ruling evolved into an in-depth Q&A with panelist David Morenoff, FERC’s acting general counsel.
Allegheny upended longstanding FERC practice by barring the commission from using tolling orders to delay judicial review under the Natural Gas Act and Federal Power Act. The July order by the D.C. Circuit Court of Appeals concluded that the commission’s use of tolling orders to stop the 30-day clock for acting on rehearing requests improperly prevents litigants from appealing its rulings indefinitely even as it allows gas pipeline companies to seize property under eminent domain and begin construction. (See D.C. Circuit Rejects FERC on Tolling Orders.)
Adrienne Claire, Thompson Coburn | Energy Bar Association
Moderator Adrienne Claire, a partner with Thompson Coburn, noted that FERC Chairman Neil Chatterjee and Commission Richard Glick asked Congress to provide the commission with a “reasonable amount of time to act on rehearing requests.” (In light of Allegheny, FERC must now respond to all rehearing requests within 30 days or they are deemed denied “by operation of law.”)
“What would be a reasonable amount of time in your opinion? What’s feasible?” Claire asked.
Morenoff said Chatterjee developed “great respect” for members of Congress and their staff from both parties through his extensive experience working on Capitol Hill, “so he leaves to Congress the question about what will be the reasonable amount of additional time if Congress were to respond to that call and take action.”
Morenoff pointed to two bills introduced into Congress last spring, H.R. 6982 and H.R. 6963, to address rights to timely rehearing of FERC decisions under the NGA and FPA, respectively. The two bills would set rehearing time frames to 90 days under the NGA and 120 days under the FPA, “perhaps reflecting the relative greater complexity that we often see in rehearing requests under the FPA with respect to particularly the organized markets,” he said.
“I think that those provide a really good starting point for discussions that are proceeding on the Hill,” Morenoff said.
In response to Claire’s question about what changes FERC has already made in response to Allegheny, Morenoff said that, even before Allegheny, Chatterjee had directed commission staff to expedite actions on rehearing requests, especially regarding landowner requests in gas pipeline certificate proceedings.
David Morenoff, FERC | Energy Bar Association
“We have been doing coordination among not only the sections across [FERC’s Office of the General Counsel], including the rehearings section that we set up in February, but among the various program offices at FERC that work closely on a rehearing request … and I think that’s just more important now as we try to move even more quickly to cover that same ground in a post-Allegheny world,” Morenoff said.
Allegheny also prompted FERC to begin issuing two types of new notices in response to rehearing requests, Morenoff said. The first states that “rehearing may be deemed denied, period,” while the second says that “rehearing may be deemed denied and the commission intends to issue a further order on the merits addressing arguments on rehearing,” he said. (See FERC will not Seek SCOTUS Review of Tolling Decision.)
“We’ve been trying to move quickly on those second orders, but I think both of those notices indicate that the commission is going to put more emphasis on our underlying orders more often because, as we’re trying to move more quickly, the old kind of standing rehearing order that would have a lengthy background section, then summarize the order in detail, then summarize all the arguments raised in rehearing, that probably isn’t possible anymore given these time frames,” Morenoff said.
‘Uphill Battle’
“One of the issues that was percolating a few years ago was whether in the absence of a quorum, FERC could even issue a merits order on rehearing, much less a tolling order,” an audience member said. “Do you think the Allegheny decision gives us any insight into how the courts might resolve that issue?”
“I don’t think that Allegheny sheds a great deal of light on that subject, but I think it’s a very important question because regrettably we’ve had less time recently with five commissioners that all of us inside and outside would like,” Morenoff responded. He noted that when the commission realized it would be dropping below quorum in 2017, it issued an order that covered the delegation of additional responsibilities to staff.
“At the time, based on the research we had done, we felt quite confident that as long as there is a proper delegation from the quorum of the commission, there’s quite a good deal that can be done by staff,” he said.
Claire turned to the broader panel to pose a hypothetical question about how the Supreme Court would have responded had FERC appealed Allegheny, a step the commission said last month it would not take.
“I think there’s a decent chance the court would’ve granted review because it has a pretty high rate of granting petitions when the government is asking it to do so,” said Erin Murphy, an Environmental Defense Fund attorney.
But Murphy thought FERC would have faced a “pretty uphill battle” on appeal because the court, while potentially sympathetic to FERC’s arguments about the tolling orders as a longstanding policy matter, would still doubt that the rehearing delays complied with what Congress was “trying to accomplish” when it set rehearing request deadlines under the NGA.
“There’s certainly arguments about congressional acquiescence, and there’s a lot of water under the bridge at this point, but I think that there’s just that dynamic of [the rehearing delays] feeling like circumvention that would’ve been hard to overcome at the court,” Murphy said.
NERC prepares the list of risk elements annually to help regional entities and utilities plan for the year ahead. Risk elements are identified according to the ERO Enterprise Guide for Compliance Monitoring through compliance filings, event analysis and data analysis. The organization also solicits input from ERO Enterprise staff and committees, such as NERC’s Reliability Issues Steering Committee (RISC), and reviews the State of Reliability report as well as other publications.
This year’s report identifies the following risk elements for the coming year:
remote connectivity and supply chain;
poor quality models impacting planning and operations;
loss of major transmission equipment with extended lead times;
inadequate real-time analysis during tool and data outages;
determination and prevention of misoperations; and
gaps in program execution.
While the COVID-19 pandemic did not gain its own spot on the list, drafters incorporated its impacts into several of the risk elements. Although NERC and other organizations had prepared contingency plans for a pandemic, the arrival of an actual crisis exposed some mistaken assumptions. (See Pandemic Poses Long-term Reliability Challenges.)
“Pandemic risk differs from many of the other threats facing the BPS because it is a ‘people event,’” the report says. “The fundamental risk is the loss of staff critical to operating and maintaining the BPS such that firm loads could no longer be served reliably and securely. Regions may consider reviewing requirements related to personnel training in order to address this risk.”
Remote Work Raises Cyber Risks
The coronavirus impacts are particularly visible in the entry for remote connectivity and supply chain, which highlights entities’ shortfalls in addressing cybersecurity. Cyber hygiene became an unexpectedly pressing issue this year when many entities transitioned to a remote work posture, greatly expanding the “attack surface” for malicious actors who may try to exploit employees distracted from best practices by family or personal challenges. (See PPE, Testing Top Coronavirus Concerns for NERC.)
“Regardless of the sophistication of a security system, there is potential for human error,” the report notes. “If security has increased the difficulty in performing personnel’s normal tasks, personnel may look for ways to circumvent the security to make it easier to perform their job.”
Notable cybersecurity issues unconnected to the pandemic include supply chain risk, which continues “to be a focal point of the federal government” with actions this year including President Trump’s emergency declaration in May and subsequent inquiries from FERC Opens Supply Chain Cyber Risk Inquiry.) These risks can both “create issues within individual entities [and] collectively … cause disruptions within the [bulk electric system].”
New Risks to Modeling, Rating
| NERC
In calling out utilities’ inadequate modeling, the report focuses on new technologies, such as distributed energy resources and inverter-based generation. Shortcomings in utilities’ approach to both resources have been frequently noted by NERC and the REs in recent years; for example, in a joint report issued in August, NERC and WECC warned that many utilities in the Western Interconnection use outdated models, or none at all, for their solar and wind generation resources. (See NERC, WECC Warn of Inverter Modeling Gaps.)
In addition, the report’s “Gaps in program execution” section notes that inaccurate, outdated facility ratings pose a significant challenge to creating useful planning models. Rating violations may occur because of change management systems that are either not enforced or not rigorous enough to document all relevant updates. This year also saw many utilities introduce travel limitations and physical distancing requirements in light of the pandemic, which “complicated … inspection and maintenance programs,” NERC said.
The remaining areas revisit last year’s report. In the “Loss of major transmission equipment” section, NERC urges utilities to prepare for scenarios that can “reduce contingency margins” while personnel seek replacements for equipment with long manufacturing lead times. These include aging infrastructure, natural disasters and deliberate attacks such as an electromagnetic pulse, along with pandemic-related supply chain complications.
Under “Inadequate real-time analysis during tool and data outages,” the report notes the need for registered entities to “be able to demonstrate how their real-time assessment is sufficient … during the loss of primary tools or data sources.” The final section, “Determination and prevention of misoperations,” aims to remind utilities that protection systems that operate at the wrong time can be just as dangerous to the BPS as those that fail to operate at all.
Data Submittal Schedule Released
Alongside the CMEP Implementation Plan, NERC last week also published its Periodic Data Submittals (PDS) Schedule for next year. The PDS is updated annually to inform registered entities of data submittals required by NERC’s reliability standards, along with their deadlines. Data requests issued under sections 800 and 1600 of NERC’s Rules of Procedure are not included in the list.
Next year’s PDS largely carries over the schedule from 2020. Exceptions include the addition of two standards — BAL-001-TRE-2 (Primary frequency response in the ERCOT region) and TPL-007-4 (Transmission system planned performance for geomagnetic disturbance events) — that became effective in 2020 but were not included in this year’s schedule. In addition, PRC-004-WECC-2 (Protection system and remedial action scheme misoperation) and PRC-016-1 (Remedial action scheme misoperation) will become inactive in 2021 and have been removed from the schedule.
CIP-008-6 (Cybersecurity — Incident reporting and response planning) and PRC-012-2 (Remedial action schemes) are set to take effect next year as well. However, they were not included in the schedule for 2021.
FERC on Thursday declined to rehear its February order approving a NYISO proposal to apply buyer-side mitigation to energy storage resources (ESRs). The 2-1 ruling expanded on the previous order and drew another sharp dissent from Commissioner Richard Glick, the lone Democrat on the commission (EL19-86-001).
The commission continued to find that the New York Public Service Commission and the New York State Energy Research and Development Authority “failed to show that applying buyer-side market power mitigation [BSM] to electric storage resources in NYISO is unjust and unreasonable or unduly discriminatory or preferential” and asserted “that such mitigation does not inappropriately intrude on New York’s jurisdiction.”
Chairman Neil Chatterjee and Commissioner James Danly said the complainants failed to show that applying BSM to new electric storage resources offering into the NYISO capacity market is unjust or inconsistent with FERC Order 841.
They further said the commission’s denial of the requested exemption reflected reasoned decision-making based on substantial record evidence, including economic theory, and relied on the opinion of the NYISO’s Market Monitoring Unit that storage resources have the ability to suppress capacity prices absent appropriate mitigation.
“We continue to find that applying buyer-side market power mitigation to electric storage resources will protect the integrity of competition in the wholesale capacity market against unreasonable price distortions and cost shifts caused by out-of-market state support,” the order said.
Workers enter a container-size energy storage unit in New York. | NY-BEST
Glick said the commission “once again perverts buyer-side market power mitigation into a series of unnecessary and unreasoned obstacles to New York’s efforts to shape the resource mix.” It failed to justify the continued use of BSM measures against individual storage resources and explain its differing approaches to issuing exemptions from mitigation for different types of resources, he said.
“All told, today’s order aptly illustrates what a mess buyer-side market power mitigation has become in New York,” Glick said.
Free Markets
The commission said that under-mitigation of uneconomic entry can suppress capacity prices, over-mitigation discourages new entry, and that both extremes jeopardize long-term consumer interests.
Applying BSM to storage resources will protect the integrity of competition in the capacity market against unreasonable price distortions and cost shifts caused by out-of-market state support, the commission said, disagreeing with New York Transmission Owners’ contention that the commission presumed that storage resources participate in the capacity market on an aggregate basis.
“Rather, the commission was concerned with the combined effect that individual subsidized storage resources would have on clearing prices,” it said, noting that BSM “rules may change over time to protect the integrity of the capacity market.”
The commission also said it had not “conflated lower prices resulting from normal supply and demand (competition) with artificial downward price manipulation or … made any finding regarding the per se exercise of market power. … ESRs that receive out-of-market support are not competing on an equal basis with those resources that do not receive similar out-of-market support.”
Glick said the ruling was illogical; instead of promoting true competition, the commission’s approach to buyer-side market power “has degenerated into a scheme for propping up prices, protecting incumbent generators and impeding state clean energy policies.”
Although the specifics of the mitigation regimes vary among the Eastern RTOs, they all generally force new entrants to bid at or above an administratively determined estimate of what a new resource “should” cost, while existing resources are permitted to bid at a lower level, Glick said.
The more the commission interferes with state public policies under the pretext of mitigating buyer-side market power, the more it will force states to choose between their public policy priorities and the benefits of the wholesale markets that the commission has spent the last two decades fostering, Glick said.
“New York provides the perfect example, as the Public Service Commission has begun a proceeding to consider ‘taking back’ from NYISO the responsibility for ensuring resource adequacy,” Glick said.
He noted that numerous states are considering leaving the other Eastern RTOs’ capacity markets, which also have rules that hinder states’ exercise of their resource decision-making authority.
“We got to this point largely because of the commission’s misguided belief that it must ‘protect’ capacity markets from the influence of state public policies,” Glick said. “And the end result will be profoundly inefficient, no matter how many times my colleagues use the words ‘market’ and ‘competition.’ … It is becoming increasingly clear that, unless something changes, the commission’s effort to ‘protect’ NYISO’s capacity market may ultimately be what dooms it.”
FERC last week accepted PJM’s proposed Tariff revisions on five-minute pricing to resolve inaccuracy and dispatch misalignment issues.
In its order issued Oct. 13, the commission determined that PJM’s revisions were “just and reasonable enhancements to its pricing and dispatch methodologies” (ER20-2573). The RTO had calculated current prices based on a future dispatch interval, which FERC said contributed to a misalignment between pricing and dispatch.
PJM’s proposed short-term fixes revise the locational price calculator (LPC) to use the reference real-time security-constrained economic dispatch (RT SCED) case for the same target time. For example, the LPC would calculate prices for the interval from 11:55 a.m. to 12 p.m. using the RT SCED solution for a 12 p.m. target time.
Resource offers, parameters and ancillary service assignments would be inputs to the RT SCED cases. Offers for 11 a.m. to 12 p.m. would be effective through 12 p.m., with offers for 12 to 1 p.m. used for the dispatch target time of 12:05 through 1 p.m.
PJM control room | PJM
The commission said it agreed with PJM that the proposal to modify the LPC pricing program to use the approved RT SCED dispatch case for the same target time will better align pricing and dispatch intervals.
“Specifically, we find that PJM’s proposal will more accurately ensure that prices appropriately reflect the costs of the marginal resources consistent with the future timing of the dispatch instructions they receive,” the commission said.
In April 2019, the commission ordered PJM and NYISO to revise their tariffs to allow fast-start resources to set clearing prices, contending the current rules were not just and reasonable. (See FERC Orders Fast-start Rules for NYISO, PJM.) PJM submitted a compliance filing in July 2019 that the Independent Market Monitor, state commissions and consumer advocates argued didn’t provide clear evidence that it would implement fast-start pricing correctly. Those commenters noted that PJM uses a different market interval to compute dispatch instructions and calculate prices.
FERC delayed PJM’s follow-up fast-start compliance filing in January, giving the RTO until July to make a filing as members continued working on the issue in the stakeholder process. (See PJM, IMM at Odds on 5-Minute Dispatch, Pricing Rules.)
Several months of heated debate led to members endorsing short-term fixes aligning the LPC to use the reference RT SCED case for the same target time at the June MIC meeting. (See PJM 5-Minute Dispatch Proposal Endorsed.)
PJM’s accepted plan for short-term fixes to its fast-start pricing | PJM
Stakeholders officially endorsed the Tariff changes in an unusual unanimous sector-weighted vote at the Markets and Reliability Committee’s July 23 meeting while encouraging PJM to continue to pursue both intermediate and long-term changes. (See PJM Stakeholders OK 5-Minute Dispatch Proposal.)
In last week’s order, FERC rejected the Monitor’s arguments that PJM’s proposal “creates a systematic delay between the dispatch signal and pricing that undermines the incentive to follow dispatch” and that this mismatch “occurs for any price fluctuations due to changes in load or transmission constraints, not just shortages.”
“PJM’s proposal would better align calculated prices that determine real-time, five-minute settlements for generators with the timing of when they are expected to achieve their indicated dispatch levels,” the commission said.
FERC encouraged PJM to continue to work with stakeholders on long-term reforms in its efforts to address the pricing and dispatch misalignment.
The Tariff revisions took effect on Thursday. Approval of the PJM’s fast-start proposal is still pending.
Permits are the first things needed to continue developing a sustainable supply chain for the U.S. offshore wind industry. All else flows from that starting point, a panel told the American Wind Energy Association’s Offshore Windpower Virtual Summit on Wednesday.
“I’m tired of talking about potential; I want to talk about actual … and for that we need certainty and transparency,” said Aaron Smith, CEO of the Offshore Marine Service Association (OMSA), based in New Orleans.
Aaron Smith, OMSA | AWEA
Any time the U.S. maritime industry has had certainty and transparency, it has built and even overbuilt to the market need, from launch barges, to multipurpose supply vessels, to LNG carriers, Smith said.
“Every time there’s certainty and transparency, we have built to that market, but you need to have that transparency, and you need to have that certainty, and the first step to getting there is to have those permits being issued,” Smith said. “Permits equal certainty, equal a supply chain. So, that’s what we need to see. If we can have the certainty in investment, then we can capitalize on it.”
The first big OSW project in the permitting pipeline is the 800-MW Vineyard Wind project south of Martha’s Vineyard off Massachusetts, on which the U.S. Bureau of Ocean Energy Management expects to issue a final decision in December. (See Developers Seek 1-Mile Spacing for Vineyard Wind.)
Emmanuel Martin-Lauzer of Nexans High Voltage USA agreed with Smith, saying the U.S. market is difficult for investors to put money into without timely and predictable permits.
Despite the very slow start in the U.S. compared to Europe, Nexans, which has several offices around the country and in Canada, is adding submarine cable manufacturing capability to its existing facility in South Carolina.
Jones Act and More
OSW supply chain factors other than permitting include workforce training, the Jones Act requirement that vessels working coastal trade be built in the U.S., local content requirements, and the potential of benefiting from oil and gas industry assets and experience.
Maria Ravn, MHI Vestas OSW | AWEA
Moderator Maria Ravn, U.S. global supply chain management lead at turbine manufacturer MHI Vestas Offshore Wind, relayed an audience question on how the lack of Jones-compliant vessels is affecting planning or projects timelines.
Joris Veldhoven, Atlantic Shores | AWEA
“Is it a known fact that there are no available large installation vessels for turbines and foundations, at least for the monopile foundations?” said Joris Veldhoven, treasurer and commercial director of Atlantic Shores Offshore Wind, a joint venture created by Shell New Energies and EDF Renewables to develop a lease area off New Jersey.
“I think that’s a reality that all the developers can work around and are working around; all the projects along the East Coast are certainly maturing their development plans in sight of this,” Veldhoven said. “It has the potential to be a gamechanger … but when it comes to local content, even beyond the offshore scope, a lot of local content development is going on in spite of this.”
Smith said the question appeared targeted to wind turbine installation vessel (WTIV) fleets, and that floating platforms and jack-up heavy-lift vessels — and vertical lifts — don’t need to be Jones-compliant.
When Danish shipping company Maersk applied to do the installations for Vineyard, for example, it was going to use a foreign-flagged ship being supplied by U.S. feeder vessels, “so, that is a perfectly legal way for these operations to happen; so, no, there is no impact,” Smith said. “Now, how do we ensure that we have the U.S. feeding vessels? I know of at least four different companies that are looking to invest in this space, but they need certainty.”
Shipowners and builders have not yet seen the certainty to invest in feeding vessels, and some wonder if there is going to be a strict adherence to the Jones Act on this matter, or if WTIVs would be used to transport and install turbines and foundations, Smith said.
Diversification and Training
Edward Anthes-Washburn, New Bedford Port | AWEA
Edward Anthes-Washburn, executive director of the New Bedford Port Authority, which hosts the main OSW terminal for the state of Massachusetts, said Gulf of Mexico infrastructure tailored to oil and gas drilling can be repurposed for OSW, and that companies are looking at the downturn in oil and gas as an opportunity to diversify.
“Especially right now, with the price of oil so low, they’ve been cutting in half the deep-water drilling operations, so there’s a lot of equipment,” Anthes-Washburn said. “In the U.S. market, there’s a lot of expertise that exists in the gulf, and that’s what our target will look like 10 years from now — it will be a combination of northern Europe and southern Louisiana.”
Nexans’ Martin-Lauzer said that repurposing the feeder barges and jack-up feeder barges developed in the gulf wouldn’t necessarily cost much more because those jack-up vessels are very expensive by the day, and using feeder vessels would actually minimize the amount of time the jack-up rig has to be offshore.
Emily Kuhn, Renewables Consulting Group | AWEA
And the skills needed to run those vessels and operate the heavy machinery already exist in the Gulf, with “200 of 800 vessels out of action now because of the downturn in the oil and gas sector,” Smith said.
Emily Kuhn of The Renewables Consulting Group said the Northeast also has a skilled workforce, but that more people will be needed for an estimated $80 billion in OSW construction contracts over the coming decade, and the sooner people can start being trained for such jobs, the better.
“So that when the time comes, we don’t have a non-U.S. labor force coming in and taking the jobs … training can help make the U.S. on a par with more experienced workforces around the world,” Kuhn said. “The jobs will follow the infrastructure and … the jobs do not end up moving to Europe.”
