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November 7, 2024

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RAW CRUTHIRDS — GCPA special briefing: Challenges Changes in Energy on the Bayou

 

David CruthirdsEditor’s Note: Below is the full, unedited version of David Cruthirds’ report on the Gulf Coast Power Association’s Feb. 5, 2015 special briefing “Challenges & Changes in Energy on the Bayou.”

New Orleans, Louisiana

By David Cruthirds

Skrmetta throws out gauntlet to FERC and MISO – Outspoken Louisiana Commissioner Eric Skrmetta came out swinging with his opening keynote speech at the Gulf Coast Power Association’s Feb. 5, 2015 “special briefing” in New Orleans, La.  Skrmetta, who defeated challenger Forest Wright in a hotly contested and closer-than-expected run-off last December, quickly attacked the “federal government” – FERC and the EPA – by saying Louisiana’s challenges stem directly from the federal government’s efforts to supplant the state’s sovereign authority.  He acknowledged the federal government’s and the states’ interests diverge, noting the federal government seeks a cohesive national electric system while the states focus on keeping the system running to meet local needs.

Skrmetta contended Louisiana’s low electric rates are being threatened by the federal government’s push for more renewable energy and cleaner power generation because those objectives are being pursued without regard to the cost to consumers.  Skrmetta contended the federal government’s various initiatives would cost consumers an estimated $1 trillion, and the section 111 (d) Clean Power Plan wouldn’t be the end of it.   He slammed the federal government’s “predatory regulation” and “unfunded mandates,” asserting the feds are “long on viewpoint, but short on cash.”  Skrmetta contended the federal government’s initiatives threaten Louisiana’s industrial renaissance, which is due in part to high electric rates in Europe from renewable energy mandates that are driving industrial companies toward the United States in general and Louisiana I particular.

New generation needed by Entergy – Skrmetta said the estimated $119 billion of industrial investment coming to Louisiana would require Entergy to build 1,500 MW to 2,000 MW of new generation during the next three years, with another 1,000 MW needed after that.  He credited Entergy for its proactive plan to buy the Union Power merchant plant, as well as the company’s plan to build new generation in Southwest Louisiana and on the Mississippi River corridor.

Entergy Louisiana President & CEO Phillip May participated in an afternoon panel, agreeing the industrial growth in Louisiana would drive the need for and location of new generation resources.  Entergy expects to see 1,700 MW of new load by 2017, so the company will need to build or acquire new generation to serve that load.  He noted Entergy is reviewing bids for long-term resources in one RFP, and expects to issue one or more RFPs in the future.  May said declining reserve margins in MISO North/Central are expected to absorb the excess generation capacity in MISO South, so Entergy would need new steel in the ground whether in the form of self-build projects or long-term PPA.

Comment – Commissioner Skrmetta and May provided interesting perspectives on plans to build new generation to serve growing loads in Louisiana.  Skrmetta’s view was that Entergy would be building the new generation itself, while May was careful to say the company would be issuing RFPs to measure bids against self-build projects.  The Louisiana PSC requires jurisdictional utilities to test self-build proposals against the market under the oversight of an independent monitor, but the “Market-Based Mechanism” rules were adopted years ago and none of the current commissioners are very strong supporters of wholesale competition. 

Entergy’s comments on recent earnings calls clearly indicate the company plans to meet its ambitious earnings growth targets by building the new generation itself, so the company likely will structure its RFPs in a way to favor its self-build projects.  Entergy single-handedly decimated the once-thriving merchant sector in its footprint through its “market foreclosure” strategy, prompting the United States Department of Justice to conduct an as-yet unresolved investigation of the company’s transmission and power procurement practices.  As a result, there aren’t any merchant left to compete, and non-affiliated suppliers know of Entergy’s predisposition toward self-dealing, so no one should expect very robust participation in the upcoming RFPs.  That increases the chances that Entergy’s self-build proposals will “win” upcoming RFPs.

May also presented Entergy’s “Power to Grow: A Blueprint for a Brighter Future,” saying Entergy hopes to limit rate increases despite the massive new investments because load growth and new customers hopefully will allow the costs to be spread across a broader customer base.

May elaborated on Entergy’s supply plans, noting the company’s needs also would be impacted by expiring PPAs and possible generation retirements, so it needs flexibility.  He said Entergy might roll over some expiring PPAs, and low natural gas prices might make it economical to refurbish some older, less efficient generation units.  May noted Entergy Louisiana recently filed its integrated resource plan (IRP) with the Louisiana PSC, and the IRP details the company’s projections.  The company will need to add combined cycle generation under all foreseeable scenarios, but also might need some combustion turbine units in load-constrained areas.

May said the company needs to be able to act quickly in response to the dynamic changes in its service territory.  He noted it took three years to construct the recently completed Ninemile Unit 6 combined cycle project, but the overall process took six years when you include the time for the RFP and permitting.  Entergy is evaluating ways to accelerate that process.

GCPA Executive Director Tom Foreman asked about prospects for self-generation and cogeneration.  Tulane’s Eric Smith said petrochemical plants and refineries that operate cogens are more concerned about generating steam so they only generate surplus power for the market on an intermittent basis, which makes them look a lot like intermittent renewable resources.  He said that means cogens generally aren’t dispatchable resources.

Texas Commissioner Anderson quickly countered that many cogens are very active participants in ERCOT, and make themselves available to be dispatched.   Anderson contended the problem in Louisiana is due to the lack of flexibility provided by the incumbent utilities, noting “that isn’t a problem in a ‘real’ market” like ERCOT.

May observed that industrials often have very different load profiles and needs, so some like Sasol would self-generate.  It will make sense for others to buy their power from the grid, while others will fall somewhere in between.  He noted Entergy Gulf States Louisiana would be serving Sempra’s Cameron LNG liquefaction project, but Sempra initially planned to self-generate.  May said reliability needs and economics convinced Sempra to take service from Entergy.  May noted it is much simpler to permit and construct an industrial facility when it doesn’t have a power generation component.

May said it might make sense for Entergy to partner with some industrials to help the industrial lower its power and steam costs, which also could help Entergy’s customers.  May said Entergy would work with its industrial customers whether they self-generate or are somewhere in between that and full retail service.  Katherine King (Kean Miller law firm) noted qualifying facilities (QFs) are concerned about the potential loss of their “PURPA-put” rights, and are worried about the costs and risks of participating in MISO’s markets.

Anderson followed up on May’s comment about how long it takes Entergy to develop generation, reiterating the benefits of competitive markets because developers can build combined cycle projects in ERCOT in less than four years.  He said Entergy Texas has been talking for six and a half years about adding new generation in East Texas, but the company has built “zero megawatts” and “precious little” new transmission.  He said ERCOT has a much more robust environment because of competition.  He conceded the Texas PUC is not known for “being overly generous” with granting returns on investment, but that is because it think the risks associated with regulated utility investments are low.  Anderson declared he’d take the competitive market “any day.”

MISO’s policies targeted – Skrmetta turned his attention to MISO’s transmission cost allocation policies, noting Louisiana is expected to export a significant amount of power to MISO North/Central because environmental regulations are expected to make the North and Central regions 2.6 GW short of generation, while Louisiana is expected to be long by 2.6 GW.  Skrmetta wants to make sure those who benefit from those imports to pay their share of the estimated $1.25 billion of transmission investment needed.

MISO CEO John Bear countered in a subsequent talk that low-cost wind generation from MISO North/Central is lowering energy costs in states without renewable mandates like those in MISO South.  Bear contended that consumers in those states shouldn’t object to paying their share of transmission associated with those beneficial wind imports.

Skrmetta acknowledged the MISO relationship has been beneficial to Louisiana, but said MISO needs to be more cognizant of the Louisiana PSC’s jurisdiction, calling that a “paramount concern.”  He called on MISO to have more interaction with the commission and its staff, noting the LPSC is “laser focused on serving consumers” rather than on executing federal programs.  Skrmetta cautioned that the long-term success of MISO’s relationship with Louisiana requires “great deference” by MISO to Louisiana’s goals and objectives.

EPA’s Clean Power Plan – The special briefing included a good bit of discussion of the impact of the EPA’s proposed section 111 (d) rules on Louisiana’s industrial renaissance.  Representatives from the Louisiana Department of Environmental Quality (LDEQ) and industry representatives expressed concerns about the impact of the EPA’s overreaching policies while expressing hope that errors in the EPA’s calculations, equitable considerations, and defects in the legal basis for the rule would cause the EPA to modify some of the more egregious provisions.

LDEQ Environmental Scientist Bryan Johnston contended the EPA’s proposal ignored the unambiguous language of Clean Air Act section 111 (d) that is limited to the “best system of emission reduction (BSER).  He also asserted the EPA knows its “beyond the unit” proposal has a weak legal basis because of the great lengths the EPA went to when justifying building blocks 2 (more gas-fired generation), 3 (more renewables), and 4 (more energy efficiency) which are beyond the control of individual electric generators.  Johnston also asserted the proposal would jeopardize reliability and increase costs.   He criticized the rule for discriminating against states with less coal-fired generation by requiring higher percentage emission reductions, while also penalizing states that took early action to reduce carbon emissions.

Baker Botts lawyer Pam Giblin lamented the “meteoric shower” of EPA air emission regulations that likely will be extended to the chemicals and oil & gas sectors “if the EPA gets away with it” in the power sector.  Giblin also criticized the EPA’s legal underpinnings, but acknowledged the EPA used a “masterful approach” to justify the extension of section 111 (d) to existing power plants that aren’t being modified.

AEP-SWEPCO’s Brian Bond also criticized the EPA’s initiative, especially the unreasonable compliance schedule that doesn’t consider the time for development and approval of state implementation plans (SIPs).  ION Consulting’s Brian Walshe predicted an $8 billion surge in energy efficiency investments nationwide, suggesting energy efficiency companies could emerge as big winners.  He also observed the political dynamics, asserting the “best political negotiators” would gain the most during the EPA’s review of public comments.

The Environmental Defense Fund’s Nicholas Bianco gamely defended the EPA’s initiative based on the expected public health benefits while asserting the cost of renewable generation has dropped to the point where the cost impacts are manageable.  He also contended we must have a sustainable climate if we want sustained economic growth, so we must figure out how to do both like India and China.

John Bear weighs in – MISO President & CEO John Bear was the keynote speaker following lunch, providing MISO’s views on a number of topics including section 111 (d) compliance.  Bear conceded that surplus generation margins in MISO meant the RTO didn’t need to move very quickly in the past, but shrinking margins from section 111 (d) and issues that arose during last year’s polar vortex are forcing MISO to reexamine its processes and respond much faster.  MISO needs to move faster but not at the expense of transparency, inclusiveness and thoughtfulness according to Bear.

Seams issues – Bear tiptoed around the ongoing seams disputes with MISO’s neighbors, asserting the disputes are driven by fundamental regional differences between organizations that are equally convinced they have the best models.   He acknowledged the need to compromise and resolve the disputes, especially in light of the looming challenges, reduced reserve margins, and the need to better optimize inter-regional power flows and transactions.

Bear acknowledged criticism for the unresolved dispute with SPP, but said both RTOs have good people but they have different views and these are hard issues.  They are making progress, but not as fast as he’d like.  Bear said he expects a settlement to be reached this summer.

MISO South “year in review” – Bear also provided a recap of the first year for MISO South, saying things went well overall, but MISO needs to continue to improve and examine its processes, especially for transmission planning.  He said the “value proposition” (net economic benefits) for MISO South during the first year were 50% to 60% more than initially projected.  The value from MISO membership was initially estimated to be $524 million per year, but the actual results for the first year were in the range of $747 million to $976 million.   Bear noted the details would be presented on Feb. 26, 2015 during “MISO week” meetings in New Orleans.   He invited stakeholders to provide feedback on how MISO is calculating its value and scorecard.

Lauren Seliga with Genscape’s MISO Analyst Team provided a very interesting recap of power trading, pricing, flows, and market barriers during the first year of MISO South’s integration.  Genscape’s analysis showed that power flowed from MISO North/Central to MISO South more often than South to North contrary to the expectations of many.  She said the MISO-SPP seams dispute and associated power flow management schemes were a significant barrier to trading and efficient power flows, but the scheduled March 1, 2015 “market-to-market” integration should help.

Patton slams seams management – MISO independent market monitor Dr. David Patton with Potomac Economics was extremely critical of the way the MISO-SPP seams dispute has been handled, scoffing at the notion that operational transmission congestion was the problems.  Patton said it is very clear the issue is a “generation imbalance” situation between MISO North/Central and MISO South rather than physical congestion on the grid.  Patton was very critical of the “completely ridiculous” constructs approved by FERC, calling the situation a “nightmare” that likely would get worse.  Patton said there is “nothing physical” about the MISO-SPP constraint, asserting it is “totally fictional” to describe it as “congestion.”

Patton also criticized SPP for trying to get MISO to pay for SPP’s embedded transmission costs.  He lamented that the current construct is undermining reliability based on a cost dispute.  Patton said the “hurdle rate” approach helped, but the $10 hurdle rate isn’t economically efficient and leaves a lot of savings on the table.  He said raising the hurdle rate to $40 would totally shut down flows and would demonstrably hurt customers.

Patton continued to express outrage, complaining that the “fictional congestion” between MISO North/Central and MISO South has increased prices in MISO South by $3/MW hour.  Patton said he definitely opposes paying SPP for what he described as loop flows because that would be unprecedented.  Nonetheless, if SPP is to be compensated, it should be through a flat rather than volumetric rate to minimize the drag on efficient trading.   But if SPP is paid, MISO and its market participants should receive FTRs or some sort of right to SPP’s transmission system in return.  He said Potomac expects to develop and submit a proposal.

NRG Sr. VP Jennifer Vosburg chimed in with an enthusiastic “amen,” urging MISO to listen to Patton.  She said the settlement being developed between MISO and SPP shouldn’t just “check off the box,” but should produce a sound construct that works for the long-run.

Vosburg agreed the first year in MISO went well overall, but stressed the continued existence of legacy issues from the past like chronic congestion from Entergy’s historic lack of transmission investment.  She also agreed that load growth in MISO South likely would limit MISO South’s ability to meet the projected 2,300 MW shortfall in MISO North/Central.  She said capacity prices in neighboring markets are puling generation out of MISO.  She lamented the demise of merchant generators in MISO South while stressing the need to improve transmission planning and market structures, including more utilization of demand response and energy efficiency.  She hoped Louisiana would remove some of its barriers to cogeneration to make it look more like Texas.

Mark Watson with Platts asked panelists to comment on Bear’s and MISO’s assessment of the benefits to MISO South from the first year.  Patton said the savings from central generation commitment and dispatch clearly were substantial, but the drag from the SPP-MISO seams dispute subtracted from but didn’t totally eliminate the benefits.  Vosburg said the decision to join MISO was the right decision, not just for Entergy.  She said MISO has more robust stakeholder processes and is more transparent.  She said the visibility of LMP prices is a great improvement, but much more work needs to be done.  She said MISO needs to improve its understanding of the market participants and legacy system in MISO South, noting some of MISO’s traditional tariffs don’t work well for MISO South.

Market monitor slams MISO – Market monitor Patton went on the attack again by sharply criticizing MISO’s lack of progress on transitioning to a better capacity market construct and the lack of progress of products that send price signals for where new generation and transmission upgrades are needed.  Patton acknowledged the opposition to capacity markets in MISO, but also blamed FERC for not clearly addressing and providing guidance on capacity market issues.

Patton contended competition should shift the risk of capital investments from ratepayers to market participants, but that hasn’t happened in MISO despite the tools and knowledge to accomplish that objective being readily available.  The looming generation shortages increase the importance of addressing those issues now according to Patton.   Patton said the question of regulated or unregulated generation isn’t an “either or” question because both can be part of a competitive market, but it is essential to have products and market structures that send proper price signals for when and where to build generation and that isn’t being done now in MISO.

Load pockets generate discussion – Bear said MISO is performing economic studies to address the WOTAB and Amite South load pockets located in Southwest and Southeast Louisiana respectively.  He said high “Voltage & Local Reliability” (VLR, known elsewhere as “reliability must-run” generation) payments prompted MISO to study whether transmission upgrades to address those areas would be economical.  He said MISO sees $70 million in uneconomic generation dispatch costs, but the transmission upgrades don’t appear to be economic based on the current analysis.   MISO expects to finalize its recommendations later in 2015, but the Locational Marginal Price (LMP) differentials don’t appear to be significant enough to justify the required transmission investment.

Market monitor David Patton also weighed in on the load pocket issues, generally agreeing that annual make-whole VLR payments of $69 million probably don’t justify significant transmission investments to eliminate.  He agreed the load pockets face reliability risks because of the lack of transmission import capacity so they need to rely on old, inefficient generation.  Patton said the situation “cries out for a market solution” rather than MISO’s transmission planning approach.  MISO needs to develop a 30-minute planning reserve product that would send a price signal so developers would build new gas-fired combustion turbines in the load pockets.  He said adding new generation should be a cheaper solution to the load pocket issues than building transmission.  Patton stressed the need to develop better market structures rather than continue to depend on regulated generation built at ratepayer risk and expense.

Vosburg countered that the WOTAB and Amite South load pocket issues aren’t new, but – “setting aside the lack of historical transmission investment by Entergy” – transmission may need to be built for the long-term.  She agreed with Patton’s concern about the cost and risk to ratepayers if the problems are solved by utility self-build generation.

The view from Texas – Texas Commissioner Ken Anderson provided his frank perspective during a panel discussion of the industrial renaissance, agreeing that Texas also has seen dramatic economic growth – dubbed the “Texas miracle.”  Anderson observed that job growth in the United Sates would be negative if jobs created in Texas were deducted from the national numbers.  He said pro-growth tax and business policies contribute to the positive environment in Texas.

Plug for competitive markets – Anderson drew sharp contrasts between the results of the competitive electricity market in ERCOT versus East Texas where Entergy and AEP-SWEPCO operate under traditional cost-based rate regulation.   Anderson – a strong supporter of competitive markets, and long-time skeptic of Entergy’s ways & means – said the responses of utilities and electric suppliers in ERCOT are very different than by utilities in the “frontier.”   He said the competitive market in ERCOT causes suppliers and “wires” companies to be very responsive to customers’ needs.  Utilities in East Texas traditionally have been slow to respond to interconnection requests, but he conceded that recent reports indicate utilities like Entergy are treating companies like “customers” rather than like “captive hostages.”

As to MISO, Anderson said MISO needs better pricing transparency and “more steel in the ground” in the form of transmission because of the impact of congestion on locational prices.

Tulane Energy Institute Associate Director Eric Smith listed the numerous large-scale industrial projects being developed in Louisiana, saying the “elephant in the room” is whether the labor pool will be adequate to support all of the projects.  He questioned whether there will be enough pipefitters and welders to build all of the projects, predicting fierce competition for skilled workers and escalating wages.

HV-DC projects on the horizon – High-Voltage Direct Current transmission projects entered the conversation during MISO South Region Vice President Todd Hillman’s presentation when an audience member asked about the impact if proposed HV-DC projects like Pattern Energy’s proposed Southern Cross project are built.  Hillman said the short answer is that MISO doesn’t know, but is studying that project and others.   MISO sees some advantages from such projects, but needs to be careful.  He said the concept makes sense because it would move wind power from ERCOT to the Southeast, but MISO must evaluate the projects holistically and needs to coordinate its assessment with ERCOT and the transmission owners in the Southeast.

Market monitor Patton said HV-DC transmission lines present contingency concerns, but nothing different than what transmission operators already face.  He said HV-DC lines amount to moving a generator from one place to another, although you would also need to factor in the probability of the transmission line going down.  Peter Nance with ICF noted the Southern Cross line out of ERCOT would be supported by a diverse generation fleet and system, so there wouldn’t be much generator risk so the real reliability risk would be if the transmission line was knocked out.

(Editor’s Note – Southern Cross is a proposed HV-DC transmission project that would connect ERCOT with the Southeast US, enabling wind power from Texas to be moved to the Southeast and allow surplus power from the Southeast to flow into ERCOT when economically justified.  Author David Cruthirds provides general regulatory support to Pattern for the Southern Cross project.)

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PJM TEAC Briefs

VALLEY FORGE, Pa. — PJM planners again pushed back a decision on the stability fix for New Jersey’s Artificial Island and said they could offer no timeframe for a recommendation to the RTO’s board.

PJM has hired a consultant to review studies of four finalists’ proposals. (See Further Study Delays PJM’s Artificial Island Decision.)

During a presentation at Thursday’s meeting of the Transmission Expansion Advisory Committee, Steve Herling, vice president of planning, said there was no telling how long it would take for PJM to decide on a recommendation after receiving the consultant’s report.

“Obviously, we want this done as quickly as possible, but each step has taken longer than expected,” he said. “At this point we’re probably out of the business of prognostication.”

Herling said planners may end up taking pieces from the proposals and putting them together. (See Artificial Island Finalists Face Off in Tense Meeting.)

“It’s entirely possible we could take part of one proposer’s project, the line that they proposed, and elements of another proposer’s project and put them together and say this is the solution, and then go back and see whose proposal that looks most like. We think we are in our powers to assemble that solution from the parts and pieces given to us.”

Herling also said PJM will be responding to a complaint that Public Service Electric and Gas filed with the Federal Energy Regulatory Commission (EL15-40) over the solicitation process. (See PSE&G: PJM Broke the Rules in Artificial Island Solicitation.) It has until Wednesday to do so.

“The complaint is not impacting PJM’s timeline on a decision,” Herling said.

All of the potential solutions involve new transmission lines connecting Artificial Island to Delaware. LS Power and Transource have proposed a southern crossing of the Delaware River. Dominion and PSE&G offered a northern route with an overhead crossing.

The project involving the island, home to the Salem-Hope Creek nuclear complex, was PJM’s first solicitation under FERC’s Order 1000, which opens up transmission line projects to non-incumbent companies.

Study: Capacity Imports not Affecting NC Pricing, Reliability

teacPJM capacity imports for delivery year 2016/17 are not significantly affecting prices or reliability on Duke Energy’s transmission in North Carolina, planners told the TEAC last week.

PJM said that was the finding of a joint study by PJM, MISO and the North Carolina Transmission Planning Collaborative (NCTPC).

The study was requested by the North Carolina Utilities Commission following the 2013 Base Residual Auction, which PJM said had cleared an unprecedented amount of imports, most of them located in MISO.

The commission was concerned that the MISO imports could exacerbate loop flows within its state and might cause Duke Energy Carolinas (DEC) and Duke Energy Progress (DEP) to alter their joint generation dispatch, raising prices for consumers.

The analysis examined 7,663 MW of external generation that cleared, 2,774 MW of which had not procured firm transmission service. Of the imports without firm transmission service, about 463 MW will flow through the DEC and DEP transmission systems, most of it on 500-kV and 230-kV lines, the study found.

“The study results indicate that the BRA resources cannot be considered a significant adverse impact on North Carolina reliability,” PJM said. “Also, the results of the economic analysis show the impacts of the modeled BRA resources to be insignificant.”

Duke complained that PJM confidentiality provisions prevent the RTO from sharing the individual resource locations with MISO, Duke or other members of the NCTPC.

“Not having access to this information and the modeling data makes it virtually impossible for Duke Energy’s transmission planners to fully understand any identified issues or to determine appropriate corrective actions,” Duke said. “Duke Energy believes that its transmission planners have a right and necessity, due to their responsibilities under FERC and [North American Electric Reliability Corp.] rules, to obtain detailed information on all activities that may affect the reliability of Duke Energy’s bulk electric system.”

Duke also complained that using low distribution factors as a threshold for considering transmission impacts is inappropriate for the analyses conducted. The company said they limit “the likelihood that calling transmission loading reliefs (TLRs) on BRA-related generators will be a viable means of relieving congestion in real time.” It said the analysis should use higher thresholds and be run after each annual auction.

Nevertheless, Duke said it “believes that PJM performed the analysis accurately and conscientiously.”

Ill. Nuke Retirements Could Prompt Major Tx Projects in PJM, MISO

teacThe retirements of Exelon’s Byron, Quad Cities and Clinton nuclear plants in Illinois could require more than $372 million in transmission upgrades in MISO’s Northern Indiana Public Service Co. (NIPSCO) and Ameren Illinois (AMIL) zones and millions more within PJM, PJM officials told the TEAC.

Planners said their study, done at the request of the Illinois Commerce Commission, indicated the retirement of the plants would cause numerous thermal and voltage violations requiring almost $305 million in transmission improvements in AMIL and an estimated $68 million in NIPSCO. The largest potential project was the reconductoring of 34 miles of a 138-kV line in AMIL, estimated at $51.3 million.

The study also identified numerous violations within PJM, although the costs of corrective measures were not included in planners’ presentation.

“It’s not surprising that taking out 5,000 MW of generation in Illinois that we would see some reliability issues,” said Paul McGlynn, general manager of system planning.

Exelon last year said that the three nuclear plants are unprofitable under current market rules and that it might shut them down without changes. (See Illinois Considering Carbon Tax, Cap-and-Trade to Save Exelon Nukes.)

AEP Upgrade Project Triples in Cost to $130M

teacThe cost of American Electric Power’s project to upgrade 36 miles of 138-kV facilities between the Harrison and Ross substations in Ohio (Project B2256) has jumped to $130 million from $40.5 million, PJM told TEAC members.

Engineers discovered that outages of the line would jeopardize a large load pocket and that a de-energized rebuild would take much longer than the required in-service date of June 1, 2017.

Instead, AEP will rebuild the line while it is energized, increasing the cost, PJM said.

Dominion, FirstEnergy Recommended for Pratts Solution

PJM planners are recommending the RTO’s board select a proposal from Dominion Resources and FirstEnergy to solve reliability problems near Pratts, Va.

Dominion and FirstEnergy estimated the cost of the project at $149 million, but PJM says the cost could range between $129 million and $164 million.

PJM solicited solutions in its second Order 1000 proposal window last year. Four developers suggested 16 proposals, including two transmission owner upgrades and 14 greenfield projects. Only six of the proposals were judged to have solved the violations.

LS Power’s Northeast Transmission Development agreed to cap the costs on its proposals but PJM said its own estimates suggested the upgrades would exceed the developer’s caps, making them more expensive than the Dominion-FirstEnergy greenfield proposal, which also had less risk because the companies own the substations involved and most of the rights-of-way required.

Planners said the winning project (2014_2-13A) should be submitted to the Virginia State Corporation Commission for approval by the end of the first quarter. It includes a new 230-kV line, uprates of existing 115-kV lines and substation upgrades.

Suzanne Herel and Rich Heidorn Jr.

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DOE IG Warns FERC Information Security ‘Severely Lacking’

By Ted Knutson and Rich Heidorn Jr.

ferc
Former FERC Chairman Jon Wellinghoff

WASHINGTON — The Federal Energy Regulatory Commission’s protection of information on the vulnerability of the nation’s electrical grid is “severely lacking,” Department of Energy Inspector General Gregory Friedman warned in an inspection report.

The report, released Feb. 4, also said investigators found “troubling” inconsistencies between the testimony of FERC staffers and former FERC Chairman Jon Wellinghoff. Investigators said their efforts to reconcile the disparities were hampered because relevant emails were missing from Wellinghoff’s account.

Friedman called on the agency’s staff to develop a system to review sensitive information with the aim of providing appropriate access to the industry while protecting the data from would-be adversaries. He also recommended commission workers have security clearances.

The report came as a result of accusations that Wellinghoff inappropriately disclosed information to industry and federal officials on an analysis he commissioned on critical substations. Details of the analysis also were the subject of news articles. (See FERC Criticism of Ex-Chair Mounts.)

FERC staffers told the IG the non-public information Wellinghoff released was highly sensitive though it wasn’t classified. “The commission failed to have the material reviewed even though some commission staff referred to the analysis and substation failure simulations as being of ‘national security’ interest,” the IG said.

The report did not cite Wellinghoff by name, only referring to him as “the former FERC chairman.”

The report said that from June through October 2013, commission staff, including the former chairman, briefed or shared details of the electric grid analysis with industry and federal officials and congressional staff.

Factual Disputes, Missing Email

Before the briefings, the IG said, an unidentified “senior commission official” requested that the chairman consider using generic simulations to avoid revealing sensitive information, but Wellinghoff denied the request. The creators of the analysis told investigators that in response to concerns about sharing the information, Wellinghoff permitted them to treat the documents as Critical Energy Infrastructure Information (CEII), requiring those who viewed the information to sign nondisclosure agreements. The report cites emails dated April 23 and 25, 2013, in which a senior commission official wrote that he discussed the use of nondisclosure agreements with the former chairman, who agreed with the idea.

But Wellinghoff told investigators that although there was a general assumption that the analysis should be considered CEII, it was never formally designated as such. The former chairman also said he was unaware of commission staff requiring the completion of nondisclosure agreements prior to his sharing the information.

The IG said that in an effort to resolve the “troubling” inconsistences in the testimony of commission staff and the former chairman, investigators obtained emails and other relevant documentation from commission records.

“In our view, the information contemporaneously generated by the commission staff supported the testimonial evidence they provided regarding the circumstances surrounding the creation and subsequent handling of the electric grid analysis and substation failure simulations,” the IG said. “When we attempted to compare the statements made to us by the former chairman to supporting information, we found no email traffic in the former chairman’s account for a relevant period in October and November of 2013.”

Although commission staff said they had provided all of Wellinghoff’s emails in commission records, investigators did obtain some emails generated or received by the former chairman that were not found in his account from the email accounts of other commission staff members. “Nonetheless, because of the inability to obtain information from the former chairman’s email account for that period, we were unable to completely reconcile the differing positions,” the IG said.

Wellinghoff did not respond to a request for comment on the report.

‘Deeply Troubling’

The report was requested last February by then-Senate Energy and Natural Resources Committee Chairman Mary Landrieu (D.-La.) and the current chair, Alaska Republican Lisa Murkowski.

Murkowski issued a statement Feb. 4 terming the findings “deeply troubling.”

“Not only did the report find inconsistencies between the testimony of former FERC Chairman Wellinghoff and commission officials, but it found that during Wellinghoff’s tenure there was a ‘culture of reluctance to classify certain nonpublic documents,’” Murkowski said.

“Additionally, it is concerning that Mr. Wellinghoff’s email during the relevant period apparently went missing. Oversight of FERC is an important duty of this committee. As chairman, I will fully review the inspector general’s recommendations, including potential legislative proposals to improve FERC’s handling of sensitive information.”

FERC Chairman Cheryl LaFleur, who succeeded Wellinghoff, said she concurred with the report’s findings and had begun to implement its recommendations.

In response to the IG’s preliminary findings in April 2014, the commission modified its mandatory annual ethics and classified security training to emphasize the proper handling of nonpublic and classified material. (See IG Faults FERC on Leaked Sabotage Report.)

Commission staff also has begun meeting with Department of Energy officials to address confusion identified by investigators over their respective responsibilities for classifying commission-created information.

The IG said the commission’s comments and planned corrective actions were “generally responsive” to its findings.

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NYISO: We’ll Cooperate with PSC Review

By William Opalka

nyisoNYISO last week defended itself against criticism from New York Gov. Andrew Cuomo but said it will cooperate with a review by state regulators that could result in changes to the ISO’s governance and market design.

Cuomo called last month for the Public Service Commission to review the ISO, saying its market design is at odds with his administration’s Reforming the Energy Vision initiative, which seeks increased deployment of distributed resources and clean energy. Cuomo also called for more public and consumer representation on the ISO’s board of directors.

The review was proposed in the 548-page 2015 Opportunity Agenda, a companion document to the state budget that outlines state policy goals.

“The development of cleaner energy resources requires proper price signals at both retail and wholesale levels and a marketplace that recognizes their value. The current wholesale market structure is not designed for, nor may be well suited for, the proliferation of clean distributed energy resources. The evidence lies in the limited deployment of demand response in the wholesale energy and ancillary services markets and the eroding penetration of demand response in the capacity market. Renewable energy resources also face financial difficulty operating within the current wholesale market structure,” the agenda said.

“In designing and administering the wholesale markets, NYISO makes decisions that can have profound impacts on New York’s electricity prices and energy resource mix, and thus on consumers, the economy and the environment. However, NYISO’s board of directors does not have adequate public and consumer representation and are not subject to the same transparency standards as other governmental organizations.”

Review ‘Prudent’

James Denn, a spokesman for the PSC, said a review is “prudent policy and practice” as it seeks to align the operation of the wholesale electricity market with REV.

He also alluded to the PSC’s opposition to NYISO actions that have raised rates. The most recent is the creation of a capacity zone in the counties north of New York City that NYISO proposed and the Federal Energy Regulatory Commission approved. Consumers were hit with higher costs, which NYISO said was necessary to send price signals to power generators to encourage plant construction in the region to alleviate a transmission bottleneck.

“The commission regularly reviews market issues and has successfully argued to FERC for changes that have saved ratepayers hundreds of millions of dollars, such as the 2011 reversal of a FERC decision regarding the NYISO demand curve,” Denn said. “Our recent experience fighting the new capacity zone in the lower Hudson Valley has raised serious questions as to whether there are underlying governance and market design problems at the NYISO that if fixed would avoid similar problems in the future.”

The review, which has no deadline, could include recommendations for legislative changes.

Strong Relationship

NYISO spokesman David Flanagan said the ISO will cooperate with the PSC inquiry. “We look forward to continuing our strong relationship with the Public Service Commission and building on the NYISO’s 15-year track record of open collaboration with our regulators and stakeholders as markets and innovative technologies continue to evolve,” he said. “We are proud of the significant value the NYISO provides to consumers through unmatched system reliability, efficient wholesale energy markets and long-term planning.”

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Bill Halting Dominion Rate Reviews Passes Va. Legislature

The Virginia General Assembly passed a bill Thursday that would temporarily suspend the State Corporation Commission’s biennial review of Dominion Virginia Power’s base rates.

SB 1349, introduced by Republican Sen. Frank Wagner, was written with help from Dominion. It would freeze the utility’s base rates while preventing the SCC from reviewing those rates after the scheduled 2015 review until 2020.

Dominion would still be able to request increases for fuel and infrastructure costs. It has already promised not to pass along $85 million in fuel costs to ratepayers as part of its support for the bill.

The bill passed the state Senate 32-6 on Feb. 6 before clearing the House of Delegates 72-24 last week. Support and opposition to the bill were both bipartisan. The bill now goes to Gov. Terry McAuliffe (D), who can veto it, though under Virginia law the legislature may override the veto with a two-thirds majority in each house.

Wagner has said he introduced the bill to prevent rate increases that would occur due to coal retirements under the U.S. Environmental Protection Agency’s proposed carbon emissions rule, called the Clean Power Plan. Wagner was among 11 senators who owned stock in Dominion, but earlier this month he told the Associated Press that he sold it because he didn’t want to be perceived as profiting from the bill.

State Attorney General Mark Herring (D) has come out against the bill, as have consumer advocate and environmental groups. The Sierra Club, however, dropped its opposition after Dominion promised to invest in 500 MW of solar generation.

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FERC Rejects Fee on Greenfield Transmission Projects

greenfield transmissionPJM’s proposal to exempt transmission upgrades under $20 million from a $30,000 study fee is unduly discriminatory, the Federal Energy Regulatory Commission ruled Friday.

While the ruling (ER15-639) would seem to be a victory for non-incumbent developers, two non-incumbents, LS Power and ITC Holdings, had asked FERC to approve the PJM filing, the result of a compromise Members Committee vote in November. (See PJM Independent Transmission Cos. Win Concession on Project Evaluation Fees.)

LS Power proposed the compromise after an earlier proposal, which would have charged only new “greenfield” transmission facilities, fell short of a two-thirds majority. The proposed compromise would have assessed the fee on upgrades of $20 million or more as well as all greenfield transmission proposals.

LS Power and other non-incumbent transmission developers had contended the original proposal was unfair because it applied to greenfield projects only.

PJM officials said that upgrades by transmission owners typically did not require the intensive engineering analysis that the fee is intended to pay for.

The Members Committee approved LS Power’s compromise with an 84% sector-weighted vote.

But the commission ruled that PJM failed to show that the costs of studying transmission owner upgrade proposals with estimated costs under $20 million would be different than the costs of studying greenfield projects with similar costs.

“Even though PJM’s proposal represents a compromise among stakeholders, PJM’s proposal is inconsistent with the requirements of Order No. 1000,” the commission said.

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Members Dispute PJM, IMM on Unfinished Changes to Notification, Start-Up Times

By Rich Heidorn Jr.

VALLEY FORGE, Pa. — An attempt by PJM officials and the Independent Market Monitor to complete what they called unfinished business ran into a roadblock last week as several stakeholders questioned their authority, saying members should consider a new problem statement.

Officials are seeking manual changes to document rules on generator notification and start-up times they said had been authorized by members — but never implemented — in 2012.

The issue dates to a January 2011 problem statement to address reliability and market implications of generators’ desire to “de-staff” little-used units during the spring and fall shoulder months. At the time, there were no market rules governing start time and notification time parameters.

PJM and the Monitor said the Operating and Market Implementation committees approved rule changes in 2011 and 2012 but that manual changes endorsed by the Markets and Reliability Committee in June 2012 implemented only part of the “solution.”

The MRC endorsed the addition of a new section 1.4 to Manual 10 and made revisions to manuals 13 and 14D. The changes defined what happens when PJM issues a notification or start-up alert, and set notification and start-up time requirements for peak and off-peak periods.

Last week, officials told OC and MIC members they want to add a section to Manual 11 that would fully implement the rule changes. The new language, which is still being drafted, would:

  • Require units to use the same notification and start-up times for both price-based and cost-based offers;
  • Define “safe harbor” provisions for units whose notification and start-up times don’t affect PJM scheduling decisions;
  • Establish an economic indicator in eMKT that signals to generation owners whether the Monitor anticipates their units will be economic or uneconomic;
  • Add an approval and change process for notification and start-up time parameters; and
  • Establish rules on start-up cost offers for short lead-time units.

Lost in the Ether

Dave Anders, director of PJM stakeholder affairs, said his research found that manual language was drafted for elements involving PJM but not for those concerning the Monitor’s role in enforcing the rules.

“They were never drafted and taken to the MRC and for some reason we closed this issue out in the issue-tracking and it got lost in the ether,” Anders told the MIC on Wednesday.

But some members who took part in the 2012 MRC vote said their recollections of the issue differ from the portrayal by PJM and the Monitor.

One stakeholder said the Manual 11 changes the Monitor is now seeking would allow it to approve both cost- and price-based schedules. “I’m telling you that would not have been approved” by members, said the stakeholder, who declined to be quoted by name.

Members “did not come to any resolution on what an appropriate notifying time would be except for … long lead-time units,” he told the OC on Tuesday. “Never did we agree that the start-up and notification was subject to approval by the Market Monitor.”

Several stakeholders said members should consider a new problem statement on the unapproved manual changes and other concerns that generators have regarding parameter-limited schedules.

A second stakeholder who also declined to be quoted by name asked whether there was a “statute of limitations” on problem statements, saying it “seems like a stretch” for officials to make the changes years later. “Everybody who was a part of the process has different recollections of what was agreed on,” he added.

Joel Romero Luna, representing the Monitor, told the OC that PJM and the Monitor have been unable to find any documentation “that things were purposely kept out.”

“Some things were implemented. Some things were not implemented,” said Luna, who was not part of the 2012 discussions.

“There was a reason that it didn’t” get implemented, the second stakeholder responded. “Because the [members] didn’t come to agreement on everything on the Market Monitor’s wish list.”

Meeting Minutes

Minutes of the March 14, 2012, MIC meeting record members’ unanimous approval of two related items. An agenda item titled “parameter limited schedules” reports that Marker Monitor Joe Bowring “reviewed the consensus proposal that resulted from the special sessions of the MIC, which focused on developing potential solutions to the issues identified with the application of parameter-limited schedules to only cost-based offers.” (Emphasis added.)

Under a second agenda item titled “unit notification and startup time,” the minutes report that PJM’s Simon Tam “reviewed the consensus proposal resulting from the special sessions of the MIC, which focused on addressing market-related issues stemming from the operational requirements for units with extended notification and start-up time. The proposal will be implemented once the required technical changes are in place, but no sooner than fall 2012.”

Minutes of the June 28, 2012, MRC meeting, at which members endorsed the earlier manual changes, are no longer publicly available on the PJM website.

What’s the Rush?

Mike Borgatti of Gabel Associates noted that the Federal Energy Regulatory Commission’s response to PJM’s Capacity Performance proposal could result in additional rule changes. “What’s the rush with putting this into effect now?” he asked. “That’s a very contentious piece of the filing.”

Path Forward

MIC Chair Adrien Ford said the manual changes would be brought to a first read at the committee’s March meeting, at which time members will consider whether to move forward or to seek a new problem statement. PJM intends to refer a provision allowing generators to include the cost of shortening notification and start-up times in the cost-based start-up cost to the Cost Development Subcommittee.

Ford said that in the interim, PJM, the Monitor and stakeholders will “seek agreement on what was the history” of the issue.

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MISO Tx Customers: FERC Erred in Membership Adder Ruling

The Coalition of MISO Transmission Customers (CMTC) has asked the Federal Energy Regulatory Commission to reconsider its approval of a 50-basis-point incentive adder for MISO membership.

FERC conditionally approved the adder last month, saying that the resulting base return on equity must be in the zone of reasonableness — 7.03 to 11.74%. The commission said that industrial customers, including the CMTC, had failed to provide sufficient evidence for their argument that TOs did not need an incentive to remain in the RTO. (See MISO TOs Can Collect Membership Adder — Once Base ROE is Found Just.)

In its rehearing request, the coalition said that FERC’s ruling violated Section 205 of the Federal Power Act, which holds that the burden of proof in a ROE-related filing falls on the filers, not the complainants. FERC “not only failed to hold the MISO [transmission owners] accountable for demonstrating that the RTO adder in this case is just and reasonable, but also effectively, and erroneously, shifted the burden onto protestors to show that the RTO adder is unjust and unreasonable,” the coalition said (ER15-358).

MISO TOs requested the adder last November. Industrials criticized the adder as an attempt to hedge against a potential decrease in the TOs’ base return on equity, which industrials have contended is too high. Settlement talks between the TOs and industrials broke down in December.

A FERC administrative law judge issued a schedule last month calling for written testimony beginning Feb. 23, with hearings beginning in August (EL14-12). (See ROE Talks Between MISO Industrials and TOs Collapse.)

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Stakeholders Again Light up MISO over Support for Entergy Out-of-Cycle Upgrade

By Chris O’Malley

entergyMISO planners recommended Wednesday that Entergy’s request for a $187 million transmission upgrade near Lake Charles, La., be sent up the line for consideration by the RTO’s board, despite continued objections from transmission developers.

“I know there are some contentious issues around this,” Jeff Webb, MISO’s director of planning, acknowledged shortly after opening a discussion of the project at a meeting of the South Technical Study Task Force in Metairie, La.

On Dec. 15, Entergy Gulf States Louisiana filed an out-of-cycle request with MISO, saying the need for the transmission upgrade was identified on Dec. 1. Entergy told MISO that increased industrial demand for power requires it complete the Lake Charles project by June 2018.

The company requested that the project be treated as an out-of-cycle project outside of the usual MISO Transmission Expansion Planning (MTEP) process and the competitive solicitation rules under the Federal Energy Regulatory Commission’s Order 1000.

At MISO’s Planning Advisory Committee meeting Jan. 28, transmission developers questioned the timing and motives behind Entergy’s request, which would deny them a chance to compete for the project. (See Entergy Out-of-Cycle Transmission Request Draws Competitors’ Ire.)

Webb started last week’s meeting by spending more than 30 minutes explaining MISO’s transmission planning rules, which limit out-of-cycle requests to reliability projects identified after the submittal cutoff date of the prior annual MTEP cycle with a need date within three years of the request date and expected in-service date within four years.

“We see the [Lake Charles] projects as fitting [the out-of-cycle] requirements,” Webb said.

Stakeholders Dubious

But, as during last month’s PAC meeting, stakeholders questioned how Entergy could only recently decide it needed the project and whether it needed to be done on a fast-track outside the MTEP.

A representative of NRG Energy asked Webb whether MISO had done any due diligence or simply took Entergy’s word “at face value.”

MISO officials replied that they are aware of substantial growth in the Gulf Coast region and that Entergy’s Module E load forecast data was consistent with the amount of load growth that’s been represented in the Lake Charles project. It would include two new substations, expansion of another and 25 miles of 500-kV and 230-kV transmission.

Edin Habibovic, manager of expansion planning at MISO, said that between MTEP 14 and MTEP 15, an additional 617 MW of growth was identified. Without upgrades, the increased loads could result in North American Electric Reliability Corp. violations due to overloaded transmission lines and voltage issues, Habibovic said.

George Dawe, vice president of Duke American Transmission, said evidence provided by Entergy amounts to anecdotal information.

“In our view, what’s the urgent need? I don’t see it anywhere. … It’s not a baseline reliability project,” Dawe said.

MISO officials said they have talked with Entergy’s industrial load customers, but that the customers haven’t been transparent about the timing of their power needs. Habibovic said obtaining detailed demand information from individual industrial companies is challenging in part, because they often make decisions at the last minute.

That wasn’t good enough for Dawe.

“A normal planning process has been thrown out the window,” he said. “It’s not a defined new load addition. It speculates on future economic development.”

Webb replied that if MISO ran the proposed project through the developer selection process, it would not meet Entergy’s deadline.

“We can’t risk going through that process and speculate that Entergy is wrong here — that the process could be done in two years versus two and a half years.”

MISO will not let the planning process stand in the way of needed transmission, he added, saying that’s why FERC allows exceptions to the competitive process under Order 1000.

No Attractive Alternatives

Habibovic said MISO has looked at alternatives to Entergy’s proposal to meet the increased demand, including routing power from Beaumont, 35 miles to the west in Texas, and from Lafayette, 50 miles to the east. Also modeled was an update of existing 230-kV lines.

He said the alternatives presented a number of problems, including reliability issues during construction, right-of-way challenges and high-impedance issues.

Kip Fox, director of transmission strategy and grid development at American Electric Power, asked if MISO reviewed recent public filings of electric customers who have deferred plant expansions. Other stakeholders cited reports that the drop in petroleum prices has put some liquefied natural gas projects in the Gulf region in limbo.

An Entergy representative replied that the timing of plant expansions can be volatile. Even if industrials delay a project, the need often resurfaces within a few years’ time, he said.

Cost-Overrun Concerns

Stakeholders also asked whether MISO had conducted due diligence on Entergy’s estimated costs for the project, questioning whether the $187 million price tag may grow.

Webb responded that most state regulatory agencies have provisions to deal with cost escalation and require utilities to justify overruns.

Board Consideration

Entergy’s out-of-cycle request will be discussed again at MISO’s Feb. 18 PAC meeting. It would then proceed to the System Planning Committee of the Board of Directors, likely in March, with potential consideration by the full board in April.

Overshadowed at the Metairie task force meeting by the Lake Charles discussion was a recommendation to approve five other out-of-cycle projects in the region, the largest at $10.3 million.

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PJM Planning Committee Briefs

VALLEY FORGE, Pa. — PJM is developing design, engineering and construction standards for non-incumbent transmission developers who can win “designated entity” status under the Federal Energy Regulatory Commission’s Order 1000.

PJM’s Suzanne Glatz told Thursday’s Planning Committee meeting that the RTO is seeking a balance between “innovative designs” and reliability. Greenfield projects would not have to conform to an incumbent transmission owner’s design standards but would have to meet reliability standards.

A non-incumbent could reference standards filed in FERC Form 715 for other jurisdictions, adhere to standards approved by PJM’s Transmission and Substation Subcommittee or win the subcommittee’s approval for the developer’s own standards.

Voltage Floor Among Changes to Improve Order 1000 Process

PJM is considering changes to improve the Order 1000 process and expects to present a problem statement to the Planning Committee after its fourth and final “lessons learned” conference call on the issue Feb. 27.

One possible change would exempt projects below 200 kV from the competitive process.

Improvements already underway include the use of webcasting, development of a new tool to permit the secure exchange of large files and process improvements to gain access to annual transmission planning and evaluation reports.

Light-Load Study: Generation Up, Load Down

PJM is considering changes to the assumptions it uses for modeling light-load conditions in transmission planning.

“We want to determine whether the assumptions we made four years ago should be revisited,” PJM’s Mark Sims said. “We have a lot more wind now. We have a lot more data.”

An analysis of light-load historical data confirmed that the windiest hours continue to be 1 to 5 a.m. November through April — a time when load often is less than the assumed 50% of the summer peak.

Meanwhile, wind generation often exceeds the 80% capacity factor assumed in the modeling.

Planners will discuss potential changes with stakeholders in March.

DR Assumption Model to Change

planning committeePJM is proposing to change the way it models demand response in planning studies to reflect the amount of DR that is replaced by other resources before the delivery year.

Currently, the model relies on the amount of DR that clears the Base Residual Auction and any Incremental Auctions for a delivery year. That amount is held constant for all future years.

One alternative PJM is considering would reduce DR by the lesser of either the locational deliverability area’s existing uncleared generation for the delivery year, or a rolling three-year average of the amount of DR replaced by other resources RTO-wide.

The three-year rolling average ending June 1, 2014, showed about 34% of DR was replaced RTO-wide.

Suzanne Herel