DTE Energy’s fourth-quarter earnings soared 141%, largely on growth in its non-utility operations.
The Detroit-based company serving 3.3 million gas and electric customers posted a profit of $299 million, or $1.68 a share, compared with $124 million, or 70 cents a share, for the fourth quarter last year.
DTE Electric’s operating earnings in the fourth quarter rose 27%, to $128 million. DTE Gas operating earnings fell 40%, to $31 million.
But operating earnings of DTE Energy’s non-utility units — gas storage and pipelines, power and industrial projects and energy trading — increased 70%, to $66 million.
For the full year, DTE Energy’s net income rose 37%, to $905 million or $5.10 a share.
Full-year operating revenues were $12.3 billion, up 27% from 2013.
Upward Expectations
DTE Energy increased its 2015 operating earnings per share guidance to $4.48 to $4.72, from the $4.43 to $4.67 outlook provided in November. Most of that increase is predicated on higher-than-expected prospects in the non-utility segments of gas storage and pipelines, and power and industrial projects.
During a conference call with analysts on Feb. 13, DTE Energy Chief Executive Officer Gerard Anderson said the company was embarking on a “capital investment era.”
DTE said its investments in non-utility units could amount to $1.5 billion to $1.9 billion in 2015-2019.
That includes DTE’s participation in the Nexus Gas Transmission pipeline that will run from Michigan through northern Ohio and then south to the border of the West Virginia panhandle.
The 250-mile Nexus will tap into shale gas production in the tri-state region. DTE, which is partnering on the pipeline with Spectra Energy, said it has made a pre-filing submission with the Federal Energy Regulatory Commission and has engaged an engineering firm.
Anderson said gas and pipeline operating earnings, which totaled $82 million in 2014, could grow to $145 million by 2019.
The company also has been investing in generation, including plans to acquire the 732-MW Renaissance power plant in Carson City, Mich., for $240 million.
Anderson said that MISO planning has shown a 900-MW summer capacity shortfall in Michigan. He noted that Gov. Rick Snyder recently called for Michigan to develop a comprehensive energy policy this year.
In December, DTE filed its first electric rate case in four years. If approved as proposed, the average residential customer would pay $3.25 more a month, or about a 1.5% increase annually.
David Cruthirds brings this report from the Gulf Coast Power Association’s Feb. 5 special briefing: “Challenges & Changes in Energy on the Bayou.” Among the topics discussed were Entergy’s growth plans, Year 1 in MISO South and the RTO’s ongoing seams battles.
Entergy’s Growth Plans: Room for Competitors?
NEW ORLEANS — Entergy Louisiana CEO Phillip May talked about Louisiana’s industrial growth, saying Entergy will need to build or acquire additional generation to serve 1,700 MW of new load by 2017. He noted Entergy is reviewing bids for long-term resources in one request for proposal (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 power purchase agreements (PPAs).
May said Entergy’s needs also would be impacted by expiring PPAs and possible generation retirements.
May also said the company needs to be able to act quickly. He noted it took three years to construct the recently completed Ninemile Unit 6 combined-cycle project, but the overall process took six years, including the time for the RFP and permitting. Entergy is evaluating ways to accelerate that process, he said.
Comment – 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 U.S. 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 merchants 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.
Skrmetta Throws down Gauntlet on FERC and MISO
The outspoken Skrmetta came out swinging with his opening keynote speech at the briefing. Skrmetta, who defeated challenger Forest Wright in a hotly contested and closer-than-expected run-off last December, attacked the Federal Energy Regulatory Commission and the Environmental Protection Agency, saying that the federal government is trying to supplant the state’s authority.
Skrmetta wasn’t alone in his criticism of the federal government. Some speakers questioned the impact the EPA’s proposed carbon emission rules would have on Louisiana’s industrial renaissance. Baker Botts lawyer Pam Giblin lamented the “meteoric shower” of EPA air emission regulations that likely will be extended to the chemicals, oil and gas sectors “if the EPA gets away with it” in the power sector.
In later remarks, Skrmetta turned his attention to MISO’s transmission cost allocation policies, noting Louisiana is expected to export a significant amount of power to the RTO’s North and Central regions because environmental regulations are expected to leave them 2.6 GW short of generation, while Louisiana is expected to have a surplus of the same amount. Skrmetta wants to make sure those who benefit from those imports 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 such as those in MISO South. Bear contended that consumers in those states shouldn’t object to paying their share of transmission needed to obtain wind generation.
Skrmetta acknowledged the MISO relationship has been beneficial to Louisiana, but he 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 that the PSC 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.
MISO South ‘Year in Review’
Bear was the keynote speaker following lunch, providing MISO’s views on a number of topics.
Bear said MISO’s surplus generation margins meant the RTO didn’t need to move very quickly in the past, but shrinking margins as a result of the EPA rules and issues that arose during last year’s polar vortex are forcing it to reexamine its processes and respond much faster.
Bear also provided a recap of the first year for MISO South, saying things went well overall, but that MISO needs to continue to improve and examine its processes, especially for transmission planning. He said the net economic benefits for MISO South during the first year were 50 to 60% more than initial projections of $524 million.
Lauren Seliga, a MISO analyst for Genscape, provided a very interesting recap of power trading, pricing, flows and market barriers during the first year of MISO South’s integration. Contrary to the expectations of many, she said power flowed from MISO North/Central to MISO South more often than South to North. She said the MISO-SPP seams dispute is a significant barrier to trading and efficient power flows, but that the scheduled March 1 launch of market-to-market integration should help. (See SPP, MISO Move Ahead on Flowgate Rules.)
Patton Slams Seams Management
Bear tiptoed around the ongoing seams disputes with MISO’s neighbors, asserting the disputes are driven by fundamental differences between organizations that are equally convinced they have the best models. He acknowledged the need to compromise and resolve the disputes, and that he expects a settlement on the MISO-SPP dispute to be reached this summer. (See MISO Seeks FERC Review on ‘Hurdle Rate’ for SPP Seam.)
MISO Independent Market Monitor David Patton was extremely critical of the way the MISO-SPP seams dispute has been handled, scoffing at the notion that operational transmission congestion was the problem. 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/MWh hurdle rate isn’t economically efficient and leaves a lot of savings on the table. He said raising the hurdle rate to $40/MWh would totally shut down flows and hurt customers.
Patton went on the attack again by sharply criticizing MISO’s lack of progress on transitioning to a capacity market that would send price signals for where new generation and transmission upgrades are needed. Patton acknowledged the opposition to capacity markets in MISO, but he also blamed FERC for not clearly addressing and providing guidance on capacity market issues.
Load Pockets Generate Discussion
Bear said MISO is performing economic studies to address the WOTAB (West of the Atchafalaya Basin) and Amite South load pockets in Louisiana. He said high “voltage and local reliability” (VLR) payments (known in some regions, including PJM, as reliability-must-run generation) 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.
Patton agreed that the make-whole VLR payments probably don’t justify transmission investments, which leaves the regions vulnerable to reliability risks because of their reliance on old, inefficient generation, he said. 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 attract developers to build new gas-fired combustion turbines in the load pockets, he said.
Jennifer Vosburg, NRG Energy’s senior vice president for the Gulf Coast Region, said that the 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.
Can’t get enough Cruthirds? Click here for a more detailed account of the GCPA conference.
Editor’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.)
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.
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.”
“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
PJM 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
The 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.
The 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.
VALLEY FORGE, Pa. — A senior PJM official acknowledged last week that a proposal to allow load-serving entities such as the Illinois Municipal Energy Agency to use external resources to meet their capacity requirements could be construed as “somewhat preferential.”
Stu Bresler, vice president of market operations, outlined a proposal to allocate capacity transfer rights (CTRs) to resources external to the PJM region that historically have been used to serve the needs of the PJM load.
“We think this is a relatively small population and we can do this … very narrowly,” Bresler told the Market Implementation Committee.
PJM estimates 1,037 MW of historic external resources would qualify under its proposal: 122 MW in the DOM zone, 533 in COMED, 261 in AEP and 121 in DAY.
GT Power Group’s Dave Pratzon, who represents generation owners, took issue with the plan. “What you’re proposing seems like a real sweetheart deal, and any rules I’d want to see would be very strict in terms of identification and not be able to be expanded in the future,” he said.
“I’ll be the first to admit the treatment here could be seen as somewhat preferential,” Bresler responded. The question for stakeholders, he said, is “does the historic nature of the commitments justify that solution?”
Independent Market Monitor Joe Bowring asked whether IMEA could sell its rights to a third party under the proposal.
Bresler said “that level of detail is not decided yet.” He said PJM will expand the detail of the proposal and return it to the committee in March.
Members on Wednesday approved an optional scheduling product intended to reduce uneconomic power flows between PJM and MISO, similar to the Coordinated Transaction Scheduling product launched Nov. 4 with NYISO. (See NYISO Scheduling Product Wins FERC OK.)
The product would allow traders to submit bids that would clear only when the price difference between the two regions exceeds a threshold set by the bidder.
The product would operate on a joint clearing mechanism in which each party would evaluate the prices individually, and the common set would be the transactions that flow.
PJM stakeholders will have to vote on the accuracy of the product’s prices before the offering goes live.
The RTOs are expected to agree upon a common method of interface pricing by November 2016.
PJM, MISO near Agreement on M2M Language
PJM and MISO expect to file a revised Joint Operating Agreement this spring on three market-to-market rules.
PJM’s Asanga Perera told the MIC that the two RTOs have agreed in concept on all three issues and drafted language for one, a change to the threshold for naming flowgates. Perera said RTO officials were still “wordsmithing” provisions regarding conflicting constraint control and hold-harmless settlements for planned outages submitted after the day ahead market deadline.
The threshold for flowgates will be amended for transmission lines at 138 kV or less. The change means that 138-kV and lower elements will not be named as flowgates unless flows from the neighboring RTO amount to 35% or more of the line’s rating, up from the current 25%. The 20% threshold will remain for lines more than 138 kV.
Perera said language on the other two rule changes should be complete by the March MIC meeting. A filing with the Federal Energy Regulatory Commission is targeted for early in the second quarter.
Test Shows Highest Promised Load Reductions
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Summer limited demand response produced 135% of promised load reductions in tests this year, the highest ever.
The test showed 9,668 MW of limited DR responding, 2,510 more than the commitment. However, some providers failed the test, resulting in penalties of $2.7 million, at an average penalty rate of $140/MW-day.
PJM has not actually called on DR during delivery year 2014/15.
Faulty Models Hamper Net Energy Metering Study
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PJM’s attempt to track the growth of distributed solar generation is being hampered by modeling issues. In a briefing on its net energy metering quarterly review, PJM told members that the locations identified as sources of “negative energy” — net energy injections at load buses — are not where most solar PV is located.
“Usually the largest ‘injections’ are because of modeling issues on the distribution system,” PJM’s Ken Schuyler said. “We haven’t really seen a trend of negative injections because of net energy metering.”
PricewaterhouseCoopers’ fourth-quarter 2014 power and utilities mergers and acquisitions report showed an increase in both the number and value of deals greater than $50 million. The firm recorded 22 deals in the last quarter, compared to 12 in the third and 14 in the fourth quarter of 2013. The total value of the deals increased 57% to $17.4 billion in Q4 from $11.1 billion in Q3.
PSE&G Ranks Highest in Gas Service Customer Satisfaction in East
Public Service Electric & Gas was named No. 1 in gas-service business customer satisfaction in a poll by J.D. Power, with a score of 690 on a scale of 1,000. The ranking comes on the heels of PSE&G’s first-place ranking in electric-service business customer satisfaction among 12 utility companies earlier this year. It is the first time the company has achieved first-place rankings in both categories.
PPL Shutting Down J.E. Corette Coal Plant near Billings, Mont.
A PPL subsidiary said that it will permanently shut down its mothballed 153-MW coal-fired J.E. Corette plant near Billings, Mont. PPL Montana closed the plant in 2012 because of low market prices and the high cost of environmental upgrades. At the time, it said that the plant might be returned to service if power prices warranted. It is not part of the PPL-Riverstone Holdings deal that will form a new merchant generation company, Talen Energy.
Entergy Says Vermont Yankee Decom Money not Guaranteed After 60 Years
Entergy is not guaranteeing that it will finance any decommissioning costs at the now-closed Vermont Yankee plant if it takes longer than 60 years.
Entergy Vice President Michael Twomey told Vermont legislators that if decommissioning isn’t completed by then, “there would probably be quite a lot of litigation” concerning additional funding. Vermont Yankee’s decommissioning fund currently holds about $600 million. He said he believes the fund will grow enough to cover the cost of dismantling the reactor and at least part of the cost of managing the plant’s spent fuel.
Because there is still no federal spent-fuel storage facility, all of the spent fuel since the plant started up in 1972 remains on site in pools. Twomey said the company has arranged two lines of credit to pay for transferring the fuel to dry casks and expects to be reimbursed by the U.S. Department of Energy.
Atlantic Coast Pipeline Signs $400 Million Pipe Contract
While awaiting approval from the Federal Energy Regulatory Commission, and battling with opponents in Virginia, Atlantic Coast Pipeline is moving forward with a planned 550-mile natural gas pipeline and just signed a $400 million contract with a steel pipe company. The line is intended to bring shale field gas through Virginia into North Carolina. Last week, the consortium behind the pipeline said it contracted with Dura-Bond Industries to produce steel pipe ranging from 30 to 42 inches in diameter. It is the largest single order in Dura-Bond’s history, and the company’s Steelton, Pa., plant will add a second shift to help complete the order.
Duke Energy Buys Majority Stake in Calif. Solar Company
Duke Energy added to its solar portfolio last week by buying a majority stake in REC Solar, a commercial solar company based in San Luis Obispo, Calif. Industry figures put REC Solar as the eighth largest solar installation company in the U.S. It has installed more than 400 commercial systems totaling more than 140 MW. Although the terms of the transaction were not disclosed, Duke has said it is ready to invest up to $225 million more in REC projects.
Duke Energy said it plans to spend up to $68.7 million on solar projects in South Carolina over the next five years, adding 111 MW of solar capacity to the state’s grid. The plan calls for 53 MW of commercial solar capacity and 58 MW of rooftop solar. The residential rooftop solar will be spurred by customer incentives of up to $5,000 each, the company said.
Dominion Awaiting FERC OK for Gas Tx Projects in Md.
The Federal Energy Regulatory Commission is in the final phase of reviewing two natural gas transmission projects proposed by Dominion Transmission to fuel two new power plants in Maryland. The 725-MW CPV St. Charles Energy Center in Waldorf and the 735-MW Keys Energy Center in Brandywine will be fed from Dominion’s existing pipeline, but the taps on the pipeline need to be approved by FERC. The $775 million St. Charles plant is under construction and due to come online by June 2017. Construction of the Keys Energy Center, a $750 million plant, will begin this year and come online in early 2018.
The Tennessee Valley Authority board last week approved a plan to buy a 760-MW natural gas-fired combined-cycle plant in Ackerman, Miss., for $340 million. The board also approved plans to enter into a power purchase agreement with an 80-MW solar plant to be built near TVA’s Colbert Fossil Plant in North Alabama. Charles “Chip” Pardee, chief operating officer, said the decisions were driven by a desire to add a cleaner mix to its coal-heavy portfolio to help meet pending Environmental Protection Agency emissions mandates. TVA has built or purchased five combined-cycle plants totaling 3,900 MW.
FirstEnergy Investing Nearly $35 Million in Tx Projects to Support Shale Gas
FirstEnergy said it is upgrading existing transmission lines and building new substations in a $35 million project to support the Marcellus Shale gas industry in western Pennsylvania. Although the projects are aimed at serving the growing power needs of the shale gas industry, FirstEnergy customers will also reap the benefits: new shale gas projects account for about 370 MW of projected load growth in the area, the company said.
Maria Korsnick, Exelon Generation’s senior vice president for Northeast operations and chief nuclear officer of the company’s joint venture with Electricite de France, is being loaned to the Nuclear Energy Institute for an 18-month assignment as the lobbying group’s chief operating officer. Korsnick has 28 years of experience in the nuclear industry.“Under Maria’s leadership, nuclear energy facilities at Constellation Energy Nuclear Group and Exelon have operated at exceptional levels of safety and performance,” said Marvin S. Fertel, president and chief executive officer at the NEI. “Maria will provide that same organizational effectiveness, vision and leadership working with our staff and members at NEI.”
Google Signs 20-Year Wind Contract with NextEra Energy
Google has signed a 20-year power purchase agreement with NextEra Energy to buy wind-generated electricity for its Googleplex headquarters in Mountainview, Calif. The company committed to buying half of the output from NextEra’s windmills on the Altamont Pass in eastern Alameda and Contra Cost counties. The output is estimated at 43 MW. Terms of the deal were not disclosed.
Ameren Asking for More Time to Meet EPA Emissions Goals
Ameren is asking for an additional five years to meet emissions-reduction goals set by the Environmental Protection Agency, saying the current schedule that calls for incremental goals to be reached by 2020 is unreasonable. It said that expecting states to meet the goals “with such stringent targets at short notice” would lead to “staggering costs” of approximately $4 billion. It said it could meet the targets of compliance by 2035, five years past the suggested 2030 deadline.
“The EPA should allow states that put in plans that show they would be hitting the 2030 targets within a reasonable time frame around that 2030 date — in our case 2035 — the EPA should be flexible and allow that,” said Joe Power, Ameren’s vice president of federal legislative and regulatory affairs.
Dynegy has reached a settlement with PJM’s Independent Market Monitor to alleviate market power concerns over its purchase of 12,400 MW of generation from Duke Energy and Energy Capital Partners.
In an agreement filed Feb. 6 (EC14-140), Dynegy said it would not to buy any of the plants that will come on the market as a result of the PPL-Riverstone Holdings spinoff to form Talen Energy.
Additionally, Dynegy committed to offer all of its units into PJM capacity market auctions and promised it wouldn’t retire any units unless they failed to clear. It also promised to enter such plants into reliability-must-run agreements if PJM decided they were necessary. The settlement also contained commitments concerning energy and ancillary services offers, which Dynegy said would be good for seven years.
Dynegy is hoping to acquire 11 Duke generating units in the Midwest and 10 Energy Capital Partners generators in the Midwest and New England. Dynegy would gain about 9,000 MW in PJM, boosting it to more than 10,700 MW and eighth in generation share in the RTO. (See Dynegy Back in the Game with Duke, ECP Acquisitions.)
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In their application for approval of the purchase, the companies told the Federal Energy Regulatory Commission that Dynegy’s 6.5% share of the PJM market post-acquisition would have a minimal impact on competition.
The settlement was filed along with a response to a Jan. 16 deficiency notice in which FERC said that the applicants had not addressed all of the commission’s competitive concerns.
The response included market power analyses it said proved that the transactions “will not have an adverse effect on competition” in PJM or any PJM submarket.
Noting that the Monitor was the only intervenor to raise competitive concerns in PJM, the companies asked FERC to approve the deals by April 1. Dynegy said additional delays would cost it $1 million a day in financing costs, impact outage coordination activities needed to prepare for summer operations and threaten the consummation of the deal.
Nuclear a Renewable Resource? Arizona Senate Panel Says ‘Yes’
A state Senate committee has passed a bill — by one vote — that would declare nuclear power a renewable energy source. SB1134 would define nuclear energy as renewable if it comes from “sources fueled by uranium fuel rods that include 80% or more of recycled nuclear fuel and natural thorium reactor resources under development.” State code currently holds nuclear and fossil fuels as non-renewable.
Senators’ Bill Would Give States Say over Feds on Tx Lines
The state’s two Republican U.S. senators, prompted by a proposed Clean Line transmission project in the state, have introduced federal legislation to “restore the right of states” to rule on transmission projects before the federal government steps in.
Sens. John Boozman and Tom Cotton introduced the Assuring Private Property Rights Over Vast Access to Lands (APPROVAL) Act, which calls for the U.S. Department of Energy to get approval from states’ governors and public service commissions before exercising eminent domain. Such decisions, Boozman said, “should not be in the hands of Washington bureaucrats. If a project is not good for Arkansas, our governor or public service commission should have the power to say ‘no.’”
Environmental Groups Ask Judge for Venue to Stop Oil Shipments
Rebuffed by two state boards, two environmental groups went to a Superior Court judge to appeal a state order allowing increased crude oil shipments out of the Delaware City Refinery. At issue is a 2013 order by the Department of Natural Resources and Environmental Control, which granted an amended air pollution permit for the refinery. The permit allowed crude to be loaded on vessels at the refinery’s dock. Now, long lines of rail cars carrying crude are rolling into the refinery and the crude is being shipped out.
The environmental groups argue that such use is a violation of the state’s Coastal Zone Act. But both the Environmental Appeals Board and Coastal Zone Act Industrial Control Board have said challenges to the permit are outside of their jurisdiction. The groups asked Superior Court Judge Andrea L. Rocanelli to identify a venue for their challenges to the permit. She is expected to rule within 90 days.
Madigan, Emanuel Call for Investigations of Peoples Gas
Madigan
Chicago Mayor Rahm Emanuel and state Attorney General Lisa Madigan are calling for an audit of Peoples Gas to be made public in light of the company’s burgeoning cost overruns on pipeline replacement projects. Costs for the project went from a projected $2.2 billion to $4.6 billion. Madigan and Emanuel have called for a subpoena of the auditing company, Liberty Consulting Group, to have it testify about what it discovered about the projects and the company’s management of them. Peoples is replacing about 1,700 miles of gas mains and is supposed to complete that by 2020. An administrative law judge earlier this month denied Madigan’s request to make the audit public.
IURC Denies IPL’s $12.3 Million Recovery Request for Charging Stations
Indianapolis Power & Light’s request for $12.3 million in cost recovery that would have paid, in part, for a program to build charging stations for electric cars was denied by the Utility Regulatory Commission. IPL said it would decide whether to appeal the decision. It had asked for the money to install charging stations and kiosks for the BlueIndy project, part of Indianapolis’ electric-car sharing program.
Gov.’s Office Says We Energies ‘Double-Dipping’ in UP Deal
Gov. Rick Snyder’s senior policy advisor accused We Energies of “double-dipping” for collecting ratepayer subsidies to keep an Upper Peninsula power plant on while at the same time getting paid by a returning industrial customer whose departure helped spur the subsidies in the first place.
We Energies is collecting about $8 million a month in system support resource (SSR) payments to keep the Presque Isle plant in Marquette open. Those payments and higher rates were necessary, the utility successfully argued, to keep the plant open. But Cliffs Natural Resources, an industrial customer that left two years ago, returned earlier this month. Cliffs Natural Resources makes up 85% of the plant’s load. “We absolutely believe they are double-dipping,” said Valerie Brader, Snyder’s senior policy advisor said.
WE spokesman Brian Manthey disputed that, saying the industrial customer is not guaranteed to stay with the company. Cliffs Natural Resources “could leave at any time, leaving other customers at risk,” Manthey said. “Without a long-term agreement over an extended period of time with the mines, they could potentially leave. We feel the SSR should stay in place at this point because they are not committed.” The company has until Feb. 25 to respond to the Public Service Commission.
State to Meet 10% Renewable Energy Goal by End of Year
The Public Service Commission says the state will have 10% of its energy come from renewable sources by the end of the year. Its report said that the level was at 8.1% in 2014, up from 7.8% in 2013. “By the end of the year, Michigan will have reached its renewable energy portfolio standard — 10% by 2015,” PSC Chairman John D. Quackenbush said. “The RPS can be credited with over 1,450 MW of new renewable energy projects becoming commercially operational since [the law] took effect.” The PSC said 59% of its renewable energy comes from wind, followed by 16% hydro and 14% biomass.
The Public Utilities Commission last week approved three solar projects proposed by Xcel Energy that will increase the state’s solar capacity by a factor of 10. The largest of the three projects is a 100-MW array in North Branch. Community Energy Solar, a Radnor, Pa.-based company selected by Xcel to build it, said it will be “far and away the biggest” solar project in the Midwest. Two other projects near the towns of Tracy and Marshall will add another 87 MW of capacity. Those two alone will be enough to allow Xcel to meet its state mandate for 1.5% of its electricity from solar by 2020.
TransCanada Puts Keystone Land Buys on Hold Pending Suit
TransCanada, the company attempting to build the Keystone XL Pipeline, is holding off on buying any more state land until a state court decision on a suit filed by landowners who don’t want to sell. The company has already purchased about 90% of the land necessary for the proposed pipeline to run through the state.
A 2012 state law gave the governor the power to determine the pipeline route through the state. Landowners are suing, saying that power properly rests with the state Public Service Commission. Four of the seven state Supreme Court justices already ruled in the landowners’ favor, but five justices are needed to strike down a state law.
Senate Passes Bill that Would Force BPU Approval of Wind Plan
The state Senate passed a bill that would force the Board of Public Utilities to approve the proposed Fishermen’s Energy offshore wind project. The BPU has twice rejected the $188 million project, saying it would be burdensome for ratepayers. S2711 now goes to Gov. Chris Christie for his signature. The project already has $46.7 million in federal funding, but one of the requirements to get that money is BPU approval.
For the third time in three months, Piedmont Natural Gas has filed with regulators here and in South Carolina to cut its natural gas rates. The rates are a pass through on a dollar-for-dollar basis, and dropping wholesale natural gas prices are driving the reductions. If approved, residential customers would see an average savings of about $10 per month.
The Public Utilities Commission is near a decision on whether to grant American Electric Power a power purchase agreement that will guarantee income on its share of a coal-fired generating plant. The company said the agreement is necessary to ensure continued operation of the plant in the face of increased competition. AEP, which has a larger, similar request before the commission, has hinted that if PUCO denies either request, it may decide to sell more than 2,700 MW of generation in the state. Consumer advocates and environmental groups are against it, because it transfers the risk from AEP shareholders to ratepayers.
Earthquake Victim Filing for Class Action Lawsuit Status Against Energy Companies
A woman whose home was damaged in a 2011 earthquake she claims was caused by hydraulic fracturing has sued two energy companies. Jennifer Lin Cooper filed in Lincoln County, saying the quake caused $100,000 damage to her home and she cannot afford repairs. She named Spess Oil and New Dominion as defendants. The suit seeks class action status for residents of nine counties whose homes suffered damage from three large earthquakes in the Prague area. Oklahoma had more earthquakes than California last year. It recorded 585 quakes of 3.0 magnitude or greater in 2014, more than the past 35 years combined.
New Gov.’s Shale Gas Tax Gets Rise Out of Industry
Gov. Tom Wolf almost immediately announced new taxes on gas extraction in the state when he got into office, but a coalition of energy companies thinks Wolf’s moves will put a chill in the state’s energy industry. As part of Wolf’s Pennsylvania Education Reinvestment Act, shale gas operations will be taxed at 5% of income and an additional 4.7 cents per 1,000 feet of gas extracted. “Make no mistake, adding a 5% tax to any business sector, including the energy industry, is going to reduce capital spending and hit the supply chain, especially Pennsylvania-based small and mid-sized business,” said David Spigelmyer, president of the Marcellus Shale Coalition.
PSC-Approved Tx Project Facing Land Rights Challenges
A 144-mile, $54 million transmission line approved by the state Public Service Commission is in jeopardy because Black Hills Power is having difficulty convincing property owners to let them build. Black Hills Power wants to build the line between substations in Wyoming and South Dakota, but 65 property owners are balking. The company had estimated the line would be complete by the end of the year but said it may have to resort to eminent domain action to move forward.
House Passes Bill to Give Lawmakers Last Say in EPA Clean Power Mandates
The state House overwhelmingly passed a bill that would give the legislature the last word when it comes to developing a compliance plan to meet the U.S. Environmental Protection Agency’s Clean Power Plan. The plan gives each state a goal to reduce carbon dioxide emissions and calls for each state to come up with a compliance plan. The bill, which has not yet passed the house, would call for state agencies to deliver compliance plans to the legislature, rather than to the EPA.
“In my opinion, the EPA has overstepped its boundaries,” said the bill’s sponsor, Del. Josh Nelson.
Judge Overrules PSC’s Solar Panel Size Restriction
A Dane County judge ruled last week that the state Public Service Commission erred when it set a limit on the size of solar panels that could qualify for net metering. The PSC, backed by arguments from utilities that were mandated to pay solar panel owners who qualified, said there needed to be a size restriction on the program that allows businesses, schools and churches with large solar arrays to earn credits for power they sell back to the utilities. The judge said that the PSC didn’t gather enough information before issuing its ruling.
The owner of the R.E. Ginna nuclear power plant announced an agreement with Rochester Gas & Electric on Friday that will keep the plant operating for another three and a half years with fixed monthly payments of about $17.5 million.
The New York Public Service Commission in November ordered a reliability support services agreement between the Rochester utility and plant owner Constellation Energy Nuclear Group in an effort to save the 580-MW generator on Lake Ontario. NYISO and RG&E said the plant is needed until at least 2018 to maintain system reliability in western New York.
RG&E estimates an average residential customer using 600 kWh a month will see bills rise about 4.2%, or about $3.89. The exact amount will depend on the monthly output of the plant and changes in wholesale energy and capacity market prices.
RG&E will recover some of its $17.5 million in monthly payments through its share of the plant’s “applicable revenues”: 85% of energy and capacity sales and 100% of ancillary services.
The companies originally faced a Jan. 15 deadline to complete talks for the agreement. Two extensions were granted by the PSC while negotiations continued until Friday. The agreement, which was also filed with the Federal Energy Regulatory Commission, runs from April 1 of this year to Sept. 30, 2018.
“The RSSA will ensure grid reliability in the greater Rochester area while RG&E completes a host of necessary transmission and distribution upgrades,” Exelon said in a statement. “In addition, the agreement protects 700 facility jobs, up to 1,000 skilled contractor jobs and critical tax revenue for Wayne County and the region.”
RG&E CEO Mark Lynch said the company “worked diligently in the best interests of our customers to reach an agreement with Ginna, recognizing the importance of ensuring reliable service on reasonable terms for all parties.”
The agreement is subject to approval by the PSC and FERC.
“The focus of PSC’s in-depth review will be to ensure that the reliability of the electric grid is maintained,” PSC spokesman James Denn said in a statement. “This review will include a significant opportunity for public and stakeholder comment and input.”
RG&E, a subsidiary of Iberdrola USA, has the right to terminate the agreement early with 12 months’ notice. The proposed end date in late 2018 is when a transmission upgrade in western New York is scheduled to go online. That project is intended to provide enough energy into the RG&E service territory without Ginna.
The agreement could be extended for 18 months if RG&E gives notice by Jan. 30, 2017.
Constellation, a unit of Exelon, said the plant has lost $100 million over the past three years and would be mothballed without better financial terms.
Hedge fund twins Kevin and Richard Gates, already embroiled in a battle with the Federal Energy Regulatory Commission’s Office of Enforcement, have now taken on PJM.
The Gates brothers and a trader for their Powhatan Energy Fund are awaiting a ruling from FERC on an order to show cause why they shouldn’t be fined for allegedly making round-trip up-to-congestion trades to collect line-loss rebates.
A PJM analysis done at the request of the Office of Enforcement showed that Powhatan’s trading strategy cost more than 20 market participants at least $100,000 each. PJM issued a statement Feb. 3 criticizing Powhatan’s trading activities, saying the fund failed “to appreciate the unique legal and regulatory framework governing organized wholesale electricity markets.” (See PJM: Gates’ Trades Cost Exelon, AEP, Dominion $1M Each.)
“Yeah, perhaps we do not understand this ‘uniqueness,’” Powhatan said in a press release last week. “We were under the impression that constitutional protections applied to all regulated markets in this country, including theirs.
“Our activities were perfectly legal,” the statement continued. “And the thing is — PJM knows it.”
PJM spokesman Ray Dotter’s response to the latest Gates salvo was short and to the point.
“While we stand by our position, the simple fact is that Powhatan’s problems will be resolved by FERC and the courts and not by any opinions held by PJM or Powhatan,” he said.
DTE Energy’s fourth-quarter earnings soared 141%, largely on growth in its non-utility operations.
