VALLEY FORGE, Pa. — PJM stakeholders last week launched another bid to change the $1,000/MWh energy offer cap, but consumer advocates said they were not optimistic about reaching consensus in time for next winter.
Marji Philips of Direct Energy proposed raising the cap to $2,700/MWh for cost-based day-ahead offers and price-based real-time offers — 50% more than the highest offers reported by PJM last winter.
“Everybody likes a piece of it and nobody likes the whole thing,” she said of those with whom she shared the proposal before the meeting. “So that means it must be pretty good.”
PJM’s Board of Managers asked stakeholders to make another attempt to reach consensus after efforts last year fell short. (See Members Deadlock on Change to $1,000 Offer Cap.) Philips and other PJM veterans said the $1,000 cap, which has been in effect for about 18 years, was set as a multiple of the highest prices seen at that time.
In January, PJM won FERC approval for a temporary waiver that allowed prices to rise as high as $1,800/MWh, but the RTO made it through last winter without having to invoke it. In the 75 days that the waiver was in effect, there were 54 cost-based offers between $1,000/MWh and $1,800/MWh, but none cleared.
PJM said the waiver was necessary to allow some gas-fired generators to cover marginal costs that hit $1,200/MWh in late January, as spot gas prices spiked as high as $140/mmBtu.
Higher Cap Better for LSEs
Philips said raising the cap is better for load-serving entities such as her company, because higher LMPs can be hedged while uplift cannot. She said it would also reduce capacity prices because increased energy market revenue would cause a drop in the net cost of new entry (CONE). “Here’s an opportunity to control our destiny,” she said. “We’d rather see [stakeholders] filing [a change] than PJM.”
Philips said she had been reluctant to back a change to the cap on day-ahead offers but was convinced by PJM that it was needed to enable price convergence with the real-time market.
The proposal also would require changes to scarcity pricing rules to ensure that generation dispatched for reserves receives lost opportunity costs — which could be higher than the existing $1,000 cap — she said.
Philips said her goal was “incenting the market to do the right thing. We’re trying to keep PJM as a market and not as a cost-based system.”
PJM Endorses Proposal
PJM officials — who proposed a $2,700 cap on price-based offers and removing the cap on cost-based offers in a FERC docket on price formation in March (AD14-14) — said they would accept the proposal. “It is something we would consider to be acceptable,” said Stu Bresler, senior vice president of market services.
Jim Benchek of FirstEnergy thanked Philips for the proposal, calling it “a good starting point.”
Consumer Reps Wary
But consumer representatives were not quick to embrace it.
Carl Johnson, representing the PJM Public Power Coalition, said he did not think consensus could be reached in time for an Oct. 1 FERC filing — the deadline PJM officials have said is necessary to ensure new rules are in place for winter 2015/16.
Johnson noted that stakeholders were unable to reach agreement last year despite months of debate. “Even though the pope will be in [Philadelphia], I don’t think that’s going to be enough time to give us the miracle we need to come up with consensus,” he said.
“There’s a lot here that we will need to digest,” said Dan Griffiths, executive director of the Consumer Advocates of PJM States.
Griffiths said while consumer advocates are willing to consider lifting the offer cap for generators that can demonstrate costs above $1,000/MWh, they continue to have concerns about letting those offers set LMPs for the entire market.
Philips responded that while stakeholders can debate whether the cap should be lower than $2,700, not allowing high marginal prices to set LMPs is “antithetical to the entire market structure.”
Griffiths said later that his members are willing to consider market clearing prices above $1,000/MWh but that PJM had not demonstrated a spirit of compromise in last year’s efforts, saying the RTO’s unwillingness to consider a cap below $1,800 was “insulting.”
David Mabry, representing the PJM Industrial Customer Coalition, said any change in the cap should be accompanied by broader market power protections than current rules, which test only local market power. He cited the Independent Market Monitor’s charge in the 2014 State of the Market report that some generators appeared to engage in economic withholding during high demand hours in January 2014. (See Monitor: Winter Prices Boosted PJM Prices, Raise Withholding Concerns.) Mabry said cost-based offers should be limited to short-run marginal costs.
Consultant Roy Shanker called market power concerns a “red herring,” saying existing rules are sufficient. “If you misrepresent your costs, you’re in big trouble,” he said.
Entergy has proposed closing one of its two largest Arkansas coal plants by 2028 and making modifications to the other to comply with the Environmental Protection Agency’s Regional Haze rule.
Entergy filed the proposal with EPA on Aug. 7, describing it as a “more reasonable, long-term, multi-unit approach” than the agency’s recently published federal implementation plan (FIP) for controlling the utility’s emissions. Entergy said its plan would achieve “virtually identical visibility benefits” as the EPA proposal but cost more than $2 billion less.
The company told EPA it would end coal-fired operations at its White Bluff plant by 2028, accept lower sulfur dioxide (SO2) emission rates at its White Bluff and Independence plants and install nitrogen oxide (NOx) control technology on its coal units within three years of the final FIP’s effective date — likely in 2016.
The EPA’s proposed FIP required installation of scrubbers and low-NOx burners on the four units at White Bluff and Independence, and NOx controls at Entergy’s gas/oil-fired Lake Catherine plant. The Regional Haze rule seeks to improve visibility in parks and wildlife areas by reducing particulate matter emissions.
White Bluff coal plant
The New Orleans-based company said its modeling — which it said “EPA should have conducted but failed to undertake” — indicates it does not need to invest more than $2 billion in scrubber technology at the plants and asked the EPA to amend the FIP accordingly.
Entergy said it would not be able to install dry scrubbers at White Bluff — which it shares with several other entities — until at least 2021, leaving only a few years to recover the approximately $1 billion investment. It said the EPA’s analysis incorrectly classified Independence as a best-available retrofit technology (BART)-eligible resource under the Clean Air Act and said the plant is well below EPA’s haze standards.
“Scrubbers at Independence are simply not necessary to ensure that visibility … nor are they justifiable based on EPA’s own analysis of the visibility benefits resulting from such a huge investment,” Entergy said, citing costs of as much as $1.53 billion to install scrubbers.
The utility also disagreed with the EPA’s analysis that proposed NOx BART controls at Lake Catherine. Referring to its own study, Entergy said the NOx controls would result in “inconsequential” visibility improvements.
Entergy said its approach “would ensure superior, long-term visibility benefits than would the proposed FIP” and a “dramatic decrease in [greenhouse gas] emissions, large reductions in SO2 emissions … and large reductions in … NOx emissions.”
White Bluff and Independence are both two-unit baseload coal plants capable of generating more than 1,600 MW each. The two plants date back to 1980 and 1983, respectively, and are ranked among the top 45 dirtiest coal plants by Environment America.
Lake Catherine is a 45-year-old, single-unit, gas/oil-fired plant capable of 750 MW. It is used primarily for peaking purposes.
Glen Hooks, director of the Sierra Club’s Arkansas chapter, praised Entergy for the decision to close White Bluffs but said the company should go further. “Although we’re excited about the announcement, we hope that it also spurs the company to take a hard look at its dirty and outdated Independence coal plant,” he said in a statement.
Competitive developers expressed reservations last week about a PJM proposal to exclude transmission projects below 200 kV from competition.
PJM said projects below 200 kV are almost always allocated to one zone and thus automatically assigned to the incumbent transmission owner.
PJM’s Suzanne Glatz said the “voltage floor” would allow the RTO to eliminate the cost of evaluating competitive proposals in cases where the likely solution is a transmission owner upgrade. The voltage threshold would not apply to market efficiency projects.
Of 1,523 projects approved by the PJM Board of Managers under the Regional Transmission Expansion Plan, 104 (7%) were greenfield projects, of which only 13 (less than 1%) were allocated to more than one zone and thus open to competition, Glatz said.
In 2014, only two of 55 projects selected to correct violations below 200 kV resulted in solutions above 200 kV. Both projects were transmission owner upgrades.
“There’s very few that are coming out as potential greenfield [competitive] projects,” Glatz said.
“Is 15 years really a sufficient baseline for what the future may hold?” asked Sharon Segner of LS Power, citing technology changes affecting demand response and energy efficiency. Segner also questioned why PJM’s analysis failed to include 2015 submissions, which included dozens of lower voltage submissions from the marketplace.
Brenda Prokop of ITC Holdings said her company doesn’t favor a voltage floor but that PJM’s criteria for excluding projects (see table) “gives us a little more comfort.”
“We appreciate PJM’s effort to balance interests” of developers and efficiency, she said.
Vice President of Planning Steve Herling said PJM would like to implement the changes in 2016.
Climate Change Impact? Higher Highs has PJM Adjusting Weather Forecasts
PJM is planning to change the way it forecasts weather in its planning studies due to a trend of higher peak temperatures.
The RTO has based its forecasts on temperature and humidity data from 26 weather stations dating back to 1973. But a new analysis revealed that peak readings for 1993-2013 were higher than those for 1973-1993.
Twenty of 26 weather stations had higher maximum temperature humidity index readings in the last 20 years than the earlier period, PJM’s Andrew Gledhill said.
As a result, Gledhill said, the RTO plans to exclude the earlier data and rely on that from 1994/95. It will reevaluate the historical base on a regular schedule — perhaps every five years — going forward.
Gledhill said a survey of North American forecasters indicated that most use samples of 20 years or less. “The fact that PJM uses 40 years — we’re kind of an outlier,” he said.
The change would suggest higher load forecasts, countering factors such as lackluster economic growth and energy efficiency that are likely to mute projected load growth. Herling said PJM will offer stakeholders a look at the combined impact of all of the load forecast changes at the Planning Committee’s September meeting.
Exelon’s Rebecca Stadelmeyer and FirstEnergy’s Jim Benchek asked for more discussion of the weather forecasting at the Load Analysis Subcommittee.
“This is a drastic change to what we’re used to,” Stadelmeyer said. “We want to be comfortable [with the change]. We’re not now.”
“We’re very uncomfortable at this time,” Benchek said.
Consolidated Edison reported second-quarter net income of $219 million ($0.75/share), compared with $212 million ($0.73/share) a year ago.
The company said results reflected changes in the rate plans of its utility subsidiaries, including growth in its gas delivery service related to oil-to-gas conversions, and lower operations and maintenance expenses, offset in part by higher interest expenses.
Adjusted earnings, excluding a gain on the sale of solar electric production projects, leasing transactions and the mark-to-market effects of the competitive energy businesses, were $228 million ($0.78/share) in 2015 compared with $189 million ($0.65/share) in 2014.
“Con Edison’s operating and financial performance continues to be strong,” CEO John McAvoy said. “We are embarking on a new era of energy delivery and customer choice. We are proposing new demonstration projects that will showcase energy efficiency tools, demand response and the usage information customers need to make choices, promoting solar power, energy storage and other distributed energy resources.”
Operations and maintenance expenses for Con Ed of New York were lower, reflecting lower electric operating costs and lower costs for support and protection of underground facilities to accommodate municipal projects. (See related story, NYPSC Accepts 7 REV Demos, Rejects 5.)
— William Opalka
Duke Q2 Earnings Drop; 2015 Still on Track
Duke Energy reported lower-than-expected second-quarter earnings Aug. 6, but the company said it remains on track to meet its 2015 goals.
Although adjusted earnings dropped to 95 cents/share from $1.11 for last year’s second quarter, Duke reaffirmed its 2015 adjusted diluted earnings guidance range of $4.55 to $4.75 per share.
The company reported $5.59 billion in revenue for the quarter, significantly below Wall Street estimates of $5.85 billion and the $5.71 billion it generated last year.
The Charlotte, N.C.-based company said results were affected by continued weakness in its international business — particularly Brazil — and the timing of operations and maintenance expenses at its regulated utilities.
Duke’s international business income was $52 million for the quarter, down 64% from the second quarter of 2014. A $1.5 billion stock buyback in connection with its $2.8 billion sale of 11 power plants in April to Dynegy helped offset international results.
“We met our customers’ energy needs … during extended periods of warmer-than-normal temperatures, particularly in the Southeast,” Duke CEO Lynn Good said in a press release. “Equally important, we continued to follow through on the growth initiatives that will provide long-term benefits for our customers.”
In a call with investors, Good said Duke has made “significant progress” in its coal ash removal efforts. The company announced in June it would shut down 12 coal ash basins in North Carolina in addition to 12 basins it already announced plans to close.
— Tom Kleckner
Dominion Meets Expectations
Dominion Resources met expectations with second-quarter earnings of 73 cents/share, near the top of its guidance of 65 to 75 cents.
Dominion posted earnings of $413 million, compared with earnings of $159 million for the same period in 2014. Revenue of $2.75 billion missed Zacks Investment Research’s estimate of $2.93 billion, however.
The Richmond, Va.-based company said earnings were up because a planned refueling outage at Millstone Power Station did not occur and because of higher revenues from growth projects. “All of the major projects in our infrastructure growth plan continue to move forward on time and on budget,” CEO Thomas Farrell said.
Dominion affirmed its 2015 operating earnings guidance of $3.50 to 3.85 a share.
— Tom Kleckner
Wholesale Business Drags Down Entergy Earnings
Entergy’s second-quarter profit tumbled 21% on declines in its wholesale commodities unit.
Net income of $148.8 million ($0.83/share) fell below analyst expectations of $1.14/share and the $189.4 million ($1.15/share) in the second quarter of last year.
Revenue for the New Orleans-based power provider fell 9%, to $2.71 billion.
Most pronounced was a $121 million drop in revenue for the wholesale commodities business. Power sales declined due to lower wholesale energy and capacity prices.
Revenue from Entergy’s utility segment of $1.5 billion was flat: it compares to $1.4 billion in the same quarter last year.
Clean energy technologies like wind turbines are seen as beneficiaries of the Clean Power Plan, and two reports released by the U.S. Department of Energy show its growth continued last year despite uncertainty over federal policies.
The 2014 Wind Technologies Market Report from the Lawrence Berkeley National Laboratory shows total installed wind power capacity in the United States grew 8% in 2014 to reach a nameplate capacity of nearly 66 GW, enough for almost 5% of electricity demand. Wind now generates more than 20% of electricity used in Iowa, South Dakota and Kansas. Meanwhile, prices for wind power purchase agreements have reached all-time lows. The national average levelized price of wind PPAs signed in 2014 was $23.50/MWh, down from $70/MWh in 2009.
The report cautions that most of these PPAs are from lower-cost regions of the country. The prices also benefit from the production tax credit, a federal subsidy that has helped the industry boom but will expire unless Congress extends it. Projects under construction at the end of 2014 will qualify, but that pipeline is expected to end sometime in 2016.
Electric utilities continued to be the dominant off-takers of wind power in 2014, either owning (26%) or buying (40%) power from two-thirds of the new capacity installed last year, according to the report. Merchant projects accounted for the remaining one-third.
Distributed wind — 7,400 turbines serving on-site or local loads — reached an installed capacity of 906 MW according to the 2014 Distributed Wind Market Report, by the Pacific Northwest National Laboratory.
About 58% of the distributed capacity is connected to distribution lines, with the remaining 42% serving on-site loads, either as behind-the-meter, off-grid, microgrid or remote net meter resources.
SPP and MISO met last week with their stakeholders to review the first five months of market-to-market (M2M) operations between the two RTOs, saying that while the process is off to a good start, there’s much room for improvement.
“On the whole, market-to-market is working well. It’s a more efficient solution when both markets have control of the congested flowgate,” said David Kelley, SPP’s director of interregional relations. “We’re just talking about design flaws in the overall process … specific instances where we don’t believe it’s working as it should.”
“The price convergence is not happening on some flowgates,” said MISO’s Ron Arness, senior manager of seams administration. “We need to improve that.”
M2M is intended to improve price convergence on flowgates along the RTOs’ seams: The RTOs compensate each other for redispatching generation to reduce congestion in a way that reduces overall costs.
‘Philosophical Discussion’ Needed
The two RTOS have identified nine issues that need a “philosophical discussion,” Kelley said. They include developing criteria for M2M’s usage when one or both RTOs do not have effective control of a flowgate, leading to oscillation — when one market has significantly more control over a flowgate than the other market, resulting in the constraint’s unbinding and reloading too quickly during the exchange of shadow prices — and price separation. They also have called for criteria to recalculate firm-flow entitlements (FFE) due to modeling issues or outages.
SPP has a separate concern over the differences in the RTOs’ settlement billing cycles, which ends up with SPP floating dollars for several days while trying to remain revenue neutral. Arness said those discussions will involve SPP’s and MISO’s upper management.
SPP maintains the oscillations have overloaded flowgates and led to higher shadow prices for transmission constraints — the marginal costs of reducing a constraint per megawatt of flow.
“SPP was able to manage constraints just fine before market-to-market, and we didn’t have oscillation,” Kelley said. “We believe changes can be made, but the [joint operating agreement] is flexible enough to where we can do that.”
Through July 27, MISO has sent $10.4 million to SPP to compensate for congestion costs, with SPP sending MISO $2.2 million. The two RTOs have experienced 243 M2M events — when the RTOs exchange messages concerning a flowgate needing relief — totaling 1,024 hours.
SPP and MISO have 135 permanent flowgates and 45 temporary flowgates between the two. MISO’s footprint accounts for the bulk of those flowgates, with 89 permanent and 13 temporary.
The two RTOs hold weekly review calls to approve M2M events. SPP and MISO review real-time operations of the events and the data-sharing processes to ensure they are able to correctly perform M2M settlements. The two parties must reach agreement before performing any settlements or adjustments.
Monitors’ Perspective
SPP’s and MISO’s market monitors took turns presenting their views of M2M’s performance so far.
SPP’s Market Monitoring Unit noted effective M2M should lower shadow prices and the length of congestion events but that it has not yet looked at enough data for most constraints. It said data for the first months showed no major unexpected M2M effect on prices, but those impacts vary by constraint.
The MMU also said SPP and MISO calculate their shadow prices differently and that M2M on some flowgates can have a significant impact on prices for a large portion of the SPP market, especially in Nebraska and western Kansas.
MISO’s Independent Market Monitor (IMM) said M2M coordination has been a “net benefit” in MISO by reducing congestion costs. The IMM did note, however, a number of startup issues that were “isolated and … not ongoing.”
The IMM said the two RTOs have used work-arounds when normal coordination did not lead to efficient results. It said while some work-arounds have been expedient, they “have not been ideal” and called for improved coordination procedures and possible JOA revisions.
“In particular,” the IMM said, “the current JOA may assign the monitoring responsibility for a flowgate to the RTO that has less or ineffective relief capability. In theory, this would not preclude efficient coordination. In practice, timing and coordination issues cause this to result in constraint oscillation, inefficiencies that are difficult to resolve and higher costs.”
Cap-and-trade, appealing to economists but anathema to most in Congress, is likely to be a core compliance plan for many states under the Environmental Protection Agency’s final version of the Clean Power Plan.
“Trading itself got a lot more prominent than” in the draft plan, said Doug Scott, vice president of strategic initiatives at the Great Plains Institute and a former Illinois Commerce Commissioner.
Trading would set a price on carbon much like the cap-and-trade program that helped reduce compliance costs with acid rain regulations in the 1990s and the Waxman-Markey CO2 plan that died in Congress in 2010.
While at least 40 states have been talking about some sort of trading collaboration toward meeting their carbon-reduction mandates, EPA’s initial proposal in mid-2014 set rate-based goals measured in pounds of CO2 per megawatt-hour.
Last fall, EPA provided technical advice explaining how to translate rate-based goals to mass-based equivalents that measure total carbon emissions in metric tons — a measurement more conducive to multistate trading.
The final rule goes a step further and “reduces confusion and ambiguity” for states contemplating trading, said Minnesota Public Utilities Commissioner Nancy Lange.
Essentially, the final rule “sets out elements you need to have for a trading-ready plan,” Lange added.
“I think you’ll find EPA is not only recognizing but embracing trading [plans],” Scott said.
Uncertainty Remains for Clean Power Plan
But Scott and Lange said that how many and which states will make carbon allowance trading a big part of compliance is impossible to say this early into the game.
For one thing, the final rule turned many states’ preliminary compliance planning upside down. EPA in its final rule loosened — or in many cases tightened — carbon-reduction targets in each state.
Kentucky is reeling from the final rule, which is 27% more stringent than the draft rule. Indiana and West Virginia, which also generate a big portion of power from coal, are facing carbon reductions that are 19% more stringent than before.
In addition to having to make big changes to their compliance modeling, some states face uncertain outcomes as their elected leaders vow to fight EPA in court.
The Indiana Department of Environmental Management, for instance, said it is still studying the final rule and doesn’t want to discuss potential options. The agency deferred to Gov. Mike Pence’s office as to how the state is likely to proceed.
Pence has already signaled his intentions. In June, he wrote a letter to President Obama stating that Indiana would not comply unless the rule was significantly changed.
Even with such fighting words in many states, Scott predicts state regulators will continue to discuss carbon-allowance trading scenarios in the months ahead.
“There will be a lot of discussions between states individually,” he said, though predicting it might be a year before anything coalesces.
Scott’s Minneapolis-based Great Plains Institute and the Washington-based Bipartisan Policy Center have been providing staffing support on carbon compliance to the Midcontinent States Environmental and Energy Regulators (MSEER), which includes MISO and SPP states, and to the Midwestern Power Sector Collaborative.
A number of meetings have already been held, including a workshop in Detroit in June.
Trading credits or allowances has lots of potential, says Todd Ramey, MISO’s vice president of system operations. “Trading has the benefits of allowing for a level of price transparency folks need to know. In order to monetize your carbon emissions, there needs to be a general understanding of what that value is in real time,” Ramey told the Detroit workshop.
A number of panelists agreed that multistate trading plans that were “trading-ready” were likely more plausible than formal multistate trading agreements. “Nobody has committed to anything in terms of a multistate effort” so far, Lange said.
She said MSEER has a workshop planned for Sept. 16 in Minneapolis that should be a good forum to discuss trading and other compliance scenarios in light of the final rule.
In the meantime, it’s not just Midwest states thinking more intently about trading plans. Scott said the Great Plains Institute also has been helping advise a number of states in the PJM footprint. His group plans to hold a seminar in October in Little Rock.
Nearly two years after joining MISO — and despite a seams spat between the RTO and SPP — Entergy said it is realizing expected cost savings from the integration.
Entergy and MISO’s Independent Market Monitor told the Entergy Regional State Committee in Little Rock on Aug. 11 that the December 2013 integration has produced substantial benefits and that the transition was well-managed.
Entergy cautioned that its recent review amounts only to an initial snapshot. But, so far, at least, it has identified $236 million in annualized energy related savings since integration in 2013.
MISO had estimated at the time of integration that Entergy customers could see savings of $1.4 billion over a decade.
Six Entergy operating companies operate in four MISO states: Arkansas, Louisiana, Mississippi and Texas.
Entergy vice president Matt Brown said the company would have had to acquire 1,402 MW of additional capacity resources had Entergy not joined MISO.
That’s slightly lower than 1,413 MW of avoided capacity estimated during a May 2011 study Entergy commissioned to look at potential cost savings of joining the RTO.
“The benefits that our customers are realizing from actual participation in the MISO RTO are meaningful and that they are at a level that is on par or better than what we projected in the change of control filings,” Brown told stakeholders.
The study focused on non-baseload resources and did not take into account transmission related benefits.
Broadly, the study looked at changes in costs resulting from the move to Day 2 RTO commitment and dispatch. That includes benefits in generation costs, purchased power costs, net wheeling costs and additional Day 2 production cost savings such as deferred generation investment.
On the other side of the equation were additional costs such as RTO administration and cost allocations for its share of MISO’s regional transmission projects.
“The takeaway here is that the capacity-related savings, the planning reserves, additional production cost [savings], if you will, associated with being in MISO have been in line with what we projected,” Brown said.
Among them was a 9% reduction in the portion of energy provided by Entergy’s legacy generation. “The legacy generation that we are using is being used more efficiently,” Brown said.
He cautioned that the approximately one-year post-integration period studied wasn’t enough time to draw broader conclusions. “But the information that we’re seeing is encouraging. Our customers are realizing meaningful benefits from being in MISO.”
Constraints Mar Integration’s Potential
The results also received some affirmation from MISO’s Market Monitor, Potomac Economics.
“Overall, we found that the market performance in MISO South has been well-managed and has produced substantial benefits,” said Robert Sinclair, a principal at Potomac. “The integration has been efficient.”
But Sinclair said the Operations Reliability Coordination Agreement (ORCA) and the South Region Power Balance Constraint (SRPBC) remain obstacles to transfers between MISO Midwest and MISO South.
The latter was created in response to the need to make transmission payments to neighbors for transfers more than 1,000 MW. MISO began limiting flows last year after SPP complained that MISO breached their joint operating agreement by moving power over its transmission footprint in excess of a 1,000-MW contractual limit.
Currently there’s a hurdle rate of nearly $10/MWh for transfers more than 1,000 MW, causing price separations between the regions. That raises efficiency concerns by limiting transfers more than 1,000 MW and price effects in both regions that don’t reflect physical realities of the network, Sinclair noted.
The best mechanism would be one allowing MISO to eliminate the SRPBC, Sinclair said. Reducing the hurdle rate to zero would support efficient interregional transfers and improved pricing.
Sinclair also reiterated the Monitor’s call to develop a reserve product that will reflect operating reserve needs in MISO South, in particular.
“We believe that if that constraint was released, we would have more instances where the power flows were above 1,000 MW and that would be more efficient because we would be experiencing more production cost savings,” Sinclair added.
$844M in Tx Projects for MISO South
Meanwhile, stakeholders received an update from MISO about its 2015 Transmission Expansion Plan, which proposes 352 projects totaling $2.4 billion.
Of those, 79 projects totaling $844 million are proposed for MISO South:
Arkansas: 15 projects totaling $159 million;
Louisiana: 34 projects ($473 million);
Mississippi: Seven projects ($30 million); and
Texas: 23 projects ($182 million).
However, the list is expected to be whittled down prior to board consideration in December.
The nine states participating in the Regional Greenhouse Gas Initiative released the “CO2 Emissions from Electricity Generation and Imports in the Regional Greenhouse Gas Initiative: 2013 Monitoring Report.” This report is the fifth in a series of annual monitoring reports called for in the 2005 RGGI Memorandum of Understanding. The report summarizes data for electricity generation, electricity imports and related carbon dioxide emissions for the RGGI states.
New Englanders are using less on electricity because of the mild summer. An abundance of natural gas and more efficient power plants have also helped reduce the wholesale price of energy, a respite from soaring heating costs in the winter, ISO-NE said.
The average wholesale price in June was 1.96 cents/kWh, down nearly 50% since June 2014. The decline continued in July, dropping by more than 27% year over year, the RTO said. Costs are falling for some ratepayers, but it’s uneven among New England states. The U.S. Energy Department said retail prices in New England were higher in June and July than in the same months last year.
The price for customers of Central Maine Power dropped by more than 13% in March 1. In Massachusetts, a reduction of more than 20% kicked in May 1.
Consumption Breaks Record in MISO South but Lights Stay on
The four states in MISO’s southern region set an all-time record for power usage of 32,618 MW on July 29, but the RTO didn’t have to declare emergency operations. MISO issued several hot weather notifications, which apparently worked. “Not only was this a big success for MISO and our members, but it was the first time our South Region Operations Center was truly tested,” said Katherine Prewitt, senior director of MISO’s South Region Operations, in Little Rock. The region consists of all or parts of Arkansas, Louisiana, Mississippi and Texas.
The previous peak for the region was 31,789 MW on Aug. 3, 2011.
Three solar projects could soon be online in the state, and additional installations could follow, induced by environmental regulations reducing carbon emissions and a 30% federal tax credit that will be reduced by 2017.
Arkansas Electric Cooperative Corp. announced plans for a 12-MW solar generation facility in February. Entergy in April announced an 81-MW facility. More recently, Ozarks Electric Cooperative said it would build a small facility in the northwest part of the state.
Any utility seeking to recoup costs from a state solar project through rate increases must obtain regulatory approval from the Public Service Commission. A decision is expected in Entergy’s case by the end of September.
State Senate President Martin M. Looney and New Haven officials are urging prospective merger partners UIL Holdings and Spanish energy giant Iberdrola to commit to paying the cost of cleaning up the mothballed English Station power plant.
The two merger partners are in negotiations with Attorney General George Jepsen and the Department of Energy and Environmental Protection to play a significant role in the cleanup of the 9-acre power plant site. A regulatory filing by the two companies said both would be involved in the cleanup, the cost of which has been estimated at $30 million. (See Iberdrola Refiles Acquisition Bid for UIL Holdings.)
Two out-of-state entities, Asnat Realty and Evergreen Power, bought the plant from UIL, but they failed to follow through on promises to clean it up.
Judge Denies Watchdog’s Request for Legislative Correspondence
Osborn
Marion County Superior Court Judge James Osborn turned down a request by Indianapolis-based Citizens Action Coalition to force a legislator to reveal his correspondence with utility executives, ruling that the separation of powers doctrine forbids the courts from getting involved in legislative affairs.
CAC filed suit after state House leaders denied its public records request for emails between House Energy Chairman Eric Koch (R-Bedford) and Duke Energy and Indianapolis Power & Light. The group sought correspondence that concerned a net metering bill that would have changed the way customers with solar panels are billed. That bill eventually was killed.
A Senate committee last week questioned former Consumers Energy executive Norm Saari whom Gov. Rick Snyder nominated to serve a six-year term on the Public Service Commission.
Saari appeared Aug. 13 before the Senate Energy and Technology Committee, where some members said that while they respect him, they were wary of his appointment by Snyder. Saari tried to assure them that while he worked nearly 30 years for Consumers Energy, he had no financial interest in Consumers or any other utility in the state.
Most recently Saari, a Republican, was chief of staff for the state House of Representatives. If affirmed, Saari would replace Commissioner Greg White, who is retiring.
Couple’s Complaint of Connection Fee Spurs Commission-Ordered Review
A letter written by a Stewartville couple to the Public Utilities Commission complaining of a $5 monthly fee they had to pay for their small wind generator has spurred the commission to order a review of the state’s electric utilities to see if they charge similar fees.
Alan and Kris Miller installed a small wind generator to power their hobby farm and were surprised when People’s Energy Cooperative charged them the monthly fee. People’s has since offered to refund Miller and about 30 other customers who faced similar monthly charges for wind or solar facilities.
After a five-month investigation, the commission last week declared the fee illegal and ordered a state-wide review of so-called net metering charges. Renewable advocates say such fees, which so far are unregulated, sap the incentive of those considering installing solar or wind generation for their homes or small businesses.
“They have no idea what the fee is going to be,” said David Shaffer, general counsel for the Minnesota Solar Energy Industries Association. “Maybe it is going to be $5 and maybe it is going to be $85 — until they know, they can’t make an informed purchasing decision so they choose not to buy.”
Gov. Nixon Appoints Former Aide to Chair State’s PSC
Gov. Jay Nixon has appointed former aide Daniel Hall to chair the Public Service Commission. Hall has served on the five-member PSC since 2010; he replaces Robert Kenney, whose six-year term expired Aug. 7.
Hall served under Gov. Bob Holden and House Speaker Steve Gaw before becoming a legislative aide to Nixon when he was attorney general. Kenney will join San Francisco-based Pacific Gas and Electric as its vice president for regulatory relations.
Witnesses Testify Against Federal Coal Royalty Payments
An overflow crowd packed a U.S. Interior Department meeting in Billings to discuss its policy of allowing private coal mining on government land. It was one of five sessions scheduled by Interior Secretary Sally Jewell, who has pledged a review of the government’s coal leasing program.
Most of the comments concerned the 12.5% royalties that the government collects on coal. “It’s time that you crack down on coal companies that have been getting sweetheart deals for too long,” said Renette Kaline, a Northern Cheyenne tribe member.
But some who depend on the mining said they were afraid that additional regulatory burdens could put their livelihoods at risk. “I’m scared,” said Ryan White, a miner. “I’m fearful of my future. I go to work every day wondering when the federal government will put my employer out of business.”
The Greycliff Wind Energy project, a 12-turbine project in central Montana that was proposed five years ago, continues to battle regulatory headwinds.
The project’s developers, Minnesota-based National Renewable Solutions, must persuade the Public Service Commission that the company has enough Montana owners to qualify as a Community Renewable Energy Project. The PSC rejected Greycliff Wind in June because it wasn’t convinced that local owners had a 50% stake in the company’s income, equity and voting rights.
National Renewable Solutions representatives spent last week in Sweet Grass County assuring the county commissioners “the project isn’t going away,” said the company’s Pat Pelstring.
Senior executives for Eversource Energy say the power company is willing to bury more of the transmission lines for the Northern Pass hydroelectric project, but not the entire 187-mile route from the Canadian border through northern New Hampshire to Deerfield.
“Full undergrounding is unnecessary and prohibitively expensive,” Lee Olivier, Eversource executive vice president, said in a conference call with financial analysts on July 31. “But some project modifications could be done with some additional undergrounding.”
The company is reviewing the environmental impact statement with an eye toward burying more of the line, he said. The most likely area for additional burial would be through 10 miles in the White Mountain National Forest, where the environmental report suggests overhead lines would not be allowed.
The state has reopened the Renewable Energy Fund, although with new restrictions and less money than was initially anticipated.
The freeze on REF applications, imposed on July 20, continues on applications for solar projects in the 100- to 500-kW range. Those projects have mostly been popular with businesses, according to Kate Epsen, executive director of the New Hampshire Sustainable Energy Association, a trade organization representing the renewable energy industry.
“It’s a really good category and a real shame that it’s being cut out, hopefully not forever, but even temporarily is a problem,” she said. “This was hitting an important market gap for these mid-sized projects. A lot of companies have been putting together good proposals, and there has been some good groundwork and business interest. Now that’s been taken away, or at least temporarily halted.”
Gov. Christie Signs Bill Boosting Net Metering Cap for Solar
Christie
Gov. Chris Christie has signed a bill that increases the cap under which utilities can stop paying owners of distributed solar for electricity their systems generate. The previous cap allowed utilities to stop paying when net metering systems recorded 2.5% of the state’s peak demand.
That level has already been reached. The new bill, sponsored by Sen. Bob Smith (D-Middlesex), boosted the cap to 2.9%. It is estimated that it will take another three years for that level to be reached. The new limit is designed to ensure economic incentive for the home solar industry in the state. The new level leaves room for another 700 MW of solar to be installed in the state.
“This is an important bill that moves solar forward in New Jersey,” Jeff Tittel, director of the New Jersey Sierra Club, said. “This is a ray of sunshine for the solar industry and will create clean energy and more green jobs.”
Coalition Opposes Utility Ownership of Large Renewables
Power plant owners and energy groups have joined forces to oppose utilities directly owning large-scale renewable energy projects such as wind farms. The Independent Power Producers of New York, Alliance for a Clean Energy New York, the Electric Power Supply Association and the New York Affordable Reliable Electricity Alliance said the concept would raise wholesale electric rates.
“New York cannot afford to overlook the benefits and tremendous successes of competitive wholesale energy markets by allowing utilities to once again put ratepayers directly on the hook for costly electricity investments — especially when the private sector has been successfully developing and operating large-scale renewable electric generation facilities for more than a decade,” Gavin Donohue, CEO of IPPNY, said in a statement.
The New York State Energy Research Development Authority countered that its ideas for utility ownership are just one of many options it listed in a June study to give the state new ideas on how to promote large-scale renewable energy projects.
Power Siting Board Moves Ahead on Clean Energy Future Plant
An administrative judge has ruled that a plan to build an 800-MW gas-fired power plant can go ahead to the Power Siting Board for the next step in the approval process. The judge noted that board staff have already determined the plant, proposed by Clean Energy Future, complies with applicable state law. CEF plans to spend $800 million on the plant, which would be built in an industrial park near Lordstown.
The next hearing of the board, which is overseen by the Public Utilities Commission, will be in September. If approved, the plant would begin operations in 2018.
Oklahoma Gas and Electric is pressing ahead with upgrades to its generating plants and preparing for a general rate case as it awaits a decision from state regulators in a $1.1 billion environmental compliance and replacement generation case. If approved, the OG&E request would increase customer bills by 15 to 19% by 2019, with the increases phased in each year as a separate line item on customer bills.
The Corporation Commission has not come to an agreement for a final order in the case. However, two commissioners indicated they would prefer to issue a final order within the next 30 days.
OG&E said it expects to spend about $700 million on an environmental plan to meet federal emissions regulations for regional haze and mercury and air toxics standards. It also estimates it will need about $410 million to modernize its aging Mustang natural gas plant in western Oklahoma City.
Corporation Commissioner Dana Murphy has been appointed to the Electric Power Research Institute’s Advisory Council to the Board of Directors. Murphy chairs SPP’s Regional State Committee.
The Advisory Council advises EPRI management and its board and assists in prioritizing relevant and balanced research to serve the public interest. The appointment was made by Lisa Edgar, president of the National Association of Regulatory Utility Commissioners, who said Murphy’s active service on the EPRI Advisory Council is “important to the cause of strengthening effective public regulation.”
PennFuture Names New Operating, Communications Officers
The environmental advocacy organization PennFuture has named a new chief operating officer and a new director of communications. The statewide organization said Jacquelyn Bonomo, who has experience with other environmental organizations, will become chief operating officer and vice president. She comes to PennFuture from Chesapeake Bay Funders Network, where she was executive director. She also has held upper positions in the National Audubon Society, the Western Pennsylvania Conservancy and the national Wildlife Federation.
Lauren Fraley, a legislative communications professional and former president of the Greater Pittsburgh Chamber of Commerce, will become PennFuture’s director of communications. She is taking the place of Elaine Lablame, who has moved to become the organization’s strategic campaigns director.
Invenergy says its proposed $700 million natural gas-fired Clear River Energy Center in Burrillville would be the most efficient fossil fuel power plant in New England. The plan was announced by Gov. Gina Raimondo and Invenergy CEO Michael Polsky.
If the project is approved by the Energy Facility Siting Board, construction of the 900-MW combined-cycle generator in the northwest corner of the state would start next year and the facility would begin selling power to the New England electric grid in 2019.
Invenergy expects the low-cost plant to displace older, less-efficient power plants that burn oil, coal or gas.
According to a report by the Texas Coalition for Affordable Power, 85% of the state’s customers served by the competitive electricity market pay more for power than those served by municipal utilities in Austin and San Antonio.
The report analyzed U.S. Energy Information Administration data on residential prices since 2002, the first year most residents were allowed to choose their electricity provider under deregulation. According to the study, residents in deregulated areas paid lower electric bills than most Americans for the first time in 2012 and 2013. However, the analysis found the average Texas household in deregulated areas paid about $4,800 more than residents of Austin, San Antonio and other cities served by just one municipal utility or by electric cooperatives from 2002 to 2013.
The state was the 18th cheapest state for homeowners over that 12-year period. Residents in nine states saw cheaper prices than Texans in regulated areas, while 26 states averaged cheaper prices in the competitive market.
State and RTO officials have had two weeks to digest the Environmental Protection Agency’s final power plant carbon emission rule and the battle lines — and paths to compliance — are developing.
While states in the Northeast say they are well on the way to compliance, many in the South and Midwest have already joined in the first set of legal challenges — even as other officials in the Midwest consider carbon trading plans.
Change in state carbon emission targets from draft rule to final
The 15 states who joined in the request for a stay included half of those in SPP, six of those in MISO and five of those in PJM. No Northeastern states were among them. More states may join once the clock on legal challenges begins with publication of the rule in the Federal Register.
PJM, meanwhile, remains concerned about the time required to build transmission to deliver wind power to eastern load centers.
RTO Insider’s follow-up coverage of EPA’s Clean Power Plan includes reports from throughout the Eastern Interconnection:
