Page 1692 – RTO Insider

May 28, 2013

NERC Urges Planners to Incorporate Gas Risk

The North American Electric Reliability Corp. urged electric industry planners Wednesday to begin incorporating the risk of natural gas supply interruptions in their reliability and resource assessments.

In its second major report on the growing interdependence between the natural gas and electric industries, NERC also identified gas-related reliability risks and mitigation strategies and recommended increased communication and coordination between the two industries.

“Resource planning and adequacy assessments in some areas do not fully account for the risk of disruptions in the natural gas and other fuel supply chains,” NERC wrote, noting that such assessments typically assume the availability of fuel.

Trends

NERC noted that natural gas has risen from 17% to 25% of electric generation over the past decade and is projected to provide 50% of peak demand by 2015. At the same time, natural gas demand from transportation, manufacturing and exports is also expected to increase.

Unlike fuel oil and coal, natural gas is not easily stored on-site, meaning that generators must rely on just-in-time deliveries.

Most gas peaking units and many intermediate and baseload units have interruptible gas transportation contracts, leaving them increasingly vulnerable to interruptions during times of peak gas demand.

power-and-non-power-gas-demand-vs.-temperature — Non-Power & Power Gas Demand as a Function of Temperature (Source: NERC)

In NERC regions reporting such data, about 58% of gas‐fired capacity has firm supply. PJM reported that all of its dual-fuel generators and less than half of its other gas-fired units had firm fuel transportation contracts.

“As gas consumption for both power and non‐power uses has grown, the availability of interruptible capacity has declined, especially during periods of peak gas demand,” NERC said. “… Although generators may have contractual obligations to perform, performance incentives, particularly in competitive wholesale electricity markets, may not be strong enough to incentivize generators to procure firm or otherwise reliable fuel supplies.”

History of Interruptions

Using its Generator Availability Data System (GADS), NERC identified 1,240 cases over the last 10 years in which gas-fired generators reported outages due to lack of fuel. Almost half of the incidents occurred in the Reliability First Corp. (RFC) territory, which includes most of PJM.

Regions reported average lost capacity of 96 MW to 140 MW and outage lengths of 5½ hours (Florida Reliability Coordinating Council) to 47 hours (RFC).

The report summarizes several notable incidents, including February 2011, when the Southwest suffered rolling blackouts and major gas curtailments as a result of extreme cold. More than 250 electric generating units experienced outages totaling 1.2 TWh.

The 2011 incident also exposed the gas industry’s dependence on electricity: While most gas curtailments were the result of wellhead freeze‐offs, more than a quarter of the lost gas supply was due to the loss of electric pumping units or compressors.

Vulnerabilities

Gas-fired generators are vulnerable not only to supply interruptions but also to reduced pipeline pressure, which can persist even after gas starts flowing again. NERC said critical gas generators should consider on‐site booster compression to improve reliability.

Generators also require consistent gas quality. Gas with a high British thermal unit (Btu) level from high ethane, or propane compositions can burn too hot in low‐nitrogen oxide (NOx) burners. “In cases where a number of gas‐fired units obtain their fuel from the same pipelines, changes in natural gas heat content can result in multiple unit trips at nearly the same time,” NERC said.

Risk-based Approach Needed

NERC recommended planners begin conducting a “three-layer” analysis of regional interdependencies and risks.

Layer 1 would require PJM and other system operators to compare their gas load for various weather conditions to the capacity of their gas infrastructure under normal operating conditions.

In Layer 2, the same gas load duration curves are compared to gas infrastructure capacity under contingencies, such as a compressor station outage or mainline capacity reduction.

NERC outlined such a scenario for a pipeline serving six gas-fired generators totaling 3,500 MW. The loss of all primary and backup compressors at a compressor station on the line would result in loss of all 3,500 MW within 110 minutes. Under the line break scenario, gas flow would be eliminated, resulting in a loss of all generation in about 16 minutes.

Line-break-scenario — Line Break Scenario (Source: NERC)

The final step in the three-layer scheme is the performance of a Monte Carlo analysis to provide a probabilistic assessment on how often gas-fired generators would lose fuel under a wide range of weather and gas supply conditions.

Such analyses requires good data, but the gas industry has no comprehensive statistics on interruptions similar to NERC’s GADS data on generators. As a result, gas outage data would have to be estimated from several sources, including pipeline bulletin boards, accident reports filed with government agencies and industry surveys.

Operational and resource planning implications

NERC also recommended increased training of pipeline and electric system operators to enhance cross-industry understanding and information sharing. NERC said electric Balancing Authorities and Reliability Coordinators may not “have an adequate understanding” of the information available to them under FERC order 587, which requires gas pipelines to post information on issues such as capacity constraints, gas quality warnings and scheduled maintenance.

“While the generators’ fuel managers may understand the critical and non-critical notices the information may not be readily communicated or understood well enough by the BAs or RCs,” NERC said.

Electric “operational procedures should include formalized coordination with the gas supply and pipeline industry, as well as emergency procedures during extreme events,” NERC said.

Dual Fuel

About 125 GW of gas‐fired generation, 35% of gas capacity under NERC jurisdiction, has dual‐fuel capabilities. NERC said state and federal environmental agencies should consider relaxing rules regulating backup oil use and emissions to maximize the flexibility of such units.

May 24, 2013

Capacity Auction: New Generation, Imports Up, Prices, DR Down – UPDATE

By Rich Heidorn Jr.

New gas-fired generation and a near doubling of imports caused a big price drop in PJM’s annual capacity auction, the RTO announced late Friday.

Prices ranged from $59 to $119/MW-day — down 29% to 68% — in most of PJM, although the Public Service Electric and Gas. Co. Locational Deliverability Area saw a 31% rise to $219.

More than 169,000 MW of unforced capacity was acquired for the 2016-2017 planning year, giving the RTO a projected reserve margin of 21.1%.

BRA Clearing Prices in the RTO (Source: PJM Interconnection, LLC) — (Source: PJM Interconnection, LLC)

“Prices were generally lower than last year’s auction due to competition from new, gas-fired generation, low growth in demand because of the slow economy and increased imports from other regions, primarily to the west of PJM,” said Andy Ott, senior vice president of markets.

The annual Reliability Pricing Model auction cleared a record 5,463 MW of new generation and 7,483 MW of imports from outside PJM, nearly double the level of imports from a year ago. Most of the imports — 4,723 MW — came from the Midcontinent Independent System Operator (formerly Midwest ISO).

Demand response contributed 12,408 MW, a reduction from last year, while energy efficiency cleared 1,117 MW, a 21% increase.

Demand Flat

The auction is the first to include the East Kentucky Power Cooperative (EKPC), whose load and resources will be integrated into PJM on June 1, 2013. EKPC’s peak load of 2,200 MW — offset by resources the cooperative owns or controls — pushed PJM’s reliability requirement to 180,332 MW.

But for the addition, PJM’s reliability requirement would have been unchanged from the 2015/16 planning year, and below that for 2014/2015.

Market Mitigation

As in past auctions, the RTO failed the Three-Pivotal Supplier test for supply-side market power. As a result, prices for all existing generation were limited to the lesser of the supplier’s offer price or approved offer cap.

Gas-fired combustion turbines and combined cycle generators that have not cleared a previous RPM auction were subject to the Minimum Offer Price Rule (MOPR) as a check on buyer-side market power. PJM granted exemptions to the rule for 11,821 MW of “competitive entry” generation — winners of competitive, non-discriminatory requests for proposals open to both new and existing resources — and 1,433 MW of self-supply generation. The exemption procedure was approved by the Federal Energy Regulatory Commission May 2. (See “Split Decision on MOPR.”) Only 4,915 MW (37%) exempt generation offered cleared.

New Generation

About 82% of capacity offered by new generation units cleared in the total RTO, but its success was highly dependent on geography, with only 27% clearing in EMAAC versus 91% in MAAC.

About 89% of capacity additions for 2016/17 were from natural gas-fired units, mostly combined cycle, with an additional 8% from coal-fired steam units and the remainder from nuclear, diesel and wind.

Imports

Imports offered increased 90%, and virtually all of it cleared. West of PJM imports nearly doubled to 7,081 MW over last year’s auction. MISO offered and cleared 4,723 MW, including generation from areas that will be integrated into MISO by the 2016/2017 Delivery Year. MISO’s installed capacity will increase by more than 37,000 MW with the incorporation of Entergy and South Mississippi Electric Power Association (SME) in December 2013 and Cleco in January 2014.

“It’s really the only forward capacity market available for those regions,” Ott said in a press briefing this morning.

Demand Response Declines

Demand resources offered declined 27% and cleared DR dropped to 12,408 MW, a 16% decrease from a year ago. The biggest declines were in EMAAC and MAAC.

PJM attributed the drop to expectations of decreased prices and the increased scrutiny on DR’s ability to deliver promised resources.

PJM started a stakeholder process in October to standardize the information DR providers must supply to be included in the auction. The initiative was sparked by concern that DR providers might be overestimating or double-counting demand resources. DR offered more than 20% of the forecast peak load in some zones in the 2015/2016 base residual auction.

FERC rejected on procedural grounds rules approved by the Markets and Reliability Committee in March requiring demand response aggregators to provide officer certifications and additional information on their customers. The commission said the changes required amendments to the PJM tariff and thus had to be submitted to FERC for approval. (See “FERC Remands DR Information Requirements.”)

Although the requirements were not officially in effect for this year’s auction, the timing of the commission’s order — coming on April 19, the date DR Plans were due for inclusion in the auction — appeared to have caused more caution in DR providers’ projections.

Energy Efficiency, Renewables Up

While DR was down, energy efficiency offers increased 23% to 1,157 MW, 97% of which cleared.

Contributions from renewable generation also increased, with 871 MW of wind offering and clearing, a 9% increase over last year. Solar generators offered and cleared 90 MW, a 60% increase.

Ott said the increase reflected the rising targets in state energy efficiency and renewable portfolio programs. “It allows customers to monetize their investments,” Ott said.

Gas Continues Growth, Coal Declines

Natural gas-fired generation, which cleared capacity equal to coal for the first time in last year’s auction, cleared almost 65,000 MW this year, while coal’s cleared capacity declined to less than 50,000 MW. About 9,485 MW of coal capacity failed to clear in the auction.

Transmission Constraints Affect Regions

Capacity Auction Clearing Prices by Region 2016/2017 (Note: All Prices Provided in MW-day) (Source: PJM Interconnection, LLC)

Clearing prices in the MAAC, ATSI, and PSEG Locational Deliverability Areas (LDA) were higher than in the balance of the RTO due to transmission constraints. Prices for ATSI dropped 68% from last year’s auction, however, due in part to planned transmission improvements to address reliability violations resulting from announced plant retirements.

Historical Role of RPM

PJM credited the Reliability Pricing Model with adding or preserving more than 58,000 MW of capacity in its 10 years of existence.

PJM has added 23,342 MW in installed capacity (ICAP) over that period, including a net increase of 7,858 MW in generation (28,178 MW in new generation, upgrades and reactivations less 20,319 MW in retirements) and 15,483 MW in demand response and energy efficiency.

Over the same period, PJM has gone from a net capacity export of 2,616 MW to net importer of 7,193 MW, a change of 9,809 MW. Canceled plant retirements also contributed 4,640 MW of capacity.

Impact of Environmental Regulations

The 2016/2017 planning year will be subject to the EPA Mercury and Air Toxics Standards (MATS), which are scheduled to take effect in 2015 with a possible one-year compliance extension to April 16, 2016. It also will be subject to the New Jersey High Electricity Demand Day (HEDD) rule, which sets NOx emission rates on intermediate and peaking units effective May 1, 2015.

May 21, 2013

FERC Orders Rules on Geomagnetic Disturbances

The electric transmission system needs more protections against geomagnetic disturbances like the 1989 solar storm that caused the collapse of the Hydro-Quebec grid, the Federal Energy Regulatory Commission said last week.

In its Final Rule on a Notice of Proposed Rulemaking issued last October (RM12-22), the commission ordered the North American Electric Reliability Corp. (NERC) to issue standards to close the “reliability gap” regarding geomagnetic disturbances (GMDs) caused by solar events.

1989 Solar Storm (Source: Metatech Corp.)

GMDs caused by solar events can cause distortions in the earth’s magnetic field, affecting the operations of pipelines and communications systems as well as electric power systems. Geomagnetically induced currents (GICs) can enter the transmission system, flowing through transformers and transmission lines and leading to increased reactive power consumption and disruptive harmonics that can cause system collapse.

The commission ordered NERC to propose reliability standards in two stages. Stage one standards will mandate operational procedures to mitigate the effect of GMDs. PJM already has GMD operational procedures in place (see below).

A Sense of Urgency

The stage one standards must be submitted for FERC review within about eight months (six months from the effective date of the order, which takes effect 60 days after publication in the Federal Register).

The short deadline underscores the urgency regulators place on preparing for GMDs. The current 11-year solar activity cycle is expected to hit its maximum activity in June. Large solar events often occur within four years of such a cycle maximum, panelists told FERC at a technical conference last year.

In stage two, due within 18 months, NERC must determine what severity GMD will constitute a “benchmark” GMD event. Transmission and generator owners and operators will be required to assess the potential impact of such benchmark events on their equipment and systems.

100-year solar storm: Areas of probable power system collapse; green = transformers; red = population centers. (Source: Oak Ridge National Laboratory)

The severity of GMDs are affected by variables including the strength of the solar event; geology, which affects ground conductivity, and the orientation and length of the transmission lines. If a responsible entity finds no potential GMD impacts in its vulnerability assessment, no additional plan is required.

Entities that are vulnerable will be required to implement protections against “instability, uncontrolled separation, or cascading failures” from such events. Such plans cannot be limited to operational procedures or enhanced training, FERC said.

“These strategies could, for example, include automatically blocking geomagnetically induced currents from entering the Bulk-Power System, instituting specification requirements for new equipment, inventory management, isolating certain equipment that is not cost effective to retrofit, or a combination thereof,” FERC wrote. The commission said it was not ordering NERC to require the use of automatic blocking devices or any specific technology.

Disagreement over Worst-Case Scenario

FERC acknowledged it was acting despite a lack of consensus on the severity of the threat. Some comments on the NOPR supported NERC’s 2012 interim GMD report, which predicted that the worst-case GMD scenario is “voltage instability and subsequent voltage collapse.” Others took side with reports issued in 2010 by the Oak Ridge National Laboratory, which concluded that a severe GMD event could damage or destroy transformers.

FERC said the rule “is warranted by even the lesser consequence of a projected widespread blackout without long-term, significant damage to the Bulk-Power System.”

Damaged Transformer at Salem Nuclear Plant, 1989 (Source: Oak Ridge National Laboratory)

The National Academy of Sciences estimated in 2008 that the most extreme solar event could cost more than $1 trillion and require four to 10 years to recover, while the cost of installing protective equipment was estimated at less than 20 cents per year for an average residential customer.

Oak Ridge’s simulation of a 1 in 100-year geomagnetic storm centered over southern Canada predicted that more than 300 EHV transformers would fail or suffer permanent damage, leading to the collapse of the grids serving 130 million people in the Northeast, Mid-Atlantic and Pacific Northwest.

The 1989 incident started shortly before 3 a.m. EST on March 13, when a large impulse in the geomagnetic field was detected near the U.S.-Canada border. That started a series of disturbances that brought down the grid serving Montreal and the rest of Quebec province within about 90 seconds.

The storm also caused large disturbances in the U.S., damaging some transformers severely — including one at the Salem nuclear plant in New Jersey — and nearly knocking out PJM and transmission systems from New England to the Midwest.

PJM Operating Plans in Place

PJM’s operating plans for dealing with GMDs are detailed in section 3.7 of Manual 13. The plan calls for PJM to notify generation and transmission members via the PJM All-Call system and Emergency Procedure posting application when the National Oceanic and Atmospheric Administration (NOAA) issues an alert for a potential GMD with a ranking of 5 or greater on the 9-point “K-index.”

Once a GMD has been confirmed, PJM dispatchers must operate the system under GMD transfer limits determined from studies that modeled several scenarios, including: loss of the Hydro-Quebec Phase 2 DC line to Sandy Pond; tripping of certain extra high voltage capacitors, and reduction or loss of generation at Artificial Island, the site of the Salem and Hope Creek nuclear plants in New Jersey.

No Guarantees

In its comments in response to the NOPR, PJM said there “is no question that severe space weather has the potential to create serious problems for the Bulk-Power System.” However, PJM and other commenters also asked FERC to clarify that reliability standards cannot eliminate all risks.

The commission agreed: “Given that the scientific understanding of GMDs is still evolving, we recognize that Reliability Standards cannot be expected to protect against all GMD-induced outages.”

May 21, 2013

Public Interest Orgs. Scold, Praise PJM

By Rich Heidorn Jr.

WHITE SULPHUR SPRINGS, WV — Public interest groups Tuesday scolded PJM for excluding them from the MOPR stakeholder process and for setting its annual meeting at the exclusive Greenbrier resort here.

At their annual meeting with the PJM Board of Managers, the public interest groups and state regulators also praised PJM for its handling of generation retirements and lobbied it to increase use of demand response and energy efficiency.

The meeting included about a dozen representatives from state consumer advocate offices and regulatory commissions as well as several environmental organizations. Others listened via phone.

Robert Mork, attorney in the Indiana Office of Utility Consumer Counselor, said he was able to attend the meeting thanks to funding from the newly formed Consumer Advocates of PJM States (CAPS) because there was no state funding available. He said the location of the event also created image problems for state officials like him.

While he said the setting “probably isn’t extravagant by private industry standards,” he said the cost and reputation of the Greenbrier — which advertises itself as “one of the finest luxury resorts in the world” — made it difficult for consumer advocates to get approvals to attend.

Rooms at the hotel cost $315 a night at PJM’s discounted rate. A take-out sandwich set you back $12.

“At the Table”

“I think any concept of RTO inclusiveness needs to have people like us at the table,” Mork said, asking the RTO to consider a less expensive, more accessible location for future meetings.

Board Chairman Howard Schneider told the organizations that the annual meeting with them is important to the board. “Anything we can do to make your job easier, we’re certainly open to suggestions.”

Asked after the meeting whether he had a comment on the criticism of the meeting location, however, Schneider said simply, “no comment.” Would the board discuss the matter later? “I said: `no comment,’” he repeated.

Asked for his response, board member John McNeely Foster reacted like he had been tossed a live grenade: “Nah, I don’t have a comment, sorry.”

Board Member Jean Kinsey was more expansive: “I could have been sympathetic to their plight, but it is what it is,” she said. “Everybody is cost-conscious. But they have smaller resources. I applaud them for doing what they can to get here.”

Room for 500

PJM CEO Terry Boston said PJM staff “will take [the criticism] into consideration for future meetings.”

“There’s very few places in our footprint that can handle our size,” he added, noting that 480 attendees registered.

Actually, there are more than 50 facilities in the PJM territory with facilities to host 500 people, according to the Cvent Supplier Network, which has an online database. But few of them have a noted golf course like the Greenbrier’s Jack Nicklaus-designed links –- a big draw for the mostly-male attendees at an event that is at least as much social as substantive.

The locations for the next two annual meetings are already set: next year at the Hyatt Regency in Cambridge, Md., and 2015 at for the Borgati Hotel Casino and Spa in Atlantic City.

Boston added that staff got an “attractive price” for the Greenbrier conference space with a multi-year contract for this year’s event and the one in 2010. He noted that the leisure activities — including free spa treatments and golf — were paid for by sponsors.

The state officials, not allowed to participate in the free activities, were offered a training session Wednesday afternoon instead. Most of them stayed in cheaper lodging off of the resort’s gated grounds.

MOPR Still Rankles

PJM also came under criticism for the stakeholder process that resulted in changes to its minimum offer price rule (MOPR), a tool for preventing buyer-side market power in PJM’s capacity market auctions.

Consumer advocates and state regulators were outraged when they learned last September that PJM and the market monitor had participated in confidential settlement negotiations among seven generating companies and five load-serving entities over more than two months. The resulting settlement won an 89% sector-weighted vote.

On May 2, the Federal Energy Regulatory Commission issued a split decision on the changes, allowing the RTO to exempt two categories of resources but denying its request to eliminate its current unit-specific review. FERC rejected state officials’ complaints that the process violated PJM’s Code of Conduct. (See “FERC Upholds PJM Exemptions; Rejects End to Unit-Specific Review.”)

“We felt that the stakeholder discussions were not adequate,” said Bill Fields, an attorney in the Maryland Office of People’s Counsel. “It creates at least an appearance of a lack of independence to announce simultaneously that PJM has a concern about an issue and that a proposed solution to that problem has been agreed to by a group of stakeholders.”

Praise for Staff

The groups praised PJM’s staff for its professionalism and expressed relief that the board had agreed to seek a new three-year contract with Independent Market Monitor Joseph Bowring and his firm Monitoring Analytics.

Attorney Will Burns, who represents environmental groups, praised PJM’s transmission planners for their “herculean job of dealing with a lot of retirements dumped on them all at once.” He also gave PJM credit for its implementation of FERC Order 745 on compensation for demand response and increasing the cap for demand response’s share of the synchronized reserve market from 25% to 33%.

“Thanking PJM is really unlike us,” he said, drawing laughter — a rare light moment in the cordial but tense meeting.

Relief over Market Monitor Contract Extension

The meeting would have been far more contentious had the board not backed off from its original plan to open the monitoring role to competitors.

The board announced last month it was negotiating a new contract with the market monitor and dropping plans to put the contract out for bid. The board acted after receiving letters of protest from state regulators, industrial consumers and cooperatives, who said the draft request for proposals contained terms that would undermine the independence and quality of the monitoring function. (See “PJM Working on New Deal with Monitor; Backs Down on RFP.”)

“If [a new contract] comes to fruition it will ensure the continued well functioning of the PJM markets,” said Dave Evrard, an attorney in the Pennsylvania Office of Consumer Advocate.

Jackie Roberts, Deputy Consumer Advocate for the West Virginia Public Service Commission, said she was relieved that PJM would not repeat the turmoil of 2007, when Bowring accused PJM’s then-president of attempting to muzzle him by squelching his reports and cutting his budget.

“It was a very difficult time for all of us,” Roberts said. “I think I did a happy dance when I heard [about the board’s decision to extend the contract]. I think we may have avoided some uncertainty in bringing in a new market monitor.”

Environmental Groups Lobby for DR and EE

Environmental groups in attendance pressed their case for energy efficiency and demand response as alternatives to new transmission and generation.

“We believe PJM has an affirmative obligation to identify and evaluate non-transmission alternatives under the Federal Power Act,” said John Moore, senior attorney for the Natural Resources Defense Council’s Sustainable FERC Project.

The Regional Transmission Expansion Plan (RTEP) doesn’t “capture fully all the locational benefits” of non-transmission alternatives, Moore said. “We think waiting for developers to propose these solutions is insufficient.”

Moore said PJM’s requirement that generators provide 90-days notice of plant retirements is too short for energy efficiency and demand response providers to offer alternatives to new transmission lines.

Debate over DR “Saturation”

Environmentalists also said PJM was premature in worrying about the potential for demand response “saturation” – the fear that DR providers will reduce participation as their resources are called on more often.

“We shouldn’t assume there’s a problem until we see some more evidence of it,” said attorney Will Burns.

Board members Sarah Rogers and Ake Almgren insisted their concerns were well founded. “Subscription to DR can fall off and fall off very rapidly,” Rogers said.

Boston said he had seen DR participation decline in Florida. “We found that DR did not stay with us during the boom times” when it was called on more, he said.

Stephen Whitley, president and CEO of the New York ISO, provided his own testimonial in a speech to the Members Committee Thursday. Whitley said New York has lost some of its demand response since calling on those resources five times last year. “After the fifth time, I got a lot of phone calls from DR participants asking, `What’s going on?’ So that’s a big concern to me.”

May 21, 2013

PJM Year in Review: Storm Recovery, Lower Prices, Continued Growth

Storms provided challenges, but a bounty of cheap natural gas brought consumers lower prices in 2012, PJM officials said in their Year in Review presentations at the annual meeting.

“The weather was relentless, but PJM and its members rose to the occasion,” said CEO Terry Boston.

The June 29 derecho, a 600-mile series of storms, took out 90 high voltage and extra high voltage transmission lines, leaving 4.2 million customers without electricity.

Hurricane Sandy, Oct. 29, was even more damaging, causing 40 generators to trip and knocking out 142 transmission lines and interrupting service for 5 million. “The system is rated for N-1,” said Boston. “We ended up with N-142 elements out on the transmission system.”

Load in the MidAtlantic dropped to 15,000 MW, 6,000 MW below normal. In 25 years at PJM, said PJM Senior Vice President of Operations Michael Kormos, it was the first time he ever saw power flowing west to east over PJM’s high voltage lines.

The good news? “We’re much better at emergency planning than we were before the storm,” Boston said. “Drills are one thing. Actually doing it is something else.”

Prices, Emissions Lower from Cheap Gas

The PJM markets, meanwhile, were driven by the natural gas’s increasing market share.

Gas rose to nearly 20% of the fuel mix for electricity production, while coal dropped to 42%. The shift helped reduce PJM’s CO₂, SO₂ and NOX emissions per MWh to new lows.

PJM membership rose to a record 797 as of Dec. 31, 2012, up from 738 the year before. But PJM Market settlements volume dropped to $29.18 billion in 2012 from a record $35.89 billion in 2011 as the average wholesale cost dropped to about $48/MWh from almost $63.

“Is that sustainable?” Andy Ott, Senior Vice President of Markets asked. “I leave that to you.”

emissions-per-MWh — Source: PJM Interconnection, LLC

Market Monitor Joseph Bowring gave his answer in his own presentation, noting that power prices rose 20% in the first quarter of 2013 versus the same period in 2012, pushed by increasing gas costs.

May 21, 2013

PJM Keynotes: Humility, Efficiency Needed for Fracking’s Future

WHITE SULPHUR SPRINGS, WV — Natural gas’ growing role in electric generation was a recurrent theme at PJM’s annual meeting last week, with author Michael Levi warning that overconfidence could threaten the fracking boom and gas executive Steven L. Mueller calling for increased efficiency to protect the “national treasure” in U.S. gas

“If we don’t set our standards high enough we could have more than a few high profile accidents … that could put a lot of land off limits” to drilling, said Levi, director of the Council on Foreign Relations’ Program on Energy Security and Climate Change, and author of the forthcoming book “The Power Surge: Energy, Opportunity, and the Battle for America’s Future.” “There’s a bit too much certainty in a lot of the messages we hear and not enough humility,” Levi said. “And people don’t buy that.” In his own speech, Mueller, president and CEO of Southwestern Energy Co., conceded: “I can’t tell you [U.S. producers will] never have a problem drilling 12,000 wells a year.” But he said his company, one of the largest North American natural gas producers, is “doing to everything we can not to screw it up.”

“Unsustainable” Practices

Mueller said that the fracking boom will be “unsustainable” unless drillers find ways of decreasing their water use. He noted that drillers currently require 900 truck trips per well, including deliveries of equipment and supplies. About 400 of the trips are deliveries of water. “The constraint becomes the roads you have,” he said. Mueller said drillers also will increase their productivity, predicting that unconventional wells — which now collect about 30% of the gas present — will increase their yield to 70% to 80% within three decades. “Today if you can’t get 80-90% from a conventional well you’re not doing it right.”

Another challenge, Mueller said, is finding enough pipeline and storage capacity to ensure adequate supplies of gas to meet both heating and electric loads. “We need to continue building our pipeline infrastructure out. We’re about two-thirds of the way there. We need to build overcapacity; if we have overcapacity, we’ll have that storage.” Levi said he did not expect the federal government to limit natural gas exports because exports won’t cause a significant price rise for most energy and chemical companies. “The place that really gets hurts by exports is fertilizer” companies, he said.

Solar to Challenge Utility Model

Turning to the electric industry, Levi predicted distributed solar generation will grow and present “some tough challenges for the traditional utility model.” What’s the next big thing in energy? Batteries, said Levi. “If you wanted a sort of killer app in the energy world that cuts across all areas like fracking — it’s storage,” he said. “There’s some real breakthrough chemistry that can still happen.”

May 21, 2013

Members Committee Approvals

The Members Committee approved the following changes by acclimation last week:

System Restoration Strategy

The committee approved updates to the system restoration strategy, including updates to cost allocation.

Reason for Change: The System Restoration Strategy Task Force has been researching ways to ensure sufficient black start capability. Environmental regulations, NERC reliability standards and the increasing cost of black start generation raised reliability concerns.

Impact: Deletes references to transmission owner. Adds conditions for involuntary termination of black start service. Adds reference to performance capabilities in PJM manuals; deletes reference to 90-minute response time. Adds cost allocation provision for black start units designated to serve multiple zones.

Provision of E-Tag Data

The committee approved revisions to the confidentiality provisions of its tariff to comply with FERC Order 771, requiring provision of e-Tag data to Independent System Operators, Market Monitoring Units and FERC. The new language extends confidentiality protections to counterparties that are not PJM members.

Up-To Congestion Transactions – Trading Limits

The committee approved volume limitations for up-to congestion transactions.

Reason for Change: PJM proposed the cap because high bid volumes can make it difficult for the RTO’s day-ahead markets software to reach solutions.

Impact: PJM can limit market participants to no more than 3,000 UTC transactions each in the day-ahead market when necessary for market operations. (A similar cap also applies to increment offers and decrement bids.) The definition of market participant includes all sub-accounts established under the member. Affiliates will be treated as separate participants and have their bids counted individually. The cap includes changes to the tariff, Operating Agreement and Manual 11.

Up-To Congestion Transactions – FTR forfeiture rules

Reason for Change: The rule is intended to prevent market manipulation — in this case, the submission of UTCs that boost the value of a participant’s FTRs.

Impact: The rule is applied when those UTCs result in a higher LMP spread in the day-ahead market than in the real-time market.

PJM Settlement Reconciliations

The committee approved revisions to Schedule 9-PJMSettlement of the Open Access Transmission Tariff to adjust the quarterly rate for the cumulative over or under collection of Schedule 9-PJMSettlement funds.

Reason for Change: Section c of Schedule 9 requires the quarterly 9-PJMSettement rate be adjusted for prior quarter revenues in excess of expenses. The formula does not provide for a reconciliation of prior period balances.

Impact: Section c is revised to adjust the quarterly rate for the cumulative over or under collection of Schedule 9-PJMSettlement funds relative to cumulative costs.

May 21, 2013

Tx Planning Standard OK’d on Second Try

The Federal Energy Regulatory Commission last week approved a revised transmission planning reliability standard it had previously rejected as “vague and unenforceable.”

The North American Electric Reliability Corp.’s proposed reliability standard TPL-001-2 would have allowed transmission planners to plan for non-consequential load loss following a single contingency as long as the plan was the result of an open and transparent stakeholder process.

The commission said the revised standard TPL-001-4 will improve reliability “by providing a blend of specific quantitative and qualitative parameters for the permissible use of planned non-consequential load loss to address bulk electric system performance issues.” The commission said the new rule defines the stakeholder process and criteria that must be followed and includes safeguards, including a review process to ensure the procedure does not hurt reliability.

The commission’s approval, a Notice of Proposed Rulemaking, will be open for 30 days after its publication in the Federal Register. In a concurring statement, Commissioner John R. Norris praised the rule for balancing the need to protect system reliability and minimize costs.

“NERC’s proposal goes a long way towards empowering local communities to consider the economic tradeoffs between incurring costs to avoid shedding firm load versus planning to shed firm load, while still ensuring that the decision-making process is more open and transparent and building in a safeguard for NERC to review decisions for possible adverse reliability impacts,” Norris said.

May 16, 2013

PJM Chooses Continuity over New Voices for Board – UPDATE

By Rich Heidorn Jr.

WHITE SULPHUR SPRINGS, WV – “I don’t want to put the board on the spot,” said Robert Mork, doing just that at the PJM Board of Managers annual meeting with public interest groups and state regulators Tuesday. “But I think it’s the case that none of you have worked in a consumer advocate’s office or served on a state commission.”

There was an awkward silence in the wood-paneled Eisenhower conference room at the opulent but mostly empty Greenbrier resort here. No one corrected Mork, an attorney in the Indiana Office of Utility Consumer Counselor.

Would the 10-member PJM benefit from the presence of at least one board member with a state ratemaking perspective? It will have to wait at least another year to find out.

The PJM Members Committee this morning approved the re-election of three long-serving members to the PJM Board of Managers: Jean Kinsey, William Mayben and Richard Lahey. Given the absence of any other candidates, reelection was all but certain.

Kinsey, a Ph.D. economist, has served on the board since 2003. She is a Professor Emeritus in the Department of Applied Economics at the University of Minnesota and an expert on food consumption trends, obesity issues, consumer buying behavior, and food industry organization.

Lahey, who has a Ph.D. in mechanical engineering, is an expert on nuclear reactor safety technology, power engineering, and the use of advanced technology in industrial applications. A Professor Emeritus at the Rensselaer Polytechnic Institute, he has served since PJM’s independent board was created in 1997.

Mayben, who joined the board in 2007, worked as a management consultant serving utilities and is former president and CEO of the Nebraska Public Power District. He holds a B.S. in electrical engineering.

The three were selected for new three-year terms by the nominating committee, comprised of Board Chair Howard Schneider; also a member of the original board; board members John McNeely Foster and Susan Riley, and five PJM members. The members represent the Electric Distributor, Generation Owner, Other Supplier, End Use Customer and Transmission Owner sectors.

Lahey and Mayben, who both serve on the board’s reliability committee, told PJM Insider that maintaining the security of the PJM grid against physical and cyber attacks would be among their priorities in their next terms.

“I’m concerned about people getting into our system,” said Mayben, who is also on board’s audit committee.

Lahey also is a member of the human resources and finance committees. He said had he had no specific goals. “It’s hard to predict the future,” he said. “At every meeting there’s some new challenges.”

Kinsey is a member of the competitive markets and audits committees.

She declined to comment on her pending election Wednesday. “I think they [members] know what I’m doing and what I will be doing,” she said.

May 13, 2013

No Changes for Wind BOR, Forecasting Costs

PJM will continue its current methods for calculating wind farms’ operating reserve charges and allocating costs of its wind forecasting tool.

The Intermittent Resources Task Force concluded a six-month review last month without reaching consensus on any proposed changes to the current methods.

The task force’s 2008 charter included an assignment to “recommend methodology for allocating wind production forecasting costs, and potential changes to how operating reserve charges are applied to intermittent resources.”

Balancing Operating Reserves (BOR) are calculated for wind resources the same as for non-intermittent resources: Resources can earn reserve credits by following dispatch instructions; those that fail to do so are ineligible to earn credits and are charged for deviations.

PJM’s wind power forecasting tool, used to ensure scheduling of sufficient generation in the day-ahead market, costs $135,600 annually. The cost is allocated RTO-wide, based on transmission use, through PJM’s monthly Schedule 9-1 charges.

“We wouldn’t have a need for this tool but for the wind technology and the issues it creates for the rest of the system,” said one member in a Market Implementation Committee discussion of the task force’s findings last week.

The task force concluded, however, that because accurate forecasts improve system reliability, the costs should continue to be spread among all market participants. A proposal to assess the costs solely to wind projects, with offsets in operating reserve charges, won support of only 10% of the task force.

Another member noted that the RTO-wide cost allocation is consistent with how PJM pays for its hydropower scheduling software.

Editor’s Note: PJM Insider is withholding the names and organizations of the speakers in accordance with the PJM Code of Conduct (Section 4.5 of Manual 34). The code prohibits quoting members by name or organization without their approval for all meetings other than those of the Markets and Reliability and Members committees.