PJM will seek stakeholder approval this month for contingency plans to respond to an Internet outage that forces the RTO to suspend the day-ahead market.
PJM has no procedures for dealing with an Internet outage that could prevent the RTO from receiving participant data needed to solve the day-ahead market. Under the proposed tariff changes outlined to the Markets and Reliability Committee Thursday, all market settlements would be done in real time.
The procedure requires changes to sections 1.10.8 and 1.10.9 of the Open Access Transmission Tariff, including clarification that the rebid period will be from 4 p.m. to 6 p.m. but may be revised by PJM if the clearing of the day-ahead energy market is significantly delayed.
Below is a summary of problem statements and manual, Operating Agreement and Tariff changes approved by the Markets and Reliability Committee Thursday, May 30, 2013.
PMU Deployment
The committee endorsed manual revisions requiring new generators to pay for the installation of phasor measurement units (PMUs). There were four no votes and three abstentions. The Planning Committee approved the changes March 7, rejecting an alternate proposal to have PJM cover the cost.
Reason for change: PMU data can enhance grid reliability for both real-time operations and planning applications (e.g., generation dynamic model calibration and validation, primary frequency response, oscillation monitoring and detection). PJM expects to receive PMU data from 82 substations by the end of 2013 but has none located at generation stations.
Impact: The Interconnection Service Agreement will be changed to require installation of PMUs at new interconnections for generators with nameplate ratings of 100MVA or larger. Data collected by the PMU must be transmitted to PJM continuously and stored locally for 30 days.
Commodity Futures Trading Commission Exemption Order
MRC and the Members Committee approved changes to the Operating Agreement and Tariff to comply with conditions in the Commodity Futures Trading Commission order exempting most PJM market participants from CFTC jurisdiction.
Reason for Change: The CFTC agreed March 28 to largely exempt from its regulations Financial Transmission Rights, day ahead and real time energy transactions, forward capacity transactions and reserve regulation transactions, sales that are already regulated by the Federal Energy Regulatory Commission.
However, the CFTC said the exemption did not apply to financial market participants that cannot qualify as “appropriate persons” under the Commodity Exchange Act (CEA). PJM responded April 7 by announcing it may deny trading privileges to small market participants if they are unable to qualify for the exemption.
Impact: The changes approved Thursday expand financial marketers’ officer certification requirements. Although the changes require FERC approval, PJM CFO Suzanne Daugherty said her staff will immediately begin contacting about 100 market participants for whom the RTO does not have sufficient financial information.
The MRC was asked to choose between two options regarding the financial qualifications of an unlimited guarantor.
Stephanie Staska, of Twin Cities Power LLC, proposed language requiring “an issuer that has at least $1 million of total net worth or $5 million of total assets per Participant for which the issuer has issued an unlimited Corporate Guaranty.”
PJM proposed that the guarantor be “an issuer that would qualify for an Unsecured Credit Allowance of at least $1 million.”
Daugherty said the Twin Cities language complied with the CFTC order but was “just a little less thorough” than PJM’s proposal.
Staska said her proposal was identical to that used by MISO for compliance with FERC order 741. “It “does just as much to protect the market,” she said.
The changes were approved with the Twin Cities language with no objections and three abstentions.
MRC and the Members Committee endorsed credit requirements for up-to-congestion (UTC) trades, a fast-growing virtual transaction that previously had no credit requirements.
Reason for Change: UTC trading volumes have grown dramatically since 2010 but there are no credit requirements to protect market participants against defaults.
Impact: Bid screen and cleared portfolio credit requirements are based on a percentile of the difference between each member’s bid or cleared price and the two-month rolling average of real-time value per path.
Traders who fail the credit screen based on their initial bids will be able to rebid within their limits.
MRC approved a manual change documenting the Market Monitor’s current application of the FTR forfeiture rule on increment and decrement transactions and a problem statement to determine how the rule should be interpreted in the future.
Reason for Change: PJM discovered only recently that it disagreed with the criteria by which the monitor has been determining whether a company’s virtual bid is “at or near” the delivery or receipt buses of its FTR.
Impact: The manual change documents the monitor’s interpretation of the rule. The inquiry may result in changes to the application of the rule.
The monitor has been applying the penalty based on the net impact of virtual bids, triggering its application in less than one-tenth of 1% of trades. PJM proposed a different calculation under which companies would lose any profit for an FTR if 75% or more of the energy injected or withdrawn by a virtual bid is reflected in a constrained path between FTR source and sink.
“We believe this is about as clear as we can make it,” Stu Bresler, PJM vice president of market operations, said of the manual change.
The problem statement was approved over the objections of 15 members of the PJM Public Power Coalition.
“There are at least five new problem statements on this week’s agenda,” said Bill Schofield, of Customized Energy Solutions, which represents the coalition. “This is not the time to be adding this to our plate.”
But representatives of financial marketers said revising the rule was important to them.
“Because of the heightened risk in terms of FERC enforcement action … I think it’s important that we get some clarity on how we analyze these power flows,” said Greg Pakela of DTE Energy Trading. “This kind of acts as a safe harbor.”
FTRs are “a fundamental building block to the forward price curve,” said Bruce Bleiweis, of DC Energy, LLC. “Many people would like some additional clarity here.”
Market Monitor Joseph Bowring also supported the review, noting that the rule has been unchanged since 2001. “Are we getting false positives or false negatives?” he asked. “We need to make sure everyone understands the rule. I think there’s a lot of misunderstanding.”
MRC approved a problem statement creating a senior task force to take a broad review of its method of providing Operating Reserve payments.
Reason for Change: PJM said changes are needed to reduce growing uplift costs. Operating Reserves are “make whole” payments that ensure generators dispatched out of merit for system reliability don’t operate at a loss. Because they are collected through uplift charges and not reflected in day-ahead or real-time locational marginal prices, they cannot be hedged.
Impact: The task force will consider revising the sources of Operating Reserve charges and the methodology used to allocate them. The goal will be to minimize uplift costs while ensuring market prices are consistent with operational reliability, decrease charge rates, and reduce transaction risk due to variable fees.
With its reliance on demand response and heavy concentration in PJM, EnerNOC has seen its fortunes wax and wane based on decisions made in Valley Forge and Washington. The company cited the following examples in its 10-K disclosures to shareholders:
The company saw its DR revenues fall in 2011 versus 2010 due in part to lower prices in the PJM, New York and New England markets and fewer demand response events in PJM during the year, which cut energy payments.
The Federal Energy Regulatory Commission’s February 2012 order accepting a PJM proposal on measuring and verifying DR capacity hurt the company’s revenues and profit margins.
PJM’s elimination of its Interruptible Load for Reliability (ILR) program last June “reduced the flexibility that we had to manage our portfolio of demand response capacity in the PJM market and impacted our revenues and profit margins.”
Declining PJM capacity market prices hurt revenues, gross profits and profit margins in 2012. “To the extent we are subject to other similar price reductions in the future, our revenues, gross profits and profit margins could be further negatively impacted.”
PJM system operators took over management of the East Kentucky Power Cooperative system at midnight Saturday, adding almost 3,100 MW of generation and 2,800 miles of transmission to the RTO.
While PJM is a summer-peaking system, EKPC’s demand peaks in the winter. “The diversity of demand between EKPC and other PJM members and the resources they bring will strengthen reliability and have economic benefits not only for EKPC but throughout the region we serve,” said PJM President and CEO Terry Boston.
East Kentucky, which joined PJM as an Other Supplier in 2005, estimates it will save almost $132 million over the next decade by taking advantage of PJM’s economies of scale and generation diversity.
“Our organizations have put a lot of hard work into this integration,” EKPC CEO Anthony “Tony” Campbell said in a statement. “This move will help EKPC to operate more efficiently and economically.”
The biggest savings will come from reduced reserve requirements. East Kentucky maintains a 12% reserve margin. By joining the summer-peaking PJM, it will be able to reduce its reserve to 2.8%, allowing it to sell the difference in the capacity market. The integration also will result in more economical generation dispatch, as the coop replaces its higher cost generation with cheaper PJM power.
East Kentucky said its move was prompted by increasing transmission constraints with potential counterparties and federal environmental regulations, which made it expensive to continue operating as an independent control area and balancing authority. The coop has interconnections with TVA, Duke Energy, American Electric Power and Louisville Gas and Electric Co./Kentucky Utilities Co.
EKPC is owned by 16 distribution cooperatives that serve 1.1 million people in 87 counties across Kentucky.
But last week, PJM’s Senior Vice President for markets and the Independent Market Monitor said there’s at least one thing on which they agree: the MOPR unit-specific review process is “flawed, non-transparent and provide[s] too much discretion to PJM and the IMM.”
The Markets and Reliability Committee approved a problem statement Thursday to standardize and improve the transparency of the unit-specific review process used in applying the Minimum Offer Price Rule (MOPR).
PJM and the monitor wanted to do away with the unit-specific MOPR exemptions in favor of blanket exemptions for winners of competitive solicitations and self-supply resources.
But the Federal Energy Regulatory Commission ruled May 2 (ER13-535) that eliminating the review for generators that don’t meet the exemptions was not just and reasonable. Instead, FERC suggested that PJM conduct a stakeholder process to consider revisions to the process. (See “Split Decision on MOPR.”)
MOPR was added to PJM’s capacity market rules in 2006 to prevent buyer-side market power.
The problem statement and issue charge approved by MRC seeks to develop new financial modeling assumptions, with a goal of standardizing them and making them more consistent with those used to establish Net CONE (cost of new entry). Among the issues to be considered are asset life and calculations of net revenue and cost of capital.
The project, to be assigned to the Capacity Senior Task Force, is scheduled for completion in time for a December 1 FERC filing and implementation in the 2014/15 delivery year.
Compliance Filing
Ott also briefed the MRC on a compliance filing the RTO must make in response to the FERC order.
PJM’s response, filed yesterday:
allows MOPR exemptions for qualifying facilities under contract to capacity market sellers;
pledges to review the net short and net long thresholds for the self-supply exemption every four years; and
defines “repowering” to clarify that it includes both projects that increase capacity and those that don’t. PJM had proposed that repowered gas generators be treated as a new resource under MOPR.
Also yesterday, Calpine Corp., FirstEnergy Corp. and NRG Energy Inc. filed requests asking FERC to reconsider its ruling, joining a rehearing request filed last week by the Illinois Commerce Commission.
The Illinois filing alleges FERC erred in allowing PJM to subject integrated gasification combined cycle (IGCC) generators to MOPR.
Calpine Corp said FERC was mistaken in requiring PJM to retain the unit-specific review. The commission “neglected to address the fact that the MOPR modifications set forth in the December 7 Filing were proposed as a package that was overwhelmingly approved by stakeholders and that reflected significant compromises on the part of Calpine and other parties,” Calpine said.
FirstEnergy said the self-supply exemption is based on PJM’s analysis of the 2015/2016 auction, which it said is not representative of current market conditions. The company said FERC should address the potential that the exemption could be gamed.
NRG said the commission had abandoned its long-standing “regulatory compact” with investors. “The MOPR Order cuts the legs out from under the buyer-side power mitigation rules by selectively approving the elements of the PJM proposal that would weaken the MOPR, while rejecting those elements that would strengthen the buyer-side market power protections,” the company said.
erators to pay for the installation of phasor measurement units (PMUs).
The Planning Committee approved the changes March 7, rejecting an alternate proposal to have PJM cover the cost. PMU data can enhance grid reliability for both real-time operations and planning applications.
Planning Committee Votes to Bill Generators for PMUs
3. Commodity Futures Trading Commission (CFTC) Exemption Order (9:25-9:55)
The committee will be asked to endorse the changes to the Operating Agreement and Tariff to comply with conditions in the Commodity Futures Trading Commission order exempting most PJM market participants from CFTC jurisdiction.
The CFTC agreed March 28 to largely exempt from its regulations Financial Transmission Rights, day ahead and real time energy transactions, forward capacity transactions and reserve regulation transactions, sales that are already regulated by the Federal Energy Regulatory Commission. However, the CFTC said the exemption did not apply to financial market participants that cannot qualify as “appropriate persons” under the Commodity Exchange Act (CEA). PJM responded April 7 by announcing it may deny trading privileges to as many as 55 small market participants if they are unable to qualify for the exemption. PJM said the change was necessary for the RTO to avoid being deemed a swap dealer and becoming subject to CFTC reporting requirements.
The changes being considered expand financial marketers’ officer certification requirements.
PJM Delays Action on CFTC Order
CFTC Approves Dodd-Frank Exemption for RTOs
PJM May Bar Some Financial Players from Trading
4. Up-To Congestion (UTC) Transaction Credit Requirements (9:55-10:10)
The committee will be asked to endorse credit requirements for up-to-congestion (UTC) transactions.
UTC trading volumes have grown dramatically since 2010 but there are no credit requirements to protect market participants against defaults. Bid screen and cleared portfolio credit requirements are based on a percentile of the difference between each member’s bid or cleared price and the two-month rolling average of real-time value per path.
MIC OKs UTC Credit Requirement
5. PJM Manuals (10:10-10:30)
The committee will be asked to approve the following manual revisions:
A. Electronic Notifications for Curtailment Service Providers: Changes to Manuals 1 and 18 will implement an automated process that will allow Curtailment Service Providers to provide operational data to — and receive dispatch instructions from — PJM. The new Load Response System (eLRS) process replaces the current manual methods, which rely on email and spreadsheets.
Manual Changes to Implement Electronic Notification System
B. Residual Zone Pricing: Residual Zone Pricing will replace physical zone LMPs for real-time load effective June 1, 2015. A Residual Zone is an aggregate of all load buses in the physical zone, excluding load priced at nodal locations. The change was endorsed by the Members Committee in February 2012 and approved by FERC in Docket ER13-347.
Manual, Tariff Changes: Residual Zones, EKPC, Loss of Internet, Regulation Market
C. East Kentucky Power Cooperative: PJM needs to add the East Kentucky Power Cooperative zone into PJM markets manuals to accommodate the coop’s integration into PJM effective June 1.
Manual, Tariff Changes: Residual Zones, EKPC, Loss of Internet, Regulation Market
D. NERC Reliability Standards: PJM needs to amend M-36: System Restoration to reflect NERC Standards EOP-005-2 (System Restoration Plans) and EOP-006-2 (Reliability Coordination – System Restoration). Updates for consistency with other RTOs; updates underfrequency load shed tables; incorporates recommendations from RFC/SERC audit, and adds specific references to transmission operator restoration plans.
E. Manual 03A: Energy Management System (EMS) Model Updates and Quality Assurance:
The changes include numerous edits for updates and clarity.
Manual 03: Transmission Operations
F. Regulation Market Cost-Based Offers: New rules implemented in October require regulation offers to include capability (cost, in $/MWh to reserve a resource for regulation) and performance (costs of tracking the regulation signal in miles/MW). Previous rules, as defined in Manual 15, did not include performance costs.
Manual, Tariff Changes: Residual Zones, EKPC, Loss of Internet, Regulation Market
G. Manual 35: Definitions and Acronyms: Adds language to Economic Maximum and Economic Minimum definitions; changed Operations Analysis Working Group to Operations Assessment Working Group; Replaced TTV4TF (TO/TOP Version 4 Task Force) with TTMS (TO/TOP Matrix Subcommittee).
H. NERC standard PRC-023-2: Updates to Manual 14B: PJM Region Transmission Planning Process are required to implement standard PRC-023-2 (Transmission Relay Loadability). PJM annually develops transmission facility list to comply with NERC criteria.
I. Manual 03: Transmission Operations: Semi-annual update to incorporate procedural changes.
Recess (10:30-11:15)
The MRC will recess for a brief Members Committee meeting to finalize revisions to the OA and Tariff regarding the CFTC Exemption Order and the UTC credit requirements (#s 3 and 4 above).
6. FTR Forfeiture Rule Changes (11:15-11:30)
MRC will be asked to approve a manual change documenting the Market Monitor’s current application of the FTR forfeiture rule on increment and decrement transactions and a problem statement to determine how the rule should be interpreted in the future.
PJM discovered only recently that it disagreed with the criteria by which the monitor has been determining whether a company’s virtual bid is “at or near” the delivery or receipt buses of its FTR.
The monitor has been applying the penalty based on the net impact of virtual bids, triggering its application in less than one-tenth of 1% of trades. PJM proposed a different calculation under which companies would lose any profit for an FTR if 75% or more of the energy injected or withdrawn by a virtual bid is reflected in a constrained path between FTR source and sink.
Back to the Drawing Board on FTR Forfeitures For Incs, Decs
7. Energy Market Uplift Costs (11:30-11:45)
MRC will be asked to vote on a proposed problem statement that would create a senior task force to take a broad review of its method of providing Operating Reserve payments. PJM said changes are needed to reduce growing uplift costs.
Operating Reserves are “make whole” payments that ensure generators dispatched out of merit for system reliability don’t operate at a loss. Because they are collected through uplift charges and not reflected in day-ahead or real-time locational marginal prices, they cannot be hedged.
PJM Proposes Operating Reserve Changes to Cut Uplift
8. Minimum Offer Price Rule (MOPR) Compliance Filing (11:45-12:00)
PJM will provide a summary of PJM’s compliance filing in response to FERC’s May 2 order on the Minimum Offer Price Rule (ER13-535). FERC allowed PJM to exempt two categories of resources from MOPR but denied its request to eliminate its current unit-specific review.
Split Decision on MOPR
First Readings:
9. MOPR Unit Specific Exemption (12:45-1:00)
10. FTR Modeling Proposals (1:00-1:30)
11. Suspension of Day-Ahead Market for Loss of Internet (1:30-1:45)
12. Regional Planning Process Task Force (RPPTF) (1:45-2:15)
13. Demand Response Problem Statement (2:15-2:30)
14. Gas Electric Senior Task Force (GESTF) (2:30-2:45)
Two utilities last week signaled their intent to oppose a proposed “multi-driver” approach for incorporating public policy goals in PJM’s transmission planning process.
Representatives of Public Service Electric and Gas Co. and Rockland Electric Co. objected at a teleconference Wednesday of the Regional Planning Process Task Force when participants were asked if there were anyone who “couldn’t live with” the multi-driver proposal.
In a non-binding poll May 14, 112 of 128 task force participants (88%) said they favored the multi-driver approach, which would integrate public policy requirements into PJM’s existing reliability and market efficiency analyses for transmission improvements. 85% of those participating said public policy upgrades should be allocated only the incremental costs they add to an identified reliability or market efficiency project.
Because of the utilities’ objections Wednesday, the task force was not able to claim a Tier 1 consensus and will schedule a formal vote to determine its recommendation to the Markets and Reliability Committee. As a result, the issue will not go to a first reading in the MRC until at least June 27.
Order 1000 Compliance
To require public policy transmission improvements to be funded only as standalone projects would result in unnecessary expense, said Walter Hall, of the Maryland Public Service Commission. “If PJM doesn’t develop a rational approach [to public policy requirements] they will find themselves very quickly in violation of FERC [Order 1000] requirements,” he said. “… I really think we need more from these two objectors as to how to move forward.”
PSEG noted that FERC did not require PJM to incorporate the multi-driver approach.
In its Order 1000 compliance filing Oct. 25, PJM said it was committed to developing the multi-driver approach. The RTO said it may allow “greater flexibility in developing more efficient and cost-effective projects that could include a combination of public policy components and reliability and/or economic components.”
Some commenters told FERC that PJM’s filing was not compliant with Order 1000 without a multi-driver approach. AEP said PJM’s planning process does not credit proposals that more efficiently address multiple benefits because the planning process looks for solutions that solve individual needs. As a result, AEP said, projects that provide greater multi-driver benefits may be rejected in favor of a project that has a greater impact on only reliability.
FERC Won’t Force Multi-Driver
In its March 22 ruling on PJM’s compliance filing, FERC noted PJM’s commitment to developing the multi-driver approach and encouraged PJM and its stakeholders to “explore future enhancements to improve the regional transmission planning process.”
However, it ruled that the multi-driver approach was not required to meet Order 1000. “PJM has integrated consideration of transmission needs driven by public policy requirements into is transmission planning process by incorporating those needs into the sensitivity studies, modeling assumption variations and scenario planning analyses,” the commission wrote.
Benefit Determination,“Upgrade” Definition
The task force also received the results of a vote on how to determine benefits for regional market efficiency projects. 87% of respondents favored a proposal to calculate benefits on a 50/50 ratio based on its impact on production costs and net load payments (energy benefits) or impact on capacity costs and net capacity payments (capacity benefits). Only 29% favored continuing the current method, under which 70% of benefits are calculated based on production or capacity cost savings.
The task force also is developing a revised definition of transmission reliability “upgrades” in response to the March 22 FERC ruling. (See “PJM’s ‘To Do’ List.”)
Order 1000 reserved construction of transmission reliability upgrades — which it defined as including tower change outs and reconductoring — to incumbent utilities. The commission said PJM’s OATT and agreements contain references to several types of upgrades and it is unclear which PJM intends to include in the Order 1000 definition.
For combinations of new and existing transmission lines, PJM’s proposal would differentiate based on the following criteria:
For lines shorter than 20 miles, the entire project is an upgrade only if the new line segment is less than 50% of total transmission line length.
For lines 20 miles or longer the entire project is an upgrade if the new line segment is either less than 10 miles or less than 10% of the total transmission line length. For example, on an existing 120-mile line, an addition of 10.1 miles would be considered an upgrade because — although it is longer than 10 miles — it is less than 10% of the original length. An addition of 13 miles would be considered a new project because it is both longer than 10 miles and greater than 10% of the original length.
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.
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 (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.
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%.
(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.
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.”
