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Jul142014

ISO-NE and NEPOOL file proposal with FERC to implement a Winter Reliability Program for winter 2014/2015

On July 11, 2014, ISO New England and the New England Power Pool (NEPOOL) filed with the Federal Energy Regulatory Commission (FERC) a proposal to implement a revised Winter Reliability Program (WRP) for the upcoming winter (2014/2015). This past winter, the ISO implemented the first WRP, which helped to increase the amount of oil inventory held by oil and dual-fuel generators in the region. The program proved to be critical in keeping the lights on throughout colder-than-normal winter conditions. That first WRP was intended to be a one-time solution to bridge a reliability gap. However, ISO New England’s operational experience last winter and other developments have prompted the ISO and NEPOOL to seek approval of another program to mitigate significant reliability concerns for the upcoming winter.

Challenges that prompted request for another winter program

More severe pipeline constraints

Over the past several winters, the pipelines carrying natural gas into New England have become progressively more constrained as demand for the fuel has greatly increased for both heating and power generation. The ISO has commissioned various studies of the capacity of the pipeline infrastructure in the region; findings from one updated study and operating conditions last winter revealed that the pipelines are even more constrained than previously understood. These limitations have caused volatility and natural gas price spikes, which have translated into higher wholesale electricity prices. To illustrate, the total value of the wholesale energy market from December 2013 through February 2014 was about $5.05 billion, compared to the $5.2 billion value of energy market transactions for the entire 12 months of 2012, the year that averaged the lowest wholesale power prices since 2003. Beyond the effects on prices, pipeline constraints also have an immediate impact on grid reliability.

Difficulty replenishing oil inventories

These pipeline constraints pushed up gas prices above oil prices for much of last winter, which resulted in more frequent dispatch of oil generators, with extended run times. Because of these conditions, oil inventory was used up rapidly. Even with the first WRP in place, many oil-fired generators depleted their inventory mid-winter, and had difficulty securing and transporting additional oil due to harsh weather conditions and competition for the barges and trucks required to move the fuel.

Generator retirements

Two large, non-gas-fired generators that provided valuable resource diversity during the 2013/2014 winter will be retired by the time winter arrives this year. Vermont Yankee nuclear power plant—with more than 600 megawatts (MW) of capacity—announced it will retire this fall, and two Salem Harbor generators with a combined capacity of 587 MW retired on June 1, 2014. To put this into perspective, the 2013/2014 WRP procured oil and demand resources capable of producing more than 1.9 million megawatt-hours of power while the combined capabilities of these retiring resources is 2.6 million megawatt-hours.

2014/2015 Winter Reliability Program

The proposal filed with FERC is not an extension of the first WRP; it has been modified as a result of several market changes that will be in effect prior to winter 2014/2015 as well as the Commission’s clarification of generator obligations to procure adequate fuel to meet their expected run times.

Several elements of the 2014/2015 proposed WRP are consistent with the first program, including the demand-response component, as well as permanent rules related to dual-fuel generator audits and the partial elimination of higher-cost fuel requirements that evolved from similar features in last winter’s WRP.

The proposal is also fundamentally different from the first program. Those significant differences include:

  • Improved fuel neutrality, achieved by adding a liquefied natural gas (LNG) component
  • Compensation for fuel that is based on unused inventory at the end of the winter rather than upfront inventory
  • Instead of an “as-bid” design, compensation for the fuel inventory and demand response programs that is based on a set rate

Core components of the proposal

  1. Compensation for unused oil inventory: Participating generators that have a minimum level of oil inventory in place prior to the start of the winter will receive a payment to offset some (but not all) of the carrying costs of unused oil left after winter is over. The proposed set rate is $18/barrel. The ISO is seeking an aggregate oil inventory that ranges from 2.8 million barrels to 3.8 million barrels of oil.
  2. Compensation for unused LNG contract volume: As with participating oil and dual-fuel generators, generators that contract for LNG will receive an end-of-season payment to offset the risk of unused contract volumes. This portion of the program is intended to create incentives for generators to contract for LNG as a peaking fuel to augment the use of pipeline gas. The proposed set rate of $3/MMBtu is based upon the unused oil inventory program rate, converted to dollars per million British thermal units (MMBtu). The ISO will accept contracts up to the aggregate cap of 6 billion cubic feet (Bcf).
  3. Demand response: Like the first WRP, the program is open to demand-response (DR) resources that are new assets and not currently participating in the wholesale electricity markets, or resources that are currently participating in the Forward Capacity Market but have additional capacity beyond that needed to meet their capacity supply obligation. DR participants will receive monthly payments to be available. Unlike the first program, the payment rate will be set—rather than established by bid—at $1.80/kilowatt-month, which is equivalent to the unused oil inventory rate. The aggregate cap for demand response participation is 100 MW.
  4. Incentives for commissioning dual-fuel capacity: This facet of the program is intended to incentivize gas-fired generators to invest in dual-fuel capability—that is, the ability to run on either oil or gas. Generators that have not operated on oil since at least December 1, 2011, and that demonstrate a plan for commissioning, or recommissioning a mothballed dual-fuel unit, by December 1, 2016, will be eligible for compensation to offset some of the associated costs.

In addition to these components that, if approved, would be in effect for the 2014/2015 winter period, the ISO is also seeking market rule changes to be in effect for the 2014/2015 winter and beyond.

  1. Partial elimination of higher-priced fuel burn requirement for dual-fuel resources: Under current market rules, a dual-fuel resource that submits a supply offer based on its higher-cost fuel is required to submit evidence that the higher-cost fuel was burned; failure to report this information results in price mitigation. The existing rule restricts a market participant’s ability to effectively manage its fuel supply during times of uncertainty and price volatility in the natural gas markets when it is difficult to know, in advance of submitting a supply offer, whether oil or gas will be the least-cost fuel. This portion of the program would exempt dual-fuel resources from the requirements on certain days when the price of oil and natural gas approach convergence and gas prices are volatile.  
  2. Dual-fuel auditing: An aspect of the first winter program compensated dual-fuel resources when they ran their generators to test their ability to successfully switch from one type of fuel to another. In total, the tests cost approximately $1.7 million, and provided ISO system operators with increased certainty about these units’ capability. This component of the proposal seeks to preserve the ability to conduct and compensate dual-fuel resources for annual audits.

Cost and cost allocation

After adjusting for resource unavailability, the final cost of the 2013/2014 WRP was approximately $66 million; initially, the cost was estimated to be about $75 million. For the proposed 2014/2015 WRP, the Analysis Group estimated costs for the separate components: the maximum cost of the DR component would be about $2.4 million; the cost of the unused oil inventory and LNG contract volume components would be based on how much fuel remains unused, and assuming, at the high end, that 100% of the targeted amount of fuel is unused, the estimated cost would be $82.6 million; and the maximum cost for the dual-fuel commissioning program is estimated to be $12.9 million for units that commission by December 1, 2015.  The dual-fuel auditing provisions are estimated to cost a maximum, annually, of $7 million.

Consistent with the Commission’s order on the first winter program, the costs will be allocated to real-time load obligation, which is paid by load-serving entities, rather than to regional network load, which is paid by transmission owners.

The filing parties have requested an effective date of September 9, 2014.

View the full filing, submitted in two parts: