Utility2Utility: American Electric Power

Kathleen Wolf Davis | May 20, 2014

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American Electric Power (AEP) is one of the largest electric utilities in the U.S. It serves more than 5.3 million customers in 11 states. It also owns nearly 38,000 MW of generating capacity and owns the nation’s largest electricity transmission system, a more than 40,000-mile network that includes more 765-kilovolt extra-high voltage transmission lines than all other U.S. transmission systems combined. 

For this installment of Utility2Utility, we corresponded with AEP on grid reliability issues the utility can trace to plant shutdowns, specifically the loss of coal-fired generation.

 

Intelligent Utility: Tell us about coal plant retirements at AEP and how you’re planning for that.

AEP: AEP is retiring more than 6,500 MWs of additional coal units between now and mid-2015. This is primarily a result of the Mercury and Air Toxics Standards (MATS) rules, but the current market structure in PJM is not providing the type of long-term pricing signals necessary for us to make long-term investment decisions regarding the compilation of our future, post-MATS fleet.

Beyond energy and capacity, many of these units provide other ancillary services that are necessary for maintaining grid reliability.  One of these ancillary services is the provision of black start capability, which is necessary for restoring energy to the grid in the event of a large catastrophic blackout.  PJM has now issued four requests for proposals (RFPs) for this type of service in the AEP territory to replace the black start units being retired.  The first three proposals, which took more than two years to complete, were only partially successful in replacing this type of capability. The fourth is still open until mid-July.  Even if this fourth RFP is successful, it will be challenging to have the replacement in operation prior to the retirements taking place.

AEP has stated publicly that 89 percent of the generation that AEP will be retiring in 2015 was called upon to meet electricity demand in January 2014.  These units were called upon by PJM and relied upon to maintain regional reliability.  AEP is concerned about what happens if a similar, or worse, polar vortex occurs post mid-2015 after all of these coal units are retired.

AEP is not calling for abandoning or postponing the MATS rules, but we also believe that additional EPA regulations at this time would be very detrimental to grid reliability.

We cannot leave these plants online past June 2015, and have reduced maintenance spending on these units with the expectation that they will be fully retired by mid-2015.  This includes a reduction and reassignment of staffing levels to minimize our transition costs and impact to our employees working at these plants.

AEP and PJM have been planning for unit retirements for more than three years and have invested more than $3.6 billion dollars in the last two years to reinforce the electricity grid where retiring units present threats to reliability.  However, additional retirement announcements as the MATS deadline approaches may force AEP and other utilities to reevaluate the adequacy of these mitigation plans, with little or no time to implement alternatives.

 

Intelligent Utility: Why is replacement sometimes problematic?

The retiring units are largely being replaced by units that may not have the same level of reliability—demand response and gas generation.  The vast majority of demand response capacity is available in the summer only, which does not provide much help in the winter (only 1,911 MWs of demand response voluntarily responded during PJM’s recent winter polar vortex peak of 141,000 MWs on Jan. 7.) Meanwhile, almost all of the new generation offered in the PJM market in the last several years has been natural gas-fueled. We saw this past winter that gas/electric scheduling issues are causing problems with getting sufficient gas supplies to power plants, and this will only increase as our dependence on gas-fired generation increases. Finally, gas has a much more volatile market price than fuel sources that can be stored on site at power plants.  

 

Intelligent Utility: Do you expect these grid reliability issues to grow?  Why or why not?

AEP: Additional environmental rules still in development could create more issues. The Cooling Water Intake Rule (316b), the Coal Ash Rule and the Greenhouse Gas New Source Performance Standards all could potentially result in additional base load generation units being retired. The MATS rule implementation did not allow a lot of flexibility in meeting the regulatory standards. If a rational approach with sufficient flexibility is not taken in setting these new environmental standards, we will face additional threats to grid reliability.  

Future grid reliability also depends a lot on whether PJM and the other regional transmission organizations (RTOs) can fix their capacity and energy markets.  Reliability is a critical public need.  The competitive wholesale markets currently are not providing the structure necessary to maintain that reliability and do not currently provide the proper economic signals to foster new power plant investment for the future.

The real value of steel-in-the-ground capacity must be recognized in the competitive markets. Insufficient revenues from both the capacity and the energy markets mean additional nuclear and fossil generation may be retired.

The market flaws that create economic inefficiencies include inequities in the treatment of actual generating assets versus demand response, imported power, and even new planned generation. Yes, PJM has more than 8,000 MWs of planned (mostly gas) generation committed in the last two capacity auctions, but many of those generators are being proposed with some form of state regulatory funding support. What this means is that many new builds are the result of state directives rather than a response to market signals. Other market design problems exist with demand response compensation. Specifically, while existing generators are required to be available for dispatch when needed and face financial penalties for failure to respond the entire year, most demand response is only required to perform in the summer.  Further inequity results from that fact that most of the summer demand response is only required to perform 10 times per summer for a maximum of six hours each time.

In PJM, a total of 12,000 MWs of demand response cleared the PJM capacity auction for 2016-2017.This composes about half of the PJM target reserve margin for 2016-2017, and 99 percent of that demand response is a summer-only resource.

Importing power from plants in other reliability regions also can be an issue. On July 15, 2013, a Tennessee Valley Authority transmission constraint, exacerbated by the reduction of a MISO resource, resulted in the curtailment of more than 3,300 MWs of PJM imports, including 29 MWs of imports on firm transmission. This is the reliability risk of depending on imported power. PJM has committed power imported from Louisiana in its capacity auction, although the ability of that Louisiana power to ever be delivered into PJM territory during emergency conditions is questionable at best. 

Currently, PJM’s three-year Base Residual Auctions are augmented with annual incremental auctions. Demand response resources can bid into the Base Residual Auction at one price, buy back their own resources in the incremental auctions at a nice profit, and never have to perform a demand response function for reliability. PJM’s Independent Market Monitor has issued two reports on this problem. As much as 57.6 percent of demand resources have purchased replacement capacity in the incremental auctions. The average over the seven-year measurement period was 32.5 percent. These speculative resources are replacing the actual physical generation we need because it is financially more lucrative to buy back in the incremental auctions than to deliver the capacity. Further, demand response does not provide the very important ancillary services currently provided by many of the retiring generating units.

AEP believes capacity prices should be augmented by a reliability adder, or price floor. This would support continued operation of base load generating units and provide incentives to spur construction of new generation. We also believe a longer-term commitment for price certainty would help all companies with both existing and new assets to make long-term investment decisions. Power plant investments are for 30+ years. A reliability adder combined with a longer-term award would provide proper incentives, ease financing, and provide longer-term price stability for the markets, all of which will preserve and increase grid stability.

 

Intelligent Utility: What advice would you give the industry on this issue?

AEP: Regulated utilities plan for peak usage through integrated resource planning processes. Competitive generators depend on clear market signals to support the investment necessary for stable operations. Megawatts flow seamlessly across state borders. As additional stressors impact the bulk power system in the coming years, state and federal regulators must be vigilant to ensure that regulated customers are not harmed by the scarcity and volatility that will develop if competitive markets are not fixed. 

Toward that end, AEP advocates for: 

 

  • Significant progress on fixing the capacity markets by January 2015. We need to return the focus of the nation’s electric grid to reliability and away from a financial scheme that rewards speculative activity. That can be achieved through the FERC. 
  • Passage of legislation to resolve the conflict between the authority of the Department of Energy and that of the Environmental Protection Agency that could manifest in the DOE ordering a unit to run even when that unit would violate environmental requirements. Legislation is needed to clarify the rules and expedite new construction to ensure that existing generation will not have to face a choice between violating the environmental rules and letting the lights go out. 
  • Completion of the action recently begun by the FERC to coordinate the natural gas and electric industries. FERC has taken important steps in this direction and is doing so as rapidly as possible. We need resolution before next winter. Nothing good comes from a scenario in which anyone has to choose between electricity and heat. 

 

 

Read more from this series:

 

Got a utility suggestion for this series? Contact me anytime at kdavis@energycentral.com. My digital door is always open.

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