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Serving 5.4 million customers across 11 states, American Electric Power is still grappling with various scenarios for complying with the Environmental Protection Agency's Clean Power Plan despite the rule being stayed by the U.S. Supreme Court. During a recent forum sponsored by the Electric Power Research Institute, Scott Weaver, manager of strategy policy analysis at AEP, spoke about the difficulties the multistate company will face once states begin to implement the Clean Power Plan (RIN:2060-AR33), which sets carbon dioxide emissions limits on the existing fleet of power plants.
Driven partly by market forces and with an eye toward complying with the rule, AEP is already shifting its generating capacity away from coal and toward a broader portfolio of cleaner options. While coal accounts for 60 percent of the company's generation currently, that share is expected to fall to 45 percent by 2026 as AEP invests in more renewables and natural gas.
Weaver spoke to Bloomberg BNA reporter Andrew Childers about how the company is assessing the multitude of options available to states. The interview has been edited for length and clarity.
At AEP, you're already transitioning away from coal toward a broader portfolio. You were doing that before the rule came out. Is the rule affecting those plans going forward?
We've incorporated a price on carbon within our resource-planning process for a number of years and the Clean Power Plan is just kind of an extension of that. So it's more of a formal requirement to look at carbon now. Obviously, with the rule being stayed, that puts some uncertainty on it, but directionally we've been heading on that track for a number of years. So I wouldn't say the Clean Power Plan necessarily created a shift in our plans, but it's something we've already been planning for and will continue to plan for as we're going forward.
How are you viewing your preparation? What are you looking at if the rule is eventually upheld?
Through our planning processes, we're looking at ultimately what might be a market-based outcome for the compliance with the rule and that, of course, would be a price on carbon whether it be an emissions allowance or an emissions reduction credit. We're baking that in. We're looking at ultimately what is the lowest cost for our customers what would minimize customer costs with this rule. Obviously, a number of steps we've taken with shutting down older coal units, increasing our natural gas consumption through acquisition of new natural gas units as well as increasingly adding renewables to our mix well positioned us, but we need to see that continuing going forward. But ultimately, it's going to be our states' direction in terms of what they want to do from a planning perspective that will ultimately dovetail into our internal planning processes. After the courts have a chance to weigh in on what the ultimate outcome of the rule may be, we'll get back in touch with our states and work with them to figure out how best to develop state compliance plans that minimize customer costs as well as allow us to plan for a least cost solution.
That goes back to something you had said at EPRI; you said you cover 11 states but only Virginia is currently working on a plan.
Virginia is the only one active. Louisiana has indicated it might continue, but most of our states have put their pencils down.
So how do you begin to prepare for something like that when you don't know what direction a state might be going in yet?
You know, it's a little bit tricky. We're doing internal analyses, obviously. In a number of states, we have resource-planning requirements, which will continue to analyze the effect of CO2 regulation whether it will be the Clean Power Plan or some other proxy which ultimately we think might come to bear. That process will shed a lot of light on terms of what's economic for our customers. Additionally, we're keeping track of other studies in the market, whether these studies are by PJM or [the Southwest Power Pool] or other reliability entities. I think as we go through this process there will be numerous information points that we can reference and, ultimately, it's not a single point that's useful to stake but collectively looking at the volume of information out there and assessing, “OK, what kind of robust conclusions can we draw going forward?” I think our states, even if they're not actively pursuing a plan, they are, I think, in an information-seeking mode. They'll keep their pulse on the studies out there, I think, behind the scenes on what ultimately may come to bear and how to prepare for it.
Because your company spans 11 states, is the worst case scenario for you guys getting a hodgepodge of state plans—some go mass while others choose rate—that would create difficulties with maximizing efficiencies across your system?
It is a risk for us. Given our operating company focus though, ultimately if there are disparities in compliance plans, as long as those plans match up well with what our operating companies can do with cost effective solutions, we're OK with that. Obviously, it adds some operational costs and management costs on our part trying to comply with disparate policies just because there's more legwork on our end trying to match our compliance plans to that state plan, but ultimately this can be in the best interest of customers. Whether it's rate or mass, we'll follow that track.
It does create some challenges particularly because some of our operating companies' footprint does stretch across multiple states. That's where we have our biggest risk in operating companies that operate in multiple states. If those states go different ways, that adds planning complexity.
Do you have a preference, rate versus mass? You still have a significant coal presence, which would incline it to a mass approach. But do you have a preferred option?
We don't have a preferred option at this point. We broadly acknowledge that mass has its inherent advantages in its simplicity as well as our past experience utilizing a mass-based plan. For a number of states where there is a significant coal footprint, mass seems to make more sense because it's pretty simple to reduce mass by reducing utilization of coal units. We are recognizing that for some of our states, particularly those with a lot of renewable options at a low cost, rate may also be an attractive pathway. So ultimately, it's a little bit hard to forecast what might come to bear now seven years down the line in terms of renewable costs as well as the composition of what the electric fleet looks like. At this point, we're not driving that decision by the states, but we're encouraging them to look at all cost effective pathways and make a determination based on cost.
You mentioned cost. Earlier you said you'd done some cost analysis that suggested it could be as much as $200 million to $400 million more in compliance costs without trading. Is that going to be one of the driving factors as you work with states on compliance?
Encouraging trading is key with this whether it's taking a rate-based approach or a mass-based approach. In any situation, trading is always more cost effective, and that's one of our early conclusions. We think that states going down a path which would lead them to adopting the model trading rule would be the most cost-effective. That's something we're broadly encouraging across states. We'd also eliminate some of these cross-state issues by having a common currency we can all have for compliance between states.
You had also mentioned that AEP across the entire system has hit close to that 30 percent reduction already, but you said it wasn't uniform. Are there particular spots along the system you see needing extra attention as you plan for compliance?
Obviously, some states, I think I mentioned Virginia and Kentucky, we've completely shut down our coal footprint there. However, other states like West Virginia, our generation mix there is 100 percent coal. Even though we shut down some smaller units, we still have a large footprint in that state, greater than 4 gigawatts of coal. I think states like West Virginia are going to be kind of markers for what happens with the broader coal fleet in terms of compliance with this rule. I think that's where a lot of our attention is going to be going forward. And again, that coal footprint in West Virginia does supply customers in Virginia as well.
AEP has said that you guys have already made significant reductions. However, you're not going to be getting credit under the Clean Power Plan for some of that early action. Do you see any other easy targets of opportunity? Does the fact that some of your other early actions don't count toward compliance present any unique challenges for you guys?
It's a function of how EPA structured this rule. I think at this point it's water under the bridge. There's not much we can do given that we have a final rule. Obviously, we'll look toward opportunities to maximize our compliance opportunities going forward, looking toward things like the Clean Energy Incentive Program, which we can potentially draw some additional allowances from. Those reductions did occur from 2005 to 2012, and unfortunately EPA's compliance [window] is from 2012 forward. Those are reductions that have been realized and environmental benefit actually has too.
You mentioned the CEIP. You guys see opportunities there as well for additional action and early credit then?
We have plans for a large deployment of renewable energy resources across our footprint within the next 10 to 15 years. With the extension of the production tax credit as well as the potential for the CEIP program, deploying those resources early could make a lot of sense for us. We're looking forward to reviewing the rule —I guess it's at OMB now—and comes back out for comment. It might influence our compliance plan going forward, so that's something we're interested in. But, obviously, there's a lot of details that need ironing out.
You mentioned the uncertainty because of the lawsuit going on. How does the upcoming argument and the litigation affect your planning going forward?
Obviously, we have to plan for several outcomes. One where the rule doesn't go into effect, one where the rule goes into effect as is and there's some middle ground between in terms of if the court strikes down a narrow portion of it and keeps another portion. We're just planning for multiple scenarios now. We're not going to speculate on what the court outcome might be. Obviously, it's setting up for a lengthy process, probably two to four years before we have final resolution. In that time frame we're going to do internal analyses where needed. We're going to respond to requests for external analysis from our states where they think we need to weigh in on pathways. But ultimately, we're not going to make any firm commitments or investment decisions before the process plays out.
To contact the reporter on this story: Andrew Childers in Washington at firstname.lastname@example.org
To contact the editor responsible for this story: Larry Pearl at email@example.com
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