The Federal Energy Regulatory Commission is at it again. It is in the process of reshaping our bulk transmission system through Order 1000. This order attempts to shape how regional transmission planning moves forward and even dips into assuring that new transmission is competitively bid. Rules taking place will impact operation and maintenance of newly built transmission lines. Incumbent utilities will lose the right of first refusal, leading to both threats and opportunities for incumbents and service providers.

Burns & McDonnell sponsored an executive roundtable to address FERC Order 1000 and other critical issues facing transmission owners in North America. Transmission & Distribution World is pleased to share the steps our top executives are taking to impact and comply with this critical regulatory order.

T&D World: Why we should care about FERC Order 1000?

Maureen Borkowski
Maureen Borkowsk
President and CEO
Ameren Transmission Service

Maureen Borkowski: Let’s start by laying out what makes up Order 1000. There are three components to this order. The first is the regional planning component of cost allocation. Then there’s the inter-regional planning component, which spans multiple regional transmission organizations (RTOs) and non-RTO entities, to enable the building of more efficient transmission across multiple regions. The third and probably the most controversial component is the elimination of the right of first refusal from any FERC jurisdictional contracts.

As a regulated entity, Ameren, along with many others, have been challenged to come up with its own compliance plans to meet what is laid out as a policy initiative.

T&D World: Bob, American Electric Power (AEP), is probably the biggest transmission owning entity in North America. What impact will this order have on your multi-regional utility?

Robert Bradish
Robert Bradish
Vice President
Grid Development
American Electric Power

Robert Bradish: AEP has been a supporter of FERC Order 1000. We operate in three RTOs PJM, Southwest Power Pool (SPP) and Midwest Independent System Operator (MISO). If your footprint is entirely within an RTO, much of FERC Order 1000 has a limited impact on you. There was already a regional planning process in place with some form of cost allocation. Obviously the elimination of right of first refusal is a new component. We’re okay with that. It opens up opportunities for more providers to participate in building more transmission in our service territory. But it also opens up an opportunity for us to go in and participate in other parts of the country. When we look at trying to plan our system, we naturally have some issues at the seams. So, to the extent Order 1000 gets the RTOs to work more effectively on interregional planning, it will be a good outcome.

Michael Deggendorf
Michael Deggendorf

Senior Vice President
Kansas City Power & Light

Michael Deggendorf: Let me step in and state that the overall objective of the order is increasing reliability while getting lower-cost power to markets and integrating renewables. The order is moving us more aggressively towards that objective, including the elimination of right of first refusal.

T&D World: Teresa, Xcel has a big transmission footprint in many states in several regions. Would you like to comment on your company’s focus?

Teresa Mogensen
Teresa Mogensen
Vice President Transmission
Xcel Energy

Teresa Mogensen: Xcel is in both MISO and SPP. We very much support regional planning and regional cost allocation. The right of first refusal issue is challenging for us. Being a vertically integrated utility with retail load-serving responsibilities, we have concerns about the potential chaos from opening up transmission development to any potential entrant to our system. And I don’t see FERC 1000 as a reliability advocacy approach. It is all about market and energy policy. Reliability has a potential to be a casualty of it if we’re not careful.

T&D World: So we will have competent known independent companies bidding on new transmission, but we will also see companies formed that don’t have a track record. Paul, maybe you would like to share your thoughts on new entrants.

Paul McCoy
Paul McCoy

Principal
Atlantic Wind Connection

Paul McCoy: We don’t want “two people and a laptop” to participate in the new opportunities, either. If you take a look at, for example, the Texas Competitive Renewable Energy Zone (CREZ) process, Texas was an experiment. The Texas PUC staff spent 18 months on a very methodical approach. And if you take a look at who got approved, and the staff’s concerns about financial viability, the outcomes were pretty good. I think the same thing will occur for order 1000. We'll be including people with track records in the industry, potentially along with foreign entries. By and large, you'll see this work.

Borkowski: Paul, having public policy that leads to a strong, more robust system than we have today that is planned on a broader basis will ultimately be good for the country. But in the short run, I expect we'll see a giant step backwards from some of the regional transmission investment that we were already expecting. In the MISO, we’re now just at the point of moving major projects forward, and now we’ve got to address FERC Order 1000. There are so many unknowns and so many different things that have to be played out. I really believe that once these compliance plans are filed and accepted, you will probably have a three- to five-year period to refocus because there are so many issues to deal with. And the way FERC Order 1000 was written, reliability-based projects are no longer subject to right of first refusal by the incumbent. So, now you have incumbents who have a state obligation to provide reliable service and no vehicle on which to deliver on that state obligation. That’s very much a concern to me as an entity that’s responsible for providing reliable service.

Mogensen: Rick, the critical issues is who pays. Once that's settled, it’s not an issue to get it done. The utilities who have kept transmission as a competency are very capable of getting it done. So I think that is one of the critical issues. It’s not who can get it done, and it’s not getting lines built. It’s who’s going to pay for it. And once that’s clear, it will get done. But if it’s not clear, it won’t. Building it is only half the battle, even less than half the battle. The broader issues are operating, maintaining, and integrating the whole system to serve the public reliably long term.

Jon Jipping
Jon Jipping

Executive Vice President
and COO
ITC Holdings Corp.

Jon Jipping: As Theresa said, building transmission has not been an impediment. The issue is cost allocation and will the company be around to operate and maintain the lines for 40, 50 or 60 years after that? We just finished a large project in Oklahoma and also completed the first phase of another project in western Kansas. We went through a full certification audit to become a transmission operator and demonstrated our capability and long-term commitment to projects. FERC Order 1000 must address these issues of competency and commitment of the operator to those assets over the long term.

T&D World: So the person that builds it, in many instances, also will be the person who operates it and maintains it? Is that what you’re saying?

Jipping: It may be. It is an issue, but right now it's not a requirement.

John Kellum
John Kellum

Division Vice President
High Voltage Power Delivery
CenterPoint Energy

John Kellum: ERCOT is independent of the national transmission system, but we face similar issues. With the CREZ projects under the authority of the Electric Reliability Council of Texas (ERCOT), we have entities that aren’t incumbents and are building projects. So we may face the issue of who will be the long-term owners and operators of these non-incumbent facilities.

T&D World: Will we see incumbent transmission owners such as CenterPoint and Oncor take over the operation and maintenance of new transmission facilities?

Kellum: I can’t speak for Oncor, but this is an issue worth watching.

David Mead
David Mead

Senior Vice President
Transmission and Distribution
Business Unit
Southern California Edison

David Mead: Being in California, under California ISO, our cost allocation is established. Most of the lines we’re building are for renewables, and we’re not sure what Order 1000 does for us. We were not a supporter of the need for this order. But we have to go forward and we’ll work it out. I sat with FERC Commissioner Marc Spitzer, and he told me that he and his fellow commissioners came to the conclusion that transmission is not a natural monopoly. That competition should drive down prices. But issues remain to be addressed. If I were an independent now, I would not know how to go into the California market with a competitive bid. We have seen environmental costs that are 10 times what we thought they would be. That's hard to address under a fixed price bid.

In California, we’ve got a small section of a 500-kV Tehachapi line going in through a community. The commission supported the plan and approved it. And now we’ve been debating this question for a year. The poles are already up. All we have to do is string it and it’s done. If the commission decides to order us to underground, those poles will come down and the first 500-kV underground system built in the United States will go in instead. I’d hate to think I had a firm price on this contract. It seems to me the best route forward may be to have some kind of partnership, where the local utility helps get through the licensing.

Scott Thon
Scott Thon

President and CEO
AltaLink

Scott Thon: Clearly, we see a similar drive to introduce competition from policy makers in Canada. We need a lot of transmission to be built. And it needs to be delivered cost-effectively. We have moved towards bringing in competition on our large projects. It takes a lot longer, because now you’re setting up a competitive bid process, and you have to do a bid and qualification process. Our first competitive project in Alberta will be fixed price to build, operate and maintain over 30 years. Can companies support a fixed price on transmission when environmental and location siting is not complete? I am not sure, but clearly the desire for competition is there. We are opening the market to competition and hope there will be competent people who will show up to play from the global transmission marketplace.

Mogensen: If the risk/reward is not well synced, an entity can come in and make a low bid, and if the going gets too tough, there aren’t any financial ramifications to them just walking away. If the project is to meet a reliability standards requirement and is not done on time, there could be significant impacts to the local utility or market. This needs to be well thought out.

Thon: This kind of process has worked in Brazil for a decade, and they’ve had companies from all over the world to come in and do it. The difference in Brazil is that the transmission line has a well-defined route. In Alberta, there is no route, so there’s a lot of risk and lot of uncertainty.

Kim Hanemann
Kim Hanemann

Vice President Delivery Projects
and Construction
Public Service Electric & Gas

Kim Hanemann: In New Jersey, you also have a municipal approval process in addition to a state-run Board of Public Utilities siting approval process. So you end up adding municipality requirements on top of state demands and potential federal requirements.

T&D World: So that adds another layer of complexity?

Hanemann: Yes, we must work with all kinds of interface issues, conflicting priorities and varying requirements for mitigation. It is getting very, very complicated.

Mead: I want these needed transmission projects to be successful. Maybe the incumbent utilities should do the siting, the licensing and get the routes in some type of partnership. Get to the point where you can say, “Okay, now we know what the project is. Go build it.” That might be how we're going to get the price down. If this is really going to work, we’re going to make it work, and in my opinion, the incumbent utilities will have to deeply involved.

Bradish: You’ve got to have the competition at the front end. Let folks come with their ideas about how to solve a problem, get different solutions out there on the table, and let those solutions fight it out as to what is the most cost-effective solution. The folks with best idea move forward with the project. The customers will get a better, more cost-effective solution than if we just focus on the tail end, where everybody is just submitting bid packages for the same project. Utilities already bid projects out today, so I see very little opportunity for the customer to gain additional benefit from that approach. If we want innovative solutions, we need to incent folks to commit their resources to developing those solutions. Innovation and creativity happen at the front of the process and that is where we need to encourage competition.

Mogensen: Isn’t the planning a challenge, too? It’s an iterative process. Bring ideas in, work them through and let the best overall plan come out. Then you have to ultimately figure out who’s the best builder, and that gets into all the issues about a local utility versus a new entrant, and the array of capabilities required for building, operating and maintaining it for the best price over the long term.

Mead: I don’t think you’re ever going to be able to know whether it was cheaper one way or the other. But you’ve got to create that competitive environment to drive the price down. In order to do that, I think you have to partner on an awful lot of this. Somebody has to get the rights to go in and develop the project just to get through that first part.

Deggendorf: The biggest challenge is incenting folks to invest in creative problem solving. If you get into a just-turn-in-your-bid process, you’re going to get the solution that requires the least amount of investment on the front end. Transmission may not be the only solution that should be considered. In terms of an ultimate solution, how does storage fit in, how does dropping a generator at a critical site play into the solution? I’m concerned that these options may get stripped out of the valuation.

T&D World: So there might be lower-cost solutions that we might not have investigated or even have the opportunity to explore?

Mead: A short-term lower-cost transmission solution might not even be the best solution for the long haul. Single circuits versus double circuits, for example. You do the minimum required to fix the problem, and then you’re back 10 years later. That’s not the way the system’s been built in the past. System planners have looked 30 and 40 years ahead. In a strictly competitive world, you might lose that capability.

Borkowski: We’re going to have competition, so transmission’s going to go to the low bidder that meets the requirements. Yet we have an incentive policy that gives you more favorable rate treatment than we get on our traditional state-regulated businesses. What happens with all of that in this Order 1000 competitive marketplace?

McCoy: That issue is not lost on the FERC and other policy makers. We’re really talking about bidding the capital structuring. When you look at where this might go long term, you don't really get so much into the fixed cost, or a fixed price on original cost. It’s who’s willing to take the revenue requirement that comes out of the capital structure. That’s a very slippery slope.