Merchant Transmission Projects - excerpts from a discussion about potential opportunities in the project finance market

Merchant Transmission Projects - excerpts from a discussion about potential opportunities in the project finance market

August 01, 2003
The following are excerpts from a discussion about potential opportunities in the project finance market.  The discussion took place in San Diego in June.  This segment focused on merchant transmission projects.  The question posed was, “The area where there is the clearest need for more capacity is electric transmission, but transmission projects face daunting obstacles.  Is it sheer fantasy to undertake such a project?”

The speakers are Robert Mitchell, president and chief operating officer of Trans-Elect New Transmission Development Company, Jon Erik Larson, a managing director of Trimaran Capital Partners in New York, Dominic Capolongo, a managing director of Credit Suisse First Boston in New York, and Adam Wenner, a regulatory lawyer with Chadbourne in Washington.  Michael Polsky, president of Invenergy, asked a question.  The moderator is David Schumacher, a project finance lawyer who is in Washington for part of each week but who works primarily out of the Chadbourne office in Houston.

MR. SCHUMACHER: Bob Mitchell, what were some of the things that made Trans-Elect think the time was ripe for a private company that would focus on transmission?

MR. MITCHELL: In 1998, when I started thinking about transmission, I had the luxury of not coming from a utility background.  I was looking at this more from a public policy point of view independent of transmission and the benefits that it could bring to the consumer.  In analyzing the situation, it struck me in 1998 and 1999, when we were in the process of forming Trans-Elect, that the utilities had a lot of opportunities where they could place their money in non-regulated activities and get a lot bigger return than the 10 1/2% or 11% return that they were allowed for their regulated businesses.

The more I looked at it, the more clear it was that the direction of regulators is to take more and more power and control over that asset away from the utilities.  So I thought that if I were a utility CEO, why would I want to continue holding on to an asset that, for most utilities, is only about seven to 10% — maybe in some cases 12% — of their total asset bases.  Here was an opportunity to monetize that asset.  From research that I was doing, it looked to me like we were going to be able to pay a premium.

It was really on that basis that we — some colleagues of mine who knew more about utilities than I did — came together, and we formed Trans-Elect.  We did some pioneering.  We were able to be part of the consortium that put together the first transaction where an independent company bought a transmission system from a utility in Canada.  We bought it from Trans-Alta.  Then we were successful in putting together an acquisition from Consumers Energy in Michigan.  More recently, we succeeded in putting together a project in California, which is actually new transmission, called Path 15.

Frankly, after having spent four years or so working with utilities, I think I clearly underestimated the bond that utilities have with their transmission systems.  It’s like jerking an arm right out of the body in order to get a utility to part with one.

There has been some progress.  KKR and Trimaran were successful in buying the Detroit system.  Over the next few years, you are going actually to see a lot of activity on the transmission side.

MR. SCHUMACHER: Jon Larson, why are transmission projects attractive to an investment fund like Trimaran?

MR. LARSON: First, this is a very large asset opportunity.  Every other commodity has an exchange or some sort of agency that facilitates trades.  Stocks are traded on the New York Stock Exchange.  Commodities are traded on the Chicago Board of Trade.  Effectively I think what is required in order to make commodity markets work for electricity is some large entity steps in that has the infrastructure to facilitate trades.

Right now, we are looking at a world that looks like 90 different Spokane Stock Exchanges.  We are trying to consolidate those 90 into something that looks like a New York Stock Exchange, an American Stock Exchange or the NASDAQ.  Funds such as KKR and Trimaran have access to the larger pools of capital that are trying to seek more predictable returns than are available in the merchant power market.  In order to satisfy that investment criterion, we may be targeting lower rates but a much more stable rate.

US government policy has been to encourage entities that do not have a natural monopoly in the power supply market to invest in transmission.  We consciously decided when we started this buyout business — now six years ago in Trimaran — that we were not going to purchase power plants.  We will not pursue power plants basically because we figured we were not as smart as most of the other people in this room.

Best Investments

MR. SCHUMACHER: Is it safe to say that as of right now, the best way to invest in transmission is by acquiring existing systems, or is there a realistic possibility that some greenfield transmission projects will be built and earn an attractive return?

MR. LARSON: The best opportunities right at this moment are, in fact, new construction.  It appears that the US Senate is preparing to clip the wings of the Federal Energy Regulatory Commission in the energy bill.  If it does, then I think that sales of existing systems by the integrated utilities will slow.  Therefore, the Trans-Elects and Trimarans will probably find greener pastures in fixing transmission problems that are not being addressed by the integrated utilities.

MR. MITCHELL: Let me add to that.  The most recent study on the subject of what needs to be done to the transmission infrastructure was done by the Edison Electric Institute about a year and a half ago.  EEI concluded that over the next 10 years, there will be a need for $56 billion of investment in transmission.  It did a survey of the utilities to find out what investments are planned, and the number came to $24 billion.  Since then, 60% of the utilities in this country have been downgraded, and some are in bankruptcy or near bankruptcy.  I think it is fair to predict that that $24 billion shrank rather dramatically.

I do not want to create a lot of competition.  However, there is a tremendous backlog of transmission needs in this country.  There has been underinvestment and almost disinvestment in transmission over the last 15 to 20 years.

The issue comes down to whether the United States is prepared to institute enough regulatory certainty to enable companies like ours to take the risk of developing new transmission.  When you are a utility and you decide you want to do a new transmission project, you have basically unlimited resources to do the planning, the permitting, the regulatory process, and if the project must be abandoned, you will get that money back through rates.  For independent companies, it is all risk.  You have to do it a lot smarter and spend your money more slowly, but the need is there.

MR. CAPOLONGO: I have to agree.  As you said, in 1990’s, utilities had a lot of other things to put their money into, and transmission was really a non-core activity, the investors did not care about it, and it produced a low return.  It carried a low risk for a utility, but there was a low return.  Everybody was thinking about the 20% return that could be earned on the unregulated side of the business.  Now many utilities have been burned in their unregulated businesses, and they have, in my view, unrealistic notions about the value of their transmission assets partly due to what has happened in some of the recent purchases and partly from the hopes that FERC premiums will come that have not yet happened.

As a long-term value proposition, clearly the best place for an investor to put his money is in new transmission.  Having said that, such projects require more equity, less debt, and long-term view.  You cannot look at a three-year time horizon to get your money back.  It takes three years to build the darned thing, much less to get your money out of it.  However, on a dollar-for-dollar basis, if you want to put a dollar to work in a place that will earn the highest return, it is best to put it into a new build rather than pay 1.6 times earnings for an existing property.

Key to Financing

MR. SCHUMACHER: As a lender, what do you need to see to lend either to a new build or to someone who wants to acquire an existing transmission system?

MR. CAPOLONGO: That is an interesting question.  The debt markets are completely unpredictable.  Bank debt — if you are doing new build or anything on a discrete basis using project financing — can be very high priced.  The market is significantly restricted, as Jon Larson can attest given his recent pain and suffering.  If you use the double leverage structure that many people are using, you will have to contend — at least at the upper level — with cash sweeps and all those other things that limit your ability to recycle the cash generated by the asset and to put it back to work.  You can build or buy into a sweep situation, but that is all you will be able to do with the money you raise.

The Holy Grail that new transmission companies are after is they want to build enough of a foundation to be able to borrow traditional corporate debt.  That frees up the cash that is generated from existing assets to reinvest in new projects.

A year or even six months ago, the popular wisdom was that one could not borrow in the capital markets for a pure transmission company.  However, lately rates in both the bank market and the capital markets have been extraordinarily low.  Prices are coming down, people seem to want to put their money to work and are lending in situations where I would not have thought even six months ago that a financing was possible.  Therefore, given the right size financing, you can now do a corporate financing and take the cash to put into projects.

MR. SCHUMACHER: If I’m not mistaken, it seems that these projects are not financed based on long-term contracts, but rather are financed as if the transmission company was a standalone utility with a rate-based asset.  Is that correct?

MR. CAPOLONGO: The current view of the regulatory environment is that you don’t need the contracts at least as to the portion covering the debt financing.  The assets are usually essential to the utility system.  This makes people more comfortable relying on the revenue stream.

Regulatory Distinctions

MR. SCHUMACHER: Let me step back.  I probably should have started with Adam Wenner.  I know that the Federal Energy Regulatory Commission distinguishes between merchant transmission projects and independent transmission projects? What is difference?

MR. WENNER: Most merchant projects are small, newly-constructed links that interconnect two existing transmission systems that otherwise have natural barriers between them and, therefore, have different system costs.  An example of such a project is a line connecting — let’s say — Connecticut to Long Island.  Several merchant projects that fit this description have been proposed.  Most are short and run under the sea or a river or sound.  They connect two utility systems that are not already connected due to natural barriers.

The other type of project is basically acquisition of an existing transmission grid from an integrated utility. For the most part, those are the types of transactions that Trans-Elect and Trimaran have done.  The Path 15 project in California is an exception.  It is a new build.  FERC still views the transmission system as a regulated monopoly, even though someone has now acquired it from the utility, and it remains subject to regulated pricing.

Finally, there is a third type of project at which FERC has looked, but I don’t think anyone has done.  It is an alternating current system, which is a participant-funded and participant-owned addition to an existing system.  Most existing transmission lines are direct current.  Direct current is more controllable in terms of how electricity flows.  Let me ask the others whether they see much future for alternating current projects?

MR. LARSON: Let me tell you the issue with alternating current systems.  Let’s imagine that you decided to take one particular section of the New York Stock Exchange over to Lehman Brothers and Morgan Stanley.  They pay the cost.  It facilitates their trading of certain stocks.  How are you going to parse the revenue? Right now we have an extremely complicated way of billing.  I mean, we haven’t even finished figuring out how we are going to create a market and already we have to parse it into little pieces? As anyone in the telecom industry can attest, most of the continuing war in that industry is how you do the separations with respect to long-line carriage.  That’s where we are in transmission.  Do you really want us to go through that war for the next 20 years?

I can see why people are talking about alternating current, but frankly, I think it is completely unnecessary with the likes of companies like Trans-Elect and our international transmission company.  And I will tell you why.  The way we make money is by investing money.  We don’t have generating facilities to protect.  We don’t want to keep all of you wholesale generators off our system.  We want to invest in an intertie.  We want to accommodate you and enable you to move your power into the markets where you want to deliver it.

What is required is that, as it goes through the regional bidding process, there must be an imprimatur of prudency on that investment for us.  As soon as that imprimatur is there, we will make the investment.  We are not going to go through this long conversation with you about how much you will have to reimburse us for the cost of the intertie up to the substation and then beyond the substation, and you are going to have to do this and you are going to have to change that.  All that is moot.  We will make investment.  We will be spending our own dollars and not yours.

PUHCA Repeal

MR. SCHUMACHER: Adam Wenner mentioned in a regulatory update just before this session that Congress is looking for the Nth time at repealing the Public Utility Holding Company Act.  If that were to happen, what impact would it have on independent transmission?

MR. MITCHELL: Jon and I were actually talking about that earlier.  It would remove some constraints on utility mergers.

FERC has an interesting aspect to this that actually Jon pointed out, and that is FERC wants to make a distinction between generators and companies that just do transmission.  In our two cases, we do not have generators involved.  And so a utility that owns generation and would like to expand and compete with us will be constrained from doing that because it does not pass the independence test for ownership of transmission.

MR. LARSON: I think, Bob, you might want to add that we both would love to see the Public Utility Holding Company Act repealed because in order for our companies to make sense, we have to be able to operate in multiple states.  There will have to be holding companies when we begin doing what we want to do.

MR. WENNER: Repeal would also open the door for others to enter the business who are neither integrated utilities nor transmission holding companies — say a Microsoft or a PacBell or Mitsubishi.

MR. LARSON: But Bob and I will tell you that it has taken each of us three to four years to understand the fundamentals of this business.  I think there will be others who emerge, but I don’t think the competition will come from the major utilities because I don’t think FERC will permit it.  And then the question is among the others, who is going will commit the dollars and time required.  The intellectual capital required to operate in this space is scarce.  It won’t always be scarce, but it is scarce today.  It will take a major upfront investment for a new entrant to learn the business.  There have been other investment funds that competed with us to acquire existing systems, and they were not even close to our bids.  The reason is they don’t really understand the business.

MR. MITCHELL: I think you could ask Andrew Schroeder [of Energy Investors Funds] to talk about what they had to go through to bone up and get comfortable with an investment in Path 15.  It’s ugly enough that now that I’ve suggested it, I’m not sure actually that I want to talk about it.

MR. SCHUMACHER: So there is no real fear about the utilities taking over the space?

MR. LARSON: If they own power plants, then at least as long as someone like Pat Wood or James Hecker is running the Federal Energy Regulatory Commission, they might be allowed to buy, but they will not be allowed the premium returns.  They will not get the regulatory treatment required for such returns, and they will certainly get a lot of scrutiny with respect to their interconnection policies.

Hurdles

MR. SCHUMACHER: Bob Mitchell, Trans-Elect is involved in Path 15 here in California. Tell us the two or three biggest hurdles that you had to cross to make that project a reality.

MR. MITCHELL: When we started Trans-Elect, we made a decision that we would not get involved in new transmission because there was no regulatory incentive.  In fact, there was a disincentive.  But when I saw the announcement by the US Department of Energy that the energy secretary, Spencer Abraham, had decided to invite the private sector to become involved in the expansion of Path 15, which had been talked about for 12 or 15 years and was undoubtedly the most notorious transmission congestion point in the United States, I thought what the hell.  It took me a couple hours to bang out a response.  Then we waited to see what would happen.

What happened is 14 parties also banged out responses, and the good news was that we were selected.  The bad news was that the energy department selected 13 of us to participate.  So on a $300 million deal, we had I think 6.75% or $20 million which was way below our threshold.  But I looked at the list of others and said I don’t think most of them are going to stick around.  It turns out that none of them did.  Only Pacific Gas & Electric, the Western Area Power Administration itself and Trans-Elect ended up remaining involved.  So we are financing 100% of the line.  PG&E is financing the substations at each end of the new line.

We have had many challenges.  One was to work out a structure for a public/private partnership that never had really been done before where you have an existing utility that, by the way, is in bankruptcy, and an independent transmission company working with a federal agency.  That was a major challenge.  I think we’ve created a pretty exciting model that probably could be replicated.  We hope that it will.

Another challenge was that FERC had never given the sort of declaratory order before that we felt we would need to proceed with the investment.  We went to FERC and said this is what we plan on doing and we want you to declare in advance what the economic conditions will be.  FERC to its credit gave us a declaratory order allowing us a 13 1/2% return on our equity.  It also granted us a three-year moratorium on rate adjustments so that we could assure the people supplying us capital that things would be steady for three years.  Significantly, FERC also gave us the ability to do a hypothetical capital structure, which meant that our rate was going to be based on the assumption that the capital structure was 50% equity and 50% debt when, in fact, we were going to be able to finance the project with roughly an 80-20 capital structure.  Those three things were absolutely crucial.  Without them, we would not have been able to get our investors to take the risk and invest money.

The next hurdle was the environment in California.  The California situation is often described as being as bad as, or worse than, a third-world country.  This reputation was not without justification.  However, for those of you looking at investing in California, I want to emphasize that there is new leadership at the California Public Utilities Commission.  The new people in charge have worked a miracle at turning around the adversarial attitude, at least in the case a Path 15.  Maybe if San Diego Gas & Electric were here, it might have a slightly different view, but we had our major test two or three weeks ago where the commission had to vote whether to continue with what the previous chair of the commission had started — mainly suing FERC over our rate case.  The commission decided to drop it.  It removed itself from the lawsuit as the suit relates to us.  It essentially said it is now supporting the project going forward.  That was a very positive move.  It sends a signal to the market about investing in California.  Everyone here ought to take a look at it.

MR. SCHUMACHER: Was political risk insurance available in California?

MR. MITCHELL: Well, I told you in the beginning that I had the luxury of not having a utility background.  I do have a political background, and it gives me a degree of comfort working in that environment that perhaps somebody who does not have the same background would shy away from — and I would strongly advise them to do it. [Laughter.]

Regulatory Policy

MR. SCHUMACHER: You talked earlier about FERC’s rate of return policy.  Has the FERC policy had the effect of encouraging investment in transmission assets? Has FERC done enough to encourage such investment? If not, what does it still need to do?

MR. LARSON: Well, I think we’re all through right now.  The fact is the premium returns are icing on the cake.  Both Bob Mitchell and I were pursuing transmission projects going back four or five years without necessarily presuming that there would be favorable rates of return.  But it helped that there was a trend by the regulators toward removing control over an asset class from integrators, turning ownership of transmission for them into merely a passive investment with a low return.  In PG&E’s case, it looked like it might involve a return on equity in the sevens in a market where debt rates were in the sevens.  This makes transmission uninteresting for the utilities as an asset class.

The premiums were not put in there for our benefit.  They were put in there in order to enable us to offer prices that were at least in the range of what sellers were expecting.  Frankly at a 10% return on equity without some of the regulatory treatment that we have received — the ability to book an intangible asset — we could not have paid anything close to the prices that we have paid to sellers.

MR. SCHUMACHER: Dominic Capolongo, from a lender’s perspective, are the rates of return that are allowed on these projects by FERC a benefit in the eyes of the debt market? Do they make financing transmission more attractive?

MR. CAPOLONGO: No, I don’t think so.  As Bob Mitchell said correctly, the debt markets are looking for certainty.  They are not looking at the premiums.  They want a regulated rate of return that is fixed over the life of the debt.  As far as I can tell, all — if not all — of the financings have had maturity dates tied to the period over which the rates have been fixed.  You have not seen lenders willing to go out much longer than that.  What the lenders want is cash flow certainty.

MR. SCHUMACHER: How is the lending market dealing with the regulatory uncertainty? Regulatory uncertainty infects the entire power industry.

MR. CAPOLONGO: The regulatory uncertainty to which you are referring affects equity participation more than debt participation.  As these guys have said, the premiums suddenly opened a big door.  The result is you have a lot of people chasing these deals but not understanding the FERC situation, and not having the background to analyze the state issues with which transmission companies have to deal.  I think you will see many of those players who came running in the door go running out the same door.  You will see fewer people truly interested in transmission in the long haul.  Regulatory uncertainty affects the number of equity investors.

On the debt side, I don’t see any big change.  The ability to do long-term financing rather than short-term will be enhanced by the more regulatory certainty there is.  But financing for these projects will remain available.

Financing Merchant Risks

MR. POLSKY: I have a question for the panel.  I do not understand how people can develop merchant transmission — here you have been talking about new construction — without long-term contracts for transmission.  It seems inconceivable in today’s climate that somebody can get financing for merchant transmission.  I can understand how one can get financing to buy an existing transmission system where you have fixed revenue.  And Path 15 is a unique case where the developers were able to fix their economics in advance probably because of the political situation in California.  But I do not understand how anyone can get financing to build a new line.

MR. CAPOLONGO: You are talking about true merchant transmission.  That is why I said that for purely merchant projects, you are looking at having to cover the capital cost solely out of equity.  You will not find the debt markets receptive, at least not in the early stages.

MR. LARSON: I agree.  However, some things that may be characterized as merchant aren’t merchant at all.  I mean, you are building a rate base.  That is essentially what Path 15 is.  It is a rate-based transaction.  There is one distinction between Trans-Elect and us.  We don’t go for hypothetical structures.  Therefore, we are financed a little less aggressively.

MR. SCHUMACHER: Why is that?

MR. LARSON: Because we are scared of what the regulators might do six years from now.

MR. MITCHELL: I would just add to this discussion that Path 15 is regulated.  But there is another important distinction, and that is there is an independent system operator in California.  We were able to put the capacity for Path 15 into the ISO, and we’ve socialized the cost of Path 15 across the entire rate base in California.  If a new line is going to be built in an area where there a regional transmission organization or ISO and you have the ability to have the capacity factored into the planning process of the RTO, then it is a very different situation.

We are working to build a 480-mile line — approximately a $600 million project — called the Navajo transmission project.  It will cross three states.  There is no RTO in the southwest at this point.  I think there will be one there eventually.  We are facing all of the challenges that you articulated.  We will have to have some firm contracts in order to finance it.  If we don’t have such contracts, then it won’t be financeable.

MR. SCHUMACHER: Jon, there are certain advantages for independent generators in dealing with independent transmission providers versus dealing with public utilities.  Talk further about them.

MR. LARSON: The first one is we are willing to engineer or talk to you about whatever you feel you need to interconnect, assuming we can get it through the bidding process at the RTO.  We will also spend the money because the ratemaking mechanism in place for us is such that it means essentially that we will get a return on our investment.

There is another advantage we have over the incumbents.  Let’s be blunt about it.  When they spend the money, it means a rate increase for transmission service.  We need to be able to show that there is a positive benefit from the investment.  In the case of the International Transmission Company, we had a perfect example.  I can’t promise you will find something like this in every case, but we began to comb every single engineered project on the ITC’s books that had not been pursued.  We had people run the numbers on each of them in order to come up with an analysis of what the net benefit was in each case.  We identified one line that is basically a voltage rerating and on which we are spending $8 million to improve.  The net one-year benefit to the marketplace is $60 million.  Some of the $60 million will be captured by the power marketers, but ultimately much of it will find its way to the consumer.

That’s an investment that would have been irresponsible for Detroit Edison to have made.  It would have not served the best interest of the Detroit Edison shareholders.  It is not that the incumbent utilities are dragging their feet about investing in transmission when the RTO is trying to encourage them — although we are looking at one situation where a utility is dragging its feet and the RTO wants us to get involved.  It is not that the utilities are bad people.  They are serving the best interests of their shareholders.

The benefit of having an independent transmission company is the way we serve our shareholders is by prudently investing in transmission and frankly investing as much as we can, subject to the prudence review which means that we need to work out all the cost alternatives.

MR. WENNER: Let me ask one question about the prudence review.  One advantage of being in the transmission-only business is that both of you are subject only to FERC regulation and not to state regulation.  Are you able to go to FERC —

MR. LARSON: There are 23 committees that you have to clear before you make any investment greater than $5 million.  Twenty-three committees.