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The Hottest Seat in the House
NU gambles that new top dog Morris can save the day
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Business New Haven
12/29/1997
By: BNH
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Perhaps no Connecticut company has endured more trauma or faces a less certain future than Northeast Utilities. The Berlin-based utility provides electricity through subsidiaries in New Hampshire, Massachusetts and Connecticut. Michael G. Morris was named chairman, president and CEO in August to guide the company through its nuclear-generated woes and into the potentially stormy waters of a new deregulated environment. Morris has 25 years' experience as a utility executive; he was president and CEO of Consumers Energy & Gas, a $4.3 billion subsidiary of CMS Energy of Dearborn, Mich. BNH asked Morris to address the utility's financial and regulatory challenges, deregulation and nuclear power generation issues.
When you were interviewed for the job, what was attractive to you considering all of NU's difficulties?
That was part of the attraction. Consumers Energy had been in some very similar situations, and I had played a significant role in helping them, pulling themselves out of a pretty unfriendly relationship with regulators in Michigan. I had [similar nuclear difficulties] at Consumers, although nothing quite as dramatic as the situation at Millstone. I had done some of this before and there was an opportunity to do it from the No. 1 chair.
Is the regulatory environment similar in each of your service states? Is it more hostile in one vs. the other?
I don't think hostile is the right word. There are different regulatory challenges in each of the three states. Today, the average outsider would say that the environment in New Hampshire is more hostile toward NU then it is in Connecticut or Massachusetts. The fact is I don't really believe there is any hostility there. What is there is a challenge and a desire for customer choice. Every state has its own [deregulation] undertaking. All but New Hampshire chose a traditional cost-of-service model for defining stranded costs. New Hampshire chose a 'region average' price, which unhooks the transition from the Financial Accounting Standard Board requirements that are placed on utilities. That had a dramatic impact on the in-state utilities and PSNH, our subsidiary in New Hampshire, was most impacted by it.
Stock market reaction to a possible sale of assets in New Hampshire seemed to be very positive. Did you agree to sell your system there?
No. A New Hampshire electric cooperative made an unsolicited proposal to buy the delivery system. Although it is an interesting proposal, it seemed to us that it was a bit premature and not necessarily well thought-through. The financing was not in place.
Why did the stock market see that as a positive?
That goes back to the question of the hostile environment. The 100-year, 50-state history is that utilities that don't get along with their regulators don't do very well. So the [Wall Street] theory was: Here's a one-time opportunity to get out of this terrible environment and walk away with some money.
How do you see deregulation playing out differently among the three states?
Most of New England is following a very similar path. Rhode Island customers will be free to select their providers beginning early next year. Massachusetts has a law and a hope for implementation in March of [1998]. All of the commissions in New England and the legislative bodies are coming to the conclusion that you have to address investments that were made in the old model. The divestiture of your non-nuclear power facilities seems to be a concept that is being embraced widely, and that is a requirement in Massachusetts. We already committed to do that in New Hampshire. Although the Connecticut legislative activity is only in the very beginning stages again, it may be that divestiture is a requirement in Connecticut. If it is, we'll be prepared to do that.
Does that mean separating generation and distribution assets?
In a very real sense. We will put [generation] assets on the market for sale.
What would NU's business then be?
We still would like to have the freedom to enter the auction ourselves and place a bid. If we're successful in that effort, we'll have a segregated business but still be in the generation business.
The grid is one company and power-generation is another?
And then the marketing entity would be yet another company. As far as the generation end of the business, we've been in it for over 100 years. And notwithstanding the current challenges at Millstone, we're pretty good at it.
When you refer to stranded costs, you mean in generation as opposed to the distribution system?
There really are no stranded costs on the distribution system. We're talking about four principal areas [of stranded costs]. One is the generation assets [power plants]. The process that we went through is you need to serve all the growth in these market areas, and that power plant is going to be in operation for 40 years. So [regulators] will allow you to recover your capital investment over that 40-year period. We are now in the 20th year of depreciating plant X; the 15th year of plant Y. You can't come in now and say those plants will no longer serve these people and you therefore can no longer collect these dollars. There's another piece called regulatory assets. A few years ago it became very important to do what was called demand-side management. In essence you spent a lot of money to dampen the growth in energy consumption.
You mean like NU putting insulation in my basement?
Exactly, but on a much larger scale, like in a Pratt & Whitney facility where we would spend $10 million so their peak demand would be reduced. The regulators said, Let's collect it over ten years. Well, you're in the third year; again you can't just say forget the regulatory assets, you can't now collect them. A third category has to do with independent power purchase (IPP) agreements. We entered into contracts with qualifying facilities and we are duty-bound to buy from them. Those contracts run 20 years. The last cost is a transition cost. For customers to be able to buy in the open marketplace, we have to have a totally different billing system. A number of our employees are going to have to be retrained, and there may be some downsizing. Those are true transitional costs that have to do with being able to allow the customers this freedom to choose.
It's the stranded nuclear costs that have really created the most controversy, right?
Only because it's nuclear power. It's exactly the same issue. It's a capital investment that you were going to recover over 40 years, and now we're saying after the tenth year you're no longer going to do that. Whether it's a fossil plant or a dam or an IPP contract - they're all the same. Now, you raise two very real issues. Nuclear brings its own emotional issues with it. And two, the capital is huge.
Isn't the problem that nuclear plants are not considered as competitive as other plants? Because if they were competitive, there wouldn't be stranded costs?
In every industry that's gone through that transition [to competition, companies] all recovered stranded costs. In the telecommunications business, they all recovered capital - they called it accelerated depreciation. Now the local [phone] company that didn't want to have to pay any of the AT&T stranded costs are saying, We need to recover our stranded costs. When you transition from a 100-year model to a new model, all that freedom isn't free. It has to be compensated for.
Some would say NU made this nuclear mistake, and now ratepayers have to pay for it.
It was never a mistake. Remember, we're in the northeast quarter of the U.S. Bringing coal in here to make power without environmental concerns wasn't a viable 1970s option. Bringing oil in here from Texas or from Iraq and Iran wasn't a viable option. The federal government had passed a law saying you couldn't use natural gas for power production. There were no more rivers to be dammed in New England to make huge power production. So if New England was going to have an energy base, it was going to be nuclear fuel. The costs of nuclear plants after Three Mile Island became prohibitively high. But you were already in a cycle where people were eight, nine years into the construction cycle and they needed to finish because this part of the country needed the power.
Will gas-generating plants be built by the dozen to match the capacity?
That's the general belief: that the competitor will be combined cycle gas-fired facilities. They are smaller. For years there was an economy of scale in the power production business that said if 500 megawatts was good, then 1,000 was better and 1,500 was better yet. The technology has turned around now that you can use natural gas. Jimmy Carter forecast in 1972 that by 1990 there would be no gas production in the U.S. - zero. We made a huge forecasting mistake.
Even a gas-generating plant takes a long time to come on line. Are we talking about Canadian electricity or from New York, and is there power transmission into this area for that?
Quebec Hydro will be a major competitor. Some of the New York power will be competitive. Is there sufficient capacity to import all of that energy? The answer is no.
So we would have to build new transmission lines?
And if you think it takes a long time to build gas-fired generating capacity, you should see the time it will take to build an EHV transmission facility.
Well, doesn't that moot the issue of these costs being stranded, if there isn't going to be any real competition for ten years anyway?
No, there will be plenty of competitive power that comes into the marketplace. Like any supply-demand situation, as long as there is an overhang, prices will come down. And there is an overhang in the marketplace. There will be plenty of competition.
Which consumers will benefit most?
In any competitive marketplace you will get volume discounts for volume buying. But the way the states are going about doing this, with an eye toward savings for residential customers, everyone will benefit. One of the beauties of this issue is called “securization.” Securization is taking the current capital invested in the facilities and the regulatory assets that are going to be stranded by this model, and replacing the current cost of financing that with AAA-quality securization bonds. And all of those refinanced savings will be passed directly to the ratepayers.
In the Massachusetts model, was there some portion of stranded costs that weren't being allowed?
No, the Massachusetts model provides for 100 percent of the defined stranded costs. All the things we call stranded costs are already in the rates. This isn't a new cost item; there won't be any argument about money that was written off at Seabrook II. The shareholders have already suffered that loss.
When the state auditor's report was issued on the Millstone plant claiming past problems at the site, that seemed to get highly politicized very quickly.
Customers in Connecticut are not paying for the power we are buying to replace the power that isn't being produced at Millstone. They are not paying the increased expenses we are incurring to bring the Millstone units back on line, and they shouldn't be asked to and they won't be asked to.
What about the decommissioning costs?
It's an interesting debate. According to federal law, nuclear power plant operators are required at the end of the operating life to totally de-fuel, dismantle and decommission the facility so the site can be put back to a pre-power plant use. You're authorized to recover from your customers a decommissioning charge. Over the years at Connecticut Yankee, we were under-recovering what we were forecasting we would need to spend to decommission the plant. So the debate today is over our forecast that it will cost $427 million to decommission that plant.
What have you collected?
$225 million of it.
Isn't the argument from state officials that it shouldn't cost $427 million, and that the high costs are the result of NU mismanagement?
Right. The attorney general's view of it is that there was not sufficient radiological control at the site, and therefore Connecticut customers should not pay the total bill. What's in the $427 million for radiological control is about $12 million. There's a proceeding in front of the Federal Energy Regulatory Commission to determine how much we are going to recover to decommission Connecticut Yankee. This debate has been held in other jurisdictions over other decommissioned plants. Yankee Rowe cost $400 million; Fort St. Vrain in Colorado cost $350 million; and the Trojan plant in Oregon cost $400 million. Connecticut Yankee is going to cost $400 million, plus or minus, to decommission.
At the time of the auditor's report, headlines such as 'Nuclear Nightmare' must have made you folks pretty unhappy. What was the source of that kind of response?
The source of most of the comments
that caused everyone to feel justifiably concerned came out of the attorney
general's office.
The governor was pretty vocal as well, we recall.
The governor joined in on that issue in
a justifiable sense as well. Because if that were true, we should all be alarmed. What we were asking the governor and the attorney general to do is gather
the facts before we come to those conclusions. Now, months later, many of the facts are in, and what we are beginning to learn is that those statements were a bit beyond the reality of what's being
discovered.
Has that PR nightmare damaged
NU in terms of the outcome for deregulation?
I would hope not. Individual legislators are above that type of activity; they'll make their decisions based on what they think is best for their constituents. I think you're beginning to see a coalescence around the idea that competition makes sense. And that recovery of the stranded capital invested and the regulatory assets probably makes sense. Hopefully, they'll believe that securitization makes sense, because you pass those savings on directly to the customer.
And that's basically the strategy NU has for embracing deregulation?
Absolutely, and therefore if done properly, we are 100 percent behind competition. Ultimately, as it has in other industries, it will lead to price reductions.
Is refinancing the main place we will realize savings?
You and I as small consumers - that's where we save money. If you're big enough to be a large-volume buyer, you'll probably save some money on the commodity of electricity itself.
Does deregulation mean that NU will find itself in other New England markets?
We're already there. In the Rhode Island pilot, the NU subsidiaries were most successful and captured 70 percent of the market.
So you can get the benefit of your current customers paying your stranded costs and then go out with new markets and pick up additional benefit that way?
There is the potential to have your revenue base grow. The reason that a utility like NU would embrace competition is you've allowed me to recover
yesterday's investment, and therefore these plants are going to be competitive in the marketplace. If we sell energy
out of those plants, we expect to do it at
a profit. You obviously can't make it up on volume.
In most cases a company will transfer all its costs to all its customers?
But you won't be able to transfer any
of your power production costs to any of your customers. That's part of the deregulated model. It's not a belt and suspenders; it's a pure risk model.
How do the capital markets view NU's challenge?
The major advancement in the value of NU's stock is going to be impacted by two or three principal events that we hope happen in the not-too-distant future. Bringing the Millstone III station back on line should be a very positive stock event. Finding some resolution to the restructuring debate that continues to rage in New Hampshire and getting a restructuring bill in Connecticut [are the other two]. Wall Street doesn't like to deal with uncertainty. When those things are done, hopefully in 1998, we'll be viewed more like your typical utility. Our multiples will be based on the analyst's view of how successful we'll be in that competitive model in New England.
Where do we stand with Millstone and what is the likely time frame?
The units are off line and we can't bring them back on line with our own management decision; we need to receive the authority of the NRC. We continue to make reasonable progress toward that end. I would hope that some time in the first quarter, and no later than the second quarter, we bring the first unit back on line. Financially, we're prepared to weather that storm. Then there are a number of evaluations that have to be done by third parties. All of those evaluations will raise an issue or two. We'll have to react to those issues. We don't know how long that evaluation and reaction process will take. I feel comfortable that will happen in the early part of '98. And when that does happen I think you'll see some very positive reaction out of Wall Street.
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