康涅狄格電力 (ES) 2003 Q1 法說會逐字稿

Good afternoon, ladies and gentlemen.

Welcome to the first quarter conference call.

At this time all participants are in a listen-only mode.

Later we will conduct a question and answer session.

I would now like to turn the call over to Mr. Jeffrey Kotkin, Vice President of investor relations.

You may begin.

Thank you, Elsa (ph).

Good afternoon, and thank you for joining us today.

My name is Jeff Kotkin (ph), and I am NU's Vice President of Investor Relations.

Speaking to you this afternoon will be Mike Morris, NU's chairman, president and chief executive officer;

John Forsgren, NU's vice chairman and chief financial officer;

Cheryl Grise, president of our utility group; and Chuck Shivery, President of NU Enterprises, which handles our competitive energy subsidiaries.

Mike, John, Cheryl and Chuck will provide an overview of the first quarter of 2003 and comment on what we see ahead of us for the balance of the year.

Also joining us for the call are Dave McHale, our vice president and treasurer;

John Stack, our vice president and controller; and John Roman, controller of NU Enterprises.

Before turning the call over to Mike, allow me to read a short statement.

Comments made during this investor call may include forward-looking statements within the meeting of the Private Securities Litigation reformat of 1995, which are statements of future expectations and not facts.

Actual results or developments might differ materially from those included in the forward-looking statements because of factors such as competition and industry restructuring, changes in economic condition, changes in historical weather patterns, changes in laws, regulations or regulatory policies.

Developments in legal or public policy doctrines, technological developments, volatility and electric and natural gas commodity markets and other presently unknown or unforeseen factors.

Other risk factors are detailed from time to time in end-use reports to the Securities and Exchange Commission.

Now let me turn over the call to Mike.

Jeff, thank you very much.

And let me add a welcome to all of you who are on the phone with us.

I appreciate that it's late in the day, but there haven't been many utility earnings reports yet.

So hopefully you'll be with us and we'll enjoy your question and answer as we get there.

I think you've seen the earnings release.

You can see that we earned $60 million in the first quarter of 2003, or 47 cents per share.

Obviously this is much better than the earnings we experienced a year ago of $18.6 million, or 14 cents a share in the first quarter of '02.

As you probably read in the news release, you'll recall that the first quarter of '02 was negatively affect by the $10 million write-down of the investment in the NEON Communications company.

Obviously NEON last year, as I think most of you know, went through and emerged from a bankruptcy filing.

And also, absent from the 2003 activities was the write-off that was taken of $28 million, or 22 cents a share that we experienced in the first quarter from the gas activities.

For this year, of course, we had no similar gains or losses.

However, as you may have seen in our annual report, we did record an after-tax gain of $2.6 million, based on the final resolution by the DPUC here in Connecticut.

CL&P's use of the proceeds case from draft to final order, which was issued after we closed the books for 2002.

And that, of course, improved their decision by reducing the disallowance by some $13 million.

The biggest area for improvement for the first quarter, however, was in our unregulated energy businesses, which earned 5.2 million compared with a loss of 20.1 million in the first quarter of '02.

Chuck will give us the details on how that turnaround occurred, but let me simply say the performance of those businesses was consistent with the earning range that we talked about toward October of last year of 15 to 25 cents a share that we continue to project for the entire year of '03.

Well, let me simply say that we're all pleased at long last to have a solid quarter which hopefully will lead to a solid year for Select Energy and the unregulated activities, particularly in the face of the flexibility and the volatility that we saw in energy prices and weather during that first quarter period.

I would like to turn the conversation over to Cheryl for presentation on the regulated activities as to the earnings by operating company.

And then she and I will tag team our way through legislative and regulatory changes going on in the regulated businesses.

Cheryl?

Thanks, Mike.

Good afternoon, everyone.

I'm happy to say that our regulated business had a very good first quarter.

It was consistently cold, but not so cold that it stressed our electric or natural gas delivery system.

As a result, sales were up significantly, but reliability was still good, too.

Residential electric sales, which is the most weather-affected, rose 15.3 percent overall, 16.3 percent for CL&P, 12.6 percent for PSNH, and 14.1 percent for WMECO.

Commercial electric sales rose 6.5 percent overall, 5.5 percent to CL&P, 8.8 for PSNH (ph), and 8 percent for WMECO.

Industrial sales, which continue to suffer from the economy, were down 1.2 percent for CL&P, 1.2 percent for PSNH, but up 3.2 percent for WMECO. (inaudible) gas probably benefited most from the weather with residential sales up 21.8 percent, commercial sales up 31.7 percent, but industrial sales down about 14 percent, primarily due to lower sales to non-firm customers.

Yankee Energy Systems earnings totaled $15.1 million in the first quarter of 2003, compared to $12.6 million in the mild first quarter of 2002.

Overall, colder than normal weather added approximately $12 million, or 9 cents a share to first quarter earnings compared with last years a very mild winter.

The cold of the normal first quarter of 2003 added about $5 million of earnings, or 4 cents a share compared with what earnings would have been during a normal winter.

On a weather-adjusted basis, we estimate that electric sales rose 3.8 percent in the first quarter of 2003 compared with the first quarter of 2002.

With the higher sales, CL&P earnings totaled $25.3 million in the first quarter compared with $20.3 million dollars in the same quarter of 2002.

PSNH earnings totaled $10.8 million in the first quarter of 2003 compared with $11.7 million a year ago.

With the cold weather, you might have thought that PSNH's comparison would have been stronger, but the sale of Seabrook on November 1, 2002 cost us about $2 million in earnings at PSNH and North Atlantic Energy in the first quarter of 2003 compared with the same period in 2002.

At WMECO, earnings totaled $6.1 million in the first quarter of 2003, compared with $6.9 million in the same period of 2002.

The decline was due to lower pension incomes, which more than offset higher sales.

Well, let me turn it back to Mike, who is going to discuss our efforts in the Connecticut legislature.

And then I'll come back and talk about a pending regulatory issue in Connecticut.

Thanks again, Cheryl.

As many of you have focused, and I think rightfully so, on the activities going on legislatively and regulatorally (sic) here in Connecticut, let us try to address those issues for you.

On the legislative side, the energy and technology environment committees have both approved Senate Bill Number 733, which includes substantial revisions to the state's landmark 1998 restructuring legislation.

Among other things, it calls for an extension of the standard offer of service for two years beyond the current 1144 termination date.

Base rates would be allowed to return to the 1996 levels, which would be approximately a 10 percent increase from current prices.

However, those prices could even rise further if necessary as we go through the implementation of the FERC-approved, standard market design activities here throughout New England.

Distribution companies would be allowed to earn under the current legislation a half-note procurement fee for every kilowatt hour that they bought on behalf of their customers.

And that fee would not be calculated in any over-earnings calculations according to Senate Bill 733.

We expect that there will be some changes as we go forward in this activity, but we are very encouraged by what we read and of course, there's lots of provisions for conversation, green energy, development of distribution -- excuse me, distributed generation and many other things, that we feel comfortable about that.

Clearly it still has to go to the entire House and Senate floor for a vote, and I'm sure it will go through some continuing changes, but we do feel very comfortable about what we have today.

We think that it's balanced.

We think that it's reasonable, and we think that it will help Connecticut's economy in going forward, and therefore be advantageous to our customers, as well as our shareholders at CL&P and at NU.

Cheryl?

Some of you may know that we recently completed an informational series before the Connecticut regulators associated with standard market design, or so-called SMD.

I saw New England implemented SMD and locational marginal pricing on March 1 of this year.

Locational marginal pricing essentially requires that areas of New England that gave inadequate transmission pay the full cost of running out of merit generations rather than threading (ph) such costs across New England, as has been done historically. (inaudible) has estimated that between $50 and to $300 million of cost will be allocated through LMP, and that most of those costs will hit Connecticut.

Eighty percent of Connecticut's costs will blow to CL&P's.

CL&P has recently received bills associated with March, 2003 LMP, and they totaled about $15 million.

Today CL&P will file with the DPUC to recover these costs by applying the considerable excess recoveries in our generation services charged to the LMP bills each month, and to apply an energy adjustment clause charge to any remaining balance.

Over the past few years, we have applied those excess VSC (ph) recoveries to recover millions of dollars a month of nuclear-related stranded costs that could not be securitized, but those expanded costs are pretty much fully collected.

We've asked the DPUC to schedule can an administrative proceeding for early next week so we will have the opportunity to reflect any changes in bills in early May.

We've asked the DPUC to conduct similar proceedings every month this year to properly reflect actual LMP costs in customers bills.

CL&P's contracts were written prior to SMD, and therefore allowed the suppliers to choose the location to which they deliver power to CL&P.

If those suppliers choose to deliver to an area with a lower LMP than Connecticut, then CL&P will incur the difference in cost between the delivery point LMP and the Connecticut LMP.

As you may know, the Connecticut attorney general believes that the contracts should be interpreted to hold the suppliers responsible for the new LMP.

Interestingly, the AG took a different position when he had filed with the federal courts to stop SMD earlier this year.

We don't agree with the AG's position that Connecticut customers should not be held responsible for these costs.

We're hopeful that the DPUC will act to add cost recovery filings promptly.

Let me also remind you that the existing supply contracts expire at the end of this year, when CL&P's standard offer needs are rebid this fall, all parties will better understand the full cost of locational marginal pricing and their impact on CL&P costs.

Now, let me turn it back to Mike for an update on New Hampshire and federal legislative issues.

One of the interesting pieces of legislation that I want to bring you all up-to-date on is in the state of New Hampshire, where both the Senate and the House have now approved a bill that would allow PSNH to retain it's 1,200 megawatt ownership of fossil hydro-powered facilities to be used to continue to serve the customers in New Hampshire at least until April 30 of 2006.

Although Governor Benson has not yet signed that bill into law, we hope that he will and have every reason to believe that this will continue not only to serve the customers in New Hampshire (inaudible) on a cost-savings basis, but also continue to serve the shareholders of NU in an equally appropriate way.

On the federal scene, although much is going on, let me tell you that we are very strong supporters of the bill that came out of the U.S.

House on April 11th.

We believe that federal backstop citing authority on any (inaudible) domain basis, we believe that shorter depreciation of transmission asset investments, additional funding for LIHEAP, ultimately the reversal or retirement of PUKA (ph) at long last and some changes in the purpa (ph) law are all very appropriate.

As Senator Domenici and his staff have been floating a potential draft proposal out of the Senate that is very different and has many issues that we and others in the industry continue - will continue to work with the Senate so that we can get to conference with a bill that may have an opportunity to at long last bring forward an energy policy for the U.S. country as we look at this very important issue.

Let me update you on a couple of other issues before I ask John to take you through some other financial activities as we face the first quarter.

First, we continue to work very diligently on our two transmission projects at the 345 KB level here in Connecticut.

You may recall that the earlier line which runs from Bethel to Norwalk is in the final phases of review by the Connecticut citing counsel.

We have been able to reach agreement with the communities along that line, and we think that with that commitment, the citing council hopefully will find their way to approval the project and will continue to move forward as smartly as we can to alleviate some of the power requirements for that section of the state of Connecticut.

We're very encouraged by the activities of the communities that joined us.

Obviously we have committed to realign the facility, going more underground than we had planned.

Although we feel very good about where we stand in front of the citing council as we sit here today.

Later this year, actually in the not-too-distant future, we will make a filing for the second phase of the line, which runs from Middletown, Connecticut also to the point in Norwalk.

That is a very massive undertaking, a $500 million project, but we believe that that loop will ultimately allow for adequate energy and competitive prices to be realized by all of the citizens of Connecticut, have a major impact on reducing congestion costs as we move forward in the implement process of standard market designs here in New England.

So we feel very good about those projects and we hope again that we'll be able to make some kinds of meeting of the mind with the communities along the Middletown to Norwalk alignments and have a reasonable hearing in front of the citing council here in Connecticut.

In March, I think many of you know that we received what we thought was a very positive decision on summary judgment motions in our billion-plus dollar case against Con Ed for failure to consummate the merger with NU back in the Spring of 2001.

The judge in that federal court dismissed Con Ed's motion for summary judgment and granted ours to dismiss the fraud and negligent misrepresentation claims lodged against us by Con Ed.

Obviously there are two sides to every story, but we feel very comfortable with that decision.

And since those issues remain no longer in dispute, we will take the case forward and hopefully good things will come our way from that.

We will be filing an order called Motions in Limine toward the end of the month in that case, and we hope to further restrict the actions that we will actually debate as we go forward with the case, hopefully later this year.

Now, let me turn the call over to John Forsgren.

John?

Thank you, Mike.

I would like to spend a few minutes with you going over capital spending and liquidity issues for the current year for Northeast Utilities.

First of all, let me talk about capital spending.

Capital expenditures in the year 2002 totaled about $492 million.

This is about $100 million below what we had projected in our 10K at the beginning of that year.

The primary reasons were a decision to abandon a plan for construction of a merchant underwater cable between Connecticut and Long Island.

And secondly, a reduction in the number of natural gas distribution projects and that our hurdle tests at Yankee Gas.

We were able to meet all of our capital spending requirements and reduce total indebtedness by more than $200 million in 2002, probably because we sold Seabrook in November.

This year in 2003, we budgeted capital spending of some $640 million, about half of that at CL&P.

At this time I would expect that most of the projects envisioned in that budget will be completed, but that a few will not ,and that spending will be somewhat below the planned $640 million level as it was last year.

I want to emphasize to you as well that our credit ratings are extremely important to us.

We worked very hard to achieve ratings that we are currently very proud of, and that we can and we will modulate our spending if necessary to maintain strong ratings and a strong balance sheet.

Along those lines, let me talk about share repurchase for a moment.

In the first quarter, we repurchased more than 1.5 million shares and issued about a half million shares as a result of our discount employee stock purchase plan, employee stock ownership plan, and our decision to issue restricted shares rather than options for employee incentive bonuses.

As a result, our share count fell by a net one million shares in the quarter to 126.5 million shares outstanding.

We still have authorization outstanding from the board to repurchase about 5.5 million shares through the month of June of this year.

That's under the current 15 million share authorization.

I doubt that we will be able to buy back that number of shares before the end of June, but I think it is reasonably likely that the board will extend our share repurchase authority beyond that June date.

On the issue of liquidity, we currently have about $95 million borrowed on our $650 million credit lines and about $50 million on CL&P's $100 million account receivable line.

That's up somewhat from year-end, primarily because we paid about $90 million in taxes on the Seabrook sale in March of this year.

The NU parent currently has more than $200 million in cash lent to subsidiaries through the system money pool.

So overall we have approximately $100 million of net excess cash in the system as of the end of the quarter.

We feel very comfortable with the current liquidity in the system.

So although we do not need to issue long-term debt at this time, we are considering several opportunities to do so because of the current interest rate environment and capital market situation.

We have the opportunity to fund out some of the short-term debt, and we are contemplating doing so in the form of an NU medium-term bond in the amount of $100 to $150 million dollars.

Also we have applications in place to refinance some $200 million in spent nuclear fuel obligations at CL&P, and about $50 million at Western Mass Electric.

Given the current low interest rates, as I said, we are also considering fixing out another $50 million in short-term debt at WMECO, money that WMECO is essentially borrowing from the parent right now.

Whether or not we go ahead with the latter financing is dependent largely on rate treatment granted by the regulatory agencies.

Given the strong first quarter (audio gap) earnings for the year.

After all, in the first quarter we've earned about 42 percent of the bottom end of our projected range of 2003 earnings.

One reason we're not doing so at this time is that we expect the earnings comparisons in the second half of the year to be weaker.

Due mostly to weather patterns last year, regulated sales were up 6.4 percent in the third quarter of 2002 from the same period the prior year.

And in the fourth quarter they were up 3 and a half percent from the prior year.

We never budget or project that weather patterns like that would recur, and so that we expect will be a negative comparison.

Also the sale of Seabrook provided us with significant benefits in both the third and fourth quarter.

And other regulatory decisions related to strand and cost recovery and investment tax credits gave us significant benefits in the second and fourth quarters of '02.

Finally, as you know, we are expecting more than a $40 million reduction in pension income this year from the level of approximately $70 million to about $30 million.

While some of that is capitalized, lower pension income is likely to be a drag of about 3 to 4 cents per share each quarter this year, primarily at the regulated companies.

Finally let me address the dividend.

During each of the last two years, the annual board of trustees has voted to raise the dividend at our annual meeting.

This year's annual meeting will be held on May 13th.

And as we have said in the past, we expect the board to reaffirm the continuing increase strategy and the dividend level at that time.

At this time, I'll turn the call over to Chuck Shivery.

John, thank you.

As noted by Mike and in the news release, we had a significant turnaround in our competitive businesses in the first quarter.

I was pleased with how we managed our book of business in the face of rapid increases in natural gas prices, rapid changes in weather, and the implementation of locational marginal pricing in New England.

Our wholesale group, which includes not only generation, but also the marketing and our small trading operation, earned about $7 million in the first quarter of 2003 compared with a loss of about $6 million in the first quarter of 2002.

Results last year were hurt by losses of approximately $10 million in the trading operation in that first quarter when natural gas prices rose significantly in March.

And we've discussed that with you in the past.

Now energy trading is just a small adjunct that helps provide price discovery, market intelligence and provides our marketing group with execution to allow it to manage its full requirements contracts.

The wholesale group had a strong first quarter booking of new business.

On March 1, we began serving central Maine Power and Bango-hydro (ph) under a new six-month agreement that would generate $30 million in revenue.

We also announced that we had won 1,200 megawatts in the latest version of the New Jersey BGS, or basic generation service auction.

Seven hundred megawatts are for 10 months, and 500 megawatts are for 34 months.

Both of those start August 1.

Finally, we won a new contract with National Grid for default service that starts next week and runs for six months.

That will bring in about an estimated $75 million of additional revenue through October.

In terms of new contracts, bids are due in May for WMECO, or Western Mass Electric's default service for the second half of the year.

As you may recall, we served that roughly 100 megawatt load the second half of 2002, but we are not currently serving it.

At this point, I am comfortable that the wholesale group will bring in the annual margin that we expect.

Our retail marketing group lost about $2 million in the first quarter of 2003, clearly performing better than the first quarter of 2002 when they lost about $14 million .

Last year our demand was well below expectations for the entire quarter because of weather, and also because we were required to sell gas into the market as the market was declining.

For the balance of this year I'm hopeful that we'll reach our goal and break even as we said in October when we were down at EEI that we anticipated the retail operation to break even.

To date, however, we've only signed up about 40 percent of the margin that we need to cover those costs and break even.

We found that retail gas customers have been very hesitant to commit to long-term contracts during this period of high prices.

We are serving a lot of these customers on a month-to-month basis, but the margins tend to be smaller.

With the gas prices now trending downward, we believe the business will improve as we move forward.

Our two services businesses, Select Energy Services and Northeast Generation Services earned a combined $400,000 in the first quarter compared with a loss of about $400,000 in the first quarter of 2002.

This was better than last year, but slightly below budget, and it was in part related to the weather which prevented us from moving forward on some of the construction projects.

One benefit we did receive from the weather was a return to more normal precipitation in our hydroelectric plants generating more output.

They increased their output by about 40 percent compared to last year's very dry quarter, but still, even with that, we were about 14 percent below normal.

Because of the cold weather essentially it froze and we didn't get the water run.

For the remainder of the year, we continue to feel comfortable with the competitive business earnings range of 15 to 25 cents a share which translates roughly into the $20 to $30 million of earnings.

Now let me turn this back to Jeff.

All right, thank you very much, Chuck.

And let me turn the call back to our conference operator.

Thank you.

You will now begin the question and answer session.

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If your question has been answered and you wish to be removed from the queue, please press the pound sign.

Your questions will be queued in the order that they are received.

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Once again, if there are any questions, please press the one on your touch tone phone.

One moment please.

We have Michael Goldberg (ph) from the (inaudible) Management (inaudible) with a question.

Please go ahead.

Good afternoon, gentlemen.

Congratulations on a good quarter.

Thank you, Michael.

Can you please tell us what the earliest the Con Ed trial can start?

Well, it's very hard for us to predict that.

As I mentioned, we will be filing the Motions in Limine.

The schedule for that is for the end of this month, and then no different from the petition for summary judgment.

The judge has no time line, obviously.

He and his staff will read those motions and make some kind of determination.

I'm sure there will be some oral presentation associated with it at which time we may have a better feeling for when he might issue an order as to those facts, and then we might begin the trial.

So it's very difficult to forecast when it might happen.

Our hope is that it's a matter that gets under way this year.

Again, we feel very comfortable with our position.

And we feel it's time to bring that matter to resolution.

Thanks.

Just two more quick questions?

Yes, sir.

One, why is the (inaudible) so much higher in this quarter versus previous quarter?

You're talking about the increase from $20 to $57 million?

Yeah.

Okay, let me ask John Stack to pick that up.

Sure, that's primarily due to the price of energy.

And CL&P still has some IPP contracts their self sic (ph) that they're selling into the open market.

And we're getting - the revenues we're getting from those IPP contracts are much closer to the price that we're paying.

Therefore we had, we're able to amortize more stranded costs as a result of the that.

Okay, so it's amortization of stranded costs.

That is correct.

Which is really a good thing.

That is correct.

Okay, and just one final question.

In the previous call you've stated that you pretty much hedged out the CL&P contract for '03.

Given this relatively high weather in the first quarter, during any point in time, did you have to buy purchase power?

Did you have to buy power to satisfy the contract?

If we -- Michael, if we look at all of New England, and we really manage this as a portfolio, there were hours during the day when we were long and there were some hours during the day we were short.

And we were selling into typically what were the higher priced hours during the day and buying back during the lower priced hours during the day.

Okay, thank you very much.

We have Jay Zeamello (ph) from UBS Warburg on line with a question.

Please go ahead.

Good afternoon.

And I think my question could be for Chuck.

With regard to Select, does the size of the trading portfolio - I think at year end it was - the fair value was $41 million.

What was the change?

And what does the book look like at the end of the first quarter?

The total mark to market value at the end of the first quarter is about $46 million .

That's not only the trading positions, but there also are some positions in the wholesale book that by their nature are also mark to market, and that's included in that number.

Okay, so roughly what part of 1Q '03 was mark to market?

And what was the tenure of it?

The gain in 2003 from mark to market was about a million dollars.

And if you look out at the whole $46 million mark to market portfolio over the period of time, about one half of it will probably be recognized within the next couple of years and then the rest of it spreads out, but a lot of that is already locked in.

Okay.

I see that in the this, okay, thank you.

Our next question comes from Jeff Gildersleeve from Argus ...

Please go ahead.

Thank you.

Good afternoon.

Good afternoon, Jeff.

And perhaps this is probably Chuck as well.

I was interested, it seems that things have picked up, especially what's not here in the first quarter is to BGS auction in the second half of this year.

I'm just wondering, you know, at what point does the up side to this business start to, you know, exceed the range you've laid out?

And just if you could talk about what the rest of the year looks like?

Well, we feel very comfortable with the earnings estimates that we gave you before, the 15 to 25 cents.

I think on the conference call that we had in January, I outlined about what we already had locked in on the wholesale business, and it was about 50 percent in most of the areas PJM (ph) and New York.

And I think we needed about $5 million more in New England.

We've made significant progress on that from the origination side.

We've probably completed about 85 percent of the total margin we need for this year already.

Okay, and when you speak of that, you're speaking of the whole non-regulated side, or just Select or...

No, that's just the wholesale side is Select.

If you look at retail, it's not quite that good.

We've probably locked in about 40 percent of the gross margin right now that we need for the year.

And then in the services business, they're in excess of 60 percent of the margins locked in.

Okay, and it seems you're most sort of concerned on the retail business, and there seems to be quite a bit of work to do there.

Going into the summer months, is this, I mean a critical time to start securing some of that margin?

Oh, I think it's a critical time to start securing some of that margin right now.

Right.

We do need to get some of the retail sales up and we're spending a lot of time doing that.

I think, Jeff, you'll remember that much of the retail business, because of the habits of the buyers throughout our service territory and the 11 states we focused on is on the gas side.

And with gas price bouncing around as they did early in the year, particularly reaching as high as 10 or 11 dollars (inaudible) up here, people who are buying oil are not buying long-term.

Now that gas is selling down, we hope that the retail voids will continue to be more successful.

In fact, just this week, they signed a contract to do some activities we'll be announcing in the not-too-distant future.

But Chuck is right, though, it's time to sign that stuff up today and not wait for the summer.

Great, so it seems like as prices have come down, there's a little bit more participation.

We're seeing that, yes, sir.

Okay, thank you very much.

You're welcome.

Our next question comes from Philson Yim from Morgan Stanley.

Please go ahead.

Good afternoon.

Good afternoon, Philson ...

I may have missed it.

Did you talk about -- did you quantify the revenues you're expecting from the BGS, in your BGS contracts?

Yes, we did.

And we did it actually in a news release that we put out a little while ago on April 14th, and the BGS contracts, hang on just a second, I'm looking for that. $400 million for the total and the 10 month contracts are about one third of that.

Okay, so 400, okay.

In the previous contracts, wasn't it $475 million annually?

I think that's right.

Okay, but then you have some residual revenues from that, so on top of the new contracts, you should be having some growth there?

Yes, there are residual revenues from the old BGS contracts until that's over and then the new contract starts.

I see.

And again, some of these stretch out for 34 months, which gives us a base as we move forward in the out years.

I see, great.

Thanks very much.

Thank you.

Our next question comes from Greg Flora (ph) from Lehman Brothers.

Please go ahead.

Thanks.

Good afternoon.

Good afternoon, Frank.

Hi, two questions.

The first one, I guess was for Chuck on gross margin forecast.

I think you were talking of percentage of total for the year locked in.

Could you give us either a forecast of gross margin for the year or even, you know, by the business segment?

You're asking for gross margin for each of the different lines?

Is that what you're asking for, Greg?

Yes, that would be ideal.

Okay, well, I'm not sure we can provide the ideal answer right now, but let's - thanks for the question, Greg.

What we have said before, Greg, I think was that we gave you by business line an order of magnitude of net income that we expected to come from each business line.

Okay.

And, you know, that's pretty much the disclosure I think is appropriate rather than specific gross margin numbers for each business line.

I mean clearly, we have to manage the gross margin coming -- we have to get the gross margin coming from the sales, we have to manage the portfolio and we have to control the expenses, but we think given the position that we're in on the wholesale side of the business that we're in very, very good shape for the year.

And as we have stated earlier, we've got some work still do on the retail side.

And in the services business we feel pretty comfortable about where we are going forward.

Okay, and then you also talked about, you know, the application in Connecticut that you are going to make for recovery on the LMP charges ...

Yes.

... for the first month.

Could you walk through just sort of what the adjustment is within range?

I think it was under an energy adjustment clause?

There are two ways that we're hoping the commission will agree with us on recovering these costs.

And we hope that the ways that we have proposed to the commission will have a very small impact on the customer, which should allow for that to happen.

The billings for the month of March have come in at $15.5 million, although ISO New England continues to work on line-lost abatements back to some customers, and we don't know exactly what the impact of that will be, but let me take you through the view as we see it today.

Each and every month, because of a very wise decision by the DPUC, we collect what's called a retail adder to the cost of the generation service charge.

And of course, that amount of money builds up month over month.

And our hope is that we will offset some of the $15.5 million with the monthly over-collections for the GCS.

That would leave about $9 million for the energy adjustment clause, which is a clause that continues to be used by all of the utilities here in Connecticut, even after the 9828.

And it's really a remnant of days gone by on means to clear through costs that either are below or above what you had forecasted to recover in your base rate.

The contemplation for March would be that that rate would go to six mills (ph) per kilowatt hour.

That would mean an average customer using 500 kilowatt hours per month would see a $3 charge to amortize this month's LMP charges.

And we feel again that this is a very creative way to address this.

And we surely hope that the commission will agree with us in that regard and allow us to service these federally-charged costs in a very reasonable way as we go forward.

Clearly that's an open issue as Cheryl mentioned in her comments.

There are others who see the contracts differently.

But we feel comfortable about what we have filed.

And we surely feel these are federally-approved rates that need to be recovered through 9828, which is very clear restructuring law in Connecticut, which is very clear about how these issues are to be dealt with.

And we just hope that the commission will see it the same way, Greg.

Okay, thank you.

Our next question come from Zack Stryber (ph) from the Lapine Capital (ph) .

Please go ahead.

Hi, Mike, hi, John, hi Jeff, hi Chuck, it's Zack Stryber.

Hey, Zack.

Hi, on this $15.5 million of LMP charges, is there any way to break down in terms of what the experience was in March, what that would imply for the full year in terms of where we fall in this $83 (inaudible) million range for all of New England, and then the portion that's applicable (ph) to Connecticut?

That was the first part.

And the second part is, if I understand this right, there's several buckets of these costs, some of these costs were billed directly to CL&P.

Some of them were billed to Duke and to NRG (ph) and to Select who then sort of remitted them on to CL&P.

Is there any way to differentiate between that?

And are the great preponderance of the costs billed directly to CL&P so CL&P - the DPUC cannot shirk the kind of recovery of that?

And is it right to differentiate between those bills that are direct to CL&P versus those that are sort of passed for suppliers from the (inaudible) and ISO and then remitted from the suppliers to CL&P?

Well, let me, as you typically do, Zack, your multi-tiered question is right on point.

But let me try to address that.

The fact of the matter is the dollars can be broken out by contract, but because of the privacy of those contracts, we have asked the commission to treat that in a protective way.

And therefore I'll continue to treat it in that sense.

There are different buckets.

NRG's (ph) contract is different than Duke and Select, and that is exactly as you point out, some of them are directly billed.

I wouldn't characterize it as causing then the DPUC to be forced to deal with it.

This is an issue that the DPUC clearly has an opportunity to come to whatever conclusion they would like.

We believe the contracts speak for themselves, and we think that's the appropriate way to recover it.

As to the start of your question, our experiences in March were heavier on line loss, which is an activity that the ISO is continuing to refine and review, because they changed the way that line losses are allocated to load servers as we implemented standard market design.

And the second phase of it is, of course, congestion.

And because of the lower demands, we didn't see much congestion.

We did when Millstone, too, fell off line for a short period of time.

We expect that going forward we're still probably in that hundred to $200 million range for the year.

We do expect that a good chunk of that will come to Connecticut because of the congestion that we experience in the southwestern part of the state, but we continue to manage that at CL&P.

I think you know that we have put in some activities on the transmission grid that allow for substantial additional power to flow into southwest Connecticut to hopefully dampen the congestion costs as we go forward.

And we have done remedial work on a cross-town cable that was damaged earlier in the year by a runaway barge, actually in the last part of 2002.

So we will be able to, we hope, be at full peak shaving opportunities for energy coming into the region on the cross-town, our cable, which is not the cross-town cable, I really didn't give that name inappropriately.

So again, we think we're going to be able to manage our way through these costs.

They might not be as big as people are forecasting, but even so, the older collections on the retail letter (ph) is going to be something in excess of $100 million.

So if the commission thinks the way that we're doing this is the appropriate way to do it, the impact on the customers is going to be very, very small.

If we get, you know, maybe $5 a month for the remaining -- well actually that would be mostly through the four summer months, that's $20 for the year for a customer, which is really diminimous (ph).

In terms of this $100 to $200 million, Mike, a large portion of it allocatable to Connecticut, what do you think breakdown is between CL&P and United Illuminating (ph)?

I mean, is there any major congestion issues in the bridge port area and that would make a big portion applicable to them, or do you think most of it falls on CL&P?

Well, I think it's pretty clear.

Just on customer account it's about 80/20 on a percentage breakdown, but the UI of course has a different contractual structure with Dominion as we understand it.

I'm just trying to figure out what portion of those costs would be sort of UI and Dominion's issue, and what portion of it would be CL&P's issue to work out with itself.

It's about 80/20, Zack.

And again, so long as the commission sees fit to treat it the way we have, it's a pretty creative way to (inaudible) really help the customers help the economy here.

Is there any precedent to kind of use, I mean, as you said, that this ECAC (ph) is kind of a vestige of the past in terms of a pre-sort of landmark restructuring legislation regime.

Is there any precedent for using the ECAC to recover these kinds of costs in the state?

Yes, we've actually been doing that all along since 9828 has been employed here on any one of a number of other occasions.

You know, as you know and John pointed out on the amortization answer, we do have the IDP contracts.

Right.

We sell those into the market.

Sometimes that yields a lot of money that we flow back through the EAC (ph).

Sometimes it doesn't yield as much money as we pay to the IPP suppliers and we recover that through EAC (ph) adjustments.

Got it.

So, this is a perfect vehicle to use and then it's been used like that over the last three years and three months.

Just two more real quick questions on this, Mike.

Has there been any preliminary response from the commission?

I know there were some technical, sort of educational workshops on this issue.

Has there been any sort of preliminary feedback from the commission on this?

No Chairman Downs (ph) made it very clear at the technical meetings that he wanted it to be educational so that we could all understand the delta between how billings used to come on the pre-SMD implementation and how they're now coming.

So, no, there hasn't been any preview of it whatsoever.

And the final question, Mike, is you mentioned some differences between the NRG contract versus the Select and the Duke contract.

I was wondering if you could just explore that a little bit.

I had been under the impression that the contracts had been relatively similar based on the way the auction was set up going back a few years so that Select could participate in the contract and not violate any affiliate rules?

Well, yes, and the only difference here is how they're being handled administratively.

Duke and Select have agreed to help coordinate the ultimate delivery of the energy to the point of consumption in Connecticut, and NRG (ph) has chosen not to do that.

So it's really more of an administrative matter and a helps to CL&P to help manage costs because, you know, those Select and Duke guys are in the market day in, day out, where the CL&P folks really aren't.

Got it.

Thank you so much.

You bet, Zack.

Thank you.

Once again, if there are any questions or comments, please press the one on your touch tone phone.

We have Norman Greenberg (ph) from Greenberg Consultants (ph) on the line with a question.

Please go ahead.

Hi, I was just wondering on the transmission line, (inaudible) involved in that, but I'm ...

Norman, thanks for the question.

The way that the Federal Energy Regulatory Commission has already spoken to the first phase of those two phases, the lines will actually be, the cost for building the Norwalk-Bethel line will be socialized over the entire New England region as it should be because these are really for the benefit of the entire New England region.

They will allow the excess generation in certain pockets to continue to flow throughout the region in a less congested way.

So we'll all see the benefit of it.

And the FERC has already issued a rule in that regard.

I would tell you that Maine and Vermont aren't real happy with that rule, but as we look at congested Boston markets in the north of Boston, we look at a bit of a congestion between Maine and New Hampshire, and a bit in Vermont coming into Massachusetts.

We're all going to share in what are considered to be knee pool kinds of transmissions so that it helps power to flow throughout the region.

They have also led us to believe that the phase two line may have the potential to be treated in the same way.

And we think again it's justifiably so to be treated that way.

And those agreements, if then passed by the FERC, have an automatic flow-through process through the ISO, through the local rate-making authority in all of the states.

So we feel again, very comfortable about how those projects will flow into rates.

And remember, if you look at a delivered kilowatt hour, the transmission portion of that is mills, not pennies.

So again, it has a very small impact, particularly when you get to the customer benefit on a region-wide basis and moving the excess generation.

And there is plenty of it here in New England and to the pockets of heavy demand.

I'm never worried about the cost of that.

I'm always worried about the backyard, the NIMBY problem.

And I appreciate that.

And having gone through that in Norwalk, I think our transmission group, our communications group and our legislative group deserve a tremendous amount of credit for bringing that to a very meaningful resolution, to a very meaningful resolution.

And I will tell you that on the Middletown to Norwalk sections, which have already begun with some local officials, we're getting tremendous credit and good will because we were able to reach those resolutions.

I'm not trying to say that that's going to be a walk in the park, it won't be, because a lot of people love to have the light switch work when it's flipped on.

They just don't want to know where the power game from.

Yes, they just don't want disconnection, that's all.

Okay, thank you very much, congratulations.

Thank you.

Our next question comes from Fivrel (ph) from SLS Capital.

Please go ahead.

Thank you.

Let me make sure I understand this.

The LMP costs, your guidance does not contemplate either CLP or Select taking any hit from this change, that you'll be able to recover the entire cost from your customer base?

Yes, sir.

Once again, if there are any questions, please press the one on your touch tone phone.

We have Michael Goldberg from Luminous Management on the line with a question.

Please go ahead.

Hi, Guys.

Just wanted to follow up, I think I missed that number.

Out of your wholesale marketing and trading, what percentage of gross margin have you locked up already?

Michael, this is Chuck Shivery.

We've probably locked up over 80 percent on the wholesale side of the business already for 2003.

Okay, and it's 40 for retail and 60 for services?

Yes, it's about 40 percent of the gross margin locked up for retail.

And the two services business differ, but I would suggest that it's probably in the 60 to 65 percent when you average the two of them.

Okay.

Thanks.

Thank you, Michael.

Our next question comes from David Thickens (ph) from ...

Please go ahead.

Thank you, Michael actually just asked my question.

Well, good, David, thank you.

At this time, we have no further questions.

All right, well thank you very much for joining us today.

We appreciate it.

If you have any further questions, please give me a call in the office and have a good evening.

Thank you.

Thank you, ladies and gentlemen.

This does conclude our conference for today.

Thank you for participating.

You may now disconnect.