康涅狄格電力 (ES) 2004 Q4 法說會逐字稿

Good morning, and welcome to the Northeast Utilities Q4 investor relations call.

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

Following the presentation, we will conduct a question-and-answer session. (OPERATOR INSTRUCTIONS).

Today's conference is being recorded.

If you have any objections, you may disconnect at this time.

Now, I will turn the call meeting over to Mr. Jeffrey Kotkin, Vice President of Investor Relations.

Good morning, and thank you for joining us today.

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

Speaking with you this morning will be Chuck Shivery, NU's Chairman, President and Chief Executive Officer;

David McHale, NU's Senior Vice President and Chief Financial Officer;

Larry De Simone, President of NU Enterprises, which houses our competitive energy subsidiary;

Cheryl Grise, President of NU's Utility Group; and Lee Olivier, President of NU's Transmission Business.

Chuck, Dave, Cheryl, Larry and Lee will provide an overview of 2004 results and comment on what we see ahead of us for 2005.

Also joining us for the call is John Stack, our Vice President and Controller.

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

This call will contain statements concerning NU's expectations, plans, objectives, future financial performance and other statements that are not historical facts.

These statements are forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995.

In some cases, the listener can identify these forward-looking statements by words such as estimate, expect, anticipate, intend, plan, believe, forecast, should, could and similar expressions.

Forward-looking statements involve risks and uncertainties that may cause actual results or outcomes to differ materially from those included in the forward-looking statements.

Factors that may cause actual results to differ materially from those included in the forward-looking statements include, but are not limited to, actions by state and federal regulatory bodies; competition and industry restructuring; changes in economic conditions; changes in weather patterns; changes in laws, regulations or regulatory policy; expiration or initiation of significant energy supply contracts; changes in levels of capital expenditures; developments in legal or public policy doctrines; technological developments; volatility in electric and natural gas commodity markets; effectiveness of our risk management policies and procedures; changes in accounting standards and financial reporting regulations; fluctuations in the value of electricity positions; changes in the ability to sell electricity positions and close out natural gas positions at anticipated margins; obtaining new contracts at anticipated volumes and margins; terrorist attacks at domestic energy facilities; and other presently unknown or unforeseen factors.

Other risk factors are detailed from time to time in our reports to the SEC.

We undertake no obligation to update the information contained in any forward-looking statements to reflect developments or circumstances occurring after the statement is made.

Now, let me turn over this call to Chuck.

Jeff, thank you.

And good morning and thank you for joining us to discuss NU's results for 2004.

I would like to provide a summary of the fourth quarter and the full year of 2004, an update on our projections for 2005, and then discuss the status of the comprehensive review of our competitive businesses.

Dave McHale will review our financial performance, and the heads of our three business groups -- Cheryl Grise, Lee Olivier and Larry De Simone -- will update you on recent events in their areas.

This will be the first time that Larry and Lee have joined us for an investor call.

Larry joined NU in late October to oversee NU Enterprises, our competitive energy businesses.

Lee was formerly President of Connecticut Light and Power, and was named to the new post of President of our Transmission Business last month.

And, although known to most of you, Dave McHale is on the call in his new role as Chief Financial Officer.

Let me start with fourth-quarter results.

As you can see from this morning's news release, NU earned $33.1 million or 26 cents per share in the fourth quarter of 2004, compared with a loss of $9.9 million or 8 cents per share in the fourth quarter of 2003.

Results for the fourth quarter included a number of significant charges.

Investments in a fuel cell development company and a telecommunications company were written down by a total of $4.9 million after tax.

Also, as we announced last week, we are now reflecting the value of certain natural gas contracts on a marked-to-market rather than an accrual basis.

Although the primary impact of that change was reflected in the third quarter of 2004, which we have restated to a $7.9 million loss rather than a $39.1 million profit, there was an additional -$2.4 million after tax of marked-to-market change in the fourth quarter.

On the positive side, fourth-quarter earnings at our regulated businesses were up 15.5 million from last year, and for the year, regulated company earnings were up $23.1 million or about 17 percent.

Cheryl and Dave will describe some of the reasons for that, but clearly we are very pleased with that performance.

For the year, NU earned $116.6 million or 91 cents per share.

That includes the $48.3 million or 38 cents per share marked-to-market charge and the investment write-downs of $8.8 million or 7 cents a share, primarily associated with our investment in the fuel cell company I mentioned earlier.

Earnings without those changes were $1.36 per share.

In 2003, we earned 91 cents a share.

Excluding the standard market design settlement and a write-off in a bill collection business we bought as part of the Yankee Gas acquisition, we earned $1.24 per share in 2003.

Moving to our competitive businesses, you'll recall that we revised our 2005 guidance downward on November 15, due to much weaker than expected success in various New England wholesale electric RFPs, lower margins on the RFPs we did win and an electricity presourcing strategy that was the genesis of the 2004 marked-to-market charge.

At that time, we told investors that we would be evaluating the competitive wholesale market to determine if it had changed significantly, or if our results were a onetime event.

That evaluation was focused primarily on the New England wholesale marketplace, which has been the largest piece of our competitive business for years.

As part of this review, we looked at multiple factors, including the trend in margins, our competitors, our bidding strategies and our cost structure.

Our initial conclusions were that we have more competitors selling into the higher-end market of full requirements electric service.

Many of these competitors have significantly larger scale, allowing them to spread fixed cost or market risk, including price volatility, over a larger base.

Wholesale pricing has become more aggressive, resulting in declining margins, and certain competitors may have lower cost structures, due to the financial restructuring of certain power plant ownership.

As a result of reaching these conclusions, and because the wholesale component of our business is so intertwined with all aspects of the merchant energy business, we felt it necessary to take a broader and more comprehensive look at all our competitive businesses.

Among other things, this review includes the impact of declining wholesale margins on our continued participation in this aspect of the merchant business; the potential for our retail business, since this market appears to be growing and our business is showing improved financial results; opportunities for our hydro and coal generation assets in a New England market that is long on capacity, but may have opportunities for changes that could potentially benefit these assets; and the impact of any decision with respect to the competitive businesses on NU as a whole.

Although not a component of merchant energy, we will, as part of this review, evaluate the strategic fit of the energy services in contracting businesses.

As noted in our previous news release, we expect to finish this review in the next several weeks, making appropriate decisions and promptly advise you of those decisions.

Larry will tell you later how we are operating this business until we conclude our review.

We will provide 2005 earnings guidance for the competitive businesses and for the consolidated company after we finish this review.

However, we have reaffirmed the regulated business earnings guidance for 2005 of between $1.22 per share and $1.30 per share.

That includes earnings of between 96 cents and $1 per share in the regulated distribution and generation businesses, and earnings of between 26 cents and 30 cents per share on our transmission business.

Parent company costs, mostly related to NU parent debt, are projected to total between 8 cents and 13 cents per share.

Now, I will turn the call over to Dave McHale, our Senior Vice President and Chief Financial Officer.

I will review earnings results for NU's business segments and discuss 2005 earnings drivers, capital expenditures and financing plans.

Our 2004 regulated business earnings of $1.21 per share is consistent with the upwardly revised range we announced last week.

It also compares favorably with the $1.05 per share we earned in 2003.

The primary reason for this improvement in results was CL&P, which earned 82.5 million in 2004, compared with 63.4 million in 2003.

CL&P earned 17.3 million in the fourth quarter of 2004, compared with 4.3 million in the same period of 2003.

The improvement in CL&P results was due in part to higher retail rates that took effect on January 1st, 2004.

They also reflect the difference between a 2003 rate case-related charge of approximately 5 million CL&P took in the fourth quarter of 2003, and a benefit of 6 million CL&P booked in the third quarter of 2004, when part of that rate case decision was reconsidered by our Connecticut regulators.

The Public Service Company of New Hampshire's earnings totaled 46.6 million in 2004, compared with 45.6 million in 2003, and 10.6 million in the fourth quarter of '04, compared with 11.1 million in the same period of '03.

A $3.5 million annualized rate increase took effect October 1, 2004 but was offset by higher O&M, including higher pension costs.

PSNH did benefit in 2004 by $5 million, resulting from a lower effective tax rate and certain adjustments to income tax reserves.

Western Massachusetts Electric Company earned 12.4 million in 2004, compared with 16.2 million in 2003 and 3.7 million in the fourth quarter of '04, compared with 2.4 million in the same quarter of 2003.

Western Mass' earnings this year declined, due to higher operating and interest expense and lower pension credits.

Yankee Gas Services earned 14.1 million in 2004, compared with 7.3 million in 2003 and 5.6 million in the fourth quarter of '04, compared with 3.9 million in the same period of '03.

Improved Yankee Gas earnings resulted to a large extent from 6.2 million of downward adjustments to unbilled revenues which occurred in 2003.

On the competitive side, losses amounted to 15.1 million in 2004, compared with a loss of 3.4 million in 2003.

As Chuck mentioned, the 2004 loss reflected the effects of marking to market certain natural gas contracts.

The 2003 loss included the 35.6 million after-tax cost of the standard market design settlement.

In terms of earnings drivers for 2005, we expect all four of our regulated companies to benefit from rate increases, which would put each of our companies in a position to achieve reasonable return on equity levels during the course of the year.

At CL&P and PSNH, we have secured a total of approximately 35 million of new rate increases that will go into effect in 2005, primarily driven by a need to recover a return on increasing capital investment that is needed to address customer load growth and reliability requirements.

At Western Mass Electric and Yankee Gas, we have implemented a total of $20 million of increases, primarily to address weak earnings and increasing capital spending.

In terms of electric sales growth, we seek CL&P and PSNH sales growing in the 2 percent range, although Western Mass' sales growth is at a more modest 1 percent.

As an offset, we do continue to see significant escalation in employee benefit and health-care costs and increases in the Company's pension expense.

Capital expenditures totaled $640 million in 2004, compared with 738 million we projected at the beginning of the year.

Most of the spending shortfall occurred in our transmission buildout, and much of that was due to a slower-than-expected start of work on the Bethel-Norwalk 345 kV line, due to a court appeal that was ultimately rejected and the need to obtain final siting permits.

We currently project capital spending of $700 million to $800 million in 2005 across the entire NU system, including amounts to fund CL&P's continuing four-year, $900 million capital program, PSNH's Northern Wood Power Project, Yankee's LNG storage facility and, of course, several large transmission projects here in Connecticut.

From a credit perspective, our balance sheet remained in good shape at the end of the year, with a total-debt-to-total-capital ratio in our target range at 56 percent, excluding rate reduction volumes.

Absolute debt levels rose from about 2.65 billion at the end of 2003 to 3.06 billion at the end of 2004.

That increase in debt in large part resulted from our 2004 capital program, almost exclusively in the regulated business.

It also reflects CL&P's ongoing refunds during 2004 of 2003 over-collections to its customers.

Common equity levels for NU consolidated increased from about 2.26 billion at the end of 2003 to 2.3 billion at the end of 2004.

NU parent closed 2004 with $120 million of cash on its books, most of which was temporarily invested in the internal NU system money pool.

We expect to continue to use that cash in future subsidiary dividends, primarily to inject equity into the regulated businesses when needed, and to fund NU's common dividend.

That equity will be primarily needed by CL&P to fund its transmission and distribution expansion program.

In 2004, NU made capital contributions totaling approximately 90 million to CL&P.

As a result of those infusions and retained earnings, CL&P had 822 million of equity on its balance sheet at the end of 2004, compared with just under 700 million at the end of 2003.

CL&P currently has about 110 million of short-term borrowings, either through its receivable line or through our money pool.

Last month, our Connecticut regulators approved the issuance of up to 600 million of long-term debt over the coming years to finance our capital needs, and we expect to issue about 150 million of that by midyear 2005.

We expect smaller debt issuances in the $50 million range for each of our gas companies -- PSNH, Western Mass Electric and Yankee Gas.

Finally, I would like to update you on recent discussions we have had with our rating agencies.

On January 14th, Fitch removed NU from watch negative, but established negative outlooks for both NU and CL&P.

Fitch's ratings for NU parent are BBB and A- for CL&P's senior secured debt.

On January 19th, Moody's placed all of our securities under review for downgrade.

We believe the Moody's review will conclude later this quarter.

Currently, Moody's rates NU parent to be AA-1, CL&P's senior secured debt A-2 and PSNH's senior secured debt A-3.

Regardless of the current ratings and outlooks, we clearly understand the agencies' focus.

Our growing regulated business capital program comes at a time when our internal cash flows have fallen somewhat, and that will result in rising debt levels.

This will require us to carefully balance the trade-offs between growing rate base and earnings and actively managing our credit measures over the next several years.

In addition, because our competitive business financial performance has fallen well short of our projections, the agencies are placing additional scrutiny on previously-projected cash flows, which would have aided NU's funding of the regulated growth strategy.

We have told the agencies that maintaining strong investment-grade ratings is essential to our investment plans, and that we will infuse equity from NU when necessary, to keep our utility balance sheet strong.

In addition, we have told the agencies that, if necessary, NU will issue new common shares to the public to manage its overall leverage and keep its balance sheet strong.

We believe the agencies recognize that from a regulatory standpoint, there is more visibility and predictability on our rate paths (ph) than there has been in quite some time, and we believe that certainty will continue to be reflected in our credit ratings.

Now, I would like to turn the call over to Larry De Simone, President of our NU Enterprises business.

Thank you, David.

Our competitive businesses are comprised of a merchant wholesale energy business, which includes our New England power plants, our merchant retail energy business and the services business made up of several electrical, mechanical and plumbing contractors, along with an energy services contracting company.

On a consolidated basis, our competitive businesses earned $5.1 million in the fourth quarter of 2004, compared with $8.2 million in the same period of 2003, excluding the SMD charge.

For the year 2004, our competitive businesses lost $15.1 million, with the marked-to-market charge, compared with a loss of $3.4 million in 2003 with the SMD charge.

Let's look at our merchant energy business in a little more detail.

In 2004, our merchant retail energy business earned $4.9 million, compared with a loss of nearly $2 million in 2003 and a loss of about $28 million in 2002.

Our retail marketing business now serves approximately 30,000 commercial and industrial gas and electric accounts in the Northeast United States.

We believe our retail business will continue to expand, as large customers opt to purchase their energy directly from suppliers, such a Select Energy.

The growth in the retail business is mostly spurred by an increasing number of commercial and industrial customers in the Northeast buying their electricity and natural gas directly from suppliers, rather than through the utility.

Select Energy is a major participant in this market.

Our renewal rate is above 80 percent, which we believe it is consistent with our competitors.

Turning to wholesale, we have another story.

Comparisons are difficult here, because of the charges in 2003 and 2004.

The wholesale group lost $17 million in 2004, compared with a $3.7 million loss in 2003.

To wrap 2004, we continue to operate our New England power plant safely, which is consistent with the core value of this corporation.

In 2004, we completed a scheduled outage at our Mount Tom coal station, and upgrades that will improve the efficiency and capacity across our fleet of hydro plants.

We continue to see solid output and good availability from the majority of our plants.

However, we do not see the wide spreads between peak and off-peak power prices and high-capacity values in the New England marketplace that would allow us to realize high margins from our Northfield Mountain pumped storage facility.

We marked certain natural gas contracts to market in 2004, resulting in a $48.3 million charge against wholesale earnings.

This situation developed due to a decision Select Energy made to contract in mid-2004 to buy electricity for delivery in New England, in anticipation of business we expected to win in 2005 and, to a much lesser extent, in 2006.

To mitigate the risk associated with the electricity purchases, Select signed contracts to sell natural gas.

We have already contracted to sell slightly more than half of the electricity we bought at positive margins.

Our 2005 wholesale results will depend largely on selling our remaining electricity positions at positive margins and continuing to close out the gas positions we established.

In 2004, we served a peak load of approximately 3,800 megawatts in New England.

About half of that load was CL&P.

We have no CL&P load this year.

Additionally, some of the load we have won outside of Connecticut has been at narrower margins than the $2 a megawatt-hour margin that we have seen in the past.

Also, we have been less successful over the past six months winning bids in New England, even with the lower margins.

We have learned a lot from our recent assessment of the wholesale marketplace.

Pending the outcome of our comprehensive review, our ongoing forward strategy for wholesale will be a much more cautious and scaled-back approach from the past.

We will continue to participate in wholesale auctions and compete for small blocks of full requirements load.

As we consider taking on new positions, we will remain acutely mindful of critical risk parameters, including sourcing, commercial, regulatory, counterparty credit and other risk considerations.

Finally, our services businesses lost $2.3 million after earning $2.6 million in 2003.

Charges of over $4 million after tax on a single construction contract contributed most of that variance.

Our focus in 2005 is to complete work on our remaining large projects and return to the basics that have made these companies profitable in the past.

Now, it is my pleasure to turn the call over to Cheryl Grise.

Thank you, Larry, and good morning, everyone.

Overall, we were pleased with the financial performance of the regulated companies in 2004, but I am most pleased with our ability to put behind us a high level of near-term rate case uncertainty.

Three of our companies reached rate settlements in 2004, and one had a fully litigated outcome at the end of 2003.

Regulatory issues in the year ahead will focus on ensuring that we continue to flow through certain costs, many of them related to power procurement.

Let's look at CL&P first.

Our 2003 CL&P rate case provided us with nearly $60 million of transmission and distribution rate relief in 2004, prior to the application of $30 million a year in refunds that do not affect net income.

Some of that rate relief helped pay for a $900 million, four-year upgrade and expansion of CL&P's distribution system.

We expect to spend more than $240 million on distribution capital expenditures at CL&P in 2005, similar to 2004 levels.

As David mentioned, we implemented another $25 million distribution rate increase at CL&P on January 1, 2005.

Separately, you may have read recently about a 16.2 percent overall rate increase that CL&P put into effect on January 1st of this your.

Ultimately, more than a third of that increase was offset by a separate ongoing credit on CL&P customer bills.

Of the 16.2 percent, only 1 percent of that increase was retained by CL&P as a 1 mil (ph) increase in distribution rates.

That's the $25 million I referenced earlier.

Another 5 percent was due to federally mandated congestion charges.

This money is a direct result of a lack of sufficient generation and transmission infrastructure in Southwest Connecticut.

The charge pays to keep older generating units operable that are needed to ensure bulk power reliability.

It pays to run less efficient generating units out of economic order, and it pays for a number of other costs, including installing temporary generation in Southwest Connecticut.

The remainder of that more than 16 percent increase was attributable to higher commodity costs that resulted from the bidding that took place in November for CL&P's standard offer service.

In 2005, CL&P's suppliers will be J. Aron, Sempra, Constellation, and PP&L.

We are pleased that the DPUC passed through and did not defer any of these additional costs.

We recently filed with the DPUC an application to boost rates yet another 1.6 percent later this year, largely driven by a new, FERC-approved reliability must-run contract.

We also filed with the DPUC this week a request to recover transmission costs associated with the initiation of the New England RTO operations on February 1st.

Moving to our New Hampshire electric company, PSNH's earnings were somewhat ahead of our expectation in 2004, due in part to strong sales.

PSNH's retail sales rose by 3.1 percent in 2004 compared to 2003, partially attributable to a robust economy in New Hampshire and the acquisition of 11,000 customer accounts in western New Hampshire at the beginning of 2004 which were acquired from a central Vermont public service subsidiary.

This compares to an increase of 0.1 percent at CL&P and a 1.6 percent increase at WMECO.

Overall, NU's regulated retail electric sales rose by 0.9 percent in 2004, compared with 2003 on an actual basis, but nearly 2 percent on a weather-normalized basis.

PSNH received a small benefit from a $3.5 million energy delivery rate increase on October 1, 2004.

A $10 million annualized increase will go into effect on June 1, 2005, as part of a rate case settlement approved in September of 2004.

Effective February 1st, New Hampshire PUC approved an increase of 0.7 cents per kilowatt-hour in PSNH's transition service rate.

This reflects higher fuel and purchased power prices, and is consistent with the policy of regulators in all three states we serve to pass through energy costs in a timely manner.

PSNH has commenced construction of a $75 million conversion of a 50-megawatt coal-fired unit in Portsmouth, New Hampshire to burn wood chips.

We continue to target a completion date of late 2006.

Moving now to our Massachusetts electric company, WMECO's earnings fell off in 2004 from historical levels, but were not sufficiently low to enable us to file a rate case asking for substantial rate relief.

Therefore, we negotiated a modest, non-rate-case settlement that provides WMECO with a $6 million delivery increase effective January 1, 2005, and an additional $3 million increase effective January 1, 2006.

Customers will actually see an offsetting decrease in rates in 2005, because of a drop in our stranded cost recovery charge which had been overrecovering our stranded costs.

We expect to file a full rate case in 2006 in Massachusetts for new rates effective in 2007.

Finally, at Yankee Gas, we expect to benefit from a $14 million delivery rate increase that took effect on January 1st of this year, and on January 27th, Yankee broke ground on construction of a $100 million LNG storage facility in Waterbury, Connecticut that we expect will be complete in time to be filled for the 2007 and 2008 heating season.

With that, I will turn the call over to Lee Olivier.

Thank you, Cheryl.

First of all, I would like to say I am pleased to assume the role of President of NU's transmission business, and I look forward to meeting many of you.

We view our transmission business as a significant contributor to NU's growth over the coming years.

National policies promoting transmission expansion to ensure reliability and competitive markets.

The risk-adjusted returns on these assets are among some of the best in the electric value chain.

NU's transmission business is fundamentally aligned with the federal policy direction, and our electric franchises will require significant investment over time.

ISO New England's transmission upgrade plan includes more than $1.5 billion over the next five years for NU transmission projects alone.

Now, what I would like to do is provide you with an update of our progress on our various transmission plans.

Transmission capital spending totaled $171 million in 2004, up from $99 million in 2003.

Of the $171 million, 133 million was spent by CL&P, 52 million on the Bethel to Norwalk 345 kV voltage transmission line.

Most of the capital spend in 2004 on that line was in substations.

Final plans for the overhead line were approved by the Connecticut Siting Council in December, and we expect to begin construction in March of this your.

We continue to expect this project to cost between $300 million and $350 million and be complete around the end of 2006.

Hearings have continued on the 345,000 volt Middletown to Norwalk transmission line.

We expect our estimate of 80 percent of our ownership to be around $700 to $800 million, but that will depend on a number of factors, including the final design.

Hearings will continue later this month, and a vote is expected in April of this year.

We have jointly filed a report with the Siting Council in late December with United Illuminating Company and ISO New England, indicating that we could build a 24-mile stretch of the 70-mile line underground and maintain adequate system reliability.

There continues to be quite a bit of discussion as to whether, despite the study, more of the line should be constructed underground.

We expect that hearings on that topic will be wrapped up by the end of this month.

On the $120 million, 115,000 volt Norwalk to Stanford Lindbergh (ph) cable line, Siting Council hearings were delayed until the Middletown to Norwalk hearings were complete.

We continue to expect that project will be operational in 2008.

I won't list all of the other transmission projects we have underway, but please note that these three projects listed above are only the most visible of a very comprehensive program we have to improve the reliability and capacity of the electric grid for the benefit of New England's electric consumers.

We have a number of other projects, many of them inside the substation fence (ph), that draw less attention, are very manageable and are needed for reliability and to contribute to the steady increase in the size of our FERC rate base.

As we have mentioned earlier, we expect to spend about $60 million annually on these kind of projects.

We are installing a new autotransformer on the 345 kV system in Haddam, Connecticut this year at a cost of about $22 million.

We expect to complete a $20 million improvement of our transmission system in and around Manchester, New Hampshire later this year.

We recently filed with the Siting Council in Connecticut to build a new substation in Killingly, Connecticut on the 345 kV system.

We hope to complete that project, for $35 million, in 2006.

I should also note that the New England Regional Transmission Organization, or the RTO, commenced operations this week.

As Cheryl previously mentioned, hearings on the return on equity transmission owners receive has commenced before the Federal Energy Regulatory Commission last week, and we expect an Administrative Law Judge's decision in the late spring and a FERC decision later this year.

Now, what I would like to do is to turn the call back to Jeff Kotkin for Q&A.

Thank you, Lee.

And I am going to turn the call back to our operator, Daniela, who will remind you of the instructions for putting in Q's and A's.

(OPERATOR INSTRUCTIONS).

Erica Piserchia.

I just wanted to ask -- I guess before, you were discussing sort of the outlook with regard to the rating agencies, and I know at EEI in October you'd discussed, obviously, the need to do equity further out for the funding for the transmission projects.

In light of some of the discussions that you have been having with the rating agencies, is there any possibility that you would have to move up an equity issuance before kind of the end of '06, which is what I think you had indicated you might do it?

I think our plans as a result of conversations over the last several weeks with the agencies certainly has not changed.

I think the '06 timeframe is the earliest that we would focus on, and of course this depends on the timing of our capital program and the size of our capital program.

But I would say those discussions have not changed our views.

And a second question.

I may have missed this, but I don't know if you have indicated what the amount was that Select earned in 2004, just from serving the CL&P standard offer service load.

We did not break that out, Erica.

We normally don't break that out.

Anthony Crowdell (ph), Jefferies.

The question -- I guess I have two questions.

The first one would be when I look at using a matching principal perspective, it looks to me that the gas losses in 2004 will be offset by electric contract gains in 2005.

Based on the earnings release, though, it looks to me as if your 2004 operating number excludes these gas losses.

Is it correct to assume, then, your 2005 operating number will exclude the benefit of your long electric contract position?

I think, Anthony, that we will have to be very clear in are 2005 guidance and our 2005 results to make it absolutely clear what comes from day-to-day operations and what comes from any changes in the mark to market on the gas position.

And then the second question would be on -- it looks like the fourth quarter, you had an increase in your tax expense, compared to fourth quarter '03?

Could you explain the driver behind that?

You are talking specifically about the fourth quarter?

Yes.

I think you went from a -- where is it -- a loss last year to a benefit this year. (Indiscernible).

Well, remember, last year we did have a loss, because that's when we wrote down the SMD settlement.

Are you saying beside that, or is that (multiple speakers) --?

Is there anything besides that or no?

No, we think that's it.

At this time we don't appear to have any other questions.

Steve Runkhouse (ph), Talon Capital.

Actually, what I wanted to know if you could elaborate a little more on some of the different businesses within the competitive energy segment.

Specifically, you had mentioned that the wholesale side, there seems to be a lot of competition, lower margins.

And the Hydro might be an interesting asset in the New England market.

So I was wondering those two things specifically, as well as maybe touching on the pump storage and how the fossil fits into that strategy going forward.

If you were to separate the businesses or do something with the businesses, can you just comment on the different pieces as they are today and, I guess, go into a little more detail on the hydro specifically?

Larry did that a little bit in his prepared remarks.

You might have missed that, but I will ask him to kind of go back and talk a little bit more about the assets in those businesses.

I had heard what he said.

I just wanted him to kind of elaborate on his point on the hydro that it might be a significant positive going forward in the New England market.

Actually, that was my point on the hydro.

If you look at the New England marketplace right now, there are some changes as we look forward that clearly may happen over the next few years.

Probably the largest one of that is the introduction of locational installed capacity that FERC is currently planning to introduce in January of 2006.

But clearly, to the extent that that locational installed capacity comes in, it would benefit all of the generating assets in that area, and we would see some benefit from that.

There are also a few other changes that ISO is contemplating around how they pay for specific assets, and that is primarily related to the almost 1,100 megawatt pump storage unit that we have that could provide benefit in the future.

So there are some potential opportunities to benefit those assets as we look out.

Greg Orrill, Lehman Brothers.

What are you seeing in the difference between peak and off-peak prices in New England?

Greg, hang on just a second.

Larry has got that, I think.

About a $20 spread of on peak and around $70 off peak, around $50.

And how has that changed?

It's probably more compressed, I think.

On an average basis, if you look forward, that is probably not out of line.

But we are not seeing the volatility in the prices between peak and off peak, the spreads that we would want to see if we were pumping, so that we could pump at low prices and be able to sell at high prices.

It's more compressed on a daily basis.

It's not that much more compressed, I don't think, if you were to look on a forward average basis.

And then, are you looking to participate in the New Jersey BGS auction coming up, and can you remind us, if it's possible, how much load you won last year?

Well, we are not at Liberty to comment on that, in terms of our intentions regarding participation.

Give me a minute, and I'll take a look and see what load we have.

Greg, I think we put that into a news release last year, about New Jersey.

I think it was somewhere in excess of 1,000 megawatts or so, but we printed that last year.

And Larry was referring to the rules that we're talking about are roles of the BGS, not NU rules, about commenting about whether you're going to bid on future contracts.

Jim Ferguson (ph), AIG.

A question to follow up on the comment about locational installed capacity.

Would that, in 2006, earn capacity charges greater than you now incur or now generate in the pump storage business?

Yes.

In fact, if you look across the entire fleet of generation we have in New England, we estimate gross margins of probably around $15 or $16 million.

So after tax, a $10 (ph) million net income contribution to the Company.

And what is that likely to increase by, if the as-planned goes into effect in 2006?

It's quite significant.

The trajectory on those payments is a very steep slope, and it could result in tens of millions of dollars of net income by 2009 -- tens multiplied by a single-digit number.

At this point, could you give us some preliminary information on the earnings or cash flow of Northeast generation?

Are you talking about for 2004, Jim?

Yes, please.

They should be fairly similar to the previous years, just because it's formulaic, and it should be true in '05, as well.

Philson Yim, Morgan Stanley.

You sound a little more optimistic about the prospects of the retail supply business.

Could you just talk about where that kind of stems from?

Is it from margin maintenance, or are you going to expand into other states?

Because we're seeing some other companies talk about margins really being compressed there, and only being offset by volume growth and aggressively pushing into other states.

I'll ask Larry to comment on that in a little more detail about what we have seen in '04 around the retail business.

But this question has come up in the past about the margin compression from other folks.

I think one of the issues is that in at least a couple instances, they started at a relatively high margin and have actually come down, and we have at least seen essentially the same margins, maybe a little bit of compression, but nowhere near some of the other competitors that we have.

And that really is much more a function of the starting point of those margins, I think, than the market that we find ourselves operating in.

And I'll ask Larry to comment a little more about not only the expansion of that marketplace, but also some of the reasons that they had a good year in '04.

Let's just separate the retail business into electric and gas.

On the electric side, our volumes were around 10 million megawatt-hours in 2004.

And while we did see some flattening or downward pressure on margins, the reality is that the margins are holding pretty well.

I think we have historically talked about margins in the $2 to $2.25 range.

But you probably have to widen that a little bit.

Depending on the type of customer, it's probably more like $1.70, but still $2.25, perhaps even more on the upside, as you move down to serve some of the smaller electric customers.

And that's particularly true in New England, although you will see the bottom end of that range with the book of business that we're putting together in New York and in some of the CJM (ph) states.

On the gas side, there has been downward pressure on margins, and I think we have overcome that with volume.

Our volumes in 2004 were about 40 billion cubic feet, and I think that while the margins have been pushed down a little bit, as a book of business, the retail gas group has actually maintained a fairly consistent total gross margin contribution in the business between 2003 and 2004.

Maury May.

I have a question on the pump hydro at Northfield.

With the reduction in spread between peak and off-peak prices, you seem to be making Northfield out to be some kind of dinosaur in the business.

What are your thoughts on -- positive thoughts, on how this could turn out?

Or are there any?

Actually, I think the issue is that we did not have the benefit of transferring the generating assets to the competitors' side at book value, like a number of other competitors have in the Northeast.

So we have a little higher basis to start from.

The economic value of that plant was based in large part on the forward-looking view that there would be significant spreads between on-peak and off-peak prices, so that we could pump cheaply and garner very high margins during peak periods.

We have seen a compression and actually a reduction of that ratio of the on-peak prices to the off-peak prices.

So the benefit of pumping and then selling in peak doesn't generate the kinds of margins that we had anticipated.

And that is a phenomenon we have seen since, really, late 2002 or early 2003.

But if the Federal Energy Regulatory Commission moves ahead and says that assets of this site (ph) are of value in New England, providing this locational installed capacity credit that Chuck has referred to, we did see significant benefit to all of our generation, in particular almost 1,100 megawatts of generation at Northfield, and that that is a payment as an alternative to their reliability must-run streams at some of the more antiquated, inefficient, more dinosaur type plants that you have referred to are garnering today.

Now, you mentioned that the possibility for these locational credits could be in the tens of millions of dollars through 2009.

That sounds like a cumulative number over four years.

Can you put it on an annual basis?

I was not suggesting that that was cumulative.

I was suggesting that if FERC were to actually implement the (indiscernible) proposed by the New England independent system operator and what is being adjudicated today, if that plant is put into effect as proposed by ISO New England, effective 1-1-06, that we would see a benefit in net income in 2006 of $10 million, and we would see an incremental benefit going forward of probably $50 million in the out-years, per year.

And my second question has to do with the result of your study.

You have said that you would have something to say to us within several weeks.

But, with all due respect, you said that 10 days ago, and it seems to be kind of a rolling several weeks.

But can you put more of a firm date on when the results of the reassessment might be given to us?

As we said I guess a week or so ago, when we did the press release, it's several weeks.

It's not meant to be a rolling several weeks.

I don't want to put a specific timeframe on it, and say we're going to have it done by specifically X date.

It will be a few weeks.

We appreciate the urgency and the issue, and we are working as diligently as possible to get that done.

But as you can appreciate, this has an awful lot of impact on this organization, not only on whatever decisions we reach around the competitive businesses, but potentially on NU as a whole.

And we want to make sure we do that in a very deliberate and rigorous way, to reach those conclusions.

But we do appreciate that there is a sense of urgency around it.

It doesn't appear that we have any more questions in the queue, so I'm going to thank everybody for joining us this morning.

If you have any follow-up questions, please feel free to give us a call this afternoon or next week, and thank you very much for joining us.

Thank you for attending today's conference.

You may disconnect at this time.