康涅狄格電力 (ES) 2005 Q1 法說會逐字稿

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

David McHale, our Senior Vice President, and Chief Financial Officer;

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

Cheryl Grisé, President of our Utility Group; and Lee Olivier, President of our Transmission group.

This conference call will include 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 Litigation Reform Act of 1995.

In some cases, the reader can identify these forward-looking statements by such words 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 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, obtaining new contracts and at anticipated volumes and margins, terrorist attacks on 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 the call to Chuck.

Jeff, thank you.

And thank you all very much for joining us today.

I understand that you have been buried under an avalanche of utility earnings announcements over the past three days, and we are very pleased that you're able to join us this morning.

The first quarter represents the beginning of an important transition for us as we change the profile of Northeast Utilities.

In March we announced the decision to exit our wholesale marketing and services businesses, and we recognized that due to a number of factors.

We were not able to generate the earnings in cash flows, we could previously anticipate it within acceptable risk levels.

After this transition is complete, we will be a company with a lower risk.

Significant earnings growth opportunities in our transmission and distribution businesses and the ability to take advantage of improving market conditions in the competitive businesses we have retained.

As we would hear later in the discussion, we have made considerable progress on all firms.

Today's charges, primarily are the result of exiting the businesses and reflect a number of factors which we would discuss in more detail.

We view these charges as transition cost.

We will be a better company going forward with more transparent financial performance in earnings drivers and a lower risk profile.

When this transition is complete the benefits of our regulated investment strategy which is addressing important energy delivery needs in our service territory will no longer be diffused by the volatility of wholesale marketing business. $3.7 billion of capital expenditures will grow rate base by about 2.5 billion over the next five years as we create a more secure and reliable Energy infrastructure in Connecticut, New Hampshire and Massachusetts.

David, Cheryl and Lee will update you on the progress we've made in various areas in the regulated businesses in the first quarter.

The bottom-line is that, overall we are exactly were we expected to be with our transition and distribution business at this time.

We are also encouraged by the result we saw this pass quarter in the competitor's businesses we are retaining.

Our retail marketing group has made solid progress in contracting for new load.

With a 20-25% market share in New England, and approximately 10% market share in both New York and PJM., we are a major retail supplier in the Northeast United States.

And we continue to see the competitor retail market growing as commercial and industrial customers continue to switch to utility sponsored standard offer, provider of last resorts services.

Now before I turn this call over to Dave McHale to comment on the first quarter financial performance of the company, let me give you an update on the ConEd Litigation.

We have a date for arguments in front of the second circuit court, associated with the appeal of judge Cournal's (phonetic) decision that the March 2001 stock holders were the appropriate recipients of any benefits as opposed to the current shareholders.

That date is June 8, and we will be making those arguments again at the second circuit.

We would anticipate that we may receive an order within a few months after arguments are completed.

Now let me turn the discussion over to Dave and have him comment on the financial performance of the company.

Thank you Chuck.

Yesterday, NU reported a first quarter loss of $117.7 million or 91cents per share compared with net income of 67.4 million, or 53 cents per share in the same period of 2004.

As Chuck indicated, these lower results are due primarily to charges associated with NU's previously announced decision to exit 2 of our 4 competitive energy businesses.

In terms of the components of these results, let me start with a review of our regulated businesses and then move on to the competitive businesses.

Following earnings of $1.4 per share in 2003 and $1.21 per share in 2004, we are estimating regulated business earnings of $1.22 per share to 130 per share this year.

This reflects between 96 cents in a dollar share in a regulated distribution generated businesses and between 26 cents and 30 cents per share in a regulated transmission business.

Overall, we started the year well.

As a whole, the regulated companies earn $53.6 million in the first quarter of 2005, versus $53.4 million in the first quarter of ‘'04; a $200,000 increase despite a 1% decline in electric sales.

This represents a $1.5 million increase in transmission earnings and 1.3 million reductions in distribution and regulated generation earnings.

Before launching into our view of each companies performance, I would like to make a general comment on overall sales results through out our services territory.

Two general comments are that, it was somewhat warmer in the first quarter of 2005 than in the first quarter of ‘'04, and the sales were negatively impacted since we had one fewer day due is 2004 being a leap year.

Overall regulated retail electric sales were off about 1%, 3/4 of % whether adjusted.

Residential sales rose nearly half a percent, 0.65 whether adjusted.

Commercial sales were essentially flat year-over-year, but industrial sales were off about 6.6% with the significant decline at PSNH where they were off 11.5%.

We know that three separate customers accounted for about half of that decline, one of which switched to self generation system and two of which were shut down all together.

Foreign gas sales we were up about 2.3% in part due to softening in usage among industrial customers.

Now let us turn to the specific financial result of each of the regulated companies.

On transmission, Lee will describe an on going England RTO return equity case before FERC but at this time we are basing our 2005 earnings at each of the three electric company’s in our overall transmission segment guidance, on a transmission ROE between 11 and 12%.

CL&P are $25.2 million in the quarter compared with 26.2 million in the first quarter of 2004, the company benefited from a $25 million annualized distribution rate increase that took place on January 1, of this year, but that increase was offset by lower sales, particularly to industrial customers.

Higher interest pensions and depreciation expense.

Over the balance of the year, we are projecting higher earnings for CL&P over the same period of '04, due to the distribution rate increase, higher transmission rate a return to normal summer weather form a very mild 2004.

Last year NU used $88 million of equity into CL&P and at the end of the first quarter '05 indebted another $22 million.

We expect to earn ROE for CL&P's distribution business to be in the 9%-10% range this year.

PSNH earned 8.8 million in the first quarter of '05, compared with 11.8 million in the first quarter of '04.

The reasons are similar to CL&P, though in PSNH losses, industrial sales was much more significant.

Over the balance of 2005, we expect PSNH earnings to because some what lower than they were in '04, despite a $10 million energy delivery rate increase that will take effect on June 1.

This decrease is largely due to some income-tax benefits, PSNH received in the third quarter of last year which will not repeat themselves This year we expect PSNH distribution and generation ROE to be in the 9%-10% range.

Western Massachusetts Electric Earnings were $4.7 million in the quarter, up 2005 compared to $3.5 million in the first quarter of 2004, this was due primarily to a $6 million annualized distribution rate increase that took us back January 1 of this year and some modest residential sales growth.

Despite this strong start we expect WMECO earnings to be relatively flat in 2005, compared with '04 as higher expenses offset distribution rate.

As a result we are anticipating WMECO distribution of ROE will also be in the 9%-10% range.

Yankee gas earned $14.9 million in the quarter verses a $11.9 million last year, this increase was largely due to a $14 million delivery rate increase that took effect January 1.

That increase will help Yankee improve year-over-year earnings in 2005.

We are projecting that Yankee will earn a regulatory ROE in the same 9%-10% which is consistent with its recently improved settlement.

At the NU Parent level expenses are $3.9 million after-tax, reflected more than 2 million after-tax increase in environmental remediation reserves, at a coal power site, Mt. Tom generating unit.

The balance of parent costs reflects the anticipated interest in WMECO.

Although Larry reviewed the specific results for the competitive businesses, but first I want to discuss some of the financial ramification of the write off's we announced today.

The lion's share of the $167.4 million loss was driven by 150.2 million in restructuring costs associated with exiting the business.

They are reflected on NU's income statements as 234.4 million of restructuring and impairment charges offset by 84.2 million of reduced income tax expense.

These charges consist of four components, the first and the largest component is 164.2 million or $1.27 per share associated with mark-to-market, certain long terms currently below market wholesale electricity contracts.

We announced in March 2005 that NUEI would exit the wholesale energy marketing business, and that would take certain charges in the first quarter on its remaining book of business.

Prior to deciding to exit the wholesale marketing business, these contracts were part of the company’s ongoing business and were accounted for on a accrual basis.

Due to the decision to exit that business, NU is required to account for them on a mar-to-market basis.

We currently have contract to sell nearly 60 million megawatts hours of electricity to wholesale customers over the next nine years.

Some of those sales contracts, in combination with their corresponding supply contracts are in the money and are expected to produce value to the company upon sale; more than 60% of that load is 2005 and 2006.

Most of the load in next few years is comprised of full requirement sales to utility extended offer in default solicitations in New England, New Jersey, Maryland and Washington DC.

The longer term contracts are generally with smaller utilities, many of them municipally owned.

They were signed when power prices were lower and our prices well below today’s market.

Under the applicable accounting rules, the decision to exit the wholesale market requires us to mark these contracts to market.

We could serve the contract until expire, but that will continue to expose us to risks associated with serving these contracts and it will result in a potential lost opportunities for the generation going forward.

Until we divest these contracts, volatility in our quarterly income statements will occur, since whenever electricity prices rise, we’ll have a non-cash mark-to-market loss and whenever they fall we’ll have non-cash mark-to-market gain.

On top of the mark-to-market loss we recorded this quarter, this volatility could be substantial on a mark to market basis, there are approximately 9 million megawatts hours of position which are subject to market movements. 5% move in the market would introduce a $25 million -$30 million pre-tax variation, positive or negative depending on the direction of market places.

I would like to emphasize however on an economic basis across our entire portfolio, our opened mark-to-market positions are well balanced against our generation and supply contract addition, which are recorded on an accrual basis.

Shortly we will seek to divest these out the money longer term contract as well as in the money shorter term contracts.

Divesting the out of the money contracts may require us to make a payment to a new buyer, we will have to take a look at the profits we receive in negotiations with our current counterparts or from potential buyers before determining whether it is in our economic interest, to divest or retain these contracts.

The second component of the restructuring charge is $25.3 million or 20 cent per share associated with impairment on our companies energy services business.

NU had about 60million of equity invested in the businesses and another 30 million of internally funded debt.

We have hired an outside firm SMI Corp to evaluate the companies and help us divest the assets.

Based in part on the firm's review, we have concluded that all of the goodwill is impaired as well as most of the intangible assets that have been recorded in the book; together, these total of $38 million.

After accounting for tax benefits of around 13 million these write-off costs are approximately $25 million of net income in the first quarter.

Our hope is to sell the Services businesses by the end of 2005 and once the sales do occur, we will chew up the reduced book value to the actual net cash received and record any result in gains or losses.

This would generate positive cash flow which will be available to meet our other obligation including investments in regulated businesses.

The third component is a $20.6 million or 16 cents per share of charges associated with other costs, exiting the wholesale business such as termination payments, and contract asset write-off resulting from market to market these contracts.

These costs were partially offset by the marking to market and shorter term wholesale contracts of three years or less.

The fourth and final component, are gains at 59.9 million or 46 cents per share associated with marking to market.

Selling wholesale Electricity position that was obtained before the company's retail marketing contract.

Originally, retail electric supply was sourced along with the whole sale supply by our internal wholesale marketing organization.

As a result of our decision to exit the wholesale marketing business, we are required to mark to market these retail supply contracts.

This mark was approximately positive $94 million pre tax since those supply contacts are below today's market prices.

Recording these supply contracts on a mark-to-market basis, will complicate reporting future retail earnings because the 94 million of pre tax margin, from attractive supply contracts was essentially moved from 2006-2007 and the balance 2005, into the first quarter of 2005.

This does not affect retail gas contracts and it will not affect new wholesale contracts because their supply contracts are specific to the retail business which is on an accrual accounting basis.

That’s it for the restructuring charges; again they totaled $150.2 million.

In addition to these charges there is one charge reflected on the income statement as 40.7 million of increase fuel and purchased power offset by 15 million of reduced income tax expense, that 25.7 million after-tax charges is associated with continuing mark-to-market in wholesale natural gas sales contract signed in 2004 previously discussed as our pre-sourcing position.

NU like to close now it's pre-source electricity in natural gas positions it is established in 2004 and expect those positions to have no impact on future financial results.

In February, we told analysts that in mid 2004 we had bought electricity for wholesale delivery in ‘05 and up to in 2006 and sold natural gas as a hedge.

The rise in natural gas prices last year in the need to mark those natural gas positions to market costs of $78 million pre-tax, $48 million after tax in ‘04.

The in-the money long electric positions would not reflect in 2004 because they remain on accrual accounting.

Our decision in 2005 to exit the wholesale business required us to mark the electrical position to market as well; at March 31st these positions had a positive value of $73milion.

In the first quarter of 2005 natural gas prices moved higher resulting in 40million of additional pre-tax mark- to-market losses or about 25 million after tax.

That 40million loss is reflected as additional fuel and purchase power cost.

All of the 73 million of pre-tax benefits, of the pre-source electric positions, have shown up now in the first quarter results.

Most of it offset the negative mark- to-market restructuring, but some of it help to reduce our 11.7million merchant energy operating profit.

So, overall the pre-sourcing strategy cost is about 28million after tax with 48 million of losses in '04 and 20 million of gain in the first quarter of '05. again the pre source position is now closed out they will have no impact on earnings, though there will be some cash flow benefits associated with the electric position of the balance of '05, in 2006.

From cash prospective it's important you recognize that the vast majority of charges we recorded in the first quarter were non-cash in nature.

In some cases, we wrote down assets on the balance sheet and in another cases we recorded mark-to-market losses, either way though cash was not actually being utilized.

In the future as we seek to sale of our contracts, we expect some of them to produce cash because they are in the money and sin some cases expect to take on parties to renegotiate contracts that are out of money.

However during the cash we expect to receive from selling in the money contracts and our services business and the tax benefits we will receive as a result of this write down.

We believe that the net cash requirements will be modest and not cause us to infuse additional cash resources in to the competitors businesses.

As Larry will discuss further, we think of 2005 as a transition year particularly for generation though we do expect retail to earn equivalent of $ 5-6 million of net income this year.

Beyond 2005, we expect our merchant energy business which consists of retail and generation to be profitable.

The extent of its profitability depends upon the way in which we dispatch our assets, to expense its life asset values and the success of our retail business.

We anticipate providing more visibility around this issue, including specific earnings guidance later this year.

Now turning our financial statements as of March 31 the total debt component where balance sheet was approximately 58%, which is above the 55% level we have traditionally target in the level at which attained at the end of 2004.

We are committed to maintaining a strong balance sheet and credit ratings that will allow our regulated businesses to continue to follow at attractive rates.

We have shared the results and details of this quarter with rating agencies and continue to work closely to communicate our ongoing earnings, cash flow and risk profile expectation, as well as our overall credit rating objectives.

From a liquidity stand point, NU used credit line totaling $ 900 million remain largely unutilized with current cash burn at 125 million.

At this time, NU Parent still has more than 50 million of cash which is available to invest in the regulated companies to support their near term capital requirements, in fact NU did invest 22 million in CL&P in first quarter of 2005 to fund it's construction programmed.

The total amount of capital expenditures for the entire NU system this year is expected to reach $ 740 million of which 150 million was actually invested in the first quarter as we invest additional capital this year, we do expected to borrow money externally as well.

In fact in first quarter, we issued 100 million of 10 year CL&P bond that are 5% coupon and an another 100 million of 30 year bonds and 5 and 5 A's coupons, and expected issues 500 million of new debt at each of our other regulated companies later this year.

On the horizon we continue to expect to issue common equity, to raise additional proceeds to support our regulated investments, while maintaining the equity capitalization required to support our credit rating objectives.

Based on the amount and pace of our capital expenditures, particularly around large transmission projects, we expected an equity offering could come next year.

Let me pause there on the financial matters and I will turn the call over to Larry De Simone.

Thank you David and good morning everybody.

David already has reviewed the first quarter charges, so I'll review our progress in each of the business segments.

Let's start with the six service companies.

As David noted, we have retained FMI to help us through this divesture.

FMI has a solid track record in transactions involving mechanical, electrical, and fuming contractors, and energy services businesses.

We expect to begin distributing descriptive memoranda by mid-May and to begin meeting with potential buyers in early June.

We already have received significant interests in these businesses.

With respect to our exit of the wholesale marketing business, we're looking at two types of contracts.

As noted in the news release, the shorter term contracts are generally in the money, and the longer term contracts are not.

With the help of Lazard we're putting together list of the contracts for distribution to perspective bidders, by the middle of May.

We expect to receive indicative offers by the end of May, and we hope to begin confer mating transaction as soon as this summer.

On our longer dated contracts, we're looking at both restructuring opportunities, and the possible sale of these contracts.

We also may serve some of these contracts to conclusion if we cannot divest them.

Our goal is to divest all of the contracts by the end of 2005.

So then we can put the wholesale marketing business behind us and maximize the value of our generating assets going forward. 2005 is clearly a transition year.

As we look ahead, here is the calculus for computing financial performance for our competitive businesses.

First will be the margin from selling generation into the market.

Second will be the benefits we expect to see once location installed capacity is implemented in New England.

Third will be the retail origination margin from new retail sales.

And fourth and finally we will continue to experience the effects of having accelerated future retail margins into the first quarter of 2005.

By retaining our retail marking platform and our generating assets we preserve the opportunity to take advantage of improving market conditions at a reduced risk profile.

Now let's turn to retail.

Retail continues to sign-up new business.

We now expect revenues to be between 1.1 billion and 1.3 billion in 2005 compared with our $1 billion estimate that’s beginning at this year.

We booked more than $300 million of business in the first quarter alone and margins continue to hold reasonably well.

As David mentioned earlier, the net income and gross margins from retail for the next few years will be negatively affected by marking-to-market certain power purchase contract that had been used to source our current backlog.

On a GAAP bases, retail marketing earned more than $61 million on the first quarter.

But that’s not how we want you to look at the business, because included in that $61 million is a mark to market gain of nearly $60 million.

The core retail business actually earned approximately earned $1.5 million in the first quarter.

This was ahead of target for the $6 million that we expected to generate from retail calendar 2005.

So rather than net income, let me talk about sales volumes and margins because that’s what will produce cash returns for us in the coming years.

We expect to deliver more than 30 million megawatt hours of electricity and about 67 billion cubic feet of natural gas in 2005.Our sales force is very active and we now have supply proposals exceeding $1 billion in the market place.

These new contracts, all will be on accrual accounting.

Our retail origination margins on new sales are holding.

For power, unit margins are ranging between a $1.60 to $2.20 per mega watt hour, depending upon customer size and location.

For natural gas, unit margins are ranging between 20 cents and 25 cents a deicer.

In the past, we've not spoken much about our generation since it represented such a small potion of are overall supply business.

However, we will discuss it more as we move forward since it’s a large part of our future.

We choose to retain our 1,443 megawatts of generation because it's very competitive in today's environment of high natural gas prices, because we see a significant improvement on the value of the capacity and New England going forward.

And because our generation has very modest capital requirements over the next several years.

To help provide you with more transparency of our generation, business we'll present you with a detail on plan availability, output, and operating and capital cost.

We believe unit availability will become increasingly important as the capacity market tightens in New England due to low growth and the absence of new plant construction.

In the first quarter our 1,080 megawatts Northfield Mountain pumped storage facility had an availability of 98%, while the Mt. Tom, 147 megawatts whole unit had an availability of 93%.

Our nearly 200 megawatts of conventional Hydro-Electric units had an aggregate availability of 81%.

On an annual basis we expect Mt. Tom and the Hydro-Electric units to produce about 1.7 million megawatt hours of low cost power.

In the first quarter alone these units produced 482,000 megawatt hours.

Total non-fuel [inaudible] for our generation runs about $40 million a year.

In the first quarter we came in nearly $2 million below budget and about $8 million.

As we move forward, we're looking at several ways to maximize the values of generation including using it to back retail contracts.

We've completed the re-licensing process on most of our Connecticut hydro units and have licenses that extend through 2014, I'm sorry 2044.

On our last conference call I noticed that our competitive generation could benefit significantly from the implementation of locational installed capacity.

The Federal Energy Regulatory Commission like LICAP proceeding is progressing.

Parties filed pleas in the FERC proceeding on Wednesday.

We expect a FERC administrated Lazard's recommendation in mid-June on the price curb that will be used when LICAP is instituted in New England.

At this time a FERC decision is expected in the second half of this year with LICAP implementation on January 1, of 2006.

Under ISO New England's proposed rules, maintaining strong unit availability would be critical to ensuring maximum LICAP value.

Regardless to the outcome of the current LICAP case, we see an improving New England capacity market as an important driver in achieving earnings growth in the generating business.

We've positioned our Merchant Energy business which includes retail marketing and generating assets to be profitable in 2006, at a significantly reduced risk profile compared with the wholesale marketing business that we are exiting.

As the retail markets grow and the New England load expands, we believe these businesses have significant room for improvement over the next few years.

Let me now turn over the call to Cheryl Grise.

Thank you, Larry, and good morning.

From a rate making standpoint, all of our regulated companies continue to enjoy a high-level of certainties.

All of our companies have implemented distribution rate increases over the 7 months and we do not expect to file any new rate cases until 2006.

Additionally, three of them have additional increases that are approved for implementation over the coming year or two.

Dave mentioned that the $10 million increase at PSNH in June.

CL&P has a $12 million increase in January of 2006 and another $7 million in January of 2007.

UMICO has a $3 million increase in January of 2006.

There will also be rate adjustments at each of the regulated companies to reflect the changing costs of power, natural gas and federally mandated congestion costs.

Regulators in all three states have been very responsible in passing these costs through on a timely basis.

With rate making on the back burner, we have been quiet focused this spring on the legislative arena.

I know that some of you have read news reports about legislation proposed in Connecticut and New Hampshire.

So let me review where we stand.

There are actually a number of bills pending in Connecticut but I'll note two areas in particular.

The first bill allows us to implement a transmission tracking mechanism in our retail rates, I am sorry -- the first bill to allow us implement a transition tracking mechanism in our retail rate has been approved by the transportation committee and referred to the energy and technology committee.

This bill will allow us to true-up retail customer bill to reflect over collections and under collections of work approved transmission costs.

UMICO already has a similar type of mechanism.

This bill will prevent CL&P from being caught in a type of regulatory lag as new transmission investments are placed in service.

Since the bill has not yet been cast by the legislature, we have pending before the Connecticut DPUC, a proposal that we either differ or allow collection of higher transmission costs that took effect with the start of the New England archive on February 1.

Another bill under consideration in the Connecticut legislature would encourage the construction of distributed generation in Connecticut to help meet the state's generation shortfall.

It also provides for long-term capacity contracts.

Moving to New Hampshire, we've been actively addressing a bill that passed the New Hampshire senate that would place strict limits on mercury emission from PSNH's coal burning power plant.

The bill, if enacted into law, would be far more restrictive than the recently enacted EPA rules in mercury emissions and would require a 40% reduction in emissions by July of 2009 and an 81% reduction by July of 2013 with no provision for emission credit trading.

It would be very difficult for PSNH to achieve this level of reduction.

The matter is now before a committee of the New Hampshire Health representatives, but problems with the senate passed bill are being discussed along with alternative provisions that would allow PSNH to achieve a substantial reduction in mercury emissions within a more reasonable time frame and cost.

We believe that the house is likely to retain the bill to allow more time to work out an acceptable amendment which will be proposed in the next legislative session that is in 2006.

On a more positive note, earlier this month, the New Hampshire Supreme Court dismissed an appeal by owners of several wood-fired units in the state, who objected to state regulators' approval of the conversion of one of our coal-fired units at Chiller Station to burn wood chips.

That $75 million project should be complete in the second half of 2006.

The project is on schedule, though we are currently dealing with an easement dispute with the rail road that runs by the plan.

From an operational perspective, our utilities had a strong first quarter.

Service reliability was up compared to last year and our operating costs were below budget due in part to a lack of major storm damage in the quarter and in parts of good costs management.

With that I'll now turn the call over to Lee Olivier.

Thank you Cheryl and good morning.

First of all, I'd like to report that our transmission business has achieved two important milestones in our business plan in the first 4 months of 2005.

This month we will begin constructions of Bethel to Norwalk line.

We expect the combination of overhead and underground projects to be complete by the end of 2006 and cost between $300 and $350 million.

The Bethel to Norwalk project which represents about half of our $245 million transmission construction budget for 2005 is currently on schedule and on budget.

On April 7, the Connecticut citing council approved the construction of the 69 mile Middleton to Norwich line that we will build with United Illuminated companies.

This is one of the largest transmission investment currently being proposed in the United States and will significantly eliminate the reliability of congesting challenges that are facing Southwest Connecticut.

We expect our 80% share of outline to cost between 670 million and $800 million and for the major construction activities to take place between 2007 and 2009.

There is a 45 day period during which any affected party may file an appeal of a citing decision.

During the remainder of this year, we've preparing detailed engineering design plans and final environmental permits.

One major project that is now days away from the hearing stages are our $120 million Glenberg cable's project which will consist two new underground 115 KB lines between Norwalk and Stanford.

Hearings were delayed while the citing council considered the Middletown to Norwalk project but are due to resume Tuesday May 3.

This is a critical project which in concert with the Bethel to Norwalk and Middletown to Norwalk projects will the address the reliability needs in Southwest Connecticut.

As this is an essentially all underground project, we expect the citing council hearings will be less controversial than the other two major projects.

While there is a great deal of focus on larger projects, it's important to recognize that we have a portfolio well over a 100 transmission projects that are either in the engineering or construction phases.

We are on target through the first quarter to meet our 2005 capital spending program of $245 million, with similar levels of capital spending expected in 2006 and beyond.

I'll continue to provide you with updates on our capital program progress in future conference calls.

Now with respect to earnings, currently we are allowed to bill a 13.3% equity return on our regional transmission investments, this ROE level is current being adjudicated at FERC and is subject to refund until our final audit is received.

Transmission owners filed a 12.8% ROE and FERC already has approved a 50 basis point adder to whatever the base ROE is finally authorized.

The two primary issues now before FERC are what the base ROE should be and what kind of additional incentives transmission owners will receive for new projects.

We expect the final FERC decision next year and at this time I cannot form in or what that outcome would be.

However as Dave said, our current earnings line which is based upon an ROE range that is more conservative than the 13.3%.

Now I want to thank you all and I’d like to turn the phone call back to Jeff Kotkin.

Thanks very much Lee and I’m going to turn the call back to Mike, just to remind you how to queue in questions.

Once again if you’d like to ask a question, please press ‘*’ then ‘1’.

Thank you Mike.

Our first question is from Paul Fremont from Jeffries.

Paul?

Thank you, Northeast Utilities have previously indicated that it would issue equity as necessary to stay within a targeted debt-to-total cap ratio of 55%, if you’re already out of that range and you essentially are going to need to add leverage to fund the utility construction program.

Why the decision to wait until next year to issue equity?

Paul this is David McHale, I think our position is then 55% within the range of [above and below] one or two hundred basis points.

I think we’ve sort of creped out of that a little bit.

Now, we don’t anticipate a lot of cash requirements going to fund the exit of these wholesale businesses although that shows exactly financial on a consolidated base anyway and the method in which we exit the business.

The system also does have financing on the horizon.

We've already anticipated that in the guidance that we provided you and directions we provided you and we indicate that we need to work with the agencies going to study this matter and I wouldn’t say that it is alarming to us now to be a little bit outside of this range but again it's something that we continue to watch and we do anticipate something in 2006.

But you do have a quarter if I heard you correctly you have only funded about a150 million of your CapEx program at the utilities for the year, you cut back another 600 million of CapEx to go between now and the end of the year?

That’s right.

I think the way we look at this, you take a little bit of more math around it Paul, that we know based on where our 2005 initial performance would have been where we would have ended up the year.

And based on that we had projected that 2006 would have been in issuance window.

I think the erosion to where our expectations were even with the CapEx program in front of us and even with some external [inaudible]in front of us is erosion of what our expectations was and that erosion might be a couple of 100 basis points which I think you have seen here, I think that you know still within our particular credit profile and that’s the way we deal it.

However we will continue to work with the agencies and others going to focus on the immediately as such a need but at this time I think 2006 is still a wind of hope.

Thank you

Our next call is from Kurlata Chan (phonetic) from Angel Gard Gorder (phonetic).

Kurlata.

Hi good morning.

Can you just remind me of what if NU is associated with the services company and the prompt disposal, what would you think that would look like.

This is [inaudible], we’ve got about $30 million associated the Company’s now that in internally funded through assistance money pools, so short term advances or NU parent advances, so its internally funded subset, any proceeds from the business would be used to repay it essentially ourselves.

In addition to that, one of the reserves this Company has about 100 million has been in fact securitized debt obligation that has paid back from the revenues stream associated with energy performance contracts, those are guaranteed by the NU parent and those will be part of the sales package and it’s our expectation that those obligations will go to the new owner and we will negotiate structure around the NU guarantee obligation.

Can I ask one more question about LICAP?

Sure.

There was a recent letter by the Massachusetts DTE in their response to FERC on LICAP and they had suggested a more narrow scope to resolve the reliability issues and they brought up the issue of locational reserves market and I just, Larry wanted to get your perspective on that and whether you think that that is the something that might replace LICAP near term?

I am not familiar with the letter but I don’t think the concept is some thing that we are looking at adding as a real opportunities to play out is well as the revenue generated for the Company.

Okay thanks.

Our next question is from Paul Patterson from Glen Rock Associates, Paul?

Hi guys

Hi

I wanted just basically and I am sorry if I just missed it so what is the book value of the businesses is being divested in NUEI, I mean what’s the net book value now, with all the write-offs?

Paul there’s a few pieces to it and the biggest piece is the generating piece which is somewhere near our 400 - I am sorry, you are talking about the divesting fees, that’s --

I think Dave's got that information.

Or the other business is that where divested, the discreet services business right now for example, that’ll be about $30 million in an equity remaining in those businesses.

Okay and the wholesale contract?

The whole sale contract runs through on the legal entity Select Energy and I don’t have that specific number in front of me, its clearly a negative number at this point, I don’t have that sitting in front of me I’ll do a little bit of home work for you.

Okay, so I mean just to sort of understand it, the reason why you’re now marking-to-market is because you guys are planning on divesting these contracts.

Is that the reason why you had a marking-to-market and as a result why there is a write-off?

That’s the reason.

Okay and then when you look at the balance sheet, where does that show up and I feel they could well write-off as you mentioned and I looked at the derivative assets.

I’m just trying to get the idea as to where these write-offs have showed up?

This is John Stack, Vice President and Controller.

On the balance sheet the write off in effect that reduces retained earnings, reduces our equity.

Is that the question?

Okay let me, I just wanted to know if there was any specific asset acquired or liability, that increased your assets that decreases as a results of this divestiture?

We set up a liability, derivative liability to reflect the -- in effect the obligation, our estimate of the obligation to get out of these contracts.

Okay and the assets also seems to increase as well, when you did that.

I mean it just seems like would that make a difference.

I could follow it offline.

It just seems that if you look at the increase in derivative assets and liabilities they seem to increase pretty closely to the sale analysis.

Just try to figure that out, but we can follow it offline.

Okay, Paul I will give you a call and I'll give you the different balance sheet and trade associated with what we do in the first quarter.

Okay, great.

Thanks.

Alright.

Our next question is from Michael Goldenberg from Luminous Management.

Michael?

No.

Okay, next question we have right now is from Maurine May from Power Insights.

Let's try Michael-- Michael, are you on?

Can you hear me?

Yeah, we can hear you now.

Okay good, alright, just two quick questions.

One is could you talk a little bit about peak and off-peak prices in the New England region, just because that seems to be pretty important for your pump storage units.

Yeah Michael, Larry will do that.

Yeah.

On Operator: forward basis, on-peak prices are in mid to high $70 and the off-peak prices are in the high $50 to $60 range.

But when you -- and that's really the answer for New England.

But the specific answer to your question about the Northfield Mountains pump storage units have to do with the intra-day volatility of prices.

That is to say how higher the price is on-peak when we would sell power, how lower the price is off-peak when we would actually pump the water up the mountain and those prices are actually have been running fairly tight.

I have been monitoring the relationship between the high prices and the low prices and the ratio is running at about 1.5 or so with the efficiency of Northfield Mountain, in other words, we basically used up 1.4 MWh for every MWh that we generate, we need those ratios to be well in excess of 1.4 and we are just not seeing that kind intra-day price volatility to be able to schedule, say a day or real time and see the kinds of spread 2.5 to the 3.0 kinds of spreads that we saw a few years ago.

And my next question is on transmission you obviously have a very expensive build-up program, how confident do you feel that the timeframe will be met?

It just seems with some transmission project there is always something around the corner from this advocacy group or that group that doesn't want it to get it build.

How confident do you feel that you've put all those issues to rest at this point?

First of all, I'd like to say Michael that our Bethel to Norwalk project is as I've said is underway, under construction.

We are dead on target on there and on schedule we expect there will be no intervention in that project.

In the big project, in the Middletown to Norwalk project, we think that as result of the Siting Council decision, we think that we have a very strong case; the Sitting Council ran a very fair open process.

There has been no appeals filed to-date.

In any case, we think the rigor of the decision will withstand any appeal and so therefore we think our timeframe in terms of getting that project in service which is to late 2009, early 2010 is a very good timeframe and you know, we expect to hit our targets and we expect to hit all of our 2005 capital spend as well.

Thank you very much.

You are welcome.

Thank you Michael.

Our next question is from Anthony Scardell from Jefferies.

Anthony?

Just a quick question on the competitive businesses.

I guess I am looking for --I guess guidance.

The competitive businesses when you strip out the volatile mark-to-markets and everything -- you earned $8.5 billion this quarter, if you strip that out all the volatile mark-to-market charges, could you give us some guidance on what the company could earn in this segment in third and fourth quarter for this year?

We are not prepared to provide that guidance today.

Okay.

Our next question is from Mike Weinstein from Zimmer Lucas.

Mike?

My question is to do with the wholesale business and what they made last year.

You guys reported last year that they made 24 cents in 2004 and most of it in the first quarter.

Now with -- since you are marking everything to market and there is no more accrual earnings, does the entire 24 cents go away when we look at each quarter going forward?

That --Mike, that 24 cents was last year.

Yeah, that’s what I’m saying.

I’m doing quarter-over-quarter comparisons, right?

So, for the next three quarters, I should eliminate that 24 cents and there will be no more accrual earnings in 2005, right?

Right.

That's correct.

On the wholesale business and clearly not only is the impacted by mark-to-market but it's also impacted by how quickly we exit those contracts.

Right.

So if I wanted, for instance exclude mark-to-market earnings for my calculations completely, I would just eliminate the wholesale business entirely from the way I look at the company at this point.

Sort of treated like a discontinued operation even though you are not treating it that way.

I think that's fair.

Yes.

Is there any time table for when you might discontinue it officially?

I think, as Larry said, we would like to have to exit not only all of the services, businesses but contracts that we are going to be able to get out, exit by the end of the year.

Okay, thanks.

Next question is from Steven Fleishman from Merrill Lynch.

Steve?

Yeah, hi, couple of questions.

First, this may have been answered but what was the debt to capital balance sheet at the end of the quarter.

58% Steve.

58%?

Yeah.

Okay.

Secondly, on the -- first of all on the retail mark-to-market that related to, I guess, retail contract being at wholesale.

I think you said that was $60 million mark-to-market gain.

After-tax.

After-tax and two questions on that.

First, is that in your one-timers that you have listed here, is that part of the 8 cents that the competitive business has earned in the quarter of operations.

That's part of the $115.2 million re-structuring charge.

That is part of the re-structuring charge.

Yes.

Okay.

And then Larry, as you said on a go-forward basis, you essentially have to source that power based on market.

So that ended up getting earnings today that have been turned to I guess the cost pressure in next couple of years.

That's exactly right.

How are you planning to kind of disclose that or deal with that or is that just going to be a cost pressure, will we able to that timing difference that occurred.

We were going to actually just consolidate everything and then report our total merchant energy number going forward and that would be one of the cost drivers is calculating the net income for the business.

Okay, so okay.

You know, if we get the specific question, I suppose we should look at sharing how that actually plays out in 2000 -- the remainder of 2005, 2006, [inaudible].

It tails off-- but it is a drag going forward.

Then secondly, you mentioned related to the contract that was signed in ‘04 in ahead of the CL&P auction.

You took another mark-to-market hit on the gas contract.

That’s part of the one time charges?

Yeah see that’s a separate charge of 25.7 million you see it separately on a press release page runs through fuel and [purchased] power.

Okay so that was part of the 8 cents in the quarter that you earned in the competitive businesses operationally or no?

It's not part of the 8 cents that we have described separately in the press release but it does go through the income statement outside of the charges.

Okay and then how about the power contracts which I think you said now some of those were mark-to-market?

The electric position?

Right.

The electric positions that were worked out $73 million now all on through the income statements they were mark-to-market.

Some of them actually been they were delivered in quarter show up in the quarter with the vast majority run through the mark-to-market as an offset to the negative charges.

Okay, so that’s all those are incorporated in the one time charges in some way?

All those with exception of the gas figure of 25 million, that is not in the -- you may refer to as one mind as being specific to with respect to occurring terminology of the restructuring charge.

Okay I am not being specific I am more referring to, so you are saying the 124.9, and then you have the gas here as a separate item.

Right and I think your nomenclature, it is a one time charge broadly speaking.

Okay.

So the 8 cents is net of all the stuff we just discussed.

Yes it is.

Okay, one last question on the cash requirements, should we view the net impact of all these mark-to- market as kind of the discounted cash that might be required to exit all the stuff.

Why wouldn't that be somewhat equivalent to the cash requirement you might ultimately have?

It would.

I think from the cash perspective if you have taken the discussion around the restructuring charge, let’s say at 150 million which includes both the wholesale and services piece.

And it grows that after taxes and then starts striping out of that.

The non-cash charges because some of their right offs are simply assets that were on the balance sheet recorded years ago.

Yeah

Just skip those out and then if you see the tax benefit, and then offset that with the actual sales proceeds of the services business even though there’s a charge on actually received cash proceeds that will get to my statement about this being pretty fairly marked cash outlay?

Okay, thank you, very much.

Thanks Steve.

Our next question is from Morie Neigh (phonetic), Morie?

Yeah, Good morning gentlemen.

If we could revisit the retail marketing margins one more time and head for a summarization here because in recent months we all have been talking about 5 perhaps $6 million contribution from retail energy marketing and it looks that has been changed because as I understand your booking all existing margins from retail to contract in the first quarter.

As for the balance for this year for the balance of those contracts you have to outsource some again, which would be a drag non adjusting contract.

So that’s the only source of margin in retail will now henceforth come from new contracts signed.

Is that correct?

That is correct.

So that the 5 million to 6 million in retail marketing guidance is really goes to loss for the balance of the year.

Is that correct?

We have to report, if we report, net income for retail over 2005 on a stand alone basis and pull out that $60 million mark-to-market, gain after tax gains that we were showing in the first quarter.

You are right.

So that is how you would report for the balance of the year?

Yeah.

Excluding any new contract?

That’s right.

Okay and my second question have to do with the dividend.

I just want to make sure that the dividend policies remains intact following these write offs?

It does [Morie].

Okay and the annual meeting is scheduled for what date?

its May 10 [Morie].

Okay.

Good to know.

Thank you folks.

Okay.

Thank you.

All right.

We don’t have any more questions at this time so I want to thank you all for joining us today and if you have any follow up questions, please give us a call today or visit us, those of you who will be at the AGA conference on Monday and Tuesday.

Thank you very much.