康涅狄格電力 (ES) 2005 Q2 法說會逐字稿

Good afternoon and welcome to the Northeast Utilities Q2 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 we'll turn the meeting over to Mr. Jeffrey Kotkin, Vice President of Investor Relations.

Sir, you may begin.

Thank you very much.

Good afternoon 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 afternoon 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 subsidiaries;

Cheryl Grise, 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 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; development in legal or public policy doctrines; technological development; 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 at anticipated volumes in 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.

Good afternoon and thank you all very much for joining us today.

Let me start by providing an overview of the progress we're making in executing both our strategic initiatives and the more immediate tasks we set for ourselves for 2005.

Our regulated businesses are performing well.

From an earnings perspective, we continue to project regulated Company earnings of between $1.22 and $1.30 per share, despite the $0.035 per share charge we took from a recent Connecticut regulatory decision.

Achieving this target would allow us to continue the growth that has brought our regulated earnings from $1.04 per share in 2003 to $1.21 per share in 2004.

From an operating perspective, our systems are performing well, which is allowing us to benefit from the rather warm weather we've been experiencing recently.

In fact, we have been hitting record peaks.

In 2004, New England's peak load was slightly over 24,000 megawatts.

Since June 13, there have been eight days, six of which are in July, where New England's peak load -- hourly load exceeded the 2004 peak.

In fact, 2005's peak occurred on July 19 and was 26,749 megawatts.

I should point out that today, ISO has suggested that we might hit 27,000 megawatts, which would of course be a new peak for us.

I should mention, however, that although we have seen increased sales in late June and certainly during July due to weather, we are watching the fact that on a weather-adjusted basis, sales are somewhat lower than our expectation.

Cheryl plans to discuss this in more detail later on.

Our regulated investment program is on target and I think it's fair to say that it has picked up momentum this year with the Connecticut Siting Council approving $1 billion in new high-voltage transmission projects in Southwest Connecticut in the past four months alone.

Additionally, the Bethel to Norwalk project is now 30% complete. on time and on budget.

Meanwhile, public service of New Hampshire's woodchip generation project is now more than half complete.

Our Waterbury, Connecticut natural gas storage facility is 20% complete.

Both of these projects are on time to meet their projected in-service dates.

Both Lee and Cheryl will provide you with more details later in the discussion on these major projects.

Moving to the state capitals, we were generally pleased with the outcome of legislative sessions in Connecticut and New Hampshire.

The Connecticut Legislature addressed two areas that are key to us.

On July 6, Governor Rell signed House Bill 6720, which will allow CL&P's retail transmission rate to track its wholesale transmission costs.

On July 22, Governor Rell signed House Bill 7501, an energy independence bill that is designed to reduce federally mandated congestion costs by encouraging the construction of new generation in Connecticut and the implementation of more conservation and load management initiatives.

We consider this bill to be a very responsible step by the state's elected leadership to address the fact that Connecticut is short electric generating capacity and is paying an increasing price for that shortfall.

It provides financial incentives that align our customer and shareholder interests and protect our balance sheet.

It allows CL&P to bid on building new generation and to receive incentives if others build generation in CL&P's service territory.

Importantly, it also requires regulators to consider the impact on in-use capital structure and credit metrics if CL&P enters into long-term capacity contracts with generators.

In New Hampshire, we were pleased with that the Legislature decided to study the issue of mercury emissions from generating plants rather than passing a Senate-approved bill that could have been extremely difficult for Public Service of New Hampshire generating assets to meet.

We expect this issue to be addressed again in the 2006 session.

On the competitive side, we are focusing on the two businesses where we believe we have a competitive advantage -- generation and retail marketing.

As we look ahead, we believe our generation fleet has potential to generate steadily rising earnings and cash flow over the coming years once it is detached from our current wholesale marketing contracts.

Larry will describe to you how well our competitive generation units are operating and how coal and hydroelectric generation are attractive in today's high gas price market.

He will also discuss changes we are starting to see in the New England capacity market, with or without the introduction of LICAP, that we expect to create additional annual revenues for us in years ahead.

We are also pleased with the performance of our Competitive Retail Marketing Group, which aside from some accounting adjustments that David will go over, continues to be profitable, hit its unit margin targets and remain one of the major suppliers of electricity and natural gas in the Northeast United States.

While we are making progress on the divestiture of our wholesale marketing and energy services businesses, you can see that the projected costs associated with unwinding those businesses have grown since the first quarter.

Second-quarter results were negatively affected by the variable we identified last quarter as a source of near-term earnings volatility -- the marking to market of wholesale electric positions we are seeking to divest.

We will continue to mark that portfolio to market until we divest it or until the underlying contracts expire.

Larry will elaborate on our progress to date, but I am pleased to report that we have renegotiated five long-term obligations with five New England municipal systems that will warrant result in those contracts being terminated.

Larry will also update you on the ongoing efforts to terminate other wholesale contracts, but I believe that events in the competitive marketplace continue to reaffirm for us the wisdom of leaving the wholesale marketing and services businesses.

Because our current commitments are generally covered, either through power purchases or our own generation, we're not conducting a fire sale and will only agree to buyout arrangements that are fair to our shareholders.

But we also understand that the faster we exit this wholesale marketing business, the sooner you will have clarity on the earnings potential of our competitive generation and of NU as a whole.

Now, let me turn over the call to David.

Thank you, Chuck.

I will cover second-quarter financial performance and then discuss current and future financing activity.

As you read in the news release, NU lost 27.7 million in the second quarter of 2005 or $0.21 per share.

Our Utility Group earned 22.1 million or $0.17 a share compared with 27.1 million in the second quarter of 2004.

The lower results are entirely due to a 4.4 million after-tax charge CL&P took in the second quarter of 2005 as a result of a regulatory decision and a 2.3 million positive tax adjustment Yankee recorded in the second quarter of 2004 which did not recur in 2005.

Absent those adjustments, earnings were higher as our rate increases and slightly higher sales offset higher pension, depreciation and interest expense.

And as Chuck noted, despite these second-quarter adjustments, we continue to expect 2005 regulated earnings to achieve our earnings guidance of between $1.22 and $1.30 per share, compared with $1.21 per share in 2004.

Now turning to the individual utilities, CL&P earned 11.1 million in the second quarter of 2005 and 36.2 million in the first half of 2005, compared with 17.3 million in the same quarter of 2004 and 43.5 million in the first half of 2004.

Aside from the 4.4 million charge related to straight-line billing, CL&P earnings benefited from a 25 million distribution rate increase that took effect January 1 of this year and from increasing transmission segment earnings, but those benefits were offset by higher pension, depreciation and interest costs.

To remind you, as a result of CL&P's 2003 rate decision, the Company will implement another distribution rate increase of about 12 million at the beginning of 2006.

Public Service New Hampshire earned 9 million in the second quarter, compared to the quarter of 2005 and 17.8 million in the first half of 2005, compared with 6 million in the second quarter of 2004 and 17.8 million in the first half of 2004.

PSNH benefited from delivery rate increases of 3.5 million annually in October of 2004 and 10 million annually in June of this year.

But on a year-to-date basis, those increases have been somewhat offset by higher pension and other operating costs.

Western Massachusetts Electric earned 2.4 million in the second quarter of 2005 and 7.1 million in the first half of 2005, compared with 3.6 million in the second quarter of 2004 and 7.1 million in the first half of 2004.

Western Mass benefited from a 6 million distribution rate increase in 2005, but that was offset also by higher operating and interest costs.

Yankee Gas lost $400,000 in the second quarter of 2005 and earned 14.5 million in the first half of 2005, compared with a small profit of $200,000 in the second quarter of 2004 and 12.1 million in the first half of 2004.

A $14 million base rate increase that took effect January 1 has helped Yankee considerably.

But in the second quarter, that was offset by the absence of last year's favorable tax adjustment.

Fundamentally, the challenge in our regulated businesses will be to ensure that revenue increases, either through sales growth or rate recovery, are sufficient to cover capital costs related to our buildout.

We continue to targets authorized distribution returns in the 9 to 10% range and 11 to 12% in transmission.

On a year-to-date basis, in terms of segments, our distribution business earned 56.2 million in '05, compared with 68.0 in 2004.

Our transmission business has earned 19.4 million year-to-date compared with 12.5 million in 2004 as it earns FERC-approved returns on a rapidly growing rate base.

As I mentioned earlier, the distribution earnings are down in 2005 due to the street lighting refund of CL&P and the absence of the tax adjustments at Yankee Gas.

In addition to these two items, the distribution earnings are lower in 2005 as a result of certain retail transmission expenses that were charged to the distribution business but not included in the retail transmission rates that are billed to customers.

On a consolidated basis, the net impact to the 2005 earnings is zero because the 2005 transmission earnings increased by an equal amount.

With the enactment of the new law that Cheryl Grise will describe later, CL&P will be able to recover all future increases in retail transmission expenses, and thereby improve the overall earnings on a consolidated basis.

WMECO already has a similar tracking mechanism for its retail transmission expenses, but PSNH does not.

The near-term challenges at our competitive businesses, which have little new capital investment, are different.

As Chuck mentioned, the major factor affecting second-quarter financial results was the continued marking to market of the wholesale marketing contracts that we are in the process of divesting.

Here I want to differentiate between the one- to two- to three-year contracts we have to supply investor-owned utilities in the Northeast and the long-term contracts we have to supply municipal electric systems, primarily here in New England.

The shorter-term book is essentially flat with power purchases and sales roughly equal in volume and period.

As a result, market movements have less impact on their mark-to-market values.

On a longer-term book, fluctuations in the forward price curve have a very significant impact on our mark-to-market results, as we do not back them with power procurement contracts, which would be marked to market as prices fluctuate.

Rather, these commitments are backed with our generating assets, which do not get marked to market and remain on accrual accounting.

During our April conference call, I gave an example that a 5% move in the forward price curve up or down would have a 25 to $30 million impact on a pretax basis.

In the second quarter, we had on average in excess of a 10% upward movement in the forward price curve, driven to a great extent by June run-up in oil and gas prices.

This resulted in about a $63 million pretax mark-to-market loss on the book of long-term contracts.

That amounted to 39.8 million after tax, which represents the bulk of the 41.2 million of charges taken in the quarter.

We will continue to mark these contracts to market until they are sold, renegotiated or expire, and they may continue to cause significant earnings volatility in NUEI.

Going into the third quarter, there are somewhat less than 9 million megawatt-hours that are in this mark-to-market position, and while it's clearly difficult to project market movements, thus far this quarter, we have observed that forward prices have changed little relative to our June 30 mark.

Aside from that mark-to-market impact, and $700,000 in other restructuring and impairment charges, our merchant business lost 3.1 million in the second quarter of 2005.

That includes a GAAP loss of 4.9 million in our retail marketing business.

You may recall that in the first quarter, we had to mark certain retail power procurement contracts to market, resulting in a onetime mark-to-market gain of about $59.9 million.

That gain will be essentially be unwound over the next three years.

Excluding those mark-to-market effects, our retail marketing business earned 1.4 million in the quarter and 2.8 million in the first half of the year.

It remains on target to earn the 6 million that we had projected for 2005, compared with about 5 million in 2004.

Our services business and NU Enterprises parent lost 3.5 million in the second quarter of 2005.

This was due in large part to losses related to some large contracts that are nearing completion and the after-tax write-off of plant assets of about $700,000.

Across the NU system, our capital spending totaled $330 million through June 30.

Of that sum, 317.5 million was invested in the regulated business, including about 192 million in distribution, 83 million in transmission and about 33 million in PSNH generation.

We expect to complete the year close to our $740 million capital budget, with transmission representing more than 200 million of that sum.

As you probably know, in May, the NU Board of Trustees raised the annualized common dividend $0.05 a share.

We will pay a $0.00175 per share common dividend September 30, up from $0.16.25 per share June 30.

This 7.7% increase represents the fifth consecutive year of above-average dividend growth.

On the financing front, there are a few items to discuss.

Last week, we closed on the sale of 50 million of privately placed 30-year first mortgage bonds for Yankee Gas.

They carry a coupon of 5.35%.

It was the second regulated financing of the year, following CL&P's sale of 200 million of bonds in April.

We expect Western Mass Electric to sell 50 million of senior notes in August and PSNH to sell 50 million of bonds later in the fourth quarter of this year.

Western Mass already has state and regulatory approvals for its issuance;

PSNH is currently in the regulatory approval process.

We're very aware that the near-term cash costs associated with our efforts to exit the wholesale business could be meaningful.

However, there are significant tax offsets associated with selling these contracts at a loss, and we believe there will be meaningful proceeds from selling services businesses.

On balance, the net cash outflow from the Company may be somewhat greater than the modest impact projected in April, but the numbers should be quite manageable from a liquidity and leveraged standpoint.

At quarter end, total debt to total capital was 59%.

At that level, we consider ourselves within but at the outer band of rating agency guidelines for the Triple B ratings category.

We have filed a financing application with the SEC's 35 Act Holding Company staff to issue up to 750 million of securities to fund our regulated investment initiatives and meet our other spending needs.

We expect the 35 Act's BAFTA (ph) review to be concluded this fall, which would put us in a position to issue NU common shares as soon as late this year.

The need to issue equity is due primarily to the 2006 regulated investment plan.

But the exact timing may be accelerated by our work to exit the wholesale and services business, fund large transmission projects, which as Lee will describe are all moving forward nicely, and maintain our creditworthy balance sheet.

At this point, I would like to now turn the call over to Larry De Simone.

Thank you, David, and good afternoon, everybody.

We continue to see positive trends concerning the generation and retail marketing businesses we are retaining.

The competitive retail markets are expanding, and the market for our hydroelectric and coal-fired generating capacity is improving.

Both of these trends are good for long-term profitability and validate our strategic decision to retain our merchant generation and retail marketing businesses.

Before going into details about our two going-forward businesses, let me take a few minutes to amplify on Chuck's and David's comments concerning the businesses we're divesting, energy services and wholesale marketing.

We have six energy services businesses that we are seeking to sell.

Two are high-end electrical contracting businesses -- E.S.

Boulos in Maine and Woods Electric in Connecticut.

One is telecommunication construction -- Woods Network in Connecticut.

One is performance contracting, particularly for the U.S.

Defense Department -- Select Energy Services in Massachusetts.

The fifth and sixth are heating, ventilation and air conditioning and plumbing -- Select Energy Contracting, one in Connecticut and the other in New Hampshire.

We've distributed descriptive memoranda and made management presentations to potential buyers and are in the process of receiving and analyzing bids for several of these companies.

We intend to sell these businesses by the end of this year, but it's too early to tell if we will meet this schedule.

Our objective is to net at least the $50 million that is now reflected as the book value of these businesses, but it's too early to know for sure how much we will ultimately receive for these businesses.

We will operate all of these companies as ongoing businesses until we sell them.

We do anticipate improved performance from our services companies for the remainder of 2005.

Our losses to date come from a handful of projects in which we experienced cost overruns and we're completing shortly.

Moving to the wholesale marketing business, our goal is to exit this business line by the end of this year.

We continue to evaluate several alternatives to accomplish this goal, including selling our portfolio of contracts, restructuring longer-term contracts and serving out shorter-term contracts until they expire.

We continue down the path of selling existing contracts.

With the help of Lazard, we solicited bids earlier this summer from firms that wanted to purchase all or a large portion of the book. 28 firms expressed interest in the book. 15 firms submitted indicative bids and we've begun discussions with a short list of a few firms.

Because those negotiations are still ongoing, we cannot project our ultimate conclusion.

Our goal is to sell the entire book, but we cannot make any definitive comments at this time.

As Chuck mentioned, we continue in parallel to restructure the long-dated obligations and have now reached agreement to buy out five of the 15 municipal contracts we're seeking to exit.

Those five contracts, which account for between 15 and 20% of the value of those loan obligations, will terminate between September 1 of 2005 and March 1 of 2006.

The reactive negotiations are continuing with the other 10 municipalities and we remain hopeful we will be able to renegotiate or sell all of these contracts this year on terms that are acceptable.

We're also seeking to sell off the contracts we have to serve a number of industrial utilities in New England and PJM over the next three years.

These contracts now total approximately 26 million megawatt-hours of sales obligations.

Approximately three-quarters of the sales and purchase obligations are for delivery over the next 12 months.

This book is essentially flat based on our projected loan obligations.

If we cannot sell this portfolio of contracts on acceptable terms, we could either divest them individually or serve them out.

Let me now turn to the businesses we are retaining.

Let's start with retail marketing, which remains on plan.

The number of commercial and industrial customers seeking to leave their T&D (ph) companies for the purpose of securing competitive electric and gas supplies continues to rise.

This year, we're bidding on 50% more business than we bid on in 2004, so we're now winning nearly 20% of what we bid on, up from about 13% last year.

We expect our retail revenues to be between 1.1 million and -- I'm sorry, 1.1 billion and 1.3 billion in 2005, compared with about 850 million in 2004.

Through the first six months of 2005, we delivered 5.3 million megawatt-hours versus 4.8 million megawatt-hours in 2004.

For natural gas, we delivered 27.8 billion cubic feet in the first six months of 2005 versus 22.5 billion cubic feet in the first six months of 2004.

We expect delivered megawatt-hours to reach 13 million in 2005, compared with 10 million in 2004.

We expect delivered natural gas to exceed 60 billion cubic feet in 2005, up from 40 billion cubic feet in 2004.

On average, our margins are holding.

Electric unit margins on new business range from $1.60 to $2.20 a megawatt-hour.

On the natural gas side, the unit margins range from between $0.20 to $0.25 per thousand cubic feet.

If you modify our projected volumes times our unit margins, you can see that our 2005 gross margin goal was approximately $40 million -- 25 million from electric and 15 million from gas.

Based on what we have had delivered to date and what we have under contract, we've secured approximately 70% of the gross margin we've projected for the year.

Many of our customers are signing short-term contracts in hopes that energy prices will fall.

Even so, we remain within reach of our targeted 2005 margins.

We continue to like this business and succeed at it, but as David mentioned, the $60 million after-tax first-quarter mark-to-market gain taken on retail sourcing will unwind.

We expect the 6 million negative impact in the second quarter to increase to 17 million in the third quarter of this year and drop to 4 million in the fourth quarter.

It will remain a significant negative, $20 million in 2006, and then decline to $10 million in 2007 and about $3.5 million in 2008.

Let's now turn to our merchant generating business, where we continue to see positive results.

Our power plants continue to run well, energy prices have strengthened and reserve margins have started to tighten.

We believe that generating 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.

Through the first six months of 2005, our 1080-megawatt Northfield Mountain facility had an availability of 94%, while the 147-megawatt Mount Tom plant had an availability of 91%.

Our nearly 200 megawatts of other hydroelectric unit had an aggregate availability of 85%.

Conventional hydrogeneration this year is nearly 10% ahead of budget due to good rainfall and plant availability.

That translates into over 400,000 megawatt-hours through June, compared with a projection of 370,000 megawatt-hours.

On an annual basis, we expect conventional hydroelectric production of approximately 650,000 megawatt-hours.

We're on track to exceed that in 2005.

We generate about 1 million megawatt-hours annually at Mount Tom, our coal unit located in Holyoke, Massachusetts.

Through June, we have generated more than 500,000 megawatt-hours.

At Mount Tom, we've begun a $14 million project to install a selective catalytic reduction system to reduce nitrogen oxide emissions.

The project should be complete before the summer of 2006.

We also have locked in coal contracts through 2008 that should allow this unit to continue to generate at an all-in fuel price of about $40 a megawatt-hour, a level that is very competitive in New England.

The centerpiece of our competitive generation fleet is the 1080-megawatt Northfield Mountain sub-storage station, from which we expect to sell 1 million megawatt-hours each year.

We've experienced a challenging market for Northfield during the past few years because of low on-peak, off-peak spreads and weak capacity markets.

But we've seen some positive gains lately.

The ratio of on-peak to off-peak prices rose to as high as 2 to 1 in June, up from about 1.4 to 1 earlier this year.

These spreads are the best that we've seen in almost two years.

This is important to us since Northfield requires nearly 1.4 megawatt-hours of electricity to pump water to the reservoir on top of the mountain for each megawatt-hour that we generate as the water flows down through its turbans.

We've realized $6 million of energy-related gross margins through June and are on target to earn 12 million in energy-related gross margin that we've projected for Northfield in 2005.

Going forward, we believe that Northfield's greatest source of potential revenue, however, is in the capacity market.

In 2006, we believe that if FERC approves LICAP to take effect January 1, consistent with the administrative law judge's recommendation, we will receive about $50 million of capacity-related revenue in 2006.

About 60% of this revenue will come from Northfield.

If there is no LICAP market in 2006, we estimate based on today's capacity values that our capacity and forward reserve revenue will be somewhat less than $30 million.

As we look several years out, we now believe that even without the introduction of LICAP, capacity will rise to above $3.00 a kilowatt-month by 2009, with significant additional revenue from forward reserves.

Based on our projections of the New England load and capacity situations, we believe that our capacity related and forward reserve revenue without LICAP could reach $90 million by 2009.

This is significantly higher than the $50 million that we were projecting earlier this year.

With Lightcap, we believe that capacity-related revenue will be still be approximately $120 million in 2009.

We know that many of you continue to track the progress of LICAP, both at FERC and in the U.S.

House-Senate conference committee on the energy bill.

Initial comments on the administrative law judge's recommendation were filed July 15 and additional comments are due next week.

ISO New England has indicated that it needs FERC approval of the LICAP market by September 15 to have adequate time to implement LICAP by January 1 of 2006.

We also continue to closely watch the energy bill to determine whether it will affect LICAP timing.

These developments continue to reinforce the strategic decision we made earlier this year to retain our own generation.

In fact, in anticipation of exiting our New England wholesale load obligations, we are exploring forward sales opportunities out of our conventional hydro and baseload pole (ph) units.

One last point worth mentioning involves the changes we've made to our competitive business organization.

We believe that for our retail marketing and merchant generation business volume to be successful, it is essential that our organization and cost structure reflect the competitive nature of these businesses.

We're reducing our current staffing level of greater than 500 by more than 100 positions.

This excludes the 700 employees in our services business.

While this is a very painful process because of the many long-tenured and valued employees who are finding their positions eliminated, it's been a necessary step in focusing our competitive business on the merchant generation and retail marketing going forward.

In addition to staffing reductions, we've undertaken a comprehensive review of our cost structure.

It is our goal to put in place appropriate cost-saving initiatives by January 1 of 2006.

Now, let me turn over the call to Cheryl Grise.

Thank you, Larry, and good afternoon, everyone.

I would like to start by providing some additional details about the important Connecticut legislation Chuck describe earlier.

The new so-called Energy Independence Law is designed to reduce federally mandated congestion costs by encouraging through various incentives the construction of new generation in Connecticut and the implementation of more conservation and load management initiatives.

Federally mandated congestion costs represent the cost of power market rules approved by FERC that are resulting in substantially higher costs for Connecticut.

The most significant cost item in 2005 is reliability must run contracts.

In 2006, it will be LICAP if FERC authorizes its implementation for 2006.

The new Connecticut law requires regulators to issue a request for proposal to build customer-owned generation, to implement conservation and load response programs and to contract for new or repowered larger generation facilities in the states.

Developers could receive contracts of up to 15 years from the distribution companies.

The law provides utilities with the opportunity to earn onetime incentives for generation that is installed in their service territory.

Those incentives can be as high as $200 per kilowatt for distributed generation and $25 per kilowatt for more traditional generation.

The new statute also allows distribution companies such as CL&P to bid as much as 250 megawatts of capacity into the request for proposal.

If a utility bid were accepted, then the unit after five years would have to be sold, have its capacity sold or both, provided, however, that the DPUC could waive those requirements if it determined it to be in the public interest.

The law also provides utility incentives to implement additional confirmation and load management measures.

The DPUC will be required to investigate the financial impact on distribution companies of entering into long-term contracts and to allow distribution companies to recover through rates any increased costs.

This was a direct result of the likelihood that Standard & Poor's will increase CL&P's level of adjusted debt as it begins signing new long-term contracts with generating.

The DPUC is moving swiftly to comply with the aggressive schedule set out in the new law.

Two days ago, it produced a schedule that should result in the awarding of long-term capacity contracts next year.

Chuck also mentioned earlier the passage in Connecticut of a transmission tracking law.

While this will not increase our earnings to date, it will benefit future earnings and should help the consistency of CL&P's distribution earnings and cash flow by ensuring that CL&P bills its customers on a timely basis for the transmission lines that are assigned to it by ISO New England.

This is particularly important during a period of new transmission lines construction throughout New England, which will result in regular increases in wholesale transmission tariffs.

This law will help avoid rate lag and improve cash flow stability and predictability.

And we were pleased that Standard & Poor's recently recognized its passage as favorable to our credit quality.

We expect to file with the DPUC next week a proposal to implement the transmission tracking mechanism.

This law really underscores one of the most critical factors in the success of our energy delivery businesses -- the ability to recover costs on a timely basis.

This includes the federally mandated congestion costs we have experienced in Connecticut for which we received an interim rate increase in May, as well as the fuel and purchased power-related costs we are seeking to recover in New Hampshire starting August 1.

Turning now to year-to-date results, Connecticut Light and Power, Western Massachusetts Electric and Yankee Gas each implemented distribution rate increases on January 1 of this year and through our Public Service Company of New Hampshire implemented its most recent rate increase on June 1.

These rate increases were necessary to offset increased operating expenses and interest expense.

Electric and firm gas sales for the second quarter were approximately 1% and 3% greater than the second quarter of last year, respectively.

However, on year-to-date basis, electric sales were the same as last year and firm gas sales were down 8/10ths of 1%.

On a weather-normalized basis, both electric and firm gas sales were approximately 1.5% lower than last year.

The impact of this was minimized as a result of cost control measures and relatively light storm damage so far in 2005.

On the regulatory front, the New Hampshire regulators lowered the allowed return on equity of Public Service Company of New Hampshire's nearly 1200 megawatts of generation to 9.63% from 11%.

On an annual basis, that will reduce earnings by about $0.01 a share, but we are asking the New Hampshire PUC to reconsider its position due a number of factors, including mathematical error.

In Connecticut, we received a file decision on streetlighting refunds that will force us to calculate refunds based on a longer look back.

And a higher financing rate than we had assumed.

As a result of that decision, as David mentioned earlier, we increased our reserve of refunds by $7.4 million or $4.4 million on an after-tax basis.

With that, I would like to turn the call over to Lee Olivier now.

Thank you, Cheryl.

I would like to update you on our transmission projects as well as the ongoing FERC docket that set blanket return on equity for New England's transmission owners.

First, I'm very pleased to report that all of our major Southwest Connecticut projects, which total more than $1.3 billion, have now received approval from the Connecticut Siting Council.

This is a major accomplishment and provides for a significant level of certainty and improvement in grid reliability while increasing transfer capacity into Southwest Connecticut.

These projects are at various stages of completion, which I will discuss in more detail and are on schedule and on budget.

The Bethel to Norwalk 345,000-volt line is now 30% complete, with an expected in-service date of December of 2006.

We continue to estimate that this project will cost between 300 and $350 million.

Our Middletown to Norwalk transmission projects received Siting Council approval in April, and while there have been three appeals filed to date, we do not expect any of these appeals to delay construction at this time.

NU's 80% portion of this project was estimated to cost between 670 million and $790 million.

We are currently updating the project cost estimates as we prepare and file the development and management plans for the Siting Council, which detail the precise project configurations.

On July 20, we received Siting Council approval for our Glenbrook Cables project.

This project is a nine-mile $120 million project which runs underground, 115,000, volts between Norwalk and Stamford, Connecticut.

We plan on beginning construction of that project next year and completing the project in 2008.

We're also clearing the final hurdles to begin work on the Long Island replacement cable project.

On June 20, the New York State Comptroller's Office and the New York State Attorney General approved an agreement between Connecticut Light and Power and the Long Island Power Authority to replace the 138,000-volt Norwalk to Northport Long Island cable build more than 30 years ago.

We expect to sign a construction contract for that project this summer and begin replacement in late 2006, so it can be operational in the spring of 2007.

We expect our 50% share of that project to cost approximately $72 million.

While there is a great deal of focus on our larger projects, we also continue to make significant progress on smaller projects in Connecticut, Massachusetts and New Hampshire.

These projects include the addition of a $22 million bulk transformer substation in Haddam, Connecticut, and a $19 million Tioga project which installs 115,000-volt lines in and around Manchester, New Hampshire and installs two new bulk substations.

As a whole, our portfolio of smaller project is on schedule and on budget, and we expect to place a significant amount of plant in service in 2005.

All of these developments over the past three months should underscore for you that our transmission program is moving ahead steadily.

There is a real momentum behind the program, driven by an urgent need for it, particularly in transmission- and generation-constrained Connecticut.

Successful execution of our transmission buildout in Connecticut and throughout New England is critical to the liability and to mitigating the impact of higher federally mandated congestion costs.

In February of 2005, the New England ISO and RTO became operational.

Since that time, the ISO has begun to play an increasingly active role in regional planning -- in the regional planning process identifying critical transmission needs and potential solutions, as the ISO seeks to strengthen the transmission infrastructure throughout New England.

We believe that this regional planning process will identify the need for significant transmission investment well beyond the five-year horizon that we typically discuss during these conferences.

Given the scale and pace of our transmission program, full and timely recovery of cost associated with this transmission investment is critically important.

Northeast Utilities has in place a former tariff structure which allows us to include the cost of our projects and rates immediately as those projects enter service, eliminating any rate lag and ensuring that we fully recover all of our cost.

And as Cheryl mentioned, we now have a retail transmission tracking mechanism in both Connecticut and Massachusetts, mitigating concerns about these costs getting trapped within the end-use system.

One tariff issue which does remain outstanding is the establishment of a base return on equity for the New England transmission owners.

In June, a FERC administrative law judge recommended a base of 10.72% return on equity for all New England transmission owners, plus a 50-basis-point incentive for joining the RTO.

The judge took no position on the potential for an additional 100-basis-point adder on new facilities.

The New England transmission owners took issue with many of the law judge's findings and filed exception briefs in late June.

We expect the FERC to issue a final decision in this case around the end of November of this year.

FERC's decision will be increasingly important to us in the years ahead, as we expect that significant investment that we're making will more than triple our $500 million transmission rate base by the year 2010.

Now, what I would like to do is turn the call back over to Jeff Kotkin.

Thank you, Lee, and I'm going to turn the call back over to Francis (ph), just to remind you of how to enter questions.

(Operator Instructions).

Ashar Khan, SAC Capital.

Can I just go over the -- first of all, you guys mentioned that you could be moving your equity forward this year from next year, if I'm right.

You guys had mentioned that the equity offering would be in 2006, and if I heard in the prepared remarks, you guys mentioned that you are now thinking of doing it in '05.

Is that correct, David?

Ashar, this is David.

I think what we said is that we have filed our applications with the SEC -- our U1 application in order to put us in a position to be able to issue late this year.

We haven't made that determination, but it is based in large part on the success that we're having in the transmission business.

The last time we talked, we were still waiting for the appeals around the Middletown to Norwalk project.

We now have those appeals in hand.

They may be a little more modest.

The thinking I think in the spring was there would be maybe a one-year stand-down period.

We would wait through that process.

Now it may be that in fact we move forward, so that if the 2006 CapEx program around transmission is a little more significant, it might be that we accelerate that process, and as I said, with applications completed and the reviews completed by the SEC, it could happen as late as the fourth quarter this year.

No determination at this point.

And then if I can just shift on the earnings, I guess CL&P, even if you add back this charge, was still underreporting earnings versus last year, and I guess the ROE is going south.

I am just trying to understand is that are we going to expect better earnings in the third and fourth quarter, or why is it under-earning, and what is the direct benefit from this new law?

I guess you guys mentioned you would probably get much better recovery of the transmission costs.

Is that what the real benefit is on a cash flow basis?

I can just address that last piece, Ashar.

Clearly, that's what the tracker is meant to do.

So, where in the first half of this year, the transmission business charged the distribution company and it had no ability to turn around and charge its retail customers, going forward, the tracker will allow just that.

It will pass those costs through and get the full earnings and cash flow basis of those charges.

So you will get both transmission earnings growing and the distribution companies held harmless.

And from which date is this tracker effective?

July of this year.

Okay, so we should now expect for the later half.

So all the underrecovery for the first -- what was happening in the current rate should go away and you should see a positive impact in the second half of the year because of this tracker.

Is that a fair statement?

That's a fair statement, and let me just put that in perspective.

I think those charges, while it did benefit the transmission segment costs, the distribution company is about $3.5 million during the first half of the year.

Okay, so David, if this tracker -- if you could just help me -- if this tracker was in effect January 1 of this year, would the earnings of the overall Company would have been higher?

Yes, absolutely.

By 3.5 million?

That's an approximate number, yes.

Okay.

And then just apart from that, is there any other reason why CL&P, their effect of the rate increases is not showing up?

Well, I think the Company is still earning just about its regulated cost to capital, which as you know, the Commission has set at 9.85%.

There were revenue increases for the Company flowing through, but as we continue to deploy capital, we have interest costs and depreciation costs, property taxes that are increasing.

So, on balance, we're still getting pretty close to that allowed.

And I will say that the sales, as Cheryl and I discussed, during the first half of the year were pretty modest, so we didn't get any sales benefit that we might have normally received.

But can I ask you if I heard her correctly, she said on a normalized weather basis, sales were down 1.5% or something?

That's correct.

Why is that happening?

It's Cheryl.

We think that our customers are actually starting to conserve a little in response to the higher prices that they've been experiencing since early in the year.

This is a relatively new phenomenon, but we're watching it carefully.

But we seem to be connecting as many customers as we have traditionally, so we believe that they are actually just conserving a little more.

Okay.

And then can I just ask you what's happening at WMECO?

It's similar.

Actually, we're seeing a similar phenomenon with respect to sales throughout our service territory.

So, on a normalized-weather basis, the sales are down in WMECO as well?

Yes, they are down in my entire distribution grid.

That's correct -- on a weather-normalized basis.

Okay.

Okay.

Thank you, Ashar.

I think the next call is from Paul Patterson from Glenrock Associates.

Just to clarify some things that Larry said, it's about a $20 million benefit that see in LICAP in 2006, and only a $30 million benefit in 2009, Larry?

Incrementally, Paul, that is correct.

Okay.

That's a pretax number.

And why is the non-LICAP number doing so much better now?

We're actually seeing some strengthening in the forward markets in the sense that the capacity market is going to be tighter in the 2007-2008-2009 time-frame, and so we've actually adjusted our expectation as to what the market clearing price will be for capacity, as well as revenue that we would derive from forward reserves, which is a source of revenue that we're not sure that would realize in a LICAP future.

Okay, and then the NUEI wholesale contracts, with all this mark-to-market adjustments, etc., do we have a simple sort of book value, plus or minus, that you guys have roughly speaking on what these contracts are now at sort of on your balance sheet, or how they are accounted for just in a purely -- what's the worth now with those most recent decrease in value?

We have that, give us a minute.

I will let somebody else ask a question and I know you guys are short on time here.

We will take you up on your invitation and we'll move onto the next question.

Then we'll get back to you on that answer.

Anthony Krasnell (ph), Jefferies & Company.

Jeff, I have a question on your ongoing EPS number for the quarter.

It says you reported $0.11.

I just want to verify my numbers.

If you add back the onetime charge at CL&P for the street lighting, which comes to about $0.03, and then you strip out the $6.3 million charge in the competitive businesses, I come up with something about a $0.19 ongoing EPS.

Does that sound correct?

Given those adjustments, that's correct.

We're going to get back to Paul's question.

Larry?

Paul, we thought we had answer.

We just wanted to check it.

The net position is minus $250 million, and that's what we have pretax on the books.

Michael Goldenberg, Luminous Management.

Just wanted to focus on LICAP.

As it stands right now, could you go through each one of your generation plants and tell us what you expect the dollars per KW month capacity pricing would be as LICAP stands right now, if it was approved?

Michael, can you repeat the question and maybe speak a little bit louder?

What the pricing for your generation plants would be in dollars per KW-month per LICAP as it is structured right now, assuming no changes.

And this is you're looking for -- over the '06, '09 period?

No, just 2006.

2006.

If you can give more, then that's fine.

Sure.

No.

Just remember that there are five zones in New England.

We would have generation in three of those zones.

About 100 watts would qualify for Southwest Connecticut, a couple hundred megawatts for the rest of Connecticut and then about 1300 megawatts for the rest of New England, the rest of the pool.

And we have, of course, some -- a couple of hundred megawatts of capacity that we have under contract, so (multiple speakers)

Southwest Connecticut is the coal plant, right?

No, no, no, it's hydro.

It's hydro, and then a couple hundred (multiple speakers)

It's 100 in Southwest Connecticut.

Rest of Connecticut is predominantly hydro, and then rest of pool would be the Mount Tom coal station, as well as the Northfield Mountain.

So all the Connecticut stuff, that's run of the river, and rest of New England is coal and pump storage?

Right.

Now, this is just a scenario, but if LICAP were instituted and you looked at what ISO New England filed and made some assumptions about load and capacity and so on, you would be looking at numbers for the rest of New England around $2.30 to $2.40 a kilowatt-month.

For the rest of Connecticut, more like $3.50 to 3.60 a kilowatt-month.

And our expectation is that the Southwest Connecticut zone would immediately go to $6.30 to $6.40 a kilowatt-month.

Now what plays out over the 2006 to 2009 or 2010 time-frame is that as the transmission projects are added, you see an equalization of LICAP throughout New England.

So the Southwest Connecticut zone stays at the $6.30 to $6.40 level, but the other zones converge gradually towards that number.

And so the out-year of 2009 or 2010, you're looking at $6.30 to $6.40 a kilowatt-month across our entire 1600 megawatts of generation.

So improved transmission offset by increased load and no new generation?

Correct.

Okay.

A modest amount of generation.

Modest amount of generation.

Okay.

So those are the current assumptions.

Two other quick questions.

One is on the LICAP being instituted as it currently stands.

What are you -- can you talk a little bit about timing of January 1, and how -- what powers do the Governor -- let's say, the Governor of Connecticut, have to delay that in any way?

I'm not quite sure how to handicap the date of January 1.

I think ISO New England has made it very clear that a lot needs to be done to have an option in place in December so that we can have a LICAP market functioning by January 1.

There is an issue that you raised which is more of a political issue, which is it has been recognized in discussions of the energy bill and there is a sense of Congress regarding locational solid capacity, which indicates that Congress is directing FERC to pay particular attention to the governors in New England.

And I don't know how that is going to play out.

Okay, but is it a 50-50, more than 50-50 -- is there any sort of--?

Can't handicap it for you.

Understood.

And finally, I just wanted to talk about the pump storage plant.

It had very high availability -- I think you guys mentioned 94%, was it?

Right.

What was its actual capacity and overall, what are the spreads you're seeing these days between on-peak and off-peak?

I don't have a year-to-date capacity factory number.

I can tell you that we produced about 400,000 megawatt-hours in the first six months of the year.

We were projecting (multiple speakers)

I can back into the capacity.

And what are you seeing these days in on-peak versus off-peak?

We're seeing on-peak prices in the $100 to $140 range on a good day and we're seeing pumping costs -- the price that we pay for pumping at about 50 to $60, but add 40% of that to get our true cost of generation.

Right.

So 1.4 times gearing?

1.4 times 50 would get you to 70, which would tell you what our all-in costs would be.

Right, it takes 1.4 megawatt-hours to create (technical difficulty).

Right.

Greg Orrill, Lehman Brothers.

I wanted to go back to the discussion on retail marketing, and I wasn't quite sure I got what the numbers were from '06 to '08 that were being described.

Was that -- what was that, I guess?

We had taken an after-tax gain for power that we had purchased to supply our retail loads, and we took an after-tax gain of $60 million in the first quarter of this year.

That will unwind associated with the loads that we had actually sourced, and that will unload negatively throughout the subsequent quarters and years.

You saw a $6 million negative impact of that unwind in the second quarter of 2005.

You will see 17 million negative in the third quarter, 4 million in the fourth quarter.

This will remain a significant factor to the tune of $20 million in 2006, drop to 10 million in 2007 and between 3 and 4 million in 2008.

Okay.

And then, separately, just going back to the discussion around what capacity markets later on in the decade would bring.

I guess, what are your anticipations -- what are you seeing in terms of pricing?

I think what we thought a LICAP scenario would be, which would be prices depending on where we were and which zone we were in, between $2.30 to $2.40 and between $6.30 to $6.40 in the early and out years.

The capacity markets right now that we use for a -- the assumptions we use for our no-LICAP scenarios, the capacity markets are less than $0.80 a kilowatt-month right now.

We've seen $1.35 in the 2006 time-frame and we've seen a bid-asked (ph) spread of $1.50 to $2.00 in the 2007 time-frame.

Zach Schreiber, Duquesne.

Actually, my questions have been asked and answered.

Sorry about that.

Ashar Khan, SAC Capital.

Just a follow-up on if I can get -- Larry, if LICAP is not implemented, what is the incremental capacity payment under your budget for '06 versus '05?

Incremental, I mean, we're seeing significantly less than $1.00 today per kilowatt-month.

Our assumption for the 2006 projections is roughly the same kind of number, say, $0.60 to $0.80 a kilowatt-month.

So if LICAP in the worst-case situation doesn't go through, incrementally there will be no gain on the capacity side?

There will be no gain on the capacity market revenue.

Remember there's another market in play, which is the forward reserve market.

And in the forward reserve market, you have to meet certain conditions of being able to ramp your units quickly, and we have several units, including Northfield, that will qualify for that and will derive revenue in the forward reserve market.

And that's duplicate to any capacity revenue.

We refer to both the capacity or LICAP, as well as the forward reserve revenue, as capacity-related revenue and we would have revenue from both sources in 2006 without LICAP.

I understand, but there might be some incremental there in '06 or no?

That was my question -- '06 versus '05.

Yes, yes, we've seen $1.35 and we're assuming $0.60 to $0.80 right now.

Okay.

And then if I can just ask -- David in his initial remarks said that as you stand right now, you talked all of these contracts, getting them off and all that were going to have not major impact -- very small, and that you talked now that the impact would be higher, slightly higher.

David, can you quantify by how much higher?

Is it about 10 million, 20 million, 30 million, or what the number is in your change in your outlook?

Sure.

I think it clearly depends on the way in which we exit these businesses in all of these contracts.

In the first quarter we had use the terms modest.

Here, since that time, the markets moved away from a $60 million, so if we were to settle on that mark after tax it would have cost us another 30, $40 million of cash.

Okay.

So it's about 30, 40 million more cash right now, as you stand.

And just going back to your negotiations with the other municipalities, is that something else?

And on the remaining book, David, as you're going with Lazard, is that something which we could see resolved by the end of the third quarter?

It's quite possible that that will be resolved by then.

So could it be resolved next month?

You know, we're going through the process right now.

I think we are making progress.

Clearly, if we continue on this path we will get it done third quarter.

But not clear, Ashar.

And then can we expect guidance after it's resolved for the whole business at that period of time?

I think over the last couple of years we've tried to provide guidance early in the third quarter, typically around the EEI conference, and I think we may remain on track to do just that.

Ashar, I think that is for -- David's talking about for '06, not for '05.

Why don't we take our next question from Zach Schreiber from Duquesne.

Just a question on LICAP and capacity values and forward reserve market.

Any thoughts or any estimation as to why capacity prices are going up in the market irrespective of LICAP?

Is this kind of one of those things where people think there's going to be capacity values set administratively one way or another, and even if it's going to be -- there's going to be a delayed implementation of LICAP?

I know that they're going to need to own it and procure it, so you're seeing that concept express itself through alternative products.

Or is there organically a real sort of tightening in the underlying capacity reserve margin, such that we're actually seeing that economic signal be sent, and if that economic signal continues to be sent organically, is that going to save FERC from having to put in place their own capacity and market and take all the political heat because the market is going to do FERC's job for it?

Zach, I think you have both factors in play here.

Clearly, there's a sense that capacity margins -- reserve margins, capacity margins are tightening in New England.

I think there's also a bit of fear that there may be administratively some very high prices that people may have to pay, and so some of that may be factored into the forward quotes that we're seeing today.

Those quotes are lower than what might play out under a certain set of assumptions, but people might be willing to pay that for insurance to avoid a FERC-mandated payment stream.

So then the fact that there may be a LICAP premium already in some of the alternative products because they could be theoretically transferable or convertible into LICAP?

Yes, but those numbers -- those premium -- the total price is not high as what I think you would see with the LICAP market administered by the ISO.

Can you sort of tell us how these capacity prices or reserve prices have fluctuated over the last six months, just kind of paint that?

They've been between $0.60 and $1.00 a kilowatt-month, up and down, and we tend to look at that on a forward basis -- forward 12 months.

And if you can pardon the ignorance, what exactly is a forward reserve?

A forward reserve is a payment that we would receive as a generator for being available to ramp our units up and down.

And there's a parallel -- there's an option for forward reserves.

There's actually two options a year -- one held in the spring for primarily the summer period, one held in the fall for the remainder of the year.

And the payment streams that we tend to see from those numbers are $2.00 to $4.00 dollars a kilowatt-month.

$2.00 to $4.00 per kilowatt-month?

Right.

Sometimes a little higher than that.

And what kind of generation qualifies for that?

It's generation that has the ability to move quickly to ramp up around town, so in our fleet it would be Northfield Mountain, Rocky River and we have some jets -- some peaking units at South Meadow on the east side of the state that we call tunnel.

And is it safe to say that these alternative products -- these alternative capacity markets, are they going to be convertible into these LICAP products?

I.e., if I wanted to express a view on LICAP, I can go out and buy this stuff and hope that LICAP is implemented?

Or, I mean, are they going to be convertible one-for-one into different sort of LICAP requirement units?

How is that going to work?

Or are these people saying I don't know when this thing is coming, but you are going to need capacity one way or another, and I might as well buy this stuff now as insurance.

And it may not be convertible in a clean way, but it's going to be convertible in a kind of directional way.

I'm not quite sure which way this is going to go.

I'm not quite sure what to say about the fungibility of the existing products.

Clearly, there's some correlation.

Whether it's one-to-one I think is probably stretching it just a bit.

And then the last question is whether the forward reserve product is part of other ancillary services products?

We tend to group it with capacity-related revenue.

So, that qualifies as an ancillary service or not?

It could.

I mean, it's a separate market.

I mean, when you talk about ancillary services, you're talking about regulation and things of that nature.

Next question is from Mike Weinstein from Zimmer Lucas.

Actually, just to go back to what Zach was just asking, it's my understanding LICAP is simply capacity payments.

This forward reserve ancillary services -- that revenue should continue, even on top of LICAP, from the way I understand the system will work.

Yes, it's not clear, Mike.

I think it's actually constructed both scenarios -- one where you have parallel markets and one where you may have to take a credit of any forward reserves against any LICAP payments.

Okay, well, interesting.

So, from what I can hear, it sounds like your estimate of capacity prices going forward, that 90 million does not include the forward reserve, right?

No, it does include the forward reserve.

Oh, it does include that.

Yes it does.

Okay.

And (multiple speakers)

And the 120 does not.

Does not include it?

Right.

That's in like a stressed scenario, right? 120?

Is that what you're saying?

120 is our best assumptions about how LICAP would (multiple speakers)

Oh, with LICAP.

I get it.

Okay.

Had you guys heard at all or do you have an opinion on what's going to happen with the energy bill in terms of -- I think it was the Domenici amendments -- you know, the one that wants governors' approval?

Are you guys getting any kind of political sense about what's going on in New England -- about whether LICAP will actually be implemented on time?

No, what you are referring to, of course, is in conference we saw the sense of Congress regarding locational solid capacity.

And what we have is a directive that FERC paid particular attention to the concerns of New England governors.

We haven't heard anything specifically on that.

I mean, I think we've all heard tidbits as to how we ended up with this sense of Congress, but that's all rumor.

Mike, this is Chuck.

The bill just essentially gave a sense of Congress that in no way prohibited LICAP, and so far we haven't seen from FERC any backing off of the positions that they've taken on LICAP.

Not to say that they may not.

Of course, there's a lot of political opposition to that in New England.

But it's not precluding us or not precluding FERC from doing that.

Oh, are you saying that because it's a sense of Congress that this is not -- even if the amendment is included in the energy bill, it would not be a requirement to get governor approval?

It's just a request?

My understanding is it is a sense of Congress that they should consider the governors' objections, but it does not prohibit them from having -- -- or does not prohibit FERC from implementing LICAP.

We only have time for one more question.

Michael Goldenberg, Luminous.

I just want to go back to this whole issue of LICAP and capacity payments on top.

When you told me the LICAP payments, and I guess I calculated revenue, the way you think about your business right now, you're thinking that's going to be on top of existing capacity payments or instead of existing capacity payments?

I understand there's two possibilities, but which way do you think about your business?

We currently have constructed two scenarios.

One scenario is LICAP is put in place January 1, 2006, and LICAP provides the entire capacity-related revenue stream for our market generation fleet.

The second scenario is that LICAP does not go into effect and that we would continue to participate in the capacity markets, as well as the forward reserve markets, and that we would add to the revenue stream from those two markets and call those capacity-related revenue.

Now, in the LICAP scenario, there's discussion of a forward reserve market.

We are assuming that whatever we derive from the forward reserve market is netted against any payments that we would have received from LICAP.

Got you.

So, if I'm looking at 2006 upside from LICAP or 2007-8, I should subtract these minimal payments that you're getting these days.

I'm not sure I heard the beginning of your question.

If I'm trying to estimate your 2006, 7, 8, 9 upside from LICAP, I should take the LICAP number and back out the rather minimal amounts you're getting these days from capacity markets.

Yes.

It's an alternative to.

That's correct.

Got you.

Okay, understood, thank you very much.

Michael, thank you very much and thank everybody for joining us today.

If you have any future questions, you know, give us a call today or tomorrow, and stay cool.

Thank you very much.