康涅狄格電力 (ES) 2007 Q2 法說會逐字稿

Good morning and thank you for joining us.

I am Jeff Kotkin, NU's Vice President for Investor Relations.

Speaking today will be Chuck Shivery, NU's Chairman, President and Chief Executive Officer; David McHale, NU's Senior Vice President and Chief Financial Officer; and Lee Olivier, NU Executive Vice President who oversees our regulated businesses.

Also in the room today is Shirley Payne, our Vice President and Controller.

Comments made this morning contain statements concerning NU's expectations, plans, objectives, future financial performance and other statements that are not historical facts.

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

In some cases a 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 or inactions by local, state and federal regulatory bodies; competition and industry restructuring; changes in economic conditions; changes in weather patterns; changes in laws, regulations or regulatory policy; changes in levels or timing of capital expenditures; developments in legal or public policy doctrines; technological developments; changes in accounting standards and financial reporting legislation; fluctuations in the value of our remaining competitive electricity positions; actions of rating agencies; subsequent recognition, derecognition and measurement of tax positions; and other presently unknown or unforeseen factors.

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

Any forward-looking statement speaks only as to the date on which such statement is made, and 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.

I will now turn over the call to Chuck.

Thank you, Jeff, and good morning, everyone.

I am pleased to say that this was another good quarter for Northeast Utilities.

We earned $0.31 per share in the second quarter and $0.80 a share in the first six months of 2007.

Those results are consistent with the earnings guidance we first provided you last November of between $1.30 and $1.55 per share.

When we speak of another good quarter, we're discussing a wider range of progress than we have made over the past several months, progress that includes positive developments in the regulatory and legislative arenas; positive developments on our capital investment program; and positive developments in both our ongoing operations and the continued unwinding of the remainder of our competitive businesses.

We consider this past quarter to be the latest in a series of quarters dating back to early 2006 where we have made significant progress implementing the strategy we announced in November of 2005, a strategy that is paying dividends for our customers and for our investors.

Lee and David will provide you with more financial and operational details, but I would like to take a moment to focus on a few key accomplishments we have made since April.

Many of our key initiatives involve working with our customers to contain and, where possible, reduce their overall cost of energy while providing them with a reliable and secure energy infrastructure.

To that end, we believe that the Connecticut legislation took a major step forward in June when it passed and the Governor signed new energy legislation.

That bill contains incentives for customers to reduce both their use and peak demand for energy.

In working on that bill, our focus was on a number of items, including providing the state with a better long-range energy planning process, providing CL&P with more flexibility in its power procurement process, allowing more options for constructing new generation and restoring funding to the state's energy conservation programs.

The legislation does all of that and provides us with new opportunities to potentially invest money in regulated rate base investments.

Let me focus on two of those areas -- peaking generation and integrated resource planning.

And I will ask Lee Olivier to cover a couple of others.

The legislation requires electric distribution companies to propose in January of 2008 new peaking generation in Connecticut.

The amount of peaking generation we can propose is not defined, but we believe Connecticut requires several hundred megawatts and we intend to summit a proposal, subject to DPUC approval, to meet much of that need.

We are encouraged that CL&P and the state of Connecticut have an option available to them for utilities to participate in building generation that had been closed for nearly 10 years.

The second area relates to integrated resource planning.

The legislation requires distribution companies to submit an annual plan to the state, then find demand-side and supply-side needs for Connecticut in the three-, five- and 10-year horizons.

The legislation has a stated preference for demand-side programs and energy conservation, and to the extent the need for additional generation can be identified, distribution companies could submit a proposal to build it.

This planning process, which has largely been absent since restructuring in the late 1990s, is an important step forward for Connecticut.

By focusing on long-term planning, we believe we can produce long-term answers to the state's concern about adequate electricity resources and high costs, which are in part related to the fact that the state currently is heavily dependent on imports to meet its peak load requirements.

We are now working to develop a plan that can be filed with the state at the beginning of next year.

In New Hampshire, the legislature regrettably did not act to allow Public Services New Hampshire to build additional biomass generation.

However, it did undertake a number of important policy initiatives.

First, it established renewable portfolio standards for the state.

Second, it approved a separate bill that directs the New Hampshire Public Utilities Commission to encourage upgrades to the transmission system in northern New Hampshire, directs the State Site Evaluation Committee to develop new rules for siting renewable facilities, and adds utility ownership of distributed renewable generation and demand-side management to the topics that the Legislature's standing State Energy Policy Committee should examine.

Taken together, we are encouraged that New Hampshire sees the value of plants such as our 50-megawatt Northern Wood unit in Portsmouth that we build on budget and are operating successfully.

We hope that success will be recognized as we continue our efforts at the capital to be allowed to build renewable generation in the state.

This movement toward renewable generation is common across all six states in New England.

Along with upgrading the region's transmission grid, new investment in both renewable generation and the infrastructure needed to bring that generation to New England load centers will be a significant focus for Northeast Utilities over the coming years.

We see it as a natural extension to the transmission we're currently undertaking.

Currently, we are upgrading transmission links between Southwest Connecticut and the remainder of New England, as well as Long Island.

The NEEWS project we are undertaking with National Grid are designed to remedy east-west power flow deficiencies in the region.

As a result of our ongoing transmission projects and completion and successful operation of Northern Wood, we have developed a leadership role in the development of transmission and renewable generation in New England.

A natural follow-on role for us would be to make increased renewable generation accessible to the region's load centers, whether that generation is built in northern New Hampshire, or Maine, elsewhere in New England or in Canada.

We hope to both transmit some of that power and to a limited extent participate in its generation.

Even with such new opportunities on the horizon, it remains critical for our management to continue to focus on sound execution of our capital program so that our current projects are completed on time and on budget.

Effective project management benefits our customers by bringing reliability-related initiatives into service on or ahead of schedule and on or below budget.

Recent success occurred last month when we completed Yankee Gas' $108 million, 1.2 Bcf LNG storage and production facility.

We also are now reviewing our Middletown and Norwalk transmission project to determine whether it can be finished earlier than our initial targeted completion date of the end of 2009.

Before turning the call over to Lee, I would like to discuss one other area where we have achieved significant progress over the past several quarters.

That is in laying the groundwork to restore an adequate level of profitability to our distribution businesses and to implement mechanisms that would keep our ROEs at reasonable levels going forward.

We have largely accomplished those goals with our WMECO rate settlement that took effect January 1 and our Public Services New Hampshire and Yankee Gas rate settlements that took effect July 1.

With those three cases behind us, we are now focused on our largest distribution company.

Earlier this week, CL&P filed its distribution rate case, a case that is very important in our efforts to improve the lagging financial performance of CL&P's distribution business.

We need a reasonable outcome in that case to achieve a fair return to NU's shareholders.

NU's senior management is extremely focused on this case, and we will keep you abreast of its progress.

Now let me turn the call over to Lee.

Thank you, Chuck.

There has been a number of positive developments since our last call in April.

So I would like to review them with you by category, which is operational, capital investment and our plans to meet the requirements of the new Connecticut legislation that Chuck just described.

On an operational basis, our system has performed well this summer.

Although New England eclipsed its all-time peak demand record for the month of June this year, our system has operated smoothly.

The combination of additional inspections and investment in our underground distribution systems, the start of which we anticipate will be a five-year initiatives to upgrade those systems, and somewhat lower July and early August peak demand compared with last year, have helped us to prevent some of the outages we experienced last summer.

Increasing our investment in our distribution system will be a significant focus in the CL&P rate case we filed earlier this week.

We're proposing to increase the distribution capital expenditures from approximately $210 million in 2006 to $290 million in 2007, 2008 and 2009.

Our Bethel-to-Norwalk transmission line energized last fall and the balance of our transmission system continued to operate very reliably.

In addition to improving reliability, the Bethel-to-Norwalk line is lowering customer bills.

Adjusting costs have been cut in half to date in Connecticut, down from $120 million through the late July of 2006 to about $60 million over the same period of this year, and we expect to see this trend continue.

PSNH customers continue to benefit from our generation fleet in New Hampshire, which generates about 60% of the customers' needs through a combination of coal-, hydro-, wood- and natural gas-powered facilities.

Those units has operated very well and are on plan for capacity and energy production.

Effective May 1 of this year, three of PSNH's low-cost hydroelectric facilities totaling 30 megawatts were issued a new 40-year license by the Federal Energy Regulatory Commission.

This fleet continues to provide excellent economic benefits to PSNH customers and PSNH energy rates continue to be the lowest among the major utilities in New England.

Our 50-megawatt Northern Wood power plant, which began commercial operation in December of 2006, has operated at a capacity factor of about 70% this year, including a seven-day scheduled outage in April.

We continue to see a robust market for sale of renewable energy certificates in New England, a revenue source that has allowed us to reflect this environmentally advanced $74 million project in rates without an increase in PSNH customer bills.

Yankee's new 1.2 billion cubic feet LNG facility in Waterbury, Connecticut, was completed in July and is in rates.

We began filling that facility with LNG trucked in from the Boston area and we continue to fill it with natural gas from the Algonquin pipeline that we are liquefying on site.

We have tested all the major equipment and expect the tank to be full when the heating system begins on November 1.

During our negotiations to resolve both the PSNH and Yankee Gas rate cases, we committed to increase our annual distribution spending.

For PSNH, we agreed to increase capital investment on the liability projects by about $10 million in the first year of the settlement.

Yankee Gas also increased its capital expenditures for system integrity projects to $15 million annually.

As a result, we will show you our new five-year capital spending projections at EEI.

You'll see higher levels of distribution capital than we showed you last year.

We see these regulatory agreements and higher distribution capital expenditures as a positive trend, demonstrating that commission staff and consumer advocates recognize the need to increase expenditures on delivery system reliability and infrastructure.

We hope that trend will continue with our CL&P rate case.

Turning to transmission, the earnings improvement we have seen to date is due to the rapid progress we are making in our major projects and on our system upgrades.

If you look at our first series of initiatives, the four major transmission projects to improve reliability in Southwest Connecticut, we have now spent about half of the $1.65 billion we expect to spend by the end of 2009, when all four projects will be complete.

Our [serve the] Middletown-to-Norwalk project, due to be finished by the end of 2009, is now about 38% complete and ahead of schedule.

We are reviewing the remaining elements of the project to assess if an earlier completion date can be achieved.

Our $183 million Glenbrook project to build 115kV underground lines between Norwalk and Stamford, Connecticut, is about 36% complete and on schedule to finish in the second half of 2008.

Finally, we have now secured state permits needed to replace our 138,000-volt undersea cable between Norwalk, Connecticut, and Northport, Long Island, and expect to receive the Army Corps of Engineers permit shortly.

The cable is now being manufactured in Norway and we expect to install it this winter.

Our share of this overall project will cost about $72 million and we estimate it is about 41% complete at this time.

In addition to the major Southwest Connecticut projects, about 70 others transmission projects in our three states are currently under active construction.

In general, these projects are going well.

We continue to identify opportunities to complete our Southwest Connecticut and other projects earlier than we had anticipated and have added additional capital projects to be completed this year.

As a result, we have increased our 2007 transmission capital budget from $700 million to about $750 million this year.

As you may recall from our prior calls, we are continuing to move forward with our next major set of transmission projects known as the New England East-West Solution or NEEWS.

This family of projects includes 115kV additions and upgrades in the Springfield, Massachusetts, area, as well as 345kV projects in Massachusetts, Connecticut and Rhode Island.

NEEWS is a joint project with National Grid and our share is expected to cost between $1.1 and $1.4 billion, probably toward the upper end of that range.

The Springfield 115kV upgrades consist of about 22 circuit miles of upgraded overhead transmission lines, 10 circuit miles of new and replacement underground circuits and the rebuilding of several substations.

These improvements will upgrade a critical section of our system, which is nearing its full capacity at peak.

We are currently reviewing these upgrades with ISO [and Inman] and hope to complete that process by the end of this year, at which time we will begin to file applications with Massachusetts siting agencies, commencing with the underground circuits.

We currently expect these upgrades to cost between $250 and $350 million and be completed by the end of 2010.

The NEEWS 345kW upgrades consist of four groups of projects.

First, CL&P and Western Mass Electric expect to build a new 345kV line from Western Massachusetts into Connecticut.

Second, National Grid will upgrade the ties between Northern and Central Rhode Island.

Third, National Grid will expand the 345kV system in Central Massachusetts and Rhode Island to connect to the Connecticut border.

CL&P would build the Connecticut section of that third group of projects and would also build the fourth group of projects in Central Connecticut.

Working jointly with National Grid, we expect to complete the ISO review of these projects, some of these 345kV projects, early next year and to begin making siting applications in Massachusetts, Rhode Island and Connecticut around that time.

Our preliminary schedule calls for these projects to be complete in 2013, but there will be a lot of approvals to secure, contractors to hire and contracts to negotiate, so this is very preliminary.

At this time, we expect our share of these 345kV projects to cost between $850 million and $1.1 billion, which includes 21 miles of underground construction in those estimates.

To the extent our final studies determine additional underground construction is feasible, costs could increase since underground construction costs are about five times more than overhead lines.

Turning from capital projects to regulatory compliance, in late June NU became the first transmission operator within the Northeast Power Coordinating Council region to be audited for compliance since reliability standards became mandatory on June 18.

The audit was undertaken by the North American Reliability Corporation, which is serving as the auditor for the Federal Energy Regulatory Commission.

The preliminary findings were very positive.

FERC auditors found us in compliance with all of the auditing standards and found our documentation and employee support excellent and precise.

This was a very important audit of us because, as I have said before, there are very serious financial and reputational ramifications for transmission operators that do not operate their systems in accordance with all of the standards and requirements approved by FERC.

Before I turn the call over to David, I would like to amplify on some of the additional aspects of the Connecticut legislation Chuck described, starting with peaking generation.

We believe the peaking generation proposal required by the Connecticut legislation is important for Connecticut customers and NU.

Therefore, we have asked John MacDonald, a Vice President of Public Service of New Hampshire Generation, to lead our efforts to develop a comprehensive proposal which will be filed in January of 2008.

John is a seasoned generation professional with over 30 years of experience and was responsible for the development of PSNH's highly successful renewable energy Northern Wood facility commissioned late last year.

Once the projects are proposed, the legislation requires the DPUC to issue a decision within 120 days.

Other parties could also propose peaking generation, which the DPUC could select in addition to or instead of distribution company generation.

Any peaking plant proposal we make would be for a cost of service rate-base generation.

Legislation calls for the return on equity for such generation to be developed outside of the distribution rate case.

Another topic addressed in the bill is Advanced Metering Infrastructure, or AMI.

Our AMI implementation plan was modified on July 2 to correspond with the new statute.

We provided the Commission with a range of seven alternatives, from a modest initiative which would install AMI only at our customers' request to the full deployment of AMI technology in all 1.2 million customer sites.

We will update you as we receive a DPU response to our proposals.

A third element of the bill is revenue decoupling, and we have made a proposal in the CL&P rate case that would partially decouple distribution revenues from sales volumes.

Our revenue per customer decoupling proposal is similar to what Maryland Public Service Commission approved last month for Potomac Electric and Delmarva Electric.

Our proposal would align our interests with those of customers who are seeking to reduce their usage of electricity.

We expect the DPUC to rule on the decoupling proposal early next year when it rules on the full CL&P rate filing.

Now I would like to turn the call over to Dave McHale.

Thank you, Lee, and good morning.

Now that we're more than halfway through 2007, we are pleased to say we're meeting our earnings targets, deploying our capital, completing projects, improving our internal cash generation and completing our distribution rate case with outcomes that are consistent with the 9% to 10% distribution returns on equity we first targeted for you in late 2005.

In terms of our overall financial results, we are right on track.

On a consolidated basis, we earned $48.5 million in the second quarter of '07 and $123.6 million in the first half of this year, compared with $22.2 million and $12.1 million in the same periods of last year.

Our regulated and parent company segments earned $46 million in the second quarter or $0.30 a share, up 26% from the second quarter of '06.

In the first six months of the year, our regulated and parent segments earned $116.2 million or $0.75 a share, up 31% from the first half of 2006.

Through June, our distribution and generation segments earned $71.6 million or $0.45 per share, and we remain quite comfortable with our full-year guidance of $0.80 to $0.90 per share.

Our transmission business earned $37 million or $0.25 per share through June, and since transmission earnings grow as rate base grows, we remain comfortable with the $0.50 to $0.60 per share we expect to earn this year.

Because transmission earnings are tied to capital investment, not to items such as sales, weather or severity of storm damage, [early] transmission earnings tend to grow in a linear fashion over the course of a year.

Transmission rate base at the end of June was $1.2 billion, up from $1 billion at the end of 2006, and is expected to reach $1.45 billion by the end of this year.

Our parent company and other affiliates earned $7.6 million or $0.05 per share through June, at the top end of our full-year guidance of zero to $0.05 a share.

As a result, we're also quit comfortable with our consolidated earnings range of $1.30 to $1.55 per share for '07.

When we speak with you again at EEI in November, we will announce third-quarter results and provide you with more refined guidance relative to where we expect to end this year.

Let's take a closer look at the business segments, starting with transmission.

As you have seen in past quarters, the greatest growth of transmission earnings occurred at CL&P.

This is a function of our transmission construction being focused right now in Southwest Connecticut.

Through June, CL&P accounted for $267 million of our $297 million total transmission CapEx.

Because our transmission rates track our capital investment, CL&P accounted for $30.4 million of the $37 million of transmission earnings to date, up from $18.8 million we earned in the first half of last year.

Within the distribution segment, CL&P earned $7 million in the second quarter and $27.6 million year to date compared with $6.4 million in the second quarter of last year and $29.8 million in the first half of 2006.

CL&P benefited this year from higher sales, the $7 million annualized distribution rate increase that took effect at the beginning of this year, an increase in rate base that resulted from the tax impact of selling or competitive generation last year.

For the year-to-date results, some of these benefits have been offset by higher depreciation, operating and interest expenses, and the loss of about a $0.5 million procurement fee in the absence of a state tax settlement that benefited the first quarter of 2006.

From a returns standpoint, CL&P's distribution earnings are clearly below where they should be.

Over the last 12 months, CL&P's regulatory return on equity is approximately 7.8%, well below our currently authorized 9.85%.

We expect continued ROE erosion through the end of 2007 and estimate a year-end ROE of between 7% and 7.5% -- again, well below our currently allowed authorized rate.

These results underscore CL&P's need for distribution rate relief.

As Chuck mentioned, we filed with Connecticut regulators this week for a $188.8 million distribution rate increase in 2008 and an incremental step increase of $21.9 million in 2009.

The first year's change would result in a 4.6% increase in overall customer bills.

A number of factors are driving this increase, including actual retail sales being about 5% lower than it was imputed into our rates four years ago; the need Lee described to make additional investments in our distribution system; and the need to offset a $30 million a year four-year credit to distribution bills that was instituted in 2004 to refund the customers about $120 million of previous generation overcollections.

I would like to mention some of the specific financial metrics contained in our schedules to our rate application, which we filed earlier this week.

We are requesting a weighted average cost of capital of 8.47% and an 11% return on equity.

We are asking for a common equity component in rate-making of 49.5%, which translates into a 45% equity component as measured by rating agencies.

We're proposing capital expenditures of $294 million in 2008 and $288 million in '09.

Average rate base for 2008 would amount to $2.308 billion and $2.464 billion in '09.

Should the DPUC grant rate relief based on these parameters, CL&P's distribution segment net income would amount to $111.8 million, up from $74 million we earned in 2006.

This figure excludes the tax benefits the Company received relative to the IRS private letter ruling in 2006.

To help you understand the case, we have posted our testimony and summaries of testimony on the Investors section of the NU website.

Currently, we expect hearings to be held in the late fall, with a decision in early 2008.

We are asking that new rates be effective January 1 of 2008.

From CL&P, let me turn to PSNH, where we implemented a $46.6 million delivery rate increase last month, an increase that was more than offset by a $0.0075 per kilowatt-hour decrease in the energy charge.

This resulted in a 0.4% reduction in overall rates on July 1 for PSNH customers.

PSNH's distribution and generation businesses earned $12.6 million in the second quarter and $20.7 million in the first half of '07 compared with earnings of $12.9 million in the second quarter of '06 and $15.4 million in the first half of '06.

The lower quarterly results were primarily the result of an unusually low effective tax rate in the second quarter of last year that resulted from a timing issue related to the end of PSNH's amortization of its Part 3 stranded costs.

Second-quarter 2007 earnings benefited by about $2.7 million from the recovery of retail transmission costs per the rate settlement that had been expensed in 2006.

Year-to-date '07 results are better than last year's due to a 1.6% increase in retail electric sales, the impact of a $24.5 million T&D rate increase that took effect in July of '06, and the effect of a retail transmission tracking mechanism that had been approved for PSNH as part of the rate settlement.

PSNH's regulatory return on equity was approximately 9.4% for the 12 months ended June 30, '07, and we expect it to remain between the 9% and 10% at year end.

Western Mass' distribution earnings continued to benefit from the rate settlement we implemented on January 1, which included a number of tracking mechanisms.

WMECO earned $3.5 million in the second quarter of 2007 and $9.4 million for the first half of the year compared with $1.6 million in the second quarter of '06 and $5.8 million for the first half of '06.

Over the 12 months ended June 30, '07, WMECO's regulatory ROE was approximately 10.1%, the best among our four distribution companies.

Yankee Gas earned $300,000 in the second quarter of 2007 compared with a loss of $100,000 in the second quarter of last year.

Over the first half of 2007, Yankee earned $13.9 million compared with $11.7 million last year, a nearly 20% increase.

Yankee has benefited from an 11% increase in firms sales this year due to colder weather and more competitively priced natural gas, but its regulatory ROE over the past 12 months was still only 6.6%.

We think Yankee is at a key inflection point today.

Its 108 million LNG facility is now complete, in service and in rates.

Also, a very important rate case is now over, resulting in an increase in base rates of $53.7 million annually, effective last month, offset by more than $31 million in commodity-related savings related to the operation of the LNG facility.

Like PSNH and Western Mass Electric rate increases, Yankee's increase was a result of a settlement with the Commission and the consumer staff.

As a result of this increase, we expect Yankee's earnings to improve considerably over the next 12 months and for us to achieve the 9% to 10% distribution ROEs we have targeted.

Yankee's sales gains were much more significant than the electric companies.

Retail kilowatt-hour sales were up 1.6% in the second quarter of 2007 compared with last year.

On a weather-adjusted basis, they were up 1.2%.

For the first half of the year, electric sales were up 1.7% compared with '06 and up 0.8% on a weather-adjusted basis.

Our competitive businesses earned $2.5 million in the quarter and have earned $7.4 million in 2007.

This compares quite favorably with last year, when we had a number of charges associated with our former retail marketing business as we were selling it.

As a result, our competitive businesses lost $76.9 million in the first half of last year.

The profitability this year results from modest operating profits, including some favorable outcomes as we unwind our remaining contracts and projects.

We now expect the competitive businesses to be modestly profitable this year, including the impact of marking to market our remaining wholesale power positions.

To date, we have experienced an after-tax loss of $1.2 million marking these positions to market.

On May 31, four of our remaining five PJM wholesale contracts expired, meaning we only have about 10 months left on a single contract in that power pool, after which our obligations there will cease.

We also have a single wholesale contract in New York covering a group of small municipal electric companies through 2013.

Much of that contract is hedged, but some of the later periods are not, leading to modest exposure to our mark-to-market changes.

At this time, in total, we expect that on a net basis, our wholesale obligations through 2013 will cost us less than $50 million in cash to satisfy.

Our earlier guidance was for less than $100 million, but many of those obligations were front-end-loaded and have now expired.

In terms of liquidity, NU parent has benefited in recent quarters from investing proceeds from last year's generation sales and now has nearly $400 million of cash either lent to NU's subsidiaries through our internal system money pool or invested externally.

Over the course of this year, most of that cash will be infused as equity into our regulated companies, particularly CL&P, as we build out our infrastructure.

So far this year, NU has invested $215 million into CL&P and a total of $87 million into our other three utilities.

At June 30, our balance sheet was 52% debt, 46% common equity and 2% preferred equity.

We expect the leverage to increase over the balance of the year as we issue debt at each of the utilities.

Over the longer term, we continue to target a consolidated leverage ratio of about 60%, though we expect each utility's balance sheet to be about 45% equity and 55% debt.

Although leverage will rise, we're starting to see our cash flows improve.

Excluding the nearly $400 million in taxes we paid in March of this year on last year's generation sale, our net cash flows from our operations totaled $361 million in the first half of '07 compared with $213 million in the first half of '06, a nearly 70% increase.

Cash flows will improve further in the second half of '07 as the PSNH and Yankee rate increases take effect.

Lee mentioned earlier that our transmission capital expenditures are now projected to be about $750 million in '07 rather than $700 million.

We also are projecting a modest increase in our distribution capital spending.

As a result, we now project overall CapEx of approximately $1.3 billion this year rather than $1.2 billion.

About $531 million of that sum was spent in the first half.

To fund our capital programs, we expect to issue debt, but not equity, both this year and in 2008.

Together, we expect CL&P, PSNH and Western Mass to issue about $300 million of debt in the third quarter of this year.

Beyond 2008, our utilities will continue to access the debt markets to fund their capital programs.

We will take into consideration our capital program, our common dividend requirements and our increasing levels of internally generated cash to decide if additional equity is required beyond 2008.

And most important to determine in driving this assessment is the size of our capital program in 2009 and beyond, which we continue to plan and develop.

Our second determinate is our internal cash generation.

As our major projects enter service, whether they are the Northern Wood power project, our LNG storage facility or our Bethel-to-Norwalk transmission project, they become 100% reflected in rates and produce cash flow for our Company.

Additionally, we are currently receiving a cash return on 50% of our three other Southwest Connecticut projects as they move towards 2008 and 2009 completion dates.

Finally, I would like to remind you that next month, our shareholders will receive a dividend of $0.20 per share, up 6.7% from last quarter's dividend.

It represents our seventh consecutive year of meaningful dividend growth.

It underscores our confidence in our business accomplishments and strategy and complements what we think is a very attractive earnings per share growth rate trajectory, both in the immediate term and in the longer term as we continue to deploy capital into our infrastructure in order to craft solutions which benefit our customers, the region and our shareholders.

I will now turn the call back to Jeff Kotkin.

And I will return the call to our operator, Christine, so she can describe to you how you can answer questions.

(OPERATOR INSTRUCTIONS).

Ashar Khan.

Dave, based on results and your expectations that the two rate cases are going to have positive impacts in the last half of the year, is it not fair to say that you will be approaching the upper level, upper end of your guidance for the year?

I think it is fair to say that we're having confidence that we are probably moving in a favorable direction there relative to our guidance.

We are a little apprehensive right now at this phase of August with still some summer ahead of us, the storm season ahead of us, to really refine that guidance.

But I think your comment is probably fair.

We are getting our rate cases done.

We are meeting our targets.

We are hitting our completion dates.

And if all works will with a reasonable summer, reasonable fall in terms of storms, we will probably be in that neighborhood.

And then could I go back to the comment you made that if you get the [ask] on your Connecticut rate filing, what would be the incremental impact from 2007?

There, what I have said is that last year, which is now closed and in the books, of course, the distribution segment of CL&P earned $74 million, aside from the additional $74 million that we gained through the tax benefit.

We haven't of course projected specifically what CL&P's distribution segment will earn in 2007.

So you don't really have a good sort of springboard from '07 into the full rate year.

We know from our filing that the rate year math would get to $111.8 million, and probably maybe a modest increase in '07 over '06, but no specific data point in '07 yet.

Steve Fleischman, Catapult.

Ashar answered my question on the range.

So moving on, could you just give us a little more detail on the transmission CapEx increase you have done for this year?

I think I missed the number on that.

And also, a little more color on the potential acceleration of Middletown-to-Norwalk -- is that a matter of a month or two, or is that something that could be, like, six months or a year?

This is Lee Olivier.

In regards to 2007, we had a budget for transmission of about $690 million, and we are going to move the transmission spend up to about $750 million.

About $40 million of that is essentially pulling projects that exist now forward.

In other words, we're making good progress and we want to maintain that.

There is another approximately $20 to $24 million of new projects that were not previously inside of our capital plan.

One is to replace essentially a failed transformer and the other is for new communications equipment associated with NERC reliability standards.

So that is what it looks like for this year in '07.

In regards to Middletown-to-Norwalk, we continue to make very strong progress on that project.

We are ahead of schedule in all phases of the project.

Of course, as you know, that project requires us to tie into the United Illuminating section of the project -- they have about 20% of the project.

It is conceivable that the project could end anywhere from three to six months ahead of schedule.

But right now, it is too early for us to make that final determination.

We will examine our progress this fall prior to EEI, as well, of course, communicate with UI to see where they are on theirs.

We know they are at least on schedule.

And we will give an update later this fall.

Paul Patterson, Glenrock.

On the rate case, what is the possibility of settling it?

When might that -- I mean, you guys did so I think in the Yankee case, right?

That is correct.

Is there a possibility that this one might be settled?

This is Chuck.

As you know and as we talked a little bit about earlier on the call, we have settled all three of the rate cases in the other three companies this year.

We did WMECO at the very end of last year.

But both Public Service New Hampshire and Yankee Gas were settled this year for rates effective July 1.

The timing of the CL&P rate case is such that the settlement discussions, if they were to occur, wouldn't occur until the rate case process has happened.

So clearly, the momentum we have in settling the other three we think is very positive, but it is a little premature to talk about specific settlement on the CL&P rate case.

And then the peaking plant legislation situation -- you guys mentioned that the ROE would be determined differently.

I am wondering whether or not there would be a different capital structure or if there would be any other sort of -- how that might be -- what is your view in terms of the potential investment in peaking plants, how that would be reviewed in the context of the wholesale power market or what benefits you guys might actually be able to bring in terms of either -- I don't know -- why would the building of the peaking plant be perceived to be a better move than obviously having an IPP do it or what have you?

Could you just address that a little bit?

This is David.

Let me take the first element of that.

The statute actually calls for the determination of an ROE outside of or separate from the distribution case.

And you know from my commentary or maybe through flipping through the filing that we have requested an 11% ROE.

And that is really a composite of a number of methodologies -- almost an average, if you will, of looking at various DCF methodologies, [cap end], equity risk premium and the like.

I am sure that is going to form the basis or at least a starting point for having this discussion about what premium, if any, a generating asset would require or would deserve.

Some of that has to do with what we propose for the specific rate recovery mechanisms.

Lee mentioned earlier, or Chuck, that this is going to be kind of rate-base cost of service.

And certainly it will, but as you know from other jurisdictions around the country, you can have rate-base mechanisms that still take on some level of risk, or some like our New Hampshire generation that are more true-up and segmented rate base.

So depending on that regulatory recovery construct, it is going to have an impact on this discussion about the risk premium associated with the generating asset, as well as the underlying capitalization.

And that is something that is now currently under study by our team here and will be embodied in our proposal in January.

And then the idea about the peaking plants themselves in terms of in light of the competitive market or how -- what the advantage that CL&P might have with respect to someone else building the peakers or what have you or relying on the market?

This is Lee Olivier.

I think the advantage that we have is clearly there are things like cost of capital, the cost of service, regulated return, which is generally speaking lower than a competitive generated demand in a marketplace.

Also the fact that we have essentially facilities close to where transmission, close to where the distribution interconnections are, and in terms of building those facilities, we have the -- that particular demand is there.

But I think it is essentially cost of capital and regulated return and service for peaking.

For baseload plants, should we do those at a future date, then clearly generating and selling into the marketplace, [that] cost generates, we think, somewhere between a 3 to 4 million per kilowatt-hour savings.

3 to 4 million per kilowatt is about $100 million a year for a baseload plant.

So there is probably more advantage going forward in a baseload plant, should there be a call for one.

Neil Kalton, A.G.

Edwards.

A bit of a longer-term question in nature related to Canada.

Energy East is also looking at some lines through Maine to tap into Canada.

How should we view their proposal versus what you're thinking about doing?

Would these be competing-type projects?

This is Lee Olivier.

I think there are a lot of options in terms of resolving the overall energy issues.

You have the Regional Greenhouse Gas Initiative, which requires a fairly significant reduction in CO2 emissions from plants.

You have the whole issue of the renewable energy portfolios, which will require a significant number of renewable plants to either be built or transmission capacity to be built to areas in Canada to bring power down.

Then you have just the general capacity issue with a lot of older plants that will shut down.

We see that there is a number of options.

There's options to get power from the maritime provinces of Eastern Canada, certainly to tap into the renewable resources both in Maine and New Hampshire and bring those down into the Boston/Connecticut/Rhode Island area.

And of course there already exists a D.C.

line that runs down from Quebec, from Quebec Hydro, down into Massachusetts, and which NU is a part owner on that.

So there are multiple ways.

And of course, as Chuck mentioned to you, you have the whole issue of the mandate in New Hampshire to work out building transmission into Northern New Hampshire so you can connect new renewable power facilities.

So we see a number of venues in order to solve all of these kinds of major issues that I've talked about -- environmental issues, capacity issues.

So we don't think it is one or the other.

We see multiple lines being built in.

Clearly, there is no one utility that can solve this thing by themselves.

So in many ways, it will be the New England transmission members working together to come up with an overall solution.

Travis Miller, Morningstar.

Got your 2007 updated guidance on the CapEx.

Are you also updating '08 to '11 guidance on CapEx?

Again, this is David.

Absolutely.

And I think Lee touched on a couple of those matters, including some distribution spending.

Our typical cycle internally is to do that work now and then shape up and then frame that work for discussion in November.

And I think that you can expect that.

And it will address a couple of things, including, by the way, some view on CapEx spending around AMI initiatives, generation initiatives here in Connecticut and even in New Hampshire, in advance of having a regulatory determination.

So there could be a little bit of guesswork there, but more definitively, for all of our utilities, the distribution and transmission and taking into account Lee's comments on potentially accelerating Middletown-Norwalk, we will have a new set of curves and graphics for you that will lay out our plan between 2008 and 2012.

So you should expect that in that first week of November.

And just on that $40 million that you had mentioned pulling projects forward, that is something that would come out of '08/'09 potentially?

At this time, we actually have other projects that would fill in for that $40 million for the '08 and '09 timeframe.

So the likelihood is you would not see any substantial reduction of the '08 capital spend.

Jonathan Arnold, Merrill Lynch.

You mentioned that the filings in Connecticut need to be made by the beginning of 2008 regarding peaking generation.

Do you have any sense of how soon you'd end up with a determination on that front?

And in the event that you do get -- your project you proposed gets selected and you move forward, can you remind us, or is there, given that there hasn't been a case for some time, is there a clear sense of how you would earn a return on spending on projects like that?

Is there a quick mechanism that would apply to generation, etc.?

This is Lee Olivier.

The statute essentially provides for the DPUC within approximately 120 days after they receive our proposal.

So they will receive those proposals in January, probably late January.

It gives them 120 days to assess the proposals.

And as well as the DPUC, you have the Connecticut Energy Advisory Board, which will review the proposals and then make a recommendation to the DPUC.

And so you're really talking in the second quarter of 2008 before the likelihood of the DPUC making a proposal.

In terms of structure, I will let Dave talk about what the overall kind of capital structure could look like and also rate of return.

Jonathan, there really is no legislative direction or mandate on this.

It is really up to us to propose one, along with the technology and the site itself.

And again, that is something that we're looking at right now.

I suspect that this is going to or could very much look like traditional rate-making that, at least here in Connecticut with our assets, does not include [sea width] and rate bases, more of a kind of AFUDC during the course of the build.

And this particular asset is not a four- or five-year build, and it is not a $1 billion build.

So I think it is quite manageable within the context of all that we're trying to do here at NU.

But that will be in our filing, laid out in a great deal of specificity in the month of January.

Shalini Mahajan.

Another question on the peaking generation in Connecticut.

What is the magnitude of the peaking assets that we're talking about for '08?

The order of magnitude, was that the question?

Yes.

We haven't defined that specifically, but we think it is in the area of a few hundred megawatts.

And then I am actually not familiar with [vashilar] decoupling.

Could you explain how that works?

This is David.

We have as a follow-up to this, again, the statute, proposed a revenue per customer decoupling mechanism in our filing.

And I think there are probably two issues to discuss.

I should also mention that there has been initiated a separate decoupling mechanism, a generic proceeding that the state utilities and stakeholders will participate in, in parallel to our Connecticut rate case, so that the answer from that generic decoupling can become included and embodied in whatever rate decision they reach in the CL&P docket.

So you should see that initiated shortly.

I think that's where we will have a debate.

I think the debate and the discussion is on two fronts.

I think from a financial policy perspective and a public policy perspective, the issue of how much risk the Company is accepting and how much risk the Company is mitigating through the mechanism I think is something that will ultimately be borne out in a discussion around the appropriate return on equity.

For example, what I mean by that is, at least under our proposal, the mechanism itself, which is a revenue per customer mechanism, that does not protect against weather normalization, we are the Company that is still taking on significant risk in this business.

We are managing a business, we are managing the operations, we are managing the capital deployment of the business, we are managing our own end expenses, and as I said, we're still subjecting ourselves to both weather risk and customer count risk.

What it does in terms of mitigation is it limits the amount of financial exposure we have as our customers perhaps use less electricity in response to conservation and load management, DSM and other public policy initiatives that really help them manage their bill.

So it helps us against erosion on an average use per customer basis.

The mechanism itself is laid out in great detail in our filing.

I suspect that will be then transported -- that debate will be transported into the separate docket and debated there too.

And just one other question -- sensitivity to 100 basis points change in ROE -- would that be the order of $10 million or so?

We're going to have in the rate year something north of $1 billion, $1.040 billion -- so a 1% change on that gets you in that neighborhood.

Well, thank you very much.

We don't have any more calls right now.

So if you have any questions later on in the day, please feel free to give us a call.

Have a great weekend, and thank you for joining us this morning.