康涅狄格電力 (ES) 2007 Q4 法說會逐字稿

The conference is being recorded.

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

For today's call, is Mr.

Jeffrey Kotkin, Vice President of Investor Relations.

Mr.

Kotkin, you may begin.

Thank you.

Good afternoon, and thank you for joining us, I'm Jeff Kotkin, Vice President for Investor Relations.

Speaking us today will be Chuck Shivery, NU's Chairman, President, and Chief Executive Officer; David McHale, NU Senior Vice President and Chief Financial Officer; and Leon Olivier, NU Executive Vice President who oversees our regulated businesses; also in the room today are Jim Muntz, Senior Vice President and head of our Transmission business; and Shirley Payne, our Vice President and Controller.

Before we begin, I would like to remind you that some of the statements made during this conference call may be forward looking as defined within the meanings of the Safe Harbor provision of the U.S.

Private Securities Litigation Reform Act of 1995.

These forward-looking statements are subject to risks and uncertainty which may cause the actual results to differ materially from forecasts and projections.

Some of these factors are set forth in the press release issued yesterday evening, announcing our earnings for the third quarter of 2007.

Additional information about the various factors that may cause actual results to differ can be found in our quarterly report on Form 10-Q for the third quarter of 2007, and also in our annual report on Form 10-K for the year ended December 31, 2006.

Now, I will turn over the call to Chuck.

Thank you, Jeff, and thank all of you for joining us this afternoon.

2007 was a very strong year for us and it was the first full year where we were operating under our fully regulated business model.

Much more than a transition year of 2006, 2007 was indicative of what this Company can accomplish.

From an operational perspective we continue to make significant progress on a number of initiatives.

Our Southwest Connecticut transmission projects continued to move forward with about 70% of the aggregate work for these projects complete, compared with 40% at the end of 2006.

We continue to move forward on the next generation of major transmission projects, where we expect to be completed between 2011 and 2013.

And New Hampshire generation, including our new renewable energy (inaudible) unit, operating very well, providing measurable cost and environmental benefits to New Hampshire.

On the distribution side, we settled distribution rate cases at Public Service Company of New Hampshire and Yankee Gas and experienced significant financial improvement at those subsidiaries.

Earlier this year we concluded the CL&P rate case.

While we appreciate that the Connecticut Commission was faced with a difficult decision, in light of increasing cost pressures on our customers, we were disappointed with the disallowance of several legitimate operating costs and with the 9.4% return on equity.

In 2007, we were able to effectively deploy capital on all parts of our business and have seen an improvement in distribution reliability as a result of those efforts.

From the financial standpoint, we also made considerable progress.

By earning $1.59 per share, we exceeded the high end of our initial earnings range of $1.30 to $1.55 per share, and earned near the top of our revised range of $1.45 to $1.60 per share.

Given our strong earnings for 2007, we appropriately changed our five-year growth rate projections to reflect the higher 2007 earnings level and we continue to remain optimistic with respect to the Company's future opportunities.

Dave will discuss this item in more detail in a moment.

2007 was also a year during which we made progress on many of the longer term energy issues facing our customers in our region.

In Connecticut, at the beginning of the month, we and United Illuminating jointly filed the state's first integrated resource plan in about a decade.

This plan looks out over the medium and longer term to estimate the state's future power needs and how best to meet them.

This plan is now before the Connecticut Energy Advisory Board, which will review, modify, and forward that plan to our utility regulators this spring.

The foremost important recommendations in that filing are related to developing strategies to meet the state's increasing renewable energy requirements, reduce dependence on natural gas generation, increase the demand side management investments and increase the distribution utilities, flexibility, and arranging for long-term supply options.

In just over a week, we and others will file applications to build peaking generation in Connecticut.

Like the integrated resource plan, this application is required under Connecticut's 2007 Energy Legislation and we applaud the state for looking at its long-term supply power changes and considering innovative solutions.

In New Hampshire, the legislature last year requested an analysis of the transmission upgrades that would be necessary to support increased renewable energy development in northern New Hampshire.

Regulators completed that analysis in December and forwarded a report to legislators noting that to develop 400 to 500 additional megawatts of renewable generation could require investing up to $200 million in additional transmission infrastructure in northern New Hampshire.

We are encouraged that New Hampshire officials are showing keen interest in developing this indigenous energy source and we are working with them towards making this a reality.

Although we have not discussed the topic of our litigation with ConEd for a number of months, I want to provide an update of recent events.

In January, the judge ordered the parties to be ready for trial as early as March 25.

As you will recall, ConEd claims that NU breached the 1999 merger agreement.

ConEd seeks to recover what it claims would have been its share of the merger synergies, totaling some $314 million, plus its merger-related costs and expenses of about $32 million.

These figures do not include prejudgment interests.

NU believes there is no merit whatsoever to this claim.

NU claims that ConEd breached the merger agreement by repudiating the agreement and refusing to close in March of 2001.

You may also remember that NU originally sought to recover the merger premium on behalf of its shareholders but the appellate court ruled in October of 2005 that the merger agreement did not provide NU shareholders with the right to sue ConEd for breaching the agreement.

NU seeks to recover its merger-related costs and expenses of about $27 million on this claim.

That number is also before including prejudgment interest.

ConEd contends that it was excused from closing because NU suffered various material adverse changes, all of which NU disputes and believes are entirely without merit.

2007 is behind us, but the accomplishments are important because they are indicative of what we can accomplish both in 2008 and beyond.

Citing and managing large transmission projects is not an easy skill to develop, but has become a core competency for us.

Converting a 40-year-old coal unit to a 50-megawatt low emission wood-fired generating plant and operating it successfully shows that we can creatively address the region's environmental concerns.

On that note, we continue to see the development of renewable generation, not just in northern -- in New England, but also in Canada, as a logical and important option for meeting New England's future energy needs.

We have positioned NU as the catalyst for developing a consensus among the region's stakeholders as to the best alternatives to meet these critical energy requirements.

To continue this momentum, we have appointed a team inside NU, under Jim Robb, our new Senior Vice President for Enterprising Planning and Development to work on this initiative and to provide an objective, informed discussion of the energy requirements of the future.

In fact, in December we presented a transmission concept at ISO New England's DC Day, that would link hydro Quebec's considerable generation resources to the load centers in New England.

Over the last several months we have initiated discussions with many of the region's transmission owners, regulatory and legislative leaders, the ISO and with the Canadian companies interested in this opportunity.

We expect to continue these discussions and would hope to have a better defined set of solutions by the second half of this year.

All in all, I'm very pleased with 2007 results and optimistic about our prospects.

Lee and David will now provide some additional details from both an operational and a financial perspective.

Thank you, Chuck.

I wanted to start by adding to Chuck's assessment of 2007.

From an operational and capital investment standpoint, 2007 was a very successful year.

Our transmission distribution reliability was generally above our targets, creating benefits for our customers.

We invested a record $1.28 billion in our infrastructure, $762 million of which went into our transmission system.

Yankee Gas' LNG facility entered service on schedule in mid-2007 and on its $108 million budget.

And there still is time to provide benefits for customers in the form of lower commodity and pipeline costs this winter.

On January 3, the Company saw demand for natural gas reach over 332 million Btus.

This represents the highest record sendout day ever for Yankee Gas.

With peak prices at $22 more million Btus, which is more than double the cost of inventory in our LNG tank.

Public service New Hampshire's Northern Wood 50-watt renewable energy plant recorded a 77% capacity factor in the first year of operation burning 481,000 tons of wood chips in one of the cleanest burning biomass plants in the country.

Dispatching at a negative price when you consider the renewable energy and the tax production credits.

Our primarily coal-fired base load generation recorded an aggregate capacity factor of about 85% and this helped PS&H keep its average rates well below those of other New England utilities.

As we look forward we see more opportunities to increase our regulated generation earnings with projects that also will have significant customer benefits.

We continue to work with the Washington Group on design and permitting applications for a web scrubber for our two coal-fired units on the Merrimac generation facility in New Hampshire.

We expect to provide you with more specifics about our proposal later this year, including an update on our $250 million cost estimate for this project.

The project must be completed by 2013.

As many of you know, we are also preparing an application to build rate-based peaking generation on two sites in Connecticut.

On February 1, CL&P announced it would seek to build four 50 megawatt units, or up to 200 megawatts on land CL&P earns adjacent to our Card Street substation in Lebanon.

We also will seek to build two new (inaudible) 65 megawatts near the LNG facility in Waterbury, Connecticut.

These applications are required by Connecticut statute.

Our proposal and competing proposals will be filed with the DPUC around March 3, and a final commission decision is due by the end of June.

The DPUC has indicated it may select up to 500 megawatts.

If our projects are approved, the Waterbury facility could be in service in early 2010, and the Lebanon units in mid-2010.

As you may recall, these potential capital projects would be incremental to the capital forecast we provided you at the EEI conference.

We invested just over $500 million in our distribution and generation systems in 2007 and expect that level of investment to rise to nearly $600 million in 2008.

Essentially all of the nearly $100 million increase will be at Connecticut Light & Power and Public Service of New Hampshire where in recent rate cases, regulators have endorsed our investment in infrastructure to improve reliability.

CL&P reliability improved in 2007 over 2006.

That improvement was driven partially by less severe weather but also by some upgrades we continue to make on the CL&P underground and overhead systems.

The clear message from the recent CL&P rate case is that the DPUC wants us to continue to address obsolescence on our distribution system and it approved a $290 million distribution capital program in 2008, followed by a $285 million distribution capital investment program in 2009.

In addition, to the $290 million on distribution infrastructure, we expect CL&P to invest up to about $10 million in 2008 on a DPUC endorsed advanced metering infrastructure pilot program for about 10,000 customers that will test both the AMI equipment and technology as well as the response by subset of customers to time of use rates.

We will file a plan with the DPUC in mid-March to implement the pilot and report back to the commission no later than December of 2009 on the results.

Expenses related to the pilot including a return on our investment will be recoverable through a tracking tariff on our allowed 9.4% return.

At PS&H, the increased level of investment is primarily due to the implementing of the reliability enhancement program that resulted from our rate case settlement last spring.

Turning to our transmission business, 2007 was a very strong year in terms of operation and building out of our transmission system.

Reliability was good, and we received a very strong NERC audit of our transmission operations.

We made significant progress on our other three remaining southwest Connecticut projects.

Two of which we expect to complete later this year.

Currently our $223 million, 115kv Glenbrook cables project, between Norwalk and Stanford, Connecticut is about 73% complete and is expected to enter service by the end of this year.

On Long Island -- on our Long Island cables replacement project, a specially outfitted ship is currently laying the new solid core cable manufactured in Norway between Norwalk Connecticut, and Northport, Long Island.

This replacement cable, the key element of our $72 million investment should be in service this summer.

Overall, the project is about 71% complete.

Our 1.050 billion share of the 69-mile, 345kv Middletown to Norwalk transmission project is about 69% complete.

Although the initial projected completion date was December 2009, we are currently several months ahead of the schedule and now expect to be completed in the mid-2009 time frame.

Because of 50% of the carrying cost on the project are currently being capitalized rather than earning a cash return, every month we can accelerate its completion will reduce its ultimate costs by about $3 million and improve our near term cash flow.

A mid-2009 completion would also allow the cable to be available for the summer of 2009, enhancing the region's reliability at peak demand and providing additional savings to customers.

As we move forward to a completion of our southwest Connecticut projects, we are working with National Grid and ISO New England to design another major set of projects to better reinforce the grid in Western, Massachusetts and the connections between Massachusetts, Connecticut, and Rhode Island.

In December, we received a very favorable vote from ISO New England, the ISO New England reliability committee on our technical analysis of the 115kv transmission system in and around Springfield, Massachusetts.

We filed an application with the Massachusetts Imagings Facilities Citing Board on the Springfield underground cables project in December and expect to complete the citing process in early 2009 and construct the new facilities between 2009 and 2011.

Secondly, we are working with ISO New England on three new overhead 345kv lines in Connecticut and Massachusetts to better connect the major East/West transmission interfaces in southern New England.

We expect to undertake this work in coordination with significant enhancements National Grid is planning in Rhode Island and central Massachusetts.

ISO is currently conducting technical reviews of these projects which we expect to conclude in the mid- to late 2008 time frame.

As we have said previously, once we complete those reviews, we expect to file citing applications with Massachusetts and Connecticut regulators.

While the southern process for the Springfield cables and NEEWS are separate, certain aspects of the projects are related, particularly the underground cables project and the greater Springfield reliability project.

The latter, a new 345kv line we expect to build from Ludlow, Massachusetts, northeast of Springfield to Bloomfield, Connecticut.

Modifications to the Springfield 115kv underground projects can affect the greater Springfield 345kv overhead project and vice versa.

In addition to the technical review we continue to work with ISO to ensure that the design of those projects balance the needs for reliability, operational flexibility, and cost.

Once this is complete, we will provide cost updates on all of these projects.

At this time, we expect those updates to take place around mid-year 2008.

As a result, for now, we will retain our cost estimate for the Springfield cables of $350 million and our estimate for the NEEWS project at about $1.050 billion; however, as we continue to review the designs of the NEEWS projects with ISO over the coming months, I expect these figures to change.

We continue to work with ISO in many other areas to improve grid reliability and capacity, reduce congestion, meet higher FERC transmission standards, and address public policy initiatives.

As Chuck mentioned earlier, we are working with New Hampshire regulators and lawmakers on new transmission to connect renewable facilities in northern New Hampshire.

Those expenditures are not reflected in our $3 billion five-year transmission capital budget, nor are any new lines connecting the U.S.

with Canada.

Yet, we believe both of these initiatives have significant potential to help New England connect to the renewable energy sources, the region will require in the future and under current state statutes.

Now, I would like to turn it over to Dave McHale.

Thank you, Lee.

As Chuck noted in 2007, we earned $246.5 million, or $1.59 per share.

Those results are above our initially guidance of $1.30 to $1.55 per share and just above -- or about at the very top of our revised range of $1.45 to $1.60 per share we announced last November at the EEI financial conference.

Comparing these results to 2006, excluding nonrecurring items, net income for our regulated businesses including NU parent and other affiliates increased from $178.2 million, or $1.16 per share in 2006, to $234.8 million or $1.51 per share in 2007, representing an EPS increase of nearly 32%.

In terms of business performance, every segment was within or above our initial guidance.

Our distribution and generation segment earned $146.2 million, or $0.94 per share, above our initial guidance of $0.80 to $0.90 per share and near the top end of our revised guidance of $0.85 to $0.90 per share.

Those results were due to a combination of improved sales, well managed cost, rate relief, and frankly, some good fortune in having have a relatively benign year for severe weather.

Our parent segment earned $6.1 million or $0.04 per share near the upper end of our initial range of $0.00 to $0.05 per share.

There we benefited from the interest we earned on the cash we received from our competitive generation sale in 2007.

At the competitive businesses we earned $11.7 million, or $0.08 per share.

We had initially projected break even in the competitive businesses and later earnings of $0.05 per share.

The improved results were due to sound management of our existing wholesale position, and closing out some contracts in our former services businesses at favorable terms.

In transmission, earnings were up $22.7 million or 38% over those of 2006.

We earned $0.53 per share within our projected range of $0.50 to $0.60 per share.

Let me drill down a bit more on 2007 results and then I would like to spend some time commenting on our financial prospects for 2008 and beyond, and touch on the financial and capital requirements necessary to achieve our long-term growth plans.

First, at the distribution companies, net income at PS&H, Western Mass and Yankee Gas were much better in 2007 than they were in 2006.

A primary driver of that improvement was higher distribution revenues.

PS&H's distribution and generation segment earned $12 million in the fourth quarter of '07, and $43.7 million for the full year, compared with $5.8 million in the fourth quarter of '06 and $27 million for the full year.

Primary reasons for the earnings increase were the impact of distribution rate settlement that was effective July 1, 2007, a lower effective tax rate, a 1.2% increase in sales and the full year operation of the Northern Wood Power Project.

PS&H finished up the year with a combined regulatory, distribution, and generation ROE of 9.5% in 2007, compared with about 6.4% in 2006.

PS&H's authorized distribution return is 9.67%.

Also I should note that effective January 1, of 2008, PS&H's authorized generation ROE, which is incorporated into our tracking tariff rose 19 basis points from 9.62%, to 9.81%.

Western Mass Electric's distribution segment -- excuse me, distribution earned $4.9 million in the fourth quarter of 2007 and $18 million for the full year of 2007, compared with $2.4 million in the fourth quarter of '06 and $11 million for the full year '06.

The increase resulted primarily from higher distribution revenues.

Western Mass' distribution and regulatory ROE was 9.7% in 2007, compared to about 9.6% in 2006.

Yankee Gas earned $12.1 million in the fourth quarter of '07 and $22.6 million for the full year 2007, compared with $5.5 million in the fourth quarter of '06 and $11.9 million for the full year '06.

Yankee's significant improvement was due primarily to higher distribution revenues joined by higher sales and implementation of a rate settlement that incorporated into rate base Yankee's $108 million, LNG facility effective July 1, 2007.

Primarily due to colder weather, Yankee's firm sales were up 15.7% in the fourth quarter of '07 and 10.3% for the full year '07, compared with the same period for 2006.

Yankee's regulatory ROE, which did benefit from six months worth of rate relief during the year was 8.7% in '07, compared with 5.9% in 2006.

Yankee's allowed ROE is 10.1%.

Turning to CL&P, the year-over-year compare is somewhat more complicated.

In 2006, CL&P's distribution segment benefited from the $74 million reduction in tax expense related to an IRS private letter ruling and a $7.7 million gain related to the competitive generation sale.

Boat of these gains were not factored into CL&Ps ROE so even though CL&Ps distribution business earned $147.6 million in 2006, its regulatory ROE was only about 7.5%.

Absent those gains, CL&P's distribution segment earned $65.9 million in 2006.

In '07, CL&P's distribution segment earned $61.4 million, equating to a regulatory ROE of 7.9%.

CL&P's earnings were also affected by higher operating and interest expenses which were only partially offset by a $7 million distribution rate increase effective July 1, '07 and a 1.7% increase in retail sales.

Transmission earnings rose from $59.8 million in '06 to $82.5 million in 2007, or [38%].

Fourth quarter transmission earnings rose from $16.2 million in '06 to $25.5 million in 2007.

About $20 million of the nearly $23 million increase in consolidated full year transmission earnings between '06 and 2007 occurred at CL&P which is investing heavily in southwest Connecticut's transmission infrastructure.

Let me now turn to prospects for 2008.

Overall, our guidance for the year is $1.65 to $1.90.

Adjusted somewhat from our initial guidance of $1.65 to $1.95, first provided to you last November at the EEI conference.

The change in guidance reflects an increase in transmission segment guidance from $0.70 to $0.80 per share to now $0.75 to $0.85 per share.

It also reflects a decrease in distribution and generation segment guidance from $1.10 to $1.25 to now $1.05 to $1.15.

We continue to view the competitive segment as a breakeven business and continue to view NU parent and other affiliates in the negative $0.15 and negative $0.10 range.

Midpoint to midpoint we have reduced guidance by $0.025, largely reflecting more modest prospects at CL&P given the recent rate case decision.

Chuck touched on this issue somewhat but let me give you a more detailed financial assessment of the rate outcome.

We originally (inaudible) the DPC in our July 2007 filing for an increase in revenue of $189 million in 2008 and $22 million in 2009 based in part on an 11% ROE, 49.5% equity rate making capital structure and capital expenditures of about $294 million in '08 and $288 million in 2009.

In the final decision, dated January 28, 2008, the commission authorized a revenue increase of $77.8 million, for 2008, $20.1 million in 2009, and ROE of 9.4% and a 48.99% equity ratio, and largely improved our capital expenditure plan.

Given that certain necessary operating costs were not recognized in rates by commissions, we estimate that in the first full year of new rates, CL&P will earn 8 to 8.5% regulatory ROE range.

And because the rate increase became effective February 1, of '08,as opposed to January 1, CL&P will achieve a regulatory ROE closer to 8% in the calendar year 2008.

We are pleased that the commission largely supported our capital structure, capital programs and electric sales forecasts.

We are also pleased that the rate relief will provide CL&P with improved year-over-year net income results which in turn will contribute to NU's overall earnings growth, however, 8 to 8.5% ROE results are below our expectations and drove the reduction in distribution and generation segment guidance for the year.

For the balance of our distribution companies, two of the rate decisions that helped 2007 results were not effective until mid-year 2007.

As a result, there will be positive carryover impact for PS&H and Yankee Gas that should benefit the results in 2008.

For the year, we expect Yankee Gas to achieve a regulatory ROE towards the mid to higher end range of our 9 to 10% ROE target range and for PS&H to achieve regulatory ROE towards the low end of that range, at about 9%.

Overall, we see improved net income and EPS results for the distribution companies compared to 2007, achieving midpoint of our guidance will result in a 17% improvement in EPS.

However, these companies will continue to need additional focus to improve longer term financial returns, particularly as we continue to invest in our infrastructure to improve service, reliability, and an aging infrastructure.

For transmission, we expect 2008 earnings growth to be driven by investments in southwest Connecticut, as we move to complete our last three major projects there.

Growth in the transmission segment continues to be driven by our investment programs particularly in southwest Connecticut.

Transmission rate-base grew from $1.05 billion at the end of 2006, to $1.49 billion at the end of 2007.

Average transmission rate base grew from $800 million in '06 to about $1.2 billion in '07.

We project a year-end rate base of nearly $2.2 billion in 2008.

For our southwest Connecticut project, it's also important to remember that we earn a cash return on 50% of our investment as we construct the projects.

Equity on the other 50% earns a noncash return at the 12.44% rate authorized by the FERC.

In that return, it's capitalized into the cost of the project.

Once project has the service, 100% of the investment earns a cash return.

Since we are financing our capital program with 45% equity, and $700 million capital program in transmission in 2008, roughly means that we will be investing more than $300 million of NU equity into our segment this year.

Earnings a return on that equity will drive our transmission earnings from the $0.53 a share we earned in 2007, to our upwardly revised $0.75 to $0.85 per share range in 2008.

Results of NU parent and other subsidiaries are primarily a function of investing in borrowing activities of the parent.

In 2007, we had hundreds of millions of dollars of cash from a 2006 generation sale that we invested in money market funds for much of the year.

As of today, virtually all of that cash has been invested as equity in our utility subsidiary to fund their capital expenditure requirement.

Also the parent company has a $263 million note due 2012 on which it is paying 7.25% interest.

Those interest payments and the absence of cash to invest are the primary reason we are forecasting the parent will move to a $0.10 to $0.15 per share loss this year.

Lastly, our competitive businesses continue to wind down.

Our last PJM wholesale contract expires in just over three months, leaving us with one wholesale contract under which we supply numerous municipal facilities in New York State with power through 2013.

We also own an electrical contracting business that operates throughout the region.

It earned about $3 million last year.

This year collectively, we expect these businesses to break even, the primary reason for our lower expectations for this segment is that 2007 results benefited from divestiture activities associated with our remaining businesses and the management of our remaining wholesale contracts.

We do not expect similar results in '08 since the businesses continue to wind down as we serve our contract and close out divestiture activities.

I will now turn to our cash flows and 2008 financing needs.

Excluding the taxes we paid in 2007, on the 2006 generation sale, and excluding repayment of rate reduction bonds our cash flows were about $450 million in 2007.

We expect that number to increase to about [$500] million this year, primarily as a result of approved rate increases and to between $800 million and $850 million by 2012.

As we noted at EEI, we project our capital expenditures to total about $1.3 billion in 2008 before declining in 2009 as our southwest Connecticut projects are completed.

We expect to fund our 2008 capital program primarily through internally generated cash and the issuance of short-term and long-term debt.

As a result we expect the debt component of our capital structure to increase over the course of the year from about 56% level at the end of the 2007, to nearly 60% by the end of 2008, right in line with our expectations.

We will maintain the capital structure of each utility at approximately 55% debt, but we utilize some leverage at the parent until we issue additional equity which we continue to foresee in 2009.

As I mentioned at EEI, we currently expect to issue about $500 million of equity over the next five years, about half of that in 2009.

Issuance will be dictated to a great extent by the ultimate size of our capital program, including the final cost and timing of the news project.

With the exception of Western Mass Electric, 2008 debt issuance will occur at each of our companies this year, including NU parent which has a $150 million debt maturity on June 1, and up to $300 million at CL&P which has the bulk of our capital program.

All told, we expect to issue about $700 million of long-term debt in 2008, including the refinancing of the maturing NU parent note.

And we have already executed forward starting slots to hedge out exposure to changes in interest rates.

We are also contemplating remarketing $89.25 million of PSNH auction rate, pollution control revenue bonds.

These securities are insured by MBIA.

Given recent developments in this market, PS&H may exercise its right to term out the security through 2013.

Although this remarketing would increase PS&H's long-term interest expense, it still preserves very attractive long-term tax exempt financing, the cost of this transition is already been factored into our 2008 guidance.

Additionally, CL&P has a $62 million auction rate dilution control revenue bond insured by AMBAC that may be remarketed later this year as well.

When we file our 10-K next week, you will see very similar five-year forecasts for rate-based growth and capital expenditures that we showed you at EEI.

They support our above industry average annual EPS growth rate through 2012, however, because our EPS in 2007 was so strong, the base from which we calculate our five-year growth rate is higher, meaning although our five-year EPS expectations are essentially unchanged, the growth rate off of 2007 is lower.

To expand on this point further, I will remind you that at the November EEI conference, we announced the long-term growth rate range of 10 to 14% and increased our 2007 guidance to $1.45 to $1.60.

At that time, we computed our growth rate off of 2007 base levels of somewhat less than the midpoint of that range.

Now that the year has closed, we recalculate the EPS growth rate of 8 to 11% based off of 2007 actual results of $1.59.

I would also add to a lesser Cree that the 11 to 8% was reduced by ROE expectations for CL&P as a results of $1.59.

I would also add to a lesser degree that the 11 to 8% growth rate was tempered modestly by reduced long-term ROE expectations for CL&P as a result of the recent rate decision.

As we discussed in the past, our growth is based in part on our distribution Company's earning in the 9 to 10% regulatory ROE range, given the outcome of this case we think it's more realistic to expect CL&P to achieve returns toward the lower end of that range.

Bigger picture, since we continue to force the capital expenditures of $6 billion over the 2008 through 2012 time frame, and rate-based growth from nearly $5.3 billion at the end of '07, to about $9.3 billion at the end of 2012, our earnings power remains intact, despite the lower compounded annual growth rate.

As a result, we are comfortable with the Street's consensus forecast for 2011 and 2012 time frame, assuming we achieve our capital expenditures and rate-base targets and receive reasonable regulatory treatment.

And just as a remainder, as we did in the fall, our $6 billion capital program does not include additional investments that may stem from updates for the NEEWS transmission project, investments in potential CL&P generation, wide scale AMI deployment, further transmission in New Hampshire to access renewables, additional PS&H renewable generation such as the Northern Wood power project, renewable generation in Connecticut and Massachusetts, value derived from increasing conservation of load management initiatives and potential Canadian solutions to address the longer term needs of our customers.

And finally as a reminder, we continue to focus on creating long-term shareholder value through an attractive total a shareholder return profile.

In part, that means a commitment to increasing the NU common stock dividend.

We were pleased to increase the annual dividend in 2007 by nearly 7%, and we continue to believe that dividend increases are an important part of the overall value proposition of this Company going forward, in addition to the type of earnings growth produced by our strategies.

Thank you for your time and attention.

Now, Jeff, I will turn the call back to you.

And I will turn back the call just to remind you of how to enter questions.

Thank you.

(OPERATOR INSTRUCTIONS) Thank you.

Our first question today is from Anthony Crowdell from Jefferies.

Anthony?

Hi, Jeff.

Two questions.

I guess the first question is maybe a year ago, a little over a year ago, we were looking at, I guess, volumes declining in your service territory and you guys attributed it to conservation because of the high commodity cost.

That doesn't seem to be the case anymore.

I wonder if you have any comment on that.

The second question is -- initially I guess we were expecting to see a pickup in the construction numbers for the NEEWS project and I think that the prepared remarks it got pushed back.

I wonder if you have any color on that?

Anthony, this is David.

Let me just take the first piece of that question, at least factually what we know in 2007 is on the surface, CL&P sales actually did since increase 1.7%.

Some of that was weather driven.

About 0.4 was the actual weather normalized growth.

The equivalent numbers for New Hampshire, they actually had about 0.6% growth weather normalized.

Western Mass was actually off fractionally off by about 0.4%.

So we are actually seeing, at least in Connecticut and New Hampshire, some modest sales growth, although not inconsistent with our expectations.

I think in a range of zero to 0.5%, is certainly less than historic trends, certainly, but my sense is that customers are still responding to higher prices there.

And we still may not know directionally where these growth rates are going to settle.

I will give you some comfort that for the CL&P sales forecast that was in the rate case that was based on about 0.3% growth and that's the type of number that's embedded in our numbers going forward.

Anthony, this is Leo Olivier.

One of the things I wanted to say is ISO New England, and we continue to reiterate the fact that the overall NEEWS project including the 115kv cables will be needed as we go forward, needed to solve reliability issues, needed to help in terms of market iniquities in terms of location, marginal pricing of power between Connecticut and the region and also to get renewable power down.

As I said we have completed the technical assessment of the 115kv portion.

We have the favorable vote out of the reliability committee of ISO.

I think the key thing here is quite frankly, the greater Springfield portion of this project, both the 345kv overhead, the 115kv underground and overhead, are probably the most complex projects we have ever built and ISOs has had to deal with, even more complex than the southwest Connecticut projects.

One of the things that ISO needs to do is make sure that these projects meet all the existing and -- and new reliability requirements as set forth by the North American reliability corporation.

And they need to understand that the operational aspects of the greater Springfield projects, the 115kv projects and how they interrelate with the other projects that we are building.

They are looking at the greater Springfield family of projects and the 115kv cables to make sure that they have the operation flexibility and we optimize the cost of those projects.

We have submitted design that is clearly technically acceptable.

They are looking at that design to make sure -- or to see if there's any other way that that can be implemented in a way that meets that criteria and we can optimize the -- the cost of the 115kv underground cables.

The overall project, as we originally had projected it, is essentially $1.4 million between the underground cables and 345kv's, those overall numbers stand up.

We have not escalated the 345kv part of the project to the most recent cost estimates in terms of labor, and/or construction materials and we just thought rather than continue to send out different cost estimates we would wait to see what the ISO's analysis would say in terms of any design changes on the 115kv and then reforecast the cost of all of these projects at one time.

We estimate that ISO will probably have their analysis done by the June time frame, at which time we will reforecast all of the projects.

I do believe that in -- in their entirety, that the project, overall project price will increase from a $1.4 billion.

Thank you, Anthony.

Our next question is from Jonathan Arnold from Merrill Lynch.

Jonathan?

Good afternoon, everyone.

Good afternoon.

Hi.

Just a quick question on your comments around the expectation of earning an 8, 8.5% ROE at CL&P in the first full year, and obviously I think this rate deal is effectively a two-year deal because you have an increase in the second year.

But should we be thinking as we look out into the second year that you will have an opportunity to work on costs and potentially push that return up or is it more likely to be trending down?

And as a follow-up, at what point would you anticipate that you either would or could be filing a new case in Connecticut?

Well, I will tell you an easy answer is that we will not be filing a new case in Connecticut this year certainly.

Jonathan, you should expect as always that we continue to work on the cost structure, not only the cost structure of our companies, but additional opportunities for these companies as well.

I think the types of costs that were not covered to some degree can be mitigated and those are the types of things that we are looking at pretty seriously.

There are other types of costs and you might describe them as maybe adding the philosophical differences with the commission about who pays for costs, simply cannot be mitigated to any large degree.

Those are things like as a classic example, might be where the commission did not cover all of the Company's director and officer insurance.

We're not going to cut premiums and policies.

I mean, we will continue to look at that and study that and look at overall limits and the like, and be as diligent as we can negotiating terms, particularly when we have our opportunities to renew our premiums but some of those costs are going to remain in the structure.

But certainly through the course of this year, we will take an opportunity to make sure that we are doing what we can to balance, providing a service to our customers and kind of maximizing our returns and we are hopeful that we can improve returns year-over-year but I would say at some point later in 2009, it's possible that we would file for new rates in 2010, but it's premature to say that now, Jonathan, but it certainly won't be in the very near term.

Thank you very much.

Thank you, Jonathan.

Our next call is from Michael Lapides from Goldman Sachs.

Michael.

Congratulations on a good quarter and a good year.

Question, can you give a real high level, I just want to make sure that I have got this down in my notes correctly.

I'm trying to think about the roster of projects that you are looking at, but that is not in your official CapEx guidance.

So the CL&P Teger's obviously, the transmission up into Canada which may be a few years off, but, kind of got that on the back of the envelope.

What else am I leaving off that are major items, $100 million plus items.

Michael, this is David.

Let me rattle through them.

I probably went through them quickly.

If you recall from the prior disclosures, typically at EEI we had a big slide up on the billboard that said here's what is in our forecast, here's what's not in our forecast.

Those are initiatives that we continue to focus on and we think we can continue to advance, but not necessarily with 100% probability.

So let me list those to you and you mentioned a couple of them.

Certainly on the Connecticut peaking generation, we talked about the tact that we will file a proposal for 260 plus megawatts.

We haven't put a number on what that will cost.

You will see that shortly, but that's going to go live very soon.

Lee touched on where we are with news, and we will update that later in the year.

And you can assign a probability or aside to, that but that's one too that's right out in front of us.

Other things that we have talked about with you include not only near term AMI but really wide scale AMI deployment through all of you states and there you can put a probability on it.

Connecticut, of course, is the most aggressive now as we work through with the pilot, but I think it will be some years before we get to the point where we are going to be swapping out 1 million meters, nevertheless, it holds the potential to be an investment for this Corporation.

We touched on the future opportunity for New Hampshire to build a transmission, to reach into renewable corridors and maybe even for PS&H to build renewables, such as wood, biomass and the like.

Bulk transmission and then additional PS&H generation which are bigger ticket items are not in our forecast as well.

I think you will see us increasingly pursue an ability to participate in the renewable market in generation in Connecticut and in Massachusetts.

Too early to really develop numbers around that, but that's something that I think is a possibility for us.

I think also to the extent that regulators and policy makers are focusing on DSM and conservation and creating business opportunities there too, I think that is already a core competency of ours.

It's not necessarily a business line, but there may be opportunities for us there.

And you mentioned the longer term Canadian solutions.

I think when you stack that up, and put some numbers on it, it's a very big number, all with varying degrees of probability.

That's probably the list that we would keep you focused on.

What is the process that is going to play out in terms of the New Hampshire transmission and getting approval, trying to think about just process and time line and tracking of the New Hampshire transmission, kind of build out?

Michael, this is Lee Olivier.

Right now the New Hampshire Public Utility Commission has issued a report on the need for transmission, and Chuck indicated some numbers in terms of 400 million to $500 million of additional transfer capacity and costs perhaps up to 100 million to $200 million of transmission investment.

Right now -- this issue is over in the legislature.

They are looking at essentially a mechanism or a methodology of who is going to pay for this.

As you know, traditionally when you interconnect generators, the generators pay for the interconnection and with all renewables anywhere in the country, if you use that approach, then the renewables never get built.

There needs to be a mechanism such that the renewable generators contribute to a tariff in support of transmission and then the balance would have to be picked up by either the local network service or potentially even through part of the region.

So they are looking at the various existing statutes and they will have to make some kind of statutory change.

We expect that to happen this year.

We will be advocating for that in the legislature.

Got it, thank you guys.

Much appreciated.

Thanks, Michael.

Our next question is from Oliver King from Zimmer Lucas.

Oliver?

I just wanted to clarify on your long-term growth rate, which you guys lowered.

You guys had the 10 to 14% five-year growth rate since the beginning of '07, when your '07 guidance was $1.42?

Now that you've lowered it to 8 to 11%, but your '07 results were actually around $1.57, would it be fair to say that your five year earnings outlook is actually unchanged despite the lower growth rate or would you actually expect lower long-term growth rate going forward?

To pick up on your mathematical construct there.

I think at this point, it's fair to say that the long-term growth prospects are driven by the amount of capital we put to work, the degree to which that capital gets into rate basin, the degree to which we can earn on it.

I mean, that basic process and the amount of capital has not changed.

Our growth process remains the same.

I did suggest that longer term we did a little refining of what we think a steady state ROE is for our CL&P electric jurisdiction.

And may have dialed that back a little bit.

Everything else remains in the 9 to 10, but fundamentally the story is the same and you will see that when you print the K.

You will have all the CapEx and rate-based information in front of you.

With the exception of a little bit of movement around CL&P ROEs, this story remains the same, our earnings power is intact.

Okay.

Thank you.

Thank you, Oliver.

The next question is from Ross Fowler from Lehman.

Ross?

Good afternoon, guys.

How are you?

Good afternoon.

Just a couple of questions around the New Hampshire transmission.

I know the study they put said they were looking at a year to year and a half of study citing an ISO review and then three to five years post that to get that done.

I was wondering if that's still in play and that puts us into a 2012 time frame?

And then kind of another question around the ISO New England presentation, there is the 135-mile D.C.

line from Quebec to New Hampshire and then there's also the 85-mile undersea line from New England to New Hampshire to Boston.

You guys haven't really talked about that at all.

I was wondering if that's still in play?

And then what the timing of that stuff is and if it would be kind of out of bounds to look at the undersea line in Connecticut and kind of the Milton and Norwalk line to get a scope out of cost per mile or what that might look like?

Ross, in terms of the kind of renewables New Hampshire transmission, there is a -- a strong momentum to try to expedite the construction of those projects, and to get them built as soon as we can, what we're hoping for, quite frankly, is legislation that would allow us to go forward and then put together a transmission design and take it through the ISO process in terms of getting approval.

We owned essentially a right-of-way, 115kv right-of-way that runs up through northern New Hampshire and then we own a right-of-way that comes off, north of the Berlin, New Hampshire, that actually -- it's a 34.5kv right-of-way that goes into Quebec.

Our position is as soon as we get legislation, we are prepared to expedite both the design and citing and the -- of the build out of that project.

So if you look up the 2012 time frame, we are -- if we get immediate legislative approval sometime this year, we would hope to have it done on or before that time period because on the -- if using the existing 115kv lines, it's not a very sophisticated design.

It would be relatively quick to design and build.

So on or before 2012, assuming we get legislative -- the legislative changes we need.

And Ross, with respect to your question about the Quebec line, as you probably know having looked at the D.C.

Dayton material, there were a number of folks who presented different opportunities in New England ranging from conceptual to specific projects.

We thought it important to begin to inform this discussion and to make this discussion a little more real to put forth a project that as you pointed out runs a D.C.

line into Quebec to bring the considerable hydro resources from Quebec down and then has at least one adjunct to it, an undersea line.

As you can appreciate, there are a lot of moving parts to this.

Each of the states have their own views on this, the transmission owners have their own particular views on this and clearly ISO does.

So one of the things that we are attempting to do and I said in my remarks that we would hope to have a more refined solution set in place that we could discuss in more detail by the second half of this year.

One of the things that we are trying to do is meet with those interested parties, begin to have informed discussions around what each party is trying to accomplish, and then see if we can't reach a consensus that begins to bring real solutions to the region.

I will say and we said this on a number of occasions.

This is not just one solution.

We are not just going to build -- nobody is going to build just one line that solves everything.

But looking at a portfolio approach, which may include accessing additional renewables in Maine or New Hampshire, or accessing additional generation capabilities in a variety of the Eastern Canadian provinces, I think we can fashion something that we can reach a consensus opinion on.

That process is, as you appreciate, got a lot of associated aspects to it and we'll continue to keep you apprised.

But our hope is that we can put a more refined solution set in space to have people talk concretely about it by the second of this year.

Ross, is your question in regards to underwater cable, is it the cost per mile for an underwater D.C.

cable?

Yes, I was just trying to get like a scope.

I know that you guys have done Norwalk to Northport and that's like 11 miles for $72 million and then Middleton to Norwalk is 69 miles for about $1 billion.

I know there's differences in geography and probably labor, Connecticut to New Hampshire, but I was just trying to scope out what this might look like down the road based on a nautical mile cost picture?

If you are looking at, like, underwater lines, like an underwater D.C.

line, as an example, -- you are probably talking a good number, about $10 million a mile for a D.C.

line under water, and if you are looking, overhead lines -- you know, overhead lines depending on what the citing criteria is in each state, Connecticut is probably the strictest and so it has the highest cost, if you do overhead, for instance, like overhead 345kv lines, they are up around, $4 million a mile with E&F mitigation technology and so forth.

So it kind of depends on the technology and on the state citing criteria.

Now all of the numbers we have given with NEEWS, to give you an example, with the exception of the underground 115kv cables, all of those 345kv numbers have no undergroundling built into that.

So to the extent that either in Connecticut or Massachusetts, that require undergroundling, then whatever the mileage is, you multiply times, essentially about 4 in terms of that cost.

Okay.

That makes sense.

Thanks very much.

Thank you, Ross.

Our next question is from Maury May from Power Insights.

Maury?

I have a question again, on the new growth rate.

If I recall, the old growth rate of 10 to 14% was -- was back end loaded in that the growth in the early years of the five years was faster than the final couple of years.

Is that also true of the new 8 to 11% rate?

David, I think it's true.

If you look at where we are going on an '08 midpoint over 2007 actual, that's again, about 12 or 13% growth.

I think when you kind of look through to '09, 2010, it kind of models out to a different shade and then probably flattens out a little bit.

And then the very end, the last tail year, you get another little pop.

So it's looking -- it's a little chunkier year by year than say last time.

Last year it was good growth in 2007, big growth in 2008.

Kind of a little bit of a U shape.

We are chewing off some of that front end as we succeeded out in 2007.

Still get kind of a U shape but last year too is a bigger increase.

You got to model out year by year.

Okay.

My second question has to do with the parent refinancing that you plan for June 1.

If I recall, you're refinancing $150 million of 3.3% debt and what do you plan to refinance, exactly that amount or a higher amount?

And if you had to do it today, what would be the costs to you all?

We are studying that now.

Those are the right numbers, $150 million, and 3.3% was issued roughly 5 years ago.

So we are studying exactly how much.

It will be that number, plus or minus, don't expect to see a $500 million offering any time soon.

We did already not only for NU parent but we did for all of our -- basically all of our debt exposure lock in interest rates already some 5s and some 10s through some forward rate starting swaps as I mentioned.

So at this point, it depends on what's happening in the credit spread market as we get into that time frame.

But, clearly, it is going to depend on where we are on the maturity spectrum.

So if we did a 10-year deal and the 10 years is trading at 380, you can guess where your parent paper is right now, it might be 225, given their rating.

But I have already got the underlying interest rate pretty locked in.

So (inaudible) is still developing.

I would say five to ten year maturity.

It would say it's generally going to be in that 150 area and I think it's generally around 200, 225 over the T.

Okay.

Thank you very much.

You're welcome.

Our next question is from Paul Patterson from Glenrock.

Paul?

Good afternoon, guys.

Hi, Paul.

I just wanted to follow up on Jonathan Arnold's question on the ROE.

When you are looking at the ROE that you guys are projecting, versus what you were allowed, you mentioned that there was a certain class of costs that you guys simply disagreed with the commission in terms of what's applicable to CL&P is what it sounded like to me.

I guess what I'm wondering is, how much of the difference in ROE, I mean if it's possible to quantify is associated with items that they simply don't feel should be -- should be expensed by CL&P and cost allocations, what have you from the parent or as you mentioned D&O insurance, versus just maybe expectations, expectations of sales growth or O&M, or something that's different.

Can you just elaborate a little bit more in terms of what is causing the differential and the earned ROE that you're expecting versus the allowed?

Sure, there are probably two types of costs that I would characterize.

The first cost is where we may have a differing view of what our rate year expense will be.

They think differently, but fully recovered, whatever they believe that rate is.

And I will give you some examples.

In the second bucket, maybe philosophically.

Costs that they feel should be borne in part by our shareholders, as opposed to exclusively in a rate payer account.

So some of those costs, for example, might be some of our benefit programs such as 401k and they are quite explicit in their rate order saying that some of those costs should be borne by our shareholders.

Also things like for incentive compensation for our executives.

Those costs should be borne by our shareholders so some of those type of costs probably philosophically the commission may continually rule that they are not recoverable.

Even if you actually do bear that expense level.

That's different than to say the first bucket of costs that may be things like storm expense, or rent expense or expense to cover your vehicles and your fleet and your auto insurance and the like, where you are just saying -- they might say your test year is not reflective of what your rate year expense level might be.

And there's just a difference.

They are not saying philosophically you should not get them covered.

But to your second point, when you look through those items where they may rule for some period of time that your shareholders should cover some of these costs, D&O insurance, 401k, executive incentives, it might be worth 30 or 40 basis points off of that 9.4 that we just can't get to.

Excellent.

That's great.

Then just to follow-up on Jonathan's question about the 2009, was your answer -- and I'm sorry to be not clear on this.

But I wasn't clear whether the answer was that you weren't sure what the 2009 ROE, whether it be improved or not or whether -- what exactly was your expectation if you had one.

First my stock answer is we are not giving 2009 guidance and I don't mean to be flip about it.

That's not our precise study period right now.

We know we have got about $20 million of revenues coming in to CL&P from the rate case, and what we are doing now and we'll do over the course of the spring in particular, as we kind of drive towards deeper in the year preparing '09 guidance is sort of think through what costs were recovered, and back to that philosophical issue of who is going to recover these costs, what is the appropriate expense structure for this organization, and what is the outcome.

What is the regulatory ROE outcome.

All of that work is in motion.

Okay.

Great.

Thanks a lot, guys.

Thank you, Paul.

We don't have anymore questions now.

So I just want to thank you all for joining us.

If you have any follow-up questions, please give us a call this afternoon or tomorrow, and we'll talk to you soon.

Thank you very much.