康涅狄格電力 (ES) 2010 Q4 法說會逐字稿

Welcome to the Northeast Utilities Q4 2010 earnings call.

My name is John, and I'll be your operator for today's call.

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

Later, we will conduct a question and answer session.

Please note that this conference is being recorded.

I will now turn the call over to Mr.

Jeffrey Kotkin.

Mr.

Kotkin, you may begin.

Thank you very much, John.

Good afternoon, and thank you for joining us.

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

Speaking today will be Chuck Shivery, NU's Chairman, President and Chief Executive Officer, Lee Olivier, NU Executive Vice President and Chief Operating Officer and David McHale, NU Executive Vice President and Chief Financial Officer.

Also joining us today are Jim Muntz, President of our Transmission Group and Jay Booth, our Controller.

Before we begin, I'd like to remind you that some of the statements made during this investor call may be forward-looking as defined within the meaning of the Safe Harbor Provisions of the US 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 forecast and projections.

Some of these factors are set forth in the news release issued yesterday.

If you have not seen that news release, it is posted on our website at www.nu.com.

Additional information about the various factors that may cause actual results to differ can be found in our Annual Report on Form 10-K for the year-ended December 31, 2009 and our Form 10-Q for the third quarter of 2010.

Additionally, our explanation of how and why we use certain non-GAAP measures is contained within our news release and in our most recent 10-Q and 10-K.

Now, I will turn over the call to Chuck.

Thanks, Jeff.

I'd like to thank everybody for joining us this afternoon.

From all aspects, 2010 was a very good year for Northeast Utilities, its customers and its shareholders.

David will cover the financial details of the quarter and the year, but I'd like to hit the year's high points.

Our earnings for the year were well beyond our initially projected range of $1.80 to $2 per share.

That was due to a combination of factors including strong cost control, sound operations, a hot summer, and the impact of mid-year rate decisions.

Earnings growth last year exceeded our 6% to 9% long-term growth rate, and we continue to increase our dividend at a rate that is faster than the industry average.

As you know, earlier this month, our Board of Trustees approved a 7.3% increase in the dividend to an annualized amount of $1.10 per share, the eleventh consecutive year we have had a dividend increase that exceeds the industry average.

In terms of how we serve our customers, we continue to see a number of successes.

The benefits to customers from the transmission upgrades we completed in Southwest Connecticut has saved electric customers more than $600 million since they were completed.

We continue to invest more than $400 million annually improving the reliability of our three state electric distribution system.

Our new customer information system has allowed us to dramatically improve our response rate to customer inquiries.

Our communities benefit from the improved reliability of our facilities.

Property tax revenue generated by our new equipment, by our employment levels which have remained steady and by our corporate philanthropy which reached record levels of nearly $5 million in 2010.

Heeding the call of Connecticut's new Governor Malloy, we are insuring that the state is open for business by improving our reliability, streamlining our processes and implementing some of the most aggressive energy conservation programs in the country.

In 2010, CL&P's energy conservation expenditures totaled approximately $120 million, including $43 million invested in the commercial and industrial sectors.

In transmission, we received final approval of the Greater Springfield Reliability Project this past fall and have already begun construction.

And ISO New England confirmed the need for the Interstate Reliability Project.

In addition, we've received strong remarks for the operation and security of our transmission system.

On February 11, FERC approved the transmission services agreement associated with our new Northern Pass transmission line to import power from Hydro Quebec.

That approval was a significant next step in the process.

FERC recognized our TSA, the product of more then a year of negotiations, as uniquely beneficial to our region.

It approved our requested initial return on equity of 12.56%, our requested 50% equity, 50% debt capital structure and our fully tracking cost recovery tariff.

We expect the Northern Pass line to commence operation by the end of 2015 and immediately provide New England's electric customers with an attractive combination of economic benefits, a significant reduction in fossil fuel consumption and a very real reduction in New England's greenhouse gas emissions.

Lee will provide you with a summary of our work as we continue to move this project forward.

On the distribution side, despite an unusual level of storm activity and a very hot summer, we maintained a reliable system, improved our customer service metrics and significantly reduced our uncollectible balances.

We also secured approvals from our Connecticut and New Hampshire regulators to continue to invest heavily to replace our aging distribution infrastructure and completed half of a new gas pipeline linking our LNG facility in Waterbury with a significant load center in the Wallingford Cheshire area.

The project will reduce gas congestion on the Yankee Gas system and help our customers lower their fuel costs and emissions.

On the generation side, we continue to make significant progress on PSNH's Clean Air Project at Merrimack Station, brought online our first solar facility in Massachusetts and announced the location of a second site for a larger solar facility.

And on the strategic side, we announced our transformative merger with NSTAR and have filed all of the regulatory applications which must be approved before we close.

The shareholder vote on the merger is continuing to progress.

Proxy advisory firms have recommended end use shareholder approval, and the special shareholder meetings for both companies are set for March 4, a week from today.

The mandatory waiting period under Hart-Scott-Rodino Act has expired, and FCC approval has been secured.

We expect other federal reviews before the FERC and the NRC to be smooth.

Our application for approval of the merger was filed late last year with the Massachusetts Department of Public Utilities, and the discovery process continues.

The DPU is currently reviewing various filings on the standard of review it should utilize in reviewing the merger.

We and NSTAR firmly believe that this standard should remain the no net harm standard that has served the state well for about 60 years.

Once the DPU makes this determination on the appropriate standard of review, we expect it will reestablish a schedule for the conclusion of the case.

At that time, though there is no statutory deadline, we expect the DPU to be in a position to vote on the merger by the end of the third quarter.

In Connecticut, we continue to believe that regulatory approval is not necessary and remain hopeful that the DPUC will reaffirm in the near term their prior conclusion that they do not have jurisdiction over the merger.

Oral arguments occurred a week ago on the earlier DPUC draft decision which concluded that since there was no change of control at Northeast Utilities, CL&P or Yankee Gas, DPUC approval was not required.

In addition to the oral argument, the DPUC will hold a public informational hearing on the merger in the near future.

You may be aware that a bill has been raised in the Connecticut legislature that would confer DPUC jurisdiction over mergers such as ours.

While we have not yet seen a detailed description of that bill, we nonetheless believe that such an approach would not serve the best interest of the state.

We have formed the integration teams that will develop recommendations on how the two companies should be merged so we can fulfill our commitment to our customers, our communities and our investors, that they will benefit from this business combination.

We believe this merger will be a pathway for both companies to implement best practices in a cost effective way that can result in better service at a lower cost than each could provide on a standalone basis.

We believe the combined businesses can offer investors a compelling opportunity to invest in a company that offers earnings and dividend growth better than most of our peers.

Together, we expect that a combined NU and NSTAR can provide long term cumulative annual earnings growth at the higher end of the 6% to 9% range we have targeted for NU on a standalone basis.

Now, I'd like to turn the call over to Lee.

Thank you, Chuck.

Overall, we had a very good year operationally, despite a very significant increase in storm activity over both 2009 and historic levels.

We experienced 39 major storms in 2010 as compared with 19 in 2009 and expensed about $30 million in costs within double our budget of $14 million.

We were, however, able to successfully offset $16 million of higher storm related expenses through rigorous cost controls and strong uncollectible expense performance.

Aside from those storms and some very high peak loads throughout the summer, our system performed well throughout the year.

System reliability clearly benefited from the capital investments we have made in recent years and from our strong focus on preventive maintenance.

Turning to generation, our base load units, which include our renewable wood chip burning Northern Wood Power Plant operated reliably and achieved an 81% capacity factor.

Our largest generation project currently underway, PSNH's Merrimack Clear Air project, is currently 82% complete and on schedule to begin operations in mid 2012.

The $430 million project involves installing a wet scrubber at our two unit Merrimack coal fired station.

Through December 31, PSNH has capitalized nearly $300 million associated with the project, about half of which was capitalized in 2010.

In Massachusetts, WMECO commenced operation of its first solar energy facility on October 26, located on a brownfield site in Pittsfield, the 1.8-megawatt facility is the largest in New England.

In January, WMECO announced its plan to develop a second and larger project located on a capped landfill in Springfield.

We believe this site can accommodate 4.2 megawatts of power, and the major permitting and procurement activities for this project are underway.

Assuming a favorable outcome, we would begin construction in the second quarter of 2011.

The cost associated with both solar facilities, including the authorized return on equity, will be recovered through a fully tracking rate mechanism.

With respect to 2011, we are seeing heavier weather related natural gas loads.

Yankee Gas has had record commodity send outs on both January 23 and 24.

Send out on January 24 was nearly 351 million BTUs, which eclipsed the previous day's record by more than 4%.

You've probably noticed that firm natural gas sales rose by 9.1% in the fourth quarter of 2010 compared with the same period of 2009 due to both colder weather and the attraction of natural gas prices in this current energy environment.

We expect to see strong sales in the first quarter of 2011 relative to 2010 as well, largely as a result of much colder January and February temperatures.

David will discuss some of the specifics of the Yankee Gas rate case that we filed last month, but a key aspect of the case is our capital investment program.

Yankee Gas invested nearly $95 million in its system in 2010, of which $26.6 million was invested in the Waterbury to Wallingford pipeline, which will improve reliability and meet increasing demand for natural gas in this area.

Approximately 10 miles of the 16-mile line extension including the Naugatuck River crossing is complete, and the line extension between Wallingford and Cheshire went into service in November.

The remainder of the project, which involves increasing vaporization output of Yankee's Waterbury LNG facility, and connecting it to the new line should be complete by this November.

We recently reduced our total estimated cost of the project from $63 million to $57.6 million due to a combination of factors, including lower labor costs, lower than expected contractor bids on our LNG upgrade.

Bringing that project into rates and increasing the scale of our program to replace older cast iron and bear steel gas mains are core elements of our rate case recently filed.

Turning to Western Mass Electric, a key element of our 2010 rate case was our proposal to increase distribution capital spending from approximately $30 million annually to about $50 million annually to better address aging infrastructure.

In its decision, which was effective this month, the DPU denied our proposed capital investment tracking mechanism.

As a result, Western Mass Electrical will not increase its current level of distribution capital expenditures.

Turning to transmission we continue to forecast capital expenditures of $445 million in 2011, up significantly from the $261 million we invested in our transmission system in 2010.

That increase primarily reflects increased investment in our $795 million Greater Springfield Reliability Project which we began building in December.

Major overhead construction will begin this spring, and we continue to target a late 2013 in-service date for the project.

The Greater Springfield Project is by far our largest project associated with the New England East/West Solutions family of transmission upgrades.

We and National Grid are targeting the second half of 2011 of filing our siting applications associated with the Interstate Reliability Project.

That project will run from eastern Connecticut through northwestern Rhode Island and into Massachusetts.

Our Connecticut section is expected to cost approximately $300 million.

In late 2010, ISO New England plant has confirmed the need for the interstate.

Those same plans continue to review the date of need for the third major leg of news, the Central Connecticut Reliability Project.

We believe ISO will complete a preliminary needs assessment this fall.

Earlier, Chuck discussed FERC's approval of the transmission services agreement we signed with an affiliate of Hydro Quebec.

We filed for two other approvals in October.

We filed with the US Department of Energy for a presidential permit and with ISO New England for a technical approval of the line.

Last week, we updated the presidential permit application to identify a location in Pittsburg, New Hampshire as our preferred option for where the line should cross the Canadian/US border.

We are close to filing our US Forest Service application and expect to make an additional application with the New Hampshire Siting Evaluation Committee and various federal agencies early next year and to have them aligned fully permitted by early 2013.

We've set up an office in northern New Hampshire to better enable us to work with the communities and land owners along the project route.

We continue to forecast completion of the line by the end of 2015.

NU's 75% share of the $1.1 billion project is approximately $830 million.

As you know once our merger with NSTAR occurs, NU's share will be 100%.

Now, I'd like to turn the call over to David.

Thank you, Lee.

As Chuck indicated earlier, 2010 was a good year financially for the Company.

We earned $387.9 million, or $2.19 per share compared with earnings of $330 million, or $1.91 per share in 2009.

Excluding the non-recurring impacts of the parent Company tax settlement and merger related expenses, we earned $2.16 per share in 2010.

That level is consistent with the guidance of $2.10 to $2.20 per share that we gave at the Edison Electric Financial conference last November.

This year on a standalone basis, we are projecting earnings per share of between $2.25 and $2.40, excluding approximately $0.15 per share of expected merger related costs.

Those earnings are consistent with our projected long term EPS growth rate of 6% to 9% and they reflect the earnings power related to the capital expenditure and rate base projections we provided to you at EI in November as well.

We recognize that this guidance is clearly above consensus, which seems to be hovering around $2.25 per share.

And speaking to several of you prior to the call, we sense that some of this difference may be related to the benefits of additional cash flow resulting from bonus depreciation, a lower effective tax rate, which we view to be about 35%, a higher level of equity capitalization within our companies, and our continued focus on cost control.

I'll spend more time on 2011 in a moment and break this down for you by segment, but let me start with the details behind 2010 results.

We earned $129.3 million, or $0.73 per share in the fourth quarter 2010 compared with earnings of $84.7 million, or $0.48 per share in the fourth quarter of 2009.

The most significant improvement was in our distribution segment which earned $206.2 million in '10 compared with $159.2 million in 2009.

That improvement was concentrated in the second half of the year and resulted from a combination of factors, including the implementation of distribution rate decisions at CL&P and PSNH, hotter summer weather and colder December temperatures and some significant progress we made in cost management, particularly in reducing our uncollectibles expense.

These factors were particularly meaningful in the fourth quarter of 2010 when our distribution segment earned $75.5 million compared with $39.2 million in 2009.

These factors are also helping to position our distribution companies to improve their earned return on equity levels.

CL&P's distribution segment earned $39.9 million in the fourth quarter of '10 compared with $19 million in the fourth quarter of 2009.

It earned $91.1 million for the full year 2010 compared with $74 million for the year 2009.

Revenues didn't necessarily drive the improvement in financial performance since CL&P's distribution rate increase did not take effect until January 1 of 2011.

Rather, both fourth quarter and full year improvements were due to a combination of lower depreciation in operating expense, both the result of CL&P's rate case decision and lower uncollectible expense due to significant progress we've made in this area and the benefits of tax settlements.

These improvements were partially offset by higher storm and pension expense.

For the year, CL&P's Electric sales were up 1.8% over 2009 although they were down 1.8% on a weather adjusted basis.

For the full year, CL&P improved its distribution segment regulatory ROE from 7.3% in 2009 to 7.9% in 2010.

In 2011, we expect CL&P to experience further improvement in its ROE, and we expect to earn in the 9% area.

CL&P's allowed return is 9.4%, as a reminder.

PSNH's distribution and generation segment earned $17.8 million in the fourth quarter of 2010 compared with $11.3 million in the fourth quarter of 2009 and $69.3 million for the full year 2010 compared with $47.5 million for the full year 2009.

PSNH benefited from the distribution rate increases that were effective in August of 2009 and July of 2010, as well as from higher AFUDC earnings on the $430 million Clean Air project.

You may recall that in addition to PSNH's permanent distribution rate increase, the Company will collect approximately $13.7 million from July 2010 through June 2011 to recoup revenues it did not receive during the 11 months that temporary rates were in effect.

Partially as a result of those additional revenues, PSNH's combined distribution and generation segment regulatory ROE for 2010 was 10.2%.

The recoupment period will end in June 2011 and for the full year 2011, we are projecting a combined distribution and generation segment regulatory ROE in the area of 9%.

For the year 2010, PSNH's sales were up 1.3% over '09, although they were down 1.8% on a weather-adjusted basis.

Western Mass Electric Company, their distribution segment earnings were $1.2 million in the fourth quarter of 2010, down about $2 million from the fourth quarter of 2009, primarily due to a $2.1 million charge resulting from the Massachusetts DPU's January 31 rate decision.

For the year, Western Mass Electric distribution segment earned $10.1 million compared to $16.7 million in 2009.

While WMECO did see sales growth of more than 2% in both the fourth quarter and full year 2010 compared with '09, higher operating expenses in the aforementioned fourth quarter charge more than offset the additional revenue.

As expected, WMECO's distribution segment ROE was off significantly in 2010, but they earned 4.6% for the year compared with 8.4% in 2009.

As you probably saw on January 31, the Massachusetts DPU approved an annualized distribution rate increase of $16.8 million for the Company that was effective this month.

While it was less than the $28.4 million initial request, we expect it will allow WMECO's earnings to recover in this year.

We are currently projecting a distribution segment regulatory ROE in the area of 9% for WMECO in 2011 compared with a DPU authorized level of 9.6%.

I should also note that in addition to the rate increase, the DPU approved WMECO's sales decoupling proposal, and our pension tracking mechanisms remain in place.

Yankee Gas earned $16.6 million in the fourth quarter of 2010 compared with $5.7 million in the forth quarter of '09.

For the full year, Yankee Gas earned $32.7 million compared with $21 million for all of 2009.

The principal drivers for Yankee Gas' 2010 earnings improvement were sales in significantly lower uncollectible expense.

Yankee Gas firm sales rose 9.1% in the fourth quarter of 2010 compared with the fourth quarter of 2009.

And while a colder month of December compared with '09 helped, weather adjusted sales still rose by 6.3% for the quarter.

For the full year, despite a mild first quarter, Yankee Gas firm sales were up 1.9% compared with 2009.

On a weather adjusted basis, firm sales were up 6.2% for the year.

Improvements we made in collecting overdue bills were particularly helpful for Yankee Gas where pre-tax uncollectible expense that affects earnings declined by about $10 million in the fourth quarter alone and $15.7 million for the year.

In 2010, Yankee Gas earned a regulatory ROE of 8.6% compared with an authorized level of 10.1%.

Yankee Gas filed a rate case with the Connecticut DPUC last month seeking a $32.8 million increase in base rates effective July 1, 2011 and another $13 million increase effective July 1, 2012.

The primary reason for the application is to reflect end rates, our continued high level of investment in the Yankee Gas system.

The increase in investment is somewhat offset by increasing sales and lower uncollectible expense, but additional rate increases are still needed to recover investments like the Waterbury to Wallingford project.

In the January filing, Yankee Gas asked to maintain its currently allowed regulatory ROE of 10.1% and is scheduled to receive a distribution -- a decision in the case in June.

Hearings are scheduled for March.

Overall, we earned $1.16 per share in our distribution and generation segment in 2010, and in 2011, we expect that segment to earn between $1.25 and $1.35 per share.

There are a number of key factors built into the projection in addition to the rate case decisions we have already received.

We expect continued economic recovery and for the first time in three years, we are not projecting sales declines.

That said, we see retail sales at essentially flat to 2010 on a weather adjusted basis.

Recall that over the past three years, weather adjusted electric sales were down by more than 2% annually.

We also foresee increased employee benefit expenses and are assuming that untracked pension and healthcare expense, primarily related to the distribution segment, rises about $0.11 per share in 2011 compared with '10.

Other untracked O&M is expected to rise about 2% overall, or $0.04 per share.

Now turning to transmission.

The segment earned $50.5 million in the fourth quarter of '10 compared with $44.4 million in the fourth quarter of 2009.

For the full year 2010, our transmission segment earned $177.8 million compared with $164.3 million in 2009.

The improvement was primarily due to the ongoing investment in our transmission system.

Our transmission rate base totaled $2.76 billion at the end of 2010 compared with $2.6 billion at the end of '09, an increase of about $160 million, or more than 6%.

For 2011, transmission segment earnings guidance is $1.05 to $1.10 per share, with earnings growth driven primarily by construction of the Greater Springfield Reliability Project.

By year end, we see transmission rate base growing to $2.93 billion, up 6.3% over year end '10.

Our competitive businesses earned $8.3 million in 2010 compared with $15.8 million in 2009.

This in part reflects expected lower operating results and mark-to-market gains in 2010.

In terms of earnings guidance going forward, we'll merge our competitive businesses into our parent and other Company guidance.

This reflects the progressively smaller impact that our competitive businesses will have on our financial performance in future years.

And finally, in relation to NU parent and other companies, when we reported our results last evening, we singled out the $6.3 million net positive impact related to a tax settlement we reached in the fourth quarter of 2010 net of our merger related expenses.

The tax settlement was a non-recurring item that added $15.7 million to earnings in the quarter.

The merger related expenses totaled $9.4 million after-tax.

Excluding those impacts, we recorded after-tax parent expenses of $3.6 million in the fourth quarter of 2010 and $10.7 million for the full year, which was consistent with our previous earnings guidance.

These figures are similar to what we recorded in 2009.

In 2011, we project net after-tax parent and other expenses of $0.05 per share, excluding merger related expenses.

At this time, we are projecting just under $30 million of after-tax merger expenses in 2011, assuming the merger closes this year.

That would amount to about $0.15 per share based on our current outstanding common share count.

All of the 2011 guidance figures are on a standalone basis.

From earnings, let me turn to a few balance sheet and cash flow items.

As a result of our strong performance in 2010, total common shareholder equity levels rose by about $230 million to just over $3.8 billion during the year.

Over the same period, our total debt levels rose about $300 million to just under $5 billion, so our total debt represented about 56% of our total capitalization at the end of 2010, excluding rate reduction bonds.

This level is well below the 60% level of debt to total capitalization to which we have managed our capital structure in recent years.

One reason for the strength of our balance sheet is the improving cash flow profile.

In 2010, operating cash flows after retirement of rate reduction bonds totaled $833 million compared with $745 million in 2009.

An important cash flow item going forward related to the impact of bonus depreciation and a 2010 federal tax bill.

We expect those provisions to add a total of about $250 million to cash flow in 2011 alone and about $450 million to $550 million to cash flow over the three year period 2011 through 2013.

As a result, we anticipate net cash flows from operations after retirement of rate reduction bonds to total between $950 million and $1 billion in 2011.

In terms of specific earnings impacts in 2011, the increased cash flow should reduce interest expense by about $5 million after-tax.

That will be only partially offset by a $2 million reduction in earnings as a result of a lower rate base.

So, there is a net favorable impact of bonus depreciation of about $3 million, or $0.02 a share this year.

In terms of the longer term impact, we'll be updating our standalone five year capital expenditures and related rate base figures in our 10-K which we anticipate filing later today.

Although you'll find that total projected rate base by the end of 2015 is down by about $500 million or 4%, the vast majority of the impact is in the distribution segment.

And even with this update, we feel very strongly that we can achieve our projected 6% to 9% compounded annual EPS growth rate, in part because we will use this additional cash flow to offset a significant amount of planned external debt and equity capital raise.

In terms of financing activity, 2011 cash flow will fund a vast majority of our capital expenditures, which we continue to project to be approximately $1.2 billion this year on a standalone basis.

As a result, we are projecting only two new long term debt issuances, both of them later this year.

We have regulatory approval to undertake both of those issuances.

$160 million of new bonds of PSNH and $100 million of senior notes at Western Mass Electric.

And we have no debt maturities this year and our bank lines have been extended through September of 2013.

Our cash flow of estimates are net off our increasing contributions to our pension plan.

In 2010, we contributed $45 million to the plan.

In 2011, we expect to contribute about $145 million to the plan.

We had earlier projected $200 million of contributions in 2011, but we lowered that figure due to a number of factors, including the strong performance of the assets in our plan.

In 2010 we saw a 16.75% return.

Also helping cash flows will be the impact of the CL&P 2010 distribution rate increase.

You may recall that while the $63.4 million of 2010 rate increase was effective July 1 of 2010, the impact on customers was deferred until January 1, 2011, so that its implementation could correspond to a sharp decline in our competitive transition assessment charge, or CTA.

The decline in the CTA was the result of CL&P making the final principal and interest payments in December of 2010 on more than $1.4 billion of rate reduction bonds that were issued in 2001.

The RRB payments were pass through costs, so their drop off does not affect our cash flows.

However, the average half cent a kilowatt hour increase in the distribution charge effective January 1 will increase CL&P's cash generation in 2011 without customers seeing an increase in their overall electric rates.

In fact, because of the decline in commodity prices, CL&P's residential and small commercial customers who remain on standard service experience the 7.8% decline in their overall bill in January.

Thank you again for your time.

Now, let me turn the call back to Jeff Kotkin.

Thank you very much, David, and I'm going to turn the call back to John to remind you how to log in any questions.

John?

If you could pick up right now.

Thank you.

(Operator Instructions)

All right, thank you very much, John.Our first question this afternoon is from Jonathan Arnold from Deutsche Bank.

Jonathan?

Good afternoon.

Hello, Jonathan.

I had a couple of things.

Firstly, you mentioned the strong weather in January and February in the gas business.

Is that -- but then you didn't mention it as one of the factors in the -- in guidance, so -- versus where the street's been.

So, is it fair to assume that that's something that might put you higher within the range, or is it something that's kind of in the range?

Jonathan, I assume you're talking about the new 2011 guidance?

Yes, sorry, excuse me.

We're normalizing for the weather effect thinking that there's flat sales going forward.

That's not clear to us what the market was expecting by way of kind of year-over-year gas or power sales.

There may be -- maybe that accounts for some of that, but we're normalizing for the sale, so we are not starting from that higher level that we achieved in 2010.

But in terms of the weather you've seen so far in 2011, is that normalized out of the guidance range?

I wouldn't say that's normalized out.

It may be worth a little bit.

We saw some pretty good gas margins, in January in particular.

We've got a little bit of weather sort of at our backs here in February, but it's probably worth a little bit, but that's not what's driving our view around the guidance this year.

So, it's in there, but it's not that material?

Right.

Okay, and then the second question was, you talked about thinking that Massachusetts might take until maybe the end of the third quarter to get to a vote on the merger.

So, my question is in some of the commentary out of the legislature in Connecticut, they've talked about wanting to keep an eye on what may or may not come out of the Massachusetts review.

Do you think that that's a decision that will -- the Connecticut case will ultimately come after Massachusetts, or they might just move forward before Massachusetts gets wrapped up?

Jonathan, this is Chuck.

As you know, Massachusetts has jurisdiction over the merger, so there has to be a case in Massachusetts where they make a decision on the merger.

We don't believe that Connecticut in fact has jurisdiction.

So far, the DPUC, at least in their draft order, has agreed with that.

I think you do know that there was oral arguments earlier this week on that particular issue and in Connecticut, there will be an informational hearing, much like the informational hearing that we had in New Hampshire.

That hearing has not yet been scheduled in Connecticut.

If that just simply proceeds along, we don't think Connecticut would then be a constraining issue on the merger approval timeline.

Did you see them getting to a definitive decision on jurisdiction ahead of Massachusetts wrapping up their case?

It's hard to project that, but I would think that the process in Connecticut, at least around jurisdiction is moving along reasonably well.

Chairman Delgado did say he was continuing to see what was going on in other jurisdictions.

So, I think there are a lot of moving parts right now, but I think both of the processes in both Massachusetts and Connecticut, and in New Hampshire for that matter, are moving along well.

Thank you very much.

Thank you, Jonathan.

Our next question is from Jay Dobson from Wunderlich.

Jay?

Hello, thanks, and good morning -- good afternoon, sorry.

It's been a long day.

Two questions for you, and I guess I'll throw it to Chuck and he can hand it out to the group.

First on O&M, clearly a good year in 2010.

How much of that should we be extrapolating forward, and what's your view on operating costs, and let's continue to think in the standalone basis.

Well, Jay, thank you, and I will do just that.

I'll agree with you that we did a great job in managing costs in 2010 and obviously, we're looking at continuing that strong cost management in 2011.

And I'll turn it over to David to see if he wants to make any specific comments.

I think that, and I mentioned this in the script, there's always a differential on our mind between core O&M and say the employee benefits, employee costs.

And we know that those things, and some of those are formulaic as we calculate things like pension expense, are going to put a little bit of pressure on our numbers, and that I quoted as being $0.11.

So, if you look at both pension and employee benefits, now a good share of that, a healthy amount of that was carbureted in the revenues that we received in the rate cases, so that's -- you've got to sort of put that into the model too.

But away from that, if you just look at what's happening with core O&M, I mentioned that we're up about 2%, so that's sort of our run rate, knowing too that there's going to be a kind of labor inflation of about 3% in the organization.

But good progress managing the overall core business, we made great progress in 2010 around uncollectible expense.

We're not going to be able to replicate that year-over-year, but I think we've got a pretty good bead on uncollectible expense.

I don't see a lot of inflation there or a lot of upward pressure there, but 2% is sort of the run rate that we're looking at this year.

That's great.

And as a follow-up, David, in pension expense for 2011, do you see any benefit there, or should we be just about flat with the run rate from 2010?

No, pension expense is definitely going up, particularly as we continue to amortize the losses really, from 2008.

So, you'll see this upward trajectory, and I'd be surprised if that is unique to Northeast Utilities and our system Company.

So, we'll experience that, but that's all embedded in the $0.11, Jay, that I quoted.

Okay, great thanks.

And then Chuck, back to Northern Pass, just great getting the TSA behind us, and now what about the PPA?

Well, Jay, yes, I think -- first of all, I agree with you, getting the TSA behind us was a very significant step forward in this whole approval process.

But I think we've chatted in the past with you that there is not a requirement to have PPAs in place, at least from Hydro-Quebec's standpoint, in order to continue to move forward with this.

We do expect to do something in New Hampshire around a PPA, but we don't have to have PPAs to take the full amount of the energy coming from Hydro-Quebec for us to move forward.

Great.

Thanks very much for your time.

Thank you, Jay.

Our next question is from Ashar Khan from Visium.

Ashar?

Hello, good afternoon.

Hello.

David, you gave a lot of numbers.

Could you just go over what the ROE in the 2011 guidance is by each jurisdiction, like CL&P in Massachusetts and New Hampshire?

I apologize, I missed some of the numbers.

Sure, we'll make it easy on you, Ashar.

Basically what we're saying is for both PSNH which, as you know, we kind of talk about as both its distribution and generation business, CL&P Distribution and then Western Mass Electric Distribution, we're saying they're in the area of 9% for all of those.

Now, you can make a determination of whether that's getting us that mid-point, high-end, low-end, but that's kind of where we feel right now.

We stopped short of giving a specific number around Yankee, predominantly because we're in the middle of this rate case there.

We've asked for 10.1%, and we'll be driving towards a decision a little bit later this spring.

Okay, and what is the ROE on the transmission business in the 2011 guidance?

That continues to be in our sort of blended 12%-ish area.

12 -- okay, okay, appreciate it.

Thank you.

All right, thank you, Ashar.

Our next question is from Paul Patterson from Glenrock.

Paul?

Good afternoon.

Hello.

Just on the -- I heard you guys talk about the Mass.

DPU and the potential or the efforts by some to get a different standard.

I think it's around renewables.

Could you elaborate a little bit more on what's exactly driving that?

Is there some -- what's driving it?

And then I guess also, if it is adopted, what does that do to the schedule or do you know what it does to the schedule?

Paul, this is Chuck.

I guess what's driving it is there was a speech given at the end of the year by an outgoing commissioner that suggested that instead of the no-net-harm schedule, they should have a schedule that says not only is it no net harm, but is there a benefit to the state or to the region or to the customers.

There have been a number of folks that have suggested that that might be the appropriate schedule or the appropriate process, even though for about the last 60 years, they've used the no-net-harm schedule.

The commission, as you know, the Mass.

DPU made the decision to suspend their procedural schedule while they evaluated this no net -- this standard of whether they should use no net harm.

It's a little premature to begin to speculate on what that might do to the schedule.

A lot of it depends on how long it would take them to come up with the decision on whether it's the appropriate standard and then continue, I think, to move forward on whatever procedural schedule they would like to implement.

I should mention though that discovery continues even now, so that process is moving along.

Even if they were to go to a benefit -- a net-benefit approach, haven't you guys mentioned that there are benefits to customers from the combination of the two companies, over time and what have you?

The -- in terms of combining the two companies?

Would it be that much different an impact on your ability to show the merger will be beneficial?

Well, we certainly have indicated that there will be, we believe, significant benefits to the customers of all the jurisdictions, as well as significant benefits to the region.

It's just a different standard, and it would require a different approach during the evaluation process.

Okay, and then is there a renewable?

I thought there was an effort to make sure there was some renewable benefit as well.

Well when I said that the standard should include something that's beneficial to the state, one of the suggestions that was made was that should include the public policy decisions made by the state around renewable energy.

Okay, and then the tax rate for 2012, I think you said it was 35 -- I'm sorry, for 2011 was 35% that you had in your guidance, is that correct?

Yes, Paul.

Is there -- do you see that substantially changing in future years like 2012?

Is there anything driving that number that would go away or something that we should think about?

I'll refrain from too much forward-looking specificity, but I think that may be a number that's kind of reflected for a 2011 and 2012 model.

Beyond that, I can't give a whole lot of visibility ,but that's probably good for the next year or two.

Okay, great.

Thanks.

Thank you, Paul.

Next question is from Chris Basset of Decade.

Chris?

It's actually Reza Hatefi from Decade.

Hello, Reza.

How are you?

Alright.

A couple of quick questions.

I thought when the merger was announced, one of the reasons that was mentioned was this would eliminate the need for equity issuances going forward.

But then earlier, I think you mentioned bonus D&A ,and debt issuances will alleviate equity issuances.

So, I'm confused on what changed -- if anything changed there, or?

Well, on your first point, we absolutely said that one of the benefits of this merger is the use of Nstar cash flow, and that Nstar cash flow would mitigate the need for what we had previously said was a $300 million need in 2012.

That was well understood by all parties and clearly, one of the broader benefits of the transaction.

What I said a few moments ago in the script is that partially offsetting the fact that because of bonus depreciation and rate base declining, it will mitigate some of the cash flow raise or some of the external raise.

And for a company like NU that has been and will be perpetually cash-flow negative, we think it sort of exaggerates the point that there are benefits from not raising capital at the NU parent level in particular, both for debt and equity.

I stopped short of suggesting that, that would completely eliminate a 2012 equity offering.

It could have a bearing on it.

It could push it out a little bit later in life, and those are the things that we continue to analyze.

But there's no question that being there to retain some of that internally generated cash flow is going to reduce our cost of capital in the coming years.

Okay, okay.

And another question, your CAGR, I think you reiterated at 6% to 9%.

Should we still be using 2009 as the base, and where in the CAGR should we -- is it towards the bottom, towards the top, the middle?

How should we think about that?

Well, it's absolutely off of 2009, and you should not expect us to update that on a stand-alone basis.

I think once this Company combines, we'll take our refresh and probably it will be appropriate to move that base.

You shouldn't expect us to be moving that 2009 base in front of that.

In the most recent disclosures that we've made around where in the range, we've said, again, one of the benefits of this transaction of the combined Company is that it will push us towards the high end of that 6% to 9% and again, no change there.

Very, very strong convictions around being there to achieve that level.

Okay, great.

Appreciate it.

Thank you.

Thank you, Reza.

Next question is from Chris Ellinghaus from Wellington.

Chris?

Hello guys, how are you?

Alright.

David, could you just refresh our memory?

I don't recall from the WMECO case what the DPU did to cause that charge, and was that an after-tax number for the fourth quarter?

Yes, that was an after-tax charge, and there were really two things.

One, we had an increase in our reserve around uncollectible expense.

And then there were about $600,000 of actually pre-tax disallowances associated with transaction costs, costs that -- it almost seemed a little funny to us, but costs that didn't necessarily come with an invoice or costs that weren't competitively bid out, that were costs directly associated with putting on the case.

So, those costs were charged off in 2010.

Okay, and it seems, just looking at the transmission earnings, that there's a pretty sizeable below-the-line component to those earnings.

Can you give us any color on what's in there and what's driving it?

And should we expect for 2011 that that number would look similar?

Well, consistent with what we've said in the past is there are a number of below-the-line items outside of the tariff.

They're not all that substantial, except for some tax benefits that we received.

So, we've said that year in and year out.

We've said that those tax benefits are related to credits that we receive in Connecticut, and we've said that those credits are more significant in years in which we're spending a lot of capital in the State of Connecticut, because it's a Connecticut CapEx type of credit.

We stopped short of trying to quantify exactly what that is, but for example, in 2011 where we're spending -- we're really ramping up on the Greater Springfield Project, even though there's spend in Massachusetts, we're spending capital in Connecticut.

Next year we'll spend a good deal of capital in Connecticut, so you should expect that there will continue to be those below-the-line benefits.

But we haven't really gone through a great deal of specificity, Chris, on what that is.

Okay, great.

Thank you very much.

Thank you, Chris.

Next question is from Jack D'Angelo from Catapult.

Jack?

Thank you, my questions have been answered.

Alright.

Thanks, Jack.

Next question is from David Paz from Bank of America.

David?

Hello, actually my questions have been answered as well, thank you.

Okay, thank you very much.

We don't have anymore questions in the queue.

We want to thank you for joining us this afternoon, and if you have any further questions, please give us a call or send us an email.

Thanks a lot.