康涅狄格電力 (ES) 2009 Q2 法說會逐字稿

Good morning, ladies and gentlemen.

Welcome to the Northeast Utilities 2009 Q2 earnings 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 morning, and thank you for joining us this morning.

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; David McHale, NU's Executive Vice President and Chief Financial Officer; and Lee Olivier, NU's Executive Vice President and Chief Operating Officer.

Also with us today is Jay Booth, our new 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 meaning of the Safe Harbor provisions of U.S.

Private Securities Litigation Reform Act of 1995.

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

Some of the factors are set forth in the press release issued yesterday announcing our earnings for the second quarter of 2009.

If you have not yet 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, 2008, and our Form 10-Q for the first quarter of 2009.

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.

Thank you, Jeff.

I'd like to thank everyone for joining us on this busy earnings reporting day.

I'd like to begin by saying that we were pleased with our financial results in the second quarter.

While some of the improvement from last year was due to the timing of the resolution of several routine tax issues, we did have underlying earnings growth, as our customers and our shareholders continue to benefit from the regional energy infrastructure investments we have made in recent years.

But the economic conditions that continue to impact our country and our region are also having an impact on us.

While the June unemployment rates of 8% in Connecticut and 6.8% in New Hampshire our below the 9.5% national average, our distribution companies continue to feel the impact of this recession.

Electric sales adjusted for weather are down 2.8% for the year, better than some parts of the country but about twice the percentage decline we had anticipated.

Also, as David will discuss, uncollectible expenses are rising somewhat faster than we had anticipated.

The showdown is clearly pressuring our distribution segment fundamentals and returns.

None of our distribution companies are earning its authorized regulatory return on equity, so it probably did not surprise many of you when we lowered our 2009 distribution segment earnings guidance.

Our distribution segment outlook would have been weaker, had we not begun taking significant steps almost a year ago to reduce our costs as we saw the economy continue to weaken.

We have already reduced hiring, implemented programs to reduce distribution capital expenditures, and have reduced operations expense across the corporation.

In addition, we froze salaries for the Company's management for 2009.

We plan to continue to identify and implement measures to reduce our costs in ways that do not have a near-term impact on the service we provide our customers.

The cost reductions cannot completely offset the impact of the economy, and the impact of the investments we must continue to make to provide long-term safe, reliable electric service.

As you know we currently have a distribution rate case pending with Public Service of New Hampshire, and in fact we were just granted rates effective August 1.

We still expect to file a CL&P rate case later this year or earlier in 2010 and a WMECO rate case in mid-2010.

While we understand the impact any increase in rates has on our customers, we believe these filings are necessary if we are to continue to provide the service levels our customers require, and provide a fair return to our shareholders for their investment in our distribution businesses.

But for our regulators to allow us to earn those returns, we know that we need to continue to provide value to our customers.

In addition to maintaining a reliable energy delivery system, we understand that regulators and legislators also look to us to provide innovative solutions for the region's energy challenges.

The Hydro-Quebec initiative we are proposing with NSTAR is one such solution.

In 2014 we expect this project to begin importing 1,200 megawatts of low carbon hydropower into New England, along a high-voltage direct current transmission that we want to build between the Canadian border and central or southern New Hampshire.

Lee will provide you with an update on the progress we have made over the past three months in bringing this project to fruition; but I want to be clear that this project could have multiple and wide-ranging benefits for the region's customers, including a meaningful reduction in New England's carbon footprint.

Other projects, such as our Solar initiative in Massachusetts, also will be needed to meet regional greenhouse gas initiatives, as well as New England's renewables requirements.

As we move forward, we expect to speak regularly with you about how we will unlock the development of thousands of megawatts of renewable power that can be built in New England and delivered to the load pockets of the region.

In addition to increasing supply, we also continue to focus on initiatives that can help our customers use power more efficiently.

Our three-month advance metering infrastructure rate pilot in Connecticut will end August 31st, and that is one such initiative.

By December 1st we will file a report on our nearly 3,000 customers' responses to the pilot, and make recommendations on how we should advance AMI in Connecticut.

The current pilot will help us learn how to best employ that technology, if our regulators give us the approval to expand its use.

I'm sure many of you are aware of the Federal stimulus programs related to electric infrastructure, and how we plan to participate.

Earlier this quarter we applied to the DOE for a grant to help develop the initial investments required to build an electric vehicle charging network in our Connecticut and Massachusetts service territories.

We are hoping to get a positive response from the DOE on that application soon.

We have also joined with Ford and several other parties to support DOE grant applications for consumer education, test electric vehicle demonstrations, and initial market rollout of electric vehicles.

These represent relatively small, but important, steps toward making New England plug-in vehicle ready.

Tomorrow, however, we will be submitting to the DOE an application for matching funds to help offset the development of nearly $250 million of smart grid technologies in Connecticut, Massachusetts and New Hampshire.

This program will build on our existing AMI pilot efforts in Connecticut, integrate with the development of electric vehicle charging infrastructure, and bring smart metering benefits to over 200,000 customers over the next three years.

In addition, it will develop critical distribution and communications infrastructure that can be expanded for broader development of AMI and in-home demand response technologies.

Assuming the DOE grants our application, we will then work with our state regulators on developing rate treatment and approvals influenced by our ongoing pilot.

We believe we have developed a very competitive application, and are optimistic that the DOE will grant our application with matching funds, and that the States will support this deployment.

At our State capitals, unlike last year, there was very little new legislation that passed in Connecticut, Massachusetts, or New Hampshire this spring that affected utilities.

Nevertheless, there is still a considerable amount of momentum to reduce the region's carbon footprint.

We estimate that the Hydro-Quebec line could reduce New England's CO2 emissions by 4 million to 6 million tons annually.

We also believe that significant annual reductions in carbon emissions are possible by replacing the use of oil with electricity or natural gas.

Enormous potential exists in transforming the region's transportation and heating sectors.

As I mentioned, we also believe New England could become a very good market for electric vehicles once the next generation becomes widely available.

If, for example, 10% of the vehicles in New England were plug-in electric vehicles, we could potentially reduce greenhouse gas emissions by another 4 million to 6 million tons.

We also believe that there is significant potential in the region, based on today's prices and environmental awareness, to convert a significant portion of the region's oil furnaces to natural gas.

A 10% increase in the number of homes heated by natural gas could reduce greenhouse gas emissions by another 1 million to 2 million tons.

For homes heated with fuel that can be converted to electric heat pumps, we could save 2 million to 3 million tons.

We are also pleased with the settlement that WMECO reached with the Massachusetts Attorney General which, if approved by regulators, will allow us to begin construction of up to 6 megawatts of solar generation in Massachusetts, representing an investment of approximately $40 million.

This solar investment, the Hydro-Quebec project, future initiatives around new, renewable generation, electric vehicles, and the electrification of the region, all represent what we see as a widening in our investment focus.

Our southwest Connecticut and NU's transmission projects are needed for reliability, and to remove significant bottlenecks in the region's grid.

The Merrimack scrubber is needed to meet New Hampshire's air emission standards.

But we believe more of our investments in the future will be made to address State and Federal policies that require the development of new facilities to meet the energy and environmental needs of our region.

As we move forward, we will continue to update you on these efforts.

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

Thank you, Chuck.

The second quarter of 2009 was a strong one for us.

Distribution and transmission reliability was significantly better than target our New Hampshire -- better than target, and our New Hampshire generation facilities performed well, exceeding our capacity and availability goals.

Construction has accelerated on our $457 million Merrimack clean air project, and is now about 15% complete.

We have poured the major foundations for the chimney, absorber and flue gas condition system.

The chimney concrete shell is now complete, and we are now finishing the installation of project construction buildings.

In September we will begin installing the fiberglass chimney liner, and start constructing the scrubber absorber facility.

We expect the project will be 33% complete by the end of this year.

In early July, despite the urging of the number of intervenors, the New Hampshire Site Evaluation Committee concluded that it did not need to review the project because we were not increasing the planned electrical output.

Earlier this morning, the New Hampshire Supreme Court ruled on a challenge to the New Hampshire PUC ruling from last year that the Commission does not have the obligation to review the scrubber under a public interest standard, since the New Hampshire legislature already determined that the scrubber was necessary and needed.

The Supreme Court dismissed the appeal, stating that the appellants were not harmed by the New Hampshire PUC decision, and thus lacked standing to bring the appeal.

The scrubber will remove about 80% of the mercury emissions and about 90% of the sulfur emissions from Merrimack's two coal-fired units.

We now believe the scrubber will be complete by mid-2012, about a year before its legislative deadline.

This will benefit customers by reducing the cost of the project, providing environmental benefits sooner, and lowering the number of SO2 allowances that PS&H will need to acquire.

As to the scrubber's cost, we continue to believe it will come in at or below budget.

We have now started to see the decline in commodity costs being reflected in bids we have received certain project opponents.

This is particularly true for steel and cement.

In the first half of 2009 our total capital expenditures across all of our business segments were $415 million, including $43 million on the clean air project.

We expect that by the end of 2009, total spending on the project will be about $145 million.

Transmission spending totalled $128 million in the first half of 2009, as we continued to work on a number of projects.

Due to the change in the timing of our investments, we now expect to exceed our previous estimated 2009 transmission capital budget of about $225 million by at least $50 million; for a total transmission spend of approximately $275 million.

We expect our next major initiative to be the $714 million Greater Springfield Reliability Project; the largest part of the New England East-West Solutions family of projects we are building with National Grid.

In the second quarter we completed public hearings on the Greater Springfield Reliability Project, and we will start -- evidentiary hearings commenced in Connecticut two weeks ago, and they are scheduled to begin in Massachusetts in October.

ISO New England has re-affirmed the timely need for this project.

Assuming we receive signing approval in both Connecticut and Massachusetts in the first half of 2010, we expect to commence construction in either late 2010 or early 2011, and complete the project by the end of 2013.

We expect to file in Connecticut for approval of the Interstate Reliability Project late this year or early 2010.

This is the project that will Connecticut our 345KB system into a similar project National Grid is building in Rhode Island.

We plan to file for approval of the third project, the Central Connecticut Reliability Project, later in 2010.

Transmission capital spending is driven by a number of factors, including the reliability requirements of the North American Electrical Reliability Corporation, and peak load growth.

Later this year ISO New England will update its regional system plan, and update its projections on its estimated year-of-need for various transmission projects around the region, including the Interstate and Central Connecticut Reliability Projects.

As I mentioned earlier, ISO has already indicated that it will make no change to the Greater Springfield Reliability Project year-of-need.

Turning from news to the Hydro-Quebec project we are seeking to develop with NSTAR, we cleared a major regulatory hurdle in May when we secured the endorsement for a particular type of transmission services agreement.

Under that agreement, Hydro-Quebec would have exclusive or near-exclusive rights to import power across the line, in return for being responsible for all support payments for the line.

In other words, unlike the liability projects in New England, the owners of this transmission line would receive all of their revenues from those who move power across the line, rather than from all New England electric customers.

On May 22nd, FERC approved the declaratory order on the petition that we and NSTAR filed.

This approval was very important, since Hydro-Quebec hopes to sign power sales contracts with New England utilities that are likely to extend for 20 years or more.

And Hydro-Quebec needs a guaranteed transmission pathway to deliver that power.

Its unanimous approval included very supportive comments by all commissioners.

Now the ball is back in our court.

In addition to negotiating the actual transmission services agreement under which we would create a cost of service [work-approved tariff] we are negotiating the power purchase agreement with Hydro-Quebec.

The prices under those agreements will need to be sufficiently competitive to convince state regulators that HQ's nearly carbon-free energy source is an attractive long-term option for our customers.

We and NSTAR hope to bring these power purchase agreements before our regulators by the end of this year or early 2010.

We will also provide other utilities in New England with the opportunity to participate in the purchase of HQ power under similar terms and conditions.

We hope that in the second half of 2010, State regulators will begin approving these contracts, and that we can begin the process of securing siting approval for the line from New Hampshire regulators next year.

If the project can keep -- can be kept to our preferred timeline, construction would begin by the end of 2011 and be completed in time to allow power to begin flowing in 2014.

Turning to our distribution capital expenditures, in the first half of this year distribution capital spending amounted to $220 million; $196 million on our three electric distribution companies and $24 million on natural gas.

We project $492 million of electric and natural gas distribution capital expenditures in 2009, but our projections for the near-term years may decline due to a couple of factors.

The first is that lower economic growth and increased conservation [advancement] may well temper the peak load growth that drives a considerable amount of work on our individual distribution service.

The amount we spent on new electric services in the first half of 2009 was about 17% below the first half of 2008.

Additionally, as part of our efforts to keep our customers' costs as low as possible, we have accepted the recommendations from an internal task force that has identified a number of strategies that together have the potential to reduce our electric distribution capital spending.

We now believe we can reduce the capital spending by at least $200 million over the next five years.

As Chuck noted, we also continue to focus intensively on managing our operating expenses.

Operations expense incurred directly by the four distribution companies was down 4% in the first half of 2009, compared with the same period of 2008.

This has been driven by fewer major storms, and cost savings initiatives applying to overtime, contractors, hiring and supplies.

We have reduced planned and unplanned overtime by more than 128,000 hours when compared to the same time period last year, and we have done this through enhanced controls.

We have scaled back our vendor contracts by about 50%.

Although we added 28 positions directly related to customer service, we have held over a significant amount of other positions across the Company.

We have instituted enhanced procedures to control labor and on-call expenses.

On the natural gas side, the dynamic is quite different.

A significant majority of Connecticut's homes and businesses heat with oil, but natural gas has a significant cost advantage over oil today.

As a result, Yankee Gas continues to see a significant interest in convergence of heating systems from oil to natural gas.

Between 2007 and 2009, the number of conversions rose from 150 to 750.

This year the number is tracking close to 1,000, which is not an insignificant level for a company with just over 200,000 customers.

That factor combined with increased installations of natural gas by distributor generation, and cooler weather, has driven an 8.8% increase in Yankee Gas [firm] sales in the first half of 2009 as compared with 2008.

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

Thank you, Lee.

As Chuck mentioned, we are pretty pleased with our performance in both the second quarter and first half of 2009.

We earned $82.9 million or $0.47 per share in the second quarter of this year.

Quarterly earnings were up by 43% from last year.

Earnings per share, including the impact of our March share issuance, were up by 27%.

In the first half of 2009, we earned $180.5 million or $1.07 per share.

Excluding the impact of last year's litigation charge, first half earnings were up by 24% and earnings per share were up by 14%.

Second quarter regulated earnings rose to $80 million in '09 from $60.8 million in 2008, up by about 32%, and first half regulated earnings rose to $174.6 million in '09 from $147.1 million in 2008, up nearly 19%.

Second quarter competitive results rose to $5.5 million in '09 from $2.2 million last year.

First half competitive earnings rose to $11.3 million in '09 from $4.1 million in 2008.

Second quarter transmission earnings rose to $41.8 million in 2009 from $35.2 million last year, an increase of 19%.

In the first half, transmission earnings rose to $77.2 million in 2009 from $67.7 million in 2008, an increase of 14%.

These increases are primarily the result of having more rate base on which we are earning.

As Lee mentioned earlier, we are now projecting higher transmission capital expenditures in 2009.

This factor gives us confidence that we will earn around $0.90 per share in this segment this year, at the high end of our previous range, which was $0.85 to $0.90.

Our distribution and generation segment earned $38.2 million in the second quarter of 2009, up nearly 50% from the $25.6 million we earned in the same quarter of 2008.

However, approximately $8.2 million of the second quarter earnings was attributable to the favorable resolution of several routine tax issues, which is certainly not representative of what we expect to unfold in the second half of this year.

In fact, across all our businesses, earnings in the quarter benefited by $11.1 million as a result of resolving various tax issues.

From an income statement standpoint, about $5 million of that value was recorded in taxes other than income taxes.

Another $5 million was recorded as an offset to interest expense, and about $1 million directly to income taxes.

The segment earned $97.4 million in the first half of 2009, up 22% from the $79.4 million we earned in the first half of 2008.

CL&P's distribution segment earned $21.9 million in the second quarter of '09, and $43.6 million in the first half of '09; compared with $14.8 million in the second quarter of last year, and $33.7 million in the first half of 2008.

In addition to distribution rate increases of $78 million annually that was effective February 1st, 2008, and another 20 million annually that was affected February 1st of this year, CL&P's distribution was helped by the resolution of the tax issues previously mentioned and lower O&M.

In the second quarter, about $3.3 million of that improvement was due to less storm activity, and another $4 million from other reductions in O&M this year, compared with the second quarter of last year.

That was partially offset by $2.8 million in higher after tax quarterly pension costs.

Despite this improvement in earnings, CL&P's distribution regulatory return on equity was only 7.7% for the 12 months ended ended June 30, '09, compared with our allowed of 9.4%.

We continue to project and earned ROE of about 7% for CL&P's distribution business for the calendar year 2009.

One factor that we expect to weigh on returns in the second half of this year is on collectible expense.

Across all of Northeast Utilities, we now project uncollectible expense that reflects earnings to be in the area of $35 million, up from $27 million in 2008, and up from the $30 million we had anticipated at the beginning of this year.

Most of that $5 million increase is projected to be at CL&P, and current economic conditions are clearly the driving factor.

Sales declines and rising uncollectible expense are two of the several primary reasons why, Chuck noted earlier, that we will need to file a distribution rate case later this year or early in 2010.

On June 29th we had a unique opportunity to discuss with the Connecticut DPUC in an open, non-contested session, the current state of the capital markets and its impact on our cost of capital.

DPUC Commissioners, hosted by the new Chairman, Kevin [Gadabo] and staff, as well as the Office of the Connecticut Attorney General and the Consumer Council, were able to discuss our capital investment needs in a session that did not have the formality or tension of a rate case.

We found the session to be a very open give and take regarding our five-year of capital investments that we need to make to address our customers' needs, and the aging of our electric infrastructure, and our view the need and costs of external financial capital over the coming years.

It is our hope that informational sessions of this sort will enhance the Commission's understanding of our expertise -- excuse me, of our experiences in the financial market, the need to earn a fair and reasonable return, and equally our understanding of their views on these matters.

Turning back to PS&H, their distribution and generation segment earned $11.9 in the second quarter of '09 and $25.4 million in the first half of 2009, compared with earnings of $10.1 million in the second quarter of 2008 and $21.6 million in the first half of 2008.

Overall, this segment has a trailing 12-month ROE of 8%, but our returns are very different from the generation side and distribution side of the business.

Our generation business is fully tracking, with an authorized ROE of 9.81%, and earnings there continue to grow as we invest in the business, including for the Merrimack scrubber projects.

On the distribution side, however, our ROE was down to about 5% for the 12 months ended June 30, 2009.

The low distribution return is due to a combination of our continued investment in the distribution system, sales declines and increasing costs, such as pension expense, depreciation and property tax.

They underscore PS&H's need for distribution rate relief.

On June 30, PS&H filed a request for the New Hampshire PUC to permanently raise annualized distribution rates by $51 million effective August 1, 2009, and by another $17 million effective July 1, 2010.

Testimony is available for you on our Investor section of the website.

Fortunately, New Hampshire regulators have the authority to permit temporary rate relief while an application to raise rates on a permanent basis is pending.

On August 1st, PS&H increased its distribution rates by $25.6 million on an annualized basis as a result of NHPUC's approval of a settlement of temporary rate application reached in July with the Commission staff.

Of that sum, $6 million will begin the recovery, and about $48 million of currently deferred costs associated with the restoration of service to hundreds of thousands of PS&H's customers who lost power in December, due to a devastating ice storm.

Because those dollars will help us work down a deferred balance and help cash flow, they will not affect earnings.

The remaining $19.6 million of temporary increase will begin the process of reversing the steady decrease that we have seen in PS&H's distribution ROE.

When the permanent case is decided in the first half of next year, that decision will be retroactive to August 1st of this year.

If our permanent rate increase is higher, we will be able to recover some revenues retroactively.

If it is lower, we will need to refund back to customers some of the dollars we will connect now between mid-2010, when we return a permanent rate case decision to be reflected in customer bills.

We are requesting the additional $17 million effective July 1st, 2010 to reflect the continued investment we expect to make in PS&H's system over the next couple of years.

Fortunately, the back drop to this case is one of declining commodity costs.

On August 1st, we had multiple changes in PS&H's bill components.

Distribution, transmission and straight across recovery components within PS&H bills all rose, but they were more than offset by the annualized decrease of more than $70 million in PS&H's energy service rates.

As a result, overall PS&H bills declined about 1% on August 1.

By the way there is regulatory precedent for this type of timetable.

In mid-2006, New Hampshire regulators allowed us to implement a temporary distribution rate increase for about one year while our request for a permanent increase was pending.

When regulators approved the settlement of the permanent case, we were able to recoup about $9 million of revenue that had not been collected from customers between July of 2006, when temporary rates took effect.

So July 1st, 2007, the permanent decision was reflected in the bills.

Turning back to the second quarter, Western Mass Electric's distribution segment earned $3.8 million in the second quarter of '09 and $8.6 million in the first half of 2009, compared with $1.7 million in the second quarter of '08 and $6.5 million in the first half of 2008.

Nearly half of that improvement was due to the absence of charges this year, and in the second quarter of 2008 Western Mass recorded a $1 million after tax charge associated with a regulatory decision involving the carrying costs on certain over-recoveries.

In the second quarter of 2009, Western Mass also benefited from less storm damage, lower O&M and the resolution of tax issues.

This offset a 10.4% reduction in retail sales, 7.4% on a weather-adjusted basis.

For the 12 months ended June 30, 2009, WMECO's distribution regulatory ROE was 7.7%, and we expect it to remain in that area for the full year 2009.

There is no question that WMECO's service territory, which is the least affluent of all our utility service territories, has been impacted most severely by the economic downturn.

For the sixth months of the year, WMECO's retail sales were off 6.6%, compared with 3.3% for CL&P and 3.8% for PS&H.

On a weather-normalized basis, WMECO's sales were off 5.8%, compared with 2.3% for CL&P and 2.9% for PS&H.

Across all three electric operating companies, industrial sales have dropped the most.

They were off about 15.7%, while commercial sales were off 3.5%.

Residential sales remained stronger, up .1% on an actual basis and up .9% on a weather-adjusted basis.

The rate design for our commercial and industrial customers through which we collect the vast majority of our distribution revenues through non-volumetric charges mitigated some of the negative impact on our results.

For the first half of the year, as Chuck mentioned, the weather normalized decline of 2.8% in retail electric sales was greater than the 1.2% decline we had anticipated.

But because that decline has been concentrated in the industrial and commercial sectors, and they do not impact our transmission and generation earnings, the impact of this economic weakness has been somewhat muted.

Additionally, CL&P and WMECO recover about two-thirds of their distribution revenue through fixed charges, so they are partially buffered from the impact of sales declines.

For PS&H, about half of its distribution revenue comes through fixed charges, and for Yankee Gas it is about 45%.

Fortunately, Yankee Gas sales have been far stronger than the electric companies.

Declining natural gas prices, the increase in natural gas-fired distribution and -- distributed generation, and increases in conversions away from heating oil, as Lee mentioned, and cooler weather have resulted in an 8.8% increase in firm sales in the first six months of this year, with actual increases of 3.2% among residential customers, 10.4% among commercial, and 13.4% among industrial customers.

Overall, sales were up 4.5%, weather-adjusted, in the first six months of this year.

Those sales gains have benefited Yankee Gas's financial performance.

In the second quarter Yankee Gas earned $600,000, compared with a $1 million loss in the second quarter of '08.

The first half of this year, Yankee has earned $19.8 million compared with $17.6 million of earnings in the first half of 2008.

Yankee Gas's sales increases have helped it offset higher operating and interest costs.

Also helping the comparison this year is the absence of a significant charge; in the second quarter of 2008, Yankee Gas recorded an after tax charge of $3.5 million as a result of a negative regulatory decision associated with purchased gas recoveries.

For the 12 months ended June 30, '09, Yankee's regulatory ROE was 8.1%, compared with its allowed of 10.1% We expect its 2009 full-year ROE to be about 8%.

Some of these projected ROEs are somewhat below what we had expected when we announce segment earnings guidance last November.

Again, while we have done well on holding down costs, electric sales are below our expectations due to weather and the economy.

With the mild weather we experienced in July, we do not at this time project our sales will recover in the second half of this year.

When combined with the impact of our March share issuance, we now expect our distribution segment earnings to be between $0.90 and $1 per share, rather than the $1 to $1.10 range we had predicted earlier.

Our competitive businesses earned $5.5 million in the second quarter of '09, and $11.3 million in the first half of '09, compared with $2.2 million in '08 and $4.1 million for the first half of '08.

We now project earnings of about $0.05 per share in this business, compared with our original estimate of between zero and $0.05 per share.

At the parent and at the Company level, we had net expense of $2.6 million in the second quarter and $5.4 million in the first half of 2009, compared with net expense of $5.2 million in the second quarter of '08 and $35 million in the first half of '08, including the first quarter of '08 litigation charge.

We continue to project net expenses of about $0.05 per share in this segment, as interest on cash raised during our March 2009 equity issuance partially offset the expense interest on our parent's long-term debt issuance.

Overall, we expect to earn between $1.80 and $1.90 per share in 2009.

This is consistent with our guidance from last quarter, when we told you that we projected earnings on the low end of $1.80 to $2.00 per share.

As the news release noted, all segments are on or at the high end of our targets, except for distribution.

With half of the year now behind us, continued challenging economic conditions and a mild month of July, we expect retail electric sales to come in below the 1% to 2% decline we had forecasted earlier this year.

We expect these factors to weigh most heavily of CL&P's distribution segment, whereas I mentioned earlier we expect our regulatory ROE to slip from about 7.7% for the 12 months ended June to about 7% of the full year '09.

Key factor that could further affect our '09 guidance are storms, uncollectible expense and sales.

Before turning the call back to Jeff, I will touch briefly on a couple of cash flow items.

Net cash flow from operations after rate reduction bonds totalled $385 million in the first half of this year, compared with about $167 million in the first half of last year.

Part of that was due to $50 million payment -- a $50 million payment we made in the first quarter of 2008 to settle outstanding litigation.

But higher net income in our regulated segments, lower regulatory refunds and the full reflection in rates of our southwest Connecticut transmission projects also have had significant impacts.

We now project operating cash flows of about $580 million in 2009, after rate reduction bond payments of $244 million.

That's about $80 million higher than the $500 million level we had projected in the spring.

The change is due primarily to fully reflecting the expected impact of stimulus legislation on the amount of bonus depreciation we can claim on our Federal returns.

Cash capital expenditures totaled $420 million in the first half of '09, compared with about $625 million in the same period of 2008.

With lower capital expenditures and stronger cash flows, our cash balances totaled nearly $500 million at the end of June and remain there today.

That $500 million is largely a result of getting in front of our financing needs, and raising debt and equity proceeds earlier in the year.

We do not yet have a new cash flow projection for 2010, but we have had some changes in our projected pension funding obligations for next year.

New IRS guidelines at [forward] companies with defined benefit plans, there's some additional flexibility in estimating their liabilities, including the use of different interest rates to develop discount rates to determining the plan's underlying liabilities.

Because of that guidance, we now estimate that we will need to contribute approximately $50 million into our pension plan in 2010.

That is considerably less than the $300 million to $350 million we had estimated earlier this year.

We continue to project modest long-term debt issuance over the next few quarters.

Our application to issue $150 million of bonds at PS&H is still pending before the New Hampshire regulators, and we now expect to issue that debt in the fourth quarter.

You may have noticed that on Monday Moody's raised by one notch the secured debt of both PS&H and CL&P, as well as a number of other utilities, as part of a general review of utility secured debt.

On July 2nd, we filed an application with Massachusetts regulators to issue up to $150 million of long-term debt at Western Mass Electric, most likely in the first half of 2010.

Let me turn the call back over to Jeff.

Now I will turn the call back to the operator, so he can instruct you on how to enter any questions.

(Operator Instructions).

I will now turn it back over to Mr.

Kotkin to take questions.

Thank you very much.

Our first question today is from Andy Levy from Incremental Capital.

Andy, good morning.

Jeff, how are you?

Good.

As you look into 2010, can you just talk about some of the positives and negatives to think about?

Because I know you haven't given guidance yet, but just to get closer to next year, what are some of the things we should be adding and subtracting to our 2009 earnings?

This is David.

I think a couple of things in terms of those that will determine kind of directional earnings.

I think clearly the outcome of the PS&H rate case.

We have got new revenues from the temporary case.

The $25 million that we talked about earlier that will help the first half of the year, but we also will have the resolution of the full case.

So that will be an important item to watch.

You know that -- we have asked for a return of 10.5% on the underlying equity of that company.

Second, we touched on this in our opening remarks, the rate case at Connecticut, the timing of the filing, the timing of an outcome, and certainly the returns that we seek in that State we expect to drive some of the 2010 results.

Also AFUDC earnings on our continued scrubber investment in the Merrimack plant will help drive for 2010 continued rate base growth on the transmission side; although not quite as aggressive as we have seen in the last couple of years, it will continue to work its way through the process.

In terms of O&M, that is something that we continue to watch and study pretty closely.

We have been successful in 2009.

I think some of that success is sustainable.

I think some of it we need to continue to look at it.

We probably can't project being under on storm expense forever, but that's something I think we've been very diligent about, and quite rigorous in 2009.

Some headwinds to watch as well.

I'm not sure we expect to see any major rebound in the economy, so I'm not sure that we'd be expecting sales growth.

That's something that we'll continue to watch and continue to study, but our long-term views there are kind of flat to maybe even declining.

We will refresh these views.

On uncollectible expense, that's something we will watch, too.

You know that we have -- the majority of those costs that are tracked, either through hardship or through the generation rate, but they have in effect nickeled and dimed us, so that's something that we'll continue to watch as well.

So there's a handful of things for you to put into your analysis.

Okay, great.

Now, have you stated in the past what your growth rate was going to be longer term?

What we've stated is, we have been fairly consistent about this view, if you think about 2007 being a base year, our long-term, sort of 5-ish year growth rate is 8% to 11%, and we signaled earlier this year that we would be at the lower end of that side.

You still feel comfortable with that for 2010?

Yes, I think as a long-term growth rate, so mathematically it is point to point, where we land in 2010 will be articulated when we give guidance.

Okay.

When will that be?

We typically do it at the November EEI Conference.

November EEI.

Then one last question, and I'll let somebody else go.

You had mentioned something in the beginning, and I actually saw it in the release, there was a tax gain or something.

I think it was small, but could you just go over that and how much that was?

We had the resolution of a number of both State, Federal, income tax, sales and use tax audits in the normal course of business.

Actually, in the quarter it produced an after tax benefit of $11.1 million.

After tax.

Thank you.

Thank you, Andy.

Our next question is from Paul Patterson from Glenrock.

Paul?

Hi, can you hear me?

Yes.

I wanted to ask you guys about a couple of things.

First of all, the timing of the Connecticut case, looks like ROEs are low and stuff.

Just wondering why not file it sooner rather than later, if you know what I mean, or what is the thought process that goes in terms of the timing of filing a case?

Paul, this is Chuck.

I think it is the same thought process we have discussed with you in the past.

We look at the economy.

We look at a variety of factors, and try to make the best decision we can as to when it is appropriate to file a rate case.

As you know, we had originally thought we would be filing one earlier this year, about the middle of this year.

We made the decision not to do that and now are, and have been for a while, indicating that we expect to file a CL&P rate case by the end of this year or very early part of next year.

Just refresh my memory in terms of the timing in Connecticut in terms of when that would be.

If you started let's say January 1, how many months would it be before we get a final decision, assuming it is not --

It is typically a six-month process, although sometimes the process extends for another month.

But if we file January 1, you could expect to see something toward the middle part of the year.

Okay.

In terms -- and I apologize about this, but the WMECO ROE and the PS&H ROE as of June 30, 2009?

I didn't get those, I'm sorry.

The PS&H ROE, the combination of distribution and its generation business is about 8%.

If you kind of strip away the generation, which is earning a tracking 9.81%, It is closer to 5%; hence the need for some rate relief.

That doesn't take into account what will unfold over the balance of the year, because we have temporary rates that will definitely help support that going forward.

And for WMECO, I think we say we are in the 7.7% area.

Okay.

And with WMECO, what's the -- I apologize.

What was the rate case plan there?

We had said -- actually last year, we had indicated to the PUC in Massachusetts that we would be filing mid-year-ish 2010.

So that case is on the horizon as well.

Okay.

And then just finally, the industrial sales and the fixed charges, if we don't see you rebound, is there a potential that those fixed charges will decrease?

In some jurisdictions, we found that there is sort of a delay factor.

In other words, if the plant hasn't been operating for some time, you sometimes see a fixed charge go down; and I'm just wondering how that rate design works, if we don't see the rebound in industrial usage?

Well, I will give you some comfort.

It varies amongst State, but if you look at CL&P in particular, right now 97% of their revenue requirement that is collected through the industrial segment is collected through customer charge and demand charges.

Only 3% is volumetric.

And that is addressed in each rate case, where rate design is taken up.

But I think that's a pretty good answer for us at this point, is that it varies for the other States but is generally 90%, even in New Hampshire, it could be two-thirds in Massachusetts.

I think that's working -- you could argue that from Connecticut, the regulator's standpoint, that is one form of decoupling.

So unless the business actually goes under, assuming that they want to have access to electricity, they also have to pay that rate, right?

That's right.

So they pay their customer charge.

Not only do they pay the demand charge, but on many of these customers there is also something called a [doing a ratchet], so it is not as though they are playing demand on that one peak month and they can walk away with subsequently lower demand charges; they have to pay relative to their peak charge.

So your point is right.

Unless they kind of walk off the system, we have revenue -- fairly predictable revenue coming in from those customers.

This could be a theme.

You will see big decreases in unit sales, but from a revenue standpoint it is not that impactive.

Okay.

The ratchet doesn't go down over time?

I think it is like a 12-month rolling ratchet, so eventually if they are reducing their peak usage, we will feel the effect of it.

But it will be 12 months or so?

I believe that's the case for most of the customers.

Okay.

Thanks a lot.

Thank you, Paul.

Next question is from Steve Fleischman from Catapult.

Steve?

A couple of questions.

First, you guys mentioned that in New Hampshire, the base rate increase -- interim increase was pretty much more than offset by supply cost reductions.

I'm wondering if you could give us some sense of the dynamic in Connecticut and Massachusetts with respect to potential supply cost reductions over the next year, given where market prices are?

Sure.

This is David.

I think at this point -- this is public information.

Generally speaking, almost entirely we have all of our 2009 energy requirements secured for our Connecticut load, our standard service load.

We have got about 80% for 2010 and we have got about 30% hedged for 2011, so we have got pretty good visibility for what will happen in 2010.

And to give you an example, residential customers are paying about $0.12 a kilowatt hour now by way of standard service.

When we look at the 2010 based on what we have hedged, we have some comfort that those rates should go down.

We will probably procure the balance in the fall, and then when we look where the forward curves are and what we have hedged for 2011, there is still a trend down.

Now, prices have been very volatile.

We have seen some creep back up in the back end of the curve in the last couple of weeks, but we think around the energy component there is going to be some headroom.

Lee mentioned this earlier, maybe Chuck, we also know that by the end of 2010 there is basically the maturity of our 10-year rate reduction bonds that were issued a decade ago, and that's almost worth $0.01.

So when you look at those two items, both energy and the rate reduction bond piece, you have an ability to manage customer bills, even within some upward pressure on both distribution and transmission.

I mean, maybe thinking about it more broadly, is it possible that you could get your utilities up to earning returns like the rest of the country, without any meaningful rate increases overall, given these other factors?

Well, let me answer your question in a vacuum.

Mathematically, it is possible to earn a fair and reasonable return on all of our businesses and have bills actually decline.

Okay.

And secondly on the pension that you mentioned, you are now -- you had thought you were going to need to fund $350 million in '10 and now it is only $50 million?

Yes.

Does that have any impact on -- I think you talked about maybe issuing equity in 2011.

Is that maybe going to push that out, or do you still think you will still be an issuer in 2011?

Well, before the pension issue was something that we were articulating as an incremental cash need, so let's think about this fall of 2008 EEI timeframe, we were looking forward into 2011 saying we stayed the course on our capital investment plan we'd need equity in 2011.

I think to the extent that there is cash needed for these pension plans, that will put additional pressure on financing plans for sure.

One thing I will caution you, and this is I'm sure not unique to Northeast Utilities or our industry, as parties that petition either Congress or the IRS, et cetera, and there are changes to these funding rules, and minimum contribution and minimum funding levels, these numbers are going to bounce around.

I think what the IRS has done recently this spring is given us some underlying flexibility in the way that we assess the liability, and that's really the difference in terms of the way we think about money to go into the pension plan.

It could change directionally in the future, depending on how successful some of these efforts are.

Okay.

I think all else being equal, it probably will require a little bit more financial capital.

Now, what's nice, of course, is those numbers are tax deductible, just spread all across our businesses.

Those also have been traditional revenue requirements, although of course we have to manage the assets well and have a competitive plan.

That will -- bottom line, it is not going to have a meaningful impact on 2011 at this point.

Deeper into the forecast, deeper into the next three to five years, depending on market performance, it might.

Thank you.

Thank you, Steve.

Our next question is from Maury May from Power Insights.

Maury?

Good morning, folks.

Good morning.

Just focusing in for a moment on the Hydro-Quebec DC line, why would regulators not approve a PPA, now that the issue of -- the costs would not be socialized across ISO New England, why would regulators not approve a PPA for a utility with with Hydro-Quebec's low carbon power?

Maury, this is chuck.

In the discussions that we have had with all the regulators in at least the States in which we operate, the overriding comment that we get back is that they want to make sure that if they approve a long-term PPA, the structure is such that it will never harm the customer.

In fact, they are looking for a benefit to the customer.

So the overriding question is, can we create a PPA structure that provides benefits to the customers over the long-term?

I think that's going to be probably the single largest determinant in the regulator's decision to approve or not approve that.

Now when you say "benefits," do you mean price of the contract?

Because structure does not Imply the structure --the cost?

Well, I think benefits can cover a wide range of things, and it depends to a large degree on how those commissions evaluate it.

Clearly the price relative to a market price is a critical component of that.

The structure of that PPA could be a critical component of that.

The impact -- or the impact in which they are willing to attribute to environmental benefits could be another piece of it.

So there is a variety of considerations I think that the regulators will evaluate.

We have not been very specific about it has to be a particular price, but I think when you take a look at all the benefits combined, it clearly has to be beneficial to the customer.

Okay.

And these PPAs, who would they be with?

I mean, clearly Northeast Utilities has three operating electric companies, and NSTAR has a couple of them.

Would these contracts primarily be with the two of you?

I think the expectation is the contracts would be between Hydro-Quebec, which is the marketing arm of Hydro-Quebec in the United States, and the individual utilities that want to buy the power.

Okay, but your utilities and NSATR's utilities would probably be fine candidates there, wouldn't they?

Well, we would certainly hope so.

The whole idea is to create a PPA structure that we and NSTAR feel comfortable taking to our regulators for our operating companies.

Okay.

And my second question really follows up on Andy's first question.

Peering into -- if you could just extrapolate a little bit and peer into 2011 on the positives and negatives, I would appreciate that.

You're asking a great deal here, Maury.

I think they are some of the same trends that we looked to.

So what is our ability to get the underlying distribution utilities closer to or at their allowed returns?

In fact, by the time you get to 2011 there is an open question on what the allowed returns or authorized returns level actually will be.

I think that's kind of an open issue.

What cost of capital environment are we in?

Are we in a 9% environment or a 10% environment?

And probably the more important question is, what are the rate cases and what's the regulatory strategy within the Company to get to that point?

But I think if you can get a collection of distribution companies that on average are earning seven [handle]-type of returns, just something that is 200 basis points better, you're going to get a lot of underlying growth on the equity base in this Company.

So that's something quite important to watch.

And that, I guess secondarily, has also a great deal to do with what their capital plans are.

So to the extent that they are earning returns on a higher level of capital, whether it is at Yankee Gas or CL&P, that will drive numbers.

And we haven't at this point changed our 2010 and 11 capital program.

On the transmission side of the business, that has a good amount to do with the underlying transmission build, including news.

So news, as we venture into particularly the Greater Springfield Project is going to begin to drive earnings, and by the way, you know based on the FERC order, we get [cash] returns on the news project.

So that's the second piece to look for.

Okay.

Great.

Thank you, folks.

All right.

Thank you, Maury.

Next question is from Michael Lapides from Goldman Sachs.

Michael?

If I look at the very detailed transmission Cap-Ex that you typically break out in some of your presentations, and you can go back like the AGA one from the Spring, you've got a big bucket.

Of the $3.5 billion between now and 2013, you've got a big bucket, the $1.5 billion of additional forecast projects.

You do a great job of giving updates on Hydro-Quebec and on news.

Can you talk to us about just kind of where a lot of these other projects are?

I know they are pretty diverse, they're pretty spread out, and lots of projects making a big sum number, but just can you give us a little guidance on where that number stands, and where they are in the permitting and sighting process?

Mike, this is Lee Olivier.

Most of those projects are smaller projects that are spread across the three states.

A number of projects in southern New Hampshire, all of them Reliability.

A number of upgrades here inside of Connecticut, various substation upgrades.

Inner ties between -- in and around the Hartford, Manchester area.

So there are really a series of smaller projects in the range of $20 million, $30 million, $40 million.

Some of the projects can be done without any kind of significant siting; they are essentially inside the fence kind of upgrades.

Others like Manchester, the Hartford project, we go through the siting process, but for the most part these are upgrades of existing equipment and/or transmission lines that are very low visibility in nature.

Okay.

Why just when I look out to 2011, 2012, why such a big step up in that bucket versus historical range, and even looking at the 2013 number?

Well, I think over the course of the last few years we have put a significant effort into the southwest Connecticut projects, and kind of concurrently while we are doing that we continue to do analysis, we continue to look at our transmission system against the NERC requirements in terms of Reliability, and as we do that what we find there are more projects that are smaller in nature.

As an example, the greater Springfield Reliability Project, as a result of that study we have found a number of other projects or other lines that needed to get upgraded to essentially support the work that we are going to do in the Greater Springfield area.

So a little bit of this is catch up, a little bit of this is tied to the Greater Springfield Reliability Project that we are working on, and some of it is just, quite frankly, aging infrastructure, equipment that needs to be changed, and making sure the we meet the NERC requirements.

Thank you, guys.

Thank you, Michael.

We don't have any more questions, so we want to thank you for joining us today.

If you have any further questions, either today or tomorrow, please give us a call.

Thank you, very much, for joining us.

Thank you, ladies and gentlemen.

This concludes today's conference.

Thank you for participating.

You may all disconnect.