康涅狄格電力 (ES) 2013 Q2 法說會逐字稿

Welcome to the Northeast Utilities Q2 earnings call.

My name is Christine, and I will be the 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 would now like to turn the call over to Mr. Jeffrey Kotkin.

You may begin.

Thank you, Christine.

Good morning, and thank you for joining us.

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

Speaking today will be Jim Judge, NU Executive Vice President and Chief Financial Officer; and Lee Olivier, NU Executive Vice President and Chief Operating Officer.

Also joining us today are Jim Muntz, President of our Transmission Business; Jay Buth, our Controller; Phil Lembo, our Treasurer; and John Moreira, our Director of Corporate Financial Forecasting and Investor Relations.

Before we begin, I would 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 based on Management's current expectations, and are subject to risk and uncertainties which may cause the actual results to differ materially from forecasts and projections.

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

If you have not yet seen that news release, it is posted on our website at www.nu.com, and has been filed as an exhibit to our Form 8-K.

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, 2012, and our Form 10-Q for the three months ended March 31, 2013.

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-K.

Now, I will turn over the call to Jim.

Thanks Jeff, and thank you everyone for joining us this morning.

We appreciate your participation in today's earnings call.

In my remarks today, I will discuss our second quarter results, some additional financing activity since last quarter, economic conditions in our region, and I will conclude with an update on various regulatory and legislative matters, including recent regulatory developments in New Hampshire, New England's ROE proceeding before FERC, some elements of Connecticut's comprehensive energy strategy, and the status of our storm cost filings in Connecticut and Massachusetts.

As you are probably aware, we released our Q2 '13 earnings after the markets closed yesterday.

Excluding merger-related and integration costs, we earned $172.8 million, or $0.55 per share this quarter compared to $135.8 million, or $0.45 per share this quarter for the same period last year.

The first half of the year we earned $402.6 million, or $1.27 per share, compared to $236.2 million, or $0.98 per share, excluding merger-related and integration costs for both periods.

This is our first quarterly comparison that includes NSTAR's operations in both periods.

Overall, we're very pleased with our financial performance in this quarter.

Our solid results exceeded Wall Street's expectations, and were driven by some core factors.

One, an increase in transmission investment return; two, a decline in O&M costs; and thirdly, higher electric and natural gas sales.

While Q2 weather conditions are typically not a significant driver, this year we did benefit from colder temperatures early in the period, and warmer weather later in the quarter compared to last year.

Heating degree days were up about 20% on average in our gas service area this quarter compared to 2012, and due to an early summer heat wave in late June, cooling degree days in Boston for the quarter were up above 13%.

Although total electric sales increased for the quarter a modest 0.6%, we did see a 1.8% increase in the residential electric sales, which is our largest sector, compared with the second quarter of 2012.

Sales for our gas operations increased 13% in the second quarter, with the strongest component also being the residential sector.

I am pleased to report that part of the gas sales performance was due to customer growth and strong conversion activity, as evidenced by the weather-normalized growth rate of 4.4%.

These higher electric and gas sales added about $0.02 per share to the quarter's earnings.

While on the topic of weather, you have all probably been affected by the hot weather conditions we experienced in July.

The number of days that the temperature hit 90 degrees or higher in Boston this month was double that of last year, and a new single-day record was set in Boston on July 19, of 99 degrees.

So while the third quarter of 2012 was a hotter than normal quarter, we are now on pace to at least match it.

Later, Lee will review our system's very good operating performance during this period.

In addition to higher sales, our second quarter revenues benefited from two distribution rate increases that took effect in mid-2012.

Yankee Gas and Public Service of New Hampshire each benefited from a $7 million annualized distribution rate increase, and together they added about $0.01 per share to earnings for the quarter.

Another positive driver in the quarter was the continued investment in our transmission business.

Transmission earnings totaled $76.8 million in the second quarter of 2013, compared with $63.7 million in the second quarter last year, adding about $0.04 per share.

I'm pleased to note that we achieved a couple of significant milestones in June regarding the transmission business -- a 345 kV line to Cape Cod was energized before the summer peak period, and we also announced a new Northern Pass route.

Lee will provide some additional details on these and other transmission initiatives shortly.

As expected, we continue to benefit from the decline in O&M costs, which added about $0.05 per share to the quarter's results.

We continue to implement efficiencies across the merged Company, where we expect the savings to be permanent.

Those efficiencies are helping us to achieve the 3% per year reduction in O&M that we first discussed with you at our Analyst Day last year, and which we expect will continue through 2015.

Year-over-year, O&M reductions, excluding merger costs, have been greater than 3% for the first half of this year, but as I said during our first quarter call, some of that we attribute to timing of items such as vegetation management and other maintenance-related work that could not be accomplished due to weather conditions earlier this year.

Nevertheless, we remain confident that we will achieve our target for this year, while at the same time continuing to improve reliability and customer service.

To conclude the discussion of the positive drivers, several minor items taken together amounted to about $0.02.

Factors that had a negative impact on the quarter's results included an increase in depreciation in property taxes, which is a function of the continued investment in our system infrastructure, and they reduced earnings by approximately $0.02.

Also, the higher level of shares outstanding as a result of the merger was a negative for the quarter of about $0.02.

Given this solid performance, we feel very comfortable moving the lower end of our 2013 earnings guidance up by $0.05, making our new guidance range $2.45 to $2.60 per share.

Our longer term earnings per share growth remains at 6% to 9% off a base of $2.28 per share of recurring earnings that we recorded in 2012.

While interest savings were not a major driver in our second quarter earnings performance, the significant financing activity we completed during the quarter will serve us well in the future.

In May, the NU parent issued two series of debt -- $300 million of 5-year notes at variable rate of 1.45%, and $450 million of 10-year notes at a fixed rate of 2.8%.

The proceeds from these new issuances cover the repayment of $550 million of debt, part of which came due in June, and the remainder due in September.

The proceeds were also used to reduce short-term debt balances.

Let me illustrate for you the benefits we realized from the low interest rate environment and the improvement in NU's credit ratings that occurred upon the consummation of the merger.

Since we closed in April 2012, we have retired more than $900 million of long-term debt, and issued nearly $2 billion in new long-term debt.

The annual cost of the new debt is less than the cost of the $900 million that we retired, some real evidence of our ability to take advantage of the attractive interest rate environment.

Now let me comment on economic conditions in our region.

I would characterize the local economy as improving.

We continue to see signs of improvement, particularly in the local labor and housing markets.

Regarding the local labor market, we have seen a notable improvement in construction-related labor activity, which increased in all three states, ranging from 2.6% in Massachusetts to 7% in Connecticut, and significantly better than the national rate of 1.8% as of June.

This is encouraging for our service area, and clearly an indication of new customers to come.

The unemployment rate for Massachusetts is at 6.7%, the same level as at year-end 2012.

The rate for Connecticut has improved, and is at 8%, compared to 8.3% at year-end.

New Hampshire's unemployment rate also improved to 5.3%, versus 5.7% at year-end 2012, remaining well below the national rate of 7.6%.

Now I'd like to provide you with a brief update on some rate actions in New Hampshire that will have a positive impact on Public Service Company of New Hampshire, as well as our New Hampshire customers.

On June 27, the New Hampshire PUC issued various rate orders that became effective July 1. A $12.6 million distribution rate increase that included $7.7 million related to plant investment, and represents the third and final step adjustment associated with the 2010 distribution rate settlement agreement.

Also included is an incremental $5 million to fund major storm costs at a new level of $12 million annually.

The Company also implemented a couple of rate decreases for its customers.

The stranded cost recovery charge was reduced by 83%, due to the final maturity of rate reduction bonds, and also the energy service charge declined 10%, due to current market conditions.

The combination of these changes is good news for New Hampshire customers, as their monthly bills will be reduced by more than 5%.

On June 7 in a separate proceeding, the New Hampshire PUC staff issued a report related to a review that was first announced by the Commission in January of this year, a review into the market conditions affecting the default service of Public Service Company of New Hampshire.

Among other things, the report recommended that the Commission open a proceeding to examine several possible solutions to PSNH's default service rates in the context of competitive retail markets, and in connection with this, to explore various alternatives related to PSNH's generation assets.

Earlier this month, the Commission issued an order to engage evaluation expert to determine the value of the Company's generation assets.

I should point out that these facilities responded very well to the demands placed on them by the June/July heat waves that I spoke about earlier.

We believe it's appropriate for the Commission to review energy issues affecting our New Hampshire customers, and we will participate in the process openly and transparently.

I would like to briefly touch on the Connecticut legislation recently enacted related to the State's energy strategy.

Connecticut Governor Malloy has signed into law two significant energy bills.

The first bill implemented a number of proposed recommendations.

The relevant components of the legislation provide, one, authorizing the filing of a plan to expand natural gas to those of the state who do not have access to natural gas currently -- an objective that looks to increase Connecticut's gas penetration rate from 32% to 50% over the next 7 to 10 years.

Secondly, the bill also requires PURA to implement decoupling for Connecticut's electric and natural gas utilities in an [ex-rate] case.

The second bill, Senate Bill 1138, allows the Department of Energy and Environmental Protection to conduct a process to procure additional renewable energy from generators under long-term contracts with the electric distribution companies to help Connecticut meet its renewable portfolio standards.

If Connecticut experiences a material shortfall in reaching its RPS standards, large scale hydropower, under certain conditions, can be used to alleviate the shortfall, up to 5% of RPS requirements in 2020.

Now for an update on the base ROE proceeding before FERC.

Hearings were held in May.

Initial briefs were filed on June 6. Final briefs were filed on June 28.

We continue to believe that FERC's decision in this complaint will be viewed widely as an important statement on efforts to promote transmission development across the United States.

We and others in the industry believe that a significant reduction in the ROE for New England's transmission owners would have a chilling effect on transmission investment throughout the country, and would run counter to FERC's very successful policy since 2005 of encouraging transmission investment as a means to make the grid more reliable and secure.

In short, the decision could have nationwide ramifications.

An initial decision is expected to be made by the administrative law judge no later than September 10, but a final decision from FERC is not expected until mid to late 2014.

After the ALJ recommendation is issued, the parties will provide briefs on the judge's decisions to the full Commission, and then later reply briefs.

After the FERC decision is issued, parties can then request reconsideration.

Of note, FERC in making its decision will take into account any changes in bond yields.

When the current New England transmission ROE was first set about five years ago, FERC increased the ROE from 10.4% to the current 11.14%, due to an increase in bond yields during its period of reconsideration.

Generally, FERC will look at average bond yields over the six-month period prior to its final decision.

As you know, long-term interest rates have moved nearly 100 basis points higher in recent months, furthering support of our position that the base ROE should not be adjusted at all.

We continue to expect the ALJ's recommendation to adhere to previously established FERC policy.

Changes to previously established FERC policy, if any, would most likely be addressed in the FERC decision, rather than the ALJ decision.

The last regulatory item I will cover is the status of our storm cost proceedings.

Primarily as a result of the four major storms that New England experienced between August of 2011 and February of 2013, we have more than $600 million of deferred storm costs that we need to recover from our 3 million electric customers.

On June 24, 2013, the PURA issued a procedural order in which it said it would review Connecticut Light and Power's storm cost recovery request.

The review would involve the accuracy of the costs, the eligibility for recovery, and the prudency of the costs.

PURA is expected to issue a decision by December of this year.

As a reminder, per the Connecticut merger settlement agreement, storm recoveries will not begin for CL&P until December 2014, and will occur over six years.

As I noted last quarter, NSTAR Electric filed their request in March to recover about $35 million of restoration costs from the 2011 storms.

Per the Massachusetts merger settlement agreement, prudently incurred costs will be recovered over a five-year period beginning January 1, 2014.

Hearings are due to begin in August.

We expect to file later this quarter with the Massachusetts Commission for recovery of 2012 and 2013 storm costs.

And as I mentioned earlier, effective July 1, PSNH was able to increase its major storm recovery collections by $5 million to $12 million per year.

If no new major storms occur, PSNH now expects to fully recover its deferred storm costs by mid-2015.

The Company also received approval to include pre-staging costs incurred in preparing for a storm event in its storm fund reserve for recovery.

And lastly, Western Mass Electric is seeking recovery of its storm costs through its typical storm recovery mechanism.

That concludes my formal remarks.

I'll turn the call over to Lee.

Thank you, Jim.

I will provide you with an update on our major capital projects and our natural gas expansion initiatives, and then turn the call back over to Jeff for Q&As.

As most of you know, we had some very important news on June 27 when we announced a new route for the northernmost 40-mile section of our Northern Pass transmission project.

We had been working on a new route for more than two years, and we were thrilled to be able to announce it in New Hampshire five weeks ago.

The Northern Pass team did a tremendous job putting together a proposal that accommodates the concerns of many in the state's North Country, while also delivering very significant economic and environmental benefits that are core to this innovative project.

This northernmost section of the new route has about 32 miles of overhead line on new rights-of-way that we either own or have under lease; and approximately 8 miles of underground.

As a result of the underground work and other changes to the structure configuration, we have raised the project's cost estimate to $1.4 billion.

The new preferred route addresses many of the concerns that have been raised about the project with the two underground sections, lower structures and heights, and a route that take the project well to the east of our earlier route.

We have significantly reduced the project potential for visual impact.

Additionally, the number of properties that would have overhead lines has been reduced to 31 from 186.

Areas with new overhead lines are now located in generally more remote terrain, and use natural topography to help with visual screening.

On July 1 we filed an amended application with the US Department of Energy, and there is now a link to that filing on the Northern Pass website.

We expect the DOE to hold scoping meetings this fall.

These scoping meetings will offer the public the opportunity to comment on the project, and will be in addition to our own open house forms.

Our open houses begin next week in the northernmost area of the project, and eventually will cover towns all along the route.

The public will be able to meet face-to-face with project representatives, and view maps and other information specific to their community.

The DOE will now continue to work on the draft environmental impact statement for the project.

As soon as that draft is complete, we will use it as part of our siting application with the New Hampshire site evaluation committee.

Once we file that application, the site evaluation committee will review and adjudicate it.

Our plan has both the state and federal permitting processes complete by mid-2015.

On that schedule, we expect to bring the project into service around mid-2017.

The benefits of Northern Pass and its 1200 megawatts of firm capacity remain extraordinarily persuasive.

We expect the project will lower New England energy costs by $200 million to $300 million annually, between $20 million and $35 million of which will directly accrue to New Hampshire customers.

Because Hydro-Quebec is almost excessively a hydroelectric system, it is expected to reduce the region's carbon dioxide emissions by up to 5 million tons per year.

We expect the project will increase property tax revenue in New Hampshire and the project host communities by about $28 million per year.

Effective Thursday, August 1, Gary Long will move from his long-time position as President of PSNH to work full-time on the Northern Pass and other New Hampshire renewable energy initiatives.

Gary has done an excellent job over the past 13 years leading PSNH through industry restructuring, and through some major initiatives, such as the innovative conversion of our Schiller 5 unit from a coal boiler to a renewable biomass generator.

As one of the most respected business leaders in New Hampshire, Gary will play a key role, ensuring that the benefits of the Northern Pass project are delivered to New Hampshire residents.

From Northern Pass, let's move to the NEEWS family of projects.

The Greater Springfield Reliability Project is now approximately 97% complete, and the new Free 45 kV line has operated flawlessly this summer, providing significant support for the reliable movement of power in Southern New England.

We continued to project 115 kV sections of the Greater Springfield project and the remaining station work will be completed later this year; and we expect the project will come in approximately 5% below it's $718 million budget.

We cleared a significant milestone last month with the second large piece of NEEWS, the three-state Interstate Reliability Project, or IRP.

Rhode Island siting regulators approved the project, meaning that we and National Grid now had two of the three state siting permits we need to start construction; and also the Connecticut Siting Council has previously approved the Connecticut aspect of the IRP project in January.

The third and final siting approval is in Massachusetts, and hearings on the need for the project will start in about two weeks, and are scheduled to conclude by the end of August.

We expect to receive Massachusetts' approval by the end of this year or early 2014.

We expect to commence substation construction in Connecticut in late 2013 or early 2014, and line work in mid-2014.

Our section is still expected to cost $218 million.

A third major piece of news is CL&P 's greater Hartford Central Connecticut Project.

As we have said before, ISO New England finished the needs assessment for the GACC study, and has found severe thermal and voltage violations on several 115 kV lines within and across the four areas in Connecticut under study, including the 115 kV system that makes up part of the Western Connecticut interface.

ISO has presented these reliability problems several times to its stakeholders, and as a final step in the needs assessment process, expects to post the needs report documenting the violations for stakeholder review in early fall of this year.

ISO New England continues to work on the preferred solutions being designed to correct these violations, and will have those ready for stakeholder review before the end of the first quarter in 2014.

Greater Springfield's 345 kV line has provided significant reliability and economic benefits to Connecticut electrical customers since it went into service in March.

Along with our Middletown-to-Norwich project completed in 2008, our Bethel projected completed in 2006, as well as a number of smaller projects completed over the past seven years, we have dramatically improving the reliability of the region's bulk power infrastructure.

Altogether, our major transmission projects have saved Connecticut customers more than $1 billion of congestion.

Reliability must run in other related charges since our first major project into service in 2006.

Despite the retirement of older fossil fuel plants in the state, congestion costs during the extremely hot weather this month were minimal in Connecticut, thanks to the transmission upgrades.

Elsewhere in transmission, we energized NSTAR's electric new 345 kV Southeast Massachusetts, or SEMA, link to Cape Cod at the end of June, on schedule and on time for the heavy summer heat loads.

This project as well will lower congestion costs for our customers.

We continue to project $636 million of transmission capital expenditures in 2013.

Over the first half of the year, we invested approximately $262 million in transmission facilities.

I am pleased to report that our electric distribution system has held up well this summer, despite the repeated heat waves in late June and early July.

Additionally, PSNH generation has performed very well, providing customers with a hedge against the wholesale power spikes we witnessed during the third week in July, when ISO New England wholesale prices topped $540 per megawatt hour in the realtime market.

On the distribution side, we invested $300 million in our electric distribution system, and $70 million in our natural gas delivery system in the first half of this year.

We continue to expect to invest approximately $670 million on our electric distribution infrastructure in 2013, but have raised our projected natural gas capital expenditures for this year to approximately $180 million from $170 million, due to more anticipated work connecting new customers.

Over the first six months of 2013, we converted more than 5,600 Yankee and NSTAR gas customers, including nearly 1,100 low use customers.

We had initially projected adding a record 9,100 additional natural gas heating customers, but through June we are ahead of our expectations.

Let's take a deeper look at our natural gas delivery business, specifically the joint infrastructure expansion plan that Yankee Gas filed with United Illuminating's gas distribution business on June 14.

We have previously discussed with you the low penetration rate of natural gas in Connecticut's heating market.

Only about 31% of the homes and 40% of the nonresidential facilities in the state currently heat with natural gas.

The most prevalent alternative is fuel oil, which today heats about 0.5 of the homes in Connecticut, and is twice as expensive as natural gas on a Btu basis.

As Jim mentioned, Connecticut legislators enacted Public Act 13298 in early June, which contains key provisions implementing Governor Malloy's energy strategy.

Key sections of the bill provide a number of tools to encourage the rapid build-out of the state's natural gas infrastructure.

In our joint filing, Yankee Gas and the state's other two natural gas delivery companies have estimated that a total of 280,000 new heating customers could be added to Connecticut's natural gas distribution systems over the next 10 years, reaching 50% of the homes and 60% of the nonresidential customers.

We also noted that such a build-out would have far-reaching benefits for the state, including a $2.8 billion of net savings expected over the next 10 years, creation of nearly 5,000 jobs by the end of the 10-year period, and nearly 1 million-ton reduction in greenhouse gas emissions.

On July 16, the Connecticut Department of Energy and Environmental Protection found the plan to be generally consistent with the state's comprehensive energy strategy goals.

DEEP asked that we make some relatively minor modifications, which we filed last week.

Utility regulators are now reviewing the plan, and that review should be complete by the middle of October.

The plan is posted on our investors' website.

The impact of Yankee Gas would be dramatic.

The plan calls for Yankee Gas to increase its annual investment and connected new customers more than threefold, and the cost of connecting new customers more than threefold from $26 million a year now to more than $50 million a year by 2016, and $90 million a year by 2023, the 10th year of the plan.

Over that period, we would expect to connect approximately 80,000 customers to the Yankee Gas system, including converting 10,000 low-use residential customers to space heating.

Today, those low-use customers use natural gas only for water heating or cooking.

By the end of 2023, we expect Yankee Gas to have nearly 300,000 customers, compared with approximately 215,000 customers today.

We have proposed a number of incentives to encourage conversions, including the flexibility to wave customer contributions for connecting certain homes or businesses to our facilities where it is cost-effective to do so.

Those homes are usually within 150 feet of our mains.

The new legislation would allow us, subject to regulatory approval, to implement a capital tracking mechanism to recover incremental investment without full general rate cases.

Revenues would be collected primarily from higher sales and temporarily higher rates on new customers.

Critical to the plan is additional natural gas supply.

A key part of the infrastructure expansion plan is bringing in an additional pipeline capacity to Connecticut.

In our June filing we asked PURA to approve agreements we have reached with the Algonquin and Tennessee pipelines that would enable Yankee Gas to secure a total of approximately 127,000 decatherms per day of additional capacity beginning in winter of 2016/2017.

We are optimistic that PURA will approve those commitments this fall.

Our gas plan will produce very significant benefits to Connecticut's economy and our customers and shareholders.

Let me add that the incremental capital expenditures and incremental earnings this plan is expected to produce were not reflected in the guidance we provided to you during our Analyst Day last fall.

So now I'd like to turn the call back over to Jeff.

Thank you, Lee.

And I will turn the call back to Christine to remind you how to key in queue for our Q&A.

Thank you.

We will now begin the question-and-answer session.

(Operator instructions)

Thank you, Christine.

Our first question this morning is from Kit Konolige from BGC.

Good morning, Kit.

Good morning.

Thanks for the call.

Jim, on your comments on O&M -- in the table that reconciles the year-over-year showing $0.12 in EPS improvement in the first six months, is all of that $0.12 attributable to merger cost savings?

No, it's not.

And actually, Kit, I prefer to focus on the second quarter numbers, only because the year-to-date Q1 2012 NSTAR wasn't in the numbers.

Maybe the way to think of O&M in terms of what's permanent savings is, I think we finished the second quarter down $28 million in total.

We think about 0.5 of that is timing-related.

As I mentioned, last year in the first quarter it was extraordinarily mild.

We had the majority of our vegetation management completed early in the year.

In fact, we have a variance year-to-year on that tree trimming of about $9 million.

That $9 million will be spent, but it'll be later in the year.

So the way to think of it is, 0.5 of the $28 million is timing related, and when you multiply that $14 million times -- as a run rate for four quarters, you get to the guidance that we've been providing, which is, we think we will be able to take O&M down by about 3%, or $50 million.

Does that answer your question?

That does, thank you.

And just to follow on that a little bit -- I think your communication to date has been that investors should not get overly optimistic that you can beat the $48 million, 3% per year O&M improvement.

Does that remain the guiding principle?

I think we have provided guidance in terms of earnings growth.

We fully expect to be a top performer over the three-year period.

Our plan -- I expect that we can do it with 3% reductions a year.

If it turns out that we need more than that, I think that we have the management capabilities to achieve it, if necessary.

Okay, very good.

And question for Lee -- Lee, is there any public feedback in the newspapers, politicians' comments, et cetera, on the new route for Northern Pass?

Yes.

I would say, Kit, by and large it has been very positive.

I think the fact that they are seeing essentially eight miles of underground, particularly eight miles of underground around very sensitive areas -- environmentally sensitive areas -- has all been very positive.

I think that the real sense is that this Company essentially took a hiatus of two years to come up with a route that is more sensitive to the environment, to the folks that live along the route, to the citizens of New Hampshire, and that's being paid a lot of the very positive compliments.

We've received a number of editorials in newspapers in support of the project, particularly because, as folks look around at the New England energy capacity situation and see anywhere from 8,000, 9,000 megawatts of old retired plants -- or plants that will have to retire, rather -- and that have, in many cases, questionable reliability, they know there's a need for this.

This is clearly the best project for the region, probably will be the best project for the region in the next 50 or 60 years in terms of its firm power, clean power, and reliable power.

So we see a building consensus in the polls that we are taking.

We see a rising support for the project.

Excellent.

Thank you.

Thanks, Kit.

Next question is from Travis Miller from Morningstar.

Good morning, Travis.

Good morning.

Thanks.

Question on the FERC ROE issue.

As we go through this proceeding, I know we have a long way to go on this most likely, but as we go through, if you get indications that this might not go your way, or there are some challenges here, what's your thought on how that would affect your capital spending budget for transmission?

Well, I think from a capital allocation perspective, transmission has been an attractive opportunity for not only Northeast Utilities, but really all the utilities across the country that are in the transmission business.

And the returns have exceeded the 10.2% allowed ROEs that we've seen in the distribution business.

If all of a sudden they were to invert, and the distribution business was to become more financially attractive as investment opportunities, you'd have to think that it would influence the capital allocation decisions that companies and their boards will make going forward.

Are we into a follow-up on that?

Is your investment spend within the time period that when we ultimately get a decision, if it's 2015, 2016, do you expect that you'd be done with a lot of the projects?

Potentially there is a chance they could be grandfathered in, or something like that?

Is there any chance there?

Actually, the expected decision out of FERC is probably a mid-2014 event.

So it's not that far off.

And the effective rate of it began October 1, 2011, when the complainants filed the complaint.

Okay, great.

Thanks so much for the clarification.

Thanks, Travis.

Julien Dumoulin-Smith, UBS.

Good morning, Julien.

Good morning.

So perhaps the first quick question here -- you talk about PSNH.

Could you perhaps help us think about the recovery on those investments, ultimately depending how this all hashes out in the state?

Then secondly, to the extent to which perhaps the state isn't heading toward restructuring, how would you reconcile the migration trend of late?

Julian, just to be clear, you're talking about PSNH generation, correct?

Indeed I am.

Okay.

The migration, or rate, of late has reflected the fact that the energy service charge had been higher than competitive suppliers' offerings.

As I mentioned in my comments, that has recently changed, and that would reduce the energy service rate by 10%.

We feel very confident from a legal perspective that the investments that were made in the generation business in New Hampshire have served customers extremely well over the last decades, and we feel highly confident that cost recovery there is unlikely to be an issue, should the state decided to pursue divestiture, which is one of the options that they're considering.

As well, the New Hampshire legislature has enacted a bill that will look at their whole New Hampshire energy future in terms of what New Hampshire wants to do with those assets, as well as other things, such as renewables.

So we expect that the future of those assets will be taken up in that legislative study bill.

It's unclear where the state goes in terms of this issue.

I think there's probably going to be lengthy proceedings to assess the merits of PSNH retaining those plants.

But in any event, we feel highly confident that the spending was prudent and in the best interest of customers in New Hampshire.

Great.

And then secondly, there's been a lot of discussion in New England on gas [distribution] supply, and obviously your announcements today, and related to Connecticut, help improve that.

I'd be curious -- how has that improved your plans for electric reliability investments?

I'd be curious if there's been any discussion around the impacts associated with Northern Pass to that effect.

From the standpoint of the investments that I referred to in my presentation, which is the Tennessee and Algonquin pipelines, if you look over the course of approximately the next 10 years and you look at the increase in gas usage in the region, almost all of that capacity gets used up by the distribution companies, by the LDCs.

Obviously, what the LDCs will do is, during that period of time, they will, whatever spare capacity they have, they will sell back into the marketplace to benefit their distribution customers.

But if the question is around -- does this solve the shortfall of natural gas for generation capacity in the region?

It actually does not do that, and if you look at the plans, the proposed plans that ISO New England has that they're going to move forward later this year for performance market in the future, generators would have to have essentially a guaranteed fuel supply to bid in.

It could be oil, it could be, obviously, firm pipeline capacity, be it LNG, but they will have to have firm capacities to bid into the market.

Perhaps looking at transmission as a fungible alternative to gas midstream in the, call it, near-term, I'd be curious -- has there been any kind of expanded discussions on electric transmission as a, quote-unquote, solution?

That conversation has been ongoing for a long period of time.

I think it probably is -- the tempo will probably increase after this summer because in this past heat wave there was, on any given day, over 3000 megawatts of capacity that couldn't start up, or tried to start up.

On the hottest day there was 4000 megawatts of generation capacity that couldn't start up.

And so it reinforces the need for connectability of transmission to where the generators are in the region and to where the load pockets are.

So I only see that as a positive.

Great.

Well, thank you very much.

Thank you, Julian.

Andrew Weisel, Macquarie.

Morning, Andrew.

Good morning, guys.

I wanted to start with a couple of questions for Lee on Northern Pass, specifically around the timing of approvals.

I believe you said you're expecting the processes to be done by mid-'15, which about 24 months from now.

If we work backwards a little bit, the New Hampshire Site Evaluation Committee takes about eight months, and before that you will need to get the draft approval from the DOE.

If the DOE scoping meetings don't start until this fall, that only leaves about a year, maybe even less, for the DOE draft decision.

Does that seem realistic to you?

How confident are you in that mid-'15 timing to end the approval process?

Yes, at this point in time, based on everything we know, we are still confident.

So if you think about the scoping meetings, the scoping meetings are really all about the DOE coming into the impacted communities, and it will probably be a not northern part of the state -- midsection and towards the southern part of the state, there'll probably be, whatever, four or five meetings.

It's really the opportunity for the DOE to hear from the people in those communities, to take their input into the overall impact of the line.

But the real hard work is really all done around doing the environmental assessment itself.

These are essentially environmental scientists who are out in the field taking samples and so forth.

So you get the feedback.

You get all the environmental samples, the data, you do the analysis, you factor in the comments of the public, and the DOE makes a decision.

So right now, I would say we think that, that is still a realistic timeframe.

Okay.

Now, the community outreach you've done past few months and the open houses you will be doing in the coming months -- will that in any way help speed along the DOE approval or the Site Evaluation Committee?

Or is that independent, just trying to gain support and the best approach for you guys to take?

Yes, they're really quite independent.

The DOE is, by their nature, completely independent, and will conduct its own analysis and studies in accordance with their procedures and requirements.

We are doing this as really good citizens, good stewards of the state, of the community, as we always have in anything PSNH has ever done inside of New Hampshire.

So this is really all about creating better understanding in the communities of the value of the project, the impact of the project.

We will have topical overviews of what it would look like if the lines run through a particular area, we'll be able to see that using a GIS, or a global information system, superimposed transmission lines on that.

So this is really about learning more about the project and building a greater trust level with the public.

Great, Next question is on the cost of the project -- went up from $1.1 billion to $1.2 billion, now $1.4 billion.

Given your agreement with Hydro-Quebec, how does that affect the earned ROE, and what you will be collecting from HQ?

Is there any upside to your earnings or downside to your ROE because of these higher costs related to undergrounding the line?

In regards to the ROE, the ROE level is set by contract.

So there is no change to the ROE, particularly during the construction of the project.

After the project is complete and in service, the ROE would float off of the base ROE of the region by a band of, I think, it's 140 basis points, 142 basis points.

Now, to the extent that the project costs $200 million more, the equity base is now gone from essentially $600 million to $700 million.

So you are earning 12.56% on a higher equity base.

So that would definitely be more earnings for the Company.

And you would look at the increase in that capital of the $200 million based over three years, about $25 million pick-up in 2015, $100 million pick-up in 2016, and a $75 million pick-up in 2017.

Thank you.

That's very helpful.

And so just to be clear, it is based on the regional base ROE.

So this could be impacted by the FERC review, right?

It could be impacted, but only after the line goes in service.

Got it.

Okay, that makes sense.

Thank you very much.

Thank you, Andrew.

Caroline Bone from Deutsche Bank.

Good morning, Caroline.

Hey, guys.

Good morning.

Actually all of my questions have been answered.

Thank you.

Thanks a lot.

Dan Fidell, US Capital.

Good morning, Dan.

Good morning.

Just a couple of questions.

Also,

my questions have mostly been asked and answered.

But maybe if you could talk just a little bit about where you are in terms of staffing for your longer term plan with the merger put together, and what your needs assessments are going forward?

Assuming that you're perhaps running a little bit ahead of schedule in terms of just early on where the staffing count is.

I think at the merger close, we had approximately 9,000 employees, and I think we are down to about 8,700 today.

So it might be about a 3% to 4% reduction in staffing.

What we've been able to do is really optimize attrition.

This year alone, we've had about 350 employees leave the Company.

Vast majority of them are retirements.

We've obviously had some replacements.

We've hired about 200 to replace them as necessary in key operational roles, primarily.

So what we're finding is that we are able to become efficient, reduce our costs going forward by really optimizing attrition opportunities across the organization.

Okay, great.

Maybe just a follow-up question on the gas conversion site.

You mentioned significant upside from that not included in the plan.

The optics really do look very good for that.

At what point would it make sense to start adding that to guidance, do you think?

Well, I think the ramp-up -- you can think of it as approximately $5 million of incremental earnings out around 2016, 2017.

So thus far we've only given guidance through 2015.

But that gives you a frame of reference.

That it's, the run rate will be about $5 million a year.

Great, appreciate it.

And then just a last question.

It's your understanding on the FERC ROE, as we start to get closer to an ALJ recommendation here that -- which has to be delivered by early September here -- will not include a bond yield mark-up.

But you do expect FERC will include that piece of it as they make their final decision mid-2014 -- is that correct?

Yes, based upon the precedent, that's what FERC has done.

As I mentioned, the bond yields have moved significantly since the testimony by all of the witnesses was filed in early May.

Terrific.

Thank you.

That's all I had.

All right.

Thanks, Dan.

Paul Patterson, Glenrock.

Good morning, Paul.

Good morning, How are you?

All right, how are you?

Okay.

Just really quickly -- the sales growth -- I'm sorry if I missed this.

The electric sales growth, weather adjusted, what was that?

I didn't get that, for the first quarter.

For the second quarter.

Second quarter, I'm sorry.

The sales growth for the quarter was 0.6%, and weather-adjusted, it was about 0.8%.

So it wasn't a huge sort of need for adjustment in weather.

Okay.

And then also, Judd Gregg and Jeanne Shaheen had an editorial about that specific piece of land and everything.

You know what I'm talking about -- with respect to Northern Pass.

Does this alternative proposal they you have, do you think that deals with that, and that specific crucial area, if you follow me?

Yes, Paul, this is Lee.

Yes, it does, actually.

The original proposal we had was essentially going under about 100 feet or so, or 115 feet of that land underground.

So visibly you would see nothing on the land.

That's in conservation.

But this new route doesn't go near there.

It goes underground, goes away from it.

So this resolves their issue that they had in the editorial.

Okay, great.

Thanks a lot, guys.

All right.

Thank you, Paul.

And as we have no other questions.

So we want to thank you all very much for joining us this morning.

If there are any follow-up questions, please call John Moreira or me today.

And have a great summer.

Thank you.

Thank you.

Thank you, and thank you ladies and gentlemen.

This concludes today's conference.

Thank you for participating.

You may now disconnect.