康涅狄格電力 (ES) 2014 Q2 法說會逐字稿

Welcome to the Northeast Utilities earnings call. My name is Vivian and I will be your operator for today's call. (Operator Instructions). 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 Vivian. 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, our Executive Vice President and Chief Financial Officer, and Lee Olivier, our Executive Vice President and Chief Operating Officer. Also joining us today are Jim Muntz, President of our Transmission business; Phil Lembo, our Treasurer; Jay Buth, our controller; and John Moreira, our Director of Corporate Financial Forecasting and Investor Relations.

Before I turn over the call to Jim, I'd like to remind you that some of the statements made during this investor call may be forward-looking as defined within the meaning of the Safe Harbor provisions of the US Private Securities Litigation Reform Act of 1995. These forward-looking statements are based on management's current expectations and are subject to risk and uncertainty 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, 2013 and on Form 10-Q for the three months ended March 31, 2014.

Additionally, our explanation of how and why we use certain non-GAAP majors 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. Today I will cover our second-quarter and midyear financial results, including the impact of two orders issued by the Federal Energy Regulatory Commission on June 19. I'll also cover sales trends, the state of our regional economy, and a number of state regulatory and legislative developments that we've seen since our last earnings call. Before I discuss those topics, though, I would like to comment on the first half of 2014.

We've had strong financial and operating performance to date. Revenues, particularly natural gas, ahead of budget and operating costs are being well-managed. And I will remind you that we have projected a 4% reduction in operations and maintenance costs this year.

As Lee will discuss, electric service reliability is running well ahead of last year. And remember, 2013 was NU's best performance ever in terms of reliability.

On the state regulatory side, we received a favorable decision on the CL&P storm docket, have cleared some important hurdles in completing our news transmission projects and made a solid start to the Connecticut Light and Power distribution rate case. We are well-positioned for a strong second half of 2014 and believe we will earn between $2.60 and $2.70 per share for the full-year, including the $0.10 charge related to the FERC ROE orders but excluding post-merger integration costs.

I'll now turn to those FERC orders which were issued on June 19. One of those orders tentatively determined that the base ROE earned by New England Transmission Owners should be lowered from 11.14% to 10.57%. The second order, set for a settlement process, a second ROE complained that was filed with FERC in late December 2012. We are pleased that, in their decision, FERC agreed that investing heavily in the nation's transmission system is critical and that returns need to be supportive to reflect the risks associated with securing approvals for and building major transmission projects.

However, we believe there were significant flaws and uncertainties in the FERC's orders. Last week, we and other New England Transmission Owners requested that FERC reconsider both orders, so both cases are still pending. But as a result of those orders, we have now set aside approximately $80 million for potential refunds or about $46 million after-tax. About $55 million of that sum was recognized in the second quarter of 2014, and the remaining $25 million was recognized in the third quarter of 2013.

The first order issued by FERC on June 19 dealt with a complaint that was filed by various parties back in September of 2011 and dealt exclusively with the base 11.14% ROE that became effective for New England Transmission Owners back in 2006. That complaint did not address the various incentives that FERC has approved for various large projects in New England and there was no testimony in the case about those incentives. We strongly believe that the incentive adders should not be changed. We also have asked FERC to clarify that the high end of the zone of reasonableness it is establishing in this case which tentatively has been set at 11.74% pending a final order would apply to utilities' total transmission ROE and not each project's ROE.

In our other requests for consideration, we have asked FERC to reconsider taking up the second complaint, since by doing so it contradicted both commission precedent and federal statutes. Specifically, we firmly believe that the first complaint and the second complaint were essentially identical and should have been handled in a single docket. Moreover, the Federal Power Act precludes implementing a second 15-month refund period in a similar case beyond the initial 15 months.

I should add that, late yesterday, the same parties to the first and second complaint actually filed a third complaint arguing the same points. It remains to be seen if FERC decides to hear or dismiss this complaint. It's only been five or six weeks since FERC decided the appropriate ROE for the New England Transmission Owners.

The after-tax charge of $32.1 million in the second quarter of 2014 relates to transmission earnings we had booked during the period of October 1, 2011 through March 31, 2014. The third-quarter charge booked last year dealt exclusively with the period of late 2011 and full-year 2012. So, what that means is nearly 90% of the charges taken relate to 2011, 2012, and 2013. Of course, if we are ultimately successful on one or both of these requests for reconsideration, we will reverse some or all of these charges in the future.

While we certainly hope these orders will be modified before they are finalized, the additional insight into how FERC will compute transmission ROEs should be helpful to our investors since they will be able to more confidently project our future transmission earnings growth. And because the New England complaint was the first filed and the first decided, we now have a degree of clarity that many other transmission owners around the country don't yet have since complaints about their transmission ROEs have not yet advanced to the decision phase. That $0.10 charge was the primary reason for the earnings decline that we announced yesterday.

Excluding integration costs, we earned $131.9 million, or $0.42 per share, in the second quarter of 2014 compared with earnings of $172.8 million, or $0.55 per share, in the second quarter of 2013. I know there was a pretty big gap between consensus estimates for the second quarter, which were around $0.50 per share, and our results, but most of that was due to the fact that only some of the quarterly estimates on the Street reflected the FERC charge. If they had all included the charge, consensus would have been around $0.45 per share.

I'll provide some details on the other factors that drove second-quarter 2014 results. The theme here is that a number of small, discrete items went in our favor in the second quarter of 2013 and against us in the second quarter of 2014, but that overall the year looks very good.

First, I will cover transmission. Core transmission business continues to grow. Increased transmission rate base added $3.8 million to earnings this quarter and $6.5 million through June of this year compared with the same period of 2013. However, there were a number of true-ups under our tariff that helped us last year and hurt us this year which together more than offset the growth in rate base as we place more of our transmission projects in service. Overall, aside from the reserve, second-quarter transmission earnings decreased about $0.01 per share from last year.

Other factors that negatively impacted the quarter included lower electric revenues, primarily driven by milder May and June temperatures, which reduced earnings per share by $0.01, and higher property tax and depreciation expense, which together reduced earnings by $0.01, and notably a reflection of our continued investment in our electric and natural gas infrastructure. Also negatively impacting the quarter were a higher effective tax rate and lower interest income which taken together lowered earnings by about $0.03 per share.

Positive factors in the quarter included the decline in non-tracked O&M costs which added $0.02 to second-quarter results and higher natural gas sales revenue, which contributed $0.01.

Turning to some positive year-to-date results, as I mentioned earlier, several areas are performing better than we anticipated, including natural gas sales, which are up 12.4% for the year due in large part to the colder than average first four months of the year. Higher natural gas revenues have added $0.04 per share to our earnings year to date. Even after weather adjustments, year-to-date natural gas sales are up 4.1%, underscoring the organic growth we are seeing as thousands of customers each quarter continue to switch from oil to natural gas for heating their homes. We also remain on track to achieve our targeted 4% reduction in operations and maintenance expense this year.

On the strength of a cold first quarter, retail electric sales are up 0.7% in the first six months of 2014 compared to the same period last year, adding $0.02 per share to year-to-date earnings. Weather adjusted electric sales were essentially flat year-to-year -- or year-to-date, excuse me -- as the strong economic growth we are experiencing was offset by the impact of our energy efficiency programs.

Moving on to our local economy, we continue to see positive signs regarding economic conditions in our region, particularly around labor and construction activity. Of note, unemployment rates in Massachusetts dropped to 5.5% and New Hampshire's rate is now 4.4%. Both are lower than the national rate of 6.1%. In Connecticut, the rate has dropped below 7% to 6.7%. The unemployment rate in each state is at its lowest level since 2008.

Construction activity in the region has gained some momentum as significant commercial and residential projects are well underway in Boston and Stanford, Connecticut. Londonderry, New Hampshire is another area that has become popular with business development.

I should also note that Moody Analytics now characterizes the Massachusetts economy as one that is expanding rather than recovering, so we are encouraged by the signs that we are seeing on the economic front.

We continue to make significant progress on our integration and cost reduction efforts. In June, we completed the realignment of our information technology functions and we have now consolidated the vast majority of those facilities that we had previously identified for consolidation. Effective just today, we moved on to a new single accounting system, one of several IT conversions that we will be making.

Lower O&M, lower non-tracked O&M has added $0.03 per share to earnings compared with 2013. This is consistent with our plans to reduce operating costs by 3% to 4% per year through 2017.

I know that many of you have asked John and Jeff what impact the FERC ruling would have on our results beyond 2014. The rulings as they stand now would reduce our annual transmission earnings by $0.05 to $0.06 per share. Even if this negative outcome were to occur, we continue to feel comfortable with our 6% to 8% earnings per share compound average growth rate from 2012 through 2017.

Turning to other regulatory and legislative areas, there have been a number of developments so far this year. You will recall that earlier this year, Connecticut regulators approved CL&P's recovery of $365 million of storm costs that were deferred in 2011 and 2012. Those costs will be recovered over a six-year period ending in late 2020. Subsequently, the state's Public Utility Regulatory Authority issued another decision to offset the storm balance with $65 million of proceeds from a US DOE settlement. This decision now leaves the future storm cost recovery balance at approximately $300 million.

Some additional background on the $65 million refund, you may recall that a number of New England utilities were joint owners of three nuclear plants that shut down in the 1990s and were subsequently decommissioned. Those utilities filed suit a number of years ago against the US DOE for not accepting responsibility for the spent nuclear fuel that continues to be stored at the three former plant sites. These costs are all being borne by customers, so when the court ruled in favor of the plaintiffs, it ordered hundreds of millions of dollars of refunds. About $200 million of those refunds were paid in March of this year by the DOE to the companies that owned and managed the three sites. PURA ordered that CL&P's share of those refunds, proximately $65 million, be used to reduce the deferred storm balance, something that will enhance CL&P's cash flow this year while providing its customers with lower costs to be collected in the future.

Also in Connecticut, on June 9, CL&P filed a rate case that was mandated by our 2012 merger settlement agreement. CL&P is seeking a $117 million distribution rate increase effective December 1, 2014. The increase is essentially driven by the significant level of investments CL&P has made in its distribution infrastructure since the conclusion of its last distribution rate case more than four years ago.

Unlike previous CL&P rate cases, increases in operating expenses are not the reason for the revenue deficiency. CL&P's filing shows that O&M expense will actually be lower in the rate year ending November 30, 2015 than pre-merger levels in 2012. O&M will be lower by about $36 million, despite increased costs due to inflation. So, costs have declined while reliability and service have dramatically improved. Hearings in the case are scheduled to begin in late August and the draft decision is scheduled for December 1 with a final decision due on December 17.

Turning to Massachusetts, NSTAR Gas notified the Mass. Department of Public Utilities in May that just before the end of this year, it expects to file a rate case, its first request for new distribution rates in more than 20 years. New rates would become effective January 1, 2016.

Also involving NSTAR Gas, in June, Governor Patrick signed new legislation designed to expedite the replacement of aging distribution mains and to accelerate the expansion of the state's natural gas distribution networks. Lee will provide you with more detail on the new law from an operations perspective, but I will note that it allows mechanisms to fully recover the costs of both initiatives and is very positive for the state.

We also had some legislative activity in New Hampshire where the House and Senate passed a bill ordering the PUC to undertake a study to determine whether divestiture of PSNH's nearly 1200 megawatts of generation would be in customers' economic interest. The bill is now before Governor Hassan. The New Hampshire PUC would commence the review no later than January 1, 2015 and we believe it would likely be completed later next year. If divestiture is ordered, we believe that full cost recovery of any stranded costs is likely.

The New Hampshire PUC has indicated that, before it begins its divestiture review, it hopes to complete its review of the prudence of our scrubber investment in Merrimack Station. That scrubber has been operating extremely well during the nearly three years it's been in operations. Hearings are currently scheduled for October and we remain hopeful for a decision by the end of this year.

Before concluding my remarks, I should mention that we continue to be attentive to the RFP process that's being conducted by the New England States Committee on Electricity, or NESCOE, because it could provide a great opportunity to develop projects to meet the region's renewable energy and carbon reduction mandates as well as address wintertime challenges in providing New England with adequate electric power resources. NESCOE is actively working on RFPs for both electric and natural gas transmission and hopes both will be issued in the coming months. We are now reviewing a number of potential opportunities that we can be involved in, projects that would bring significant value to our customers and shareholders.

Now I will 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 to Jeff for Q&As. You will recall that, during our analyst day six months ago, I noted that we had a base capital forecast for our transmission and natural gas delivery business that could grow meaningfully as we identified additional initiatives that we would include in our forecasts. Now, six months later, I'm going to update you on some of those projects. And I should add that we are not done yet as New England's energy delivery infrastructure continues to change rapidly as the region decarbonizes its fuel mix and depends more on natural gas and renewables to power its economy.

I will start our detailed update of transmission in our NU's family of projects. We commenced construction of our $218 million section of the Interstate Reliability Project in March, and as of June 30, the project was approximately 40% complete. We're building the approximately 40-mile Connecticut section of the project to national equivalents building in Rhode Island and Massachusetts sections. National Grid received its final permit in May, and we expect all sections of the project will be completed by the end of 2015.

Turning now to the greater Hartford Central Connecticut Reliability Project, in mid-July ISO, New England's planning and advisory committee, met to discuss the series of solutions necessary to remedy overload and low-voltage conditions that exist today or will emerge in the near future across central and western Connecticut. You may recall that, initially, we had expected that a single new 3.5 KV transmission line from the Hartford area to the Waterbury area would resolve transmission issues in the region. Over time, that has evolved into a series of substation and line upgrades, primarily on the 115 KV system. Due to a larger scope of work, we now estimate that those upgrades will cost approximately $350 million compared with our earlier projection of $300 million. We expect to commence construction in the second half of 2015 and complete all construction in late 2017. We intended to comprehensively update you on our long-term transmission capital investment planned in early 2015, one that will include the refined estimate for the greater Hartford and other updates.

We continue to estimate that transmission capital spending of $664 million this year and have invested $272 million in the transmission system through June. While our detailed forecast only continues through 2017, I did indicate during our analyst day that we have identified between $350 million and $400 million of reliability projects in our service territory for 2018. We continue to work on plans for those out years, but our current estimate for reliability projects for 2018 is now $450 million to $500 million, up $100 million from our analyst day estimate just five months ago. Those additional investments will be almost borrowed against our electric franchise and they involve a combination of a new substation just outside Boston, a higher estimate for the Boston reliability project, additional physical security, and enhancements in a number of other smaller initiatives.

Turning to Northern Pass, the US Department of Energy continues to work on its draft environmental impact statement and is currently conducting fieldwork on the alternative routes it identified earlier this year. DOE has posted a target date of December 2014 on its website to issue its draft EIS. Once it is issued, DOE will accept public comments before issuing a final EIS. Once we receive the draft EIS, we will be in a position to file an application with the major site evaluation committee. We continue to discuss the project with key constituencies in New Hampshire, including businesses, labor, and environmental groups and public policy leaders. There is widespread rumor that the project is needed. The past winter has shown us how tenuous New England's nuclear electricity supply situation has become, and we know that this coming winter could well be worse, given no new firm natural gas supplies reaching the region, compounded by an number of non-gas generators being retired.

Two fossil units in Salem retired at the end of May, and the Vermont Yankee nuclear power plant is due to retire at the end of this year. Additionally, the current owner of the nearly 150 megawatt Mt. Tom coal unit in western Massachusetts announced in June that it would shut down for good this year. Together, those units reduced New England's non-gas-fired supply by approximately 1400 megawatts. So if you think about it, non-gas will not even replace all of its capacity (technical difficulty) in 2014 and much more capacity is scheduled to be retired by 2017.

Northern Pass is clearly a project (technical difficulty) and has a growing base of support in New Hampshire and the region. We firmly expect to build an even broader consensus that allows the project to continue to move along in the proper permitting process.

Before moving on to other potential transmission opportunities, let me mention that we have additional leadership in our transmission organization effective this spring. We have a new Transmission Vice President, Kathy Shea, who successfully developed our NEEWS projects over the last seven years. Kathy has assumed the role of Vice President of Transmission Development. In that role, she is looking at the new competitive transmission landscape, both inside and outside New England, which would include FERC order 1000 projects and other potential partnerships.

We've had numerous inquiries from many potential partners who find and use transmission development expertise and financial strength to be very appealing. Additionally, we believe that the six day NESCOE process that Jim discussed earlier will provide a great opportunity to develop non-reliability transmission projects beneath the region's renewable energy and carbon reduction mandates. We are now reviewing a number of opportunities that could be suitable to fit into this electric transmission RFP.

Moving on to natural gas, Jim noted our very strong sales this year. This occurred not only due to cold weather but also due to each company's increased customer count. In the first half of 2014, we added 4540 new space heating customers and continue to expect to add about 10,000 customers this year.

We continue to see strong interest in natural gas (technical difficulty) not only from individual homes and business owners but from entire municipalities. On July 7, Yankee Gas reached an agreement with the town of Wilton, Connecticut on the terms of our first large-scale gas expansion project. Wilton currently has a very limited gas delivery infrastructure. The proposed expansion will add 4 miles of new delivery infrastructure to the town for 2015 for our gas service and municipal buildings and a variety of commercial and other residential customers. The new (technical difficulty) Wilton consumption alone on its first pass will be approximately 70,000 MCF annually, an amount equivalent to an annual consumption of approximately 800 (inaudible) residential customers.

Yankee's Wilton expansion is the largest expansion project to be proposed under Connecticut's comprehensive energy strategy thus far. Yankee is also evaluating several other large-scale expansion projects and are in discussions with those towns at this time.

Jim has also noted that the new natural gas pipeline replacing and expansion legislation signed by Governor Patrick early this summer overall over the next decade which we now see three primary drivers and a significant expansion of our Massachusetts natural gas business. The first driver is a requirement under legislation to replace cast-iron and unprotected bare steel gas main over the next two decades. The second driver is the requirement in the new legislation that all Massachusetts natural gas distribution companies develop expansion plans. We are working to clarify and understand the filing schedule and the requirements. Once the plan is filed, the DPU will have approximately eight months to approve it.

The third driver is our need to make additional investments in our 3.2 billion cubic feet, or BCF, Hopkinton LNG storage facility. Because that facility is owned by an NU affiliate other than NSTAR Gas, we are working with the DPU on a mechanism to recover the significant incremental investment we will need to make in the facility.

At our analyst day in February, we indicated that there could be an upside to both our electric transmission and our natural gas distribution capital forecast. (technical difficulty) was forecasted to include the capital investments in our natural gas segment of approximately $215 million a year from 2015 through 2017, so three years. With the Massachusetts legislation initiative, that spending is likely to increase, and we are now reassessing those future investment levels.

Finally, I should note that our electrical service reliability was very good in the first half of 2014. We have seen about a 25% improvement in overall reliability this year as compared to the first half of 2013 with 200,000 fewer customers interrupted, and those customers that were interrupted on average being restored at least 10 minutes sooner than last year.

So, now I'd like to turn the call back over to Jeff for Q&A.

Thank you very much Lee. And I'm going to turn it back to Vivian just to remind you how to plug-in questions.

Thank you. We will now begin the question-and-answer session. (Operator Instructions).

Thank you Vivian. The first question this morning is from Julien Dumoulin-Smith. Good morning Julien. How are you?

Thank you very much. Doing well. So, first, if you can expand a little bit, you talked about potential opportunities on the gas side. Obviously NESCOE has got its own process going on here. Can you elaborate a little bit as to where you see that going? Could this ultimately result in ownership in Midstream as well?

This is Jim, Julien. Yes, it could. You may be aware that NU, UIL and National Grid filed a proposal to NESCOE indicating that, to the extent that the generators won't step up and commit to pipeline capacity for their electric generating units and the pipeline companies themselves, it tends not to be their business model to build on spec. We think that the utilities could play an ownership role partnering in a project that would solve the issue and costs could be paid for by the customers that benefit from it, which would be the electric customers throughout the region. So, that would involve ownership potentially.

Got you. How big of an ownership do you think -- could you kind of elaborate in terms of your thought process and timeline on getting at least a proposal here?

I really can't comment at this time. Obviously, pipelines are capital-intensive to build. It would depend upon the route and the design. But we would expect to see a significant investment if we were to go forward with a project along those lines.

Excellent. And then at the time of the analyst day, you talked about potentially accelerating certain capital investments, depending upon what happened with MPT and other factors. Can you elaborate a little bit on the potential for the acceleration? I suppose some of that was tied to some Boston related investments.

Yes. This is Lee Olivier, Julien. And if you think about it, we've added another $50 million to the greater Hartford Central Connecticut project over the period of 2015 to 2017. We added $100 million, most of it in the greater Boston area and some of it is with the greater Boston project. We also have a new substation we are building in Somerville, Massachusetts. It's new business security that is required through the NERC and FERC requirements and other upgrades and substations and replacement of aging infrastructure. So, that adds $100 million, so there's $150 million.

And we talked about the gas business. We had numbers in there from 2015 through 2017 of $215 million, and there is potentially up to approximately $150 million, $160 million more of investment during that period as well, so net over $300 million.

Excellent. And just the last question, kind of bigger picture here, what's your reaction ultimately to the latest FERC order on transmission? I mean does this change tactically your view in terms of investment in one bucket versus another or in terms of coming back to FERC? I mean how are you thinking about positioning the subject going forward?

The 10.57% ROE was actually in line with I think the Street's expectations. And if you look at what we reserved for that first complaint in the third quarter of last year, it was right in line with the outcome. So, that was not a surprise.

What was a surprise was what we see as a change in precedent if FERC is going to allow a second complaint to be heard, and more importantly, the impact that we interpret the order to be on incentives. There was no record on incentives established in the case, yet the consequences of the new mechanism that FERC is proposing is to dampen incentives.

You know we entered into projects for complex innovative technology, were incented to do so, and the consequences of this order is to actually cut into those incentives that were awarded. So, we have some real issues with the way that the two orders came out. However, we still see the transmission business as attractive business to be in. I don't think the 10.57% is particularly punitive. So, it's clearly a big part of our business strategy going forward, but we would like to see resolution of these concerns that we have.

Great. Well, thank you very much.

Thank you Julien. Our next questions come from Dan Eggers from Credit Suisse. Good morning, Dan.

Good morning guys. Could I, just on the gas volume and kind of the strength this year relative to the customer additions, if you were to break down that 4% of load growth, how much of that is being driven by the conversion part of the business and how much is being driven by just greater usage?

I think a big part is probably obviously the economy is improving, particularly and obviously the greater Boston area and in Stanford and (inaudible), there's about $4 billion of construction going on there. So, between new customers is there's a series of high-rise mid-space buildings that were signing up with Yankee Gas and the customers that we have connected over the course of the last four to five years, I think the majority of it is driven by either customers that have come online over the past few years and new customers that are coming online right now.

Dan, maybe another observation is we are adding about 10,000 customers a year to a 500,000 customer base, so just the customer count alone is a 2% increase. So not every customer obviously takes the same sort of load, but I think it's a combination of both increased usage per customer as well as increased volume of customers that we are adding.

Okay. And then I guess, on the NESCOE pipe, I guess the RFP is supposed to be kind of addressed by year end. Is that still a realistic timeline from your perspective, and what would we expect to hear in the investment community once the RFP is completed?

Dan, this is Lee Olivier. NESCOE will provide a schedule next month, so September essentially they will provide a schedule that will take us all the way through to the selection of the successful bids and the awarding of the bids, the filing of the FERC applications, both in gas and electric. So, we would expect to get a schedule on that in the September timeframe.

Okay. And I guess, just so I understand this, how are you guys going to structure this from a rate perspective? Have you figured out how this will get put into rates for the utilities to cover the cost? And are you going to run into any issues with FERC as far as rate design, given the fact that you are probably going to pass through a gas cost through an electric bill?

Yes. Well, ISO New England will file the tariff and the EDC customers will collect the tariff. And obviously it will go through a state process as well. But it will be ISO New England will file for a tariff and I think the electric transmission aspect of that would be very straightforward and there is precedent to do that. Probably not a lot of precedent on the gas side. That could be a little more difficult. However, there is a strong consensus with all of the leaders in New England, the governors, most of the congressional delegation who understand the need and understand the risks that the region is facing. So with strong congressional delegation support for this with FERC, we believe this will be successful.

And I appreciate the NESCOE opportunity. When you guys maybe spend more time kind of reflecting and strategizing for this coming winter from a reliability perspective and given the gains in gas customer usage, have you guys come up with any other solutions to help further enhance reliability this winter? And if demand response rules change on this FERC decision, is that going to incrementally complicate electric deliveries?

I think, on the gas side, clearly, we have all the gas lined up for our customers on the gas side, so for all the LDC customers, they will have firm gas supply (technical difficulty) this year. FERC will -- not FERC but ISO New England is in the process of doing another kind of fuel supply plan this year. Last year, they did, they purchased X amount of oil for the generators, non-gas-fired generators, that could burn oil as a backup. We were one of those participants with our Willington plant.

ISO has a similar scheme. It's slightly different but it's similar to last year. So, we believe that there will be sufficient oil.

We've also included LNG in the mix for generators, so LNG that could be purchased and gasified for generators. So right now, that is the plan. I wouldn't speculate what would happen around the DSM decision right now, but we're going to end up going from the winter with about 1400 megawatts of less gas-fired power plants, both nuclear and coal. These are the plants that ran continuously over the winter, last winter. So, it's going to be very, very challenging to get through this winter. So you're looking at a situation, if you have the loss of one large unit, like a 1200 megawatt nuclear unit where there could be serious threats and challenge to the -- of the region. So it's an impetus to get moving on the NESCOE initiative from both electric transmission and gas pipelines.

Okay, thank you for that. I appreciate it.

Thanks Dan. The next question is from Travis Miller from Morningstar. Good morning Travis.

Good morning. Thank you. On the transmission charges, if I understand, it sounds like you guys have taken the charges for everything retroactive, backward-looking. At what point do you -- will you then that $0.05 ongoing earnings or any additional charges as we move forward? Just give me a sense for that forward look.

The consequences of the new mechanism at FERC and the new base ROE would be that we would lose on average $0.05 to $0.06 a year that would come in ratably throughout the year. We would basically be earning less every quarter.

Does that start -- I guess what's the effective date more or less of that?

The effective date would be when this order that was issued is final, and that's expected to be in the fall.

This fall? Yes. Okay, thank you very much. Very helpful.

Thanks Travis. Our next question is from Paul Patterson from Glenrock. Good morning Paul.

Good morning. Just to sort of follow-up on the NETO clarification rehearing case, are you guys implementing rates based on the simply the base ROE or are you also taking into account what the upper end of the range would cut off the incremental ROE, if you follow me?

The reserve that we've established reflects the lower base, and it also reflects the upper end of the range as it impacts the incentives that we've earned through the two complaint periods. So, we basically booked it all.

Okay, so -- and just incrementally speaking, if you were to get the rehearing on the incremental part go your way, what might that mean financially?

Well, $0.05 of the $0.10 write-off that we just took would be unwound. And I would say, of the $0.05 to $0.06 going forward, about a third of it relates to the impaired incentive impacts that we are talking about.

Okay. And then just for the quarter -- I'm sorry if I missed this -- what was the weather adjusted sales growth number for the quarter system-wide on electric?

Electric second-quarter sales were down 2.9%, but weather adjusted would have been down 1.7%.

Okay. And then just finally on the NESCOE stuff, with the legislation that was in Massachusetts with respect to hydro and stuff, I don't know what happened to it, but it looked like it was running into some difficulty in committee. I think it might have not passed. I'm just wondering. With these opportunities, which I understand the logic and everything for them and the support that the leadership has, do you think there is any legislation that would have to be implemented at the state level to have either gas or electric projects associated with these infrastructure needs to take place, or is there anything -- I mean I guess what I'm just sort of wondering is I mean leadership might think something conceptually but when you actually sort of have to get something done, sometimes it doesn't always work out exactly. I'm just sort of wondering sort of strategically how you look at that and how you sort of address that since you guys have a lot of familiarity with it.

Paul, this is Lee Olivier. The bill did die yesterday in the Massachusetts legislature. The legislative season is over, so there will be nothing this year. And that bill was essentially all around giving the state authorization to go out and purchase energy. So that would allow them to go out and purchase large-scale energy from hydro, wind, and so forth. The bill is not needed as part of the UNESCO process, so this is a Massachusetts-only initiative. And a big part of that was all around meeting their carbon reduction goals, so they've got a goal of reducing carbon essentially the equivalent of 9 TW hours by 2020. So this would allow them to go out and purchase non-carbon, low-carbon fuel sources and meet that goal.

So, from the standpoint of NESCOE, what NESCOE is about is building infrastructure, once the infrastructure is built, whether it is electric transmission or gas in the place of let's say transmission, the EDCs, with the approval of the state regulators, will have that opportunity to go out and do purchases of energy over either long-term short-term. That would obviously have to go through the Public Utility Commission approval process, but that ability is still there. It would just roll up through the EDC which would go for approval with the PUC. So we don't see any other legislation that is needed for the NESCOE initiative to go forward as is.

Okay. That's great. Thanks so much for the clarity.

Thanks Paul. Our next question is from Greg Gordon from ISI. Good morning Greg.

Thanks. Good morning. When you look at the earnings growth aspiration, what is the baseline expectation for electricity kilowatt for sales, weather normal? And can you talk about that in terms of like customer growth versus sales growth? You talked about how the economy in the region definitely looks like it's taking off. I come to Boston all the time. I see all the new customers you guys are getting. How do you think about customer growth relative to sales growth and size of the expectation for kilowatt hour sales growth going forward?

Well, I think the guidance that we've given the Street, the long-term guidance, is 0% to 0.5%. So we're not anticipating modest -- significant rather sales growth in total. You are right that we are seeing customers get added. There is a lot of construction activity going on. Obviously, what we have in addition to that is we spend about $0.5 billion a year on energy efficiency. And it has an impact. So the usage per customer is obviously going down and offsetting the fact that our customer numbers are growing.

Now, the good news is, on the energy efficiency front, we have a pretty compensatory rate-making mechanism that allows us either decoupling recovery or loss base revenues recovery, and we're also provided an incentive if we do a good job in terms of executing the programs, and we get cost recovery currently. So, we can have revenue growth in spite of the fact that the kilowatt hour sales are somewhat flat.

Thank you.

Thanks Greg. The next question is from Andrew Weisel from Macquarie. Good morning Andrew.

Good morning. First question, maybe I misheard here, but the greater Hartford Central project, you upped the CapEx. Did the ISO identify their preferred solutions, or is this more making progress without a final answer?

Andrew, this is Lee Olivier. No. ISO has identified the preferred solution, so we and ISO agree on what the preferred solutions are. And we price those out and essentially it's another $50 million onto the initial estimate of $300 million.

Okay. Thanks for clarifying. Next, the Connecticut rate case, I believe you said hearings are in August. How soon could a potential settlement be reached? Would it be after the hearings?

Yes, I think we have a long history of rate settlements and we've had rate settlements that went up to the 11th hour right before an order was issued but hearings had been completed, briefs had been filed. And we've also had instances where settlements were reached before the case was even filed. So, it's a pretty broad range. It will depend on the perspective and the willingness of both parties. We are obviously in the due diligence phase right now, answering a lot of data requests that are I would think appropriate for the consumer advocates to get comfortable that the numbers are all supportable. So, we would hope to reach settlement in this case, but when that happens, it's hard to predict.

Would you be willing to give like a 1 to 10 scale probability of a settlement?

I can't do that because it takes two obviously to agree. But we do have a pretty good track record, including some settlements in Connecticut over the last couple of years. Some of them have been lower profile, but I think the fundamentals of the case, again, it's totally driven by the investment that we've made in Connecticut. We've done a great job managing costs. The rate request would have been much higher had we not done that. So, I think the basis suggests that we should get a good outcome here. But obviously in settlement space, the other parties need to agree to that. I'm not going to probability weight it.

Okay, fair enough. Then one last one on the NESCOE RFPs. If we take Northern Pass out of the equation, because that kind of has its own trajectory, would you be interested in proposing another Northern Pass like project? I think you mentioned some other opportunities. Roughly speaking, are those very large-scale, or would they be more smaller project?

Andrew, this is Lee Olivier. We are looking at a number of projects. Some of them are smaller, you know, anywhere from several hundred megawatts to 1000 megawatts. So, if there is a good number of projects that we have reviewed and we are in the process of narrowing those down to approximately half a dozen projects that we think could add significant value to the region that would connect transmission into where there are renewable resources, whether they are wind or hydro. So when the RFP process comes to fruition, we will be ready with several options beyond Northern Pass which we can offer into that process.

Great. Thank you.

Thank you Andrew. Next question is from Nick Yuelys, Gabelli.

I guess just on the transmission side, could you talk a little bit more about how the Order 1000 process will work in New England? And then I guess you mentioned some partners, and your thoughts on pursuing transmission projects outside of the region and what types of opportunities you see there.

Yes, in terms of the FERC Order 1000, FERC has not actually issued the order and how that will work. And so we don't have an outcome here from ISO New England, so we need ISO New England and FERC to concur on what those rules will be carried. You know, we have looked at with -- a potential FERC order is we kind of think would work with the impact of our current stream of investments and we think any impact will be minimal at best. So from that standpoint, we need to wait for FERC to issue the order and ISO to concur with it and put together the actual policies and the procedures to go with it. So I would say that's probably going to be something that's going to happen probably by the end of the year, my guess probably fourth quarter.

And so you are -- yes. NESCOE is really not using kind of the Order 1000 process. So, it's their own process which they can use in concert with ISO New England filing the FERC tariff. And that's -- the ISO New England rules have always had a provision in there that the region could, for the public good, go out and do separate RFPs.

I'm sorry, you last part of your question, Nick, is --?

I guess just you talked about having some interest in partners coming to you on transmission projects maybe outside of the region, what you see there.

Yes we've had we've actually had a number of potential partners come. We've actually looked at a lot of projects, quite frankly, around the country, some on the West Coast, others nearby. We are in discussions with some folks. It's one of these things that you may look at 20 different projects and there may only be one or two that you really think fit the profile in which you would want to invest in, which is there has to be a clear need for the project. It has to have FERC treatment in terms of being able to ensure that you can fully recover your cost, very similar provisions that we have here in New England. You know, we would like to have a partner that we feel very comfortable with, that is trustworthy. So, we looked at quite a few. Some we have chosen not to pursue, and others we are in the process of looking at now, which is the reason why we hired Kathy Shea to be our VP of Transmission Development. She's got the skill set, the business skill set, that we believe is needed for that along with Jim Muntz, who is our President of the Transmission business. So, as we look at those and we find some that we think are really viable, we will share those with you all.

Okay, great. Thank you very much.

Thanks Nick. Our next question is from Michael Lapides from Goldman. Good morning Michael.

I promised Jeff I wouldn't ask any questions about the trades your Red Sox made with my Cardinals. Lee, I apologize. Had a hard time hearing you a little bit. Can you summarize on the Transmission side how in total is your CapEx forecast different than what you disclosed at analyst day?

Okay. So big picture, Michael, it's $150 million higher, so $50 million more for the greater Hartford Central Connecticut project in years 2015 through 2017, and then we have about $100 million of other transmission. And again, that's everything from the new substation we are building in Somerville, Massachusetts to our Greater Boston project, which is a $550 million project going up by another $20 million. New physical security requirements that are mandated by NERC and FERC, so another $15 million, and a whole bunch of other smaller projects that are in the $6 million to $7 million range. So, that adds up to be $100 million. So, there is $150 million of more transmission than we talked to you about in the February timeframe.

Just to clarify Michael, the $50 million in the Greater Hartford project is within the forecast horizon, but the additional $100 million that Lee references is in 2018. I think Lee had provided an estimate of what we anticipated out in 2018, and right now have identified $100 million more spend.

Okay, so a little bit more backend loaded on that $100 million?

Correct.

Right.

Okay, fine. Any changes to your Northern Pass capital spend forecast timeline especially?

No, not at this time. There is no real changes at this time. Most of the investment right now is in DOE IS process and supporting that and doing early engineering and other environmental work around the site. So really no CapEx forecast changes at this time.

And finally, on Northern Pass, what happens now on the PPA process, given the Massachusetts legislation has kind of fallen by the wayside?

Yes. So, on a PPA, when the project is built, HQ will have the sole rights to the line and anyone can do essentially a bilateral deal that chooses to with HQ. They can negotiate a power purchase agreement with HQ over some duration. So, that opportunity is still there. And that, in all likelihood, would run through the EDCs. Obviously, with the PUCs approving a PPA, that very well still could be done.

Got it. Okay. Thanks guys, much appreciated.

All right. Thanks Michael. Our next question is from Rajeev Lalwani from Morgan Stanley. Good morning.

Two questions. The first, can you provide just the pluses and minuses from your old and new guidance for 2014? I'm just curious to know what the offsets are for the transmission. And my apologies if you provided that earlier.

And then the second question, is there any excitement around reformation and I guess particularly on the telecom side, any updated thinking there as far as interest in pursuing that?

Sure. On the pluses and minuses, fundamentally, we are absorbing a $0.10 hit that we got in the second quarter here on the FERC order. And in spite of that, the guidance has remained fairly robust. The previous guidance was $2.60 to $2.75. The new guidance is $2.60 to $2.70. So obviously it reflects what we've achieved year-to-date in the first two quarters but more importantly what our expectations are as we update what we think the potential is for the last two quarters.

On the REIT side, I know there's a lot of financial reengineering activity in the industry, whether it's MLPs or YieldCos or REITs. Some have tax advantages. Others don't. It's not clear to us, given the nature of our business, where a pure regulated transmission and distribution business. I think it's difficult to imagine how we could carve out assets for such a structure and that the regulators would be willing to accommodate that. Nevertheless, we are following the activities. We are interested in understanding the opportunities that could be there in the future for future projects, and we'll continue to monitor that.

Great. Thank you.

All right. Thanks Rajeev. That's the last question. So we want to thank you all for joining us today and have a great weekend, and call John or me if you have any more questions today. Take care.

Thank you ladies and gentlemen. This concludes today's conference. Thank you for participating. You may now disconnect.