康涅狄格電力 (ES) 2016 Q3 法說會逐字稿

Welcome to the Eversource Energy third-quarter earnings call. My name is Hilda, and I will be your operator for today.

(Operator Instructions)

Please note that this conference is being recorded. I would now like to turn the call over to Mr. Jeffrey Kotkin. Sir, you may begin.

Thank you, Hilda. Good morning, and thank you for joining us today. I am Jeff Kotkin, Eversource Energy's Vice President for Investor Relations. As you can see on slide 1, 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. 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, 2015, and our Form 10-Q for the period ended June 30, 2016.

Additionally, our explanation of how and why we use certain non-GAAP measures is contained within our news release and the slides we posted last night on our website under Presentations and Webcasts, and in our most recent 10-K.

Turning to slide 2, speaking today will be Phil Lembo, our Executive Vice President, CFO and Treasurer; and Lee Olivier, our Executive Vice President for Enterprise Energy Strategy and Business Development. Also joining us today are Werner Schweiger, our Executive Vice President and COO; Jay Buth, our Vice President and Controller; and John Moreira, our Vice President of Financial Planning and Analysis. Now I will turn to slide 3, and turn over the call to Phil.

Thank you, Jeff, and thank you all for joining us this morning. Today I'll cover our third-quarter and year-to-date financial results, provide an update on certain transmission projects, and discuss recent legislative and regulatory developments in the three states.

So let's start with the quarter on slide 4. We earned $265.3 million or $0.83 per share in the third quarter of 2016, compared with earnings of $235.9 million or $0.74 per share in the third quarter of 2015. Our transmission segment earned $0.28 per share in the third quarter of 2016, compared with $0.24 per share in the third quarter last year. The primary driver of the earnings growth is the higher transmission rate base, which is due to our continued needed investment in the reliability of the New England power grid. I'll summarize some of our key reliability-driven transmission projects in a minute.

On the electric distribution and generation side, we earned $0.53 per share in the third quarter of 2016, which is the same number as the third quarter of 2015. Higher distribution revenues were largely offset by higher depreciation, property taxes and interest costs.

On the natural gas side, we lost $0.02 per share in the third quarter of 2016, compared to a loss of $0.01 per share in the third quarter of last year. Higher interest and taxes more than offset the benefits of a rate increase at NSTAR Gas and the increased revenues from our natural gas infrastructure tracking mechanisms.

Turning from the third quarter to the year-to-date results, we earned $713.1 million or $2.24 per share in the first nine months of 2016, compared with earnings of $696.7 million or $2.19 per share in the first nine months of 2015. In our earnings press release, we reiterated both our 5% to 7% long-term growth rate and our 2016 earnings projection of $2.90 to $3.05 per share. At this time, we expect to finish 2016 somewhere in the middle of that range.

Transmission earnings totaled $0.84 per share in the first nine months of 2016, compared to earnings of $0.70 per share the first nine months of last year. In addition to a larger rate base, the 2016 period benefited from the absence of a $0.04 charge we recorded in the first quarter of 2015 to a Federal Energy Regulatory Commission decision on the first complaint against the returns on equity earned by the New England transmission owners.

Our electric distribution and generation segment earned $1.20 per share in the first nine months of 2016, compared with earnings of $1.32 per share for the same period last year. The decline was primarily due to the absence of a $0.09 per share total of benefits we recognized in the first quarter of 2015 as a result of resolving multiple regulatory proceedings involving NSTAR Electric. Additionally, higher depreciation and property taxes resulting from our ongoing investment in our distribution system reduced year-to-date earnings by $0.05 per share.

Our natural gas distribution segment earned $0.16 per share in the first nine months of 2016, compared with earnings of $0.18 per share for the same period last year. The milder first-quarter weather this year, which significantly reduced natural gas sales, were partially offset by rate increases at NSTAR Gas and continued customer growth.

O&M continues to be a very good story this year, as our employees continue to provide excellent reliability for our customers while also reducing costs. Lower O&M has added $0.07 per share to earnings so far this year, if we exclude the $0.05 of benefits we recorded in the first quarter of 2015 when we successfully resolved the bad debt dispute in Massachusetts.

Turning from our financial results to operations, our transmission investments totaled approximately $559 million in the first nine months of 2016, and we continue to target transmission capital investments of about $910 million for the full year. As you can see on slide 5, we continue to move ahead on our major transmission reliability projects across the system. We are making solid progress on our two large families of reliability projects, the Greater Boston Reliability Solutions and the Greater Hartford Central Connecticut Solutions.

Last month, we announced that we had received approval of the Merrimack Valley Reliability Project, our nearly $125 million transmission project in New Hampshire and Massachusetts, which we and National Grid are building. To date, we've invested $91 million in the approximately $565 million set of Greater Boston Solutions. We expect to conclude the final Greater Boston work in 2019.

As we've done in past years, we expect to provide you with our 2017 earnings guidance and our four-year capital expenditure projections during our year-end earnings call in February. I'll just cover one area now. During our July earnings call, we discussed the impact of a nine-month extension of the state review of Northern Pass on our 2017 capital budget. And we indicated that other projects were being identified to offset about $600 million reduction in projected Northern Pass CapEx in 2017.

In July, we noted an additional $200 million in transmission reliability projects, about $200 million of solar projects in Massachusetts, and $30 million to $50 million of additional investments in our natural gas distribution segment. Since then, we've identified about $50 million of additional transmission reliability projects above the original $200 million. And as we move through our 2017 budget process, that could go higher. We'll continue to evaluate additional opportunities as we move through the next few months, and give a complete update during our year-end earnings call.

I also want to touch on capital expenditures in our natural gas distribution segment. We've invested $180 million in that segment through the first nine months of 2016, up approximately 35% from the same period last year. This increase primarily represents an acceleration of cast iron and bare steel pipe replacement in both Massachusetts and Connecticut, an increased level of work this year in our Hopkinton LNG facility, where we are undertaking a $200 million upgrade, and increased expansion activity at Yankee Gas.

Now I'll turn to slide 6 and recent developments involving the legislative and regulatory bodies in Massachusetts and New Hampshire. On August 8, Governor Baker signed -- in Massachusetts -- signed an act to promote energy diversity. The bill requires the state to contract for 1,600 megawatts of offshore wind over the next 11 years in solicitations of at least 400 megawatts apiece. Subsequently, Governor Baker announced that several firms have acquired federal leases to attractive offshore wind sites that are 25 miles to 50 miles south of Cape Cod. Had also agreed to lease a location in New Bedford, Massachusetts for staging the construction activities.

Massachusetts is clearly positioning itself to be a national leader in offshore wind development. We look forward to supporting that effort, and believe there will be considerable opportunities for Eversource to build transmission over the coming decade to connect that offshore wind to the electric load. The act also calls for Massachusetts electric companies to commence competitive solicitations by April 2017 for nearly 9,500 gigawatt hours of additional clean energy annually. Again, we look forward to working with our policymakers on helping to provide the transmission links that will bring that clean energy to Massachusetts consumers.

As you are likely aware, the three-state clean energy RFP was conducted this year by Massachusetts, Connecticut, and Rhode Island. That concluded last week, with selections focused on small-scale renewables. And as a result, neither Northern Pass nor Clean Energy Connect was selected. The states chose only 460 megawatts of class-one renewables -- about two-thirds of that solar, and one-third, wind. Our two bids included hydroelectric generation that did not strictly meet the class-one criteria in the RFP.

We're focusing our efforts on the next round of contracting that is immediately around the corner. That involves solicitations for the nearly 9,500 gigawatt hours where the Massachusetts legislation explicitly allows large hydroelectric sources to participate. We believe that both Northern Pass and Clean Energy Connect would be excellent candidates for these next solicitations, due to their potentially significant impact on lowering carbon emissions. Northern Pass alone would reduce carbon dioxide emissions by 3.3 million tons a year, the equivalent of taking about 690,000 cars off the road. It may make Massachusetts roads safer, too -- I don't know.

Switching from the regulatory slide on slide 7, hearings begin tomorrow, actually, on our proposal to build up to 62 megawatts of solar generation in Massachusetts at a cost of about $200 million. Under legislation passed in April of this year, each Massachusetts electric utility is allowed to own and operate up to 35 megawatts of solar. Western Mass Electric already has 8 megawatts of solar under a prior authorization, so we can add an additional 27 megawatts. NSTAR Electric has none, so we could build 35 megawatts. A DPU decision is due by the end of this year, with construction targeted for completion by the end of next year.

In New Hampshire, the state approved JPMorgan as the auction advisor for the divestiture of our 1,200 megawatts of regulated generation. JPMorgan has submitted a proposal for conducting the auction, which the New Hampshire Public Utility Commission is now considering. That proposal calls for active marketing to take place in early 2017. We are targeting the second half of 2017 for completing the divestiture process. You recall that the New Hampshire legislation enables the recovery of all of our plant investment, either through the sale proceeds or through securitization.

Turning to slide 8, you can see the current status of the various return-on-equity complaints before the Federal Energy Regulatory Commission related to transmission investment in New England. The latest development involves the fourth complaint. On September 20, the FERC accepted the complaint, and subsequently, assigned a settlement judge to the case. If we do not settle, FERC expects that an order in the complaint would be issued in mid-2018.

We continue to record earnings based on our original October 2014 decision in the first complaint, even though that case remains on appeal before the DC Circuit Court of Appeals, where oral arguments have been scheduled for December 6. We look forward to seeing many of you who are on this call at the EEI Financial Conference. And now, I'll turn it over to Lee.

Okay, thanks, Phil. I'll provide you with a brief update on our major investment initiatives, and then turn the call back to Jeff for Q&As. Let's start with Northern Pass on slide 10. There's been a number of developments involving Northern Pass since our late-July earnings call.

On October 14, the New Hampshire Public Utility Commission issued an order authorizing Northern Pass to do business as a New Hampshire utility. In reaching its decision, the commission approved a settlement agreement between Northern Pass and the PUC staff that determined that Northern Pass had the technical, managerial and financial expertise to operate as a public utility. The PUC further concluded that, quote, granting Northern Pass authority to commence business as a public utility is for the public good, unquote. We are pleased to have received this important foundational ruling.

In September and October, the New Hampshire Site Evaluation Committee, or SEC, held more than 20 days of hearings or technical sessions on the project, which featured 10 panels of witnesses on topics that included system stability, reliability, project construction and historical resources. The sessions allowed intervenors to question our witnesses on all aspects of the project, based on testimony that was submitted as part of the SEC application last fall. We are very pleased with how well these sessions went overall. They were an excellent opportunity for us to demonstrate the thoughtful planning, design and engineering that we have already devoted to this project, and to underscore the significant economic and environmental benefits Northern Pass will provide to the region.

The next key milestone is the submission of intervenor testimony in mid-November. Reports from the state agencies that are reviewing the project are due to the Site Evaluation Committee by March 1, and we anticipate the final committee hearings starting in April of next year. A final written decision is expected by September 30 of 2017. If the committee issues a written order approving the 192-mile New Hampshire section of Northern Pass in September of 2017, we would expect to receive our US Department of Energy approval by the end of 2017. Based on that schedule, we should be in the position to construct a project during the 2018 and 2019 timeframe, as indicated on slide 11.

From Northern Pass, let's turn to Access Northeast on slide 12. On the state regulatory level, we've had a number of developments over the past few months, as you can see on slide 13. The most important developments occurred in mid-August, when Massachusetts Supreme Judicial Court ruled that under current state law, the Massachusetts Department of Public Utilities cannot approve natural gas transmission contracts signed by electric distribution companies.

As a result of that court decision, the Massachusetts electric distribution companies requested that they be allowed to withdraw the contracts between Access Northeast and Eversource's Massachusetts electric utilities, and National Grid. That request was accepted by the DPU last month. So there's no contract currently pending before the DPU related to Access Northeast.

In New Hampshire, the PUC ruled on October 6 that under current state law, it does not have the authority to approve natural gas capacity contracts for electric distribution companies. The ruling reversed a PUC staff finding issued a year ago, and was disappointing to us. In its order, the commission cited similar reasoning to the Massachusetts court decision, and even cited that decision in a footnote. Requesting reconsideration from the commission would be required before an appeal. The New Hampshire Supreme Court could be considered by Eversource New Hampshire.

There have also been developments in other states since our late-July earnings call. In Connecticut, the State Department of Energy and Protection, or DEEP, last week canceled the natural gas RFP it issued in June, noting developments in other states. It noted that it will continue to monitor the market and activities outside Connecticut, and could re-initiate an RFP any time. In Maine, a written order was issued last month affirming the PUC's July 19 vote to endorse a contract with Access Northeast, assuming the States of Massachusetts, Connecticut, New Hampshire and Rhode Island move ahead as well.

In Rhode Island, National Grid filed with state regulators a long-term contract for Access Northeast capacity on June 30. In September, the Rhode Island PUC placed a stay on the docket, and requested an update from National Grid in mid-January. We believe the PUC's action was appropriate, given the uncertainty in Massachusetts. Given the current status of the state regulatory proceedings, we are reviewing the changes we may need to make in the project's configuration to serve both EDCs and LDC loads. As a result, we believe the construction is not likely to commence until the spring or summer of 2019, which would represent a 9- to 12-month change from our previous estimate.

One fact that hasn't changed is the need for Access Northeast. Access Northeast is designed to address a critical problem we have in New England during the winter months -- the lack of access to enough natural gas to both heat our homes and businesses, and run our power plants. Access Northeast is uniquely positioned to address this problem since it passes through Connecticut and Eastern Massachusetts, the two most densely populated parts of New England, and touches 60% of the region's gas-fired power generation.

Slide 14 shows you the current natural gas supply situation in New England. Pipelines that reach us from the west through New York, Pennsylvania and Ontario, currently can deliver up to 3 billion cubic feet of gas per day on cold winter days. However, the region's LDC loads alone can exceed 4 billion cubic feet per day. The difference is bridged by vaporized and stored LNG, and by plants switching to oil and increasing their carbon output. Exacerbating this issue is the decline of the Eastern Canadian offshore natural gas production, which is likely to continue, further diminishing supplies for natural gas to the region.

Slide 15 shows what is happening with our region's generation fleet. New England has more than 15,000 megawatts of generation where natural gas is the primary fuel. Only about a third of that generation is dual-fueled. The other 10,000-plus megawatts only burn natural gas. And you can see that virtually none of the generation has firm natural gas supplies.

Our situation will only get worse as Brighton Pointe, Pilgrim and other non-natural gas units retire over the course of the next 2 1/2 years, are replaced by gas burning units. ISO New England is calling that situation precarious. We believe there are very real concerns around reliability unless significant additional sources of natural gas can be brought into New England. Earlier, Phil discussed the results of the three-state clean energy RFP. The projects selected for contract negotiations in the RFP will add some Class I renewable resources, but will do very little to address these natural gas capacity issues, which are most acute during the cold winter months.

And reliability is just one issue. You can see the price differential that existed in New England two winters ago on slide 16. Also power prices were about three times higher during the winter then they were during the previous summer -- costs that customers ultimately pay. In a normal year, the price differential is about $1 billion. In a cold winter, it is significantly more.

Ultimately, we firmly believe that the region's need for additional pipeline capacity to the west, and Access Northeast unique attributes, will result in our project moving forward. We and our partners, Spectra Energy and National Grid, remain committed to the project and the $1 billion a year in benefits it can bring to New England customers. The two paths into Massachusetts that we have identified involve contracting with the state's natural gas distribution companies for capacity and seeking new enabling legislation.

Regarding the legislative option, the Massachusetts Legislature will reconvene in early 2017. So a new statute -- similar to laws that have been passed in recent years in Connecticut, Rhode Island and Maine -- could be voted on by mid-2017. At a recent meeting of the Coalition of Northeastern Governors, Massachusetts Governor Baker expressed his explicit support for additional natural gas supplies for the state. And we believe there is significant support in the state to increase access of additional gas supplies, while we understand that there would be opposition to such legislation from various stakeholder interests, as there were in Connecticut before a similar law was passed there.

In regards to the natural gas distribution company option, I would remind you that the Kinder Morgan's Northeast Energy Direct project had signed several gas capacity contracts, primarily with Massachusetts and New Hampshire gas distribution companies, before Kinder canceled the project earlier this year. We are currently exploring whether Access Northeast can help meet the growing long-term gas needs of these distribution companies.

There's no question that both the region's electric and natural gas consumers need the additional pipeline capacity Access Northeast can provide. And that siting a project on an existing right-of-way and an existing LNG storage site is by far the most attractive option. Now I'm going to turn the call back to Jeff.

Thank you, Lee. And I'm going to turn the call back to Hilda, just to remind you how to enter questions. Hilda?

(Operator Instructions)

Mike Weinstein, Credit Suisse.

For Access Northeast, would changes to serve LDCs allow the project to proceed without the need for any additional legislation?

Mike, this is Lee. It would really depend on the scope -- in other words, the scale -- of those contracts that could be obtained. You had the Kinder project signed up nearly 500,000 dekatherms, half a Bcf, with contracts that had been approved by their respective regulators, and essentially, Massachusetts and New Hampshire. So once you start getting up around 500,000 dekatherms, that makes the project more viable. But we have not made a complete determination on that yet, because we still think there is a need for the EDC participation in the other states So we think there could be a hybrid solution of both LDCs and EDC contracts.

I guess what I'm thinking is that if it is not reliant on EDC contracts, then if you can get enough LDCs to participate, you wouldn't need any special consideration from the commission, just where electric customers are supporting the project.

Yes, that would be true, but it would likely be a smaller project than the 900,000 dekatherms that we originally outlined.

And on Clean Energy Connect, I think you mentioned that it now supports hydro power as well. I thought that Energy Connect was mostly from supporting wind power in New York State?

No, Clean Energy Connect was the combination of existing Brookfield run-of-the-river hydro facilities -- in other words, hydro facilities that are older, mostly depreciated -- and building a new wind by two other entities, which was Iberdrola and EDP. So you would marry up essentially 600 megawatts of wind, 700 megawatts of hydro. You would have ended up with about an 85% capacity factor over the line, with having the run-of-the-river hydro balance it.

Okay, I see. And just back on Access Northeast for a second. If the project begins construction in 2019, you're looking at getting it on line no earlier than the spring of 2020, or late 2020?

It would be late 2020, in the fall.

Okay, thank you.

All right, thanks, Mike. Travis Miller, Morningstar.

I was wondering -- you talked about the winter, and gas demand and stuff. As we go into the season, you talked a lot about the constraints are still there. What has improved since the last, say, two winters, when there were the constraints? Not so much last winter, but two, three winters ago?

The fundamental improvement for now, for this winter, would be that the Spectra Energy AIM Project, which delivers about 345,000 dekatherms, the first phase of that came on, on November 1, delivering about 245,000 dekatherms. And the remainder of that is expected to come on either later this month or in December, which would give you about a total of the 345,000 dekatherms. And probably the way to look at that is, if you had AIM in and then you retire Brighton Pointe next year, they kind of wash each other out.

Okay, got it. And then on the offshore wind stuff, what recognition among regulators is there that this would most likely lead to higher customer prices? Is that something that is being discussed and being considered at a high-level? Or is this just a run to get renewables into the mix?

I would just say on that, following what has taken place in Europe, and I think the US will serve -- will have a major advantage. Because Europe -- pretty much where most of this development started, was much higher on the cost curve, and they're coming down on the backside of the cost curve.

So you've seen costs as high as $0.24, $0.25 a kilowatt hour. Our recent tenders done in Europe and Holland for less than $0.10 per kilowatt hour. So we believe, with the economy of scale and the development in places such as Asia or in China, which is starting to take place now -- Taiwan -- you will see a fairly dramatic decrease.

I think the other thing you have to remember, too, is that the load centers in New England are on the shoreline. And if you have offshore wind, it's closer to the load, so therefore, your transmission cost declines significantly. And offshore wind comes on essentially 10 turbines at a time. It doesn't come on like a traditional generator where you spend five years building 1,000 megawatts, and one push of the button, it all comes on. Every 8 megawatts, it comes on. So it rolls in over time. It has a better cost recovery curve as well.

I think also, Travis, there is a recognition that there is a mix of solutions that are needed to meet aggressive carbon reduction targets as well. So you've got a mix of needs in terms of bringing more gas. Wind and solar play a part too. So there are many fronts that need additional supply to come into the region.

Okay, great. I really appreciate the thoughts.

Thanks, Travis. Paul Patterson, Glenrock.

I wanted to follow up on Mike Weinstein's question. If I heard the answer, it sounded to me that there would be a smaller project in the absence of the passage of Massachusetts legislation for Access Northeast. Is that correct?

Paul, this is Lee. I think it's too early to determine that, because we're still in the process of understanding the LDC load. I can tell you there is strong interest from the governors of the two bigger states that we have talked to recently, on having an EDC solution as well. And you've got Maine and Rhode Island that are still in the hunt. We recently met with the Connecticut governing agency, and their view is, is that: need some new solutions, but we fully support gas -- bring us back some solutions to consider.

So you've got three states that clearly want an EDC solution. And so it's kind of marrying up that with a large enough LDC solution to make for a project that will have a meaningful difference in the region in terms of reliability and price stability, and lowering the differential between the regions. As an example, ISO, MISO and PJM, which is about a 50% differential higher in the wintertime. So we're still advocating for a project upscale that can make that difference.

Okay. So I guess I misheard the -- I thought it sounded like you might be less than 900 dekatherms if it wasn't for the EDC participation in Massachusetts.

Yes, well, the question was, is that, if it was only LDC, would it be the same size of Access Northeast at 900,000 dekatherms? And the answer to that -- if it was only LDC, no, it would not be.

Okay. And that's only LDC in Massachusetts? Or is that -- I mean, the way it's -- let me ask you the question this way. The feeling I got is that, because of the Massachusetts Supreme Court ruling, the other states seem to have -- at least some of them seem to have some issues about going ahead with something without Massachusetts fully onboard. Is that a correct way of summarizing it? Or do you see it differently?

I think there needs to be a take of gas, and obviously the related revenue requirements with it, from Massachusetts. But if you go back and look at the previous contracts that were signed by LDCs in the old Kinder project, the majority of those are in Massachusetts. And of course, gas customers are electric customers as well, so it could be picked up by gas customers. But in essence, the state makes the contribution, because gas customers are electric customers.

I got you. And then, Phil made a statement about the renewable RFP, where the hydro bids or whatever were not selected. And it sounded like there might have been a technical reason for that. Did I understand that correctly? In other words, it wasn't conforming to -- it was an issue of whether or not the bids you guys had proposed did not conform to, what, some specific technical element of it? Is that the reason why it was rejected, or was there some other issue?

One aspect, Paul -- this is Phil -- is, subsequent to the RFP going out, Massachusetts passed specific legislation enabling hydro in terms of contracting. So certainly on the Massachusetts side, the legislation that came in subsequent to the RFP being issued provided the specific authorization. So the timing was: the RFP started, but then the legislation happened. So now we have specific legislation, as I indicated, to cover a solicitation for hydro in Massachusetts.

Yes, and I would add that, if you look at the statutory authority of the three states, they could have bought up to 5 terawatt hours of energy, and they bought 0.9 terawatt hours. So they bought 17% of what they were authorized to buy. The majority of that energy is in solar. And obviously on a cold winter day at 4 o'clock, you're not going to get any of that energy. And two-thirds of it is really solar. So they bought small facilities that are --

Why is that? Why didn't they buy more?

Well, it's just -- you've got three states, and they have different needs. As an example, Connecticut, on their carbon goal, was doing very good. In other words, they've got a goal by 2020 of 39 million tons a year; they are at 40 now. So they said: hey, look, we would just rather buy Class I renewables right now.

And as Phil said, Massachusetts, in that solicitation, didn't really have authorization to buy hydro. But now that they will -- in April, they will be able to buy a large tranche of hydro, almost 10 terawatt hours. So it's a little bit of the construct in the timing, but that is kind of how it ended up.

Okay. I appreciate it. Thank you very much.

Yes.

Thanks, Paul. Caroline Bone, Deutsche Bank.

I was just wondering, could you just talk about the options you have to offset the impact to earnings from a 9- to 12-month delay in Access Northeast?

Yes, I think that -- this is Phil, Caroline -- if you look at our growth rate through 2019, there's not a significant amount of Access Northeast in there. So if you assume that it's still in that time period, you're fairly close just in terms of the spending that, even with the delay, that it would not have a significant impact there.

So we would look, as we did mention with the NPT, if there's other transmission projects. And as you've seen, we found additional reliability projects. We have additional investment in our gas infrastructure, the Massachusetts solar program. So there's a number of initiatives that could fill that. But it's not a significant number.

Okay, fair enough. And then with regards to the transmission you guys might get involved with to connect offshore wind in Massachusetts -- I know this is kind of far down the road here. But you can you discuss how cost recovery would likely work?

How cost recovery would likely work -- that whole framework is still being worked out, being discussed, in flux. There's really no specifics. There's a couple notions. One, that the state could do kind of a broad RFP for a transmission highway that would interconnect the six parcels of water back into the mainland, and folks would bid on that. There could be one or multiple winners on that, for design kind of EPC construction.

And then the other one is basically that each developer -- which is pretty consistent with what takes place currently in Europe -- each developer bids their project. And they bid whatever -- 400, 600, 800, whatever the bid is in terms of megawatts. They build their own offshore substations, and they build the cables that run into the mainland and interconnect into the existing transmission system. Which really means, all that would be onshore would be a substation and an interconnection to the 345 kV grid. So it's not really been determined exactly how that will work, but that is a topic of discussion that is taking place inside of the Commonwealth.

Okay. And then just one final one, on a different topic. I know we have the NSTAR Electric rate case finally on the horizon. Can you just remind us how much rate base is currently at NSTAR Electric distribution specifically?

2.7, 2.8, in that range.

Okay. Great, that's it. Thanks, guys.

All right, thank you.

Thank you, Caroline. Shahriar Pourreza, Guggenheim.

Hey, guys. Sorry, I had to hop in late, and I apologize if this was addressed. Lee, let me ask you. So in Access Northeast, it sounds like a solution could be EDCs for states like Vermont, Rhode Island, Connecticut, and LDC demand in Massachusetts. Would the clean energy -- I'm sorry, the Kinder project that was canceled, the Northeast Direct, it sounds like out of 1 Bcf per day for Access Northeast, you could generally account for Massachusetts just by the customers that were signed up for the Kinder pipe?

There is a potential to get very close to that. So Massachusetts created a 42% hole in the project, and they couldn't sign contacts. That's about 400,000 dekatherms or so. And there is a fairly large LDC demand in Massachusetts as well. So it could come pretty close to that.

How is the dialogue going with the off-takers of the canceled pipe?

We have our folks at Spectra that really conduct that dialogue for us, because that's kind of what they do around the nation. So I could only characterize it as an ongoing process.

Okay, great. And then on New Hampshire, obviously with the recent ruling, it's 10% of the pipe. Can you theoretically just bypass New Hampshire and socialize the cost through the rest of the New England region, just given the fact that it's such a small piece of that pipe?

I think when the states, the regional states, all the states in the region, and led by their governors, quite frankly, put this construct together, it was with the understanding that each state would take its load share of the gas. So our view on that is, we still think there's an opportunity for having New Hampshire take their respective load -- which is not big, granted, as you said. But we're still committed to work with the other governors and work with the State of New Hampshire to find a pathway through, where they pay for their share of the gas.

Right. And then let me just ask you a little bit more sort of just top-level question on the growth. Obviously investors are going to shift to 2020 and beyond, especially now, given the delay of Access Northeast which hopefully, wasn't a surprise to people.

But the question is, knowing how you've been able to backfill your growth, knowing the reliability spending -- you've done a pretty good job about negating the delay of Northern Pass. Do you envision 5% to 7% potentially being put in jeopardy if Access Northeast is further delayed? Or do you have enough in that pipeline -- and no pun intended -- but do you have enough in that pipeline, and reliability of whatever spend that you have, that you don't envision 5% to 7% being impacted?

So I know you said you may have jumped on late. I think in the actual prepared remarks, I did reiterate our comfort and our guidance of the 5% to 7% earnings growth range. So we are very comfortable there. Also, as you know, in February, we will be doing an update of our outlook, and adding another year, and giving more visibility on the capital. And have sort of outlined, as you mentioned, the hole, and how to fill that in terms of transmission, gas, the solar project in Massachusetts. So we feel good about that rate, and we will have more information in terms of adding another year on when we get to the February time period.

Excellent. Thanks, guys.

Thanks, Shahriar. Mike Gaugler, Janney.

Nice quarter.

Thank you.

Given the delay in Access Northeast and other new-capacity pipeline cancellations, just wondering how you're thinking about new reliability projects, as the existing capacity has to be spread more thinly? Or wondering, has that optionality essentially been exhausted with the projects that are already announced and underway?

Mike, this is Lee. I think the reliability projects that had been built and are under construction and under review, are all traced to either situations where there is current overloads, or current violations of near-criteria. And so therefore, they are being built out to correct that.

Most of the future reliability -- future transmission, rather, that will be needed in the region will not be liability-based. It will be needed to connect renewables from a source, whether that is offshore, in Canada or northern New England, such as Maine, to get that renewable energy into the load. So its nature will be less around what we've done over the last 10 years, and more around interconnecting renewables to get it to the load.

And Michael -- this is Phil, too -- just in terms of the specific items. I know you're talking about additional or future items, but there's still several ongoing reliability projects that we have, that we're having significant spend on through the next several years in terms of Greater Hartford or Greater Boston and projects in New Hampshire which may need some additional transmission in New Hampshire, more than they've had in recent years. So there's good amounts in the pipeline, and as Lee said, the nature of some of that going forward could change. But the pipeline is robust at this stage.

All right, that's all I had, gentlemen. Thank you.

All right, well, thanks, Mike. That's the last question that we have this morning. So thank you very much for joining us today. We look forward to seeing many of you at the EEI conference next week. Take care.

Thank you. Ladies and gentlemen, this concludes today's conference. Thank you for your participation. You may now disconnect.