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Welcome to the Eversource Energy second quarter earnings call. My name is Sylvia, and I'll be your operator for today's call. At this time, all participants are in a listen-only mode. Later, we'll conduct a question and answer session. During the question and answer session, if you have a question, please press star then one on your touch-tone phone. Please note that this conference is being recorded. I will now turn the call over to Jeffrey Kotkin. Mr. Kotkin, you may begin.
Thank you, Sylvia. Good morning. Thank you for joining us. I'm Jeff Kotkin, Eversource Energy's Vice President for Investor Relations. As you can see on slide one of the slides that we posted last night, 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 U.S. 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 31st, 2016, and the 10-Q for the three months ended March 31st, 2017. Additionally, our explanation of how and why we use certain non-GAAP measures is contained within our news release and the slides we posted under presentations and webcasts and in our most recent 10-K. Turning to slide two. Speaking today will be Phil Lembo, our Executive Vice President and CFO, and Lee Olivier, our Executive Vice President for Enterprise Energy Strategy and Business Development. Also joining us today are Jay Buth, our Vice President and Controller, John Moreira, our Vice President of Financial Planning and Analysis, and Christine Vaughan, our Treasurer and Vice President for Regulatory. Now, I will turn to slide three and turn over the call to Phil.
Thank you, Jeff. Today I'll cover second quarter and first-half financial results, the status of key regulatory dockets, the status of our Aquarion Water Company transaction, and an update on our capital plan and several transmission projects. Let's start with the financial results for the quarter in slide three. Earnings were up $0.08 per share in the second quarter of 2017 compared with the second quarter of 2016. We earned $0.72 per share in the second quarter compared with $0.64 per share in the second quarter of 2016. On the electric distribution and generation side, we earned $0.38 per share in the second quarter of 2017, and that compares to $0.32 in the second quarter last year. This increase was primarily due to lower operations and maintenance costs.
We also benefited from higher demand revenues due to warm weather, warmer weather than the prior year. Our transmission segment earned $0.30 per share in the second quarter of 2017, and this compares to $0.29 per share in the second quarter of last year. The primary driver of this earnings growth was higher transmission rate base as we continue to invest in transmission projects that enhance the reliability of the New England power grid. I'll provide an update on key transmission projects that are driving this in a moment. The benefits from the greater transmission investment were partially offset by our annual reconciliation of costs and revenues from the prior year in accordance with FERC tariffs. This reconciliation takes place annually in the second quarter. On the natural gas distribution side, we earned $0.01 per share in the second quarter of 2017.
This compares to earnings of $0.03 per share in the second quarter of the previous year. Lower earnings were due to several factors: milder early spring weather, higher depreciation, and higher O&M costs. At the Eversource parent and other, we earned $0.03 per share, and this compared to relatively flat results in the second quarter of 2016. The primary driver was related to earnings from a long-held investment in a fund that invests in renewable energy projects. In total, through 2016, the earnings from this investment were pretty much break even. However, the market for renewable projects has matured and performed well over the past year, resulting in higher equity earnings in the second quarter from this investment of about $0.02 per share, and this compared to a small loss of about $0.01 per share in the second quarter last year.
Going forward, we don't expect ongoing earnings from this investment will have a material impact on the earnings. Turning from the second quarter to the first-half results, we earned $1.54 per share in the first six months of 2017 compared to $1.41 per share in the first half of last year. Improved results were due to higher transmission earnings, higher distribution revenues, lower O&M, and improved results of the parent. For the full year, we continue to expect to earn between $3.05 and $3.20 per share, and for the long term, we continue to project 5%-7% EPS growth. From operations, I'll turn to our regulatory activity and start in Massachusetts with the Massachusetts rate case, and this is on slide four. Hearings have concluded on the rate case except for rate design topics.
We expect a decision on the financial aspects of the case by the end of November with the rate design decision around year-end. New rates would be effective in January of 2018, and to date, we've had no surprises in the rate review process. In New Hampshire, binding bids on our Public Service of New Hampshire generation fleet are due next month. There too, the overall divestiture process is moving along well, and we expect regulatory approval of the sale by the end of the year, with securitization activities to follow soon after the closing. From our state regulation, I'll turn to slide five and the various New England transmission ROE dockets before FERC. As you may recall, on April 14th of this year, the D.C. Circuit Court of Appeals vacated FERC's 2014 order that lowered the base ROE for the New England transmission owners from 11.14%-10.57%.
Before FERC commissioners is not only the vacated order from that complaint one, but the ALJ recommendations from complaints two and three, which have not yet been decided. It's unclear whether FERC will issue orders on all three complaints at the same time, or what the timing is of when this will occur. We've been conferring with other New England transmission owners about the appropriate billing for transmission service in New England in light of this April court decision and the four pending complaints. In June, the region's transmission owners, including Eversource, filed with the FERC to revert back to the last approved ROE that was approved at 11.14%. In the filing, the transmission owners proposed that the rate be effective on June 8th, and billing on the new rate to customers would not start until 60 days after FERC has a quorum.
As we all know, that has not occurred at this time. The financial results we reported last night still reflect the 10.57% ROE and the 11.74% cap on incentives that was vacated by the court. Our transmission revenues are based on what we bill to customers. Therefore, there will be no change in our transmission revenues until our rates are changed prospectively. As a reminder, every 10 basis points of change in transmission ROEs results in about a $3 million after-tax earnings annually. Next, I'll turn to slide six and the exciting announcement we made last month. On June 2nd, we announced an agreement to acquire Aquarion Water Company from Macquarie Infrastructure Partners and others for approximately $880 million in cash and assumption of $795 million of Aquarion debt.
Aquarion is a very well-managed water company with operations in the three states we already serve, Connecticut, Massachusetts, and New Hampshire, with 90% of the operations being in Connecticut. Several weeks ago, we filed regulatory applications in each of the states seeking permission to consummate the transaction, and we expect to close the deal by the end of this year. Connecticut, as I said, where 90% of the business is located, has already established a schedule with a final decision due before the end of October of this year. This transaction fits very nicely with our strategy to invest in critical infrastructure and to develop clean energy solutions for customers. Macquarie had owned Aquarion for a decade, and its decision to sell the business coincides with our divestiture of PSNH's generation fleet. In addition to being an excellent strategic fit, the timing of the opportunity was also good.
We are exiting a generation business that was shrinking because of state statutes that precluded us from any expansion, and we're entering a water distribution business that we expect will see decades of growth ahead due to the need for replacement of aging infrastructure. We expect Aquarion to help support and extend our projected 5%-7% EPS growth. We'll not be issuing any equity in association with this transaction. The cash portion of the transaction will come largely from the net proceeds from the sale and securitization of our New Hampshire generating assets. As a reminder, nearly $800 million of gross proceeds are expected as part of that transaction. We anticipate that Aquarion will operate pretty much as it does now post-closing. As you know, we are not currently in the water business.
We also expect Aquarion's earnings to substantially offset the loss of PSNH generation earnings, and we expect Aquarion's earnings to grow over time as we invest needed capital in the business. Connecticut has a constructive regulatory structure for water companies that includes revenue decoupling and infrastructure investment tracking mechanism, and the ability to include in rate base acquisition costs related to the purchase of small, financially distressed water companies. There's much fragmentation in the water business today, and over the last several years, Aquarion has acquired over a dozen smaller water systems, and I expect this trend will continue. We're very excited about the additional business diversity and long-term growth opportunities the water business will provide. We're also very pleased that Aquarion will be located locally and owned locally.
Before I turn the call over to Lee for the status report on some of our major projects, I want to provide you with our customary mid-year update on capital expenditure plans. Our capital expenditures total about $1 billion in the first half of 2017, up about $100 million from the first half of 2016. Transmission investments totaled approximately $375 million in the first half of 2017, and we continue to target nearly $1 billion in transmission investments for the year. As you can see on slide seven, we continue to make progress on a number of the major transmission reliability projects. Wanted to spend some time discussing Northern Pass spending. Northern Pass accounts for $21 million of our transmission capital invested this year, and we expect that number to rise considerably beginning next year.
We will provide you with an update of the project in a moment. As you can see in the slides and from the press release relating to our Massachusetts RFP we issued yesterday, we are now anticipating a second half of 2020 as the in-service date for the project. We expect that the vast majority of the work on Northern Pass will be completed in 2018 and 2019, but we do expect a few hundred million dollars of the project will move into 2020. We are currently developing detailed operating plans for 2018 and beyond. We fully expect to provide an overall capital spending plan for 2018 that is consistent with the plan we released earlier this year. We expect to offset the lower level of expenditures in Northern Pass in 2018 with increased investments in electric resiliency programs, natural gas infrastructure capital, and natural gas expansion projects.
We also expect, depending on the exact closing of the timing of the Aquarion transaction, a nearly $100 million of capital expenditures at the water business. We will provide you with specific capital expenditure levels for 2018 through 2021 for all segments when we update our long-term forecast in February. We expect these investments to fully support our projected 5%-7% long-term EPS growth rate. With that, I will turn the call over to Lee.
Okay, thanks, Phil. I will provide you with a brief update on our major investment initiatives. Then turn the call back to Jeff for Q&A. Let's start with Northern Pass in slide eight. The New Hampshire Site Evaluation Committee has completed more than 20 days of final evidentiary hearings for the project. Remaining hearings are scheduled to run through September. We have been quite pleased with how they have proceeded so far. We consider the New Hampshire SEC schedule to be supportive of the project, receiving all of its approvals necessary to commence construction in early 2018. Hearings in June and July focus on construction of the line, its impact on the region's power prices, and the considerable effort we are devoting to minimize the environmental impact of the project. We believe our witnesses have made a very persuasive case as to why the project should be approved as proposed.
It will bring billions of dollars of benefits to the State of New Hampshire, including an estimated $60 million a year in electric market savings, $30 million-$35 million a year in property tax revenues, $200 million over a 20-year period as part of the Forward New Hampshire Economic Development and Clean Energy Fund. Up to 2,600 jobs during the construction period. We have pledged to give priority to New Hampshire residents and businesses for construction work. In addition, the SEC permit will need to secure a presidential permit from the U.S. Department of Energy. According to its website, the DOE expects to issue a final environmental impact statement in August. That will position the DOE to issue a presidential permit by the end of this year.
We continue to expect Hydro-Québec to receive its final national and provincial permits for the Canadian portion of the project later this year. The New Hampshire PUC already has reviewed a number of items related to Northern Pass. Last year, it authorized Northern Pass Transmission to operate as a utility in the state of New Hampshire. In June, the New Hampshire PUC approved NPT's licenses to cross public waters and lands. Additionally, both the New Hampshire Department of Transportation and the State Department of Environmental Services have approved the necessary permits to construct Northern Pass, subject to final approval by the New Hampshire SEC. Receiving the New Hampshire SEC and presidential permits by year-end would support commencing construction in early 2018.
You may recall that during our first quarter earnings call, we noted that we expected to firm up our construction schedule around this time after concluding a comprehensive review of the project with our equipment vendors and contractors. We have now completed that review with a particular focus on the timing and cost of the converter station and the 60 miles of underground cable. We also wanted to get through certain key elements of our New Hampshire SEC testimony, particularly the seven days of hearings on construction, which ended in June. Based on our firm contracts, we expect that if we receive final permits for the project by the end of this year, we can complete the project in the third quarter of 2020.
At that time, Northern Pass would be fully constructed and operational testing would commence, allowing the project to enter service prior to the critical 2020 to '21 winter period. We believe the schedule would put us significantly ahead of any other major project to import Canadian hydro into New England. Our confidence in the construction schedule is also supported by the firm contracts we have with two of the most preeminent firms in the world in terms of electric transmission design and construction, ABB and Quanta Services. Turning to Slide 9. Yesterday, Eversource Energy Transmission Ventures and Hydro-Québec jointly bid Northern Pass into the Massachusetts Clean Energy RFP. We believe that this bid will be extremely competitive in the Massachusetts solicitation due to the advanced stage of our project development. To remind you, by 2022, Massachusetts is required to contract for 9.45 terawatt hours a year of clean energy.
Page one of the RFP states that of the total 9.45 terawatt hours of cost-effective clean energy contracts being sought in this RFP, the distribution companies encourage proposals which include clean energy generation able to commit to begin deliveries prior to the end of 2020 to maximize the Commonwealth's ability to meet its Global Warming Solutions Act goals. We believe that these provisions support our joint bid since we are so much further along the project development process than other bidders. Additionally, Northern Pass would reduce Massachusetts' electric sector carbon emissions by 25%, and as a result, get Massachusetts halfway to its mandated reduction for the sector by 2050. The current Massachusetts RFP schedule indicates that projects will be selected for negotiations by January 25th, with regulatory filings next spring.
Separately, an RFP exclusively for offshore wind was issued to the market at the end of June, with bids due December 20th and expected contract filings with the DPU by the end of July 2018. The RFP calls for interested bidders to submit a conforming proposal for 400 MW. It also stated alternative bids for up to 800 MW would be considered if bidders can show that a larger project would provide significant net economic benefits to customers. Bidders can also submit an alternative bid for as little as 200 MW. Bay State Wind, a 50/50 partnership between Eversource and DONG Energy, will bid into this RFP. [Bay State Wind] is 300 square off the Massachusetts coast is a very attractive location and is expected to be able to host wind turbines capable of producing at least 2,000 MW.
In addition to Massachusetts, the track could serve three other states that are expanding their solicitations for clean energy. In New York, Governor Cuomo announced a goal of procuring 2,400 MW of offshore wind, with the first RFP expected early next year. Rhode Island Governor Gina Raimondo has announced a goal of procuring 1,000 MW of clean energy by 2020. In Connecticut, Governor Malloy signed Public Act 17-144 last month, allowing offshore wind to be considered as part of a new RFP for clean energy resources, which would also include utility rate-based fuel cells. It's going to enable construction of approximately 200 MW of offshore wind. The timing of any solicitation will be at the discretion of the Connecticut Department of Energy and Environmental Protection, but it shows yet another legislative effort by a New England state to bring more clean energy resources into the region.
Additionally, earlier this week, the Connecticut Department of Energy and Environmental Protection published a draft of the state's updated comprehensive energy strategy. The strategy focuses on five major themes. They are: decreasing carbon emissions, increasing the supply of renewable energy, including expanding the state's Class I renewable requirements to 30% by 2030, and prioritizing low-cost, grid-scale renewable energy investments, expanding energy efficiency initiatives, including procurement of energy efficiency as a resource, supporting grid modernization, and accelerating electrification of the state's transportation sector. We believe Eversource Energy is uniquely positioned to support each of these state policy initiatives. With Connecticut, Massachusetts, Rhode Island, and New York all driving policies that favor efficient offshore wind development, we expect significant interest in Bay State Wind's potential over the coming years, and we have begun to make early progress on siting.
About a month ago, the Bureau of Ocean Energy Management issued to Bay State Wind the first approval of an offshore wind site assessment plan in the United States. This will allow us to take critical measurements of wind and wave speeds over the next two years to prepare for project development. Finally, turning to Access Northeast, we continue to discuss the gravity of New England's wintertime energy supply situation with policymakers in Massachusetts and New Hampshire, the two states that do not have legislation clarifying electric utilities' ability to sign natural gas supply contracts. Brayton Point, the region's largest coal and oil-fired generation plant, shut down permanently June 1st, and the Pilgrim Nuclear Plant will shut down in less than two years. ISO New England continues to express deep concern over the region's ability to meet both gas heating and electrical requirements during winter periods.
Later this year, ISO is due to issue a report on the challenges New England will face in future winters if no significant firm fuel capacity is available for the region. While we are confident that Access Northeast remains the region's best option for adding needed natural gas pipeline capacity, we also know that the project's ultimate size and configuration will depend on what kind of solution our states want to pursue to ensure electric grid reliability and to integrate renewable power sources into the New England grid. Because of that lingering regulatory uncertainty, we and our Access Northeast joint developers, Enbridge, National Grid, withdrew pre-applications from FERC last month.
FERC has a very busy calendar, particularly for siting of natural gas pipelines. We thought it best to withdraw our project from preliminary review until we are able to bring more certainty to the question of who will be the counterparties that will purchase long-term pipeline capacity from Access Northeast. We expect most of the work that we've already done on the project can be used in a future refiled Access Northeast application. We have no question that the region's wintertime gas supply situation continues to worsen, with generations such as Brayton Point retiring and more natural gas-fired plants being built, and the region's homes and businesses continuing to install tens of thousands of new natural gas space heating systems annually. However, we need state energy policy to be more consistent across the region, particularly in Massachusetts and New Hampshire.
We expect to refile a preliminary application with FERC for Access Northeast once we have a clear path to resolving the current inconsistencies in policies. Now I will turn the call back to Jeff for Q&A.
Thank you, Lee. I'm going to turn the call back to Sylvia, just to remind you how to enter questions. Sylvia?
Thank you. We'll now begin the question and answer session. If you have a question, please press star then one on your touch-tone phone. If you wish to be removed from the queue, please press the pound sign or the hash key. If you're on a speakerphone, you may need to pick up the handset first before pressing the numbers. Once again, if you have a question, please press star then one on your touch-tone phone. Now I'll turn the call back to Jeff.
Thank you. First question this morning is from Michael Weinstein from Credit Suisse. Good morning, Mike.
Good morning. Thanks, Lee, for that great update. Maybe we could just talk a little about why is it a full-year delay for Northern Pass? How come not the spring of 2020? What equipment exactly is proving to be critical path items that extend the schedule at this point? Separately, how critical is winning the RFPs to keeping the project on track? My understanding is that it's not critical. What happens if you lose? I understand there's other opportunities in these other states that will be coming next year. How critical is it to keeping the project on track?
Sure. Just to get to the first part of your question, Mike, the HVDC converter technology is the critical path, along with the underground, what they call XLPE cable, so those cables that have no oil in them. Those two components are the critical path. Both HVDC converters and that particular kind of cable is in strong demand around the world. There is long lead times for both of those. Each HVDC converter, there is nothing on the shelf, so to speak, that you can use and you backfit for a particular application. Every design is a completely unique design. It's just the time that we've got from a manufacturer, ABB, of the cable and HVDC converters, and it's really the limiting factor there. It's just how much they have in the queue and where we show up in the queue.
It's really no more complicated than that. In regards to the project, whether we win the RFP or not, we are committed to build the project, and HQ is, I have stated, there is a lot of opportunities in all of these states for clean energy. If you look at where the region is and the precarious position of the region, absent a dedicated firm fuel supply, particularly natural gas, you are going to need more firm energy like Hydro-Québec has to offer into the marketplace. You probably, I'm sure, have seen where the largest nuclear operator in the region is now inquiring through ISO what it would take to retire those assets, what that process looks like. They haven't made a commitment to go do that.
I think, in any case, whether that's done now or later, all of those assets time out, and if the region wants to meet its goals around carbon reduction and Class I renewable energy as well as clean energy, you will have more hydro coming in from Eastern Canada and Quebec to help satisfy that. We're confident that the project will get built irregardless of the outcome of this RFP.
Okay. In terms of the FERC transmission complaints, is this plan to refile to revert back to the old ROE, has that been discussed with other interveners in the case? What's your sense right now of how that's going to proceed going forward? Is there going to be a settlement process that ultimately resolves where the ROEs eventually land?
Sure, Mike, this is Phil. The filing was done by consultation with the New England transmission owners because we needed to have a rate that we could bill customers. Given that the decision of the D.C. Court vacated complaint one. We needed to have a rate on file that we could start billing our customers with. This was a consultation and a filing with the New England transmission owners that was made in early June. As you know, there's really not a forum or a quorum at FERC at this time to review that. We have not changed our billing until we move through that process. In terms of settlement, we've tried. In each of these complaints, there has been settlement process, and that's the traditional FERC process is to start that. We have not, in any of those cases, reached any settlements.
I guess one could always be reached in the future, but I guess at this stage, we're awaiting a quorum so that the case can be reviewed, and we can move forward.
Okay. One last question on Aquarion. How far in the process are you right now at looking at further acquisitions of distressed assets that are out there? Is this something that we should expect to hear within fairly soon after closing the deal, like early next year?
I can say Aquarion, they're a privately held company right now. But if you look at their track record over the last many years, there's about 12 different smaller financially distressed systems that have been, let's call it, tucked in under the Aquarion umbrella. That's about 11,000 additional customers. There's 230,000 customers now. Certainly, there's more of these types of systems out there as you get aging infrastructure, more requirements for clean water, that type of thing. Just given that kind of track record, I would expect that to continue.
If I just do the quick math, 11,000 customers on 230 now, that's about 5% increase in size. Is that sort of the opportunity on a dollar basis that you might be looking at as well?
No, it's very fragmented. Some of these systems may be five or six customers, some could be 1,000 or two. It's hard to say. Certainly, you have to match up the need with the opportunity. The 11,000 over the last five years is just an indicative number as to the process that's out there. I think if you look around the country, you'll see that this type of activity goes on.
Yeah. All right. Thanks a lot .
Thanks. You're welcome.
Thanks, Mike. Next question is from Paul Patterson from Glenrock. Good morning, Paul.
Good morning. How are you?
All right. How are you?
All right. Just to sort of follow up on Northern Pass. Is it safe to say that you guys are going to be participating in the upcoming capacity auction? Is Northern Pass going to be participating in it?
Yeah, Paul, this is Lee. The capacity auctions, the participation of that will be determined by HQ. They are in the process of evaluating that option right now, and I can't tell you what their conclusion is.
Well, let me ask you this. If you don't clear it, how is capacity going to be provided with respect to the Massachusetts RFP?
Well, the RFP is not hinged on capacity. It's really all hinged upon the things like price suppression, carbon reduction, obviously the cost of the project. Those are the things that it hinges on. If it gets capacity as well, that's an added benefit to customers in Massachusetts and into the region.
Right. You would think that would be part of the value that the project would provide. It would seem kind of strange to me, I'm sorry to be so slow on this. Why capacity wouldn't be something that you guys would want to have value being reflected in terms of the project?
Yeah, it clearly would be, Paul. I just can't tell you exactly right now where HQ is on that, but it clearly would be part of the value proposition for the state and the region.
Okay. With respect to the determination on MOPR, when would we find out how ISO New England officially will be treating Northern Pass and the issue of MOPR?
Well, one of the things that HQ has to do is to actually submit a formal request to ISO New England to have them evaluate Northern Pass vis-à-vis the MOPR requirements. They have not done that at this point.
Okay. You mentioned that if the Massachusetts RFP doesn't happen, you feel there's enough opportunity out there, which makes sense for the value of the project. I'm just wondering, do you think the project would proceed in the absence of some sort of contractual setup, such as the Massachusetts RFP or some other state-sponsored program? That there's enough confidence that you just simply proceed with the project and hope to get something, regardless, if you follow me?
I follow you, Paul. I think where we are right now is we think our project has all the attributes that it will be the winning project in this RFP. If for some reason we don't win this RFP, we'll take a
A pause. We'll take a look, and we'll look at where the other states are in those RFPs and that process, and we'll make that decision at that time.
Okay, fair enough. Just finally, the sales growth, weather adjusted year to date. I'm sorry if I missed it, just really busy, but I didn't see anything on that. Could you tell us where, for just system wide, you guys are in terms of retail electric sales growth year to date, weather adjusted?
Yeah, the normalized, Paul, is down just less than 1% on a normalized basis year to date.
Okay. Thanks so much.
You're welcome.
Thanks, Paul. Next question is from Michael Lapides from Goldman. Good morning, Michael.
Hey, good morning, guys. Real quick, just trying to think about the offshore wind process. Can you talk about let's talk about the timeline, both not just for the RFP responses, but then the DOE approvals for the tracks out in the ocean, and then kind of the other siting and permitting for where the line would potentially terminate in the U.S. onshore. How do you think about cradle to grave, what the timeline is from the RFP process to actually having an operating asset?
Yeah, Michael, this is Lee. In regards to that, I think, obviously we've got a pretty good line of sight around the Massachusetts offshore wind RFP and the process, and we've got timelines as issued inside of the draft. Then it really becomes, what is the timeline from the Bureau of Ocean Energy Management, which falls under the interior secretary's office. That's kind of, I would call that kind of a work in progress. That they've got kind of a draft timeline out there. We will be meeting later this year with staff in the office of Bureau of Ocean Energy Management, and we need to work with them a lot. Clearly, there's other stakeholders here. There's a lot of offshore wind developers that will be working with the interior department as well to finalize what that process is.
I think if this is 2017, I think that it's realistic to see the first tranche of wind in service by the end of 2022 timeframe. Based upon the feedback, obviously, we have from DONG Energy, who's built a lot of this all over the world. We feel the first part of this wind farm would come on in 2020. Because, as you know, it's not like building 2022, rather. It's not like building a large power plant. You string six of these things together, and the first six of them show up onto the grid. Every time you add another six more of them come onto the grid. It's kind of a phased in, you have early revenue production in that process.
Got it. Phil, you talked a little bit about your capital spending plan and budget, and I know you're going to give more detail either at EEI or at the fourth-quarter call. Can you just kind of rehash a little bit of that and maybe give a little more clarity? Where specifically would you see an uptick in kind of traditional, whether it's transmission or distribution CapEx in 2018 relative to what your prior forecast showed?
Sure. I guess I'll preface it by saying, I think we have very good line of sight, even as we sit here today without moving through too much time through the rest of the year. We still have our budget process to go through, et cetera. Really, at this time, have a very good line of sight. Just to remind you, too, that we've been repeatedly able to deliver these results. If you think back to our February plan, we added $1 billion of capital from the previous plan that had been submitted. Certainly, we have a track record to be able to deliver these results, and really with a focus on cost control that's unmatched in the industry.
We can deliver the results, take costs out of the business, improve our reliability, provide great service to customers, these are all great aspects of our company. We do have an experienced team. We have a strong balance sheet. If we look at it, as Lee mentioned, there's going to be additional infrastructure needs. There's going to be likely more clean energy growth opportunities. To be specific about the things, in terms of electric distribution, we have in our gas distribution business, we have these reliability enhancement programs that help to improve that service reliability on both the electric side and the gas side. We have aging infrastructure replacement and our gas expansion program in place that we expect to have incremental spending in both of those categories that is fairly significant in 2018 from our original estimate.
As I mentioned, the water business, Aquarion, again, depending on the exact closing date of that, there's a robust capital spending program in there. Those are really some of the major categories. You could see others develop as we move through the rest of the year.
Got it. Can you quantify? Is there a way to quantify how much incremental CapEx would likely come relative to kind of the movement of Northern Pass?
What I can say is we fully expect to replace the spending. In terms of the detail level and number, I'll have to hold off on that. The short answer is we fully expect and have a good line of sight to replacing any movement of spending out of 2018.
Got it. Thank you, guys. Much appreciated.
Thanks, Michael. Next question's from Shahriar Pourreza from Guggenheim. Good morning, Shar.
Good morning, guys. Let me just touch real quick on Northern Pass. Obviously, Hydro-Québec is active with a competing proposal, obviously, both lines have relatively strong attributes. Let me ask you, assuming that you don't win these RFPs, when you think about future opportunities, is there an opportunity to partner? Most agree that TDI is not going away. The other question is can you just touch a little bit on you're committed to building the project whether or not you win the RFP? Just how would that work mechanically?
Yeah. A couple things in regards to your question on partnering. Obviously, we think we're quite good on partnering because we've had a lot of partners between Enbridge and HQ and now DONG Energy. We think we're good on that. Should an opportunity to partner with these folks ever come up, we'll certainly consider that. That's not out of the question. Getting back to your second part of your question, again, I think we'll win the RFP, the Massachusetts RFP, really because our siting on both sides of the border is just about complete. The other projects, particularly those that interconnect with Canada, have a 2-to-3-year process in which they're going to have to work through and whatever their state siting processes are. Our engineering work and design is essentially completed. We have got our major contractors lined up. We have firm bids.
We have firm place in the queues from manufacturing. Again, building these things poses a lot of risk unless you have the very best contractors, and we have those, and particularly with Quanta, who's done a lot of work for us. When you look at it, the Massachusetts RFP gives special consideration for projects that are in service by the end of 2020. Just the fact that Northern Pass going into service, that would have about a 25% reduction in the electric sector CO2 emissions, that we would be right where they need to be by the end of 2020. It's got all the right attributes.
Just to repeat what I said before, Shar, if for some reason we did not win this RFP, we would sit down with our partners, HQ, assess where we are vis-à-vis the other states, and then make that decision to proceed. I think both partners believe the project will get built for all of the reasons that I just covered.
Got it. That's actually very helpful. Let me just, on Aquarion, I know you prepared remarks. You talked about the attribute, again, is it's located and doing business locally. Obviously, areas around New England, especially on the water infrastructure side, are very prone for acquisitions on the muni, especially in states like New Jersey. When you think about growth opportunities around this business, is there an opportunity to grow outside of New England? Could we eventually see this entity start to acquire munis in surrounding regions where you have similar legislation? Are you pretty much focused on remaining within the New England region?
Yeah. Yes, Shar, this is Phil.
Hey, Phil.
How you doing?
Good.
First of all, I'll say we're just starting our regulatory approval process. Our primary focus in the near term is to effectively move through those processes in the various states and get the approvals and move forward. Certainly, as we move forward into that business, we'd have to look at all the opportunities that present themselves, just like we do in all parts of our business. The projects that Lee's talked about, you have to look for those and you have to see what the opportunities are and move on them if they're in the best interest of the company. There's no reason to think we wouldn't do the same thing in all aspects of our business. Right now, I'd say our focus is on getting the deal across the goal line in terms of the regulatory approvals.
In any aspect of what we look at, we're always looking for opportunities to grow the business, provide great service, produce returns for investors, and results for customers that put us in the top quartile.
Great. Thanks. Thanks, everyone. Have a really good morning.
Thank you.
Thanks, Shar. Next question this morning's from Steve Fleishman from Wolfe. Good morning, Steve.
Hey, Jeff. Good morning. Sorry, it's been a distracting morning, so if there's a little bit of repetition here. I saw some local stories where does it look like the September 30th date is also going to be delayed for approval in New Hampshire?
Yeah, this is Lee. There is going to be a SEC pre-conference meeting, I think, on the 9th of August that will look at the final phase of the hearings. It'll be the third one, and it'll lay out the schedule to the end of the hearing process. Right now, I don't have anything other than the end of September timeframe for you. I think all of our witnesses will be done in their testimony by the end of August, and then it becomes the intervenor's witnesses for cross-examination. Obviously, most of that gets done by us. We will determine who we want to cross and who we don't want to cross and how we optimize that schedule.
It's really written briefs by all parties, there will be a deliberation by the SEC, that will be a public deliberation, the decision will be made. It'll be an oral decision, which will be followed up by a written decision that will be somewhere between 30 and 60 days. All of that, we believe, still falls into the timeframe that basically says that we will have the final EIS, the record of decision from the DOE, the SEC decision, the presidential permit by the end of the year. All of that tees up us for a, essentially third quarter 2020 completion of the build-out testing the remainder of the year in service for the winter. All of that supports.
Okay. Let's say, just let's say the dates, when we get them on August 9th, are extended. You're assuming you're going to have a final order in New Hampshire by year-end. We would have to kind of measure against that, I guess.
Yeah.
Okay.
The other piece.
You feel good? Yeah.
The other pieces fall right in place with that.
Okay. One question on the Northern Pass replacement capital that you say you'll come out with, should we think of that as more moving forward capital that was in the plan in other businesses that was going to be in later years, moving that forward? Or should we think about it as more actually just net new capital, new projects?
I'd say primarily for the most part, it'll be new. There could be some movement, but I would expect that that would be the smaller portion of it, primarily new.
Okay. Thank you.
Thanks, Steve.
Thanks, Steve. Next question's from Caroline Bone from Deutsche Bank. Morning, Caroline.
Hey, good morning. Most of my questions have been answered. I just wanted to follow up, and I also feel like it's been a busy morning, so I apologize if I missed this earlier. The benefit you guys saw in Q2 from that renewable fund investment, is that something that we should expect to continue, or is that just some sort of one-time gain? Can you just elaborate on that a bit more?
Sure, Caroline. I wouldn't consider it a one-time gain. It's been something that's been in our portfolio for many years. I'd say what was unusual was the size of it was probably higher than had been the case in the past. We don't expect it to be significant going forward.
Okay. All right. Thank you.
All right. Thank you, Caroline. Next question's from Praful Mehta from Citi. Good morning, Praful.
Hi. Thanks. Actually, I was struggling a little bit on the water side. You've talked about acquisitions as one possible opportunity to grow the water business, but if you're buying at multiples that are at the 25, 26 times or wherever the water business transactions get done, where do you see the synergy or where do you see the value creation opportunity that would justify that kind of multiple?
Yes, Praful, as I said, in terms of the operations and the asset of Aquarion, they're a very well-run, well-respected organization, have a number one in J.D. Power scores for their category. We're focused on growing the business. I think there are growth opportunities that do exist in the water business. As I said, the small distressed systems are a growth opportunity that currently exists. We see, if you look at the water business in terms of the water business versus the generation business that we're exiting, as I said, you have a business there that has no growth and is declining vis-a-vis a business that you're replacing that with that has some potentially significant growth opportunities as we move forward with aging infrastructure and the like. We see it as an excellent opportunity and certainly a good strategic fit.
Gotcha. Fair enough. In terms of size going forward, what proportion should we think about? Is there a goal in terms of how much of potential rate base or proportion of rate base of the consolidated business you want the water business to be, or should we look at it as a much smaller part of the whole business? Where do you see, I guess, the water business going longer term?
Yes, certainly. If you look at the size of the existing generation business, it's about 3%. If you look at the existing, if you just take Aquarion, it's probably in that same general ballpark. I can't give you a specific targeted number today, but certainly we do expect that number to grow over time.
Got you. Well, thank you, guys.
Thanks, Praful. Next question's from Travis Miller from Morningstar. Good morning, Travis.
Good morning. Thank you.
Just real quick, following up on Aquarion, I was wondering if you could discuss a little bit your regulatory goals, either through the approval process or in the subsequent one, two, three years in terms of things like allowed ROEs, cost riders, other cost recovery, just anything that comes to mind, things that were in your plan in terms of making the acquisition-
Sure
from a regulatory side.
Sure. Absolutely. As I mentioned in my remarks, I'll focus on Connecticut because 90% of the business of Aquarion is in Connecticut, and I would consider, certainly Connecticut is a state that we're familiar with at Eversource, and Aquarion, obviously is very familiar with from the years of dealing in the regulatory space there. The water regulation is constructive in Connecticut. There are trackers for infrastructure programs, this so-called WICA program. That's not my Boston accent. That's actually WICA. Decoupling programs, just like the electric industry that decouples usage from the bill. If you buy distressed systems, you're allowed to put that into rate base or get a higher ROE allowance. Certainly the regulatory framework is constructive. The ROE in the water business there is at least equal to or better than what we have in our electric and gas business in Connecticut.
If you look at it, you really have, I think local ownership really means a lot that if you look at the rationale for the sale of the company, it was strictly related to a fund that Macquarie had that needed to be dissolved, and that could have gone in a lot of different directions. Having local ownership where we expect to keep the existing operations pretty much in place, as I said, we're not in the water business. They have a great track record for operations. All those things I think will be favorable.
Okay, great. I appreciate it.
Thanks, Travis. Next question's from Michael Weinstein from Credit Suisse.
Hi, guys. Hey, just a couple of follow-ups. On Steve's question regarding delays in the possible approvals by September 30th. Let's say the final approvals don't come until January instead of December, the year-end. At what point does the project get moved into 2021 for completion? When is the last possible moment you can get the presidential permit to start construction, and still remain on schedule for end of 2020?
Yeah. Steve, this is Lee.
Mike.
Mike, excuse me. Right now, we've got our schedule set up that we have all of our permits in hand, such that we can get ready to go for construction in the early part of the year. Is there some slack in those schedules? Sure. As there are in all schedules. To the extent that if it did get delayed, we'd have to go back in, we'd have to assess the slack and any ways to optimize the schedule, and we would have to make that call at that point in time. We're really geared up to get all of these approvals by the end of the year, and that meets our schedule and service date in the third quarter of 2020. We'll just have to assess that as we go. There is some slack in the schedule.
Okay. I guess one thing I'd be concerned about is if the delay is too long, the vendors might say, "Hey, we have other customers that would need this equipment.
Yeah. No, that's a fair statement, yeah.
Yeah.
This equipment is in demand all over the world.
Right.
Yep.
Hey, a quick follow-up on the one-time gain, that $0.04 gain in other income. Was that part of the 2017 guidance? Is this an investment that can continue to pay off in future years? Is this really just truly a one-time thing that was not included in the guidance?
Yeah. Mike, it's not a $0.04. It was really a couple of cents that was in the quarter. The total change in that parent line was $0.03-$0.04, the incremental per share number related to that investment was just a couple of cents, really the reason it looks different is last year was a $0.01 loss. This year was a couple of cent gain. That's a $0.03 swing. It's in there. It's always in the guidance because we do have that investment, and as I said, it generally is plus or minus a $0.01 in that category. It's not synonymous with, but we have other reconciliation items. I mentioned the transmission reconciliation. That's always in our guidance. That could go plus or minus. We reconcile our energy efficiency programs. Those could go plus or minus.
It's really part of the ebb and flow.
Okay. There isn't some ongoing $0.02?
No. The reason it was a little bit higher this year was there was a special contract that one of the investments had in 2016 that wasn't there the prior year. No, I would say it's not something that we would plan on going forward.
Okay. Also, it sounds vaguely like there's some reserve of capital projects, that sits out there.
No. When you say reserve, what are you referring to, Mike?
Mike, are you still there?
Hello? Yeah.
Yeah, I think we All right. Maybe we'll move on.
EEI.
Oh, I'm sorry.
Hello.
I took you off mute.
You were on mute.
Could you just repeat the question? I think you may have gone on mute.
Oh, well, sorry about that. I'm just wondering, it sounds like there's a reserve of capital projects that sit out there that could be brought in to bear when there's a delay in other projects. That there's things being spent, when projects are higher priority now, like Northern Pass, you put off other things, and those things can be brought forward and brought into the plan, when there are delays. Should we be expecting a big increase in the capital program, EEI this year?
We do announce the capital and our guidance in the February time period. Just like I think any effective financial and business planning operation, we don't just do it one time a year. We're continuously looking at what are our needs for our customers, what do we have on the schedule. Sometimes a project gets a little bit delayed in siting, another project has progressed faster than we thought. We're not creating new activities to do. We're developing a capital program that is responsive to the needs of the region in terms of reliability. It's responsive to our customers. We're putting capital, and our O&M is all directed at providing great customer service, top-tier reliability, those types of things. There is an ebb and flow in projects, and we don't just look at them once a year. There are projects that do move.
Some move faster, you can advance them. Some move slower, they have to go into another year. There's not a reserve out there that we're picking from.
Mike, I think we lost you again. Are you still there? Okay. All right. Let's move on to, I think it's the last question of the day. Joe Xu from Avon. Joe, are you there?
Actually, it's Andy. How you guys doing?
Hey, Andy. How are you doing?
I'm doing well. Just one last question on Northern Pass. Have you guys ever talked about, because I guess through the RFP you're saying, or just in general, that you have 60 miles of undergrounding budgeted, is that correct?
Yes.
Once the Site Evaluation Committee comes out with their final ruling sometime this year, is there a number, CapEx-wise or mileage-wise, on the undergrounding that's make or break?
Andy, this is Lee. I guess you could say that, obviously by the nature of this process, it's a competitive process, we really don't disclose all the parts and pieces of the cost. As I said earlier, we have now firm contracts and places in the queue. Important to note that the New Hampshire Department of Transportation has accepted our plan for undergrounding. The New Hampshire Department of Environmental Services has accepted the project as is, as designed. Those are the two key agencies in New Hampshire that issue the reports around the viability of the design. We're quite confident in that design, we don't believe that in any way there is a justification to do more than 60 miles. We think in and of itself, we're in a good place.
I understand that, but I'm just saying, I guess the point you're making, just before I ask my question is that based on those two agencies, you don't think the SEC is going to ask you to underground more? Is that your point?
Yeah. I can't speak for the SEC, obviously. The agencies, the heads of those agencies sit on the SEC, and the agencies themselves have provided final supporting reports that support the design as is. But clearly, the SEC members vote independently.
Okay. But I guess because of competitive reasons, you're not going to put out a number or a mileage number or anything like that would make you or HQ feel uncomfortable to move ahead on the other-
Yeah.
Beyond the 60 miles that have been stated already.
Yeah, I think that's fair to say, Andy.
Okay. That's fair. Just as far as how that relates to Massachusetts RFP, because I'm not that familiar with the process. When you bid into the RFP, the amount of undergrounding, is that part of the economics of the bid or not?
No, actually it isn't. You're basically going to bid a project in that has a number of attributes. Clearly, it's going to be the cost of the project. It's going to be the delivered cost per megawatt hour of the project and the energy, right? You end up with a total cost, and that has to be competitive. It's going to be, do the owners have site control? Do they have the requisite experience in building these? Do they have the financial ability to do it? How much risk are the developers asking to be placed on the EDC customers and so forth? Exactly when will it be in schedule? What are the operational attributes in terms of things like deliverability, the voltage, and so forth? Does it have black start capability, which Hydro does? Does it have the ISO New England approval?
They're going to look at all of those things, and they'll have a grading process of approximately 100 points, and they'll score each project in accordance with that grading process.
Okay, I understand. Really, in a sense, the undergrounding affects the economics of the program, but it's really more for you guys relative to what it's going to cost the ratepayer or the customer or the consumer through this Massachusetts RFP.
Yes, that's true, Andy.
Okay, great. Thank you, guys.
All right, thanks, Andy.
Yep. Thank you.
That's the last thing. I think some folks have already moved on to the 10 o'clock call. Thanks for joining us this morning, and please call me if you have any follow-up questions.
Thank you, ladies and gentlemen. This concludes today's conference. Thank you for participating. You may now disconnect.