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Intrinsic Value is all-important and is the only logical way to evaluate the relative attractiveness of investments and businesses.
Intrinsic Value is all-important and is the only logical way to evaluate the relative attractiveness of investments and businesses.
Good day, ladies and gentlemen and welcome to the Second Quarter 2018 Avangrid, Inc. earnings conference call. At this time, all participants are in a listen-only mode. Later, we will conduct a question-and-answer session and instructions will follow at that time. [Operator Instructions]
I would now like to introduce your host for today’s conference, Ms. Patricia Cosgel. Ma’am, you may begin.
Thank you, Joel and good morning to everyone. Thank you for joining us to discuss Avangrid's second quarter 2018 earnings results. Presenting on the call today are Jim Torgerson, our Chief Executive Officer and Doug Stuver, our Chief Financial Officer. A team of Avangrid officers will also be participating on the call to answer your questions. If you do not have a copy of our press release or presentation for today's call, they are available on our website at www.avangrid.com.
During today's call, we will make various forward-looking statements within the meaning of the Safe Harbor provisions of the US Private Securities Litigation Reform Act of 1995, based on current expectations and assumptions, which are subject to risks and uncertainties. Actual results could differ materially from our forward-looking statements, if any of our key assumptions are incorrect or because of other factors discussed in Avangrid's earnings news release, in the comments made during this conference call, in the Risk Factors section of the accompanying presentation or in our latest reports and filings with the Securities and Exchange Commission, each of which can be found on our website, avangrid.com. We do not undertake any duty to update any forward-looking statements.
Today's presentation also includes references to non-GAAP financial measures. You should refer to the information contained in the slides accompanying today's presentation for definitional information and reconciliations of non-GAAP financial measures to the closest GAAP financial measures.
With that said, I will turn the call over to Jim Torgerson.
Thanks, Patricia and good morning and welcome everybody. As you will see, we are continuing to successfully execute on our long term plan. However, the second quarter was negatively impacted by a significant number of storms, for those storms that were minor ones and there were many. We really can't defer the cost for future recovery at our utilities. We also experienced transmission outages and startup costs at two of our newest wind farms that had significantly reduced our planned generation. Having said that, the earnings for the quarter were 107 million or $0.35 a share.
The adjusted net income was 128 million or $0.41 a share. For the first half of the year, the earnings were 351 million or $1.13 and adjusted net income was 371 million and earnings per share, $1.20, which was up 1%. We are reaffirming our full-year guidance, which was initially put out as of February 20, 2018, although at the lower half of the range. We talked about implementing our strategy.
We have executed a contract for new wind farms, a new wind farm of 158 megawatts. We have 497 megawatts onshore wind and solar currently under construction. In the second quarter of 2018, rate cases were filed for Berkshire Gas and Connecticut Natural Gas and new rates for United Illuminating and Southern Connecticut Gas went in January 1 and for the New York companies, May 1. We also completed this sale of our gas storage business.
Now, we are making great progress since we've received the RFP awards in Massachusetts. Our partnership of Vineyard Wind, as I think all of you know, received the winning bid for 800 megawatts offshore and our NECEC transmission project was selected in the Massachusetts RFP. We have executed the 20-year contracts, which were filed yesterday by the EDCs. We're also very happy to be able to fulfill our commitment to increase the dividend and we've raised the third quarter dividend to $0.44 a share. That was declared by the Board in July 11 and it's payable October 1.
Turning to page 6, you can see the result in a graphical form, which I just went over. The earnings per share were down 2% in the first half. The adjusted earnings per share were up 1%. The first half earnings per share includes two months of the gas trading business and four months of the gas storage, which was sold May 1 and it also -- the adjusted earnings eliminates the renewables, mark-to-market restructuring and some other charges. And the first half network was up 4% to $0.90 a share or $280 million. Included in that were the network rate plans, which added 45 million to gross margin.
As you know, not all of that goes to the bottom line, because we have increases in O&M, appreciation, interest and so forth that that is expected to offset, to recover along with our profit. Now, the impact of those minor storms and the related costs was a negative $0.07 a share for us in the first half of the year. Renewables was up 19% to $0.37 a share or 105 million on an adjusted basis. Production was up 12% year-over-year. The new renewables, the megawatts we added in production, added 64 million in margin.
But that was not all of it, because we had some startup issues and transmission issues -- we had an internal transmission outage that lasted about a month at Tule. And that impacted our new production by about $0.05 a share negatively. So between those two, the $0.07 and the $0.05, we’re at about $0.12 for items that we could put in the non-controllable category. We're pursuing obviously best practices and efficiencies. The wind generation was actually down slightly about 2%. The Western Texas were up, New England, our Northeast and the Mid-Continent were down.
From a corporate standpoint, net interest and this – remember, last year, we moved the debt off of the gas storage business to corporate, so that affected us by about $0.03 a share, so we’re not getting the income from that any longer, since it's been sold. And then we had some discrete tax items that were positive in 2017 of about $0.04 a share. I think all of you remember, last year, our effective tax rate was lower than, I think, most people expected, because of these one-time items.
Now turning to page 7, we are reaffirming the outlook for 2018. Earnings per share of $2.16 to $2.46 and adjusted earnings per share of $2.22 to $2.50. We are guiding to lower half of the range, due to those first half impacts related to the storms. We also have a delay in the earnings adjustment mechanism in New York. We now believe that won’t occur until 2019. And then the startup issues and transmission outages at our new wind farm, which I just mentioned. We are actively pursuing mitigation measures to overcome as much of this as we can through the best practices and the operating efficiencies that we are continuing to pursue. We're also now looking at selling some renewable development projects.
This is a strategic decision and looking at evaluating the pipeline of projects we have and more specific projects to see if we can generate greater value by monetizing them today versus waiting for several years to have them go, get affiliated, and go into production. So we're evaluating that on a near-term basis, which we do every year anyways, but this is getting a little more emphasis, because we have a 12-gigawatt pipeline right now and we want to make sure we're monetizing the value as quickly as we can.
The wind performance is a risk and a plus. I mean, it was off about 2%. If it improves over the last half of the year, we could see an uptick. Timing and capital spending, and then storm, we’ve had a number of storms. Unfortunately, June has been a little quieter, but the first half of the year, we had more storms than we've ever seen. And then taxes and regulatory, we’re also -- as of today or really as of February 20 of ’18, reaffirming the 2016 to 2020 earnings per share growth rate of 8% to 10% and then the ‘16 to ‘22 growth of 8% to 10% as well. We're still highly confident of being able to achieve those longer-term growth rates.
Turning to page 8, on our renewables, we did execute a contract for 158 megawatts for a new wind project with a C&I customer and that will be going to operation at the end of 2019. So our secured contracts and the long term outlook now total 1605 megawatts. That’s 83% of the original target we set for 2020 and 58% of our 2744 megawatts we set for target for 2022. We have 497 megawatts under construction, the Wy’East Solar, which will be operational later this year. We have 9 megawatts right now of the 10 that are actually producing energy, but not delivering. Montague, it will be late of 2019 as well as Karankawa.
Turning to page 9, with our V ineyard wind project. This is the joint venture we have with Copenhagen Infrastructure Partners on a 50-50 basis. It was selected in the Massachusetts RFP now to deliver 800 megawatts under a PPA. This has a lease area that could develop up to 3 gigawatts of production and we're looking at having 400 megawatts, being operational by the end of ’21 and the other 400 megawatts by the end of 2022. We've already filed the construction operation plan and it's the Bureau of Ocean Energy Management and actually this is the first and the only US offshore wind farm that has applied for the COP to date. And we expect the receipt of all of our approvals by the early 2020.
Now the US offshore has significant projects as well that we're continuing to see momentum being gathered. Kitty Hawk, which has a 2.5 gigawatt lease area, it's 100% owned by Avangrid and that is offshore on North Carolina. We also see other opportunities in the Northeast for offshore wind and Massachusetts, they will be looking for an additional 800 megawatts by 2027. New York has said, they're looking for 2400 megawatts by 2030 and 800 megawatts will be ordered in 2019 and then New Jersey is looking for 3500 megawatts by 2030. So there's a lot of momentum for offshore wind in the US, and particularly the northeast corridor, where the wind is at especially high levels, probably some of the best in the country.
Turning to page 11, we’ll switch over to networks and look at some -- the regulatory highlights related to the Tax Reform Act. In all our jurisdictions, the net benefits have been being deferred since January of this year. In New York, in March, the recommendation of the New York DPS staff was to return all tax savings to the customers to a current rate case or sur-credit by October 1. We proposed to offset the storm costs and the automated meter infrastructure revenue requirements, some resiliency investments and other deferrals. We filed that June 29 to offset that with the tax savings. And that decision is expected in the fall.
In Maine, we have a stipulation agreement which approved the increases in the distribution tariff, effective July 1 of this year and that included the recovery of the deferred October 17 storm restoration costs of 44 million, most of that being offset by the Tax Act savings and the existing storm reserve. In Connecticut, the net benefits have been deferred as well and we have proceedings in process. We would expect an answer sometime in the fall and the same in Massachusetts. Under FERC, the New England transmission owner formula rate will automatically capture those benefits and that's really for United Illuminating and Central Maine power and FERC has opened proceedings and it currently is just addressing comments.
On page 12, we have some other regulatory highlights. In New York, the AMI discussions are ongoing. We would expect an answer from the commission by year end. The earnings adjustment mechanism has been impacted by the storm investigations, AMI and management audits. So, now, we -- that same push, we believe in to 2019. Connecticut, we filed a rate case for Connecticut Natural Gas on June 29 for rates to be effective by January 1, of 2019. Berkshire refiled a rate case in May with rates to be effective in April of 2019. CMP has been ordered to file a distribution rate case by October 15.
There was a 10% complaint, which is a process in Maine that allows people to make a -- if they get to be able to sign, they can get a complaint with commission. Commission looked at it and looked at the ROE and said that it appears we’re earning above our allowance, so they want us to file a rate case, which we will do and actually that will allow us to also include capital projects for our resiliency program in Maine as well, so we'll be able to take advantage of that opportunity. At FERC, really no change in the ROE complaint number four and really no progress on complaint one in remand or in complaints 2 and 3 at this point.
NECEC update on page 13, a transmission project that was selected in Mas RFP. It's a, to remind you, a 1200 megawatt transmission project, delivering Canadian hydro. The $950 million investment, excluding AFUDC, we've executed the contracts of the Massachusetts EDCs and Hydro Quebec on June 14 and they were filed yesterday. It’s an estimated price for years one through 20 and then a fixed price for years 21 to 40 on the transmission component and construction will begin in 2019 and be operational by the end of ’22. And we expect all state permits by the first quarter of ’19 and then a final approval by year end ’19 and we really have strong support from the Maine Governor and the local communities, although one of the communities along the path has filed letters of support and the one that didn't just said, they’re supportive, they have haven’t filed the latter in support of it at this point.
We're also -- on page 14 -- developing a comprehensive and robust networks resiliency plan and we're calling it transforming energy plan for New York and Maine. It will be a $2.5 billion project over 10 years and includes capital costs of about 2 billion, of which 500 million is -- really is the AMI and which is included in our long term outlook. 1.5 billion is not in the long term outlook and then we have operating expenses of about 500 million, which would be for vegetation management primarily. And really the objective here is to harden the grid and really improve the reliability for customers. With all the storms we've been having, we believe it’s as prudent now to look at what we can do to mitigate the impact of these storm costs that are having and just eliminate the need for these – the outages that are caused by the storms as much as possible. So what we're going to do is look at an accelerated replacement program for our wood poles and using a higher quality coal in many instances. We're also going to use tree wire and this is really coated wire that if there is a contact with the branch, it can resist that from going offline.
We're going to look at the cost/benefit analysis of some infrastructure hardening and this is really undergrounding in some areas where we deem it can make a lot of sense. We’re looking at non-wires alternatives, such as using battery storage and other techniques and to enhance the grid, aerial cable that is more resistant to outages and then we're also looking at Ground to Sky tree trimming and identification of hazardous trees which are outside the right of way.
We've done the Ground to Sky in Connecticut for several years now and it allows us to be able to have less outages and we saw that this last year with the Connecticut, fewer outages than perhaps we had in New York and in Maine, because of the use of this tree wire and the Ground to Sky trimming. We’re also targeting certain distribution circuit upgrades really to improve the grid interconnectivity and alternative source of supply and really this will allow to facilitate more of the distributed energy resources that are coming on to the system. And we will be looking at full implementation of advanced metering infrastructure in New York in this timeframe.
Also, I want to point out that Avangrid announced an increase in the dividend. We raised it from $0.432 a share to $0.44 a share for an annualized rate of $1.76 and that will be in the third quarter. We’re still targeting a 65% to 75% payoff ratio and the dividend should be increased in line with earnings per share growth, again staying within that payoff range.
I want to make sure, our long term strategy is on track and we're very optimistic for Avangrid’s future. When we look at implementing our strengths, we have signed 158 megawatts for new contract already. We have the rate cases which we're going to be filing which will help improve our outlook and we're still looking at best practices and cost mitigation. This is an ongoing practice we have across all of our companies to make sure we're getting as efficient as we can in every area.
The RFP awards that we received for NECEC and the Vineyard wind partnership make our long term future and really not that long term, in the next five years, very attractive and we will continue to fulfill our commitment to increase the dividend. So we are reaffirming our 2018 outlook, with earnings per share on $2.16 to $2.46 and adjusted earnings of $2.22 to $2.50. We are guiding towards the lower half on the range, based on the two things that I mentioned with the transmission and startup issues [indiscernible] which severely impacted us. Those two together cost us $0.12 a share in the first half of the year and we're also reaffirming the 2016 to 2020 and 2016 to 2022 earnings per share and adjusted earnings per share of 8% to 10%.
So with that, I'm going to turn over to Doug Stuver for his inaugural run at a quarterly earnings call.
Thank you, Jim. Good morning, everyone and thank you for joining us today. I’m on slide 18 and we will go through the business segment details of our second quarter and first half earnings performance. On this slide, we show our US GAAP roll forward earnings per share from the second quarter and first half of 2017 to the same periods in 2018. As Jim mentioned, while we continue to execute on the key objectives of our long term plan, our second quarter EPS is down 11% versus last year, declining from $0.39 per share to $0.35 per share and our first half EPS is down 2% from $1.16 per share to $1.13 per share.
Recall that the US GAAP results include the gas trading business for the first two months of the year and the gas storage business for the first four months of the year, including all of the first quarter as well as a loss from the held for sale measurement of the gas storage and trading businesses. US GAAP results also include renewables mark-to-market, a small restructuring charge in the first quarter of 2018 and other items.
On the next slide, slide 19, we show our adjusted earnings roll forward, which excludes the gas businesses that we exited this year, the renewables mark-to-market and the other items. Adjusted EPS is down 10% from $0.46 for second quarter of 2017 to $0.41 for the second quarter of 2018. That's primarily due to lower results in the networks and corporate segments, related primarily to storm impacts, corporate interest and tax impacts. For the first half of 2018, adjusted EPS was $0.01 per share higher at $1.20 per share than it was for the first half of 2017, as positive performance in the businesses, including the benefit of new rate years in the networks business were offset by storm related costs and corporate impacts.
The next several slides provide more detail on the business segment impacts. Moving to slide 20, you can see our second quarter results for networks were negatively impacted by storm related costs. While costs related to our large storms are deferrable, in addition to large storms, we had multiple minor storms. The number and severity of storms had secondary financial impacts as well, including for example, lower capitalized labors, the distribution crews spent a higher portion of their time on storm recovery. We also had higher overtime expenses, our crews completed the storm recovery and caught up on maintenance activities.
In total, these storm related expenses had a negative after-tax impact of approximately $0.07 per share in the first half. As we catch up on the distribution CapEx over the remainder of the year, we expect to see higher capitalized labor to help reduce this impact. Importantly, also as Jim noted, our $2.5 billion resiliency plan proposes to harden our power grid and help minimize the impact of future storms. For the first half of 2018, we see that the impact of the storms was offset by increases in distribution rates, due to the multi-year rate plans in the New York State Electric and Gas, Rochester Gas and Electric, United Illuminating and Southern Connecticut Gas companies. Those rate increases produced approximately $45 million in additional gross margin during the first half.
Turning to slide 21, our renewable segment demonstrated quarter-over-quarter and year-over-year earnings improvement. As Jim mentioned, this is largely driven by the five new wind and solar projects, totaling 590 megawatts that became operational by the end of 2017. While positive, the numbers for our new wind projects do reflect the impacts of startup issues and transmission outages that we have with our El Cabo and Tule wind farms, primarily with the transformer and turbines at El Cabo and the transmission cable at Tule. As Jim noted earlier, these issues combine for a negative $0.05 per share impact on the first half results.
The issues at f Tule, I'm happy to report, have now been resolved and we've made substantial progress as well with the issues at El Cabo. As you can see, performance in the second quarter of our existing wind and solar was flat and contributed $0.02 per share in the first half. While the wind resource for the first quarter of the year was at our average, the second quarter was constrained by below normal wind results. Results were also impacted by expiring production tax credits, which reduced the second quarter adjusted EPS by negative $0.03 per share and the first half adjusted EPS by negative $0.05 per share. In addition, the reduction of federal tax rate and positive year-over-year discrete adjustments resulted in a positive impact in the second quarter of 2018 versus 2017. The impacts were offset for the first half comparison due to negative year-over-year discrete adjustments.
On slide 22, we look at the corporate segment, which was driven primarily by financing costs and taxes. At the corporate segment, adjusted EPS was down $0.09 per share for the second quarter of 2018 versus the second quarter of 2017 and the same amount for the first half year-over-year comparison. The segment results were impacted by higher financing costs with the issuance of our Green Bond in November 2017 as well as the absence in 2018 of interest income from the gas businesses that we exited earlier this year.
The loss of intercompany interest income from the gas businesses reduced the second quarter results by $0.02 per share and the first half by $0.03 per share. Taxes negatively impacted corporate by $0.06 per share in the second quarter and $0.04 per share in the first half of 2018. That's primarily from consolidating adjustments to balance the segment’s income tax results with Avangrid’s consolidated income tax results. These consolidating adjustments only apply in the quarterly results and will fully reverse by year end. The consolidated effective tax rate on adjusted earnings through six months was approximately 24.2% on a management reporting basis.
Now, turning to slide 23, we provide additional details for the drivers in the renewable segment, which I've already largely covered. Our installed capacity has increased 455 megawatts from the first half of 2017. We have approximately 497 megawatts under construction with our 10-megawatt solar plant expected to reach commercial operation in 2018 and the other two projects expected to reach commercial operation dates in 2019. As noted, our capacity factor was higher year-over-year with the new additions. Total capacity factor rose 4% from 32% in the first half of 2017 to 33.1% in the first half of 2018. The year-over-year improvement reflected a relatively flat impact from our existing wind farms, which increased from 32% to 32.5%.
Our capacity factor for new capacity in 2018 was approximately 37.6%. Wind production increased year-over-year by 12%. That's driven primarily in South Texas region due to our new capacity and in the West. While new capacity added approximately 946 gigawatt hours, to reiterate, the wind resource was below normal, as evidenced by total production at our existing fleet, which increased by about 122 gigawatt hours. As noted, pricing was slightly lower overall, reflecting the impact of lower PPA prices, mitigated by higher merchant prices. Regionally, average prices were lower in the West, Mid-Continent and Texas regions and slightly higher in the Northeast region.
Now, turning to slide 24. Our financial position remains robust and continues to position us well for opportunities, included in our outlook. To provide resiliency through unexpected events and support the new exciting opportunities outside of our current outlook. Our debt level, net of cash, as of June 30, was 5.9 billion. Our credit metrics remain strong with 2.8 times net debt to adjusted EBITDA, 28% net leverage and 31% FFO to debt and those have improved since the first quarter. Our credit ratings are very important to us and we maintain our stable BBB+, Baa1 ratings with the rating agencies.
On the next slide, slide 25, we demonstrate that we've enhanced our liquidity in the second quarter to support our long-term outlook by increasing our revolving line of credit to $2.5 billion. With this increase, we're now also in the process of upsizing our commercial paper program, which is currently $1 billion program. We're upsizing that to $2 billion. We've also added a new intercompany loan facility in the second quarter with Iberdrola for $500 million to service an additional liquidity backstop. You may recall too that we issued our first Green Bond for 600 million in November of 2017. We're proud to have also been one of the first companies in the United States to do so as well as to be one of the first to issue a revolving credit facility that links pricing to the achievement of our sustainability initiatives. As a result, Avangrid will also benefit financially from our strong commitment to reduce carbon emissions, including our pledge to be carbon neutral by 2035.
Finally, on slide 26. As Jim mentioned earlier, we're maintaining our consolidated earnings outlook of $2.22 to $2.50 per share on an adjusted basis, while guiding to the lower half of the range. We noted a number of unexpected negative impacts in the first half of 2018, the storm related impacts that affected us by a negative $0.07 per share and the startup issues at El Cabo and Tule that were negative $0.05 per share. These are driving this guidance, but we also want to highlight that we continue to work very diligently to implement our best practices, programs and cost mitigation initiatives to mitigate this impact.
We've had many successes year to date that we're proud of and we feel will contribute significantly to our long-term performance. We successfully executed a new contract to grow our renewables business, reaching 83% of our initial 2020 goals and moving us closer to our 2022 goals and we continue to increase earnings in the networks business through our forward 2022 best practices initiatives, allowing us to continue to earn our allowed returns and into the share events. As a result, we are reaffirming our 8% to 10% guidance for our 2016 to 2020 and for our 2016 to 2022 periods based on our long-term outlook, as of February 20, 2018 Investor Day.
Finally, I’ll reiterate that while continuing to implement our existing plan, we’ll continue to execute the large and industry leading projects that we have outside of the plan, positioning us for continued growth and value creation.
Thank you. And I'll now hand the call back to our operator, Joel, for questions.
[Operator Instructions] Our first question comes from Praful Mehta with Citigroup.
So just quickly on the lowering of the guidance. So I guess to the lower half, if you do the math, that's probably about, what, $0.07 of, I guess, negative impact, relative to your midpoint of guidance before. If you can just bridge, that's right, because if you take $0.07 from the renewable -- from the network side, $0.05 from renewables, that's $0.12, are there offsets to that? And what is the impact of EAM to the guidance that’s -- you kind of noted that that also impacts your guidance. So just a little bit more color on kind of the math of how you're getting to that $0.07 impact lower in terms of 2018 guidance.
Well, the 12 -- you're right on the $0.12 has come down. We're looking at mitigation strategies, which we do all the time, what costs can we take out that were in the budget, that we're looking at. So we're taking those things into consideration right now and we believe we can offset some of that. We're trying to offset as much as we can with other strategies, which are the ones we went through on looking at, everything from mitigation to best practices to selling some development projects, we do pretty much every year. Now, we're going to do that on a continuous basis, because we have such a big pipeline of products, we want to high grade it and make sure we're getting the best value out of those.
So if we can get more value by selling them now versus operating them and we just look at it on an internal rate of return and a net present value basis to see how -- which ones we can maximize the value for and we have -- a team is working on that directly. So there are things that we’re doing to mitigate it and that's why we -- it's probably a little less than just the whole $0.12, because we do believe we have to do everything we can to mitigate that.
As far as the EAM, we’ve never put out a number on that and we don't really want to at this point, because we're still in negotiations with the staff over how much we could get for that EAM.
Yeah. Jim, if I can add a couple of things on that. So, as I think about the impact of the storms in the first six months of this year and Doug touched on this, some of the impacts are not direct costs of minor storms, but there are things like, we've fallen behind on our capital spending plan for the year because our crews have been busy working on storm restoration. So to the extent, over the remainder of this year, we can catch up on the shortfall in capital investment that will allow us to get our capitalized labor number back up to where we anticipated it would be, relative to where it is in the first six months of the year. So, there are some components of the costs associated with storms in the first half that we do have the ability to try to catch up on.
On the EAMs, I would just say that historically, the New York Companies have had an incentive program around energy efficiency that we’ve earned a few million dollars on year after year. Those ended 2017, and now given the delays we've seen on the EAMs, we really anticipate no opportunity to earn any kind of incentive, whether it’s on the old program or the new one for 2018. So that's why we mentioned it, but I will say that the vast majority, a largest issue that affected networks in the first half really surrounds the cost of minor storms and associated impacts.
And I guess like, if you've delayed CapEx, because crews are busy, I get that, but just so I understand, on the storm costs, why are some of these non-recoverable or, is there not a regulatory asset that can be created at some point to recover, why do they kind of cross the threshold in terms of size where they’re too small where it kind of – [multiple speakers]
Yeah. That’s right. I mean, generally speaking, the way rates are set and it varies by jurisdiction obviously, but there's a certain amount that you're allowed in rates for minor storms. And then if a storm reaches a certain threshold, whether it’s number of customers affected, the percentage of customers in the area affected, the length of the outage and things like that, you are able to defer them for future recovery and what we saw in the first six months, in addition to some, quite frankly some very large storms, we had a series of many small storms as well as threatened storms where we have to pre-stage our crews, whether the storm occurs or not and it’s those costs that you really can’t defer because there's an assumed amount of embedded rates and what we saw is the amount that we incurred was well in excess of what was embedded in rates.
A lot of those storms just didn't hit the criteria that are required to classify it as a major storm and so we can't defer, which is what Bob was saying. So, and we had many of them and little pop up storms that affected a number of customers, it could have been 10,000 or 20,000 at a time, that we had to send crews out to work overtime, bring in contractor crews and pay them, but it didn’t meet the qualifications for our major storm. So you just don't expect to have that many and we had an inordinate amount in the first half of the year.
Our next question comes from Julien Dumoulin-Smith with Bank of America Merrill Lynch.
Wanted to follow-up here on the near term stuff and then also focus on some of the longer dated guidance updates. As far as the -- can you comment a little bit more on the impacts from the collateral received in the two contracts relating to a counterparty bankruptcy. And more, I just want to make sure if I understand it, rolling into 2019 and onwards, is there an impact we should be aware of or is this truly just kind of a wash in ’18 alone?
The bankruptcy of the FirstEnergy Solutions’ and we had contracts where we had collateral that we got paid this year, but we didn't include it in earnings and it would get spread out over the balance of the year. So that’s part of it. Then, in the future, we're going to be selling into the marketplace in PJM basically. So, yeah, the contract price was high and it's going to be a lot less now that we’re moving and we’ll be selling at the market price. So it has an impact. Now, it’s not huge to us, but it is significant. So I think you got to -- we've got to look at that and we can – that’s the color for it. So we're getting, I think we said was, what was the collateral? I think we deferred.
Yeah. We had $7 million of collateral that was taken to our GAAP earnings in the second quarter. We've adjusted that out though in our adjusted earnings. So that's only hitting the GAAP results.
Do you want to quantify that year-over-year or like how much the PPA rolloff is?
We’ll get to something on that in the future perhaps, but it's -- we usually don't give out those individual contract prices, because -- and that is something we usually can't disclose. So just know that we have two wind farms that we’ll be selling in the PJM now, which the prices are actually fairly good, but it's not the same as the old contract prices.
And then also a longer dated question here, both from the utility side and the renewable side. First, utility, you talk about a 10-year plan, about 1.5 billion of capital not yet reflected in your long-term outlook. How much of that it in the first five year outlook, as you see it right now? I just want to understand that a little bit. And then on the renewable side, just wanted to come back and understand a little bit, where these two incremental large projects place you within your long-term earnings guidance range and how you want -- when and how you want to reconcile those basically?
Well, the first part on the 1.5 billion, I think it’s spread reasonably evenly over the 10 years, Julian. So that’s -- you can look at it that way. The 500 million that’s going to be O&M, obviously, we want to have commissioned approvals to pursue those with, we could probably do some of it, but a lot of it’s going to be vegetation management treatment so forth on a different basis. But you really want the commission buying off on those.
The other part of your question was the two projects and you talk about NECEC and then the offshore wind, or?
And I understand, neither was included in your initial long-term guidance on that range, provided earlier?
Right. And it still is not. That guidance is still as of February 20 of this year and we have not included. We will look in the next time we update, which will be February of ’19 as to whether -- what we include for those two projects.
Can you give us, maybe a preliminary sense of where that puts you within the ranges or just kind of some preliminary sense of EPS contribution by ’22 from these projects?
Not yet at this time. We will get there eventually.
Our next question comes from Greg Gordon with Evercore ISI.
You answered several of my questions. I have a few more. So I guess you already answered the question, I'll try to ask it differently. In terms of the Massachusetts RFP, the New England Clean Energy, the earnings impacts from those projects, I mean, will there be some sort of construction work in progress related type of earnings stream and when might that kick in and when would they go COD and how does that fit into your long term earnings guidance?
On the NECEC, we would expect to have AFUDC on the project. And it won't start until we actually start more construction really. I mean, we're spending a little bit now, but it really is going to be 2020 when that would start kicking in, Greg for NECEC and then operational by the end of 2022. So I think, you're going to have basically three years of AFUDC.
And then on the offshore wind, we’ll have basically capitalized interest on those projects, starting again probably in about the 2020 timeframe, because the first 400 megawatts will be operational in ’21 and the next 400 in ’22. So that’s how I would look at it. And like I said, we have not included any of it in our long term plan at this point.
But I guess it's sort of a double edged sword in terms of message today, near term, you've got some headwinds from operational issues and the storms. We've also got to now contemplate the sort of mark-to-market on the FES wind projects, right. So near to medium term, there's some issues, but longer term, it seems like the -- filling in the growth opportunities is going pretty well. Is that a fair summary?
Yeah, I mean, long term, yeah, we're very optimistic. The projects we have, and even the businesses, the networks business actually performed very well, if it weren't for the storms and renewables as well and we had a couple of outages. So, when you see that renewables, the margin was up actually 64 million from our new projects and we have a few headwinds from a couple of things that are pretty much gone now. I mean, the transmission, the internal transmission outage at Tule, which caused us to be offline for a month and then the start-up issues we’ve had with the turbines are getting resolved and they're actually mostly resolved at this point. So we're in pretty good shape there. So going forward, I think things look very good for us. And this can get a couple of hiccups.
And how material, I mean within the 8% to 10%, sort of earnings guidance outlook, I mean what's the sort of materiality of the mark-to-market on the FES contracts. I mean, is it a really big swing inside the range or is it just relative to the size of the overall portfolio, is it not that big?
I wouldn't put much, either way, it’s not going to be that material to us. Well, I was going to say, we just got a word that we've been successful and we're buying a project in development phase in Texas that’s 220 megawatts with a 12-year hedge, fixed price hedge for us that we just got successfully signed up just now. So we're adding another 220 megawatts to our secured project.
Brand new, as of your words just spoken right now.
378 for the first half.
Congratulations. One last question. You talked about the Maine PUC show clause request for you to file a rate case as an opportunity, but why should we not think about that also as a risk, given that I think that your -- you might be over earning, how material, what’s the sort of risk reward that we're looking at in terms of your now being compelled to file a case there.
This is Bob. So a little bit of history maybe to start. So since we reached the prior agreement, our ROEs have generally ranged in the 9% to 11% range, with 11% being in 2017. And that is based upon our actual equity ratio, which we have kept at a level slightly higher than what was originally put in that last rate case, because of the fact that we've been between MPRG and now almost in loop in other projects and now with $1 billion NECEC project, we feel it's appropriate that we keep the equity level at that company somewhat higher. So we've been in the 57, 58 kind of range in the last couple of years.
When the commission looked at it, it looked at it in the perspective of how rates were originally set, which was a 50% and it produced obviously a higher ROE from that perspective. As we think about this going forward, there's a number of things quite frankly or even new this year as compared to ’17 results, we have a new accounting standard on pensions doesn’t allow us to capitalize as much of our pension expense. We don't have pension deferral mechanism in Maine.
We have higher property taxes, we have our resiliency plan that we want to get put in place. So there's a number of things that while, I can't say, we would have been necessarily planning to file this year, the fact that we've been ordered to do so, we'll do that and we’ll make sure we update because it's been four years since our last case for all the cost structure. The one thing is, I’ll say again, we will continue to argue though is that in light of the growth that we're seeing at CMP, it really augurs for making sure you have very strong balance sheet and so we’re going to look to try to maintain that higher equity ratio.
Our next question comes from Michael Lapides with Goldman Sachs.
Hey, guys. Just curious, how do you think about the changes in the capital program that you've announced, meaning, the energy -- transforming energy plan and obviously the offshore wind in NECEC and how much incremental, if any, balance sheet capacity you have to self-fund these type of growth projects?
From a balance sheet, we have, as you know, very little debt. So we can fund those projects on our -- with our balance sheet now. I don’t know, Bob, do you want?
Yeah. I mean, a couple of things. Obviously, the resiliency plan is one where as Jim mentioned earlier is it’s really a 10-year plan and a lot of that spending will incur until we get regulatory approval, most notably in New York and in Maine. So that's really a probably like 2020 to 2028 pro rate kind of spend, if you would, recognizing that some of it, about half a billion is OpEx, the rest is CapEx. So again I think, that's something that is over a longer period of time, but two that are more short term in nature, because the construction is going to be going currently, obviously is the NECEC and Vineyard, which are both in that late ’19 to 2022 timeframe. But as Doug had in his discussion and Jim, I mean, we’ve started with the 28% debt to capital. I think that's a pretty good spot to be in and it certainly allows us to absorb these projects with the balance sheet.
Got it. And one quick follow on, what is it -- and I'm thinking about with Vineyard Wind, what is it you think is differentiating your projects from the other projects that have bid into some of these RFPs, but maybe didn't win something as kind of scalable or as large in size as your 800 megawatt Vineyard Wind project? What are you doing differently?
Well, I think on Vineyard Winds, there is a couple of things. One, clearly, we have the expertise of our partnership with CIT and the relationship we have with Iberdrola will have expertise in building offshore wind. I mean, we already said those two, but we also have the onshore wind that we've been doing for a while. So we have that expertise and also the regulatory that we can deal with in the states in the Northeast.
The second big thing is, by being able to bring the project in 2021 and 2022, we get ITC. And I think others could not get the ITC because -- as much, because they were later. And so that is probably a big differentiating factor as well, but then as I said, we have people who have done this, who have built these projects. One of the people that's working directly on this for us is the Global Head of Offshore Wind for Iberdrola and he's partner -- he's overall -- managing the overall product from our perspective.
So having that expertise is something you just don't get by just doing small projects here and there. So I think this is something that's a big plus, plus we have the ability to then work with our suppliers to drive down the capital cost and because of Iberdrola’s purchasing power and CIP, put those two together, it gives us an advantage as well, but I think there's a number of things that have put us in a better position than others.
Our next question comes from Steve Fleishman with Wolfe Research.
Just on the renewable development projects and the plan to monetize those, can you give a sense of how meaningful that could be as an offset this year and in the future years, like how big a part of your plan does this become?
I don't think it’s going to be enormous, do you know I mean, I think it's going to be fairly small, but it's one of those we're just going to look at to look at monetizing. I don’t think I can put a number on it right now. But we have –
And you’ve included in your operating earnings, I assume?
Yeah. Because these are things that are ongoing. I mean, we do this constantly. Now, it’s more – we’re putting more of a focus on it, because of the size of our pipeline and we want to make sure that we're high grading it and getting the best projects to the market as quickly as can and those that we think are a little longer term, we may generate more value by selling it to someone who can develop it sooner. So we've done it in the past and we're going to continue to do it, but I wouldn't say it's huge, but it's going to be something, we can’t generate some capital gain out of it.
Thank you. Our next question comes from Sophie Karp with Guggenheim Securities.
Maybe real quick on the new capital plan that you are rolling out. So NY is included in that. I am assuming those are the same that you currently have pending in New York or is that something incremental?
It’s the same. We haven’t spent anything on that in New York yet because we've been waiting for the regulatory approval.
We highlighted because when we first filed for approval of AMI in New York, it was really a part of a rep proceeding and the plan to enable our customers to have better visibility into their energy usage and so therefore be able to full time use rates for the bill and better manage system peaks. But the reality is and we've experienced that in Connecticut and in Maine, where we have AMI, there's tremendous benefits to the networks business as well from the standpoint of storm restoration and visibility into the system. And so we include as a part of resiliency plan just to acknowledge that there are operational benefits as well as customer benefits, but as Jim said, it's the same thing.
So there wasn't going to be yet another precedent that deals with AMI?
No.
And switching gears a little bit on the offshore wind projects, now that you’re -- as you mentioned, you can bring them online pretty fast or versus the other potential bidders, how you’re sure about being able to obtain all of the permits on time for that, is that change maybe since the last time you spoke and also what is your timeline for key procurements decisions for that project.
Yeah. When you look at that project that is going since 2015, so CIT has been working on it since about then. So the timing aligned to get the permits, we’re looking at the end of 2019. We should have all the ones we need. I don’t know, Laura, do you want to comment on that and?
Yeah. I would tell you that our permitting plan, both federal and state is on track according to our program and we absolutely appreciate that energy and time of the different agencies that are putting in to progress in these projects, you probably saw the SEIR, the supplemental environmental impact review that was requested and we actually are really positive about that. We saw that as a positive sign that it's being taken seriously and I think it also proves that the process is working, because it provides an opportunity for people to raise concerns and for developers to respond to those. So we feel like we are absolutely on track and we are confident we are going to get there.
And just following up on some of the comments on what differentiates our projects, I would say it's the local team. We actually have had folks on the ground there since 2011, 2012 and it is a really genuine effort to gain local support and make sure that this project is a win-win. And when you look at the components of our bid, not only did we provide -- able to provide a very attractive and competitive price for the consumers, but we're also able to get value for shareholders out of the price, because we've done things like focused on local content and local jobs. We've tried to invest in accelerator program and really just bring all of the local communities along, so that everybody wants us to be successful and I think that's what helps us differentiate our projects.
And then the procurement planning?
We are in the procurement process now, the way that these large offshore projects are split up, they're put into several big packages, so you’ve got the turbine packages, you've got the underground cable packages, the offshore substation packages and so forth. So we are already out on all of those and I anticipate a lot of the decisions will have to come together at the end of this year, early 2019 in order for us to keep on track with our program, which we certainly intend to do.
And is that necessary to accomplish that by -- within this timeframe to qualify for tax credits or can that procurement slip sort of?
I don't think we want the procurement to slip, mainly because if you get the tax credits, we need to be show commercial operation by the end of ’21. So we don't want that to slip.
Our next question comes from Angie Storozynski with Macquarie Investment.
Just two quick follow-ups. So the 8% to 10% EPS CAGR through 2020, based on what we know currently where would you be in that range?
We haven't commented on where we'd be in the range, just to say that we will be in the 8% to 10% range for the growth for 2020 and 2022 for that matter.
Okay. And then on the offshore wind, assuming that there is any delay, meaningful delay on the regulatory front and that first 400 megawatts does not come on line by 2021, is this -- I am just trying to gauge how big a delta and the profitability of this project would the lack of ITC have on that first 400 megawatts.
If the ITC would go down, if it comes in 2022, let’s assume that, right now, the ITC for getting in by 2021, I think is 24% and it would drop 18% under the legislation, if it's your leader.
I mean we have clearly done and actually see the contract yet, but it would not necessarily make this first 400 megawatts unprofitable.
No. I mean, we’re assuming that we’re going to get it in 2021 to begin with.
Our next question comes from Christopher Turnure with J.P. Morgan.
The only question that I had remaining was on wind resources from both existing projects and new projects. I know you've run for, I think, a couple of quarters now below your normal expectations and commented that maybe the normal was a bit of a moving target. Is there any update there and kind of how you've been doing this quarter or year to date versus a apples-to-apples normal?
Year-to-date, we’re off about 2% from our expectations, which would be our normal. Western Texas, we’re actually well off and over on the production side. Mid-Continent, which is kind of the mildest of area and PJM in the Northeast were down. Laura, do you want to add anything to that?
I think you've got it and I think we've commented in the past that because of your point that it seems that we've had kind of multiple periods where we've been under our expectations, we have taken some steps to be more conservative around expectations going forward. So we're hoping that trend will turn around.
Our next question comes from Paul Patterson with Glenrock Associates.
Just on the corporate side, I know there's still sort of a delta of $0.10 and it sounded to me like the $0.06 associated with the tax was likely to be reversed. I want to make sure if I understood that correctly and just how we should think about the next couple of quarters and through this corporate impact.
This is Doug. So yeah, the items that’s affecting corporate is a consolidating tax adjustment that is something that by the end of the year will reverse. It's basically something that allows the overall Avangrid tax result to align with the sum of the two segments, renewables and networks. We do separate tax calculations at the segment level. We do a separate tax calculation at the Avangrid level and this corporate item is something that is used to balance those. By the end of the year, there won't be a need for any further balancing between the segments and the consolidated results. So it is something that will go away by year end.
So that would sort of suggest that, I mean, if I'm just looking at the losses associated with sort of the ongoing numbers, it sounds like there would be, I guess, I don't see why you would get close to $0.15 of potential hit from corporate and other. Do you follow me? I mean, when you look at the guidance, it looks a little wide at $0.05 to $0.15 negative for the whole year and we're now half way through the year if you follow me and you're talking about the $0.06 reversing essentially, correct?
Yeah. The impact in corporate will reverse. The other thing to add is that the tax rate that we're calculating at the consolidated level is reflective of our expected end result. So I guess if you're thinking about taxes from an Avangrid point of view, really think of it more at the Avangrid level and not at the corporate level. That's more just a balancing factor.
Just moving on to Tule and El Cabo, are those situations completely resolved now? Do I understand you guys correctly on that?
Tule has been. That was a transmission line within the property and that's been replaced and we had a catastrophic failure of that line and the startup issues we've had with the turbines at El Cabo have been mostly fixed. We’re still working on a few things there, but the production is up almost the full, but not quite yet.
And then just finally on the offshore wind. Do you guys or are you guys planning on having firm EPCs for that being built out or how should we think about just, it's – obviously, it's a big sort of offshore deal. I’m just wondering how should we think about how you guys are or with your contractors sort of, how you’re sort of mitigating the potential issue of cost overruns or something like that?
Like seven packets for different -- all the different components of the development of the project and each one is going to be looked at separately, whether it's the turbines, the foundations, the transmission lines, the substations, the offshore substation, I mean, there's a whole, all these different packets and each one is going to be developed separately and Laura, do you want to fill in on what you’re thinking?
Yeah. Absolutely. And just in general, I would say that in our initial discussions with suppliers, it's been very positive. I think everybody recognizes that we're not just starting a project here, we're starting an entire industry and so everybody is kind of in this together and there's give and take and clearly to the extent that we're able to mitigate risk by putting risk on to suppliers, we’ll absolutely work to do that, but this is a partnership with all these suppliers and I think we're going to end up in a good spot all together on this.
And next question comes from [indiscernible].
Can I just ask, you mentioned the transmission line issue, you said, do you know which month it was that it was down.
This was a transmission – transmission is probably the wrong term. That was at our facility itself, connecting the different wind turbines to our substation and that is the line that went down. It was internal to us and that was in May. So it wasn’t an external transmission line.
And then just can I just ask on the El Cabo, if I remember correctly, we also had some issues in December or I forget in the fourth quarter, you mentioned it hurt you by I think $0.03 or $0.04. So I'm just trying to understand why it's kind of like repeating it so after like nearly six months, we took some hit if I am correct in fourth quarter of last year and again now in the second quarter of this year, I don’t know if you could tell a little bit better?
That was last year was really because the transmission of -- this was -- that was a transmission line that was put out of service that would have taken the power from the New Mexico into Southern California. So that caused a transmission outage that went into what was in the fourth quarter? The startup of the turbines not performing to our expectations, the best way to put it. They’re working, but not at getting the capacity out that we need at the moment. That’s improved dramatically and so this has been a process working with to get these things at their production capabilities.
And then the last question is, can you just talk about, you mentioned the selling on the development side. So how much can we expect, how many megawatts each year could that be, could that be in the range of.
We really don't know at this point. I think we're looking at our entire pipeline as we always do to see what makes the most sense and what we can get the most value out of by selling or not so. It could be arranged. So I have no idea of what it could be at this point.
[Operator Instructions] I'm not showing any further questions at this time. I would now like to turn the call back over to Jim Torgerson for closing remarks.
Okay. Well, thank you, everybody for participating in the call today. We're happy that you all can be on this and we thank you for looking at this. And we’ll talk to you all soon I’m sure. Thank you very much.
Ladies and gentlemen, thank you for participating in today's conference. This does conclude today's program and you may all disconnect. Everyone, have a great day.