Emera Inc (EMA) 2012 Q3 法說會逐字稿

Good afternoon, ladies and gentlemen. Welcome to the Emera third-quarter 2012 conference call. I would now like to turn the meeting over to Ms. Jill MacDonald, Manager of Investor Relations. Please go ahead, Ms. McDonald.

Good everyone, and thank you for joining us for our third-quarter conference call this afternoon. Joining me in Halifax are Chris Huskilson, President and Chief Executive Officer of Emera; Scott Balfour, Executive Vice President and Chief Financial Officer of Emera; and Gerry Chasse, President and Chief Operating Officer of Emera's Maine Utilities. Rob Bennett, President and Chief Executive Officer of Nova Scotia Power is unable to join us today as he is testifying before the UARB.

Emera's third-quarter earnings release was distributed earlier today via Newswire and the financial statements and Management's Discussion and Analysis are available on our website at www.Emera.com. This afternoon Chris will begin with a Corporate update and then Scott will review the financial results in detail. We expect the presentation segment to last about 10 minutes after which we'll be happy to take questions from analysts and investors.

Please note that all amounts are in Canadian dollars with the exception of Emera's Maine and Caribbean utility operations where segment results are reported in US dollars.

I will take a moment to remind you that this conference call may contain forward-looking information, which involves certain assumptions and known and unknown risks and uncertainties that may cause actual results to be materially different from those that are expressed or implied by the comments. Those risks include but are not limited to weather, commodity prices, interest rates, foreign exchange, regulatory requirements, and general economic conditions. In addition please note that this conference is being widely disseminated via live webcast. And now I will turn things over to Chris.

Thank you, Jill, and good afternoon, everyone. Emera had another strong quarter with consolidated earnings for Q3 of 2012 of CAD44.7 million, compared to CAD40.8 million in the third quarter of 2011. Earnings per share were CAD0.36 for Q3 of 2012 and CAD0.33 for Q3 of '11. Scott will take you through the details of the quarter later in his remarks.

There were several developments in Q3 and I'd like to take a few minutes to take you through them. Beginning with the Lower Churchill project, on July 31 we completed and signed the commercial agreements with Nalcor Energy. The signing of these agreements was a key milestone for the project. And you can find all 13 signed documents online at Emera Newfoundland and Labrador's website. On October 30, Nalcor and Newfoundland government released their package of information to the Newfoundland House of Assembly on Muskrat Falls. This package included Nalcor's Decision Gate 3 cost estimates, the Manitoba Hydro international report on the review of these costs, and information outlining the continued benefit of building Muskrat Falls against an isolated island case. As expected, Nalcor's cost estimates have increased since their original forecast two years ago. And we know that these cost changes are the result of advancements in the level of detail of their design and engineering work to add improvements to the project. The Newfoundland House of Assembly is expected to address the project in two or three weeks after the members have had time to review the information that was released.

With respect to Emera's schedule for the Maritime Link, we are currently preparing our filing with the Nova Scotia regulator and are working hard to have the Maritime Link application ready to file this fall. However, our filing is dependent on the final details of the federal loan guarantee, so we will not make our application until that process is completed. At the time of our filing, we'll provide a range of costs for the Maritime Link and we'll refine these cost estimates between now and next fall as we get closer to approving the project next year. The Maritime Link is the best option for Nova Scotians to comply with the federal greenhouse gas regulations and we will file all information for Nova Scotia customers to review and discuss before the decision is made.

Keeping with developments in Nova Scotia, we're pleased that Nova Scotia Power reached a rate settlement with customer representatives on 2013 and '14 electricity rates. This represents the first multiyear rate settlement in Nova Scotia Power's history and we believe it strikes a fair balance between keeping rate increases stable for customers while ensuring cost recovery for the utility. The UARB's decision on the settlement is expected in Q4 of this year.

Subsequent to the quarter, Nova Scotia Power reached a three-year deal with its unionized employees, with wage increases of 2.65% per year and, importantly, the agreement includes amendments to the defined benefit pension plan to increase its long-term stability and affordability. And finally the transfer of the Port Hawkesbury Paper Mill to Pacific West Commercial Corporation has been completed. The plant has resumed production which means it is back to contributing to the fixed costs of the electricity system in Nova Scotia. Nova Scotia Power worked very hard with all parties to make this happen and we're happy to see business resume for an important contributor to jobs and the economy in Eastern Nova Scotia.

Our services business had another good quarter. Most noteworthy, we recently completed a very successful upgrade of our Bayside Power facility. The planned outage was completed on time and on budget and without any lost-time accidents. The plant returned to full service this week and initial performance has significantly exceeded our expectations. Our business case was based on achieving a 30-megawatt increase in plant output and the performance so far indicates we have exceeded the target by 30%. So we're very pleased with the outcome.

Our Maine Utilities performed well this quarter and the integration of Maine Public Service is going well. In October, Bangor Hydro and Maine Public Service filed a report with the Maine Public Utilities Commission that outlines the cost savings and benefits associated with integrating the two utilities. Over the past two years, we've realized more than $2.5 million in annual cost savings and going forward, we anticipate saving up to an additional $1 million annually, if permitted to consolidate the utilities. We expect to file a request to fully merge the two companies by mid-November.

Also in Maine, we continue to make progress on the development of the Northeast Energy Link project with our partners National Grid. During the quarter the interagency review panel in the state of Maine adopted rules to permit the use of the state corridor along I-95 and the Maine Turnpike. The Northeast Energy Link filed an expression of interest with the panel on October 1 and they are expected to begin processing the application later this fall.

We continue to be pleased with our investment in Algonquin Power and we are currently requesting approval from the Maine Public Utilities Commission to increase our ownership level to 25%. The MPUC held a hearing on the matter this week and we expect a decision by Q1 of next year. During the quarter we exercised 9.6 million subscription receipts in connection with Algonquin's Gamesa and Atmos transactions. These transactions brought our ownership interest in Algonquin up to 17.85% and we realized an after-tax gain of $2.7 million in the quarter on these transactions.

We continue to make good progress in the Caribbean. Our West Sunrise plant has been online in Grand Bahama since June 28 and is performing well. Like the Bayside upgrade, this investment has also been done on schedule and on budget and fits perfectly within our strategy of moving to cleaner sources of energy. Importantly, effective July 1, we have a restructured rate plan in place in Grand Bahama which will allow for the recovery of the investment in the new plant at a lower all-in cost to customers. In Barbados we continue to see operating efficiencies and remain focused on developing a clean energy island strategy. We're working closely with all stakeholders to ensure the success of the nation's renewable energy and energy efficiency plan and expect to see this plan introduced into legislation this year.

I'd also like to take a moment to address the devastation that was caused by Hurricane Sandy. We were thankful that the people in our Maine and Nova Scotia service territories were relatively unaffected and didn't experience near the disruption from the storm as some other areas in Eastern Canada and the US. We were glad to be able to help the US in a small way by deploying crews from Bangor Hydro, Maine Public Service, Emera Utility Services, and Nova Scotia Power to assist with the restoration. The island of Grand Bahama was directly impacted by the hurricane but power was restored to 70% of our customers within 40 hours after the storm and 98% of customers had power back within 72 hours.

We are pleased with our results for the year so far. In light of our strong results, the Board of Directors approved an increase in the annual common share dividend from CAD1.35 to CAD1.40 per year within the quarter. This increase reflects the Board's confidence in our future earnings prospects and in continuing success of our strategy.

And lastly, as Emera grows and expands we continue to make our business stronger by deploying the skills and experience of our people. I'm pleased to announce that we recently promoted two Emera Executives within the organization. First, Judy Steele has been appointed President and Chief Operating Officer of Emera Energy. Judy has extensive experience with Emera Energy having served as Vice President Finance and as a member of its Executive team from 2007 to 2011. Secondly, Wayne O'Connor the former President and Chief Operating Officer of Emera Energy has joined Nova Scotia Power as Executive Vice President of Operations. Wayne brings extensive energy market expertise gained over more than 20 years in the industry to his new role at Nova Scotia Power. Wayne and Judy are proven leaders and I congratulate both of them. With that I'll turn things over to Scott for his update.

Thank you, Chris. Our third-quarter results were released earlier today and are on the Emera website. And with the results reasonably straightforward I'll keep my remarks short.

As Chris referenced, Emera's consolidated net income for Q3 2012 was CAD44.7 million or CAD0.36 per share, compared to CAD40.8 million or CAD0.33 per share in the third quarter of 2011. When results are normalized for mark-to-market adjustments, Emera's adjusted net income for the third quarter of 2012 was CAD43.8 million or CAD0.35 per share, compared to CAD41.4 million or CAD0.34 per share for the third quarter last year.

Turning to our segmented results, Nova Scotia Power contributed CAD22.6 million to consolidated net income in the third quarter of 2012, compared to CAD21 million in third quarter of last year. Earnings are up modestly year over year as a result of increased rates, offset by the impact of residential and industrial load reductions. Management remains focused on cost reduction and Nova Scotia Power is still on track to earn within the regulated ROE band this year.

Emera's Maine Utility operations contributed $11 million to consolidated net income in the third quarter of 2012, compared to $9.4 million for the same period in 2011. The increase in net income is primarily a result of a transmission rate increase in Q3 of this year. Our Services, Renewables, and Other Investment segment had another strong quarter contributing CAD8.2 million to consolidated net income in the third quarter, compared to CAD2.3 million for the same period last year. The mark-to-market gains at Emera Energy Services and the CAD2.7 million of after-tax gains realized on Algonquin's subscription receipts offset the decreased revenue and earnings contribution from Bayside being shut down during the quarter for a planned outage.

Caribbean Utility operations contributed $7.2 million to consolidated net income in the third quarter of 2012 compared to $10.7 million in the third quarter last year. You may recall that in Q3 of last year we realized $4.7 million related to the [regulated] recovery of an asset impairment charge in Grand Bahama. When you normalize prior-year results for that recovery, net income in the Caribbean is up $1.2 million year over year. When you look at the earnings from that perspective, the primary driver for the increase was due to Grand Bahama Power's rate structure changes and improved efficiencies within Barbados Light and Power.

Pipeline net income contribution was consistent in both years, at CAD6.8 million in the third quarter of 2012 compared to CAD7 million in third quarter last year. Looking ahead, our average earnings per share growth of 4% to 6% over three to five years remains intact, with a strong core business and robust portfolio of greenfield development projects in front of us. That concludes my remarks. And now we'd be happy to take your questions.

(Operator Instructions)

Paul Lechem, CIBC.

On the Lower Churchill, Chris I was wondering if you could give us some more details. Maybe can you start by just walking through what the timing is of the various sanctions that you need to actually start moving ahead with some of your investments? And also the other thing I want to understand a bit better is the impact of the increased cost estimates for the Labrador Island Link and what impact that has on you.

Okay. Thanks for the question, Paul. First of all, the very first thing that will happen is what's going on in the Newfoundland legislature right now. And so the legislature will deal with the project and ultimately that will turn into a sanction of the project.

And so that will mean that the Muskrat Falls facility, the lines to Churchill and the lines roughly to the St. John's area will be endorsed and be moving forward. Next, we need to finalize the federal loan guarantee and we are certainly hopeful that will happen this year. There's certainly a lot of work going on and we expect that should happen.

There's also one more environmental release that needs to happen on the Labrador Island Link and we would expect that to happen within the next six months. We would also expect that the environmental release for Maritime Link should happen in that same relative timeframe at least by Q3. Then there is the application before the regulator where again we're hopeful to make that application before the fall is out and that we would expect to see an outcome from that six months after we've made the application.

And then last but not l east, later this fall we'll have finished our engineering work and have our estimates in shape and late in the fall of '13 Emera should be in a position to approve the project. And I think that's the timeline until we actually begin construction.

Okay. Thank you. And the impact of the increase on the Labrador Island Link, the CAD2.1 billion to CAD2.8 billion impact, are you still going to be -- how does that work? Are you still 29% owner of that link or are you still -- are you staying at a CAD600 million investment? How does that work with --

The actual contract actually calls for us to own 49% of the transmission so that will get calculated as we move through -- and certainly the amount of equity that we invest in transmission in Newfoundland will have gone up. I would say we haven't finalized that calculation yet. In fact, it will be an ongoing calculation that won't really be finalized until construction of the project is completed. But we certainly will begin once Newfoundland has sanctioned the project. We will begin to report on how that's changing.

Okay.

I think that says it well. I think, though, for your modeling, clearly the fact that the Labrador Island Link costs are higher and will drive a higher investment opportunity for Emera. And that the math can't be precisely done of course until the Maritime Link costs are done because as Chris quite rightly said our investment is actually 49% of all of the transmission assets combined.

But for sake of your modeling right now I think you could look at the same 29% interest, roughly speaking, against that higher cost estimate for Labrador Island Link in order to look at what the investment opportunity is for Emera.

Okay. And one more question if I may, just on this. Are you able to then to recover -- so if the costs come in at the current CAD7.4 billion number I think estimate is, are you able to recover your increased costs through return on rates? Any risks of you not being able to recover all your costs incurred on this?

First of all, on the Labrador Island Link investment, we actually have an arrangement with Nalcor that is clearly articulated into the agreements as to how that will work and so the answer would be yes to that. As it relates to the Maritime Link, as we said, we are just finalizing the level two engineering for that link, and so we don't have the higher level -- the best level of engineering completed yet. We don't expect that to be complete until late in '13.

And so what we will be doing with the UARB is filing a range of cost and then all of our comparisons and information we file on Maritime Link will take that cost range into effect, and then we'll go through the decision process with the UARB. And we'll be able to answer that question when we're finished the rate hearing on that project.

Okay. Thank you very much.

Linda Ezergailis, TD Securities.

Maybe just a follow-up to Paul's question on recovering cost ROE's. My recollection is that with the Maritime Link that Emera would absorb 50% of any cost increases. Is that post-project sanction? Or is that at some previous time?

That is post-approval by the UARB, and after the UARB has looked at prudency of costs. First of all we will file a range. The UARB will make their decision. Should we be successful in that decision and they approve a particular cost for the project, then it will be the cost as submitted, so there's no challenge at this moment because we'll file a full cost range that will cover the costs that we're now discussing. If further there are challenges, then prudency will come into play and then the cost-sharing formula will come into play.

And when you get the final number from the UARB in terms of the approval and a cost estimate embedded in that, what estimate would you have about having locked down what certain percentage of those costs?

First of all, what we'll be filing with the UARB will be a P50 and a P90 cost for the project. So we'll have a 90% certainty that the costs should not exceed that number based on the estimate that we'll be filing. That's from an engineering perspective. By the time we get to the point of actually approving the project, we'll have at least 60% and possibly higher than that completely locked down in contracts. In fact, we would believe that the amount that we can lock down could possibly exceed that 60%.

That's reassuring. Thank you. Now moving onto your existing operations, just wanted to get some more color on the NSPI fuel cost audit. What was the nature of the conceptual calculation and what could be the range of disallowances in the event of a negative decision?

This is a historical decision in terms of 2010 and '11. So I'm wondering how might this already affect then potentially 2012 and '13 earnings if there are disallowances that you've already made decisions on prospectively without knowing of a negative decision? Another question of context is what changed in 2010 versus 2009, if anything, that affected this disallowance in the recommendation in the audit?

First of all, we would say that we believe that everything that the Company has done has been prudent and in the interest of customers. One aspect was talking about the replacement of certain coals in one of the power plants. On the one hand, it caused the power plants to not operate as effectively as they sometimes would. On the other hand, the cost of the coal that got put in the plant was much cheaper than the other coals. So there's a balance between those two things.

And so we would have submitted evidence and as I said earlier, Rob -- as Jill said earlier, Rob is there testifying to this as we speak, but we would have submitted evidence that actually says that there will be no disallowance because we believe that everything the Company did was prudent. And so at this point, that is what we believe to be the case and we believe that will be upheld by the decision when it comes out.

Okay. That's reassuring, but can you maybe walk us through the conceptual calculation and what the magnitude of the disallowance risk there is? And how that might affect -- did you continue this practice in 2012 and is it already locked down a little bit for 2013 as well?

We are talking about events more than we are talking about practices. And so I think what has been claimed falls into two categories. One category which would be future issues around gas costs and that is a future issue -- and that's about half of what's being claimed. And the other half is related to both gas and coal, which would be more related to incidents.

So there is no future issue from the second portion. And the other priority is not even determined. And so again, I think we feel very confident in our case and we would say that we've acted in a prudent fashion and in the best interest of customers.

Okay.

Just to add a little bit to that, Linda. The amount of that was claimed as a matter of record is -- it was CAD22 million and also the record would now reflect the CAD12 million of that, thereabouts. It relates to the future portion that Chris was speaking to that's a little bit more theoretical in terms of the basis of calculation.

And it's the CAD10 million that is the substance of the hearing that's going on now that fundamentally we disagree with both portions of it. But the piece that is relevant to rate payers in Nova Scotia today is the CAD10 million that's the substance of the hearing that's taking place and that's both of the issues that Chris spoke about that we disagree with. And we'll wait for the decision from UARB.

Thank you. Assuming you are successful in that, how might that change how you approach your caution and pre-approval of practices and getting the regulator more involved up front so that there's no historical surprises like this?

I'll just take the coal example. There is no way to have predetermined that particular situation. It's an incident and we would say the incident was caused by a combination of a change in coal and also an amount of rainfall that occurred on the site. And so you can't predetermine that kind of thing. I think what we're doing right now is appropriate. We have put forward evidence that would say that the Company continues to manage its fuel in the best possible way. And we'll await the decision. That's great. Thank you.

Juan Plessis, Canaccord Genuity.

This was the first full quarter with Northeast Wind joint venture. Can you tell us what that investment contributed to net income in the quarter?

Yes. We have really two components to our involvement with Northeast Wind because we have an equity investment and we also have a loan that was provided as part of the transaction. And so the CAD150 million loan contributed income at the expected rate. The equity contributions for the period were modestly negative, with an expectation that the seasonal nature of that business would generally drive lower results during that period and we're early days for this transaction.

The nature of these kinds of investments, which is different than core investments that we have in businesses like Nova Scotia Power and Bangor-Hydro where we've got a reasonably strong EBITDA performance but because of the nature of the accounting for them within an unregulated environment, obviously we're deducting a depreciation and interest cost. So the earnings profile for these businesses build over time and so the earnings results for the quarter were modest and generally within expectations.

Okay. Thanks for that. And maybe sticking with that transaction, the Maine PUC approval has been appealed. Can you give us a bit of color on the issues around that?

In general, the appeal is related to the fact that some of the interveners felt the Maine Public Utilities Commission overstepped its bounds and its authority to provide some of the various restrictions that they've placed on the Company as a result of the decision. And so that's really the basis. We feel very strongly that we're in a very good place and we're looking forward to the outcome.

Okay. Thanks for that. And just finally here, housekeeping item, can you separate the mark-to-market gains and losses at Northeast Wind and the mark-to-market gains on the natural gas contract at Emera Energy Services?

I don't think we've provided that disclosure in our MD&A. I think we've just grouped it in together. We can reflect upon whether that additional disclosure is helpful, but I think for the time being I don't have the numbers ready at hand. So reflect on that, but generally right now we've just kept those mark-to-market adjustments within the segment. I don't think one number or the other stands out relative to the total. So it's sort of a balance between the two. There's not one that's the lion's share over another.

Okay. Thanks for that, Scott.

Andrew Kuske, Credit Suisse.

My first question just relates to your interest in the Brunswick Pipeline. And given that Repsol is actively looking to sell their LNG business en masse, do you have any counterparty protections as it relates to really just a change of your counterparty on Brunswick if Repsol exits entirely and someone else steps in? What kind of recourse do you have if, say, the credit quality is just very different?

Where we are today is we actually have a guarantee from Repsol YPF and part of the criteria is that the credit quality has to be the same. And so at the end of the day, if part of the business is sold, we will be looking to Repsol YPF to deal with that.

And arguably one of the reasons they're looking to sell is they have their own balance sheet issues. You probably have a better credit quality step in.

I think at the end of the day, the credit quality is defined in the agreement that we have and we're comfortable with our credit quality and so as long as they can meet that, then things will be fine from our perspective.

That's helpful. Turning the attention to Maine, a merger of those two utilities, you mentioned some of the costs that you could strip out. Will there be any benefit to effectively Emera as a shareholder of the two utilities or is there any kind of benefit any kind of cost savings? Will that just accrue to rate payers?

I think to the extent that we can stay out of rates for the immediate future, I think that benefit flows to the shareholder. And clearly the savings that we've been able to accrue to date have allowed us to do that. And we expect that the future savings that we will achieve by merging the two utilities more fully will allow us to do that further.

I think, Andrew, the bottom line is that over the long term those do accrue to customers and you know that going in the door. The reason really that we've bought that business and looked to merge those two utilities is because we see the opportunity to continue to invest in transmission in that area.

For us it's quite strategic in that renewable energy is going to occur in Northern Maine, it's going to occur in the Maritime and Atlantic Canada. And we see ourselves as both aiding in getting that renewable energy built and also in bringing it to market. And having that footprint, having that participation in that part of the state of Maine we think will be crucial to that outcome. And it flows along. In my remarks we talked about the corridor commission and the work that's going on there on I-95, et cetera. And we're quite excited about the potential there as well.

Just as a matter of looking at this very practically, if you have just one utility, it really makes your life a lot easier from a filing perspective to the regulator and really multiple regulators at times on transmission initiatives, just for the sake of argument.

I think we would also argue that we can deliver ultimately better service to our customers as we put -- as we homogenize the service across that territory and have a more efficient operation.

That's very helpful. Thank you.

Ben Pham, BMO Capital Markets.

Just going back to that Repsol question and LNG export and obviously a hot topic on the western side of Canada. But there's a long-shot proposal on Eastside now. And just broadly, a sense in terms of potential development to export gas. Do you see that as an opportunity for you guys or more something directionally negative?

No. I think we look at any development in gas in this part of the country to be a positive. I think we all would be well aware of the fact that gas supply at this point now is in question. The stable resources are in decline. Deep Panuke has a relatively short lifespan based on the current projections.

And so I think anything that brings more gas to the region, and clearly if you are exporting gas you have to have gas to export and so somehow or another gas would have to be brought to the region. We would expect number one for that to be good for the region, and number two we would also expect that we could find a way to participate as well in that we certainly do a lot of business in this particular area.

Okay. Thanks for that, Chris. Circling back to the Lower Churchill, and thanks so much for the update on that. I wanted to ask about the investment opportunity beyond the base project. Just curious on the degree in which you think there's additional transmission opportunities in Nova Scotia on the investment side. And I think you talked about a CAD200 million before, but can you give a quick update on that?

For sure as we sit today, we're really clearly focused on getting the project that's in front of us across the finish line from an approval perspective, getting all the various permits we require and moving that forward. So that's clearly where our focus is. From our perspective at this moment, there will continue to be smaller investments as we continue to consolidate generation needs and generator lead-type investments.

And then lastly, we see the connection between what will happen in Labrador and in Northern Maine and the possibility for NEL. So it's that kind of a picture that we would see as being quite appropriate.

And the one thing that will happen is with Nalcor moving energy through Nova Scotia through New Brunswick and into the state of Maine, that's going to change the whole dynamic in the region. It's going to open up new possibilities and also open up new capacity on the transmission system because the traditional flows are the other way. And so West-East flows would be much more normal, and so East-West flows in this region will make a big difference to the capacity of the existing system.

Okay. And finally on Bayside Power you talked about the upgrade there. It's going pretty well. Can you remind me of the contracting strategy of that facility?

Well, the facility is contracted five months of the year to NV Power. It has, through the Point Lepreau outage, been contracted virtually 12 months of the year to NV Power as well. So as we see what happens with gas prices and with supply with Point Lepreau nuclear Pant back on, we will see the opportunity to contract that again. At this point it relies on that five month contract.

Okay. Thanks a lot.

(Operator Instructions)

Robert Kwan, RBC Capital Markets.

Just coming back to Lower Churchill and the federal loan guarantee can you talk about what are some of the reasons why it's taking a long time? Is this just things around dealing with government or some specific stumbling blocks?

It's as simple as wanting to make sure that with the federal loan guarantee that it reflected the updated estimate of costs from Nalcor for their two projects. And so it's simply a matter of updating and reflecting the change of cost structure and some finalization of discussions around the term of the guarantee to try to best match the intended term of our financing plan.

Those are really the two key issues. So now with Nalcor's numbers public, the federal government had benefit of some of that data a little bit earlier but they're working with that data and we're hopeful to resolve those last issues shortly.

Okay. That's great. Thanks, Scott. And then just turning to NSPI, with the Pacific West plant now up and running, is the approved load retention rate by the UARB, is that enough to be a noticeable uplift on top of the 2013, 2014 settlement?

I would say, Robert, it's a minor, minor contribution, not a material change.

Not enough to push the ROEs then? Is that fair?

That would be for sure.

Okay.

It reflects a small contribution to fixed costs.

Okay. Great. Last question on Maine. With the rate increase that became effective in third quarter, were any amounts there booked related to prior periods or is the third quarter just a true reflection of the new rates?

It would be a true reflection of new rates that went into effect beginning July 1 of this year.

Are you able to quantify between the old rates and the new rates how much regulatory lag there was that you caught up with in the third quarter?

Most of the regulatory lag has been eliminated due to the fact that some of those investments were put into rates prospectively that will go in the plan at the end of this year. So there's very little if any regulatory lag in the recovery of those investments.

Okay. I was just thinking more of if you didn't have the new rates, would -- put differently are the new rates -- did they help earnings by CAD1 million, CAD2 million?

How much capital would it reflect?

It would have reflected about CAD60 million of capital put in service prospectively.

Okay.

$3 million.

That will give you the order of magnitude on it.

That's great. Thank you.

Paul Lechem, CIBC.

Your outlook section shows some slight reductions in your CapEx plans for the balance of this year. Wondering for the whole year just wondering what drove the lower numbers and also if you can give us an update on your total planned spending on the Lower Churchill project this year?

I think it's just in relation to Churchill -- so right now we've got about CAD22 million of costs incurred including AFUDC project to date to the end of the third quarter. And if there's a change as it relates to the fourth quarter it's only in relation to the expected timing of the closing of the sanction for the Labrador Island Link project. At sanction we would be making a contribution to that project for the first time so it's just a matter of whether that occurs before calendar year-end or into early in the first quarter and at this point it's more likely to be early in the first quarter.

The CAD22 million looks like the number for the full-year then?

No. We continue to spend a little bit on Muskrat -- sorry, on Maritime Link but the big number that was I think previously expected would have been -- so we'll continue to incur costs as we continue our project development on Maritime Link in the fourth quarter likely at not too dissimilar a rate that we incurred in the third quarter.

Okay. And the changes to CapEx numbers for the year in Maine and SPI Caribbean, their minor changes but any thoughts in terms of what impacting those spending rates?

It's all just timing and pace, Paul. All of the project are pretty much still moving forward. It's just timing and pace.

Okay. Thank you.

Thank you. There are no further questions registered at this time. I would now like to return the meeting to Mr. Huskilson.

Thank you very much. We always appreciate the opportunity to speak with you about Emera. Thank you for taking the time today and I hope you all have a great weekend.

Thank you. The conference has now ended. Please disconnect your lines at this time and we thank you for your participation.