Q3 2017 Algonquin Power & Utilities Corp Earnings Call
Nov 15, 2017 AM EST
AQN.TO - Algonquin Power & Utilities Corp
Q3 2017 Algonquin Power & Utilities Corp Earnings Call
Nov 15, 2017 / 03:00PM GMT
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Corporate Participants
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* Alison Holditch
* Christopher K. Jarratt
Algonquin Power & Utilities Corp. - Vice Chairman
* David Bronicheski
Algonquin Power & Utilities Corp. - CFO and CFO of Algonquin Power Management Inc
* Ian E. Robertson
Algonquin Power & Utilities Corp. - CEO, President and Non-Independent Director
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Conference Call Participants
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* Benjamin Pham
BMO Capital Markets Equity Research - Analyst
* David Quezada
Raymond James Ltd., Research Division - Equity Analyst
* Jeremy Rosenfield
Industrial Alliance Securities Inc., Research Division - Equity Research Analyst
* Mark Thomas Jarvi
CIBC Capital Markets, Research Division - Director of Institutional Equity Research
* Richard Sunderland III
* Rupert M. Merer
National Bank Financial, Inc., Research Division - MD and Research Analyst
* Sean Steuart
TD Securities Equity Research - Research Analyst
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Presentation
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Operator [1]
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Thank you for standing by. This is the conference operator. Welcome to the Algonquin Power & Utilities Corp's Third Quarter 2017 Conference Call. (Operator Instructions) And the conference is being recorded. (Operator Instructions)
I would now like to turn the conference over to Christopher Jarratt, Vice President of Algonquin Power & Utilities Corp. Please go ahead, Mr. Jarratt.
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Christopher K. Jarratt, Algonquin Power & Utilities Corp. - Vice Chairman [2]
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Great. Thanks. Good morning, everyone, and thank you for joining us on our 2017 Third Quarter Earnings Conference Call. My name is Chris Jarratt, and I'm the Vice Chair of Algonquin Power & Utilities Corp. Joining me on the call today are Ian Robertson, Chief Executive Officer; and David Bronicheski, our Chief Financial Officer.
For your reference, additional information on the results is available for download on our website, algonquinpowerandutilities.com as well as a webcast presentation to accompany this earnings call.
Over the course of this call, we will be providing information that relates to future events and expected financial positions, which should be considered forward-looking. I direct you to review our full disclosure and non-GAAP financial measures, which are available on the website. We'll also read a full disclaimer at the end of this call.
As usual, kicking off the call this morning will be Ian Robertson with a review of our Q3 2017 strategic achievements. David Bronicheski will then follow up with financial highlights. And then Ian will conclude with our future outlook and details on our growth plan. (Operator Instructions)
And with that, I will turn things over to Ian Robertson.
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Ian E. Robertson, Algonquin Power & Utilities Corp. - CEO, President and Non-Independent Director [3]
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Thanks, Chris. Appreciate everybody taking the time to join us this morning for our Q3 2017 results conference call.
I guess, from the top line, I'm pleased to report that our diversified utility and regulate -- our nonregulated generation portfolio has delivered another quarter of solid financial and operational results. But clearly, our focus of today's call will be to highlight some of the exciting initiatives that we've undertaken since our last call.
With the addition of Empire at the start of this year, APUC has been able to deliver another quarter of, I use the word, record financial and operational results, with close to 120% increase in adjusted EBITDA, 70% increase in our total assets. And while this significant year-over-year growth in enterprise metrics reflects the materiality of the Empire transaction, the per share increase of over 70% in adjusted earnings on a per-share basis is more meaningful in that it reflects the accretion of the Empire transaction along with our continued execution of our growth plans on the nonregulated power development side of our business.
In addition to strong financial results, we're very pleased to report several key accomplishments on the acquisition front. Firstly, 2 weeks ago, we announced the formation of a strategic joint venture with a company called Abengoa, which we refer to as Abengoa Algonquin Global Energy Solutions, or AAGES for short. An element of the execution on this strategy involved the purchase of a 25% equity interest in a company called Atlantica Yield, an organization which owns a portfolio of assets similar to those owned by APUC over the global footprint. Together, these transactions mark APUC's inaugural steps into the global energy and water infrastructure development arena.
Additionally, our Liberty Utilities Group repeated a busy quarter on the M&A front with the announcement of the acquisition of a natural gas distribution company in upstate New York called St. Lawrence Gas. And also during Q3, we announced the acquisition of 2 water systems in California from the City of Perris. And we're pleased that the requisite vote was approved by the citizens of Perris. And once we complete the approval process for these 2 utility acquisitions, we extend the Liberty Utility footprint into the State of New York, we strengthen our existing utility presence in California and we welcome over 20,000 new customers into our service territories.
And now a little bit more in depth into the Atlantica Yield and AAGES transaction. As I had mentioned previously on November 1, we're pleased to announce the formation of a new company, one which is jointly owned between Abengoa and Algonquin, which we call AAGES. AAGES will focus on the development of clean energy and water infrastructure projects in diverse global markets. It represents an exciting, but measured first step for APUC as we launch our global growth strategy. AAGES creates a unique opportunity for APUC to access a deep pipeline of development opportunities to expand globally with a proven experienced partner.
We also confirm that APUC had entered into a definitive agreement to acquire the 25% equity interest in Atlantica Yield from Abengoa. Atlantica owns and operates a portfolio of high-quality, geographically diverse clean energy, electric transmission, desalination projects across 4 continents. Strategically, the Atlantica investment provides a home for the projects which will be developed by AAGES. Tactically, the Atlantica investment will be immediately accretive to APUC's financial performance and further supports our dividend growth objectives.
Looking forward at the -- pardon me, AAGES joint venture, we believe it provides a measured strategic first step for APUC into markets outside Canada and the U.S. with a globally proven and experienced partner. The new organization will serve as the platform to develop clean energy and water infrastructure assets in selected global markets, and its development approach is aligned with APUC's criteria for global investment. Through AAGES, APUC will also gain strong access to import new modalities such as energy storage and water desalination through Abengoa's project pipeline.
As I mentioned, the investment in Atlantica secured a home for the projects, which will be developed by AAGES. Under the terms of the purchase of the 25% stake in Atlantica, APUC has the right to appoint 25% of the members of Atlantica's Board of Directors, and perhaps more importantly, has been granted a preemptive right to provide Atlantica with the capital it needs to pursue its growth aspirations. These aspirations include an immediate investment portfolio of more than $300 million in equity value for some commercially operational projects and a near to mid-term growth pipeline of commercially secured projects totaling over $800 million.
As I mentioned, we see these recent initiatives as representing a win, win, win for all parties. For Abengoa, the arrangement allows them to continue to pursue their back-to-basic strategy of being a global EPC contractor in the energy sector through the relationship with AAGES. Their recent financial results confirm that they appear to be on track in this respect. For Atlantica, the transaction resolves the uncertainty with respect to Atlantica's sponsorship and their pathway to growth. We're confident that with the sponsorship commitment through AAGES of a growth-focused organization, such as APUC, the relevance of Atlantica has been restored.
And lastly, for APUC, these initiatives represent our measured approach to global expansion. An important element of being an entrepreneur is intellectual honesty about risk. We recognized that the risk associated with moving into unfamiliar markets was real, and being able to capitalize on the global presence and history of Abengoa in these markets will materially reduce our exposure.
And now a quick comment about an opportunity that seems to have got lost in the noise of recent events. On August of this summer, we announced the acquisition of St. Lawrence Gas, a distribution utility, as you can see from the slide there. St. Lawrence Gas is headquartered in Massena, New York, and serves right now about 16,000 customers, but through close to 700 miles of gas mains and services.
I think one of the interesting opportunities that comes with St. Lawrence Gas is the ability to capitalize on infrastructure investment that has already been made to provide gas service into counties, which up till now have not had natural gas service. And while by small in comparison, St. Lawrence Gas definitely builds on our strong gas utility expertise and is consistent with our strategy to expand our regulated utility presence across the U.S.
So with that, I hand things over to David to kind of give a quick review of the quarterly financial results. David?
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David Bronicheski, Algonquin Power & Utilities Corp. - CFO and CFO of Algonquin Power Management Inc [4]
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Thanks, Ian, and good morning, everyone. We're pleased to report another quarter of strong financial results compared to the same period last year.
As Ian mentioned earlier, the inclusion of Empire is a key driver supporting our significant year-over-year growth, but we also have to call out and not forget about the continued growth that also exists within our other business units. In particular, we continue to bring online new generating assets compared to this time last year. We also have meaningful growth in our regulated utilities, aside from Empire, through growth in rate base and new rate cases. The diversity of our overall business continues to be a key component of our ability to deliver strong, sustainable financial performance to our shareholders.
Turning now to the financial metrics for the quarter. Our adjusted EBITDA was up 116% on a year-over-year basis to $197.5 million for the quarter. A total of $118.9 million of the adjusted EBITDA growth was sourced from new facilities, including the acquisition of Empire within our Liberty Utilities Group and the commissioning of new renewable energy facilities.
Taking a closer look at our individual business units and starting with Liberty Power. Liberty Power's operating profit decreased slightly compared to the third quarter of last year largely due to FX, but on a full 9 months of this year basis, has increased by 16% compared to the same time frame last year, primarily due to the addition of new generating facilities, in particular Odell, Deerfield and Bakersfield Solar.
On a production basis, Q3 production from our existing fleet of hydro facilities was 15% lower than the previous year and 17% lower than the expected long-term average resource. The shortfall in hydro production was mainly due to lower production from facilities in our Maritime in Western regions.
Looking at our wind production for Q3. Wind production was 16% stronger than Q3 2016, but below our long-term average resource expectations. The year-over-year increase can be fully attributed to a full quarter of contributions from Odell in 2017 and contributions from Deerfield, which was commissioned earlier this year.
Finally, production in our solar facilities was 23% higher than the previous year due to the addition of the 10-megawatt Bakersfield II Solar facility earlier this year. In aggregate, while Q2 presented some challenges for production from our existing fleet, our growth in new generation facilities more than offset this production shortfall.
Looking now at the Liberty Utilities Group. Q3 operating performance grew by an impressive 192% over the corresponding quarter in 2016, driven by Empire, which delivered as expected a contribution of $112.5 million in operating profit. As impressive as the contribution of Empire was, we continue to receive positive contributions from existing utilities. The implementation of new rates from successful rate cases contributed $7.3 million to Liberty Utilities operating profit in Q3 2017. While growth in our operating profit is important, what really matters to investors is whether this has translated into real per share growth, and it has. Adjusted earnings per share came in at $0.16 per share, which is 78% higher than the year before.
I'd like to now comment briefly on our financings. We were extremely pleased by the positive reaction from the Capital Markets to our $576 million common equity financing on November 1 with a solid use of proceeds being the creation of AAGES and the purchase of a 25% stake in Atlantica. The offering had both strong institutional and retail demand and attracted new institutional investors to APUC from around the world. We have also refinanced our Liberty Power revolving credit facility, upsizing it to USD 500 million and expanded the bank syndicate to provide Liberty Power with the additional liquidity that we foresee that it will need to continue growing over the next 3 to 5 years.
As a quick update on our convertible debentures, 99.7% of the CDs are now converted to equity. I would once again remind the few remaining debenture holders that these debentures are no longer interest-bearing, and I would encourage these holders to contact their broker to complete the conversion to common shares.
Before I turn things back over to Ian, I'd like to provide a few comments on U.S. tax reform in the United States. And I'll start by saying that the analysis of the impacts of the tax changes being considered in the U.S. still involves a high degree of uncertainty since the proposals by the House and Senate are different and remains subject to change. Generally, though, the proposals as it pertains to Algonquin falls into 2 buckets: one, potential for changes to the laws regarding production tax credits; and two, changes in the corporate tax rate and other items like interest deductibility and deductibility of capital expenditures.
First, with respect to the corporate tax rate and other corporate tax changes, we would note that it appears there was going to be a general carve-out exemption for regulated utilities, which will effectively see the tax regime remain much as it is today for interest deductibility and CapEx deductions. We also note that any lowering of the effective tax rate would likely get [reflected] at some point in customer rates. So all in all, the 70% of our business that is regulated would appear to be largely unaffected. But we should not lose sight of the fact that we still have about 30% of our business in the nonreg space, and 2/3 of that is in the U.S. So tax reform would actually be a net positive for that part of our business. As a result, we continue to be of the view that U.S. tax reform would be a slight positive to our EPS.
With respect to the PTCs, we continue to believe that the existing rules regarding the phase out of the PTCs will remain intact together with the current rules regarding safe harbor turbines. Nevertheless, it does appear that the House is now converging on to the Senate's view. And so we believe that our greening of the fleet strategy within Empire remains intact and will be able to deliver significant savings to customers over the life of the wind farms. I would also note that there are existing renewable power projects in development in the Empire region that would also meet the continuous construction criteria in the House proposal in any event.
So with that, I'll pass things back to Ian to comment on our plans for the rest of this year and beyond.
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Ian E. Robertson, Algonquin Power & Utilities Corp. - CEO, President and Non-Independent Director [5]
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Thanks, David. And we'll be opening up the lines in a moment to take questions from those on the call. But consistent with our past practice, I'd like to first provide an update on our growth initiatives for the final quarter of 2017 and as we look into 2018.
Within the Liberty Utilities Group, our investments in system improvements have continued unabated. We completed 9 rate cases so far in 2017 that will contribute close to $24 million in increased revenue requirements. Another 6 rate cases totaling close to $40 million in requested incremental revenue requirements are currently pending.
As I mentioned earlier, we continue to seek out new M&A opportunities and the acquisitions of St. Lawrence Gas and the City of Perris' water systems. We see a strong evidence that we are continued to be committed to prudently growing a number of customers we serve within Liberty Utilities.
And lastly, our growth plans involve the cross-functional work between our Liberty Utilities and Liberty Power groups in furtherance of our greening the fleet strategy, which we've talked about for Missouri, Arkansas, Oklahoma and Kansas. We believe that our utility customers will benefit greatly from transitioning our fleet of coal-dominated power generation to low-cost environmentally friendly renewable energy alternatives.
To support a portion of this new generation, on November 1, we submitted our plans to reduce customer rates though the development of 800 megawatts of strategically located wind generation by 2020 in the Midstates. This project is -- in fact, actually it's 3 or 4 projects are expected to generate cost savings for customers of over $300 million over the first 20 years following their commissioning. And it seems like a win-win opportunity for both cost savings for our customers, but also conducting our business practices in an environmentally responsible and sustainable manner.
Within our nonregulated Liberty Power Group, we're advancing our portfolio of commercially secure construction development projects, which currently total approximately 360 megawatts across 5 projects. Construction is proceeding in Maryland at our 75-megawatt Great Bay Solar project, with commercial operations expected later this year. And construction activities at our 75-megawatt Amherst Island Wind Project are underway, with turbines expected to show up later this month.
In addition to advancing our existing pipeline development projects, we're maintaining our commitment to new developments in the U.S. renewable energy markets, supported by our safe harbor turbine purchases completed last year.
As I mentioned before, we're excited to have made a strong commitment to international development through the formation of AAGES and our investment at Atlantica. These commitments will serve as the cornerstone for our international growth over the long term. AAGES provides a balanced entry into international growth with strong local partners, proven technologies and new geographic locations that will adhere to APUC's criteria for development.
In addition to providing a future home for AAGES-developed projects, the Atlantica investment confers benefits to APUC, in that it will be immediately accretive to key financial and operating metrics and will support our dividend growth objectives to a steady dividend stream. We look forward to working closely with Atlantica and Abengoa to close the transaction and start our pursuit on these new international development fronts.
To conclude, we're confident that APUC's financial and strategic objectives will be met through these various avenues for growth. We continue to forecast strong financial and operational results for long-term growth in earnings and cash flow supporting our growing dividend.
And lastly, as a teaser for what's coming up, we are -- just wanted to provide a reminder to our investors and analysts of our upcoming Investor Days, which we'll be holding both in Toronto on December 5 and again in New York on December 8. We've provided the event and registration details on the slide, and we obviously look forward to seeing you there. So with that, operator, it concludes our prepared remarks and perhaps we could open up for questions.
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Questions and Answers
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Operator [1]
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(Operator Instructions) Our first caller comes from David Quezada of Raymond James.
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David Quezada, Raymond James Ltd., Research Division - Equity Analyst [2]
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My first question here just bit of a housekeeping question on the St. Lawrence Gas acquisition. I noticed in the release, it said late 2018, early 2019 expected closing date. Is that a little bit later than you had initially expected and maybe what the -- just what the regulatory process is there?
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Ian E. Robertson, Algonquin Power & Utilities Corp. - CEO, President and Non-Independent Director [3]
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No. I mean, I think for -- I guess, in general, we want to avoid disappointment. You can imagine that the regulatory process, particularly in a state in which we haven't been before, there's a little bit of unknown. We have had meetings with the staff, and we're actually meeting with the commission next week. So we're cautiously comfortable that the Liberty Utilities proposition will be as well received in New York as it's been elsewhere. But we don't want to overpromise, if you will. It's a small acquisition and the last thing we want people is to be disappointed. So I think we're still targeting late next year, just given the kind of normal course for these things. But just so, don't read anything into it of significance.
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David Quezada, Raymond James Ltd., Research Division - Equity Analyst [4]
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Okay, fair enough. And then just my only other question here. The -- I believe in the Empire territory, you were going to do an RFP for wind. That was slated for, I believe, September, October. Any color you can provide on how that went?
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Ian E. Robertson, Algonquin Power & Utilities Corp. - CEO, President and Non-Independent Director [5]
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Yes. The RFP was indeed opened, as we had outlined. And maybe just a little bit color, David, for the rest of the listeners. That RFP was really to make sure that as Empire looked to getting the most competitive wind projects in addition to the projects that it has under development for its own -- on its own, we want to make sure that perhaps there were third-party developers, who -- whose projects would be equally and perhaps even more competitive. And so really this is an augment to Empire's plans of developing 2 projects, which it currently has in Missouri. So we're expecting that RFP to close in early December. And initial indications, because clearly, we're obviously in dialogue with all the RFP participants, is that it is being robustly pursued. So we are -- at this stage, we're sort of cautiously optimistic that we'll get opportunities that are equally competitive to the ones that Empire has underway right now, upon which, to be frank, our submission to the Missouri commission was premised. So things will likely only get better from where we are right now in terms of customer savings.
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Operator [6]
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Our next question comes from Rupert Merer of National Bank.
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Rupert M. Merer, National Bank Financial, Inc., Research Division - MD and Research Analyst [7]
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So it sounds like you still see more tuck-in opportunities on the regulated utility side in the U.S. with consolidation of that market. How should we look at the scale of the opportunity there versus your international markets and power markets now? And do you have potential for international investment outside of Abengoa and Atlantica?
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Ian E. Robertson, Algonquin Power & Utilities Corp. - CEO, President and Non-Independent Director [8]
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So in the first instance, for your first question, Rupert, I think we're pleased that the Empire acquisition, if you will, increased the aperture of the size of M&A opportunity that Algonquin could pursue in the U.S. regulated utility market. And so opportunities and business combinations that might have been beyond size-wise are now within scope. But I'm also pleased that -- I don't think we've raised the low end of the bar, if you want to think of it that way. Maybe that's where your question is really headed that St. Lawrence Gas, in the first instance, represents USD 70 million of investment potential, but -- or acquisition potential. But I think as we've outlined in -- is that one of the real wins for St. Lawrence Gas is to capitalize on some infrastructure, which Enbridge, who currently owns it, has built into the system to bring natural gas to counties that heretofore haven't had natural gas service. So great opportunity for us to continue to invest in the distribution side of the business. And so we could quite easily see this topping USD 100 million. But I think the short answer to your question, this organization has crafted as a core competency its ability to acquire and ultimately integrate utilities almost of any size. And so we don't discriminate on the small end of things, and the larger end of things has gotten bigger. So there's -- I -- hopefully, that's responsive to your first question. Your second question is about the scope of international development. I think we're comfortable that AAGES represents our vehicle for international power projects development. And it's certainly noncompetitive to our interest in Canada and the U.S., which is, I'll say, our backyard. And we were pretty clear about that on the earnings call. It doesn't extend and maybe where your question was going, if it's related to your first question with M&A, to potential M&A opportunities for regulated utilities. To be frank, so far, that hasn't been our focus. I think as we grow increasingly comfortable with some of these international markets, in which some of the projects of both Atlantica and maybe the ones that AAGES will undertake are located, maybe that comfort level will increase, so we could start to think about it. But that's not really on our radar scope right now, if that's where your question was headed, Rupert.
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Rupert M. Merer, National Bank Financial, Inc., Research Division - MD and Research Analyst [9]
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Yes. That's good. I guess, we frame that as 2 questions. I better get back in the queue.
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Ian E. Robertson, Algonquin Power & Utilities Corp. - CEO, President and Non-Independent Director [10]
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No. You put an and conjunctive in there, we'll give you one more. So go ahead, Rupert.
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Rupert M. Merer, National Bank Financial, Inc., Research Division - MD and Research Analyst [11]
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Great. Looking at your 2017 CapEx plan, looks like you're well within your target range, $1.1 billion to $1.3 billion for the year, but more weighted towards Liberty Power by the look of it. And you talk about the dynamic there of -- where you're investing. And will we expect to see Liberty Utilities organic investment meet your initial expectations for 2017?
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David Bronicheski, Algonquin Power & Utilities Corp. - CFO and CFO of Algonquin Power Management Inc [12]
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Yes, the Liberty Utilities CapEx program is on target. I mean, it is a little skewed towards the back half of the year, just given the seasonality of construction. So I think you should expect that they'll use CapEx to meet the guidance that we've provided.
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Operator [13]
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Our the next question comes from Ben Pham of BMO.
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Benjamin Pham, BMO Capital Markets Equity Research - Analyst [14]
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I wanted to go back to the 800 megawatts that you're [following] for Missouri. And just wanted to make sure I understand the strategy there. So is [Algonquin] looking to build 300 megawatts themselves, putting rate base and then the balance you procure it as a cost to keep customer rates flowing in? In the future, you buy that back in a few years and at its rate base?
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Ian E. Robertson, Algonquin Power & Utilities Corp. - CEO, President and Non-Independent Director [15]
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No, no. Perhaps I wasn't clear. The entire strategy, Ben, is completely founded on the investment in rate base of all 800 megawatts. I had mentioned that Empire themselves, with support of our power development group, are pursuing 2 development projects. They filed for their own interconnection request of 500 megawatts within [SPP]. But -- so to meet our total appetite for new wind, we have run an RFP not for projects to be provided to us under PPA, but to be sold to us upon their commissioning. So the expectation is that Empire will likely build its own projects, but also acquire perhaps 400 megawatts of incremental wind that would have been built by third-party developers. But the expectation is that after acquisition, all those projects would be indistinguishably collected into the rate base of Empire.
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Benjamin Pham, BMO Capital Markets Equity Research - Analyst [16]
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Okay, all right. And then does that 800 megawatts translates in that $1.5 billion you safe harbored? And then I'm just curious why that 800 megawatts -- not just a little bit, it's much different than what you said at the '16 Investor Day, it's much higher?
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Ian E. Robertson, Algonquin Power & Utilities Corp. - CEO, President and Non-Independent Director [17]
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Sure. And so 2 comments there. First of all, our safe harbor turbines, that $1.5 billion, in some respects, it's completely unrelated to the work that Empire will be doing within its service territories. They're 2, I'll say, completely separate initiatives. The expectation is that our nonregulated generation group, Liberty Power, will undertake the development, and as you might recall, sort of up to 600 megawatts or so of new generation, which will be occasioned by those safe harbor turbines we acquired. The expectation for Empire in terms of its development is that third-party developers will be providing safe harbor turbines as part of their submission under the RFP. It's required that those projects be safe harbored. Specifically with respect to -- and I assume your question was why 800 megawatts, you told us before it might have been 600 megawatts. Well, the short answer is that the way these processes work, as you run a very complicated model, to assess what is the optimal mix of generation for minimizing customer rates in the model, candidly kind of chooses those sources of generation in order to find the optimal mix. And it turns out that wind is so cost competitive that it actually elected for 800 megawatts over the 600 megawatts that we probably -- I think you're making reference to that we talked about during our Investor Day. So I -- hopefully that's provided some clarity, Ben, as to how we sort of think about those 2 separate initiatives.
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Operator [18]
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Our the next question comes from Sean Steuart of TD Securities.
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Sean Steuart, TD Securities Equity Research - Research Analyst [19]
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A couple of questions. Can you, Ian, just walk us through the applications you filed with respect to the Empire customer savings plan approvals in the 4 states. Could you just walk us through, I guess, the time frame of how those processes unfold and how that interplays with the RFP? I understand that's a separate process, but maybe just how we should think about hurdles and how that unfolds.
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Ian E. Robertson, Algonquin Power & Utilities Corp. - CEO, President and Non-Independent Director [20]
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Sure. As we had mentioned, I'll say, coincidently, in November, we filed the Integrated Resource Plan in Missouri. And that is a process, which is currently underway with a technical session -- actually there's a technical session being held in Oklahoma and in Missouri this coming week. And so it's a process that is being debated and they're obviously reviewing it. So we have socialized the content of that application or that Integrated Resource Plan long before we had submitted it. Part of the request is, from a procedural schedule perspective, is that the discussions, the determination conclude by mid next year. So call it the end of Q2 2018. So we'd -- I would say that 7 months feels like a reasonable time for the deliberations of the commission on the Integrated Resource Plan. This RFP that you make reference to is kind of running in parallel and think of it this way as we've made certain assumptions within the Integrated Resource Plan as to cost, and frankly, location of where those wind projects are, obviously favoring the certainty with respect to our Empire sites, but leaving the door open for integration and potentially lower cost opportunities, higher production, higher yield opportunities that may come under the RFP. So we expect that RFP will be completed in December. We'll kind of update our IRP filing with the commission to give them kind of a greater insight into what we actually think the final configuration will be. But in any event, the whole thing concludes by middle of next year. We then kind of proceed and just in terms of the process, will have sort of a continued dialogue with the commission on the specificity of the projects in terms of getting a prudency docket open, but at the same time, continuing the development process, permits, so that we are ready to go from a construction period some time in 2019 is the expectation. The deadline in order to qualify for 100% of the PTCs under the current rules is that the projects are commercially operational by the end of 2020. We're clearly aiming not to be part of that rush in 2020 to the extent that we can. You can imagine, cranes will be coming in scarce supply, et cetera. And so we are aiming for a construction period in late 2019, maybe bridging into early 2020. I don't know if, Sean, that's kind of the color you're looking for to put some broad timing around it.
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Sean Steuart, TD Securities Equity Research - Research Analyst [21]
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No, that's good detail. Second question maybe for David. Following up on Rupert's question on your 2017 CapEx guidance of $1.1 billion to $1.3 billion. When you build it up segment-wise -- and you addressed this that, I guess, the Q4 spend is going to be weighted to the rate base. And I'm wondering if you can just reconcile for us. Year-to-date on your cash flow statement, you're showing $570 million for property, plant and equipment. The balance, I know it gets picked up in lots of different accounts across your financials. Can you just connect some of the dots on where the rest is residing in the cash flow statement or the income statement?
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David Bronicheski, Algonquin Power & Utilities Corp. - CFO and CFO of Algonquin Power Management Inc [22]
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And this is perhaps a question for further follow-up offline, but I believe what you'll find is the difference has to do with the fact that for construction projects, we generally are building them inside of joint venture projects in order to manage the risk through the development process. And then we buy in the project after, so rather than showing it up -- showing up as fewer CapEx, it actually shows up as an investment. And so I think that is the disconnect between the 2. And you have to keep in mind that the cash flow statement is a cash flow statement. And so we'd actually track cash flows of those things. And when the construction is taking place within the JV, that's where the cash flow occurs. And so as we buy in the JV after, you don't actually see the CapEx spend as being a true PP&E addition. But happy to walk you through that after.
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Sean Steuart, TD Securities Equity Research - Research Analyst [23]
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Yes, that will be useful. I figured it was something along those lines. But I'll follow up afterwards, David.
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Operator [24]
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Our next question comes from Richard Sunderland of JPMorgan.
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Richard Sunderland III, [25]
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I just wanted to follow up on some of the quarterly items that you discussed earlier on the call, mainly the expense lines kind of after you look at adjusting for the impact of foreign exchange. So kind of your OpEx, your admin expense, your G&A quarter-over-quarter is down at a pretty decent clip. So could you provide any more color there?
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David Bronicheski, Algonquin Power & Utilities Corp. - CFO and CFO of Algonquin Power Management Inc [26]
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Well, the increase in our admin expenses is clearly the result of the acquisition of Empire, even if you were to back out the effect of FX. So there really is -- that's the primary reason for the growth. And clearly, throughout the rest of our enterprise, we're continuing to grow and that does require additional support as well.
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Ian E. Robertson, Algonquin Power & Utilities Corp. - CEO, President and Non-Independent Director [27]
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And Richard, maybe just a clarification. When you are speaking of quarter-over-quarter, you were speaking of Q3 2016 versus Q3 2017 or Q2 2017 versus Q3 2017?
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Richard Sunderland III, [28]
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Sorry, I'm trying to walk from the previous quarter, so Q2 '17?
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David Bronicheski, Algonquin Power & Utilities Corp. - CFO and CFO of Algonquin Power Management Inc [29]
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From Q2 2017. Well, a lot of those -- the admin, I think there's going to be some timing issues that you're going to see there. It's not all necessarily a straight quarter-by-quarter spend. So if your expectation is that it would be the same each quarter, that's not exactly always true. So some of what you see in Q3 could be just a timing related to when expenses got incurred in our Q2 results.
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Richard Sunderland III, [30]
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Okay. So just to be clear there, there might be some pickup in that regard on fourth quarter?
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David Bronicheski, Algonquin Power & Utilities Corp. - CFO and CFO of Algonquin Power Management Inc [31]
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Possibly. And I assume from your question, you're trying to see through the FX on that, right? Or -- because FX also will play into the ups and downs like the FX in one quarter can and has been actually different than other quarters.
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Richard Sunderland III, [32]
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Yes -- no, I was looking kind of after the impact of FX, but I can follow up after if there is still questions there.
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Ian E. Robertson, Algonquin Power & Utilities Corp. - CEO, President and Non-Independent Director [33]
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Sure. Happy to walk you through in more detail, Richard, if you want to give us a shout.
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Operator [34]
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(Operator Instructions) Our next question comes from Mark Jarvi of CIBC Capital Markets.
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Mark Thomas Jarvi, CIBC Capital Markets, Research Division - Director of Institutional Equity Research [35]
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I just wanted to go back to your comment in the prepared remarks about the ED performance and whether or not -- this quarter, the performance was with expectations, or are you talking year-to-date? I know Q1 was a bit light, but looked like, from my perspective, pretty strong performance from ED year-over-year. So maybe just to check, tell me how that's going year-to-date and where your expectations are for the last quarter of the year?
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Ian E. Robertson, Algonquin Power & Utilities Corp. - CEO, President and Non-Independent Director [36]
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Yes, so, 30,000 foot, Mark, Empire is meeting our EBITDA and earnings expectation, that to be frank, we had established at the time of announcements. I think Empire is continuing to deliver big picture on the expectations both from the revenue and expense perspective. You -- no truer words were ever spoken when you said that Q1 of this year was a very warm quarter in terms of heating degree days that negatively impacted Q1 in a fairly significant way, like $10 million or $11 million worth of net revenues. I think the Empire guys have done a good job of attempting to recover some of that through expense mitigation and expense control. Obviously, you can't make it all up. But overall -- and then I think your observation is correct. Q3 was a pretty good quarter in terms of its performance. It was kind of on track. And we're -- as we kind of stare into the balance of the year, we are completely satisfied with the overall performance of Empire, taking into account that there are the naturally occurring fluctuations in terms of heating degree days and cooling degree days. But within the context of that volatility, the acquisition is performing exactly as expected.
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Mark Thomas Jarvi, CIBC Capital Markets, Research Division - Director of Institutional Equity Research [37]
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Okay. That's good to know. And going back to the Empire situation, the application, the IRP. I know you said mid-year, and I think in some of the filings, you talked about an April time line of making decision. Given the tax uncertainty, what's the initial dialogue with the regulators in terms of their ability to move forward, given that -- seems like a lot of the value creation and the value proposition is around harvesting the PTC value. So will they be able to make a decision if tax uncertainty continues to linger here?
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Ian E. Robertson, Algonquin Power & Utilities Corp. - CEO, President and Non-Independent Director [38]
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Well -- I mean -- I think tax uncertainty, I think, clearly even in the context of the House proposal, is that -- I'm not sure that the investment in Empire's wind is actually all that impacting. What I mean by that, and David had kind of alluded to it in his prepared remarks regarding those production tax credits, that within that RFP -- and we believe there are a number of projects that have been -- that are being proposed to us under the RFP that actually even met, I'll say the, changed definition of commencement of construction, which really should minimize the impact of the House's draft, which as you're probably aware, as recently as last night, they backtracked pretty significantly, and as David said, kind of converged on the Senate's draft, which is saying no impact on the current rules for phase out of the PTCs. And so I'll start by saying, even if things didn't work out perfectly in terms of what finally comes up, Empire is largely insulated by that from the status of a number of the projects that we're aware will be bid to us under the RFP. But I'd say, plan B and the more likely plan is that, that won't be needed, because we actually don't think there'll be any change in the legislation in the current phase-out of the PTCs. I guess, one of the questions you ask, are the commission aware of that? Certainly, we -- I think we have spent lots of time with staffers to educate them on the benefits of tax equity in terms of customer rates. And so I'd say, they're moving quickly, they understand the urgency. We're not the only people in front of them, which is good, because these are issues which they're getting familiar with. So I guess, we're kind of hopeful, Mark, that in the context of the current round of tax reform, the PTCs are left untouched. And we'll be able to finish off our conversations early next year with the commission to get approval of the IRP as we -- as it's been offered up to the commission. That's kind of the plan right now. So I don't know if that's helpful or hurtful in terms of your question.
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Operator [39]
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Our next question comes from Jeremy Rosenfield of Industrial Alliance Securities.
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Jeremy Rosenfield, Industrial Alliance Securities Inc., Research Division - Equity Research Analyst [40]
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I just wanted to follow up very briefly on that Empire and the Missouri regulatory commission. Correct me if I'm wrong, but there have been some other utilities that have proposed using tax equity to finance the wind projects within Missouri. Is that accurate? I'm not sure if they've been approved or not. Maybe you can just clarify.
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Ian E. Robertson, Algonquin Power & Utilities Corp. - CEO, President and Non-Independent Director [41]
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No, they haven't been approved. But it is a structure, which is being adopted, not just in Missouri, to be frank, across the U.S. I like to think we kind of pioneered this, Jeremy, with our structure for the integration of our Luning Solar in California. It was obviously very difficult nut to crack and it gets quite technical. But the tax normalization rules, which if you just kind of stare at the problem, there's -- you -- regulated utilities are kind of denied the opportunity of bringing tax equity to bear in terms of customer rates. We were able to construct a structure, which was adopted and approved by the California Public Utilities Commission in respect of our Luning project a couple of years ago. I think it's kind of serving as a paradigm for a number of those applications, which not just Ameren, but Xcel and other regulated utilities are prosecuting, I'll say across the Midwest. Obviously, it's applicable across the country, but the Midwest has obviously the best wind resources, and therefore, the lowest levelized cost of energy. So no, we're not the only people in the -- pursuing this right now, Jeremy. We've got lots of company, but pretty much everybody is articulating the same message to their regulators, which is, guys, we can reduce cost for customers by taking advantage of the current [fact] pattern, please let's do it. That's kind of the theme that's been articulated by everybody.
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Operator [42]
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This concludes the question-and-answer session. I would like to turn the conference back over to the presenters for any closing remarks.
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Ian E. Robertson, Algonquin Power & Utilities Corp. - CEO, President and Non-Independent Director [43]
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Appreciate it, operator. And again, it's -- thanks for everybody taking the time out of their day to listen to our call and we appreciate all the enthusiasm and support that the organization has got over the past few weeks as we kind of embark on this exciting new venture from our perspective. So with that, I'm going to turn things over for the rivetting disclaimer from Allison. Allison?
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Alison Holditch, [44]
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During the course of this conference call, we may have made statements relating to the future performance about Algonquin's that contain forward-looking information, including statements with respect to the expected performance of the company, its future plans and its dividends for shareholders. While these forward-looking statements represent our current judgment based on certain material factors or assumptions, actual results could differ materially from such forward-looking statements made today.
Additional information about the material factors that could cause actual results to differ materially from such forward-looking information and the material factors or assumptions that were applied in making any forward-looking statements as well as risk factors that may affect the future performance and results of Algonquin are contained in the press release and Algonquin's public disclosure documents filed by the company on SEDAR at www.sedar.com and EDGAR at www.sec.gov. We undertake no obligation to update these forward-looking statements unless required by law.
Furthermore, during the course of this conference call, we have referred to certain non-GAAP financial measures including, but not limited to, adjusted net earnings, adjusted EBITDA, adjusted funds from operations, per share cash provided by adjusted funds from operations and per share cash provided by operating activity. These non-GAAP measures do not have any standardized meaning under GAAP and may not be comparable with other non-GAAP or non-IFRS financial measures presented by other companies. We refer you to our MD&A for more information about these non-GAAP measures, including a reconciliation of the non-GAAP measures to the corresponding GAAP measures where a comparable GAAP measure exists.
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Operator [45]
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This concludes today's conference call. You may disconnect your lines. Thank you for participating, and have a pleasant day.
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