AltaGas Ltd. (OTCPK:ATGFF) Q2 2016 Results Earnings Conference Call July 21, 2016 11:00 AM ET
Jess Nieukerk - Senior Director Investor Relations
David Harris - President & Chief Executive Officer
Tim Watson - Executive Vice President and Chief Financial Officer
John O’Brien - President AltaGas Services (U.S.) Inc.
Linda Ezergailis - TD Newscrest
David Galison - Canaccord Genuity
Patrick Kenny - National Bank Financial
Robert Kwan - RBC Capital Markets
Robert Catellier - CIBC World Markets
Steven Paget - FirstEnergy
Ben Pham - BMO Capital Markets
Good morning, ladies and gentlemen, and welcome to the AltaGas Ltd. Q2 2016 Conference Call. I would now like to turn the meeting over to Mr. Jess Nieukerk, Director of Finance and Communications. Please go ahead, Mr. Nieukerk.
Thank you. Good morning, everyone. Welcome to AltaGas’ second quarter 2016 conference call. Speaking today are David Harris, President and Chief Executive Officer; and Tim Watson, Executive Vice President and Chief Financial Officer. After some formal comments this morning, we will have a question-and-answer session.
Before we begin, I’d like to remind you that certain information presented today may include forward-looking statements. Such statements reflect the corporation’s current expectations, estimates, projections and assumptions. These forward-looking statements are not guarantees of future performance and they are subject to certain risks, which could cause actual performance and financial results to vary materially from those contemplated in the forward-looking statements. For additional information on these risks, please take a look at our annual information form, under the heading Risk Factors.
I’ll now turn the call over to David Harris.
Thank you, Jess. Good morning, everyone. Over the last quarter, we significantly advanced many of our key initiatives, while delivering strong results. Normalized EBITDA for the second quarter 2016 increased by 43% to CAD153 million, up from CAD107 million a year ago. This is the highest Q2 EBITDA AltaGas has ever delivered. Normalized funds from operations increased 68% to CAD114 million or CAD0.75 per share, up from CAD68 million or CAD0.50 per share a year ago.
With these strong quarterly results, the completion of our Townsend facility and our positive outlook for the remainder of 2016, the Board decided to raise the dividend 6.1% or CAD0.01 per share per month. Our strong financial performance in the quarter is primarily attributed to the addition of the San Joaquin facilities at the end of November 2015 which we acquired and to McLymont, the last of the Northwest Hydro facilities that was brought online in October 2015. Together these facilities contributed over CAD30 million in EBITDA to our second quarter results.
At the segment level, overall normalized EBITDA results for Q2 2016 compared to Q2 2015 are as follows. Our power assets more than doubled to CAD75 million; our utilities were up 12% at CAD46 million given the strong US dollar and colder weather experienced in Michigan; and despite the lower hedge gains, our gas segment was flat at CAD37 million.
On the corporate side, our costs were flat in Q2 2016 versus Q2 2015, but as a result of restructuring and corporate efficiencies, we expect to see an annualized reduction of approximately CAD7 million in operation and administrative expenses. As I mentioned in our Q1 conference call, we have a strong focus on G&A cost and on being a top tier operator with strong construction expertise.
Our construction team did a fantastic job to bring the Townsend facility, associated infrastructure, the gas gathering lines, the liquids egress lines and the Alaska Highway truck terminal in ahead of schedule and approximately CAD40 million under our original budget. The Townsend facility was completed in early July and the plant entered commercial operations on July 10. These facilities are the first major step with our Northeast BC strategy and we see significant potential to leverage the footprint we have in this area.
With one of the only major modern gas processing facilities there, we have significant competitive advantages to offer further capacity for producers in the region. We have already had significant discussions with various producers on the potential to build a deep cut facility and we certainly see the ability to double our Townsend facility well before the end of the decade. Based on our current views, we expect we could eventually get to 1 bcf of processing capacity in the region.
On our LPG export strategy, we have significantly advanced our proposed Ridley Island Propane Export Terminal. The MoU that we signed with Astomos outlines all the key terms for a multi-year off-take agreement, which has the ability to be extended. Astomos will take at least 50% of the 40,000 barrel per day facility. While this commitment is enough for us to move toward FID on the project, we have advanced commercial discussions with other off-takers as well.
We continue to make good progress on the regulatory side as demonstrated by the submission of our environmental evaluation document and we’re anticipating regulatory approvals by Q4 of this year. We continue to work closely with the First Nations, the port of Prince Rupert and the Canadian Environmental Assessment Agency to achieve FID later this year.
This project is unique in terms of its ability to offer producers in both BC and Alberta product egress into premium global markets for a modest contractual commitment relative to various other alternatives, including petrochemical which are being promoted by various players.
Our North Pine liquid separation facility near Fort St. John is also progressing. The facility can connect our existing infrastructure in the region to our proposed Ridley Island Propane Export Terminal. We completed out front-end engineering and design study for the 20,000 barrels per day of C3+ and 20,000 barrels per day of C5+ and expect to receive approvals from the B.C. Oil and Gas Commission in the third quarter.
I would note that North Pine is modeled on a standalone basis. It is not dependent on our Ridley propane export terminal. Ridley, however, has clearly driven significant interest in North Pine from producers as we can offer services throughout the full energy value chain and can offer preferential access to premium markets producers that use our value chain.
Our power segment is also seeing a lot of activity and our views on the California and Southwest markets continue to be strengthened. Already today the duck curve or the need to backstop solar generation is getting steeper and steeper. Thousands of gas fired megawatts are often needed when the sun disappears. As more solar megawatts come on during the day, flexible gas plants will all become more important.
In fact, the California ISO announced on Tuesday, June 12, solar production reached a new record of just over 8,000 megawatts. The dramatic increase of solar production in California highlights the need for flexible gas generation to quickly handle the rise and setting of the sun.
Most recently it was announced that the 2,200 megawatt Diablo Canyon nuclear facility will be retired by 2025 and replaced predominately with renewable energy. This brings the total expected retirements of nuclear and thermal generation up to approximately 15,000 megawatts over the next decade. As a good portion of these megawatts will be replaced with renewables, this further adds to the value of existing flexible fast-ramping gas fired facilities that can help backstop intermediate renewables.
We are proactively looking at all the potential options in California and the desert southwest. There have been a couple of RFPs to date and we expect several more over the course of 2016 and 2017. While you can expect that we will look and bid on these, not every RFP will best fit our profile and so we will update you on them when anything materially develops.
We also are not solely depending on RFPs. We have been proactively having discussions with utilities and public power entities for bilateral multi-year contracts. Our California sites can meet a wide variety of energy products and needs in the West. There is continued need for resource adequacy and resource adequacy market prices are expected to strengthen over the next several years.
In addition, increased renewable production will lead to an increased reliance on and payment for ancillary services from gas plants which will also provide revenue opportunities. We expect the provision of each of these products to increase the value of our existing assets and our ability to grow in the market.
Finally, our sites can house multiple technologies, including gas fired plants, renewables and storage. With this optionality and flexibility and with the market fundamentals all pointing in the right direction, we strongly believe our California desert southwest strategy remains solid.
To summarize, we continue to maintain an excellent track record as it relates to execution. Our construction capabilities are top tier and we’re certainly able to deliver projects on time and below budget, providing producers with the lowest cost option for their product. Our full Northeast BC and Canadian LPG export strategy is coming together, which will provide producers with a full energy value chain and access to Asian markets.
We expect to have significant updates on our growth over the second half of 2016. On top of this, we had a record second quarter and we’re well on track to deliver on our guidance of approximately 20% growth in normalized EBITDA and up to approximately 15% growth in normalized funds from operations over 2015.
Let me now turn the call over to Tim.
Thank you, David. Good morning everyone. The [indiscernible] diversified business lines is that they represent vital energy infrastructure assets and the strength of this combined platform was clearly evident by their record results achieved in the second quarter.
Normalized EBITDA was up 43% in the quarter to CAD153 million compared to CAD107 million in the same quarter of 2015. Across our three business lines, power EBITDA was up 120% in the second quarter of 2016 relative to last year and represented 47% of total normalized EBITDA in the quarter.
The acquisition of the San Joaquin power assets in California was a contributing factor. Also, the Northwest British Columbia hydro facilities exhibited strong performance as a result of the startup of McLymont in the fourth quarter last year and improved performance at Forrest Kerr after a full year of operations along with higher river flows. Realized hedging gains on the Alberta power portfolio were partially offset by the absence of equity income from the Sundance B PPA.
Utilities EBITDA increased 12% year over year and represented above 30% of total normalized second quarter 2016 EBITDA. Utilities had a strong quarter, driven by the US dollar, colder weather in Michigan and rate base and customer growth. This was partially offset by warmer weather in the other utility franchises as well as higher costs of the US utilities.
Finally, EBITDA from the gas midstream assets was flat compared to the second quarter of 2015 and accounted for 23% of total normalized EBITDA. Volumes of the extraction facilities increased year over year as there were no turnarounds at the two largest extraction plants being Harmattan and Younger. Offsetting this were lower fuel gathering and processing volumes, primarily due to the sale of the Tidewater assets in the first quarter of 2016 as well as lower realized frac spreads. That’s a function really of the strong hedging gains that we saw in 2015.
For the second quarter of 2016, AltaGas reported normalized funds from operations of CAD114 million or CAD0.75 per share compared to CAD68 million or CAD0.50 per share in the second quarter of 2015. This represents a 68% increase in funds from operations and a 50% increase on a per share basis.
Normalized funds from operations were up as a result of stronger results in the power and utilities segments combined with higher distributions from Petrogas, partially offset by higher interest expense and current income tax expense.
In the second quarter, we received CAD6 million in common share dividends from Petrogas, which was in line with our expectations. Year to date, we’ve received CAD12 million in common share dividends from Petrogas compared to only CAD11 million throughout all of 2015. And we expect to receive CAD6 million in Petrogas common share dividends for each of the third and fourth quarters of 2016.
In the second quarter, AltaGas invested CAD150 million in the 8.5% cumulative redeemable convertible preferred shares of Petrogas and that will result in about CAD3.2 million in dividends per quarter starting with the third quarter of 2016. The funding will go towards debt repayments and continued growth initiatives within Petrogas.
Normalized net income for the second quarter of 2016 was CAD29 million or CAD0.19 per share compared to CAD9 million or CAD0.07 per share in the second quarter of 2015. Normalized net income was higher due to the same factors impacting normalized EBITDA mentioned previously, partially offset by higher depreciation, amortization, interest expense and preferred shares dividends.
On a US GAAP basis, net income applicable to common shares for the second quarter of 2016 was CAD16 million, or CAD0.10 per share. This compares to a net loss of CAD22 million or CAD0.16 per share for the second quarter 2015. Normalizing adjustments in the second quarter of 2016 relate primarily to unrealized gains on risk management contracts and restructuring charges.
During the quarter, AltaGas completed a restructuring that reduced the non-utility workforce by approximately 10%, resulting in pretax restructuring costs of approximately CAD7 million. Going forward, this is anticipated to reduce operating and administrative expenses by approximately CAD7 million on an annualized basis.
For the second quarter of 2016, interest expense was CAD36 million, compared to CAD30 million for the same quarter last year. The increase was driven by higher average debt outstanding as a result of the purchase of the San Joaquin facilities and lower capitalized interest, as assets such as McLymont were brought into service. This was partially offset by lower overall interest rates.
Depreciation and amortization was CAD66 million in the second quarter of 2016, compared to CAD50 million in the second quarter last year. This increase was mainly due to the acquisition of the San Joaquin facilities and new assets placed into service.
For the second quarter of 2016, income tax expense was CAD4 million compared to CAD10 million in the second quarter 2015. The decrease was mainly due to the absence of a one-time non-cash CAD14 million charge in the second quarter of 2015 relating to the 2% increase in the Alberta corporate income tax rate, partially offset by higher earnings in the second quarter of 2016. On a full year basis, we expect the effective tax rate to be in the 20% to 25% range.
Net invested capital in the second quarter 2016 was CAD282 million, compared to CAD149 million in the second quarter of 2015. Investment in property, plant and equipment increased, mainly due to construction costs for the Townsend facility and related infrastructure, as well as a CAD150 million investment in Petrogas preferred shares.
With the Townsend projects largely complete and under budget, we have incurred at this point halfway through 2016 a significant portion of total expected annual capital expenditures for the year. Much of the remaining growth capital expenditures in 2016 are in fact discretionary and AltaGas has the flexibility to adjust the pace of spending at its option.
AltaGas’ balance sheet is in a strong position and fully funded for 2016. At the end of the second quarter, debt to total capital was 45%, down from 48% in the first quarter of 2016. This remains well below our bank and term note covenant levels of 65% to 70%. Also, we’ve got approximately CAD1.4 billion available on our credit facilities and we continue to have very strong access to multiple sources of funding.
During the quarter, we completed a very successful 10-year CAD350 million MTN note offering at an attractive coupon of 4.12%. Last month, we completed a CAD440 million common share offering, which was very well received by the market. These financings are forward looking in nature as we continue to see strong momentum in our development program, with plans to construct several new infrastructure projects between now and the end of 2017.
The strength and stability of our funds from operations is what drives our business and provides strong security in our dividend. AltaGas gas has one of the lower dividend payout ratios based on cash flow in its peer group. To put this in perspective, even with the recent increase in our annual dividend to CAD2.10 per share, cash flow for regulated utilities and the Northwest Hydro projects alone more than covers actual cash dividends paid, after factoring in a dividend reinvestment plan. That means that cash flow from all of the other assets within AltaGas can be directed to other investment opportunities.
Turning to the 2016 outlook, it’s largely consistent with what we communicated last quarter. The power assets are expected to contribute the majority of the 20% growth in total normalized AltaGas EBITDA year over year; approximately 42% of total 2016 expected EBITDA will come from power, driven primarily by a full year contribution from San Joaquin and the full year from the McLymont Hydro facility after its fourth quarter 2015 start up. We now only have 65 megawatts of exposure to the Alberta power market. That’s about 4% of our total generation. And Alberta power price exposure for the remainder of 2016 is hedged resulting in zero variability to Alberta power pool prices.
The utilities are expected to see a small increase in normalized EBITDA compared to 2015 and are expected to account for 36% of overall 2016 EBITDA. This is driven by rate base and customer growth, including at Semco Gas which will benefit from a full year of contribution from its main replacement program.
Also, in June 2016, ENSTAR filed its 2000 rate case requesting an interim and refundable annual rate increase of approximately US$5 million on an annualized basis effective August of this year, with final rates to be set for the third quarter of 2017. On July 18 of this week, the Alaska Public Utilities Commission approved the interim refundable rates.
Earnings at all of the other utilities except P&G are affected by weather in their franchise areas with colder weather generally benefiting earnings. Approximately three quarters of AltaGas’ utility customers are in the US and our US based utilities benefited from a favorable US dollar exchange rate.
Offsetting these factors, however, Heritage Gas is looking to adjust its regulated distribution rates for certain commercial customers to remain competitive. Interim approval was granted by the regulator in March of this year, with the revised rates if they’re approved this quarter reducing Heritage’s normalized EBITDA by approximately CAD4 million this year.
Finally, gas midstream is expected to account for approximately 22% of 2016 normalized EBITDA. Compared to 2015, the gas segment is expected to see a small decline in EBITDA. Our new Townsend facility is expected to add approximately CAD20 million of EBITDA in 2016. Other positive drivers include the absence of turnarounds of Harmattan and Younger, as well as improved performance from Petrogas.
These year over year gains, however, are more than offset by lower contributions from commodity prices as a result of higher hedging gains achieved in 2015, the sale of the Tidewater gas assets earlier this year and approximately 5% decline in processing volumes at non-core gas facilities. Approximately two thirds of 2016 gas EBITDA is underpinned by take-or-pay cost-of-service contracts, with no direct price or volume exposure. We’ve had no material impacts on midstream counterparty exposure year to date, continuing on [positives] experienced from last year.
I will point out in the second of 2016 a small five-day turnaround at Gordondale was completed which brought volumes down slightly. But overall for 2016 full year volumes are expected to average approximately 90 million to 100 million a day at Gordondale. This could potentially increase also depending on Birchcliff’s development plans for the area once the Encana acquisition closes next week.
Gordondale will be the most efficient deep cut facility within the Birchcliff focus area, with significant expansion capability. The take-or-pay provisions under the contract are based on cumulative production. We anticipate Birchcliff will reach its cumulative production in and around 2020, subject to their planned rate of area developments. That’s potentially subject to change, but will depend on how that unfolds over time. After that, we’re confident that the Gordondale facility will continue to serve as an important element of Birchcliff’s midstream strategy.
Over the last few months, frac prices have strengthened at roughly CAD11 a barrel spot pricing this past quarter versus CAD3 last year. Therefore, we reduced the amount of liquids being reinjected. Recall that AltaGas produces up to approximately 60,000 a day of natural gas liquids, but only up to a maximum about 10,000 of that can be exposed to frac spread pricing, with the balance having various different contractual arrangements.
Based on our current forecast of prices, we expect to increase the amount of extraction volumes exposed to frac spreads up to about 7,000 a day for the remainder of this year. As frac spreads recover, AltaGas is well positioned to deliver additional normalized EBITDA growth as we can continue to increase the production of exposed natural gas liquids. However, that’s not built into our 2016 expectations.
During the second quarter of 2016, AltaGas hedged about 500 barrels a day of NGL volumes at an average price CAD19 per barrel. And just again from a sensitivity standpoint, note that every plus or minus CAD1 change in frac spread impacts our 2016 EBITDA by about CAD1 million.
Turning to 2016 capital expenditures, we now expect to spend about CAD600 million to CAD650 million. The remaining amount to be spent in the second half of the year is approximately CAD300 million and it’s mainly discretionary. We have tightened that range to reflect the near completion of the Townsend midstream complex overall and this range also includes some additional capital for the RTI export project later this year and also reflects the recently restarted construction of the Alton natural gas storage project in Nova Scotia.
Maintenance capital for gas and power in 2016 is expected to be less than CAD40 million and we expect approximately CAD290 million for depreciation, amortization and accretion expense for 2016. Approximately 50% of our total 2016 EBITDA will come from the US and reflects our diversified business platform across our three major energy infrastructure business lines. For every plus or minus CAD0.05 change in FX rate, the impact of 2016 EBITDA is about CAD14 million.
Looking a little further out at 2017, we are forecasting moderate growth in overall normalized EBITDA compared to 2016, mainly driven by the gas segment. We expect power and utilities results to remain fairly consistent with 2016, although utilities will benefit should weather return to a more normalized state relative to what we experienced this past winter.
The gas segment will benefit from a full year of Townsend and we expect moderate strengthening of frac spreads in 2017. However, partially offsetting this will be the sale of the ethylene delivery systems and the Joffre Feedstock Pipeline back to NOVA Chemicals. Recall that this was first announced back in the first quarter of 2014 when NOVA Chemicals exercised the option to purchase these assets.
While proceeds are expected to be approximately CAD67 million, EBITDA will be impacted by approximately CAD10 million. Also, the Edmonton ethane extraction plant and Gordondale are both expected to undergo normally scheduled turnarounds in 2017, which will impact EBITDA by approximately CAD7 million. A full year of cost savings from the recently completed restructuring and from other efficiency initiatives should also be reflected in 2017. On the development front, as you’ve already heard, we expect to advance a number of exciting new projects in 2017, with targeted in service dates in early 2018.
In summary, we just completed a record second quarter for AltaGas and we remain on track for a record level performance through the remainder of the year. We continue to expect to deliver approximately 20% growth in normalized EBITDA and up to approximately 15% growth in normalized funds from operations for this year.
In 2017, we expect moderate growth absent any acquisitions with a number of key investments occurring in 2017 to set the stage for significant further growth beginning in early 2018. AltaGas will continue to pursue growth across all three of its diversified energy infrastructure businesses, while ensuring financial strength and flexibility. Supporting this is our attractive dividend which is currently yielding in excess of 6%, which is underpinned and fully covered on a cash basis, while AltaGas’ most stable businesses, its regularly utilities and its long-term contracts in hydro generation.
With that, I’ll turn the call back to Jess.
Thank you, Tim. Operator, we will now open the lines for question and answers.
[Operator Instructions] The first question is from Linda Ezergailis from TD Securities.
I’m just wondering with respect to the CAD40 million of capital cost savings at Townsend, how much of that benefit AltaGas versus Painted Pony? And can you maybe describe the nature of the efficiencies that you found in construction and how that might translate into some of your other projects?
The sharing is roughly 50-50. We’ve got a great alliance and partnership with Painted Pony, so look forward to keeping that going. So it’s a balance split. And then the efficiency really just comes from what we bridged off from the northwest projects. We certainly have our own construction capability. Probably, I think the only midstream out there in Western Canada has our own construction arm. So a lot of that value came from direct self-performing, lowering our direct cost, executing, eliminating G&A and overhead and profits from companies you’d normally have to go to and we’re seeing the way to that come to bear on lowering our cost to construct and passing that value back to the producers.
And you’re seeing that potential in North Pine and other projects as well?
Absolutely we are. We will expand that same philosophy across all our construction activities within the company.
You mentioned that North Pine is currently under review, but when might you get a sense of the extent of that for all of your projects?
We’ll work fairly well down that curve now, but there’s a few other things we’re looking to do with optimization and we’ll have a good point for the market as we get into October, at the October call.
And just as a follow up question on your Petrogas preferred share investment, can you describe what the war around the conversion rate and also whether it [indiscernible] co-invested in Petrogas as well and an update on your partnership with them?
I guess I can’t say whether they did or didn’t specifically, it was essentially a private placement into a private company. Standard conversion features as you would probably be accustomed to in the public convertible pref market.
And how much would that change your ownership potentially, can you comment on that and whether there might be future investment opportunities to further increase?
Again, I’m not going to throw out a specific number. I mean, I think we said CAD150 million, I think historically you know sort of what we’ve invested in a company from an equity perspective, so you can just do some rough math to get some sense I think and that’s directionally going to be sufficient probably to give you a sense for the materiality of this investment, should it convert what that would mean. But you know I would say it’s – Petrogas is an investment with three major shareholders. We’re all working well together and continue to be engaged shareholders and companies.
The following question is from David Galison from Canaccord Genuity.
First question is just in the Gordondale facility, with the take-or-pay commitment, were there any volume requirements or limits around the take-or-pay provisions? Like a total volume is what I’m referring to.
There’s a total volume associated with the contract, so that was originally established at the outset when we entered into the arrangements with Encana. I can’t give you specifics because it’s privy to a contract between two parties. We don’t normally disclose specific contract terms. But it’s a contract that I’ve given you some sense for what the timeframe is based on our expectations of how the area gets developed.
But again, that’s going to be very much subject to how Birchcliff goes about the Gordondale area going forward. We get the sense that they – I mean this is the biggest deal that Birchcliff has done in the history of the company, obviously that deal is very well supported by the market and that sounds like a very good story and it sounds like they’re quite committed to justifying the price paid and are going to set out on interesting development program. So we’re keen to see how that unfolds.
The second question, just if you can give a bit more color on the normalized FFO guidance of 15%. With the additional dividends that you’re going to receive from the increased investment in Petrogas, shouldn’t that increase a little bit or is it something else that was behind that?
We’ve said in Q1 and we repeated it word per word in Q2 that from an FFO perspective, our expectations are up to 15% year over year. And so those words are chosen quite carefully and the Petrogas – I mean we’re running a business which – the size of AltaGas overall in this investment is not overly material to dividends of whatever CAD6 million a year or whatever that come out of that investment aren’t going to swing things one way or the other. But it’s within the guidance of up to approximately 15% year over year.
And then just one further question out in the Townsend facility, you’ve mentioned that you’re going to do roughly about CAD20 million in normalized EBITDA in 2016. Once that’s up and fully running, can you give a sense of what normalized EBITDA could be generated from that?
In very rough terms, you can double it roughly, it might be a little bit over CAD40 million may be, but it’s in that order of magnitude.
The following question is from Patrick Kenny from National Bank Financial.
Maybe first just back on Gordondale and transitioning here to Birchcliff, I just wondered if you were open to renegotiating the current take-or-pay contract in exchange for an extension of the term beyond 2020 or perhaps underpin construction of phase two?
We’ll certainly once the deal close look to have a dialogue with Birchcliff. We will be open to any number of options that add value to the company and the shareholder. We certainly view Gordondale as a core asset. As Tim mentioned, it is prolific in a sense, it’s the most efficient facility within the area and we’re certainly looking to continue to provide good service as a company on that facility.
I think the other thing that’s worth noting too is our Chairman and their CEO have been very good friends for well over two decades. I think there is a good relationship all the way from the top down there. So we will certainly look to leverage that as we get into discussions with them post-close.
And then maybe just on Blythe and Blythe II, can you remind us what the construction period looks like for Blythe II Sonoran and I’m just wondering if the re-contracting of Blythe I is not directly competing now with Sonoran and for the upcoming RFPs? And if so, can you comment on where Sonoran might be on the cost curve relative to extending the existing Blythe PPA?
Sure. I’ll start and then I’ll turn it over to my esteemed colleague John O’Brien who’s with us. But from construction, we would expect somewhere in a neighborhood down when we get into it or at the time we decide to get into it on Blythe II it’d probably somewhere in the 30-month range give or take depending on what we actually end up deploying for technology there. And then as it relates to the completing of some of that, I’ll turn it over to John, he’s right next to me.
Yeah, I think as David noted in his comments, we’re watching California obviously very closely and we watch it day to day and there is a continued need for flexible assets. So for [stealing the ground in] Blythe I, that is an asset that we believe will be important post 2020, either on a re-contracted basis with Edison or others. So we pursue Blythe I that way and it is some of the outage work we’ve done for Blythe to make sure it is as flexible as possible so that we can optimize that asset in the current market and beyond. We feel we feel good about Blythe.
On Blythe II or Sonoran, we will begin the – we’ve worked very well with the CEC. We have the hearing process beginning here in the fall on our permit request to amend the existing permit on Blythe II. So as we look to Blythe II, we’ll know where we are on that amendment by the end of the year on the CEC process and between having an interconnection there for 500 megawatts and the good work we’ve done with the CEC, we believe that that site is again a very good site in light of California.
And as we look at both of them, we think that both of them are – both sites are marketable either within California or again from a transmission standpoint where we are in that area, you definitely can look beyond the state borders into Arizona and Nevada and elsewhere. So we continue to be pretty optimistic about both sites.
Just maybe one last question, I’ll jump back in the queue, for Tim. You said your debt to cap at quarter end and I’m just wondering is that the key metric for us to watch out here for – as some of your larger unsecured projects start to take off or should we be tracking debt to EBITDA or another metric as your target capital structure going forward?
First of all, I think we’re looking at all the key ones as you would expect, but it really depends on what specific – or what your specific perspective is. So I mean as I said be it from a bank covenant perspective, our most significant covenant is debt to EBITDA. And similarly for the other form of debt that we raise in our capital structure, which is medium term notes, it’s the same thing, it’s debt to EBITDA. And I actually indicated that those covenants are in 65% and 70% levels.
In terms of credit ratings, they look at again all the key measures. As you’re probably aware, S&P does focus generally on the, within the energy infrastructure space, on FFO or funds from operations to debt. And so that’s another key one that we focus on and we will continue to.
And can you just remind us what your target metrics are on debt to EBITDA and FFO to debt?
In terms of FFO to debt, we’re looking to get it into the 15% range. We’re a little bit below although over the past five years we’ve been in the 10% to 15% range depending on the year and where we’re at. So we want to be at the higher end of that range for sure and that’s a target not just for this year but into next year. So really I look at that between now and the end of 2017. That’s where I’d like to be, at the higher end of that range.
On debt to cap, which is the other relevant metric I mentioned, I don’t have a specific target. But again, if you look at our investor slides, you can see historically where we’ve been. We’ve probably been in the high 40% range up to the mid 50% range. Right now, we’re in the middle of that range, so around 50% as I said before. So we’ve got plenty of capacity there, but we don’t need to take it any higher than that really the way we run our business and the way we manage our balance sheet.
The following question is from Robert Kwan from RBC Capital Markets.
Just on the CAD600 million to CAD650 million growth capital plan guidance, how are you treating that CAD150 million Petrogas investment? Is that your net number or is that outside of that?
No, that would be outside that number. That’s more [for the coal] investments as opposed to a PPV.
So I guess if you look at the CAD150 million and then you look at kind of some of these unsecured projects if they come to fruition, Tim, trying to kind of look at that FFO to debt, the rating agencies, does the Petrogas investment bring an incremental funding obligation in your mind and with respect to the unsecured investments is there the ability to actually move forward with them without them triggering some sort of additional equity funding need from a rating agency perspective?
Robert, I guess I think we talked about this before, including the last quarter. Any specific project doesn’t trigger anything. We look through the project queue, the timing of the project queue and we prioritize accordingly. We balance that with other initiatives in the company on a day to day basis, whether it’s the capital efficiencies Dave talked about, the cost efficiencies that we’ve started to implement this past quarter and we will continue to, non-core sales which we did in the first quarter and are prepared to consider if merited on other potential non-core assets, if we so chose. So FFO to debt is not hinged on a specific project or asset. As I said I think on the last call, we will move that ratio higher over the next 18 months, it’s simple as that.
I guess where I’m going a little bit is as you look at the investment you made in those unsecured projects, if you get down – it’s not a liquidity issue by any stretch, I’m just wondering as part of your discussions with S&P, do you think you can get to where S&P wants you to be on top of what the DRIP is going to bring in or do you need to bring additional equity funding, whether that’d be hybrid to some sort of asset sales or something else?
I think the way we look at individual projects we actually see them as being accretive to that ratio. So whether it’s individual organic projects or even acquisitions, we actually see those as being accretive to that ratio and that helps us manage it.
Dave, just in your prepared remarks, you talked about the Astomos agreement for Ridley, and I think the quote was that it was enough to move you towards FID, I just don’t know if I’m trying to kind of pick between words, if that contract comes through based on the costs, the expected cost that you’re seeing for the Ridley Terminal, is that enough to get you an FID decision or is there a need to get additional contracting?
From a standpoint of off-take, it’s probably sufficient to move us towards an FID decision, with maybe a little bit trimming up on top of that. And then in addition to that though we’d be looking for producers to come on to balance the product to bring it into the 20,000 barrels a day. So from an off-take standpoint, yes, and now we just still have a little bit of work to do with respect to securing product security to – with the producers.
And if I can just finish on the power side, as you look at Pomona, I’m just wondering was there any discussion with SCE around a short term contract there? And if not, why not or what was their pushback on doing something given, as you were kind of highlighting the incremental power needs that we’re seeing?
We’ve had good conversations with Edison around Pomona and we will continue to. I think that as they look at it, they have some more fees and so forth for renewables, but they also are looking at their transmission and distribution system right now. But we will continue those conversations with Edison.
And the other thing of interest on Pomona that is pretty clear is that is as it is directly in that Los Angeles load basin, we definitely look at that: A) from the existing facility and what we can do; B) we do have the permit in to put an LMS 100 in there on more modern quicker start unit, then we expect to move through that permitting process fairly quickly; and then C) as we look at the storage targets that each of the utilities have out there, Pomona is ideally situated for battery storage as well. So we have continued conversations with SCE and others on Pomona and I would say it’s broader than just the existing facility. It is looking to the modernization of the facility or the facility used to storage.
Location-wise it is nicely in the load pocket, I’m just wondering do they not need the power right now then – on extending even a short term contract?
You probably have to ask them on exactly what they need. Sometimes they keep it to little a day in terms of telling us specifically what they need, but we continue to firmly believe it is there in the load bucket. It’s certainly been called upon in a couple a few days when they’ve had some heat down there recently. So we certainly continue to think it’s needed and continue to optimize that site.
The following question is from Robert Catellier from CIBC World Markets.
Congratulations on getting the Townsend facility in service on time and on budget actually earlier in both those accounts. I just have a few follow up questions here, specifically on Petrogas, can you clarify the preferred share investment, is it a structuring transaction or if this is new money available for Petrogas to invest and where they might put it?
This is an investment we’ve made; CAD150 million in preferred, which will in the immediate sense go to reduce their debt, but in the broader sense will be used to continue to support their growth plans. As we’ve said, Petrogas has undertaken various growth initiatives in North America building and storage terminals in the past 12 to 24 months and they’ve actually got more in the queue. And ultimately it’s a growth investment for them.
And something caught my attention when David Harris was discussing the Ridley Island Terminal. I think you said something along the lines of this provides access to premium markets for producers with minor contractual commitments versus other options. Can you just elaborate on that a little bit, what sort of contract structure you might have there that may release or provide some better option versus some of the other options for liquids that the producers might have?
I mean the contractual agreements we’re looking into a producer will be on an netback basis, all right, and turns around and opens up their opportunity more than just the Western Canadian type of market, but people will talk about Asia as long there is multiple markets within Asia. So as it relates to contractual commitments compared to the diversification activity, it’s a significant upside for them.
So contractual requirements aren’t any lower, it’s just in the relative upside versus the contractual commitments?
Yes, fair enough, other than we are open to as I also hinted at sharing value with them across our entire value chain to make it a better proposition for them other than just a one dimensional play from a direct arrangement for Western Canada.
And just on the power side, you mentioned power storage at each of Pomona and Blythe, and I’m wondering if these are requirements for re-contracting or if you see these as incremental growth opportunities and if you can sort of quantify what type of financial investment would be required for those?
No, nothing would indicate right now there’d be a requirement for re-contracting. It’s just added optionality and flexibility that we can bring to bear with those assets. As John alluded to all our assets in California have a tremendous amount of flexibility with respect to diversification of a product line.
And then as it relates to cost [indiscernible] is not necessarily a significant cost, they’re relatively low to moderate investments. It’s more with going to niche and being our cooperative partner with the market in the utilities as they want to contract those type of opportunities. John’s right next to me, he can explain that.
I think on the specific storage as an example, I mean it’s not a big capital cost; it’s making sure that you have the appropriate warranties and so forth for the batteries so that you can meet any commitments in an RFP. But certainly each of the California utilities now is under – they are under these targets, storage requirements that are a matter of policy from the PUC.
So as we look at our site that is an example where you already have interconnection rights for certain number of megawatts depending on the site that we have the ability to do at a relatively low capital cost. We have the ability to meet requirements under those impending RFPs for storage. And so that would be an example where we can optimize each of these sites, not just Blythe and Pomona, but also the GWF sites as well.
And just maybe one other quick comment, John talked about Pomona and some of the different configurations that could go on there, including storage, and storage in that case would not be mutually exclusive with the other tracks that we’re currently pursuing and have talked to you about at Pomona, the repowering of that facility and applying different technology to it. I mean they’re not mutually exclusive at all.
Pomona is a classic example, one last thing. I mean, the third piece at Pomona which we will certainly look at is Pomona today even pre putting new technology, there are things that we are in the process of evaluating to change for instance the start time, to make it a quicker start time. So there are certain things that you can do and will do depending on the economics to make those sites more valuable.
And then probably my last question is on Gordondale, I know there are deals not closed and you talked a bit about what in your view is encouraging development potential as the asset moves from Encana to Birchcliff. But at the same time, Birchcliff has a history of owning their own infrastructure. So can you maybe just provide a little bit color in your perspective on how they’re – the advantage you have with Gordondale already being in service versus Birchcliff’s desire historically to own their own infrastructure and how that might play into the future of Gordondale?
Again, Robert, I’d just reiterate it’s a core asset of ours and we will look into not only expand upon it, but continue to provide good service. I think it’s a little premature until they close the deal and we get into discussions with Birchcliff, but we certainly got great relationships at the top between the Chairman and the CEO. And we think we’re well positioned and well situated both with our operations expertise and delivering certainty around execution that we’re looking as to continue to be a strong core asset now and into future and more to come after the deal close and we get into conversations and maybe give a little bit more color when we get into the October call.
[Operator Instructions] The next question is from Steven Paget from FirstEnergy Capital.
On Townsend, is it correct to assume that capital lease payments to AltaGas will be CAD10 million per year lower than previously estimated due to realized capital efficiencies and an extended amortization period?
No, I don’t think so. I can’t quote exactly what had been previously estimated, but the number of – we said CAD20 million for the balance of this year and double that or call it CAD40 million, CAD45 million next year. That would be representative from what we would expect for that type of plant, that size of plant in that area. So I don’t think there’s any change in that.
With half the year complete, should we continue to assume that Northwest Hydro electric projects generate a run rate of CAD100 million a year in EBITDA? And how much EBITDA do you expect them to generate this year?
To put a range I think most people are more around – of the three projects and probably more around CAD110 million to CAD120 million.
The following question is from Ben Pham from BMO.
My first question is on your dividend and perhaps your future expectations on that as you head to 2020. In your prepared remarks, Tim, you mentioned the support for the dividend with respect to the BC Hydro project, I think you had Townsend in there and I’m wondering in terms of how you think about moving dividend going forward, is that perhaps based more on your contracted businesses, their assets rather than maybe less on FFO that if you can re-contract in California, may that drop off that overall bucket?
No, not at all. I mean I think I was just trying to give a different way of looking at it. And so to be clear what I said was that the regulated utilities, our five regulated gas distribution utilities as well as just our Northwest Hydro projects, not Townsend or anything else in B.C., just those – I used those because they’re arguably the longest term contracts that we have in the company. Those themselves amply cover the dividend going forward here.
It’s just a different way of thinking about it. We ultimately do look at FFO and cash generation and that’s what we show on our investor slide sets where we benchmark ourselves versus others. And as we see our FFO grow over time, we think that bodes well for the dividend.
I wanted to switch over to Ridley and I’m just wondering is that FID coming in a bit later than you expected...
Sorry, Ben, I didn’t mean to interrupt you. We’ve always expected the second half of the year and as we work through the environmental process, we’ve got great relations with the First Nations and stuff like that. We always expect timing to be a little bit lumpy, but we’ve already – we’ve always suggested the second half of the year. So we’re happy and pleased with our progress and we’re tracking through that.
And on your guidance on that EBITDA multiple, eight to 10 times in your recent presentation, is that based on that 50% contracts plus some and the rest spot or is that some other assumption that’s driving that spread there?
It’s based on ultimately having full off-take there. And given the various discussions we have really, I think we have growing visibility in terms of what to expect for the other 50%. And we’ve done a lot of work now in terms of the costing of the project and that’s down to refinements over the third quarter of this year. So are two of the key components. And at the end of the day we think about what’s the value to investors, so we’ve got expected fees to meet, match our expected returns. And when you factor those in, how does one create value for the producers who are supplying the facility and that’s sort of how we think about it and in general terms I guess.
The only last thing is just a clean-up on the power side, I’m wondering in your discussions with the California utilities and maybe some the utilities out West, you’re hearing more potential initiatives maybe for the utilities to want to build the power facilities themselves and put them in rate base instead and we’re seeing a lot of that occur outside of the western US side?
No, we’re really not hearing that right now. I mean, the California market is extremely dynamic in terms of all the policy goals that the utilities are tasked with meeting. So each entity will have a different strategy of how they meet up, but we’re not hearing that much in the West.
There are further questions registered at this time. I would now like to turn the meeting back over to Mr. Nieukerk.
Thank you, operator. Thanks everyone for joining us today. As always, Ashley and myself are available for any follow-up questions you may have.
Thank you. The conference has now ended. Please disconnect your lines at this time. Thank you for your participation.
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