Altagas Ltd. (OTCPK:ATGFF) Q4 2016 Earnings Conference Call February 23, 2017 11:00 AM ET
Jess Nieukerk – Senior Director-Investor Relations
David Harris – President and Chief Executive Officer
Tim Watson – Executive Vice President and Chief Financial Officer
John O’Brien – President, AltaGas Services (U.S.) Inc.
David Galison – Canaccord Genuity
Rob Hope – Scotiabank
Robert Catellier – CIBC World Markets
Ben Pham – BMO
Patrick Kenney – National Bank Financial
Robert Kwan – RBC Capital Markets
David Noseworthy – Macquarie
Good morning, ladies and gentlemen, and welcome to AltaGas Ltd. Fourth Quarter 2016 Conference Call. I would now like to turn the meeting over to Mr. Jess Nieukerk, Senior Director, Investor Relations. Please go ahead, Mr. Nieukerk.
Thank you. Good morning, everyone. Welcome to AltaGas’s fourth quarter and full year 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 would 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 will now turn the call over to David Harris.
Thank you, Jess. Good morning, everyone. In 2016 we delivered strong financial results in line with our guidance. We achieved a 20% increase in normalized EBITDA with CAD701 million, up from CAD582 million achieved last year. Normalized funds from operations increased 18% to CAD554 million, or CAD3.52 per share, up from CAD470 million, or CAD3.41 per share, a year ago. This was ahead of our guidance of 15%.
Our strong financial performance in the year is primarily attributed to the addition of the San Joaquin facilities at the end of November 2015, which contribute CAD102 million in EBITDA in 2016. McLymont, the last of our Northwest Hydro facilities that was brought online in October 2015, also provided strong contributions, as did our utilities from continued rate and customer growth. A rather warm winter back in Q1 2016, as well as lower hydrology in Q4 2016 at our Northwest Hydro plants, partially offset these contributions.
2016 was also an excellent year with tremendous progress made on the execution of our northeast BC and NG export strategy. We successfully started up our Townsend facility in July on time and under budget, including the gas gathering lines, the liquids egress lines, and the Alaska Highway truck terminal.
Painted Pony has been steadily ramping up volumes at the Townsend facility, hit a high of over 170 Mmcf per day in December, and has averaged approximately 136 Mmcf per day so far in 2017. In December we received permits to double the size of our Townsend facility and with Townsend 1 filling up, Painted Pony is expected to contract for an additional 99 Mmcf per day of shallow-cut gas processing capacity.
We have already ordered long-lead equipment items and are in the process of building the 99 Mmcf per day train. The facility is expected to begin commercial operations in October 2017.
In addition to this, we are in discussions with multiple parties to contract and build the already permitted second train of the expansion. Earlier this year we also announced a letter of intent with another significant Montney player. We expect to convert the letter of intent into definitive agreements over the next month, and with this new customer allowing us to add yet another 120 Mmcf per day of deep-cut gas processing capability in the Montney, as well as further liquid separation capability, all of which have real connection to RTI.
In September we received permits for our North Pine NGL separation facility and shortly thereafter announced a positive FID. The first train of the NGL separation will be capable of processing up to 10,000 barrels per day of propane plus NGL mix, C3+, and will also include 6,000 barrels per day of condensate, C5+, terminaling capacity, as well as the North Pine pipelines. A second 10,000 barrels per day NGL separation train is expected to follow after completion of the first train.
Finally, in December of 2016 we received permits for our Ridley Island propane export terminal, announced a positive FID in January of this year. Between RTI, North Pine, and Townsend 2, we have been able to secure permits for our midstream projects worth close to CAD1 billion. As Canada’s first-ever West Coast propane export terminal, Ridley will be a game-changer for the WCSB. It will open up global markets for producers and bring global propane pricing to Western Canada.
Through the combination of our processing capabilities, the North Pine facility, and RTI we can offer services across the full energy value chain and offer preferential access to existing and new markets for producers that use our value chain. The relationship we have built with Painted Pony and the letter of intent we have with yet another significant Montney player are a testament to the success of our strategy and to our ability to deliver certainty to our customers by building efficient, low-cost facilities on schedule and adding value to the resulting product streams.
Our midstream strategy has opened the door for numerous new potential customers and there are a lot of discussions happening behind the scenes. We expect a lot more to happen in 2017 and we remain committed to our ambition of providing at least 1 Bcf per day of processing services in northeast BC, as well as additional liquid separation facilities under term contracts.
In California we recently commissioned our Pomona energy storage facility on time and on budget. This is one of the largest energy storage projects in North America. We have a 10 year agreement with Southern California Edison for 20 megawatts of resource adequacy, which can produce 80 megawatts an hour over a continuous four-hour period. We are now receiving fixed monthly resource adequacy payments and retain the rights to earn additional revenue from the energy and ancillary services.
As we have stated previously, all of our sites in California have the capability to host battery storage and will continue to actively participate in all California utility energy storage RFOs.
We also continue to look at optimizing our Blythe facility. With the ongoing uncertainty at the Aliso Canyon natural gas storage facility and the threat of gas shortages impacting generation in the southern part of the state, we believe we are in a strong position to offer additional flexibility to SCE and another possible counterparties as we have the capability and are in the process of reconnecting to El Paso’s natural gas supply.
This secondary gas supply is expected to be available in the second quarter of this year and provides redundancy and flexibility in our operations at a very low cost and we believe it will provide strong value to the market going forward. Overall, we continue to see good opportunities to advance our California power strategy and position ourselves to deliver what the market requires.
Turning to our recent strategic transaction to acquire WGL Holdings. We share a lot of similarities with WGL and have spent a lot of time working with their management team there to make this transaction a success. I would note upfront that WGL will not detract from the value our midstream and power strategies bring to our shareholders. WGL is much more than just the utility.
In many ways, WGL is similar to AltaGas, a diversified energy infrastructure company with a gas utility located in three high-growth jurisdictions, a growing gas midstream business, and a clean power business through distributed generation. This transaction is highly transformational for AltaGas and increases both our scale and the breadth of quality assets. Furthermore, it significantly enhances our growth opportunities with over CAD7 billion in opportunities across all three business segments.
Fundamentally, we will look to maintain a balanced business and geographic mix over the long term. Our core premise is that market diversity allows AltaGas to uniquely take advantage of the broader energy markets as they evolve. The increased scale, strategic overlap, and exceptional growth profile we have with WGL is also expected to provide meaningful financial benefits for our shareholders.
We expect the transaction to be meaningfully accretive to normalized FFO per share with accretion of 15% to 20% starting in the first full year of operations and on average through 2021. It will also be accretive to EPS with growth in the 8% to 10% range per year. All this means we are confident in delivering 8% to 10% in annual dividend growth through 2021.
Over the next year we will continue to work closely with regulators, stakeholders, and WGL’s team to ensure approvals are obtained and a successful transaction occurs. We very much look forward to welcoming WGL into the AltaGas family.
Let me now turn the call over to Tim.
Thank you, David. Good morning, everyone. 2016 was a year which highlighted the full breadth and extent of our diversified business platform across all business units and geographies, as well as the robust nature of our assets and the strength of our balance sheet.
To underscore this, 2016 normalized EBITDA was up 20% to CAD701 million compared to CAD582 million in 2015. Normalized funds from operations, or FFO, were CAD554 million, or CAD3.52 per share, up 18% from CAD470 million, or CAD3.41 per share. Both these measures, EBITDA and FFO, met or exceeded our previously communicated guidance for 2016.
Across our three business lines, Power EBITDA increased 60% in 2016 CAD285 million. Power represented 39% of total normalized 2016 EBITDA before corporate allocations. The acquisition of the San Joaquin power assets in California was a significant contributing factor. In addition, despite low water flows in the fourth quarter, our Northwest British Columbia Hydro facilities exhibited strong performance as a result of the startup of McLymont in the fourth quarter of 2015 and improved performance at Forrest Kerr.
Productivity growth at Northwest Hydro was greater than 15% in 2016 and is positioned to deliver incremental generation in 2017. Following the termination of the Sundance B PPAs, AltaGas is fully transitioned to being a 100% clean energy power provider.
Normalized EBITDA at our regulated gas distribution utilities increased 8% to CAD277 million in 2016. AltaGas achieved customer growth across all utilities in 2016 and grew rate base by expanding its existing infrastructure through system upgrade programs and organic growth opportunities. A stronger U.S. dollar also helped.
This was partially offset by warmer weather at all of our utilities and our customer retention program, which was approved at Heritage Gas. Utilities EBITDA represented 38% of normalized EBITDA in 2016.
Finally, EBITDA from the gas midstream assets was CAD163 million, down 5% versus 2015. Gas midstream accounted for 23% of total normalized EBITDA in 2016, while volumes at our extraction facilities increased slightly year-over-year, primarily at the Harmattan co-stream and Younger facilities, EBITDA was impacted by the decline in realized frac spread due to the strong hedge prices in 2015.
On the gathering and processing side, excluding the non-core assets which were sold to Tidewater in Q1 2016, total volumes were up over 10%, mainly due to a partial year of Townsend and partially higher – marginally higher Blair Creek volumes, partially offset by slightly lower Gordondale volumes delivered in excess of take-or-pay levels.
Equity earnings from Petrogas increased to CAD12 million as compared to CAD7 million last year due to dividend income earned from the investment in the preferred shares, increased volumes at Ferndale, and generally improved conditions at other Petrogas terminals. This was partially offset by weaker results in the first half of 2016 from Petrogas segments that support upstream activities and weaker LPG export market pricing in the summer of 2016, which has subsequently improved greatly.
Normalized funds from operations increased 18% in 2016 as a result of the strong results in the power and utility segments, combined with higher common share dividends from Petrogas, partially offset by higher interest expense. In 2016, we received CAD24 million in common share dividends from Petrogas versus CAD11 million in 2015, and we also received CAD6 million in preferred share dividends, which was in line with our expectations.
Normalized net income in 2016 was CAD153 million, or CAD0.98 per share, versus CAD140 million, or CAD1.02 per share, in 2015. Normalized net income was higher due to the same factors impacting normalized EBITDA, partially offset by higher depreciation, amortization, interest expense, and preferred share dividends. We had several normalizing adjustments for 2016 and you can find those in the quarterly disclosure that we released this morning.
On a U.S. GAAP basis, net income applicable to common shares for 2016 was CAD155 million, or CAD0.99 per share. This compares with CAD10 million, or CAD0.07 per share, for 2015.
Interest expense in 2016 was CAD151 million, compared to CAD126 million for 2015. 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 and Townsend, were brought into service. This was partially offset by lower overall interest rates.
Depreciation and amortization was CAD272 million in 2016 compared to CAD212 million a year ago. The increase was mainly due to the acquisition of the San Joaquin facilities, as well as new assets placed into service and the impact of the stronger U.S. dollar. This was partially offset by lower depreciation and amortization expense as a result of the Tidewater disposition.
For 2016 income tax expense was CAD33 million, down from CAD48 million in 2015. The decrease was mainly due to the absence of the one-time non-cash CAD14 million charge recorded in 2015 related to the increase in the Alberta corporate income tax rate, as well as 2015 charges to income that did not attract tax recoveries and the CAD10 million tax recovery related to the Tidewater disposition and the CAD8 million tax recovery related to the dissolution of the ASTC partnership.
This tax decrease was partially offset by higher taxable earnings in 2016 as compared to last year. Finally, the 2016 effective tax rate was 23% based on normalized results and it was 14% based on U.S. GAAP due to the Tidewater and ASTC events.
Invested capital net of dispositions in 2016 was CAD666 million, down from CAD1.6 billion in 2015, including acquisitions. Almost 2/3 of the total capital invested in 2016 was in the gas business. Investment in property, plant, and equipment decreased as the San Joaquin acquisition was completed in 2015. Maintenance capital in 2016 totaled CAD20 million, split 75% for Power and 25% for Gas.
AltaGas’s balance sheet is in a strong position and well-funded for 2017. At the end of 2016, debt to total capital was 46%, down from 48% last year. This remains well below our bank and term note covenant levels of 65% to 70%.
There is approximately CAD1.6 billion available on our existing credit facilities and we continue to have strong access to multiple sources of funding. In 2016, we completed almost CAD800 million of new debt and equity issues, which were well received by the market to support the new infrastructure projects this year. In 2017, a full year from new facilities such as Townsend and Pomona and the start up Townsend 2 will contribute additional cash flow and further strengthen the balance sheet.
Turning to our 2017 outlook. We currently expect to deliver approximately high single-digit normalized EBITDA and FFO growth as compared to 2016. We expect growth in all three business segments with the Gas segments contributing –expecting to generate the highest EBITDA growth.
Up to 3/4 of 2017 EBITDA is expected to come from Power and Utilities, but Gas is expected to increase proportionately relative to 2016. Increased 2017 EBITDA from Gas is expected to be driven by the first full year of commercial operations at Phase 1 of the Townsend facility; higher earnings from frac-exposed volumes as a result of the expected recovery of commodity prices; higher expected earnings from Petrogas, including a full year of income from preferred share dividends; and a partial year contribution from Townsend Phase 2 entering commercial operations in the fourth quarter of this year.
The additional earnings are expected to be offset by the closing of the anticipated sale of the EDS and JFP transmission pipelines in March 2017, which will impact EBITDA by approximately CAD10 million. Furthermore, the Gordondale and EEEP facilities are expected to undergo normally scheduled turnarounds in mid-2017, which will impact EBITDA by up to approximately CAD7 million.
Based on current forecasted commodity prices, we expect to increase the amount of extraction volumes exposed to frac spreads prior to hedging to about 9,600 barrels per day for 2017. We have hedges in place this year for approximately 5,450 barrels per day at an average price of approximately CAD23 per barrel, excluding basis differentials.
Just as a quick reminder, every plus or minus CAD1 change per barrel in the frac spread results in approximately CAD1.5 million in our 2017 EBITDA. And approximately 59% of our 2017 Gas EBITDA is expected to generated or underpinned by take-or-pay and cost-of-service contracts, which, as everyone knows, have no direct price or volume exposure associated with them.
In 2017 we expect Petrogas will have several growth capital projects that may likely take some priority over common share dividends, but this does not have a material impact on AltaGas overall. Also, as a full year of preferred share dividends will be realized, we expect to see CAD13 million from that source.
2017 growth in the power segment will be driven by the addition of the Pomona energy storage facility, as Dave said earlier, which entered commercial operation in December of 2016, as well as higher expected earnings from the Northwest Hydro facilities as improvements in productivity continue and contractual price increases take effect, combined with lower planned outages at Blythe. The earnings and cash flows from the Northwest Hydro facilities are expected to be seasonally stronger beginning in the second quarter through the end of the third quarter and are expected to decline in the fourth quarter based on seasonal water flow patterns. Actual seasonal water flows will vary with regional temperatures and precipitation levels.
Utilities are expected to see a moderate increase in normalized 2017 EBITDA compared to 2016. This is driven by rate base and customer growth, as well as the expectation of a normal weather year, as compared to the warm weather experienced in 2016. Earnings at all of utilities, except PNG, are affected by weather in their franchise areas with colder weather generally benefiting earnings.
In addition, ENSTAR expect EBITDA to increase by approximately CAD3 million in 2017 as a result of interim refundable rate increase approved in 2016 by its regulator, with final rates expected to be set in the third quarter of 2017.
Turning to capital expenditures. We expect to spend between CAD550 million and CAD650 million in 2017. The Gas segment will account for 65% to 75% of that total, while Utilities will account for approximately 20% to 25% and the Power segment will account for 5% to 10%. Gas and Power maintenance capital is expected to be approximately CAD25 million to CAD35 million.
The majority of 2017 capital will be allocated towards AltaGas’s growth projects related to the northeast BC and energy export strategies. I won’t go through those projects, because you have already heard them.
The 2017 capital program is expected to be funded through internally-generated cash flow and a dividend reinvestment plan. If required, we also have sufficient borrowing capacity available on our existing credit facilities, as well as access to capital markets.
We expect approximately CAD295 million for depreciation and amortization and accretion expense in 2017. We continue to focus on enhancing productivity and streamlining our business, including a disposition of smaller non-core assets. The 2017 corporate effective tax rate, based on normalized earnings, is expected to be approximately 22%.
Approximately 50% of our total 2017 EBITDA for AltaGas will come from the U.S. and it reflects our diversified business platform across three major energy infrastructure business lines. And again, as a reminder, for every plus or minus 5% change in the Canadian/U.S. FX rate, the annual impact to total 2017 EBITDA is about CAD15 million.
In summary, we just completed an exceptionally strong year for AltaGas and we expect approximately high single-digit percentage growth in 2017 with a number of key investments setting the stage for further growth in 2018 and beyond.
A couple quick comments on WGL, because Dave has covered a lot of it. It is a very strong strategic fit for AltaGas, as you know. It brings significant opportunities for continued growth in all three business segments: midstream, power, and utilities. It also adds to our financial strength and it’s highly accretive from both an FFO-per-share and earnings-per-share basis.
We will be prudent in how we execute on the full financing plan for this acquisition. AltaGas remains committed to maintaining strong access to capital and to our BBB mid credit ratings. We have reviewed the WGL acquisition and expected financing steps with the credit rating agencies and have presented them with a plan that reinforces a strong investment-grade balance sheet.
The first step in the permanent financing plan was the largest capital markets offering in our history, a CAD2.1 billion equity subscription receipt offering, which was completed on February 3. This financing was well taken up by both Canadian and international investors.
In addition, we were pleased to undertake a CAD400 million equity private placement with OMERS, the pension plan for Ontario’s municipal employees. We have already started to implement the appropriate FX hedging for the Canadian dollar proceeds from these financings to minimize FX exposure related to the U.S. dollar purchase price for WGL.
Yesterday we also just closed a CAD300 million preferred share equity offering, which was well received by investors and upsized.
Once we complete our regulatory filings for the WGL acquisition and start to move that process forward, we will also plan to undertake senior debt, hybrid securities, as well as selected AltaGas asset sales, to complete the long-term transaction financing. Much of these additional proceeds realized will be in U.S. dollars.
We believe there are a number of attractive, actionable opportunities to monetize portions of AltaGas’s three businesses in a manner which supports our long-term strategy of growing in attractive areas and maintaining a long-term balanced mix of energy infrastructure businesses. These divestitures could include selected assets within AltaGas’s existing U.S. power portfolio, potentially some additional non-core assets within our midstream business, and potentially a minority interest in one or more of our existing utilities.
Our financing strategy presents a clear path for stronger credit metrics, including FFO to debt of approximately 15% for the first full year in 2019, to strengthen and maintain our S&P BBB rating as well as our DBS BBB rating.
The pending WGL acquisition supports AltaGas’s long-term vision by reinforcing our strategy to focus on high-quality, low-risk, and long-lived assets and to achieve a diversified long-term growing mix of businesses across our three product lines. AltaGas delivers an effective balance between yield and growth and pro forma for WGL will support an 8% to 10% annual dividend growth rate while improving the dividend payout ratio to ensure even more sustainability.
As a reminder, cash flow from our regulated utilities combined with our long-term contracted Northwest Hydro assets more than covers total cash dividends paid.
With that, let me turn the call back to Jess.
Thank you, Tim. Operator, we will now open up the call for questions.
[Operator Instructions] Our first question comes from David Galison with Canaccord Genuity. Your line is now open.
Good morning, everyone. So my first question is on the guidance; just wondering if you could give a couple of things. One, with a large portion coming from the U.S., what’s the exchange rate that you are using for your forecast? And then also if you can give you an indication on the Petrogas dividends that you are expecting, both common and preferred, that are included in that?
On the first question, David, on the FX rate for 2017, I believe it is in and around the current spot levels. It is I think about 1.3-ish, so essentially right where you see the current market levels.
Second question related to Petrogas dividends, can you just repeat it for me again, please?
Just, within your guidance, what are you expecting to receive from Petrogas?
We are expecting, as I said, first of all – well, two components, really, from a cash flow dividend standpoint. One is common share dividends.
As I said, I think they will be a little bit lighter than they were in 2016, primarily attributable to some internal reinvestment that Petrogas is putting into certain other terminals and other businesses, which obviously supports long-term growth. But there’s also the full year benefit or impact of the preferred share dividends that we have from our investment we made in 2016 that’s about CAD13 million. So those would be the two primarily cash flow dividend streams. Of course, we collect an equity investment earning stream as well.
Then on the CapEx budget, what proportion is being spent on projects that have not received FID yet?
A significant proportion would be related to projects that do have FID in hand. Obviously, the most notable ones would be RTI and North Pine and Townsend 2, which obviously is a 2017 Q4 project. Those would be the most notable ones I think, David.
Yes, those are the most notable. This is David Harris jumping in on that. And then we are spending like money as far as moving forward on the 120-day deep-cut opportunity we have in the Montney as well.
Then just a couple of maintenance questions, if I could. I didn’t – could you repeat – there’s a couple of things that you mentioned that I didn’t hear: the percentage of take-or-pay in the Gas segment and then the depreciation expected for 2017.
The take-or-pay, I would put it I think together with cost of service because both of those are – they are technically different but effectively a practical basis the same; no impact on volumes and pricing. It’s about 59% of the total in the Gas segment. So almost 2/3 of our Gas segment benefits from those two very favorable types of contracts.
What was the second piece, David?
The depreciation expense expected for 2017.
It’s about CAD290 million of depreciation and amortization and I think we might have accretion in there as well.
All right, thank you very much.
And our next question comes from Rob Hope with Scotiabank. Your line is open.
Good morning. A couple questions on WGL. And I realize it’s early days, but have you started engaging the regulators and some affected stakeholders in this transaction? If so, are there any concerns that have been raised that were not anticipated?
No, no surprises at this point and we have started dialogue with regulators and key stakeholders. Right now we’re looking to be on a path that we will probably look to do our filings with the jurisdictions in the early part of April.
All right, that’s helpful. Then just regarding your comments on the asset sales, just want to clarify. Have you already – looking through your portfolio, have you already figured out which ones you will go to market and then when do you expect to start engaging the market on these asset sales?
I will start and Dave can tell us what I forgot, but I think we certainly have this under consideration. One thing we said – I believe we said it even on our conference call around WGL – was we have…
Frankly, over the past year we have had some unsolicited approaches on selected assets, which obviously is an interesting indicator for us and a good sign of maybe where the market might be, but most certainly, around the clusters that I said on the call today. We have a decent sense for what those buckets of assets could be and we’re still formulating and making our plans.
You have to realize, of course, that really everything needs to move in parallel steps. One of the most important things we’re going to be doing in the next month is the regulatory filings to kick that process off and get that timing started. We are not going to be out in market ahead of that with any asset sales, because things have to move in lockstep through this entire transaction, so you will see more news on that as the year goes by.
Okay. Then just to clarify, you will look to time the asset sales roughly in line with the closing of the transaction rather than if you get a nice bid now?
I think that’s right, correct.
The only thing you may see us move on a little bit sooner would be the non-core gas assets that we’ve talked about in the past as well. The balance of which Tim talked about would be more towards the latter half of the year and more in sequence with our expectations of closing.
Thank you, those were my questions.
Our next question comes from Robert Catellier with CIBC World Markets. Your line is now open.
Good morning, guys. I wondered if you could just touch on the option for Ridley Island and when the exercise date is for that. Maybe comment on the type of option holder as well as whether it’s at a premium or if it’s at book.
I just think right now we are into those discussions and it would be premature to talk about them at this point, Robert.
So the – are the terms not set – is that the issue – and still under discussion?
It’s still under discussion. Things are going quite well, but just because of the tight CA and other things that we’re under, it would be just premature. But things are – we would expect to have better intel for you in the next few months when we get to the April call.
And just quickly on the Northwest Hydro and the 15% productivity gains. Can you provide a little more color around that? What exactly you were able to do to achieve that level of efficiency and the sustainability, please?
This is John O’Brien, Robert. I would say – and in fact, I think we’ve spoken about an outage in February that we are coming out of fairly soon here that has gone well. During that outage we have looked at the right technology in light of the river. I think we are getting very good knowledge of quite a dramatic river and we’ve put in different types of desanders and other technology like that that I think is very helpful in the operations.
I also think that the team up there is working cohesively. We really have a good team now up at Hydro. There’s a clear understanding of commercially how you really want to run the three projects and make sure that you are taking advantage and optimizing the use of the water. So I think it’s a combination of both technology and the team really coming together and getting up to speed up there.
Then final question is just on the outlook for Pomona, maybe it’s too early to tell but is there any – what do you really see as the impact from the Aliso Canyon storage facility incident and shut down there? Maybe you could touch on the repowering, whether there is any sort of supply issue, and on the other side of the coin, what additional storage potential could that incident create.
This is John O’Brien again. I think that what we are seeing with the battery project that we have online is that all of us, including the California ISO, are figuring out how best to deploy the batteries, as Dave referred to, in the energy market, but also in the ancillary service markets to be a control or a reg-up, reg-down mechanism that can be used as renewables come on and offline, particularly solar.
So A), I think there’s going to be – as a policy, California wants more storage, and as we’ve said, our sites are particularly well situated for storage. As an example, as we look at Pomona we basically can say to SCE and others, if you watch the California market, for instance, you have these community choice aggregators out there now where they are taking load and taking control of their own supply requirements. And I think in that you’re seeing it’s either going to be – we can knock on the door of a CCA or a utility and say we can do gas here or we can do storage. We can take the interconnect capacity that we have and fit it as best we can with the relevant customer out there.
Aliso Canyon, it still goes on in terms of policy makers out there and what their determination is as to the future of Aliso Canyon. I do think that does lead to more of a need. It will lead to more of a need for the gas plants, but I also think that there’s going to be, if you hold existing brownfield assets, you are going to have versatility to either provide the gas asset or the storage because you have that interconnectability and you have a site that’s ready. And our Pomona battery storage project, which I have to applaud our team on, is an example of using that site correctly.
Okay, thank you.
Our next question comes from Ben Pham with BMO. Your line is now open.
Okay, thanks. Good morning. I had a question on the BC Hydro asset and a bit of commentary on the below-average hydrology. Could you remind us how the production translates into revenue generation? Is it certain availability targets you need to meet and AltaGas picks the variance if it’s below?
No, it’s basically driven by river flow, based off of firm and non-firm pricing. The majority of the revenue comes through what we call about the middle of May to the middle of October timeframe, and then depending on what Mother Nature does with a little bit of rain and snow in the shoulder months kind of dictates hydrology. But it’s much more sensitive hydrology in the shoulder months than it is during the primary part of the season where we make 98% of the money.
We are not overly worried about it. You are always going to have different seasonality during the shoulder months at times. And this particular time we are just slightly below on the hydraulics that impacted the EBITDA expectations on the northwest projects.
Okay. So your initial EBITDA expectations, that was probably based on some sort of long-term average? And you are taking hydrology risk, but you also benefit from any sort of operational efficiency you’ve highlighted?
Absolutely. Going way back when we designed and put the project together was based off of 45 years of hydrology and you run the average. Then, as John pointed out, as you get smarter and as much as you can analyze and calculate to prepare for Mother Nature, she responds accordingly, right? And as we get smarter we are making enhancements as it relates to production capabilities, smarter down the river and we are seeing those values.
All right. I had – my other question is on the asset sales related to WGL and as you go through that process and assessment. I was wondering your thought process on how you plan to potentially retain value for some of your development sites in California, if that was one of the assets that you are planning to sell.
I can start. California, as you know, Ben, is very much a business; it’s not just a series of six different assets. It’s a business that encompasses all of California, Northern California and Southern California, which obviously is a humongous state.
And in each of those sites, as John said, has optionality. We can put battery storage on them. We can have multiple markets for interconnectivity. And then we can couple, like bucket two product offerings with both traditional as well as renewable type power generation.
Those are a lot of different variables that go into every site in terms of how we are running those sites and lucky part is that five of the six sites are in very nice load pockets and the sixth site is on the border, can serve three or four different states. You put that all together, that’s a business not a set of assets. There’s different ways to think about how we approach and realize value on those assets, but we’re going to sell it as a business.
And, look, we don’t need to sell all of it. We can bring a partner and continue to have our very expert people continue to do what they are doing day in and day out and add value to that, because that’s –. You can already see in the very early parts of 2017 what we have been doing there and we will have more to say on that as the year goes by, specifically on California.
Thanks for that, Tim. Just one last one on the utilities, in terms of a potential minority sale. Is there any impediments when you acquired SEMCO in terms of direct or indirect change of control?
No, for the levels that we are talking about there’s no real impediments. Of course, we have excellent regulatory relationships and we will follow all the due process that you have to do for that. But really the thresholds would be quite high for us to really trigger anything, which is what you are getting at I think in your question. And frankly, we don’t need to trigger anything to affect what we want to do here.
Okay, that’s very helpful. Thanks, everybody.
Our next question comes from Patrick Kenney with National Bank Financial. Your line is now open.
Just on the acquisition, David, I know you are not banking on any real cost synergies with your other utilities, but wanted to get your thoughts on any potential commercial synergies within your midstream business. What I’m thinking here is, if your Canadian gas customers need access to LNG, which you will pick up through Cove Point, and your new Marcellus customers might need access to the Asian propane market, which you will have by 2019, what opportunities might you be able to pursue, either through swapping molecules for customers or other marketing opportunities?
That’s a great question. That’s actually – when we started to take a look at this opportunity, it’s one of the things that came to mind for us. So it’s kind of all of the above.
We’re certainly not lacking for opportunities to provide additional egress and exit opportunities for our producers with both what we will have on the East and West Coast. Especially when you considering you’re playing in the two most prolific plays in North America, between the Montney in the Marcellus and the Utica shale. We are certainly taking a hard look at that.
And it wouldn’t just stop with molecules. WGL does a great job down there. They have got great relationships. I think we got a great reputation as a midstreamer; we may look to go a little upstream as well. And turn around and just not look at gas, but do we turn around and look at midstream opportunities, physical traditional midstream opportunities that we do an excellent job at in Marcellus and Utica as well? So we are not putting any boundaries on the opportunities at this point.
All right, thanks for that. Then maybe for Tim, if you could just confirm, outside of debt to cap, what your target pro forma debt-to-EBITDA and FFO-to-debt ratios are. After you get through the asset dispositions, of course.
And would those target ratios shift around at all, depending on whether or not the dispositions end up coming from your power and midstream portfolio versus selling a minority interest in your utilities?
I think the reality is we’re going to have some – as you well know, we are going to have some moving pieces here through the balance of this year and into 2018, because obviously 2018 will be a partial year with the WGL impact on closing.
But the guidance we have provided, going back to the January 25 conference call and reiterating today, would be that on a pro forma basis, with WGL in hand – and I think you’ve got to focus on a first full year 2019 to get a sense for a full calendar type of experience here – we would be targeting 15%-plus on that FFO-to-debt metric, which is a key metric for any infrastructure company. Debt to EBITDA, we actually think – again, this is going to be a credit-enhancing transaction for us on certain of these key ratios. And so debt to EBITDA we see trending down into the low to mid 4 range with WGL enhanced pro forma, which is an improvement from where we are at or where we have traditionally run at.
I can’t say for sure – I can’t say that that’s really – there’s a real internal target on debt to EBITDA, but folks like yourselves look at that metric and so where we are aware of where we are at. We also think it’s going to improve with WGL.
I talked about debt to cap on the call and our number is already quite strong, tons of room there, but that will also improve with WGL over time. I think the only other metric from a bank covenant standpoint is just standard EBITDA to interest type of coverage, which again we’ve got plenty of cushion on.
All right, great. Thank you very much.
Our next question comes from Robert Kwan with RBC Capital Markets. Your line is now open.
Good morning. When you look at your growth capital program, say, into 2018 and just beyond, more just even strategically how you are looking at it, just with WGL and the financing you need there, are you high-grading the growth initiatives or seeking the highest returns and the most strategic projects? Or has nothing really changed as part of the transaction?
That’s a great question, Robert. We certainly, when you take a look at the breadth of opportunities we have with the WGL transaction and say a much bigger buffet table to choose from, we are certainly going to be selective and prioritize, traditionally like we always do, quite frankly, to turn around and put the best projects forward.
I guess with that, David, are there anything the maybe you’ve talked about in the past then that maybe was or is a little more peripheral then going forward?
No, because I think if I looked right now going forward in the immediate future, say over the next three, four, five years, we are certainly not going to turn around and back off our northeast BC strategy, what we are doing there and then linking that with our RTI facility and creating optionality with diversified markets with respect to the producers. You will certainly see us going with that.
And then with the combination of what we have on the utility side and what WGL brings on their midstream and their what we call the distributed generation business of power, we will certainly see a lot of great assets. We will just, obviously, rank in priority as far as how we turn around and execute them and which ones we would put forth to give us the overall best effect for the key financial matrix of the Company.
Robert, I would just say returns are paramount for us. We are extremely focused on those. You can see those in our investor slides in terms of how we look at the EBITDA generation for every dollar of capital invested.
But I break it into our existing assets and our potential projects going forward in the future where we allocate capital. And on our existing assets, we’ve been fairly upfront to say that there are still probably some non-core assets, not unlike the Tidewater disposition, which we won’t be afraid to move on this year.
And then, as it relates to not existing assets, but future investment opportunities, as Dave said, we are going to have a great abundance of opportunities. And, frankly, we will be more selective, because we will have the luxury of doing that.
It’s notable that with WGL we’re going to open up a whole new gas province or domain I guess stateside. We’ve never done that before, but this is going to present a plethora of opportunities on the gas midstream side. And that is going to compete nicely with the other opportunities.
Got it. If I can just turn to asset sales outside of the non-core sales, it sounds like there might be a bit of a bias to partial monetizations. I’m just wondering then with that, is that a financing strategy that you might expect to use going forward or is it really just out of necessity to fund WGL?
I would say, no, it’s – I think all we are trying to do is make sure that we ultimately don’t surprise you. The reality is, when you look to divest assets, there’s different ways you can do that. And as you know, when you go to divest assets, you attract different people depending on the structure that you go out with.
If you go out with an interest or a preparedness to take on a minority partner, you are going to probably get a different type of investor than somebody who might want to buy the whole business from you. We don’t want to cut off any of those opportunities. We will let the market figure out where the highest value is and weigh that with their own objectives.
But I think the clear message is we can go a number of different paths here, depending on what optimizes things for us.
I guess what I was wondering a little bit more, Tim, was just whether – partial asset monetizations, is that something that you might look at going forward as a way of reducing capital intensity for new initiatives?
Certainly the math will lead you to that conclusion. If you have a partner who is shouldering a portion of ongoing capital or future capital with a project, certainly that helps and so that is a consideration. As you know, we are not afraid of taking on partners. We have partner relationships today, so we are good at operating within those sort of parameters. We’re not afraid of doing that, if that makes sense.
Yes, especially if that partner brings additional opportunities to AltaGas as a result of that partnership.
Got it. If I can just finish with something a little more granular just about frac spreads here. Are you able to disclose what the frac spread assumption, and if there any material changes in extraction premiums embedded in the guidance?
Then the second part being you’ve got the fracture sensitivity on EBITDA. I’m just wondering how does Petrogas figure into that given Petrogas’s different accounting, in your results.
On frac spreads – and I think you’re talking guidance here – the reality is look, what I said was about 9,600 barrels a day of total extraction volumes prior to hedging, but we have hedged almost 60% of that total. So net-net we’ve only got just over 4,000 barrels a day of actual exposure that go up and down depending on frac spreads.
So we’re just not talking a very significant amount of EBITDA, whether you want to use a CAD20 frac spread or something. But we have seen strength in the markets – and maybe Randy wants to comment on this; I don’t know.
We’ve definitely seen propane, specialty propane come back over the end of 2016 and into 2017, so I think the guidance we put in the disclosure of CAD23 before extraction premiums is good guidance.
Okay. Then how does Petrogas fit into all of this? Is that inclusive of the sensitivity that you gave?
No, the sensitivity I gave was for AltaGas proper. Petrogas is – we collect cash dividends and then, from an accounting standpoint, we book equity earnings. We equity account for Petrogas and so –. Petrogas has different aspects to their business. They don’t run extraction plants like we do. They do logistics terminals primarily and so we don’t think about it from a frac spread basis for them, per se.
That’s fine, thank you.
And our next question comes from David Noseworthy with Macquarie. Your line is now open.
Thank you and good morning. Maybe just a couple of cleanup questions. First, in regards to WGL, and you mentioned I think with Patrick about flopping molecules between East Coast and West Coast. Will there be a role for Petrogas in that sort of an operation or would that be something that is AltaGas proper?
We wouldn’t – I think with any of our relationships we wouldn’t limit the boundaries to just AltaGas proper. If we certainly believe one of our partners or affiliates can certainly help and increase value for the shareholder, we will certainly exercise and pull that lever.
Then you mentioned something about more upstream opportunities. I was wondering if you could clarify, you don’t mean production, but what did you kind of – what was that referencing to?
David, just referencing the fact that WGL has got great relationships. They’ve got projects with great egress with the pipelines they have, the full pipelines that they will have when they get completed out here over the next 12 to 18, 24 months. And with that our skills in traditional midstream, i.e., whether they are shallow cut, deep cuts, fractionations, we go one notch up in the upstream chain and take a look at positioning ourselves to do physical assets in those areas.
Got it, okay.
But just to be clear, we are not going into upstream production. We’re simply going to build on the pipeline positions Dave said and get into plants, which is what we do for a living.
Yes, we’re not talking about drilling or anything like that.
Perfect, thanks for clarifying that. Then just with respect to your Pomona location, previously you were looking for a small power plant exemption so that you could build 100 megawatt gen set. Is there any update on those efforts?
No, we are still awaiting some of the facilities studies. We are still – we have the application before the CEC, so we are still looking at some of the interconnect facility studies right now on that.
Okay, perfect. Then just one last one. I think at the beginning of the conversation you were answering, Rob, a question on timing of non-core potential asset sales. Understanding that you would want to time it with the potential close of the acquisition of WGL; is there any particular milestone you really want to see hit before you trigger those sales, or is it just timing of what you generally expect?
I just think, David, with respect to the non-core that we have identified in the past, they may not necessarily be linked to how we sequence through WGL close, because we have talked actively about maybe monetizing some of the non-core asset sales in the past. So we may move on that sooner or later; they are not necessarily linked directly with the WGL transaction.
I would just add to that, when you go out to market and you look to market an asset, it doesn’t happen overnight. It is a multi-month exercise, so if we were to start something in the middle of the year or something, it’s going to overlap nicely with the progress we expect to make on the regulatory front. That’s just the way those two things will play out.
I did mean to say core as opposed to non-core. And so you are basically saying hey, these should actually, just time-wise; there’s not a particular milestone that you want to see hit?
Okay, perfect. Thank you very much.
At this time I’m showing no further questions. I would like to turn the call back over to Mr. Jess Nieukerk for any closing remarks.
Thank you, operator. That concludes AltaGas’s 2016 fourth quarter and full year results. Ashley and myself are available for any follow-up questions. Thank you.
Ladies and gentlemen, thank you for your participation in today’s conference. This does conclude the program. You may now disconnect. Everyone, have a great day.
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