AltaGas' (ATGFF) CEO David Harris on Q3 2016 Results - Earnings Call Transcript

| About: AltaGas Ltd. (ATGFF)

Start Time: 11:00

End Time: 11:58

AltaGas Ltd. (OTCPK:ATGFF)

Q3 2016 Earnings Conference Call

October 20, 2016, 11:00 AM ET

Executives

David Harris - President and CEO

Tim Watson - EVP and CFO

John O’Brien - President AltaGas Services (U.S.) Inc.

John Lowe - EVP

Jess Nieukerk - Senior Director IR

Analysts

Linda Ezergailis - TD Newscrest

Robert Hope - Scotiabank

David Galison - Canaccord Genuity

Robert Catellier - CIBC World Markets

Robert Kwan - RBC Capital Markets

Ben Pham - BMO Capital Markets

Patrick Kenny - National Bank Financial

Operator

Good morning, ladies and gentlemen, and welcome to the AltaGas Ltd. Q3 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.

Jess Nieukerk

Thank you. Good morning, everyone. Welcome to AltaGas’ third 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.

David Harris

Thank you, Jess. Good morning, everyone. Over the last quarter, we continue to move forward many of our key initiatives while delivering strong results. We had a significantly strong third quarter with normalized EBITDA reaching 176 million, up 41% from 125 million achieved a year ago. Normalized funds from operations increased 34% to 137 million or $0.84 per share, up from 102 million or $0.75 per share a year ago.

Our strong financial performance in the quarter is primarily attributed to the addition of San Joaquin Facilities at the end of November 2015, which contributed over 25 million in EBITDA in the quarter and to McLymont, the last of our Northwest Hydro Facilities that was brought online in October 2015. We also have strong results at Forrest Kerr with strong water flows and operational efficiencies resulting in Q3 2016 being our highest generation quarter to-date.

We also made excellent progress on the execution of our northeast BC growth strategy. In July, we successfully started up our Townsend Facility and associated infrastructure, the gas gathering lines, the liquids egress lines and the Alaska highway truck terminal. Combined, these all came in ahead of schedule and approximately 40 million under our original budget. Painted Pony has been steadily ramping up volumes throughout the quarter and the Townsend Facility is currently processing approximately 115 Mmcf per day. We anticipate volumes at the facility will continue to increase through the remainder of the year.

This morning, we announced a positive FID on our North Pine NGL separation facility. We will construct the facility with two liquid separation trains, each capable of processing up to 10,000 barrels per day of propane plus NGL mix for a total of 20,000 barrels per day. The first train will also include approximately 6,000 barrels per day of condensate terminalling capacity and will ultimate reach capacity for up to 20,000 barrels per day.

Site preparation and civil design work for the first NGL separation train is expected to begin in Q1 2017 with an expected on-stream date of Q2 2018. The total cost of the first train in NGL supply pipelines is expected to be approximately 125 million to 135 million. This investment will be backstopped by long-term supply agreements with Painted Pony for a portion of the total capacity, and will include dedication of all Painted Pony’s NGL produced at the Townsend and Blair Creek facilities.

The second 10,000 barrel per day NGL separation train is expected to follow shortly after completion of the first train. North Pine will be connected to rail and can connect directly to our proposed Ridley Island Propane Export Terminal. Just two days ago, we received NEB approval to export up to 1.3 million tons a year of propane and now we are just waiting on regulatory approval, which we expect this quarter.

We continue to work closely with the First Nations, the port of Prince Rupert and federal regulators to achieve FID by the end of the year. Through the combination of our North Pine Facility and RTI, we can offer services throughout the full energy value chain and can offer superb and preferential access to existing and new markets for producers that use our value chain.

As we have previously mentioned, we also see significant potential for expansion of our proposed capabilities in northeast BC and we are very advanced on Townsend Phase 2. Townsend Phase 2 will be a standalone 100 Mmcf per day shallow-cut gas processing facility on existing Townsend site and will also provide additional liquids to our North Pine Facility. The regulatory application for Townsend 2 also includes a plan to modify our existing Townsend Facility to enhance liquids recovery.

We expect to receive approvals on Townsend 2 by Q2 next year and to bring the unit online by the end of 2017. With our major modern gas processing facilities in this area, we have significant competitive advantages to offer further capacity for producers in the region and we maintain our views of potentially achieving one Bcf of processing capacity in the region.

In California, we continue to execute on our strategy and work on all potential options for re-contracting, optimization and expansion of our sites. The California and desert southwest markets are very fluid but provide excellent opportunities for those who stay ahead of the curve and have strategically placed assets.

Our recently announced 10-year agreement with Southern California Edison to build and operate the Pomona Energy Storage project is a clear example of this. This is a significant battery storage project, the largest of its kind to-date and we expect to have it in service by year-end. We have a long-term service agreement which enables us to spend minimal capital dollars over the 10-year energy storage agreement and at the end of the 10-year term be left with the full 20 megawatts or 80 megawatt hours of energy storage.

All of our power sites in California have the capability to host battery storage and we anticipate that these opportunities will increase in the future. In fact, we expect storage RFOs to be issued by both Southern California Edison and PG&E in December. Our development of the Pomona Energy Storage project provides us with unique insights on the development and construction of these type of projects.

To reliably manage the grid, the California ISO needs flexible resources with the right operational characteristics including the ability to start and stop multiple times per day in the right geographical locations. These needs will be met by a combination of technology types, including gas-fired generation, energy storage and solar. Our California sites can also meet these wide variety of energy products. 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 the payment for all ancillary services from gas plants, which will also provide revenue opportunities. We know that stealing the ground have significant value to the market and our diversification and ability to offer different products, like firming through a combination of solar, energy storage and gas-fired generation provide us with strong advantages in the market. Some of our sites also have different transmission options and we are actively working to determine the best transmission avenue for our generation output.

To summarize, we continue to maintain an excellent track record as it relates to execution. Our construction capabilities are top tier and we are certainly able to deliver the projects on time and below budget, providing producers with the lowest cost options 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.

On top of this, our third quarter results keep us on track to deliver on our guidance of approximately 20% growth in normalized EBITDA and approximately 15% growth in normalized funds from operations over 2015.

Let me now turn the call over to Tim.

Tim Watson

Thank you, David. Good morning, everyone. As David mentioned, normalized EBITDA was up 41% in the third quarter of 2016 to 176 million compared to 125 million in the same quarter of 2015. Across our three business lines, power EBITDA was up 77% in the third quarter of 2016 at 104 million versus 59 million last year. Power represents 58% of AltaGas’ total normalized EBITDA in the quarter.

The acquisition of the San Joaquin power assets in California was a significant contributing factor adding approximately $25 million in normalized EBITDA. Our northwest British Columbia Hydro Facilities also exhibited strong performance as a result of the startup of McLymont in the fourth quarter of 2015 and strong performance at Forrest Kerr. To put that in perspective, Forrest Kerr hit its highest generation level to-date which were up 18% compared to the third quarter of 2015.

Normalized EBITDA at regulated gas distribution utilities was 33 million, up moderately compared to the third quarter of 2015. A stronger U.S. dollar, favorable services revenue and rate base and customer growth across all five utilities were beneficial in this quarter. These positive variances were partially offset by the customer retention program which was approved at Heritage Gas, warmer weather at a number of our utilities as well as certain higher costs at the U.S. utilities.

Finally, EBITDA from the gas midstream assets, excluding Petrogas, was $40 million which represents an 8% increase over third quarter of 2015. Gas accounted for 24% of total normalized AltaGas EBITDA in Q3. Key positive drivers included the start of commercial operations at Townsend, higher volumes at the extraction facilities, primarily the Harmattan and Younger facilities, and lower operating expenses.

Offsetting this were lower realized frac spreads as a result of lower hedging gains, lower fuel gathering and processing volumes primarily due to the sale of the Tidewater assets in the first quarter of 2016, which represented about 120 million a day in the prior year’s quarter. And finally lower incremental fee-for-service revenues at the Gordondale facility due to lower volumes delivered in excess of take-or-pay levels. So what I’m saying is, we were delivering in excess of take-or-pay but the volumes were just a little lower in the past quarter.

Following a strong first half of the year, Petrogas earnings decreased in the quarter as compared to the third quarter last year due to weaker netbacks in July and August on export shipments from Ferndale, and lower results is wellsite fluids and fuels business, driven by reduced activity in the upstream sector. This was, however, partially offset by dividend income earned from the preferred share investment.

For the third quarter of 2016, AltaGas reported normalized funds from operations of $137 million or $0.84 per share compared to $102 million or $0.75 per share in the third quarter of 2015. This represents a 34% increase in funds from operations year-over-year. Normalized FFO was up as a result of stronger results in the power segment combined with higher common share dividends from Petrogas, partially offset by higher current income tax and interest expense.

In the third quarter, we received $6 million in common share dividends and 3 million in preferred share dividends from Petrogas, which was in line with our expectations. Year-to-date, we have received 18 million in common share dividends and 3 million in preferred share dividends from Petrogas compared to only 11 million common share dividends throughout all of 2015. We expect to receive an additional 6 million in Petrogas common share dividends and 3 million in preferred share dividends in the fourth quarter of this year.

Normalized net income for the third quarter of 2016 was $38 million or $0.23 per share compared to $19 million or $0.14 per share in the third quarter of 2015. Normalized net income was higher due to the same factors impacting normalized EBITDA I mentioned previously, partially offset by higher depreciation, amortization, interest expense and preferred share dividends.

Normalizing adjustments in the third quarter of 2016 relate primarily to unrealized gains on risk management contracts and long-term investments and recovery of development costs for the PNG Pipeline Looping Project. On a U.S. GAAP basis, net income applicable to common shares for the third quarter of 2016 was $46 million or $0.28 per share. This compares to $20 million or $0.15 per share for the third quarter of 2015.

For the third quarter of 2016, interest expense was $39 million compared to $31 million for the same quarter in 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 67 million in the third quarter of 2016 compared to 53 million in the third quarter of 2015, again mainly due to the acquisition of the San Joaquin Facilities and new assets placed into service. For the third quarter of 2016, income tax expense was 17 million compared to 5 million in the third quarter of '15. The increase was mainly due to higher taxable earnings in the quarter, including higher taxable earnings from U.S. operations which bear higher corporate income tax rates.

On a full year basis, we expect the effective tax rate at AltaGas to be in the 20% to 25% range. Net invested capital in the third quarter of '16 was 108 million compared to 180 million in third quarter 2015. Investment in property, plant and equipment decreased as we completed construction of the Townsend Facility and related infrastructure early in the third quarter.

AltaGas' balance sheet is in a strong position and fully funded for 2016. At the end of the third quarter of 2016, debt to total capital was 45% down from 48% at the end of the third quarter of 2015. This remains well below our bank and term note covenant levels of 65% to 70%. We have approximately 1.3 billion available on existing credit facilities. We also have strong access to capital markets as evidence by almost $800 million raised in debt and equity in 2016 year-to-date.

New projects such as Townsend Phases 1 and 2, North Pine, Pomona Energy Storage [ph] and ultimately Ridley Island as well as acquisitions such as the San Joaquin power assets have been and will continue to be appropriately capitalized. In doing so, new assets like these will further strengthen the balance sheet in an accretive way from a credit perspective. The strength and stability of our funds from operations is what drives our business and provides strong security in our dividend.

AltaGas is one of the lowest dividend payout ratios based on cash flow and its peer group. To put this in perspective, even with the recent increase in our annual dividend to $2.10 per share, cash flow from our regulated utilities combined with our Northwest Hydro Projects alone more than covers total cash dividends paid after factoring in a dividend reinvestment plan. This means that cash flow from all our other assets within AltaGas can be directed to other investment opportunities.

Okay, turning quickly to 2016, I say it’s largely consistent with what we discussed last quarter but I’ll give you a few highlights. The power assets are expected to contribute the majority of the 20% growth in total normalized AltaGas EBITDA year-over-year; approximately 41% of AltaGas’ total 2016 expected normalized EBITDA will come from power driven mainly by our full year contribution from the San Joaquin power assets and McLymont Hydro Facility as well as significantly higher production of Forrest Kerr.

Following the seasonally stronger quarter in Q3 at the Northwest Hydro Facilities, we are seeing the expected decline in the seasonal water flow patterns for Q4. Actual seasonal water flows vary with regional temperatures and precipitation levels. To-date in the fourth quarter, precipitation in the region has been unseasonably low; however, this is fully accounted for in our full year outlook.

Regulated gas distribution utilities are expected to see a moderate increase in normalized EBITDA compared to 2015 on a full year basis, notwithstanding warmer weather experienced at four out of the five North American utility franchises that we have. 37% of our total 2016 normalized EBITDA is expected to come from the utility division. Growth in utilities is driven by rate base and customer growth, including at SEMCO gas which will benefit from a full year contribution of its mainline replacement program or MRP.

SEMCO [ph] is also expected to earn higher storage revenues in 2016. And in June 2016, ENSTAR filed its 2016 rate case requesting an interim and refundable annual rate increase of approximately $5 million on an annualized basis effective August of this year with final rates to be set in Q3 2017. And further to this point, on July 18, the Alaska Public Utilities Commission did approve the interim refundable rates. These increases will be partially offset by the recent approval of the customer retention program at Heritage Gas which is anticipated to decrease annual EBITDA by $3 million.

Earnings at all the utilities, except PNG, are affected by weather in their franchise areas with colder weather generally benefiting earnings. Approximately three quarters of AltaGas utility customers are in the U.S. and the U.S.-based utilities have benefited from a favorable U.S. dollar exchange rate.

Finally, gas midstream is expected to account for approximately 22% of AltaGas’ 2016 total normalized EBITDA. Compared to 2015, the gas segment is expected to see a small decline in normalized EBITDA. Positive drivers in 2016 include the addition of Townsend which is expected to add approximately $20 million of EBITDA this year as volumes from Painted Pony progressively increase through year-end.

In addition, the absence of turnarounds at Harmattan and Younger as well as higher total contributions from Petrogas are positive contributing factors. These year-over-year gains, however, are more than offset by lower contributions from commodity prices as a result of higher hedging gains that we achieved in 2015, the sale of the Tidewater gas assets earlier this year and moderately lower volumes at Gordondale and our non-core gas facilities as mentioned previously.

Approximately two-thirds of 2016 gas EBITDA is underpinned by take-or-pay in cost of service contracts with no direct price or volume exposure. We've had no material impacts on midstream counterparty exposure year-to-date which continues the positive experience from last year. We continue to expect full year volumes at Gordondale to average approximately 90 million to 100 million a day.

Birchcliff’s announced development plans include drawing an additional six wells in 2016 in the Gordondale area with the potential for increased activity in the area in 2017. Gordondale will be the most efficient deep-cut facility within 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 this cumulative production in and around 2020, but that of course is subject to their planned rate of area development.

We value the relationship that we have with Birchcliff and we believe 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 as mentioned. Therefore, we reduced the amount of liquids we've been re-injecting. Recall that AltaGas produces just over 60,000 a day of gas liquids and I'm talking ethane, propane, butane and condensate but only up to a maximum of about 10,000 a day or one-sixth of that total can be contractually exposed to frac spread pricing.

Based on current forecasted prices, we expect to increase the amount of extraction volumes exposed to frac spreads to about 7,500 barrels per day for the fourth quarter of 2016. 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.

For the remainder of the year, we have hedges in place with volumes ranging from 1,700 to 3,900 barrels a day at an average price of approximately $21 per barrel, excluding basis differentials. Note that every plus or minus $1 per barrel change in the frac spread results in approximately 1 million charge to our 2016 EBITDA.

Turning to capital expenditures, we now expect to spend between 550 million and 600 million this year. This is within the original range for capital expenditures that we communicated at the outset of the year, but on the lower end due to capital efficiencies realized.

Up to the end of Q3 2016, we have approximately 400 million of capital expenditures incurred. Excluding the $40 million to $45 million of Pomona Energy Storage project outlays, the remaining 2016 growth capital expenditures are discretionary and AltaGas has the flexibility to adjust the pace of spending at its option. Maintenance capital for the gas and power businesses in 2016 is now expected to be approximately 25 million with 12 million spent so far this year.

In 2017, our initial expectations are for approximately 600 million of total capital. However, I would emphasize that our final 2017 capital budget will not be finalized until later this year. We expect approximately 290 million for depreciation, amortization and accretion expense for 2016. The corporation also continues to focus on enhancing productivity and streamlining businesses, including the disposition of smaller non-core assets.

Approximately 50% of our total expected 2016 EBITDA for AltaGas will come from the U.S. and reflects our diversified business platform across three major energy infrastructure business lines. For every plus or minus $0.05 change in the Canadian U.S. FX rate, the annual impact to our 2016 EBITDA is about $14 million.

In summary, we’ve just completed an exceptionally strong third quarter and we do remain on track to deliver approximately 20% growth in normalized EBITDA and approximately 15% growth in normalized funds from operations for 2016.

Looking a little further out at 2017, we expect moderate growth absent any acquisitions. And I do want to put this in context. In the years leading up to 2016, AltaGas grew in the mid-to high single digit range absent acquisitions and we would expect a similar performance to that in 2017.

We expect the gas segment to experience solid growth, driven by a full year at Townsend representing approximately 20 million to 30 million in year-over-year EBITDA growth combined with moderate strengthening of frac spreads, higher Gordondale volumes, newly realized liquids blending revenues and a partial year impact from Townsend 2, as Dave described earlier, partially offset by the sale of the ethylene delivery systems and the Joffre Feedstock Pipeline to NOVA which has an approximate 10 million EBITDA impact, as well as normally scheduled turnarounds for both [indiscernible] and Gordondale which has a $7 million EBITDA impact.

Power is expected to be up moderately, driven in part by full year from the Pomona Energy Storage project while regulated gas distribution utilities are expected to be up moderately and should benefit if weather return to a more normalized state relative to last winter. A full year of cost savings from the recently completed restructuring and from other efficiency initiatives should also be reflected in 2017.

To recap, 2016 is shaping up as a record year for AltaGas. Looking into '17, we see further growth as well as some exciting new projects starting to take shape. And all of this will continue to be supplemented with an attractive well-funded dividend which is currently yielding in excess of 6%.

So with that, I’ll turn it back to Jess.

Jess Nieukerk

Thank you, Tim. Operator, we’ll now open it up for question-and-answer to the analyst community.

Question-and-Answer Session

Operator

Thank you. We will now take questions from the telephone lines. [Operator Instructions]. The first question is from Linda Ezergailis from TD Securities. Please go ahead.

Linda Ezergailis

Thank you. Congratulations on a strong quarter. I have a question with respect to your North Pine Facility. Can you give us a sense of what percent of the first train of contract and then what duration, and if this kind of base capacity is providing adequate returns for the company? And what those returns might be and how quickly it might fill up?

David Harris

Sure. This is David Harris. We’re fairly well contracted with this asset right now just with the liquids that come off from the existing Townsend Facility, the two trains that we have. Townsend 2 is tracking very, very well as expected and expect that online by the tail end of next year. That pretty much puts us all the way there with maybe 1,000 or 1,500 barrels that we’ll chase over the next year, which we're in conversation on and have clear line of sight to. So we expect the first 10,000 train to fill up quite nicely. And on an expected return basis would be in the high-single digits to low teens on an expected return.

Linda Ezergailis

Okay, that’s helpful. And just – so for your second train for North Pine, have you not yet achieved a positive FID? And what conditions might be required to achieve that, and what’s your timing do you think on that?

David Harris

We expect just of the pace and the increased interest with respect to what we’re doing in northeast BC that we expect that to follow right behind the heels of train one when it’s completed. We’re very confident on the ability to fill that train as well. We’re just sequencing it with respect to just how we’re spending the capital and how the barrels are coming into be contracted, underpin the assets.

Tim Watson

I might just say one quick comment, Dave. I think with that second train, it will be more efficient from a capital perspective simply because we put iron in the ground for the first one. So the dollar outlay will be less and that will mean the returns are better even than the first phase. So we’re clearly motivated to move forward now as quickly as we can.

Linda Ezergailis

That’s helpful, Tim. And what is the CapEx for the second train?

Tim Watson

It’d be around 50 million.

Linda Ezergailis

50 million, okay. Thank you. And just to be clear on Townsend Phase 2, are all the commercial commitments firmed up and what are the gating factors to get to proceeding next year? Is it just regulatory approvals that you’re waiting for?

David Harris

We’re fairly well along. We're within a three-fourth part of having all the commercial terms squared away on Townsend 2 and it really comes down to the regulatory approval process we’re expecting at the front side of Q2 of next year.

Linda Ezergailis

Okay, that’s helpful. And is it Painted Pony or are there other parties that you’re talking to?

David Harris

We’ll leave it at that. We just really don’t want to talk about who at this point.

Linda Ezergailis

Okay, thank you. I’ll jump back in the queue.

Operator

Thank you. The following question is from Robert Hope from Scotiabank. Please go ahead.

Robert Hope

Yes, thank you for taking my question. Just maybe a follow-up question on the North Pine Facility. Just in terms of the contractual underpinning of that asset, will you be taking any commodity exposure on the outlet of that facility, or will it largely be a fee-for-service asset?

David Harris

It’s a fee-for-service. To be clear, it’s an integral part of our value chain. As you know, it’s approximate to Townsend truck terminal. It’s on the railroad leading to the West Coast Ridley Island project. It can also go East from there as well. So a lot of functionality or marketability, I guess, that we’re offering selected producers who are going to be – who have committed to the volumes to move us forward on North Pine.

Robert Hope

All right, that’s helpful. And then just moving over to Gordondale, it looks like the volumes are still in excess of take-or-pay, but maybe not where they were in prior quarters. Just want to know if you can update us on any conversation you’re having with Birchcliff just regarding reworking the contractor or what it could look like after its initial term?

David Harris

We certainly talk to Birchcliff but I would just say it’s premature to say anything at this point. We’ll follow when we get into the beginning of the year.

Robert Hope

All right, that’s it for me. Thank you.

Operator

Thank you. The next question is from David Galison from Canaccord Genuity. Please go ahead.

David Galison

Hi. Good morning, everyone. I just wanted to follow up maybe on the Gordondale facility. So you had mentioned that you’re looking to divest some assets that were non-core. Could Gordondale actually be part of that discussion as well? Is there any color you can add around that?

David Harris

No. I made that comment because as you’re aware, we did do an encore disposition in Q1 of this year to Tidewater. If there was an opportunity that presented itself for other small non-core, clearly more legacy type and I would say smaller types of assets, we’d be open to that. But we wouldn’t put Gordondale in that category. Gordondale is almost a brand-new – it’s not brand new but it’s of recent vintage. As I said earlier, it’s the most efficient plant in that area. That area is prospective. We're actually encouraged by what Birchcliff signaling here, because that was a very important transaction to Birchcliff and we're confident they’re going to be active in that area for the next decade. So I think it will come down to just ultimately working with them commercially and growing with them.

David Galison

Okay. And then just to touch on North Pine. You had mentioned that you’re expecting the returns to be in the high-single digit to low-double digit. So when the first train ramps up in Q2, would you expect that to be a slower ramp? I guess my question would relate on how long do you think it will take to get to those types of returns? Would you see that within 2018, or would you need to have everything --?

Tim Watson

Yes. To be clear, and I think I’ll just echo Dave's comments on that range of returns which is what our standard range is for these types of infrastructure projects, we fully expect that's the range we will be looking at for that first train itself in 2018. So the first train stands by itself and meets our returns and our thresholds.

David Galison

Since the second train is going to be more capital efficient, what type of returns would you expect on that? Higher than the range you've given, or pretty much the same range?

Tim Watson

I think it would be higher, because if you’re talking simply on an incremental basis which that rounded number 50 million would be, it will be higher. But it is part of the same site. So ultimately when all the dust settles and we bring the second train on shortly thereafter, we’ll be looking at that whole North Pine Facility on a combined basis. That's the way we’ll be thinking about it.

David Galison

Okay. And just one maintenance question. You had mentioned – was 600 million that you said was the CapEx target for 2017?

Tim Watson

Yes, in round numbers. And again, just to caveat that that is not a final Board approved, management approved number yet. We're just trying to give you some general guidance.

David Galison

And then would you be able to give a rough percentage contribution from each segment in 2017? Is it roughly the same as we're seeing in 2016, or will it move around a bit in 2017?

Tim Watson

You're just talking like let’s say of the total EBITDA, which we haven't given for '17, you're just asking what the contribution from each of our business lines would be?

David Galison

Yes, like 40% will be from power, 20% from gas, like that mix or --?

Tim Watson

It’s going to be roughly that. Gas will be up just maybe a little bit, because of course we’re going to have a full year from Townsend which is meaningful, as I said, 20 million to 30 million of incremental cash flow next year versus this year. So that alone will move things a little bit. But I think the split that we’ve shown you for 2016 is going to be not to dissimilar in '17.

David Galison

Okay. Thank you very much.

Operator

Thank you. The next question is from Robert Catellier from CIBC World Markets. Please go ahead.

Robert Catellier

Hi, good morning. Thanks for the updates. I wondered if you could talk a little bit more about Ridley Island. So other than the regulatory approval, what else has to be accomplished to achieve FID? Maybe you can specifically comment on the status of the First Nations discussions and how you might achieve incremental off-take agreements if any are required in light of the weaker netbacks that you referenced at Ferndale in the MD&A?

David Harris

Sure, Robert. This is David Harris. I’ll start and others can chime in. First, with the First Nations, the First Nations consultation is going exceptionally well. We finished the public comment period both with the general public and First Nations. There was really no material comments whatsoever and there’s a lot of positive momentum behind the project in the area. So we’re looking to move pretty quickly with impacts and benefit agreements with the key First Nations. Dialogue with the government, Prince Rupert Port Authority are going exceptionally well. Once we finish pretty much with the First Nations, there’s really no hurdles left with our environmental permit at that point. So we’re anticipating receiving that by the end of the year. Just on the commercial side, conversations are going quite well. We're well into conversations with a number of parties and we’re seeing the commercial underpinning of this coming together quite nicely that will support – what we’re planning to do is an FID by the end of the year. That’s about as deep as I want to go on the commercial discussions at this point with the project.

Robert Catellier

Okay. And so you don't think current market conditions and weaker netbacks at Ferndale have any relevance here to the long-term outlook for Ridley Island?

David Harris

No, not really. It's certainly a data point and you never want to not pay attention to a data point. But the data point is not stagnant, right. It doesn't stay still. So that will move all the time. And as we have seen in our discussions with producers that they’re certainly thirsting for market optionality and Egress and Inuvik in this project certainly provides that in space.

Tim Watson

I would just say, like you put yourself in the shoes of the producer sitting at Edmonton and you look at what they’re alternatives are and they can go South and through the Panama Canal, or they can go off the West Coast. And if you run the numbers, we’re happy to share those. I think some of those are on our investor slides anyhow. It’s a superior proposition for producers and that holds today, Robert, with FEI Index [ph] at $0.72 and Bellevue at $0.58 and Edmonton at $0.35 per gallon. So it works today. It worked six months ago and we’d like the trend going forward there.

Robert Catellier

Yes. And just on the power side, can you detail the improved performance capability of Forrest Kerr, sort of the year-over-year impact that had and the sustainability there?

John O’Brien

This is John O’Brien, Robert. I think that what we’ve done this year is from an operational perspective things like the desander and other equipment like that, the seals have all been updated and improved. So operationally we have continued through another full year of operation to really make those improvements and gain a better knowledge as a staff. So, as an example, operationally, as a staff when we look to do maintenance and so forth, we're optimizing the times within which we do that and have to bring a unit down. So I think both from a staff commercial education standpoint, and then operationally from the equipment and technology that we’re putting up there, those are the operational improvements that we’re inputting and we’re also I would say very proud of our team up there, because they’re really gaining knowledge of the river and how the units run along with the equipment updates we’ve made. So I think those two things will continue year-in and year-out as we understand the river more. But operationally, the equipment we put in is making the hydro facility that much better from a performance standpoint.

Robert Catellier

So it sounds like you’d characterize these as normal operating gains that you can sustain?

John O’Brien

Absolutely. Yes, as we learn about how to deal with the sand and the stuff that gets trapped, trash rakes, all of those things are updated and are sustainable.

David Harris

Robert, our price didn’t really change year-over-year for that quarter. It’s wasn’t a price-driven thing, it was really a productivity factor increase.

Robert Catellier

Okay. And then I hate to mention this, because you had such a good quarter in power, but can you update the PPA process and is there any way to quantify what costs and balancing pool may have incurred on the Sundance B PPA since they were returned?

John Lowe

It’s John Lowe. The numbers that the balancing pool may have incurred bounce around from 2 billion originally mentioned I believe the Alberta government, and then I think Andrew Leach came out with a study which put the number more in the $900 million to $650 million range.

Robert Catellier

Right. But what’s the exposure on the Sundance B PPA? Would it be capacity proportionate?

John Lowe

For Sundance, yes, I think roughly it – they all vary and there is an article by Dr. Leach, it’s power play of the PPAs and he does break out the values of the different PPAs. If you’re trying to back in the Sundance PPA, it would be I think in the call it $100 million range.

Tim Watson

I guess just one quick thing though. You’ll see Robert in our MD&A in one of the footnotes, I don't have it in front of me, there is a disclosure that we’ve given you for our liability exposure as at the end of Q3.

Robert Catellier

Okay.

Tim Watson

It’s not material to our company. There’s also other disclosure further up at the start of the MD&A on this issue.

Robert Catellier

Right. Then can you just – like understanding it’s for the courts and there’s sensitivities associated with that in the arbitration, but how would you characterize how the process is evolving?

John Lowe

It’s John Lowe. I think the government chose to have the matter determined by the courts. The case is being court managed by the Chief Justice and there is a process set out. At the same time, there's an arbitration dispute resolution mechanism in the PPAs and that’s long-standing and well understood. And we've engaged that mechanism as well. So this will be resolved by the courts. Again, I think these are long-standing instruments and they will be determined in accordance with their terms.

Robert Catellier

Okay. Thanks for answering my questions.

Operator

Thank you. The following question is from Robert Kwan from RBC Capital Markets. Please go ahead.

Robert Kwan

Good morning. If I can just come back to North Pine and I think your previous disclosure had the EBITDA multiple eight to nine times, and I’m just kind of wondering is that still a good range? And then as you think about – I think that was for both phases. So would you be at the high end or even maybe even a little bit higher than the high end of the range for Phase 1? And then, Tim, as you had mentioned, you have a pretty attractive capital efficiencies for Phase 2 and now what would drive you back into that range?

Tim Watson

Yes, I think that’s directionally right, Robert. I don't have all my numbers right in front of me for that project. But that’s directionally I think the way to think about it. And that slide won’t change as a result of this announcement today.

Robert Kwan

Got it. And then just on the contract and the long-term supply agreements, there's a comment there around dedication and not necessarily something around take-or-pay. But that being said, is it really kind of a situation where you’ve got the take-or-pay at facilities like Townsend, and if it's dedicated out of that, that’s kind of where you get comfortable around, you’ve got an upstream take-or-pay commitment to feed North Pine?

Tim Watson

Townsend will be physically connected right in there by pipeline and so that clearly is one of the inputs to the supply at North Pine, as David said, Townsend 2 beginning Q4 next year. But we’ll also source supply from the Birchcliff area which is multiple producers not just Painted Pony. And that’s under commitment here as well.

Robert Kwan

Got it. But specifically, the North Pine contract is not take-or-pay?

Tim Watson

It’s a dedicated contract based on the available liquids. The take-or-pay exist at Townsend, so the take-or-pay liquids are coming out of Townsend flowing on our Egress lines to the truck terminal and there’s nowhere to go but from the truck terminal down to North Pine.

Robert Kwan

Okay. And if I can just finish the question on California, specifically Pomona. When you look at the EBITDA that you guys are forecasting current i.e. post-contract expiration but with the upside on the storage project, how does that compare to the EBITDA prior to the contract expiration? And if you want to talk dollars, that’s great, but if it’s possible even just talk about the percentage change.

Tim Watson

On the contract, you mean the battery contract that we’re engaged in now and then when that contract ends?

Robert Kwan

Well, I guess more so like if you look at the EBITDA from Pomona for 2015 while you were still under contract at SCE and then you look at what your forecast is with it just being open but pro forma, the upside from the battery contract. How does, call it the EBITDA for low cost I think maybe 2017, because the battery contract to be done then. What would be in your plan for '17 versus what was the EBITDA profile in 2015?

David Harris

Yes, Robert, this is David Harris, I’ll answer that. It may be slightly below but not material. And then as we get into actually running Pomona and see if there’s other ancillary services capability after that, we could see a path of maintaining neutrality compared to what we lost from the original PPA falling off.

Robert Kwan

Okay, that’s great. Thank you very much.

David Harris

But look at it as a ballpark for all practical purposes.

Tim Watson

Robert, I just want to come back to your original question on North Pine. So I was just going through some numbers while we were answering your other questions. So our number in North Pine we communicated is eight to nine times capital to EBITDA and it will be the low end of that range on Phase 1.

Robert Kwan

You’ll be at the low end of the range. So when you say low, you mean closer to the eight?

Tim Watson

Yes.

Robert Kwan

So put differently, because I think the capital spend numbers that you have on that slide are for both phases and a Phase 2 is going to be even more capital efficient assuming you don’t cut the fee proportionately. North Pine, as it’s set up right now, is likely going to be much lower than that range?

Tim Watson

It could be seven to eight, yes. We’re commenting on Phase 2 specifically because obviously there’s a couple of inputs that have to get finalized there over the next 12 months or so. But certainly on Phase 1, Phase 1 as I said at the outset stands by itself and even better, it’s at the lower end of that range.

Robert Kwan

Okay, that’s great. Thank you.

Operator

Thank you. The next question is from Ben Pham from BMO Capital Markets. Please go ahead.

Ben Pham

Thanks. Good morning. I had a question on your commentary about 2017 in terms of the expectation for growth there and I was wondering if you can clarify the magnitude of your frac spread expectation into '17, and any sort of gas volume increases? And then also can you also comment on also your per share metrics into '17? It looks like if you’re hitting the 600 million in CapEx, can you find out what the growth in that program you have?

David Harris

We’re not in a position yet as we’re sitting here in October to give you firm guidance yet. We have to complete our '17 capital budget and run it by our Board and have them approve it. So, our guidance is going to be therefore by definition less than it will be in a couple months or so. Frac spreads, we’re encouraged by what we’ve seen here in the past several months. They have trended up. As we said, we’ve increased our frac exposure volumes because we like what we’re seeing on the spread side. We’ve also hit some hedges because we like the market, so we’re taking – putting some hedges in place at these types of levels. I think you look at where the market is next year on a commodity price basis, it’s not backward dated on recent liquid, it’s still contengo meaning that people are seeing not a massive jump but a reasonable increase into '17 on liquid prices. And at the NGL prices, there’s correlation there. And on the gas side, ideally we see a spread between the liquids and gas prices. Gas prices are actually in backwardation as you get into the next year or two. So, we think it’s going to be – it’s not going to be a massive increase in frac spreads. But the way we think about it, there’s reasonable prospect of a moderate increase there. That’s all we’re saying. We’re not counting on it. We’re just saying that that’s where it looks like it’s trending. Can’t remember what else? On volumes for TMP, again, nothing dramatic; Townsend full year benefit, right. Gordondale will be a pretty stable in that probably – it could be a little bit higher than that depending on how active Birchcliff is. I think that’s sort of the direction of how we’re thinking about that.

Ben Pham

And Tim, maybe your thoughts on your balance sheet heading into 2017 with the equity offering that you did early this year, and looking at that that will pick up next year and the drill program [ph] and enhancements on that?

Tim Watson

I think we’re very happy with the balance sheet. We’ve made great strides this year. In particular, we made strong strides on the FFO to debt and that will continue through year end, and we actually see that continuing and move up next year as well. So that’s an important criteria. We’ve got lots of liquidity, lots of flexibility, we’re well below all our covenants, as I said earlier. The balance sheet is there to support the growth that we see in our business lines and we’ve got some exciting projects which we’re moving forward now with into '17. And like I said, we’re capitalizing appropriately because at the end of the day, we think these new projects which as we bring them on are going to be credit friendly, meaning that we’re going to improve ratios as these projects are executed efficiently and bring cash flow.

Ben Pham

Okay. And a question on the gas segments and going back to North Pine and maybe include the deep basin project in there, is the additional volumes that you need for commerciality on the second train in deep basin, is that contingent in anyway in the LPG export project to occur or you’d think about moving producers, maybe the volumes piece and then solve?

Tim Watson

North Pine Phase 1 will be on as we said in second quarter 2018 and Dave emphasized earlier, we can bring the second train in North Pine very quickly thereafter, which means that might be slightly ahead or just coincident with Ridley coming on. So I think they’re not directly related but clearly as we build further momentum at Ridley, producers are going to – they can’t help but notice that these are for real.

David Harris

It’s certainly complementary.

Ben Pham

Okay. And my last question switching to power and the commentary about the expected RFPs into next year, what are we looking here for? It looks like the RFP process has been pushed a little bit. It is resource plans that need to be filed by the utilities, is it regulatory policy at the federal level, what should we be looking for?

John O’Brien

It’s John O’Brien, again. I think that it’s state by state in many ways. So if you look at – yes, it’s resource planning. So if you at California and you look at both the interaction of the ISO and the PUC there with the IOUs and the POUs, it’s looking forward to both how they meet their renewable/storage commitments that they’re under as well as what gas needs will be in the future. And similarly, if you look at states like Arizona in that West area where we do look to Dave’s comment about transmission and where we sit in CAISO but also with transmission ability possible into WAPA. So you’re looking at both of those systems. So you are looking at how the states are going about planning and the utilities are going about looking at their resource needs into the next years and into 2020 and beyond. So it is a state by state review as to where resources are going to be needed and what reserves are going to be desired by both the PUC and the companies.

Ben Pham

Okay, great. Thanks for taking my questions.

Operator

Thank you. [Operator Instructions]. The following question is from Patrick Kenny from National Bank Financial. Please go ahead.

Patrick Kenny

Good morning. Just on Ferndale, did the weaker propane netbacks have an impact on volumes in the quarter? And then maybe if we can get an update on current volumes at the terminal as well as any expansion opportunities you might be looking at either onsite or nearby? Thanks.

Tim Watson

I would say in terms of the volumes, the volumes were a positive. So we had higher volumes going through Ferndale in Q3 versus Q3 last year and we’ll have materially higher volumes for the full year this year versus last year. So, to rephrase your question, the margins were squeezed in part of Q3 but the volumes were an offset to that to some extent.

David Harris

Sorry, Patrick, this is Dave Harris on expansion at the terminal, no different than any facility. We always look at opportunities based off of market conditions to see if you can turn around and get more out. And recently [indiscernible] position and the Wharf is certainly signs of expansion.

Patrick Kenny

Okay, perfect. Thanks, David. And then switching to California for the energy storage opportunity at Blythe and San Joaquin plants, maybe for John, can you talk about the potential scale of those projects? Obviously, 20 megawatts is significant for Pomona but relatively small percentage of the capacity at your larger plants. So do you see the technology around battery storage advancing quickly enough to become meaningful for your larger plants?

John O’Brien

That’s a very good question. I think that first if you look at possible RFOs that are going to be out, I believe SCE in total is going to be looking for about 120 megawatts of storage in this next RFO. So on the one hand, it’s not of a magnitude of a 500 megawatt plant. So in that regard, you’re looking at smaller sizes, that’s for sure. So when we think about this, there is an opportunity to combine a conventional plant renewable for storage resource for what – for instance publicly-owned utilities are looking at. Publicly-owned utilities are looking for something they have a renewable with a firming component that comes with gas. So that could be storage with a firming component of gas. So it won’t be of a big magnitude, the battery piece but it can be in combination with your plant to achieve a larger scale. So I think what we do is we would look at in particular our peaking facilities, like our Pomona facility where you have the ability and the land to deal with 20 megawatts or larger. So while that’s not a huge amount, that is a way to optimize our peaking facility. And then as you look at our larger facilities and our larger opportunities, you’re looking I think at combinations so that you show the innovation that the utilities are needing from a California policy standpoint. So I think when you look at our larger facilities, it’s almost you’re looking at something that is innovative and combined with your gas plant to provide that firming capacity.

Patrick Kenny

All right, that’s great, John. Thanks. That’s all I had guys.

Operator

Thank you. There are no further questions registered at this time. I would now like to turn the meeting back over to Mr. Nieukerk.

Jess Nieukerk

Thank you, Mary. I’d like to thank everyone for joining us today on our call. As always, Ashley and myself are available for any follow-up questions you have. Thank you.

Operator

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

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