AltaGas Ltd. (OTCPK:ATGFF) Q1 2016 Results Earnings Conference Call April 21, 2016 11:00 AM ET
Jess Nieukerk - Director of Finance and Communications
David Harris - President and CEO
Tim Watson - EVP & CFO
John O'Brien - President of Altagas Services U.S.
David Galison - Canaccord Genuity
Robert Kwan - RBC Capital Markets
Linda Ezergailis - TD Securities
Ben Pham - BMO Capital Markets
Good morning, ladies and gentlemen, and welcome to the AltaGas Limited Q1 2016 Conference Call.
I'll now turn the meeting over to Mr. Jess Nieukerk, Director of Finance and Communications. Please go ahead sir.
Thank you. Good morning, everyone. Welcome to AltaGas's first 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'll 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're subject to certain risks, which could cause actual performance and financial results to vary materially from those contemplated in the forward-looking statements. For additional information on these risks, please take a look at our Annual Information Form under the heading, Risk Factors.
I'll now turn the call over to David Harris.
Thank you, Jess. Good morning, everyone. Before I get started with my formal remarks, I want to thank both David Cornhill and the Board of Directors for giving me this opportunity. David has built a legacy in AltaGas and I intend to build on his legacy.
As Chairman of the Board and Founder of AltaGas, I know David is not far away and I am truly fortunate that I continue to work closely with him. AltaGas' success has been driven by a business model of low risk, long life, clean energy infrastructure assets and midstream power and utilities.
My priority is to maintain this business model and a strong focus on financial discipline in this economic environment. We'll continue to focus on our competitive advantage including being a top Tier operator in our strong construction expertise.
We'll look to streamline G&A cost across the organization and we remain nimble and prudent in how we execute on our growth strategy. The AltaGas team has the skills to deliver customer value and shareholder value.
Normalized EBITDA for the first quarter of 2016 was $178 million, consistent with the first quarter of 2015. Normalized FFO was $132 million, compared to $140 million in the first quarter of 2015.
On a full year basis, these results keep us on track to deliver on our guidance of approximately 20% growth in normalized EBITDA and up to approximately 15% growth in normalized funds from operations.
Results are down slightly quarter-over-quarter as we still had the benefit last year, excuse me, of strong hedges in place for both frac spread and Alberta Power. As such, realized pricing for both was down in the first quarter 2016 compared to the same period in 2015. For 2016 however, only about 1% of our forecast is based on commodity prices. So this does not impact our guidance.
Looking at each of our business segments, in Power for first quarter 2016, we achieved $43 million in normalized EBITDA, a 34% increase over the same period last year. This was driven primarily from the addition of the San Joaquin assets acquired in November 2015 and a stronger U.S. dollar.
These assets more than offset the declines we saw from Alberta Power as spot prices dropped to a new record low in the quarter of approximately $18 per megawatt hour. This compares to $29 per megawatt hour in the first quarter of 2015.
As a result of the Alberta Government's change to the Specified Gas Emitters Regulation, effective March 8, we exercised our right to terminate the Sundance B PPAs. AltaGas's power portfolio and Alberta now consist of 65 megawatts of natural gas fired generation coming from our three co-generation facilities at Harmattan and a few smaller peaking units. This represents less than 4% of our total generation capacity now and is not material to AltaGas's business.
In utilities we achieved $108 million in normalized EBITDA for the first quarter of 2016 a 4% increase over the same quarter of 2015. The growth in normalized EBITDA was driven by customer and rate base growth, combined with favorable foreign exchange, offset by significantly warmer weather at all of our utilities.
Finally in our gas segment, we achieved $35 million in normalized EBITDA for the first quarter of 2016, down from $47 million in the same quarter of 2015. The lower EBITDA was driven by lower extraction volumes; lower realized frac spread, as well as lower process volumes due to the sale to Tidewater during the quarter.
Equity earnings from the Petrogas were up in the quarter at $2 million versus nil for the first quarter of 2015, driven by the expansion of Petrogas’s liquefied petroleum gas business in the U.S. as well as international markets through the Ferndale terminal.
Looking ahead to 2016, the primary drivers behind our growth in normalized EBITDA and funds from operations will be full year contributions from our newly acquired San Joaquin facilities, a full year of McLymont and a partial year from our Townsend shallow cut natural gas processing facility.
We continue to be cognizant of the headwinds facing producers in our midstream business and we're focused on operational efficiencies, including lowering cost to producers, while maintaining high availability. We continue to make significant progress on our Northeast PC strategy through which we are also working to deliver higher value to our customers.
The Townsend facility is approximately 85% complete and is on track to be in service by mid 2016. With the current environment and our in-house construction expertise we expect to bring the facility in under budget.
The 25 kilometer gas gathering line is now complete and well under budget. It is under a 20-year take-or-pay with Painted Pony. We’ve under construction two liquids egress lines and a truck terminal on the Alaska Highway. Construction of pipeline was substantially completed in the first quarter.
The liquids egress lines have initial capacity of 10,000 barrels per day each with potential expansion up to 30,000 barrels per day each. The lines have been sized to accommodate any future expansions of Townsend or in the area. We expect to finalize a 20-year take or pay agreement with Painted Pony for all liquids from the Townsend facility.
Construction activities for the truck terminal are well underway with fabrication and earthwork starting in April. The terminal is expected to be complete in the third quarter of 2016. Our liquids separation facility in our Fort St. John is also progressing.
We're calling this facility the North Pine Liquids Separation facility located 45 kilometers Northwest of Fort St. John. With North Pine, we can connect our existing infrastructure in the region to our Ridley Island propane export terminal.
We've been working closely with First Nations and other key stakeholders and on April 14, we submitted a formal application to the BC Oil and Gas Commission. We're also deep into discussions with producers for backstop agreements will underpin the facility. We expect to reach an FID later this year.
We're also in the early stages of a liquid separation facility in Northwestern region of Alberta in the deep basin. A pre FEED study will be completed in May. The facility is being designed with a capacity to process up to 10,000 barrels per day of C3 plus and handle up to 10,000 barrels per day of C5 plus.
We're in active discussions with producers and have started to engage First Nations and key stakeholders. The location is in again ideal as it can easily tie to our Northeast BC infrastructure and has real connectivity to tie to our proposed Ridley Island propane export terminal.
At Ridley we have begun the formal environmental review process, preliminary engineering has been completed and a FEED study is in progress and is expected to be completed in the second quarter of 2016. We continue to work closely with First Nations and Government and key stakeholders and expect to reach FID later this year.
We're very excited about Ridley as it begins, excuse me, as it brings together the full natural gas value chain and offering for producers in Western Canada. With a design capacity to ship approximately $1.2 million tons per annum or 40,000 barrels per day of propane, this truly can be a game changer for our industry.
Throughout the entire value chain on processing, liquid separation, storage, logistics and exports, we can offer producers, lower construction cost, lower operating cost with higher reliability and the potential for higher netbacks through new markets.
As mentioned previously we've seen a significant step-up in interest from producers for exports to Ridley. AltaGas will contract for the majority of the capacity in order to assure recovery of capital and operating cost prior to making our FID.
We’ve also been in talks with multiple potential off-takers for our Ridley Island propane export terminal. These include counterparties in Japan, Korea and China among others. Feedback and initial discussions have been positive and we would expect to have MOUs in place with multiple off-takers prior to FID.
In our Power segment, we’ve had a busy quarter. We submitted a response to an RFP for the re-contracting of our Blythe facility and submitted an application with the California Energy Commission to repower our Pomona facility. The repowering of the Pomona facility through a flexible fast ramping peaking facility positions it competitively with potential upcoming RFPs in the Los Angeles lower basin.
The repower facility would be a more efficient gas fired technology with capacity up to 100 megawatts, which is more than double the current capacity. We're starting to see increased activity in the Western U.S., which we fully expect will lead to several RFPs being issued this year and next.
We’re not solely focused on California. The strategic location of our assets allows us to serve the western power grid including States of Nevada, Arizona and New Mexico.
As we move through 2016, we expect to bid both the existing Blythe facility in for re-contracting as well as the proposed Sonoran facility into upcoming RFPs in these Western U.S. States.
As we start out 2016, we have a strong diversified base business, coupled with a healthy balance sheet. We also have a lot of exciting opportunities in front of us that we expect to come to fruition. But as always, we will be disciplined in pursuing them.
I will now pass the call over to Tim.
Thank you, David. Good morning everyone. We continue to see the strength of our diversified business platform. Normalized EBITDA in the first quarter 2016 was $178 million, similar to the first quarter of 2015. Utilities represented the largest component of that total at 58% and were up 4% over the first quarter of 2015. Power increased 34% year-over-year to represent 23% of total EBITDA and gas midstream was 19% of total Q1 EBITDA and declined year-over-year.
The acquisition of the San Joaquin facilities and the impact of the stronger U.S. dollar on our U.S. operations, contributed approximately $36 million in EBITDA growth. Significantly warmer weather at all of the utilities, lower realized frac spreads and lower Alberta power prices are what offset these gains.
We remain on track to achieve our guidance for approximately 20% growth in normalized EBITDA and up to approximately 15% growth in normalized funds from operations for the year. To emphasize, we are not counting on a material near-term increase in commodity prices to deliver this growth.
For the first quarter of 2016, AltaGas reported normalized funds from operations of $132 million or $0.90 per share, down slightly from a $140 million or $1.05 per share achieved in the first quarter of 2015.
Normalized FFO was down primarily due to higher interest expense and higher contributions to AltaGas’s equity accounted investments. In the quarter, we received a dividend from Petrogas for approximately $6 million, which was in line with our expectations. We're reasonably confident of continued Petrogas dividends of this magnitude through the rest of 2016.
Normalized net income for the first quarter of 2016 was $38 million or $0.26 per share, compared to $57 million or $0.43 per share in the first quarter of 2015. Normalized net income was lower due to weather and commodity prices as referenced previously as well as higher depreciation, amortization, interest expense and preferred share dividends.
On a U.S. GAAP basis, we’ve recorded net income applicable to common shares for the first quarter of 2016 of $55 million or $0.38 per share. This compares to $66 million or $0.49 per share for the first quarter in 2015.
Normalizing adjustments in the first quarter of 2016 relate primarily to unrealized gains on risk management contracts and gain on sale of assets. On February 29, 2016, we completed the disposition of certain non-core natural gas gathering and processing assets to Tidewater Midstream for $30 million in cash and 43.7 million common shares of Tidewater.
The assets were primarily located in Central and North Central Alberta and full of approximately $490 million a day of operating capacity. They accounted for less than 2% of 2016 normalized EBITDA. As part of the transaction AltaGas recognized a pretax gain in the first quarter of 2016 of $4 million and combined with a $10 million tax recovery, this resulted in a $14 million after-tax gain.
The acquisition of the remaining 51% interest in the Edmonton ethane extraction plant on January 1, 2016, was opportunistic and strategic in nature as it ties to our longer term strategy for propane exports by providing greater control of supply. The 51% planned interest acquired has the potential to provide an additional 1,500 barrels a day of C3-Plus, subject to operating decisions and marketing pricing of course.
During the quarter, AltaGas through its partnership with TransCanada terminated the Sundance effective March 8, 2016, as change in our provisions. AltaGas recognized a pretax provision of $4 million on its investment, which together with 2015 actions results in investments being fully written down.
For the first quarter of 2016, interest expense was $36 million compared to $30 million for the same quarter in 2015. The increase is driven by higher average debt outstanding as a result of the purchase of the San Joaquin facilities and lower capitalized interest as assets like McLymont were brought into service. These were partially offset by lower overall interest rates.
Deprecation was $68 million in the first quarter of 2016 compared to $50 million in the first quarter of 2015. This was mainly due -- this increase is mainly due to the acquisition of the San Joaquin facilities, new assets placed into service and the impact of a stronger U.S. dollar.
For the first quarter of 2016, income tax expense was $6 million, compared to $30 million for the first quarter of 2015. The decrease was mainly due to the $10 million tax recovery related to the asset sale to Tidewater, which I referred to earlier, coupled with lower earnings in the first quarter of 2016. On a full year basis we expect our effective tax rate to be in the 20% to 25% range.
Net invested capital in the first quarter of 2016 was $151 million compared to $131 million in the first quarter of 2015. This was primarily comprised of increases in property plant and equipment coming primarily from construction cost related to the Townsend facility and the purchase of the remaining 51% Edmonton ethane extraction plant, partially offset by the sale of the FG&P asset to Tidewater. There was also an increase in long term investment relating primarily to AltaGas’s investment in Tidewater.
AltaGas’s balance sheet is in a strong position and we are fully funded for 2016. At the end of the first quarter of 2016, debt to total capital was 48% well below our covenant levels of 65% to 70%, debt-to-capital is also in line with historical levels.
We’ve approximately $1 billion available on our credit facilities and as we demonstrated over this past month, we have great access to multiple sources of funding.
More specifically in early April, we did a very successful 10-year, $350 million medium term note offering at an attractive coupon of 4.12% and yesterday we announced we will be implementing a premium dividend reinvestment plan along with changes to the dividend reinvestment plan.
As we previously have indicated, the drip resulting up to $100 million of additional funds annually and the premium drip may achieve up to $40 million in the balance of 2016.
Turning to our 2016 outlook, by major business line, I'll start with power, the North American power portfolio was now approximately 95% contracted with a 100% of generation coming from the energy sources.
The Power segment is expected to contribute approximately 42% of our overall forecasted normalized EBITDA for the year with strong year-over-year growth.
This will be driven by the addition of a San Joaquin facilities acquired late last year as well as a full year contribution from the McLymont Creek Hydroelectric Facility and we are benefiting also from the strong U.S. dollar on our U.S. power assets. So as overall as we stated before, the Alberta Power exposure is not material at this point to our ongoing results.
In terms of our Alberta Power portfolio it now includes only 65 megawatts of natural gas power generation. That’s primarily the co-gen units in the small peaking facilities. They represent only 4% of the total generation portfolio.
Alberta power price exposure on our remaining power portfolio for the remainder of 2016 is hedged, resulting in no variability to Alberta power prices.
Our Utility segment is expected to contribute or account for 37% of normalized 2016 EBITDA, which with moderate growth expected this year. This is driven by rate based customer growth while also benefiting from a favorable U.S. dollar.
In Michigan, Semco Gas expects approximately $8 million of additional margin in 2016 as a result of the full year contribution of its main replacement program. In Alaska, the Regulatory Commission of Alaska has accepted ENSTAR's 2015 filing, resulting in increased total margin of $6 million.
In 2016, these will be partially offset by changes made by Heritage Gas to its rate structure to remain competitive in terms of pricing and customer retention.
Finally the Gas Midstream segment is expected to have a moderate decline in EBITDA on a year-over-year basis. Overall we expect our midstream business to account for approximately 21% of 2016 normalized EBITDA.
Our integrated Northeast British Columbia strategy is expected to add additional EBITDA to our gas segment in 2016 as our Townsend facility enters commercial operations midyear.
Townsend facility is expected to generate normalized EBITDA of approximately $15 million to $20 million for 2016 once commercially on stream as volume from Painted Pony progressively increased through year end.
We also expect to see strong results from Petrogas in our gas midstream segment. In part this will be driven by continued strong performance at the Ferndale LPG facility, which AltaGas operates on U.S. West Coast.
The absence of turnarounds at the Harmattan and Younger extraction plants in 2016 will also add to perform. However this is expected to be offset by lower contributions from commodity prices, the sale of the Tidewater Gas assets and moderately lower FG&P volumes.
Today our FG&P business is increasingly focused on larger core structure assets in Northwest Alberta and Northeast BC supported by sustainable Montney development. This includes the Gordondale, Blair Creek and Townsend facilities, all of which are supported by attractive take or pay arrangements.
In Q1 2016, the core Gordondale and Blair Creek aggregate volumes were approximately $176 million and the balance of total FG&P volumes excluding the Tidewater disposition were about a $102 million a day in terms of volumes.
Gordondale, Q1 2016 volumes were flat year-over-year. Blair Creek volumes were actually up 16% and other FG&P volumes were off 3%. With the full year in 2017 for the Townsend facility, volumes from these three core FG&P assets will represent over three quarters of total FG&P volumes in the company.
Within gas and midstream overall and that includes FG&P and extraction take-or-pay contracts represent approximately 44% of 2016 EBITDA in midstream. Cost of service is 22% of total midstream EBITDA. Fee for service is 26% leading about 8% that has direct commodity exposure. This 8% in the gas midstream segment represents just slightly less than 1% in total 2016 expected corporate normalized EBITDA.
The weighted average term of the take-or-pay contracts in our portfolio is 17 years, while cost of service contracts average 10 years. Again for some sensitivity analysis every plus or minus 10% change in gas volumes impacts total corporate EBITDA by $7 million to $10 million, which is about 1% of our total expected EBITDA for this year.
And as stated before within Altagas’s gas midstream segment, a majority of our customers across the widely diversified portfolio have investment grade credit ratings. Based on Q1 2016 results, no material allowances have been incurred and achievable are very consistent with historical experiences.
Within the overall gas midstream segment, approximately 5% of our 16 expected EBITDA is exposed to commodity prices for this year. Based on current commodity prices, we expect to have approximately 2,000 barrels a day of extraction volumes exposed to frac spread for the remainder of 2016.
To put this in perspective, this represents about 3% of total produced extraction volume within Altagas, demonstrating the low amount of frac spread exposure for the duration of the year.
During the first quarter of 2016, there were no NGL frac hedges in place. In terms of hedging for 2016, subsequent to the end of the quarter, we did enter into summer and winter frac hedge with bifurcated volume ranging from 750 to 3,000 barrels per day at an average price of $22 per barrel, excluding basis differentials.
If however frac spreads do recover and we have seen some improvements in this past quarter, Altagas is well positioned to deliver additional normalized EBITDA growth as we can increase the production of exposed C3-Plus production, but we're not counting on that in our '16 expectations.
So, also important to remember that 50% of our EBITDA does come from the U.S. This shows our highlights of diversified business platform. Some of this U.S. dollar exposure is naturally offset by deprecation in the U.S., our interest on U.S. debt and dividends from U.S. denominated preferred shares and tax expenses.
Again for sensitive purposes for every plus or minus $0.05 change in the Canadian U.S. foreign exchange rate, the annual EBITDA impact is above $40 million. It's about the same as what we gave you in our previous quarterly call for the end of 2015.
Getting close to wrapping up here in terms of total expected capital expenditures in 2016, we continue to believe and expect that it will be between $550 million and $650 million this year. This is predominately related to growth and particularly the completion of Townsend and its associated infrastructure as well as investments in our regulated utilities.
We also expect to start -- restart construction on our Alton Natural Gas Storage project in the summer and have some spend in moving our Ridley Island propane export terminal and our fine-liquids separation facility forward later this year subject to FID.
Maintenance capital for gas and power businesses in 2016 is expected to be less than $40 million. We expect again just for guidance here approximately $290 million for depreciation, amortization and accretion expense for 2016. Deprecation will increase over 2015 levels to account for this McLymonta and San Joaquin power assets and other additions to our infrastructure portfolio.
So in sum, the San Joaquin facilities, Townsend, McLymont Creek, Alto and our future capital investments in our regulated utilities business are all expected to result in approximately a 50% increase in Altagas’s normalized EBITDA by 2020 relative to 2015 normalized EBITDA of $582 million.
Any discretionary development capital for other projects referenced which is beyond those numbers and will only serve to further increase our future EBITDA growth.
To wrap up 2016 looks to be a very promising and busy year for Altagas, a year where we expect to deliver strong shareholder returns as we drive approximately 20% growth in normalized EBITDA and 15% growth, up to 15% growth in normalized funds from operations.
We're moving a lot of exciting growth opportunities forward, and I will now turn it back to Jess.
Thank you, Tim. Operator, we'll now open it up to investment community for question and answers.
Thank you. [Operator instructions] First question is from David Galison of Canaccord Genuity. Please go ahead.
Good morning, everyone.
My first question really just relates to your development project pipeline. For these projects to receive final investment decision, can you talk a bit about what type of return profiles you're targeting for them?
Yes, Happy to David. So in terms of our expectations, we talk about generally IRRs, typically how well folks in the energy infrastructure look at new projects and we would be probably in the 8% to 10% range on those sorts of types of projects.
[Indiscernible] how we've looked at things historically. We do look and I think we do have in our investor slides that are on our website some expectations for the amount of expected capital and the likely investment ratio that would arise from that investment capital and certain new projects including Townsend, Alton and others.
Okay. And then just on the EEEP, acquiring the remaining interest, you said it's around -- the potential to add an additional 1,500 barrels per day.
Yeah, it has the potential to, yes.
Okay. And then that’s more just around what market conditions warrants producing that at that level.
That’s correct. The plants are very flexible and I think as David mentioned we have the ability to re-inject or pull or turn them on effectively from a volume standpoint in short order and to react to market conditions and hedges we have in place etcetera.
Okay. Thank you very much.
Thank you. The next question is from Robert Kwan of RBC Capital Markets. Please go ahead.
Hi, good morning. Just looking at North Pine and you got the expected EBITDA multiple there at eight to nine times. Is that kind of what you would expect on a fully contracted basis or what level of contracting are you looking at for some -- for that type of facility, essentially what’s underlying the eight to nine times?
Yeah, that would be based on the facility being on a full run rate to fully commercialized in an operation and with underpinning that we would expect for a row of projects including that one.
Okay. And so would you need that level then of contracting going in or are you comfortable with being something somewhat less than that and kind of filling it up over time? I don’t mean on a contract like on a taking a little bit of extra exposure but feeling good that you would fill it up.
Yeah, I think ultimately, the way we view projects, we view on them on a full cycle basis. If there is a justification for the project and it has strategic merits and based on feedback we received, we ultimately do expect to have them running close to full and being fully supportive from a contractual standpoint.
North Pine to use your example is a -- we view it as a regional project. It's not going to be a single exposure to single counterparty or single producer on the upstream side. It will be multiple producers and so that in itself is an important differentiating feature versus let's say a plant that's typically associated with a single producer.
When we think about '16 and advancing the project from a permitting and development standpoint, commercial, we’ll move along in a similar parallel path.
We don’t necessarily need to, nor necessarily expect to have a full contractual underpinning by the end of the year because in a normal course development cycle with an on-stream date in first half of 2018, there would be continued progression over those two years.
And again that’s not -- that’s not dissimilar to other projects we’ve undertaken in the past. This shouldn’t be any different from a development standpoint.
Okay. And you mentioned multiple producers and I think you've disclosed that about 70% of your customers in the gas segment are investment grade. Would that be a very similar make up of both in terms of credit rating and as well as the size of customers that might be coming into North Pine?
I think it's -- there is mixture in I think probably most folks on the phone are going to be familiar with Northeast BC activity, which is typical Montney driven. You should imagine, but there is a whole mix of producers in that region.
There is public. There is private. There is large caps. There is multinationals and there is and - there are smaller ones as well. So it’s really just microcosm of Western Canadian Basin. I’m not trying to duck the question at all. It's simply that the reality is we are in discussions with multiple parties and they would fit right across that whole spectrum.
Okay. If I can just turn to question here on funding, Tim you mentioned you're fully funded for 2016 and you've got lots of liquidity sources. I’m just wondering if you had additional discussions there with S&P on how to resolve the negative rating outlook?
We haven’t had any recently, but that’s in part because we had a very comprehensive discussion, series of discussions through the end of last year. And I think I might have said this for sure I did actually on the previous year-end conference call, that we have a very open relationship, open book with them and we’ve got some specific objectives now coming out of that. It's more on to us now. We plan our course of actions for this year as well as next year. That’s the timeframe we're thinking about in terms of addressing some of those…
So it sounds like there are thing that you need to do to resolve the negative rating outlook i.e. the current or put differently, kind of do nothing other than continue to execute the commercial side is not enough to remove negative outlook.
Well, I think when we think about just running the company which is really what management is tasked to do, status quo is never a scenario, but I think when we look to grow the company and fortify the company, many of the steps that we would be doing in normal course and that includes things like North Pine and RTI, on the development side they're actually accretive to certain measures including things like FFO to debt. So, it's part of our normal planning process and that’s how we think about it, Robert.
Okay. That’s great. Thanks very much.
Thank you. [Operator Instructions] The following question is from Linda Ezergailis from TD Securities. Please go ahead.
Thank you. I’m wondering if you can clarify on the Blythe RFP, was that through the full 507 megawatts that you submitted and when would you expect to hear back?
This is John O'Brien, Linda. That was for the full Blythe facility and as we look at RFPs going forward, we think in terms of the full Blythe facility. I think on this RFP, we're on a fairly tight timeline to hear back.
We may hear back in the next four to five weeks on this according to the timeline we got. So, I don’t know that we are not in control of the RFP certainly. So that’s what we would estimate as a timeline, but it was for the full amount of megawatts out of the facility.
Okay. Thank you. And just moving to the other part of the continent for Alton, what’s causing some of the delays there? Are there some NIMBY-ism? Is there some commercial considerations that have delayed some of the activity there?
No, commercially there is no real concern. What we do and it’s some timing, we've got the permits that we need to go around and move forward on the project and seasonality comes into play when we want to start the activity with respect to environmental limitations on construction and we'll be looking to move into construction on that project as we get into around the mid summer timeframe.
Okay. Thank you. And can you just maybe also comment, I realize it's just kind of more clean-up question, what other sources of non-core assets are you considering monetizing?
We would potentially look at some of our additional other may be non-core smaller FG&P assets consistent with what we’ve just recently done with Tidewater, but nothing specific at this time.
Okay. Great and maybe just on the quarter, can you talk about the dollar effect of the unusually warm weather? What utilities, EBITDA would have been if weather would been warmer in the quarter?
I don’t know if I've got a specific hard number to give you on that. I’m thinking a lot as I do this. As you know it was right across all the utilities and maybe in rough terms and this would be EBITDA -- on an EBITDA basis, you can say around $15 million that would be an aggregate impact. I will work out sort of a soft number, but it's representative here.
Great. Thank you.
Thank you. The next question is from Ben Pham of BMO Capital Markets. Please go ahead.
Thanks, good morning, everybody. I wanted to clarify the $15 million, you highlighted what the utilities, was that in your expectations with your guidance to some extend? And I was going to call it a little bit late, you're maintaining your guidance, but was the Q1 in line with your expectation broadly speaking?
No, we don’t forecast weather other than on a normal basis. So the $50 million would not have been factored into.
Okay. So your guidance is on a normalized basis. Could you strip the weather out, you assume its normal weather.
Yeah, there is offsets and weather is extremely unpredictable and when we were -- as we think about from that importantly when we start to think about what 2016 is going to look like and as we get in Q1 even, we're not adjusting to try to real time with what the actual weather offsets to that things that are positive, things like the FX to partially offset some of that at least from a U.S. utilities perspective.
Okay. Great. And if I may, a broader question, I was just wondering about how do you think about your boarder contracting strategy when you think about your business, could the utility side that's perpetual cash flows and the power side could be 70 years to 60 years I’m showing your power stuff and then the gas side a next step in contracts depending on the structure.
Do you think it brought your business more broadly from a contracting perspective whereas if you're adding a lot of contracting in one segment you can take a lot of contracts in other. Do you look at each of the individual segments on a silent basis?
Well they're already different clearly. I mean it's a good question and they're all very different and we do view them as complementary and perhaps like this and some flexibility in terms of how we think about it, but utilities are just plain utilities and our regulators have said, our philosophy and power is to be contracted and that's what we've achieved.
So when you look at the gas midstream side the remainder, the reality in Western Canada is you typically do see a variety of different types of contracts and what we have with our portfolio is not a whole lot different from what other true midstream companies that have a bit of a diverse midstream business, what they would have themselves.
So that mix that I talked about earlier or take or pay, cost of service, fee for service and then frankly some and you spoke commodity expose beyond that, that's typically what you end up with given a mix of midstream assets. We have some smaller pipelines. We have some newer FG&P plants. We have extraction and all those come with different types of contracts is what we expect.
And we do look to try to take volatility out where we can and we've done that. For example, on our largest extraction asset that's Harmattan, we have a healthy element of our cost-to-service arrangement on that plant, which is significant in the [recent] volatility. So that's just an example I guess.
Okay. The other question I had lastly on the cut on our power side, what will drive the additional RFPs that you've highlighted? Is that the utilities are gearing for long term resource plans? What -- maybe a bit more color there.
Yes sure. This is John O'Brien again. It's as we -- I think as Dave highlight, David Harris in his opening, it's more looking at the Western states, so that when we think of it as an example the Blythe facility from a transmission perspective, we anticipate that other states in addition to California will have power needs and so that's how we look at Blythe and the development sites we have there.
So it's a Western states perspective I would say, not just a California perspective as we anticipate what will come.
And we're aware right now about that for RFPs that will be forthcoming both this year and in early part of next year.
Into next year.
Okay. Great. Thanks for taking my questions.
Thank you. There are no further questions registered. I would like to turn the meeting back over to Mr. Jess Nieukerk. Please go ahead sir.
Thanks John. Thank you. I would like to thank everybody for joining us today. We are available for any follow-up calls afterwards. Thank you.
Thank you. The conference call has now ended. Please disconnect your line at this time. And we thank you for your participation.
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