Jess Nieukerk - Senior Director of Investor Relations David Harris - President and Chief Executive Officer Tim Watson - Executive Vice President and Chief Financial Officer

Patrick Kenny - National Bank David Galison - Canaccord Genuity Rob Hope - Scotiabank Robert Catellier - CIBC Ben Pham - BMO Capital Markets Robert Kwan - RBC Capital Markets

Thank you. Good morning, everyone.

Welcome to AltaGas’ fourth quarter and full year 2017 conference call. Speaking today are David Harris, President and Chief Executive Officer and Tim Watson, Executive Vice President and Chief Financial Officer.

After some formal comments this morning, we will have a question-and-answer session. Before we begin, I’d like to remind you that certain information presented today may include forward-looking statements.

Such statements reflect the Corporation’s current expectations, estimates, projections and assumptions. These forward-looking statements are not guarantees of future performance and they are subject to certain risks, which could cause actual performance and financial results to vary materially from those contemplated in the forward-looking statements.

For additional information on these risks, please take a look at our Annual Information Form under the heading Risk Factors. I’ll now turn the call over to David Harris.

Thank you, Jess. Good morning, everyone.

In 2017, we delivered very strong financial results, even slightly ahead of our guidance. It was a testament to our strong operations and to what each business segment can deliver.

We achieved 14% growth in normalized EBITDA at $797 million, up from $701 million in 2016. The growth came from all three of our business segments.

Our gas segment increased 36% to $221 million, utilities increased 8% to $298 million and power was up 6% at $303 million. Normalized funds from operations increased 11% to $615 million or $3.60 per share, up from $554 million or $3.52 per share a year ago.

This was ahead of our guidance and high single-digit growth. Our strong financial performance in 2017 is attributed to the strong growth we’ve had over the last few years, as well as a more favorable economic environment.

On the growth front, we had a full year contribution from Townsend and Pomona, in addition to contributions later on in the year from Townsend 2A and North Pine, we also benefit from. Higher frac spreads, which increased almost 2.5 times when compared to 2016, higher river flows and contractual prices at are Northwest Hydro Facilities and rate in customer growth across our utilities as well as colder weather at some of them.

The strong operational and financial performance demonstrated throughout the year also gave the Board confidence increase the dividend by just over 4% for 2017. Our Northeast B.C.

LNG export strategy are really taking shape. Our construction team continues to perform exceptional work, brining both Townsend 2A and North Pine Online on-time on budget.

With the addition of North Pine in December, we have a complete energy value chain available to producers at very competitive rates. Further, in just over a years’ time, we’ll be able to offer access to Asian markets for propane through our Ridley Island Propane Export Terminal.

Construction at RIPET is tracking exceptionally well and once online in Q1 2019, we’ll be able to take full advantage of Far East Asian pricing for propane and other, and offer potential for premium net backs to producers. Our indirect ownership interest in the Ferndale LPG export terminal followed by RIPET is just the start of our export business.

We believe we have strong strategic advantage to do more, and we’ll be able to leverage our own expertise, as well as the expertise and strategic positioning of our global partners like Vopak to continue to grow energy exports. Let me now turn to the pending acquisition of WGL.

First, I’d like to address some of the more recent comments we have been hearing from the market. Clearly, the U.S.

tax reform is having varying degrees of impact on different Canadian corporations. We are finding that the impact to ALA combined with WGL was less pronounced than what other utility businesses are experiencing because of diversification of our business segments.

Tim will run through this in a bit more detail, including what we expect for 2018 and for 2019 for the full year as a combined company. But I want to be clear that we do not see the impacts as overly material to our business, both to the combined businesses of AltaGas and WGL.

We continue to expect that the acquisition of WGL will be accretive to both earnings and cash flow per share, and instrumental to our long-term strategy and vision of being a leading North America LNG infrastructure company. The growth platform that it creates for AltaGas in all three of our business segments is impressive.

We’ll work hard to capture the full potential of the opportunities brought forth by WGL and achieve maximum value from the acquisition for our shareholders. Turning to the regulatory process.

In early December, we announced a positive settlement agreement with many of the key stakeholders in Maryland. The settlement agreement was an important step forward, providing enhanced benefits to Maryland.

We also completed settlement hearings in mid-February and the commission is set to issue the decision on or before April 04th. In Washington D.C., we concluded hearings in December and we expect D.C.

to wish the decision within the first half of this year. This is on track with what we have always stated and we remain comfortable with this timeframe.

I also want to quickly address financing on the acquisition in terms of asset sales. As mentioned in our press release, we have identified over $4 billion of assets from our gas power utility business segments, which we are currently evaluating and we expect to realize over $2 billion from this asset sales process in 2018.

With the present optionality available and in light of a number of factors, including recent developments in the California Resource Adequacy markets, we have discontinued the sale process for the Blythe and Tracy facilities. We will instead continue to pursue other structuring and commercial opportunities to unlock the value of the California assets, and we’ll address this some more.

With the California markets continued progress on renewables, flexible generation is needed as a back stop. Tracy and Blythe both benefit from the unique strategic locations in California.

In addition, the enhanced flexibility built into Blythe over the past year in terms of the low-load turn down and the additional connection to El Paso gas supply has proven to be quite valuable, becoming stronger resource adequacy markets, which we firmly will continue to strengthen in the coming years. The opportunity to combine energy and ancillary service offerings to support renewables and the proliferation of community choice aggregate is adding more load serving entities across the entire market.

We believe there are multiple opportunities to unlock value from these facilities. We are very excited about the year ahead and our future with WGL.

We are acquiring very high quality assets, both regulated and unregulated that are highly contracted with quality counterparties. And with the growth profile of our combine companies that I referred to earlier, we believe we can create significant future value for our shareholders.

As we move to close the acquisition, we remain disciplined and we’ll pursue our financing plan in a prudent and timely fashion. Combined with WGL, we expect to deliver significant earnings and cash flow per share growth and maintain our targeted dividend growth of 8% to 10% from 2019 through 2021.

With over $20 billion in assets and approximately $6 billion in growth opportunities still in front of us, we will ensure to capture these opportunities and maximize shareholder value. Let me now turn the call over to Tim.

Thank you, Dave. Good morning, everyone.

2017 was a transformational year at AltaGas. Our base business delivered strong results, highlighting the full benefits of our diversified business platform.

To underscore this, 2017 normalized EBITDA was up 14% to $797 million compared to $701 million in 2016. Normalized funds from operations or FFO were $615 million or $3.50 per share, up 11% from $554 million or $3.52 per share.

And both these measures EBITDA and FFO exceeded our previously communicated guidance for the year. All three business lines contributed to EBITDA growth this year.

So let’s just start with the gas segment, which grew by 36% in EBITDA for the past year to $221 million, and that represents 27% of our total normalized 2017 EBITDA. A full year contribution from the Townsen facility and commencement of operations at Townsend 2A in October of last year drove an increase of over 25% for FG&P volumes.

Following the turnaround of the Gordondale plant in Q3 2017 and the new agreement with Birchcliff, volumes at that plant increased by over 25% in fourth quarter of 2017 versus the previous year. In addition, strong realized frac spreads, which increased 80% to $13.40 per barrel versus last year, as well as higher frac exposed volumes, higher NGL marketing revenues and stronger gas storage margins, all contributed to the strong performance in gas.

Note that the first quarter sale in 2017 of the EDS and JFP pipelines impacted gas results by about $11 million versus the previous year. Equity earnings from Petrogas increased to $25 million versus $12 million last year due to dividend income earned from the investment in the preferred shares and also solid contributions from all of Petrogas’s business segments.

Turning to Power. The segment saw EBITDA growth of 6% to $303 million in 2017 now represent 37% of total normalized 2017 EBITDA.

Full year contributions from the Pomona Energy Storage facility were a positive along with the absence of equity losses from the Sundance B PPAs, and increased contributions from the Craven facility, the biomass facility due to shorter planned outages. And this was partially offset by lower realized gains on Alberta Power hedges.

Northwest Hydro ended the year achieving similar generation to 2016 but at higher average prices and is well positioned to deliver incremental generation in 2018. Operationally, Blythe’s increased flexibility and the second supply of gas led to meaningful increases for capacity factor debt facility through the second half of 2017.

Finally, AltaGas’s utilities achieved 8% EBITDA growth to $298 million in 2017 and that represent 36% of total normalized 2017 EBITDA. This was achieved through customer growth rate based expansion, as well as colder weather SEMCO, ENSTAR and AUI.

A weaker U.S. dollar in 2017 impacted power and utility EBITDA by about $10 million.

Normalized funds from operation increased 11% in 2017 to $615 million as a result of the strong results in all of our business segments, partially offset by lower distributions from Petrogas and higher current income expense. On a per share basis, normalized FFO was up $0.08 to $3.50 versus the previously year.

In 2017, we received $13 million in preferred share dividends from Petrogas versus only $6 million in 2016. And we also receive $5 million of common share dividends versus $24 million in 2015, which was in line with our expectations for the year.

During the year, the power segment recorded pre-tax provisions on assets of approximately $133 million related to the Hanford and Henrietta gas fired peaking facilities and certain non-core development stage gas fired peaking assets in both California and Alberta. A small impairment was also taken on a non-core gas processing facility that was classified as held for sale.

For 2017, income tax recovery was $34 million compared to income tax expense of $33 million previous year. Income tax decreased mainly due to the tax recovery recognized on as provisions taken during the year and the impacted U.S.

tax reform. These decreases were partially offset by higher income tax expense due to a portion of transaction costs incurred on the pending transaction and the unrealized losses on certain risk management contracts that were not tax deductible.

As at 2017 year end, the U.S. deferred tax liability was re-measured based on lower 21% U.S.

federal tax rate, which resulted in the net reduction of $136 million in the deferred tax liability. For the portion of that, which related to our non-regulated U.S.

businesses, $34 million of this re-measurement was recorded as reduction to income tax expense, while the remaining $102 million was recorded as a deferred regulatory liability on the balance sheet. Normalized net income in 2017 was $204 million or $1.19 per share versus $153 million or $0.98 per share in 2016.

Key drivers for higher EBITDA, partially offset by higher preferred share dividends, interest and depreciation expense. There were several normalizing adjustments for 2017 and you can find those in the disclosure that we released this morning.

On a U.S. GAAP basis, net income applicable to common shares for 2017 was $30 million or $0.18 per share.

This compares with $155 million or $0.99 per share for 2016. Invested capital, net of dispositions in 2017 was $408 million, down from $656 million in 2016.

Almost two-thirds of the total capital invested in 2017 was in the gas business. The actual capital expenditures incurred in 2017 net of contributions from Vopak were $478 million as compared to the previous guidance of $500 million to $550 million.

Capital expenditures were below guidance, mainly due to small adjustments on timing, as well as the completion of both Townsend 2A and North Pine below budget. Maintenance capital in 2017 totaled $19 million split approximately 50-50 between power and gas.

AltaGas’ balance sheet is in a strong position and well funded for 2018. At year end 2017, debt to total capital was 44%, down from 45% in ’16 and 46% in 2015.

This remains well below our bank and term note covenant levels of approximately 65% to 70%, and we have about $2 billion available on our existing bank credit facilities. And we continue to have very strong access to multiple sources of funding.

In 2017, we successfully completed just over $3.5 billion of new debt and equity issues to support the new infrastructure projects discussed and the WGL acquisition. So now, I’ll turn to 2018 outlook and we anticipate closing, as we said consistently, the WGL acquisition by mid-year.

As a combined entity, we expect normalized EBITDA to increase approximately 25% to 30% and normalized funds from operations to increase approximately 15% to 20%. The acquisition of WGL is expected to drive growth in all three business segments with a combined utility segment expected to be the largest contributor to EBITDA.

Gas and then power will be the next largest contributors with these two representing about half of total corporate EBITDA. Our strategic plan remains the same, create meaningful growth in each of our three business lines and that has not changed with the WGL transaction.

Over the next few years, we see significant defined growth opportunities in each business that in total sum to over $5 billion. 2018 EBITDA from gas will benefit from the first full year commercial operations at both Townsend 2A and North Pine.

Higher earnings from frac exposed volumes as a result of higher hedge prices and WGL’s pipeline investments in the prolific Marcellus and Utica. The Stonewall Gas Gathering System inside the WGL is currently in-service.

WGL’s largest new gas investment, the Central Penn pipeline in Pennsylvania is under construction currently, and is expected to be operational later this year. WGL’s second largest new gas pipeline, called the Mountain Valley pipeline located in Virginia and West Virginia, is undertaking pre-construction site preparation as it prepares final regulatory approvals -- secures final regulatory approvals.

Finally, WGL’s gas supply agreement associated with the Cove Point LNG terminal will also drive growth this year with the terminal expected to be in-service shortly. There are planned turnarounds at our Harmattan and JEEP facilities in mid ’18, which will impact EBITDA by up to approximately $6 million.

Extraction volumes exposed to frac spreads prior to hedging will be about 10,000 barrels per day for 2018 with hedges in place this year for approximately 7,500 barrels per day at a very attractive level of $33 per barrel, excluding basis differentials. Pro-forma for WGL, approximately 65% of 2018 gas EBITDA is expected to be generated or underpinned by take-or-pay and cost-of-service contracts with no direct volume or price exposure.

And this percentage should actually increase in 2019. For 2018, EBITDA from power, that will benefit from higher expected earnings from the Northwest Hydro Facilities due to both price increases, as well efficiency improvements.

In addition, I shouldn't overstate that WGL’s growing distributed generation assets, which are located in over 20 U.S. states will start contributing in 2018.

We have not included further upside from potential new energy storage development, so that we're certainly working hard in some of those. The PPA for Ripon will expire in second quarter of 2018, but it will be partially offset by the new resource adequacy contract that was announced.

2018 EBITDA from utilities will be driven by rate based growth, as well as the addition of WGL’s growing utility business. 2018 expectations assume a moderately weaker U.S.

dollar relative to 2017. Approximately 65% of total expected 2018 EBITDA from AltaGas will come from the U.S., and I’ll just give you one quick sensitivity.

So pro forma for WGL in this year for every $0.05 change in the FX rate, the annual impact to 2018 EBITDA is approximately C$27 million. Looking at AltaGas on a standalone basis, excluding WGL for 2018, we expect a moderate increase to both normalized EBITDA and FFO as compared to 2017, driven primarily by the factors previously noted.

Turning to 2018 capital expenditures. We expect to spend on a standalone basis $500 million to $600 million.

Gas will account for 55% to 60% of that total, while the utilities will account for 25% to 30% and power will account for the remainder. Gas and Power maintenance capital is expected to be approximately $25 million to $35 million.

The majority of capital this year will be allocated towards continued construction at Ripon, as well as maintaining and growing the rate base of our utilities. The 2018 capital program is expected to be funded through internally generated cash flow and a dividend reinvestment plan.

And if required, we also have sufficient borrowing capacity available on our existing credit facilities, as well as excess of capital markets. On a combined basis with the mid-year of closing of the WGL transaction, we expect capital expenditures in the range of approximately $1 billion to $1.3 billion.

Similar to AltaGas standalone spending, close to half of this total will be allocated to gas with the majority of the remaining expected capital directed to utilities followed by Power. AltaGas plans to fund WGL with the proceeds from its aggregate $2.6 billion bought equity deal and private placement of subscription receipts, which closed in the first quarter of 2017.

In addition, AltaGas has $3 billion available under its fully committed bridge facility, which can be drawn at the time of closing and which will remain available for 12 to 18 months following the transaction close. With all funding required for the closing of the WGL Acquisition in place currently, AltaGas can evaluate and pursue its asset sale process in a prudent and timely fashion in step with the regulatory process and being consistent with their long-term strategic plan.

Management, as Dave noted, has presently identified a total of over $4 billion of assets excluding California from AltaGas’ Gas, Power and Utilities business segments, which it’s evaluating various options for monetization on. This could include the sale of either minority and/or controlling interests.

Management expects to realize over $2 billion from its asset sale process in 2018, and we are testing different assets and markets and have specific criteria to comprise the score card, for which assets to move on. These criteria include strategic visions, shareholder value creation, leading WGL financing needs, future growth potential and obviously, pro forma balance sheet strength.

With the present optionality available to AltaGas and in light of a number of factors, including recent developments in the California Resource Adequacy markets, AltaGas again as noted already has discontinued the previously announced sale process of its California power assets. And I’ll just emphasize, in addition to asset sales, which have already discussed, additional financing steps could include offerings of senior debt hybrid securities and equity-linked securities of its preferred shares, and we remain committed to maintaining strong access to capital and to our investment grade credit ratings.

U.S. tax reform is not expected to be material to AltaGas on a standalone basis or the combined entity with WGL.

AltaGas estimates that normalized EBITDA and FFO in 2018 will be reduced by approximately 5% with the impact on normalized net income expected to be neutral to slightly positive. And beyond 2018, the impact of normalized net income is expected to be slightly positive, while increased cash tax ability overtime should reduce negative impact on FFO.

The lower tax rates at the combined regulated utilities will provide customers with decreased rate, which while providing the opportunity to drive rate based growth. The U.S.

non-regulated gas and power segments are expected to record higher normalized net income as a resulted the lower U.S. federal tax rate, partially offset by limitations on the deductibility of interest expense for U.S.

tax purposes. At SEMCO and Michigan, we post an immediate rate reduction from customers using the last filed rate case calculated using new federal tax rate.

Separate from that, any adjustments to the deferred tax liabilities are expected to factor into the next rate case. The lower tax rate could create additional rate based investment opportunities overtime.

The WGL transaction brings a very strong strategic fit for AltaGas to bring significant opportunities for continued growth in all three business segments, gas, power and utilities. It also adds to the financial strengths when we complete this with the combined asset base of over $20 billion.

On a combined basis, over three quarters of total EBITDA will be underpinned by long-term contracts with no direct commodity price or volume exposure. The WGL transaction remains highly accretive to both FFO per share and earnings per share beginning in the first full year of 2019.

This will support an 8% to 10% annual dividend growth rate starting in ’19 while the improving the dividend payout ratio. Finally, as a reminder, we have posted sensitivities for frac spreads, FX and natural gas volumes in our current investor presentation located on our Web site.

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

Thank you, Tim. Operator, we’ll now open it up to questions from the investing community.

So notwithstanding the man hours that have gone into the acquisition, but just given where the stock is today relative to where it was before the deal was announced, as well as the $31 sub-receipts. Now with the sales process for the California assets and the slightly negative impact of U.S.

tax reform. Have you at least taken a look at the option internally of just paying the break fee giving back the sub receipts?

And simply forging ahead with your base business and a much cleaner balance sheet? And if so, how do you look at the valuation delta between those two options?

I’ll start and then turn over to Tim. Just a couple of things is the sale process in California was not a failed one, it was an election we decided to not to go forward, because of finance value opportunities we see going forward in California.

So just as it relates to what our decision process our mindset was with respect to California. As it relates to the overall deal with WGL, we are tracking very nicely on this deal.

As we stated, this has very strong accretion earnings across the board, both gas positions of this company as well on a combined basis with a very robust three segment business that gives ourselves diversification not only from a technology base business line base but a geographic base, which is going to be equally important going forward is confident. So that’s where our mindset is and our direction is at this point.

And we’re not evaluating a break scenario certainly at this point. And so on the financial stuff, I’ll turn it over to Tim.

I mean, I think the bottom line is we think we’re better positioned financially from an accretion standpoint, so I’m talking per share metrics, EPS and FFO per share and balance sheet as well. And I’m talking credit ratios, metrics like the FFO and debt and other various ones.

We actually believe it produces a superior financial outcome. We’ve always said that 2018 is a year with a lot of moving pieces, nobody is going to debate that.

It’s a bifurcated year. If you have a half year of AltaGas and a half of year combined, you have a half year of lot of different factors that are work into the 2018 numbers.

Again, as we said, we always expect 2019 to be a first full year. It’s obviously going to be the most clean year in terms of evaluating the financial metrics for the combined company.

And when you do that and you say look what’s the pro forma from 2019 financial metrics on a combined basis versus what it would otherwise be, it’s a better outcome. So, maybe I’ll leave at that and we can continue to questions.

And just a follow up here with respect to monetizing over $2 billion of assets in 2018. You mentioned in the release that you'll be looking at both minority and controlling interest.

Does that include potentially looking at selling a controlling interest or potentially all of your Northwest Hydro assets? And if so, how do you manage the impact on your credit ratings for selling down such high quality cash flow?

Maybe I’ll start, and Dave jump in as you see fit as well. I mean, really as we said, we have a large portfolio of assets.

We're talking AltaGas assets across our three business lines, focused I’d say more on Canada. Northwest Hydro is one of a large portfolio, frankly, of the assets that we have under evaluation.

We have not made any decisions yet. I mean, as I said in my prepared comments, we're actively studying a number of different paths there with those.

We’re actually doing things here as we sync that with the regulatory timing in close, where we very much value that asset and we think it's worth a lot to us as a growing concern company. So again, maybe I’ll just stop right there.

So my first question relate to the lower EBITDA guidance for 2018. So in Q3, we were looking at about 40% growth and we’re at 25% to 30%.

Now you’ve highlighted about 5% is due to the tax reform. But could you give a bit of color about what's behind the extra 5% to 10% reduction?

Is it more to do with timing, expected timing for the acquisition or something within the assets themselves?

I would say there is a handful of things, it’s certainly not one singular issue. The tax reform really is not a material impact as I took you through, but it is there.

And did we think that there’ll be going back to last guidance, which would have been October of 2017. Did we think there’ll be some tax reform?

Sure. But as you're well aware, there are two competing proposals at that time and we didn't get resolution till the Christmas.

So we had to make some assumptions. Directionally, I think we were correct in our assumptions.

But again detail is a little bit different than when it ultimately emerged. Several other factors go into the slight shifts there.

One, I’d point out is a positive factor that’s in fact we had a very strong Q4 2017, I’m talking AltaGas, and that did have a small impact in terms of the year-over-year percentage math calculation, I guess. In terms of our timing for WGL is not shifted, I want to emphasize that emphatically.

We've always said first half of the year and more specifically mid this year. But again, if you -- it's a large transaction even if you make slight adjustments, I'm just going to illustrate, I’ll just say a month plus or minus, it has an impact.

And so again it's a modeling impact. But I want to make sure you understand, our view hasn’t changed on timing or whatsoever.

And we are tracking at or faster than what we originally thought. So that was one point.

And again last one I’d say is simply, we’ve continued to quite honestly evolve our thinking on dispositions. The dispositions we do are going to enhance value.

And we've warned a number of things as we work with our advisors, test different ideas in different markets here. And frankly, we're going to optimize those asset dispositions through a collection of steps and that shifted a little bit again frankly since October 2017, but ultimately in a good way because they’re going to be better optimally done transactions to accomplish our debt reduction.

I think the only thing I would add to the end of Tim’s commentary to the question around, is there anything wrong with the assets, no there’s nothing fundamentally wrong whatsoever. We like exactly what we see and the combined strength of the companies and expect them to perform as we anticipated when we entered the deal.

And then just a clarification on the CapEx. So as a combined entity, assuming the acquisition closes in mid-20 this year.

You’re up to $1 billion to $1.3 billion. Does that mean that CapEx in the second half increases $500 million to $700 million?

So I think in our December -- we did put a press release in December, had a few different things in it. But I think we did reference a combined CapEx number, if not mistaken.

I think it’s -- and I think it was 1.2, 1.5, we’ve tightened that in a little bit and we’re just slightly. But to answer your question, yes, it would be the WGL that gets layered into the second half of 2018.

And then just a follow-up, the last question on leverage. So post acquisition, what you expect your debt-to-EBITDA to be and ultimately what you’re targeting for the combined company?

I’ll start with while my team helps me here a little bit. I think I’ll start with the FFO to debt.

I mean we’re targeting that mid-teens level. We’re not bashful about that, we’ve been seeing for a couple of years and we’re shifting away on that and progressing that, so that’s on track.

We also look at our debt to cap metric, why because that’s governed by the covenants we have in our various documentation and our debt-to-EBITDA basis. I am going to say guys have about five times could ultimately trend a little bit lower than that.

But that would generally be the direction. So again, I think that, if I am not mistaken, it’s pretty consistent for what we said on that metric.

Couple of clarifications, just on the 2018 guidance you just walked us through. If we assume that WGL hasn’t moved and then you largely outlined tailwinds being a push out of some of the asset sales.

So can you give us what the headwinds were that moved you from 40% EBITDA growth year-over-year to a lower number, cognizant of 5% being U.S. tax reform?

So again these are things I’ve already said, but the tax reform small headwind. If you adjust out a month, just give you that example on a timing for the transaction, still within the first half of the year, that’s a headwind because you’re out of month of EBITDA for example.

If you finish stronger on a Q4 ‘17 basis then the simple math says, it’s a higher hurdle on a percentage growth year-over-year into ’18. This would be headwind examples.

And then just regarding the California sales process. Just regarding the commentary there on not being a failed process.

Was the process cancelled because the bids coming in were below your threshold or because the changes in the California market increased your expected value of the assets?

Yes, it’s the latter.

And then just regarding the settlement in Maryland in December. Does that alter meaningfully any financial expectations for WGL?

No, none whatsoever.

You’ve answered most of my questions. I noticed that you maintained the dividend growth guidance for WGL.

Does it make sense to provide us an update on your per share metrics, accretion expectations?

Consistent with what we’ve said going back a year I guess, no material shift in those accretion metrics.

Just on Northwest Hydro, you’ve referred a couple of times to efficiency enhancements. Can you walk through what’s going on there?

We constantly look to improve the asset as you get more familiar with the river flows, and the asset has always performed as we expected. But we’re actually seeing opportunities to turnaround with whether it’s how we clean the trash rakes along with a number of other smaller and minor things that we continue to with it to just continue helping and enhance efficiency and performance, Robert.

Actually not too much given what we do across the board on all our assets. So relatively that’s it, the assets that knew anymore, but they’re still in their early stages of life so you always take advantage of opportunities as you get wiser and smarter to continue to push efficiency and results and higher earnings.

So these are just supporting the assets and operating basis as opposed to capital enhancements?

That’s correct.

I guess I want to go back to the question about credit metrics with respect to changes in your asset sales plan. On a one hand obviously it is more -- could be more accretive if you saw higher value assets but there is credit or business risk profile implication there.

So I just want to confirm from totality of your comments today that you’re not contemplating any additional corporate actions as a result of the change in the asset sales plan to maintain your credit rating other than those that were already annunciated at the time of the acquisition?

I’ll start and Tim can finish. That’s correct, Robert.

I was wondering, can you talk a bit more about the cap on your market and some of your comments about reserves adequacy that’s changing a little bit. And really what’s changed there from your outlook in the prior market there?

It’s nothing that’s really changes, it’s always like a timing issue with the California market spending and how certain opportunities involve. We certainly thought at some future date, resource adequacy certainly community choice aggregators are going to gain momentum, which they are.

But as we got into the sales process and we started to see the post sales and those markets pick up, as Tim referenced and we put out earlier, we turned around and we picked up the resource adequacy contract for Ripon. We’ve seen additional interest, not only in Ripon type assets that go into 2019 and 2020 drawn, there's been recent dialogue with respect to the opportunities with Blythe.

And Blythe is sooner in the queue with respect to contract expiration and Tracy still has some fairly decent length on it. We expect the same things to take place there.

And the other thing that’s taking place too is the resurgence with respect to battery opportunity, which all our assets played very well on. So when we took a look at the overall value and specifically some of the enhancements that we've made to Blythe with the added gas line being tied into low turndown, which took place quite frankly at the end of the July into August timeframe, about the same time we were starting to put together the sales process for California assets.

We've seen significant requirement in the capacity factor of that facility, well over 20% and we’re seeing that strength continue in January and into February. We don't expect it to subside.

So those enhancement as well as gas pricing at that facility by as much as 20%, and a significant degree of flexibility with respect to the off-taker for low turn down. So a number of different key points that reset our compass with respect to value of these assets over the long-term, which required us to say, it doesn't make any sense to continue with the sale process.

I just make one or maybe nuance comment, I guess, on the California process. Our view on what the value achievable from that process could be really didn't change over Q3, Q4.

So just to emphasize, there wasn't something that came out of the blue that said, look, I mean, the value is lower than what we originally thought going in. So we had expectations, a realistic expectation that I think in terms of what an asset in that marketplace could achieve and that that goes right back to the initiation of our sale process.

To be frank, we could have gone ahead if we’ve chosen to and sold certain of those California assets. What we didn't said is said look, I mean there's a number of other options in our portfolio more in the Canadian side, that are frankly going to be a better outcome for us, both from an equity, accretion, et cetera standpoint, as well as a balance standpoint.

And so that was a decision that we made recently here. And it's the benefit of having more knowledge and having done more work and analysis, again, getting some external viewpoints.

And so, we have a better set of options we pulled the table that was our decision to be replaced by several other things that we think are going to be more value accretive, frankly.

And can you comment on what could be included in the midstream side of things in that $4 billion? Is that mostly just available for sale investments you have or is it -- could potentially beyond that?

I think it's probably more on the non-core side as well as things that would be help for trading available for sale, no secret there. We've got certain equity type investments but having said that, I want to emphasize that those are not big drivers or big factors from a dollars and cents perspective.

And so I think we have the luxury of timing those as when we want to move on those, because they're not that big from a size perspective.

If I can start coming back to the guidance. Tim, you had mentioned some of the things are just more mechanically or arithmetic pushing that year-over-year growth down.

What is specifically there just for budgeting process, the WGL close that you’re working with right, is it June 30th type thing?

I would define that as mid-year, so that sounds pretty good.

And then just so I am clear as to when you’re talking about what’s pushing around, previously you would have been using a date that was slightly before June 30th?

I think we said certainly as we met many people over the course of this year, a Q2 outcome is what we still think we’re tracking to here. And so one in Q2 I guess is the question, and you got three months in that quarter and a single month of EBITDA can swing things a little bit.

So again, probably I think it’s a mathematical of output.

And then as well back to the question around reiterating your accretion levels. Given the tax reform is really being attributed to WGL assets, is it fair that roughly speaking the accretion that you had previously is down about 5%?

The accretion for full year 2019?

Yes.

No, it’s very much what we would have indicated previously. It tend to mid-teens percent accretion levels, I think in numbers that we would have said starting in January 2017.

There’s a number of different factors here. And so there is other key levers here including which asset monetizations we’re doing, et cetera.

So you can’t to stay tax perform is a bit more of a mix than we would have originally thought, that must knock down the accretion. There is a number of puts and takes there.

I think to finish on California. So is it fair to say -- it sounds like Dave you’re talking about your outlook for what these assets could be and the cash flows is higher than just based on some of these change.

So is it fair to say that when you look at the bids and talk with potential bidders that they didn’t see it the same way or they weren’t at least willing to put that into their bids?

No, not quite. As Tim pointed out earlier, we could have very easily gone forward and transacted on these assets, because there isn’t a range or pricing of expectations that we framed out when we entered into the process.

I think it’s more of when you look at it in combination of what we’re seeing and the activity that’s taken place in the California market. Again, some of the things we’ve done with Blythe and what we’ll be doing with Tracy and our other assets, those came very late in year around the August timeframe, started to see the impact they had especially on Blythe really in the early stage of Q3 through Q4.

The activity around resource and the fact is what we’re looking for overall value creation for the company, I would say jeez, we’re going to be much better off holding these assets and we expect them to do better than expected on the post contract terms balance with what else we’re contemplating to put into the sale mix for the right financial metrics, that’s probably in a nutshell for you, Robert.

And I guess just to finish then with that comment. Can you just square that comment around stronger expected longer term cash flows than with the provision that you took at Hanford and Henrietta and why did the write down?

I think the provisions at Hanford and Henrietta are relatively small in the grand scheme of things. So I would -- and then peaking facilities.

So here’s how I would look at the market is, I certainly believe peakers will be probably knocked out the box first, because of battery and other technologies. But the nice thing about our peaking facilities is you can turnaround and repurpose those with battery technology, because they are in great locations.

Going back to your question about are we expecting to see stronger cash flows post our contract terms, I think it’s premature to state that. I would just say simply this much.

As we’ve made the efficiency moves and other moves with our assets, we’ve seen a corresponding strengthening and generation and need. And then as well as starting to see the onslaught of community chose aggregators, which opens up the market to much more customers than just your traditional utilities at the end of the day.

So all those factors coming in is we’re just seeing a brighter light get brighter and as much as there is renewable reform within California as there’s across really the globe, there is still going to be a need and the dispatch act for gas and gas is efficient and flexible to provide the appropriate need will fare very well.

Thank you, Matthew. I’d like to thank everyone for joining us today.

This concludes AltaGas’ fourth quarter and 2017 conference call. Should you have any follow up questions, Ash and I are available.

Thank you.