Ovintiv Inc

NYSE:OVV

Earnings Call Transcript 2017-Q4

[Operator]

Good day, ladies and gentlemen, and thank you for standing by. Welcome to Encana Corporation's Fourth Quarter 2017 Year-end Results Conference Call. As a reminder, today's call is being recorded. [Operator Instructions]

For members of the media attending in a listen-only mode, you may quote statements made by any of the Encana representatives. However, members of the media who wish to quote others who are speaking on this call today, we advise you to contact those individuals directly to obtain their consent.

Please be advised that this conference call may not be recorded or broadcast without the express consent of Encana Corporation.

I would now like to turn the conference call over to Corey Code, Vice President of Investor Relations. Please go ahead, Mr. Code.

[Corey Code, executive]

Thank you, operator, and welcome, everyone, to our fourth quarter and year-end 2017 results conference call. This call is being webcast and the slides are available on our website at encana.com.

Before we get started, please take note of the advisory regarding forward-looking statements in the news release and at the end of our webcast slides. Further advisory information is contained in our annual report and other disclosure documents filed on SEDAR and EDGAR.

I also wish to highlight that Encana prepares its financial statements in accordance with U.S. GAAP and reports its financial results in U.S. dollars. So references to dollars means U.S. dollars, and the reserves, resources and production information are after royalties, unless otherwise noted.

This morning, Doug Suttles, Encana's President and CEO, will open the call; Sherri Brillon, our CFO, will highlight our financial performance; Mike McAllister, our COO, will then describe our operational results; and then Renee Zemljak, our EVP of Midstream Marketing and Fundamentals, will reinforce our commercial mindset and approach to marketing and risk. We will then open up -- open the call up for Q&As. I will now turn the call over to Doug Suttles.

[Douglas Suttles, executive]

Thanks, Corey, and good morning, everyone, and thank you for joining us. We closed out 2017 with some great results, and we are set up for 2018 and beyond. The transformation we started 4 years ago has arrived. The strategic principles we began with back in 2013 have remained the same and our execution has put us in a position to deliver leading returns. We are excited to announce a $400 million share buyback, starting in the first quarter that we will fund with cash on hand. This demonstrates our commitment to our shareholders and the confidence in our plan.

We have an inventory in 4 of the most exciting plays in North America. Our Permian asset continues to deliver better and better well results across multiple benches, while only drilling 3% to 4% of our premium inventory each year. Our Montney is a world-class liquids-rich condensate play that has been self-funding its own significant liquids growth. Our Eagle Ford asset continues to produce strong well results with innovative completion approaches. And the Duvernay is an asset that the world is quickly appreciating for its true potential.

Our balance sheet is in very good position with absolutely debt levels decreasing and leverage dropping steadily. We expect our leverage ratios to be near our mid-cycle leverage targets by the end of 2018. We have been extremely disciplined in allocating capital to only our core assets, consistently investing over 90% into the core. This has accelerated margin growth by ensuring capital allocation choices are supporting this strategy to focus growth on high-value liquids and expand our margins.

At our Investor Day last October, we outlined an impressive 5-year plan. This plan will deliver a cash flow compound annual growth rate of 25%, with returns that climb into the mid-teens, driven by growing margins, total production CAGR of 10% to 15%, and a liquids production CAGR of 20%. Demonstrating the quality of this plan, we thought we could deliver all of this while generating free cash flow of about $1.5 billion at a $50 WTI oil price, and a $3 NYMEX gas price. Now with only a modestly higher oil price of $55, we now believe we can generate about $3 billion of cash flow over this 5-year plan. This is double what we showed last October. As we showed in October, our leverage continues to drop over the course of the 5-year plan. And this could provide almost $2 billion of additional financial capacity, while maintaining leverage of about 1.5x. In fact, we expect this modest price range could generate approximately $500 million of free cash flow next year. These results are fundamentally supported by the strong and consistent execution of our strategy. The fourth quarter of 2017 is another example of this. We finished 2017 by meeting or beating all of our targets, and we're off to a strong start to our 5-year plan in 2018.

In the Permian, we delivered 4Q production volumes of 82,600 BOEs per day, well ahead of the 75,000 BOE per day target in our plan. Our Montney asset delivered on its key role in our margin expansion story. We brought online 3 new plants, which helped to more than double the liquids production from the fourth quarter of 2016 to the fourth quarter of 2017. Our Eagle Ford and Duvernay assets continue to deliver great well results with our new completion designs. And as a result, are providing significant free cash flow. We grew our core assets by 31% from the fourth quarter of 2016 to the fourth quarter of 2017, driven by strong results from innovation on completion design and a relentless focus on improvement. Our core asset growth drove the increase in our liquids mix to 45% in the fourth quarter of 2017. And cash flow margin growth of 81% from 2016 to 2017. For full year 2017, our cash flow margin was $11.75 per BOE, and approximately $14 per BOE for the fourth quarter. 2017 was an exciting year for us, as we aggressively pursued advanced completions in cube development. We continue to develop our resources with long-term value creation in mind. Our objective is to maximize returns and recovery. And we do this by applying a 3-dimensional perspective to pad development that we call cubes.

2018 is setting up to be another great year for Encana. We expect to pass 400,000 barrels of oil equivalent per day this year. This is an outcome of disciplined capital allocation that is aligned with strategy. As a reminder, our core asset production was approximately 235,000 barrels per day at the end of 2016, just a little over a year ago.

A number of factors give us confidence in the efficient execution of our plan. First, we are currently at our peak activity for the year. Our plan does not having -- us adding activity through 2018. Second, we have already contracted for the vast majority of the services and supplies required for our 2018 development programs. And similar to 2017, we are confident that the combination of our supply -- I'm sorry, supply chain strategy and relentless focus on efficiency will offset inflation in 2018. Later in the call, Renee will talk about how we maximize value and manage risk with the sale of our production. But I'm going to steal some of her thunder here. Our market diversification strategy for natural gas provides us with physical transportation to a number of different price hubs, including Dawn, Chicago and Midland. The benefits of this diversified marketing program were on display in January. In January, we sold our Canadian gas at an average price above the NYMEX gas price. And that is before our financial hedges. A lot of these markets were impacted by unseasonally cold weather, but this highlights both the risk management and value enhancement of our market diversification approach. She will also tell you about our first sale of Permian crude to global markets.

I'll now turn the call over to Sherri, who will provide an update on the strong financial performance we had in 2017, and our outlook for 2018.

[Sherri Brillon, executive]

Thanks, Doug. Our focus on only premium return projects in some of North America's best plays is paying off. In 2017, our financial results are significantly higher compared to 2016. Net earnings and cash flows were up, and our leverage metrics continue to come down. As a result of the U.S. federal tax rate reduction from 35% to 21%, Encana recognized the noncash deferred tax charge of $327 million in the quarter. Going forward, we are encouraged that these lower tax rates will improve our project level returns.

Our transformed portfolio is better focused on driving higher margins with increased oil and condensate production. This focus on a higher margin product mix combined with continued cost structure improvements and stronger benchmark pricing have contributed to 81% cash flow margin growth. Early in 2017, we indicated our cash flow margin should be better than the $10 per BOE for the year, and our full year 2017 came in at $11.75 per BOE. We are expecting another 20% growth in this metric in 2018. Our leverage continues to improve as our cash flow grows. Our net debt to adjusted EBITDA metric ended 2017 lower by almost a full turn, heading toward a mid-cycle level of about 1.5x.

Building on our strong delivery in 2017, the benefits of disciplined capital allocation, cost control and continued margin expansion, we expect to deliver competitive results and returns in 2018. We expect to spend between $1.8 billion and $1.9 billion and fund our activity with full year cash flow. We have confidence in our ability to execute with key requirements, such as frac crews, drilling and materials secured for 2018. Our production outlook continues to get better. At our October Investor Day, we outlined Q4 2018 production in our core assets of 380,000 to 420,000 BOE per day. We now have raised that to between 400,000 and 425,000 BOE per day. Since the company's production is now almost entirely from the core assets, we are focusing on total production guidance rather than just the core. Our per unit cost continued to drop as our focus growth benefits from scale and continued focus on efficiency. The exception here is with our T&P cost, which we are guiding at a higher rate than 2017. This is because of our approach to diversifying our markets for products maximizing margin. Our T&P costs will go up as a result of arrangements such as our gas transport to Dawn and oil transport to Houston, but our per unit revenue is expected to exceed these costs and reduce our overall risk and reliance on a single market sales point. We expect our per unit revenue to be about $1.30 to $1.55 per BOE higher as a result of these arrangements, which helps drive overall profit higher and risk lower. Our current budget is built off of a mid-$50s WTI oil price and with NYMEX around $3.

Since 2013, we have been focused on profitable growth, delivering value, not just volumes. This is a compelling margin expansion story. The trend we are seeing with our cash flow margin is proof our strategy is working. We were up 81% versus 2016, and we see another 20% improvement in 2018. Our overall production was lower in 2017 than 2016, but we reduce cost and improved our product mix to capture a higher cash flow margin on a BOE basis. We see this trend continuing into 2018, as we continue to drive operating, G&A and other costs lower, year after year. Our strategy of maximizing margin will increase our transportation and processing cost versus 2017, but these higher costs are more than offset by the higher revenue capture at diverse sales points. Risk is lower and margin is higher.

I'll now turn the call over to Mike.

[Michael McAllister, executive]

Thanks, Sherri. 2017 was another great year of execution, as we met or exceeded all of our guidance targets.

When we outlined our original guidance for 2017, it was about Encana's return to growth in the core assets of greater than 20% on a Q4 '16 to Q4 '17 basis. At midyear, we raised that guidance to 25% to 30%, supported by strong well results across the portfolio. We ended the year above the top end of this range at 31%, while managing capital within the original guidance range.

We delivered production well above initial guidance, despite numerous industry headwinds related to service availability, weather events and pipeline impacts. This success was made possible by our sophisticated planning, supply chain management and great well performance in 2017.

Our cost control on a per unit basis was successful, despite headwinds, such as foreign exchange rates and third quarter production outages. Our execution in 2017 puts us on track to deliver on our 2018 objectives.

2018 will be another year of strong growth, coupled with expanding our margins. All of our core assets are expected to generate free operating cash flow this year. We expect our total production to grow about 30%, driven primarily by our Permian and Montney assets. The 2018 growth profile will be weighted to the second half of the year. This is a result of 2 additional liquid subs coming online in the fourth quarter in the Montney. In the Permian, we expect strong year-over-year growth of approximately 30% for less capital than we spent in 2017. This puts us on track for our 5-year plan. The shape of our 2018 program will be weighted towards the back half of the year as new wells that saw peak production in Q4 start to decline. We expect to combine Eagle Ford and Duvernay to remain roughly at the same production levels as 2017, at about 65,000 BOE per day combined.

We have secured the rigs and frac crews as well as the services and materials we need for the 2018 program at competitive rates. While there is some inflationary pressure in some services, we expect to offset that cost to increase in other areas to hold well costs flat. We are currently running at our peak activity levels for the year, particularly in the Montney, where we're filling additional facility capacity that was brought on late last year.

At Encana, we are focused on delivering the greatest value from our stacked pay reservoirs. We believe that understanding how wells will interact with each other as a system is critical. At the surface, our cube development approach provides significant capital cost efficiencies. By drilling multiple wells from a single surface location, we're able to leverage economies of scale to share services, stockpile materials and reoccupy our facilities. We utilize concurrent operations and deploy multiple drilling rigs and completion spreads on our locations to keep cycle times short. Our focused operations demand sophisticated planning and logistics that translates into getting the job done safely and efficiently. Our approach both creates value and helps to manage risk.

We're constantly collecting and analyzing data and learning from our existing cubes. Across the portfolio, we'll continue to test new benches, conducting spacing and stacking trials. Our short cycle times and real-time data analytics allows us to quickly incorporate learnings into subsequent cube developments. We strive to make each cube better than the last.

Across the company, our operating teams have been focused on creating better wells for lower costs. These efforts are generating strong results. Our objective is to ensure that any additional capital spent on completion scope is delivering additional value. Our design basis is founded in the key principles of hydraulics, intensity, fluids and proppant distribution. Our goal is to generate maximum fracture effectiveness and complexity near the wellbore. Our Eagle Ford asset is a great example of how we continue to innovate to unlock additional upside from our land base. Since 2015, we've effectively doubled our well productivity on our IP 30-, 90- and 180-day basis.

In 2017, we made another step change on our completions intensity across the company. We've reduced our cluster spacing, more than doubling the number of entry points and communication with the reservoir. We're well positioned to keep innovating. In the Permian, micro seismic data is giving us insights into how completions intensity and reservoir geo-mechanics impact fracture geometry. Our latest advanced completion design concentrates the frac energy close to the wellbore, which increases simulated rock volume and allows us to more effectively drain the reservoir. In the Montney, we've seen how changes in fluid system have allowed us to place our sand using 40% less water. In doing this, we've reduced to offset frac impacts compared to previous designs, with no degradation in well performance. We've also improved operational efficiencies, because we're able to pump a stage in less time since we're pumping less water. We continue to evaluate emerging technologies, including mid-stage diverters and dissolvable bridge plugs.

Our culture and structure promote real-time knowledge sharing across the portfolio. We continue to refine our well designs and expect to see continued improvements. Across the company, the type curves we're using for 2018 -- the 2018 plan, I should say, are on average 25% better than the ones we used last year.

We had a very strong quarter in the Permian. We exceeded our target of 75,000 BOE per day, with production of over 82,000 BOE per day. We brought 33 wells on in the quarter, and saw the benefits of peak production of the wells that came on late in the third quarter. The cold weather in December had a minor impact on gas production, due to third-party takeaway issues. Once again, we saw the strength of our field operations team, who were able to get our wells back online with minimal production impact. We brought on a number of cube developments in Midland County in 2017, our well results continue to be supportive of our type curve, and our most recent cubes are pointing results above our Midland type curve. Our cube developments have a variety of stacking, spacing and completion design pilots, and we've developed up to 5 benches at once. We expect 70% of our 2018 program will be focused in Midland, Martin and Upton Counties, with the remainder in Howard and Glasscock. We anticipate like-for-like well costs to be flat versus 2017, and we'll continue to offset any inflation in the supply chain with operational efficiencies and sourcing improvements.

In 2018, we'll be moving to predominantly local sand in the Permian. By simplifying the logistics associated with sand delivery, we're able to get a high-quality product at a significantly reduced cost. We currently have 5 rigs and 3 frac crews running in the Permian.

2017 was a transformative year on the Montney. The 3 new gas plants came on stream, we implemented cube development and realized significant efficiency improvements. Our well productivity continues to improve and our liquids results have been even better than we expected. We are resulting -- we are delivering, I should say, significant liquids growth. From Q4 2016 to Q4 2017, we more than doubled our liquids production in the Montney to 29,000 barrels per day. In the same time period, our margin expanded by over 20% with the improved liquids mix.

Cube development and completion innovations continue to unlock value across the acreage. New bench tests in both Tower and Dawson South have resulted in CGRs between 100 to 300 barrels per million. In Pipestone, innovations in completion design and a focus on operational efficiencies has reduced completion cycle times by 30%. The team has increased their pump efficiencies and changed their completion design to leverage hydraulics and reduce the total stage count. This has resulted in 50% fewer frac days per well. By switching to 100% dissolvable bridge plugs, the team has reduced milling times by 70%. Design changes like these have allowed us to increase our completions intensity, without a significant increase in well costs.

In December, average run times for the 3 new plants was 98%. The second phase of the South central liquids hub came on stream in the fourth quarter and added 3,500 barrels per day of net condensate capacity in Dawson South. We will continue to ramp into liquids capacity of the new facilities over the first half of 2018. As we discussed at our Investor Day in October, we have turnaround scheduled at our legacy plants in the second quarter. We expect this to translate to approximately 5,000 BOE per day of impact in Q2. The liquids hubs in Tower and Pipestone are scheduled to come on in Q4. We expect liquids production to be between 55,000 to 65,000 barrels per day in Q4.

I get a lot of questions about why we're investing in the Montney when we have great Permian assets. The Montney is a world-class condensate play. With incredibly competitive economics, growth in the asset in 2016 and 2017 was self-funded by operating cash flow. With expansion of our margins and increased scale driving operational efficiencies, we expect to generate significant free cash flow, starting in 2018.

We plan to do this while doubling liquids production again. In 2019, we expect the free operating cash flow to increase to $700 million. The liquids-rich Montney competes head-to-head with the Permian. The Montney has lower capital cost and condensate rates that are similar to the Permian oil rates. Montney condensate receives pricing comparable to WTI. In 2017, Montney condensate received the highest realized price of any liquid stream in the portfolio. On top of all that, the royalty rates are 15% to 20% lower in the Montney than in the Permian. You can see why this is a key component of our multi-basin strategy.

We've seen another great quarter from our Eagle Ford and Duvernay operations. Completion innovations continue to drive productivity and capital efficiency improvements in both assets. In Eagle Ford, our culture of innovation has led to doubling of well productivity since 2015.

In 2017, we implemented our advanced completions design in the Duvernay with great success. The wells with tight cluster design came on late in Q3 and performed very well. After 90 days of production, we see an average productivity improvement of 25%. With very strong margins, both assets are set to generate significant free cash flow again in 2018. In the Eagle Ford, we continue to reduce our operating cost to initiatives like artificial lift optimization and process automation. The access to premium market hubs of Houston and LLS means we command strong realized pricing for our Eagle Ford production. The Duvernay team's focus on the efficient operations has led to a 70% reduction in per unit operating costs since 2015. This translates to an increase in our margins. More than 40% of the production in the Duvernay is condensate, which receives pricing in -- on par with WTI.

In 2018, we have secured 2 rigs and 1 completion crew for our Eagle Ford program. We expect our 2018 program will be focused roughly 2/3 in the Eagle Ford and 1/3 in the Austin Chalk. We're currently running 2 rigs in Duvernay and will be starting up a third next week. Activity will taper off in the second half of the year as facilities are filled. The carry portion of our joint venture has been completed and our 2018 will be the first year we are on a heads-up basis.

I will now turn the call over to Renee.

[Renee Zemljak, executive]

Thanks, Mike, and good morning. Encana's approach to market access helps us to mitigate price and physical flow uncertainty. We're focused on maximizing our margins, ensuring physical flow and providing diverse markets for our products. We augment this approach with robust financial risk management program, which includes hedging regional differentials as well as our benchmark prices. Our oil and condensate volumes across the portfolio receive prices very close to WTI. In addition to strong condensate pricing in Canada, our Eagle Ford oil is priced relative to LLS, and our Permian oil has exposure to Midland, the Gulf Coast and most recently to international markets through export shipments. As an example of our focus of maximizing margins, we recently took advantage of our physical access to the Gulf Coast, and completed a sale to Vitol at a Brent-related price and our volumes were sold into the European markets. In Canada, we have also diversified our physical and financial gas pricing to enhance our margins. For example, in 2018, with AECO currently pricing at more than $1.50 back from NYMEX, we expect to receive NYMEX less $0.45 for our Canadian gas. We have virtually eliminated our short-term AECO price risk, and we have meaningfully reduced our longer-term exposure to AECO. Our pipeline access reflects -- reflected in increased transportation cost is more than offset by both realized sales price and the physical market diversification it provides. These activities add value and confidence to our 5-year plan, and they allow our development teams to focus on execution.

So turning to the specifics of Western Canada, the economics of our Montney program are driven by the condensate production. Strong demand for our product in Western Canada, and required imports from the U.S. have created a competitive market with prices that are highly supportive of our development plan. Currently, Western Canadian condensate prices near parity to WTI. In fact, in 2017, we averaged a realized price of about 99% of WTI. Despite strong growth of light oil production in the Montney, third-party forecasts are suggesting that growing demand of diluent will continue to require U.S. pipeline imports for the foreseeable future. Because the Montney economics have shifted to reflect a condensate play, we believe that associated gas will compete effectively from our share in North America. However, in order to optimize net backs, Montney producers require firm physical access to points beyond the AECO market. Given these dynamics, managing price of our expected gas production has been a key area of focus for my team. Our basis hedge program even further reduces our exposure to AECO price risk through 2020. We have nearly half of the Bcf hedged at about $0.88 differential to NYMEX. Our gas risk management approach includes securing firm interbasin service on NGTL and firm export capacity to Dawn, the West Coast and the Chicago market.

The combination of these activities results in flow security and a WCSB portfolio price that is substantially better than the current AECO forward market. And in fact, only 4% of our expected 2018 revenue is exposed to AECO gas price, with this number rising to just 5% for 2019 and 2020.

Our strategy has been to focus our capital on growing production from high margin liquids. Our product mix continues to shift to higher-value liquids over the next 3 years.

In 2018, more than 70% of our projected revenue comes from liquid production, and that percentage continues to grow. Much like our approach to the Canadian gas margin expansion and risk management, we also diversify U.S. sales locations and actively manage U.S. regional price exposure. We have reliable midstream solutions in place for our U.S. oil and gas production with well-established midstream partners. They are prepared to accommodate our expected growth. In addition, most of our U.S. oil wells are now pipeline connected, which generates a higher margin and mitigates weather-related curtailments. While we believe the Permian oil export infrastructure will keep pace with supply growth over the long term, we maximize our regional pricing and actively manage our exposure to the Midland pricing through differential hedging and firm pipeline transport. Our marketing team is tightly aligned with our operations teams to ensure a successful execution of our strategic objectives. Our focus is on achieving the highest margin possible and ensuring that all of our available production has a ready access to markets.

I will now turn the call back to Doug.

[Douglas Suttles, executive]

Thanks, Renee. The business we have been working extremely hard to build since 2013 is here. Our strategy has remained the same since 2013. We have been focused on building a business, which can generate quality returns through the commodity price cycle. Our strategy and plans have not prioritized volume growth. Our 4 pillars, best rocks, execution excellence, markets and fundamentals and capital allocation were chosen, because they are the core building blocks to consistently delivering quality returns. These key principles have been in place for almost 5 years now, and haven't changed with the volatility in the market. In fact, our commitment to growing shareholder value across the commodity cycle is a key reason why we are set to prosper now, even before the recent improvement in oil prices. Since 2014, we have dramatically reshaped our portfolio, aligned our organization structure and culture with our strategy, and continued to execute efficiently and consistently quarter after quarter. We began with a portfolio that was about 95% weighted to natural gas and one that had 27 plays that received capital. Today, we have a leading North American unconventional resource portfolio with some of the best positions in 4 of the best plays: the Permian and Eagle Ford in the United States, and the Montney and Duvernay in Canada, and liquids production of over 150,000 barrels per day.

This transition was accomplished while decreasing debt by $3 billion. All of the -- all of the work that we put into organization design, leadership development and culture are what underpins the innovation in our operations and commercial activities and the results that we deliver. At our 2017 Investor Day, we laid out a terrific plan that had a cash flow per share compound annual growth rate of 25% and generated significant free cash flow of about $1.5 billion over the 5-year plan at a $50 WTI oil price and a $3 NYMEX gas price. Since then, we have continued to execute on our plan and are pleased to say that we are well on track to meet or exceed those targets. The financial frame has continued to improve, both as a result of the improved WTI oil price, and a result of continued margin expansion in our business. When we look at the plan of prices similar to the current market, we expect to generate about $3 billion of cash flow. That is double the free cash flow we discussed in October. In addition, we can also generate approximately $2 billion of financial capacity by maintaining our leverage at our target of about 1.5x net debt to EBITDA. All told, this works out to about $5 billion of cash that is available in our business over the 2018 to 2022 period. And we expect 2019 to be materially stronger than we thought just last October, with free cash flow of about $500 million. All of this has accelerated our discussions about the best way to use this capital to maximize shareholder returns. As we see it, there are broadly 3 different groups of actions we can take: first would be a direct return to our shareholders. This would include dividends or share buybacks; second, our portfolio value creation options that would be accretive to our 5-year plan; and third would be a bucket we call resiliency. This would include options that reduce our risk to lower commodity prices.

In our view, it makes sense to keep all of these alive. After reviewing these alternatives, we have decided to initiate a $400 million share repurchase program. This will be funded from cash on hand and represents a disciplined approach to optimizing shareholder returns. And it also reflects our confidence in the business we built. As you heard on this call, we are very pleased with our 2017 results, and we are set up to continue our strong execution into 2018. We will deliver quality and efficient growth in high margin liquids, while spending within cash flow in 2018. Our updated 5-year plan has about $3 billion of free cash flow, double what we talked about at our Investor Day. And we are pleased to demonstrate the confidence in our plans, and our strong commitment to shareholder returns by announcing a $400 million buyback program today.

Thank you for listening to us. And now, the team would be more than happy to take your questions.

[Operator]

[Operator Instructions] Greg Pardy from RBC Capital.

[Greg Pardy, analyst]

Just a couple of quick ones for you. The Montney guidance you pointed to of a 55,000 to 65,000 was certainly on the higher end of what we would have expected. Could you talk about how Pipestone fits into that, Doug?

[Douglas Suttles, executive]

Yes, Greg. Thank for the question. I'll flip it to Mike here, but maybe just a reminder of the big piece. One is -- Mike mentioned that we have 2 more pieces of Montney infrastructure coming online in 2018. That's a liquids hub in Cutbank Ridge and then a liquids hub in Pipestone. And then we actually don't have the next piece of infrastructure expansion until the back end of the 5-year plan, which is also in Pipestone. But Mike, maybe you have a few comments about Pipestone.

[Michael McAllister, executive]

Thanks, Doug. Yes. So the Pipestone liquids hub comes on in Q4. That contributes to -- it contributes to the growth. It represents about -- sort of in range about 25% of the liquids production that we'll be seeing in that quarter, coming out of the Montney. Our well results in Pipestone have been really, really encouraging. And we have actually tested 2 other benches in Pipestone, over and above the Montney G, which again, give us a lot of confidence in that asset's ability to grow.

[Greg Pardy, analyst]

Okay. Perfect. And then maybe just -- the second one is for Renee, but just on the T&P side, like on a unit basis, should we be thinking about that number as being relatively stable from here on out? Or is that a number that potentially continues to drift up on a unit basis?

[Michael McAllister, executive]

Yes, Greg. I think that just as a reminder and Renee will fill in the details here, but we started that service to Dawn late in '17. And actually, the service out on the AECO pipeline to Houston officially starts in April. We've actually started to [ flow down ] it early, which is tied to the Vitol sale. But Renee, maybe you fill in the details here.

[Renee Zemljak, executive]

Yes. Thanks, Greg. We do expect the transportation cost on per unit basis to stay pretty steady as we go forward. That being said, we'll consider -- we'll continue to look at opportunities to expand our margin through transportation as we diversify our market. As an example maybe, for the Permian as our gas volumes are growing, you might would see us later look to take an additional transportation if that made sense. Our transportation that we have added to the portfolio has extremely expanded our margins. The cost to access markets, as you can see on the transportation, has added about an extra dollar on a per BOE basis. But we do get a $2 uplift in our realized gas prices, which gives us an expanded margin of about $1. So we will continue to look at -- for opportunities like that to add to our portfolio.

[Operator]

And our next question comes from the line of Brian Singer from Goldman Sachs.

[Brian Singer, analyst]

Doug, you spoke to the benefits to free cash flow from $55 WTI, relative to $50. And looking at today's prices and environment, that's certainly understandable. Wanted to see, are you shifting your outlook in longer-term planning assumptions to $55 or just highlighting the near-term impact -- the 29 impact at that price?

[Douglas Suttles, executive]

Yes, Brian. To be real honest, I'm not sure that we can tell that much of a difference fundamentally between $50 and $55. We're encouraged by the recent trends. Our internal view is we expect crude prices to generally strengthen towards the end of the decade, but the pathway there could be pretty bumpy. So I think what we're just trying to reflect is kind of current market conditions and actually show what it could do. The other thing we didn't highlight too much on the call was is, we have a pretty large hedge book in 2018 now. So we're not really exposed to too much volatility in the commodity prices over the balance of the year.

[Brian Singer, analyst]

Okay. And then, you talked about the back end loaded growth profile this year, partly on declines from flush wells brought online in the fourth quarter. Can you talk more about how the decline rates from your liquids-rich Montney wells, and the production mix there performing versus your expectations? And then, in the Permian, how decline rates from the wells using the cube strategy are coming in versus your expectations?

[Douglas Suttles, executive]

Yes, Brian. Good question. I'll ask Mike to comment. But I think that the shape of the year, it looks a little bit like last year, but not as extreme. Partly, it's just due to couplings. One of the things I know we've talked to you about before is, our goal here is to create the maximum value. So we kind of think about this as how do you maximize returns and recovery. And that can lead to some lumpy behavior, because we can -- if we bring a couple of cubes on at the end of one quarter, the next quarter looks particularly strong. And if we skip a quarter in that because of the schedule, it flattens out some -- but it generates the best value. And then of course, similar to last year, we do have in the Montney some infrastructure coming along. But, Mike, maybe comments on both liquids-rich Montney well performance and cube well performance in the Permian.

[Michael McAllister, executive]

You bet. Brian, yes, so just -- I'll start with the Permian. So the number of wells that we've brought on that reached their peak production in Q4 was actually double than what we would have seen in Q3. So we had lot of production coming on and we'd be seeing for the first year decline rates that has that impact in the first half of 2018. That being said, we're very, very pleased with the performance of those wells, with our tighter cluster spacing. We've seen significant improvement over where we were on type curve. When I look at the Montney, again, well performance there has been stronger than we had planned. In fact, we're seeing higher condensate rates than we actually had in our type curve. So again, a lot of confidence from that standpoint as well. It's a function of the wells coming online and the -- filling the available facility capacity in the Montney that drives the profile that you're seeing there.

[Brian Singer, analyst]

Great. So you kind of call this normal course, inline decline rates than just the timing as you described for [indiscernible].

[Michael McAllister, executive]

Yes. You bet. And I just -- I wanted to add one other point that I think I'm particularly proud of. We really focus our field operations on managing the base, and making sure we're offsetting our base decline as much as we possibly can through the artificial lift optimization and really attention to detail in terms of managing downtime, and we had a significantly strong year in 2017. We beat our base production by -- I think we had budgeted sort of 38%, and brought that in at 34%. The teams did a, I think, a fantastic job there.

[Operator]

And our next question comes from the line of Gabe Daoud from JP Morgan.

[Gabriel Daoud, analyst]

Doug, you hit on this in your prepared remarks, but could we maybe just talk a little bit about buyback versus increasing the dividend today, and how you would kind of rank increasing dividend versus buying back additional shares? And then also, how this program potentially impacts how you think about M&A?

[Douglas Suttles, executive]

Yes, Gabe. Yes. Good question. So -- I mean, as I outlined, we really see -- as the business begins to generate free cash and additional financial capacity, the 3 big buckets. And the last one I listed in the prepared remarks was about resiliency. We feel we're in pretty good shape there. We've got our debt. It's come down dramatically. We like where the leverage is going. On a run-rate basis, we ended the year at $1.9 billion. Our plan would have ascending it at about $1.4 billion, so well within our range. When we look at how we're protected with a combination of market diversification in our hedge book, so we feel like [indiscernible] pieces in a good place. So doing things like buying back commitments or debt doesn't look particularly attractive right now. When we look at the combination of buybacks versus dividends, the one thing we're very aware of when -- if we raise a dividend, we don't want to pull it back again. So as we think about it, 2 things we're watching is as commodity prices, as we see how they play out kind of related back to Brian's question. They are still volatile. The market's trying to find its rebalance point. And the second thing is, is as the business -- the cash flow's growing pretty dramatically. But clearly, we want to be very confident that it's there and is going to continue to grow from there, which is combination of performance and pricing before we do that. So we've always stated we're committed to the dividend, but we looked at it carefully. So we think the buyback program is prudent. And then lastly, on anything we do with the portfolio, what we said is, is it very clearly has to be accretive to the 5-year plan. And if it's not, it wouldn't make any sense. And that's a fairly high bar if you think about our portfolio and our development plan. So we went through that. It had lots of debate and discussion -- great discussions with our board. We came to the conclusion that the best choice today was a modest buyback program and that's why we picked it.

[Gabriel Daoud, analyst]

That's helpful. And then, I guess just sticking with the bigger picture question, can you talk a little bit about the San Juan and expectations there? And just any update on what you're thinking on that.

[Douglas Suttles, executive]

Yes. Gabe, we probably sound like a broken record when it comes to portfolio decisions. We just have a very strong view that it doesn't really make sense to talk about portfolio changes until you do them, and we've been very clear. We like the San Juan asset, the wells we drill last year, the 6 wells. The 5 in the key producing zone have performed very well, and at or above our expectations. And ultimately, we will decide whether we're going to develop this asset or exit it. But that decision, you'll see it either in our development program capital or if we had a purchase and sale agreement, we think that's the best way to manage a business. In the meantime, the -- that piece of the business producing approximately 5,000 barrels day to day, and well performance is strong. And our operating teams out there doing a great job of maintaining efficiency.

[Gabriel Daoud, analyst]

Perfect. I'll just end with one more, if I could. Just on '18 CapEx, how much of the budget is, I guess, earmarks for midstream, I guess, particularly, in the Permian? And then, the $5.6 million of D&C in the Permian, is that a current [ AFE ]? Does that assume savings from -- in basin sand?

[Douglas Suttles, executive]

Yes. Gabe, really, the only spend we have in the midstream is a little bit to do with our water infrastructure. But it's quite small this year. I mean, we don't -- one of the things I'm really pleased about is with kind of our innovative approach to how we manage things like water. We've been able to that very cost efficiently. And that -- those D&C costs are expected for the year. And as Mike mentioned, we have approximately 80% of our services across the portfolio, not just in the Permian already under contract. It was under contract before we entered into 2018. And actually, the other thing that gives us confidence, that equipment is on an Encana location right now working. So this isn't stuff we're going to mobilize, which you have risk with availability and crude performance. It's on a location today operating effectively. And there is -- in some of those services, there is increasing pricing. But I think as Mike mentioned, in other areas, we see efficiency savings. In the Permian as an example, both sand and water cost are dropping in '18 over '17. And we're absolutely certain that's going to occur. It's either under contract or it's a result of what we've done with our water management activities. So that's what gives us confidence that on a like-for-like well, we can hold them flat, because even though there is inflation, we have other areas we can offset that inflation with efficiency.

[Operator]

And our next question comes from the line of Josh Silverstein from Wolfe Research.

[Joshua Silverstein, analyst]

Just wanted to reconcile some of the stuff you were talking about on free cash flow and the direction of the different operating units. You talked about $700 million roughly in 2019 in the Montney. And I'm assuming you guys were talking about roughly a flattish outlook for the Duvernay and the Eagle Ford, which gets you to the roughly $1 billion of free cash flow next year at those 3 operating units. Should we assume that the Permian is roughly flat from there, and there's roughly $500 million of taxes and expenses. Is that how you guys are kind of looking at 2019?

[Douglas Suttles, executive]

Yes, Josh. And I'll give you a big frame and if you need to, you may have to follow up with Corey and the team. But yes, one of the things we were trying to highlight there is, as we exit '18, we've essentially reached our target production level in the Montney. The only thing that happens until late in our 5-year plan is just a small increase in liquids production as some of our dry gas wells decline and are replaced with richer gas wells. And then, if you will, the maintenance capital, not a phrase I'm particularly -- like, but the maintenance capital is quite low. So what we're showing is, even using an AECO basis of $1.50, this asset throws off a lot of free cash through the period. And we saw this coming. And in fact, it's in the corporate deck. It's online. We still have some of the carry from our deal with Mitsubishi, extends now into 2019 as our efficiencies continue to improve, which helps with that as well. And then as Mike mentioned, we're running the Duvernay and the Eagle Ford as free cash positive assets. The Permian is actually ops cash flow positive this year. So our capital is less than our ops cash flow, while we're growing at 30%. I'm not sure many people can say that about their Permian asset today. And then, the last piece of the puzzle there is actually, what we committed to a few years ago is as we grew, we would keep our corporate cost flat or declining, which means our corporate margin expands. And that's exactly what you're seeing as we go from '18 to '19, is that the corporate cost we're projecting basically stay flat. And as the volume grows, it means the margin expands.

[Joshua Silverstein, analyst]

Okay. It kind of reconciles to the financial number there then. Got it. Okay.

[Douglas Suttles, executive]

Yes. And then the other, it's back to one of the earlier questions. When we were in October, we showed that with a price deck of $53 and $1.20. What we've said now is, if you use $55.30 and $1.50, so we widen out basis in that forecast and you get yourself to the $500 million -- approximately $500 million next year.

[Joshua Silverstein, analyst]

Great. And then I just wanted to follow up on the leverage capacity target for your -- that you were referencing earlier that you could be at 1.5x and then have an additional $1.5 billion of financial leverage at that point. Is that at the end of this year that you could then use for additional share repurchases or dividends to stay at that leverage? Or is that over time that you can use that?

[Douglas Suttles, executive]

Yes. That's actually cumulative. So if you stand at the end of the 5-year plan, if you look at the free cash generated over the 5 years, which is about $3 billion. And then you look at where our leverage would be at that point, which actually -- this was true back in the October Investor Day. We didn't highlight it, but it was embedded in it, is we've actually become significantly delevered. And we've been very public about saying it, mid-cycle pricing, very similar to what I'd say is today's price that a leverage of 1.5 is about right. So if you then say -- add that in, that's another $2 billion, and that's how you get to the 5. So $3 billion of free cash flow over the 5-year period. And then $2 billion of financial capacity you have available at the end of the 5-year period.

[Operator]

And our next question comes from the line of Menno Hulshof from TD Securities.

[Menno Hulshof, analyst]

So you mentioned a sale through Vitol into the European markets. And I might have missed it in the prepared remarks, but can you elaborate on the size of that transaction? How that deal was structured and finally whether or not, we can expect to see more of that in the coming quarters.

[Douglas Suttles, executive]

Yes, Menno. Appreciate that question. I mean -- and Renee talked about this, one of the things we put in place a few years ago is what we call a margin model. So every part of our business, every single quarter, we look at what the margins are doing. And what that drives is, is every corner of the Enterprise trying to maximize value. And as Renee highlighted, in some cases, we'll increase our T&P cost to get a higher realized price, which expands our margin. And in many cases, reduces our risk. And what happened here was, we had, I think, announced this last year that we had taken out service on the new Enterprise ECHO Pipeline to Houston. That line is now up and running. Our firm service begins April 1, I believe, but we had the ability to ship some crude down that line early. And then our marketing team was able to do a transaction with Vitol of Brent pricing on an exported cargo and it's 300,000 barrels. We will continue to look for those opportunities because we're always trying to maximize the margin that we get in the business. So where we can do that, we will. It's embedded in fundamentally our strategy in Western Canada. And I'll tell you another piece of the business, so you remember, we still have our REX pipeline commitment. But through this winter, we have that capacity and we've been able to purchase gas in the Rockies and sell it into Chicago and make a margin on that production. And this is all part of our margin model, which is all driven off value. And it's actually one of the reasons why I suspect, we had such a big cash flow beat in the fourth quarter.

[Menno Hulshof, analyst]

Okay. And then, just wanted to follow up. Moving on to Duvernay, I believe you mentioned your capital carry has gone down in that place. So does that change at all how you look at the play in terms of commitment levels longer term?

[Douglas Suttles, executive]

No. It's -- in our 5-year plan, it's always been there, and in fact, when we talked about it being a core asset, we said that was based on a heads-up analysis, not as a function of the carry. The net impact though in the short term, beginning in '18, is our net capital is going up year-over-year in the Duvernay, even though the gross activity is slightly lower, is just because we're now heads-up. But as Mike mentioned, one of the things about that asset, which emphasizes the quality of it is, it's free cash positive. So even though, on a heads-up basis, it's roughly -- its production's roughly flat, and it's generating free cash flow. Because this asset has margins that are just a little bit below the Permian at today's prices, and I think that might surprise people, but the margin per barrel in the Duvernay is only a few dollars behind the margin that we realize in the Permian. And remember, we're paying about 5% royalty in the Duvernay versus 25% in the Permian.

[Operator]

And our next question comes from the line of Benny Wong from Morgan Stanley.

[Benny Wong, analyst]

I think most of my questions have been asked. But one thing I did wanted to ask was about the buyback. Just wanted to get a sense of how you guys came up with -- came to $400 million. Is there a target or a payout ratio or a cash balance sheet you're targeting? And also, how you're thinking about the pace of it? Do you think you'll be pretty ratable, or you do think you can be a little bit opportunistic around it?

[Douglas Suttles, executive]

Yes, Benny. What we really looked at, there's a whole series of things you have to assess and then through that, drive a lot of judgment. And this is where, for instance, the experience and judgment of the board is particularly useful to us. And what we did is, looked at a combination of financial capacity to leverage the amount of protection we had on the confidence in the business. And through that said, this felt appropriate. It's $400 million of $5 billion. It feels quite reasonable. We also don't -- aren't exposed to very much price volatility this year, and we're comfortable on our current leverage and where we expect it to end at the end of this year. So we looked at all of that. That's how we got to that number. In terms of the execution, there are rules around how you do that. We'll be disciplined about that process. We have every intent to execute the program. But with our broker-dealer, we'll obviously try to optimize that program as best we can to generate the best value for our shareholders.

[Benny Wong, analyst]

Great. And maybe just a nitty question around your '18 CapEx. If my math is right, If I add up the D&C spend across the core plays, it's a little under the $1.8 billion, $1.9 billion. Just wondering if you can maybe bridge the difference there. I'm assuming some of it's towards the Montney infrastructure. Just wondering if there's anything else you're spending on as well.

[Douglas Suttles, executive]

Yes. There's not much else there. I mean, we have a little bit of the Pipestone infrastructure, and then we have capitalized G&A. It's kind of the remaining pieces inside that. But one of the things we've been really pleased about, what we've been able to do is grow the business, have competitive returns and margins and not have to put a lot of money into the midstream. And that's been very successful for us and we have every intent to continue doing that.

[Operator]

And our next question comes from the line of Mike Dunn from GMP FirstEnergy.

[Michael Dunn, analyst]

Folks, just wondering if you could comment on, I guess, the lack of production interruptions due to cold weather in the Midland basin. Some of the other operators there had some freeze offs or whatnot late in the year, early in January as well. Do you have any significant issues in January, and maybe just talk to what you've done to mitigate that? I know obviously, you guys have lots of experience producing in cold weather regions.

[Douglas Suttles, executive]

Yes, Mike. I think part of this is actually our experience in cold weather regions. And if you look at our Permian team, it's an interesting mix from skills across the company. In fact, a lot of the members of that team actually came from our Piceance asset, who are very, very used to managing cold weather and freeze offs. And actually, our operations manager for the Permian is from Alberta. So I think this is something that we have some particular expertise in and can anticipate. Because actually, people in some parts of the country may not realize this, but you get freezing weather in West Texas every year and it actually snows almost every year. And in fact this year, we had ice storms in South Texas in our Eagle Ford asset. So it's really this whole concept about moving the knowledge in the business all around the portfolio because if you operate in British Columbia and Alberta, you better be able to deal with freeze offs. Otherwise, you wouldn't operate very well.

[Operator]

Ladies and gentlemen, that concludes our question-and-answer session. I will turn the call back to Mr. Code.

[Corey Code, executive]

Thank you very much, everyone, for joining us on the call. That concludes our call for today.