Ovintiv Inc. (OVV) Q4 2014 Earnings Report, Transcript and Summary

Good day, ladies and gentlemen and thank you for standing by. Welcome to the Encana Corporation’s Fourth Quarter 2014 and Year-End Earnings Results Conference Call. As a reminder, today’s call is being recorded. At this time, all participants are in a listen-only mode. Following the presentation, we will conduct a question-and-answer session. [Operator Instructions] For members of the media attending in a listen-only mode today, 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 rebroadcast without the express consent of Encana Corporation. I would now like to turn the conference call over to Brian Dutton, Director of Investor Relations. Please go ahead, Mr. Dutton.

Thank you, operator and welcome everyone to our fourth quarter and year-end 2014 results conference call. This call is being webcast and the slides are available on our Web site at encana.com. Before we get started, I must refer you to the advisory regarding forward-looking statements contained in the news release and at the end of our webcast slides, as well as the advisory on Page 40 of Encana’s AIF dated February 20, 2014, the latter of which is available on SEDAR. In particular, I’d like to draw your attention to the material factors and assumptions in those advisories. Encana prepares its financial statements in accordance with U.S. GAAP and reports its financial results in U.S. dollars and protocol. Accordingly, any reference to dollars, reserves, resources or production information in this call will be in U.S. dollars and after royalties, unless otherwise noted. This morning, Doug Suttles, Encana’s President and CEO will provide the highlights of our fourth quarter and full year 2014 results, as well as our revised spending plans for 2015. Sherri Brillon, our CFO will then discuss Encana’s financial results and revise 2015 guidance in greater detail. Lastly, Mike McAllister, our COO will provide an update on our current and recent operating activities before we open the call up for Q&A. I’ll now turn the call over to Doug Suttles.

Thanks, Brian, and thanks everyone for joining us today. I would like to take a few minutes to summarize the year in which we met or exceeded all of our strategic goals that we set for 2014 and we positioned the company favorably going into 2015. Today we are clearly better positioned than a year ago to weather the current weak oil and gas price environment. The cornerstone of our strategy is to sustainably grow cash flow per share and maintain a strong balance sheet. As we entered 2014 with our new strategy in place, we quickly resized the organization reducing our workforce by about 25% and captured approximately $150 million of enduring operating, administrative and capital cost savings. Consistent with our focus on higher margin production, we invested approximately 86% of our 2014 capital in seven growth assets. Down from around 28 assets in 2013. This focus helped generate approximately $400 million of free cash flow in 2014. We will intensify this focus in 2015 and direct around 95% of our capital on our growth assets. One of our most important strengths is our focus on operational excellence. In 2014 we delivered a 50% reduction in year-over-year drilling and completion cost in the Duvernay, 100% improvement in IP30s in the Montney. And since acquiring the Eagle Ford assets in June of 2014, we achieved a 25% improvement in IP30 rates. Mike McAllister will cover this in more detail later. In addition to our ground-up focus on operational excellence, we transformed our portfolio replacing low margin dry gas with high margin liquids. You can see evidence of this in our 2014 cash flow which is up 14% year-over-year even with a 7% reduction in total production and substantially similar oil and gas prices compared to 2013. Today, with our acreage in the Permian, Eagle Ford, Montney and Duvernay, we believe that we are positioned in the best parts of the best plays in North America. Equally important, our accomplishments in 2014 reflect a cultural transformation and a mindset that will intensify making Encana a more focused, competitive and resilient company. We are particularly proud of our safety record last year. In 2014, we delivered our best safety performance ever which is even more impressive when you consider the amount of change that was happening across the company. Consistent with our strategy, we expect to invest about 80% of our 2015 capital in our most strategic assets, the Permian, Eagle Ford, Montney and Duvernay. These four assets are for high-quality resources with good margins at $50 WTI oil price and a $3 NYMEX gas price. They offer robust supply cost, significant running room with scale to further accelerate operational efficiencies through Encana's resource play hub development model and good market access. When we announced our guidance in December, we based our programs on a $70 oil price and a $4 gas price. However, we said if market conditions change, which they were doing quite rapidly at that point, we would make appropriate adjustments. In recognition of current prices, we are acting decisively and prudently by reducing our 2015 capital budget by about $700 million to $2 billion to $2.2 billion. This is based on our revised planning assumption of a $50 WTI oil price and a $3 NYMEX natural gas price for full-year 2015. Our 2015 spending plans plus anticipated dividends are expected to be fully funded by forecasted cash flow and proceeds from previously announced asset sales. Both of which are supported by increased oil hedges. Maintaining an investment-grade credit rating is central to our plans. Before turning the call over to Sherri and Mike, I thought I would touch upon some of the highlights of our 2015 program. As we continue to focus on growing value over volumes, we expect that companywide production volumes will decline in 2015 compared to 2014. However, given our focused capital allocation on our most strategic assets, we anticipate that total production from our Permian, Eagle Ford, Montney and Duvernay assets will increase from an average of 183,000 barrels a day in the fourth quarter of 2014 to at least 240,000 barrels oil equivalent per day in the fourth quarter of 2015. Even if current low oil and gas prices persist through the end of the decade, these four assets are still capable of profitable, growing production. We expect to see strong companywide liquids growth in 2015, up approximately 60% year-over-year with an annual average of between 130,000 and 150,000 barrels per day. About 65% of our 2015 liquids production is expected to be high-value oil and field condensate. One of the key drivers of this growth will be production from our newly acquired Permian assets which we expect to produce at least 45,000 barrels of oil equivalent per day on an annualized basis. The drive to continuously improve efficiencies is embedded in our business model and our culture. Given the current environment, we believe that there are new opportunities to capture even more efficiency improvements. With this in mind, we are budgeting a further 15% improvement in capital cost efficiencies in 2015. Our focus on base optimization should also generate approximately $75 million of direct operating cost savings. We also see an opportunity to make further improvements in our corporate cost structure. I will now turn the call over to Sherri.

Thanks, Doug and good morning everyone. As Doug mentioned, Encana delivered tremendous performance in 2014 while undertaking major portfolio and organizational changes. In the fourth quarter we achieved oil and NGL production growth of approximately 60% year-over-year and generated roughly two-thirds of upstream operating cash flow including hedging from liquids. Our base assets outperformed expectations as our team is focused on minimizing natural declines through various optimization projects. When adjusted for acquisition and divestiture activities, we reduced our base declined rate from 34% to 29%. We achieved total operating, administrative and capital cost savings of approximately $150 million attributable to workforce reductions and operating efficiency. These cost savings more than offset the transition and reorganization cost incurred in 2013 and '14, positioning the company well in a challenging commodity price environment. We generated about $400 million of free cash flow in 2014 and maintained a solid balance sheet by signing about $9 billion in acquisitions largely with proceeds from divestitures as well as cash on hand. Totally year cash flow of $2.9 billion or $3.96 per share was up 14% year-over-year. This was a direct result of our strategic initiative to focus capital on our highest margin assets. Although our 2014 cash flow came in below guidance, this was not due to operational issues or cost performance. In fact liquids production in the fourth quarter averaged 106,000 barrels per day, at the upper end of our guidance range of 102,000 to 107,000 barrels per day. Instead, it was largely due to one-time items related to the Athlon transaction and early repayment of Athlon senior notes, as noted in our December guidance conference call. As well as wider than expected pricing differential, including weaker than expected Deep Panuke pricing and the settlement of a prior period tax amount in the fourth quarter. While the one-time charge related to the Athlon debt redemption had a negative impact on our fourth quarter cash flow, we expect to save approximately $515 million of future interest expenses associated with those notes. Otherwise, our 2014 guidance targets were largely met or exceeded with strong operational results in a transformational year. With our results this morning we also announced our reserves and resources as of December 31, 2014. Our reserve base continues to align with our strategy. Consistent with our focus on value versus volumes, we grew higher margin oil reserves while lower margin natural gas reserves were sold or declined. Proved oil reserves were up about 150% year-over-year and proved plus probable oil reserves were up about 360%. Our reserves evaluation also reflects the disciplined allocation of capital to our growth plays. Thus, the majority of the 2014 reserve revisions relate to a reduction in our previously planned CapEx on the PUDs outside of our growth plays. Although total reserve volumes are down 23% year-over-year on a proved basis, they are down only 4% on a proved plus probable basis. The new volumes are more valuable because they are more heavily weighted to higher margin oil. Additionally, the vast majority of the reserves and resources associated with our Permian Oil acquisition have been booked in our P2 and 2C number while very little was booked under proved reserves. Reflecting the transition of our asset base to higher margin liquids production, at the end of 2014, crude oil and NGLs increased from 15% to 38% of 2P reserves year-over-year. Similarly, on a 2C basis, our oil and NGL resources increased from 10% to 21% of our total economic resources. For oil alone, our 2C volumes grew 143% year-over-year. The only significant negative performance revision from our 2014 reserve evaluation that was associated with the earlier than expected water production rates that we experienced at the Panuke. Year-end proved reserves for the project were about 80 Bcf. For the first six weeks of 2015, Deep Panuke has been producing at a rate of about 180 to 200 million cubic feet per day consistent with the seasonal production cycle that we intend to implement on the platform to maximize the cash flow from that asset. Maintaining our balance sheet and investment grade credit rating are important aspects of our strategy. We are prudently managing our debt levels as our 2015 capital spending plans and our anticipated dividend payments are to be fully funded by our expected 2015 cash flow and the proceeds that we receive from previously announced divestitures. We recently implemented a $2 billion U.S. commercial paper program and have drawn approximately $1.1 billion which we used to fully repay the outstanding balance on our revolving credit facility. We have revolving bank credit facilities of $3.5 billion in Canada and $1 billion in U.S. committed until 2018, which provide us with significant liquidity. Our hedging programs is designed to protect our capital program from downward commodity price moves and to mitigate the risk of inefficiencies developing during times of high price volatility and uncertainty. As of February 24, we had about 1 billion cubic feet per day of our expected 2015 natural gas production hedged at an average price of $4.29 per Mcf and about 55,000 barrels per day of expected oil volumes hedged at $62.18 per barrel. We are actively managing our balance sheet, exercising capital discipline and taking the necessary steps to ensure that we have ample liquidity and financial flexibility to see us through a lower commodity price environment. To prudently respond to the current low commodity price, we have reduced our previously announced 2015 capital program by about $700 million to about $2.1 billion at the midpoint of our guidance range. The midpoint of our revised cash flow guidance range at about $1.5 billion combined with the divestiture proceeds of about $800 million from transactions we have already announced is expected to fully fund our capital program plus anticipated dividend payments of about $200 million. As you can see in the chart, the vast majority of the change in our 2015 projected cash flow is due to the drop in commodity prices. Our guidance assumes $50 per barrel WTI oil prices and NYMEX natural gas prices of $3 per million BTU. There is also less significant impact from volume reductions and lower expected pricing at Panuke. Somewhat offsetting these factors are positive impacts from the change in the assumed exchange rate and expected cost reductions. The decreased capital program has a relatively minor impact on production volumes as gas volumes remain unchanged from our previous guidance and liquids volumes are about 7% lower based on the midpoint of guidance. Compared to 2014, we are projecting oil and NGL growth of about 60% year-over-year based on the midpoint of guidance. Although total production is expected to decline by about 14%, our margin is improving. In fact, even if $50 WTI and $3 NYMEX persist into 2016, we expect to see our cash flow grow as the percentage of higher margin production from our four most strategic assets becomes even greater in our portfolio. I will now turn the call over to Mike McAllister.

Thanks, Sherri. There is no better indicator of the quality of our operational teams and the fact that they delivered impressive operational performance in 2014 while spending less than 2013. They also delivered our safest year in the company's history while our portfolio was undergoing major changes. Before I talk about our four most strategic assets, I want to explain that operational excellence means to me or why it's fundamental to Encana's competitiveness. Operational excellence means safely delivering the best wells and the best base performance for the best value. Consistent with our strategy, we aim to be the most efficient and competitive operator in our plays. This means driving maximum value for every dollar invested, sharing innovative optimization strategies across the company and ensuring we get the best value from our service providers. Over the last several months we have been actively and methodically working with our suppliers to reduce cost across the portfolio. And in some areas we are realizing cost reductions of greater than 50%. This operational focus supports one of our strategic goals of building a high performing, cost-efficient company that is resilient through the price cycle. We saw the impact of this relentless focus in 2014 through strong liquids growth, reduction in base decline rates and significant cost efficiencies. We achieved this while oil traded at around $100 per barrel. Our achievements in 2014 reflect the cultural transformation of Encana. Our employees drove these achievements from the ground up. It's what they do and how they think. As we enter 2015, we will build off our momentum, seizing the opportunity offered by lower commodity and price environment to deliver further efficiencies and enhance operational performance. This is what operational excellence means to Encana. The Permian is a perfect example of how we're trying to take advantage of the challenging market conditions which our industry is facing. When we first announced the Athlon acquisition, the market expressed concern on whether or not we would be able to retain staff and get services required to grow the high quality asset. Clearly current market conditions are helping us. We successfully retained the majority of the Athlon staff and we have been able to attract a number of new, highly talented technical professionals to our Permian team. In 2015, the main focus of the Permian team will be improving well performance, reducing cost, consolidating supply chain and everything midstream and marketing solutions. Consistent with our achievements in the Eagle Ford last year, in 2015 we expect to deliver significant cost reductions in the Permian through implementation of Encana's best practices in developing resource plays. Specifically, we expect to be delivering increased operational efficiencies, optimize well designs and realizing better value from our suppliers. Total capital for the Permian in 2015 is expected to be about $700 million. We are currently running six horizontal rigs and expect to average 4 to 6 horizontal rigs throughout the year. We expect to drill about 55 net horizontal wells in the Wolfcamp and Sprayberry. In addition, we anticipate running 46 vertical rigs consistent with our lease obligations. 2015 production is expected to average at least 45,000 BOE per day. In the Eagle Ford we have achieved significant operational improvements since we acquired the asset in the second quarter of 2014. Our IP30 rates have improved by an average of 25%, largely due to enhanced completion design as we product tested tighter cluster spacing and increased volumes of sand per stage. We continued to improve drilling cycle times, that’s spud-to-rig release. When we acquired the assets in June 2014, average cycle times were about 15 days. By the fourth quarter, we were about 25% at an average of 11 days, Spud-to-rig release. In addition, as a result of well design optimization, reduced cycle times and lower service cost, we reduced drilling cost by about 10% over that same time frame. We were particularly pleased with the results we saw from our base optimization efforts during the fourth quarter. In addition to optimization activities such as gas lift, plunger lift and field compression, we successfully executed two well refracs in the play. Realized an oil production increase on a per well basis of about 450 barrels per day on IP30. The team is currently assessing the refrac potential of over 100 existing well on our Eagle Ford asset. Through 2015, we will continue to focus on improving well performance, reducing well cost and optimizing base production. We are planning to drill about 16 net wells in the Eagle Ford, mainly in the [Kennedy] [ph] area. Production from the Eagle Ford is expected to average 50,000 BOE per day and total capital is expected to be about $550 million. We plan to be running two to three rigs in the play this year. The Montney delivered impressive annual liquids growth of 87% year-over-year to 19,000 barrels per day in 2014. We continue to successfully implement high intensity of completions in the Cutbank Ridge and Peace River Arch parts of the play. In Dawson, the high intensity of field completion wells produced an average of 100% above our prior type curve expectations. Our teams are now looking to advance completion designs even further by testing larger fracs. In Gordondale, we tested reduced inter frac spacing which resulted in an initial production being about 73% higher than expected over the first 60 days. In Pipestone, we completed 8 high intensity completions in the second half of the year and we expect to bring these wells on production in the first quarter of 2015. The performance from the base and higher intensity completions exceeded our expectations and coupled with the deferral of major facility construction, we delivered $150 million of reduced capital spending in 2014. In December of 2014 we signed a unique deal to divest of the majority of our infrastructure in Cutbank Ridge. This transaction unlocks the value from our existing midstream infrastructure while allowing us to continue operatorship of future facility construction. This transaction also enables us to redirect about $500 million of future capital towards higher rate of return drilling projects. We expect to invest about $245 million on a net basis and run three rigs in the Montney in 2015. We expect to drill about 25 net wells and produce an average of 124,000 BOE per day net to Encana. Our operational performance in Duvernay through 2014 was impressive. In 2014 we targeted significant well cost reductions in the Duvernay. Our goal was to achieve average well costs of $15 million on a multi-well pad. Our results were impressive. We drilled four multi-well pads and achieved average well costs of less than $13 million. In fact our best wells came in at $12.4 million, exceeding our target by 17%. We successfully reduced drilling cost by 38% year-over-year through a combination of well bore design optimization, the application of fit for purpose equipment and the implementation of Encana's resource play hub development model. We delivered a Pacesetter well at [16026] [ph] where we drilled 18,500 foot measured depth well in 24.5 days for a cost of $3.7 million. This is 16.5 days faster and $4 million cheaper than our 2013 average. We expect to reduce drilling cost in Duvernay further, by a further 13% in 2015. With respect to completions, a number of factors contributed to the 42% year-over-year reduction in costs such as completion design optimization, lower service cost and lower water cost. Our 2015 development program will continue to focus on the Kaybob and Simonette area. We expect to average two to three rigs for the year and drill about 15 net wells. The Duvernay team is going to execute on about a $230 million capital program with most of the capital focused on drilling completions activity. There is one additional plant phase scheduled to come online in Q3 of '15 and another one in Q1 of '16, increasing production capacity by 100 million cubic feet per day. I will now turn the call back to Doug Suttles.

Thanks, Mike. Our strategic and operational accomplishments in 2014 were tremendous. We established a track record of delivery and a strong bias for action. Encana is now stronger in every point of the price cycle. That said, I believe we are just getting started. We have the necessary ingredients to deliver sustainable shareholder value and we will build on our momentum through 2015. We will seize the opportunity presented by current marketing conditions to further evaluate our portfolio, ensuring that we are focused on high margin production in our most profitable businesses. Equally we see the opportunity to deliver efficiencies to our supply chain and our administrative cost as well as all aspects of our operations. We will intensify our capital discipline, investing about 80% of our expected 2015 capital into our four most strategic assets. These assets deliver strong margins in the current price environment and while we don’t feel it's likely, should current low oil prices continue for some time, these assets can continue to deliver sustainable cash flow growth. We will continue to drive operational excellence and have embedded capital and operating efficiency improvements in our 2015 budget. We do this with the knowledge that based on a $50 WTI oil price and $3 NYMEX gas price, our 2015 capital program and anticipated dividends are fully funded. In closing, we will continue to proactively and prudently manage the company in 2015. In parallel, we will be ready to seize opportunities if they serve the best long term interest of our company. The diligent and rigorous preparation and evaluation has served us well through 2014 enabling us to be agile and capture several value enhancing opportunities, will also serve us well through the current volatility commodity price environment. We have a highly driven culture and a proven ability to act decisively. Consequently, if anyone can prosper through this part of the commodity cycle, I am convinced it will be Encana. Thank you. And I think myself and my entire team are here and prepared to take your questions.

(Operator Instructions) Greg Pardy of RBC Capital Markets. Your line is open.

Doug, I think you touched on a little bit in terms of seizing on opportunities but is it your view that beyond the $800 million of dispositions that you have essentially already done, there may be further opportunities to sell assets this year.

I guess, Greg, is this just between you and me?

It is. Nobody else is listening, so...

All right.

Speak freely.

Okay. Well, Greg, I guess I would just back up a bit. I mean when we launched the strategy in the fall of '13, one of the things we said we thought was very very important to being very efficient was to have a focused portfolio. And you saw that most significantly, first, in going from funding 28 assets down to seven. Secondly, at that time we said we were long on gas and if the market was favorable we would reduce our number of gas positions and look to use the proceeds to accelerate our transition to a more balanced portfolio. We did all that. But I can tell you, we do have a bias to a very focused portfolio. We think that allows us to not only be lower cost, it allows us to be more efficient. And to be, if not the most efficient player where we are, amongst the very best. So we will have to see if there are opportunities to do that. The plans and the guidance we have given you today doesn’t assume anything beyond the divestments we have previously announced. And I should say that of course one of those is already closed. They did it at the end of January which accounts for more than half of that $800 million. So we will see what it is. I think we are well prepared to act in that. And I would actually say to you that action maybe tactical and it even maybe strategic. In my experience and knowledge of the history of the industry, it's the low point in the commodity cycle that are usually the most exciting times. And I can tell you we are prepared to respond if the right opportunities come along.

Okay. Thanks for that. Maybe just a question on the balance sheet for Sherri. I mean obviously 2015 is a year where even if your debt levels don’t change much, there is obviously a pretty meaningful change in terms of cash flow. The leverage only goes in one direction. But if we look at 2016 right now, directionally, where would you want to see the balance sheet in either a debt to EBITDA or a debt to kind of cap ratio.

Hi, Greg. It's Sherri. As we actively managed our balance sheet this year, we expect to do the same next year. We are in a good position in light of the fact that we have been prudently reducing our capital budget and demonstrating capital discipline to create a full funded plan coming out of 2015. 2016 is a little bit early. The volatility that we are seeing in the market, it's a little bit difficult to assess where we might be at. What is important is that we maintain our financial flexibility through the year and that we maintain our investment credit rating.

Okay. Great.

Greg, I would just add a couple of quick thoughts. I think first is, I think Sherri highlighted in the call a bit earlier, but we have a lot of liquidity today. I would also say we have a lot of financial options open to us if we chose to access any of those.

Okay. Great. And maybe just to finish off with a couple of operating questions. Mike, you guys have had great success in terms of managing down the base decline rate. Where is the corporate decline rate approximately for '15? Still 25%, 28%?

It would be probably between, I would say, 28% to 31%, the decline rate. Probably closer to the 29%.

Yes. Greg, what's happened with the transition in our portfolio, as you know we divested fairly low decline assets last year. Places like Jonah. And as we are going into the early growth phase in some of these other assets, you know the front end part of that curve has got a bit of steeper decline. So the net-net of that is, the average base decline has risen a little bit year-over-year.

Okay. And last question from me. Just on the Duvernay pads that are slated to come on. Mike, can you just remind me, just what the trajectory looks like. How many would have come on in 4Q and then what you are envisioning during the first and second quarter?

Okay. So we have four pads, 27 wells total. And so none of those came on in 4Q. We ended up being short on frac water supply which we were able to resolve here in the fourth quarter. So the pads are just being fracked out here over 4Q and 1Q. But we would expect see these 27 wells coming on here over the next quarter, quarter and half.

Great. Thanks, all.

Greg, just one point. Mike kind of highlighted this in the call. If I back the tape up to this time last year on the Duvernay, you know we have been coming from a period where well cost were over $20 million. We said that we targeted $15 million on our first multi-well pads. We originally said we were going to do three, we actually did four in the year. And our target was $15 million per well where we said, headed towards a long-term target of 12. As you may have noticed from Mike's comments, we are actually getting pretty close to 12 already. In fact our best bad came in at an average cost of 12.4. So now the question is, how much lower can we go. Because clearly we have got to set a new target now.

And our next question comes from the line of Jeffrey Campbell of Tuohy Investment Research. Your line is open.

The first question I would like to ask is, you are putting most of the -- the most 2015 capital into the Permian, which according to the January corporate presentation has a higher basis supply cost than some of your other plays. Could you add some color on, I know Mike talked about a little bit on the preamble, but could you add some color as to why the Permian has emerged as the top of the pecking order for 2015.

Yes, Jeffrey. I think first of all if you look at it on a gross basis because you got to remember, the two plays in Canada, we have big JVs and we have big carries. When you actually account for that, the four plays are almost all, are taking very very similar levels of capital. The Permian a bit higher and the Duvernay and the Montney look a little bit lower. But that’s just because we have access to partner carried capital. And one of the reasons why the Permian is so attractive, it's got a very very good margin structure. Very good returns. And we expect, as Mike highlighted, significant improvements in cost efficiency this year as we put the practices we have deployed elsewhere and we showed the good early results in the Eagle Ford. As well as our resource play hub, sort of multi-well pad model. So we think this competes incredibly well for capital. Very low supply cost and very good returns even in this part of the cycle.

Great. Thank you. And kind of staying on the theme of costs. I mean Encana more than many other operators seems to have really strived for structural reductions in cost. So when you are looking at the margin enhancement from cost reductions that you are targeting at 2015. Can you estimate what percentage of that is durable and likely to persist when commodity prices improve as opposed to simply being trough service pricing that’s likely to face when commodity prices improve.

Yes. It's a great question. And clearly as much as I would like to think that we could keep $50 service cost, with price rebound we know we will give some of that back. But I would actually point you to 2014 where in every single play we saw significant improvement in cost efficiency fighting kind of headwinds, if you will, from high industry activity and high commodity prices. The biggest drive there is innovation. It's how we execute. It's new ideas, new technology and focus on the details. We are having that discussion now. But I would hope that at least half, if not two-thirds, of these efficiency improvements are sustainable even with higher service cost and a higher price environment.

Okay. Great. Thank you. And if I could ask one last quick one. Going to the Eagle Ford refracs, this sounds like a multi question, they are also around the same thing. First of all, is this an extension of the work that was first begun in the Haynesville. Can you provide any color on costs and returns specific to these Eagle Ford refracs. And finally, did these represent an improvement in the effective frac which I think the last time we discussed this, you said it was around 25% of the rock that was contacted.

Yes. I will make a couple of comments and ask Mike to build on it. But you are right, what we did is we took what we were doing in the Haynesville and have tested it now in the Eagle Ford. We are now looking to test it elsewhere in the company. This is part of the advantage of being in multiple resource plays, is we can look at these technologies and move them around rapidly. And Mike has designed his organization to be able to do that. I think our pace of exploiting these will be relatively slow in the short term because we actually think the technology is pretty immature in both the effectiveness and the costs could come down. I think Mike can reinforce this but I think our early refracs in the Eagle Ford were about $3 million and I think there is a lot of chance to get that cost down.

Yes. Thanks, Doug. Basically or probably a little bit over $3 million. We took a pretty deliberate approach on these two refracs, pulling the tubing out. Did some additional cleanouts as well as additional perforating and went in with our high intensity frac that was similar to our new wells. The results were very very encouraging. In fact sort of taking a 50 barrel a day well up to 650 barrels a day on an IP30. So very very encouraged by that. As we move forward, I mentioned we have got over 100 wells that might be candidates for this technology. But the trick with refracking horizontal laterals is diverting your fracs over the full lateral length. And I think we mentioned in the Haynesville and we have seen here in the Eagle Ford as well, it's probably the first 30%, 25% to 30% of that well bore that’s being stimulated. So the trick is, that’s from the [heel on] [ph], I should say. So, anyways, that’s kind of where we are at right now. Lot left to learn and apply to our other plays.

Our next question comes from the line of [Amir Arif] [ph] of [Investment Bank] [ph]. Your line is open.

Just a follow-up question on the refrac. Can you just tell us how long after the initial frac you did the re-fracs and how the decline rate curve looks after the refrac?

Yes. [Amir] [ph] I think that actually what -- conceptually what we are doing is going back into some wells that were drilled in the early portion of the plays when they had much less intense completion designs. So I think it has a little less to do with how long the well has been on production and what we think the effectiveness of the original frac stimulation. I think it's a little early to comment on the decline rates. I think we are still watching that to see what do we think the type curve really looks like over its life. That’s another reason why, as I said, we are going to move a bit slow here. The potential isn't going anywhere. We need to let the technology catch up and we need to learn a little bit.

Okay. Makes sense. Just one quick question on the Permian as well. Can you just let us know, how much acreage that will be held by production currently and where that sits at the end of the year based on your drilling plans.

Well, it think our vertical drilling program is designed to maintain our acreage and meet our lease commitments. You may recall when we announced the Athlon transaction that we said that that was the only purpose of our vertical program and that by 2016, end of next year, we thought we would have that complete. I don’t know the end of this year number but by the end of the next year it will all be held.

All held by production. Okay. And then one final question on the reserves. For the next reserve revisions that you highlight. Could you just break that out in terms of how much of that is price related versus performance related?

Yes, I will ask, David Hill to fill in here a bit. But it actually depends on which method you use. If you are using SEC, there wasn't much price related impact because it uses the trailing 12-months. If you use the Canadian protocol, it actually does have some. But, David, maybe you can help here.

Yes, I think after royalties, using the Canadian protocol, I think it was about 20 million BOE was the adjustment there on price.

Okay. So on the SEC one, if there was no price related provision can you just tell us where the 260 performance related revision was on the gas side? Or was it a specific asset?

Yes. We normally don't disclose specific assets but I think as Sherri mentioned here, we did have water encroachment there at Panuke and then our year-end reserves, the majority of that technical revision in Bcfs of about, 208 Bcf is the technical revision at Panuke.

Our next question comes from the line of Bob Brackett from Bernstein. Your line is open.

Question on JV fundings/the partner carry. What does that give you this year in terms of cash from third parties to spend and what will those balances look like at the end of the year?

Yes. I think that in the Duvernay, what's the carry here, the partner carry piece. About $420 million to $460 million. And I think in the Montney it's in the neighborhood of about $200 million-$240 million. We expect that with our current plans we will likely, and of course this is subject to agreement with our partners, but we will likely consumer most of the carry in the Duvernay next year or early 2017. The Montney carry extends basically to the end of the decade.

Great. And then a follow-up. Drilling locations left in the Eagle Ford, do you guys disclose how many locations you might have remaining?

Our supplemental information gives you some idea of that. That still has a range though because like others we are still testing down spacing in there and we have actually, as you will probably see, we have actually dropped the number of rigs we have in the Eagle Ford as we are managing through this part of the environment. But we do think that there is a reasonable inventory still left and I think Mike highlighted, actually our Eagle Ford position will grow this year in terms of production even with the pull back in the rig count.

Our next question comes from the line of Jeoffrey Lambujon of Tudor, Pickering, & Holt. Your line is open.

Just real quick on the capital program. In thinking about the flexibility there and the potential to change it throughout the year, how should we think about the allocation of any potential incremental spending? Would the four focus areas likely see an uptick or could the DJ, San Juan and TMS re-enter the picture? And is there anything to say on plans there currently in those three plays that weren't highlighted in the release?

Yes, Jeoffrey, good question. I think it would depend to some degree on scale. But at the moment I think if we were to deploy with some additional capital this year, it would likely go into the four. The margin structure on the San Juan and the DJ is very competitive but you do have to make choices particularly as we want to make sure we are managing our balance sheet appropriately. So I think the first protocol for modest increases in capital would probably be in the four and likely more specifically in the Permian, the Eagle Ford and some parts of the Montney, the liquids rich portions, would like be the first places we would go back to. I would actually say, we had great results in the DJ. It grew well through the year. It's got a good margin structure and we improved efficiency. San Juan, we have talked quite a bit about. Still have a bit of a challenge on the permitting side. Maybe this pause gives us some chance to catch up. But our well results and our cost are both going in the right direction. And I should even highlight the TMS. We set some big goals for ourselves in the TMS on cost and well performance. And I think we figured out how to effectively and cost efficiently drill these wells. We are now demonstrating we can routinely and at our target cost drill 10,000 foot laterals. And we are routinely seeing IP30s of 1000 barrels of oil per day. But in this environment it's prudent to take a pause there.

Okay, great. And then just on the Eagle Ford, specifically. The most recent EUR range you all provided was fairly wide. Just wanted to get your updated thoughts on the asset and how you view productivity in the 2015 drilling plan, just given the quality of your position there and industry results around your acreage?

Yes, I think one of the great things about -- in fact the Eagle Ford, the Permian and even the Montney is where you have got some quality competitors in those plays. We have this belief we not only learn from what we do, we try to learn effectively from what others do and I am pleased to see the continued performance improvements that others are seeing here as well. And we plagiarize wherever we can as we do this. I think when you look across the Eagle Ford, even in the areas where we are in, which we think is the best of the best, you do have various factors at play. Inter-well spacing, the frac intensity that you do, the cluster spacing, the amount of sand in the well bores. So we continue to see that moving forward. And of course you have some trade-off between cost and well performance with these high intensity completions.

Great. And then I guess, maybe more specifically on the Europe. You mentioned enhanced completions and IPs improving. Just trying to get a sense for what's baked into that range there and how you think about maybe the focus of the 2015 program just again in respect to the EUR range you previously provided?

Well, maybe I will make one other comment and ask Mike if he wants to add on this. The other thing I should actually say is, in a number of our plays including the Eagle Ford, the DJ, we did this actually in the Permian, we are looking at how to manage early life well performance here. We have actually found that in the Eagle Ford, for example, that not pulling the wells as hard early results in better performance over the first six months, greater recovery and we think more ultimate recovery, we need to see a bit more time. So we are actually doing that I think quite prudently. We actually restrict the production in the early months of these wells because we think it results in greater over the first six months and the life of the well.

Yes. Thanks, Doug. It's Mike. Mike McAllister here. Just on the EUR per well. Another factor that effects the EUR on a per well basis is we have different lateral lengths depending on our units. From 3500 foot laterals up to 7500 foot laterals. So that has a impact on the EUR per well. With respect to the IPs. We have increased our IPs where we are up to over 800 barrels per day of oil. And that’s a change from where we would have started back in Q2. But we do restrict the flow rates in an effort to improve overall recoveries. And there is independent industry study that would support that, that after about three to four months, you are actually producing more out of that well than by restricting it and managing the down hole dew point.

Our next question comes from the line of Arthur Grayfer of CIBC. Your line is open.

I was hoping you could just elaborate on a comment, I may have missed it earlier. You talked about a 15% cost improvement, or a cost efficiency improvement, and $75 million in additional savings. Can you just elaborate? Is that already in the budget or is that expected to come potentially in the budget?

Yes. Thanks, Arthur. It's good to clarify that. That’s embedded in those guidance numbers that we talked about. So effectively we think we can get another 15% improvement in capital efficiency year-on-year. Clearly in some areas as demonstrated last year, we will probably go well beyond that. But that’s what we have embedded. And the $75 million of additional cost savings is also embedded in those guidance numbers that we published. And in addition to that, there is additional corporate savings we have embedded in there as well as we continue to drive not only our operating cost down but our whole cost structure down.

Great. And then how does the change in the budget alter the outlook for 2016 or even the exit rate for 2015? You've cut out a lot of money in various areas, so how does the outlook change?

Yes. If you look at the shape of how our production is going to go through the year, and I don’t think this is all that much dissimilar to some of our competitors, that because of the momentum coming out of last year in the shape of our capital spend through the year, our production will grow up fairly substantially through the first half of the year and then roughly flat now as we head towards the second half of the year. So it really will depend on, the impact in '16 will depend on how the market conditions evolve and what we decide to do with capital spending later. But we actually, I think the real point here is if you look underneath it, even at this level of capital spending, our four most strategic assets actually growth all the way through the end of the decade even at commodity prices like we have today.

Okay, great. Two more questions. The next one is on Deep Panuke. So there's about 80 Bcf I think booked, what was said. And if I take the seasonal production profile, it looks like about a four-year ROI, give or take. Given the recent water encroachment, it looks like it jumped up a lot in January. Is there any concerns that you have a [indiscernible] issue and that you won't see that four-year ROI, or is everything under control there?

Well, I think we have done a lot of work trying to make sure we understand this water mechanism. To stress here, actually, the fuel watering out was expected. That was the depletion mechanism. So it's the arriving earlier than expected was the issue. In fact the platform was designed to handle large amounts of water production. We have been doing a lot of work between late last year and this year, just saying there is various production techniques that allow us to produce ultimately more gas from the field and we will continue to test that. But as we sit here today, we think the 80 Bcf is the best number out there. And I should stress that it's producing quite strongly right now and there is very cold weather in the Northeast. We are producing somewhere in the neighborhood of 180 million to 200 million cubic feet a day. And actually we had very poor pricing in December but we have had very strong pricing in the first six-seven weeks of the year.

Yes, that's great. It is actually really high. And then the last question for me. Cash taxes, can you just tell us what cash taxes would be roughly, on the new budget?

Yes. Hi, it's Sherri. We are basically putting in about $25 million to $50 million for the year.

Our next question comes from the line of Nick Lupick of AltaCorp Capital. Your line is open.

My question was actually on Deep Panuke and it sounds like Arthur got that. So thank you.

And our next question comes from the line of analyst Mike Dunn. Your line is open.

A couple questions if I may. First, probably for Mike. Mike, in a few of your plays, you've mentioned success with IP rates and the Montney with higher frac density and higher sand per stage. Can you just sort of, from a high level, discuss what the limitations are to going even higher density with the frac stages even more sand per stage? And have you tested well designs where, I guess, going too high with either of those is offering diminishing returns or is there still quite a bit of room to expand there?

Thanks very much there, Mike, for the question. Great question. We are continuing to look to push the limits. In fact we kind of think about it as in pounds per foot. Certain of the plays are up to 2000 pounds per foot as far as our frac intensity. And in fact we are going to be testing 2500 pounds per foot coming up. As well inter cluster spacing or interperf spacing the in the lateral. We have been pushing that from, say in one point in the Permian we were at sort of 70 foot interperf spacing. We are looking at pushing that down to kind of 35 foot. So we haven't seen any limitations. We are going to continue to push that. Last part of your question is a really good one. When does it get to be too much? When is there diminishing returns, when you are capitalized. And so the way we approach this is we want to find that answer very very soon. We want to basically push the limits on spacing to identify where that threshold is and then we know we can optimally develop our field and deplete our resource. So the sooner we answer that question, that’s actually the better answer for us.

Thanks, Mike. And then maybe another one for you as well. I am not sure if I had the context right, but in your Q3 release, it noted that drilling costs in the Eagle Ford were down 25% versus Q2 and in the Q4 release it says 10%. So I'm not sure the well designs have changed or if those are apples to apples and what the difference is there? Thanks.

Yes. I might have the IR folks get back to you in terms of where that goes. But what I can say is we have been taking our drilling costs down pretty significantly in the Eagle Ford. Going from 15 days down to 11 days in spud to rig release. So that’s a significant improvement. And then in terms of where we are targeting into next year, we are looking at taking our all-in well cost down between $6.1 million to $6.5 million. And that’s with including the tubulars in the hole and gas minerals in the hole as well. So that’s the target here going forward. But in terms of the apples to apples comparison I might leave that to our IR folks to discuss with you.

Okay, thanks Mike. And then Doug and Sherri, you mentioned a couple of times that even if your budgeted commodity price forecast for 2015 lasts beyond this year, I think you said you could still grow cash flow. So I guess my question would be, would that be a self-funded cash flow beyond 2015?

Yes. I think we, and I hate to go too far out in the future because I guess the first thing I would say is, is when we launched our strategy, we actually said we didn’t believe in $100 oil price. We didn’t think that that’s it took to balance the market and I would have to say we don’t believe $50 is the right number either. That said, I am not going to give you a number for the future because all out there, it's certain to be wrong. But we do think, the way we think about this is, we want a portfolio that is very cost competitive across the entire 93 million barrels a day global supply. And we think having a supply cost of between $35 and $55 a barrel, and by the way that’s without reflecting efficiency improvements. So should give, through continued execution and innovation and lower service cost we will see in this environment. That’s not reflected in those numbers. So as you think about that -- but what we are trying to say is because of those little supply cost and focusing our capital in the right places, we can actually even in a low commodity price grow cash flow year-over-year and we can grow production. What happens is our low margin production declines out and it's replaced by higher margin, significantly higher margin production even in these lower price environments.

Thanks, Doug. And I guess last question for me. Could you guys talk about what land expiry issues you may or may not have? I guess specifically I'm thinking about the DJ, the San Juan and the TMS, given the relatively low capital spend there this year. Thanks.

Yes. The DJ and San Juan, we really don’t have any particular concerns at this point...

Ladies and gentlemen this is the operator. I apologize but there will be a slight delay in today's conference. Please hold and the conference will resume momentarily. Thank you for your patience. Ladies and gentlemen, this concludes today's conference call. You may now disconnect.