Ovintiv Inc.

Doug Suttles - President and CEO Sherri Brillon - EVP and CFO Mike McAllister - EVP and COO David Hill - EVP, Exploration & Business Development Brian Dutton - Director, IR

Greg Pardy - RBC Capital Markets Menno Hulshof - TD Securities Jeffrey Campbell - Tuohy Brothers Investment Research Michael Dunn - FirstEnergy Capital Corp. Sameer Uplenchwar - Global Hunter Securities Arthur Grayfer - CIBC John Hurling - Societe Generale

Thank you, operator, and welcome everyone for our third quarter 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 third quarter and year-to-date results.

Sherri Brillon, our CFO will then discuss Encana’s third quarter financial performance and Mike McAllister, our COO will provide an operational review of the quarter. Following the slide presentation, we’ll have time for Q&A.

I’ll now turn the call over to Doug Suttles.

Thanks, Brian, and good morning, everyone. The third quarter was pivotal and our financial results demonstrate the tremendous momentum we’ve built executing on our strategy.

We are now two years ahead on the 2017 targets we said a year-ago. Consistent with our strategy, we’ve built a resilient and commodity balance portfolio of high quality assets.

We’ve also delivered solid operational performance and we expect to end the year in a position of operational and financial strength. Transitioning our asset base and focusing our operations has delivered the intended results.

Third stream -- third quarter upstream operating cash flow was up over 50% before realized hedges against an overall production decrease of 8% year-over-year, clear evidence of our focus on value over volumes. Liquids production from our Original 5 Growth place was up over 70% in the third quarter versus the same period last year.

We hit the ground running in the Eagle Ford in Q3 where we reduced cost, improved efficiencies and demonstrated our ability to add value when integrating new plays into our operations. Company wide liquids production averaged over 100,000 barrels a day in the third quarter, our first quarter over this milestone with more to come.

Across our operations, we continue to realize efficiencies, lower cycle times and lower drilling and completion costs, leading to improved capital efficiencies and margin growth. Year-to-date capital investment is down 16% versus the same period in 2013.

Our disciplined approach to spending combined with higher margins realized so far this year have us well positioned to generate about $500 million of free cash flow in 2014. While our portfolio transition has captured a lot of the headlines, we’ve also been delivering on both the organic growth we promised from our Original 5 Growth Assets and underlying cost efficiencies.

We’ve also achieved year-to-date cost reductions of about $145 million resulting in lower G&A, operating and capital costs. Our organization is more efficient, focused and committed to creating value.

For the quarter, liquids production from the Original 5 Growth areas increased over 70% compared to the same quarter last year, averaging approximately 41,000 barrels a day of oil and NGLs. When you layer in production from the Eagle Ford, our Q3, 2014 oil and NGL production was approximately 79,000 barrels a day from just our growth assets.

At the start of the year, we indicated that from an operational perspective, the first half of 2014 would demonstrate our increased focus on efficiencies and then at the second half of the year, we demonstrate significant growth in liquids production. As expected, this has come through in our Q3 results and we expect the growth to continue through the fourth quarter.

We’ve built strong momentum year-to-date from our 6 Growth areas and we’ve set ourselves up to continue the trend of meaningfully increasing the liquids volumes from these assets, as well as the anticipated production from the Permian assets throughout 2015. Transitioning our portfolio to have more balance between oil and natural gas production has been a priority for the year.

The proceeds from our asset sales were effectively redeployed into high quality liquids rich assets with significant scale and running room. The Athlon acquisition which we announced at the end of the quarter combined with other A&D activity that we’ve announced so far this year has high graded our asset base and greatly improved our ability to generate high margin production volumes going forward.

As illustrated on this slide, we’ve divested largely gas weighted production that generated netback of approximately $20 per barrel of oil equivalent and use those proceeds to access high margin light oil that is an average netback of approximately $55 per boe. Through the A&D activity completed and announced here today, our 2017 transition target of deriving 75% of our cash flow from liquids will be achieved next year.

Two years ahead of our original plan. On September 29th we announced the transformational acquisition of Athlon Energy.

The tender offer set to expire tonight and we expect to complete the transaction tomorrow. This acquisition further propels our strategy and accelerates the achievement of our strategic goals.

With productive interval spanning over 5,000 feet of stratigraphy, these assets have massive resource potential and the ability to generate high margin liquids production. We estimate the total resource potential on the Athlon alliance to be approximately 3 billion barrels of oil equivalent with an estimated well inventory of about 5,000 locations, these assets offer exceptional running room.

We see incredible opportunity to work with the Athlon team to enhance and accelerate value of these assets by applying Encana’s resource play expertise. In 2015 we expect total production from the Athlon assets to average approximately 50,000 barrels of oil equivalent per day.

Before turning the call over to Sherri, I’d like to talk about our Deep Panuke asset. In October we chose to extend a planned maintenance outage to access the increase in water production experienced over the last few months and to determine how best to optimize production from the asset and commission a feed gas compressor.

Although we always expected the reservoir to produce water, recent levels were higher than we were anticipated at this point in the productive life. We plan to bring production back on by the beginning of December.

Once fully back up and running, we expect Deep Panuke to be producing on average between 140 million and 180 million cubic feet per day. I’ll now turn the call over to Sherri, our CFO.

Thanks Doug, and good morning, everyone. Encana’s third quarter financial results reflected strong performance of our asset base.

Total cash flow was up 22% from the third quarter of 2013 and as Doug mentioned Encana’s upstream operating cash flow excluding hedges was up over 50% compared to the third quarter of 2013 with the key driver being our shift to higher margin production. Year-to-date, Encana’s cash flow of approximately $2.6 billion is up 34% year-over-year while $967 million in year-to-date operating earnings represents an increase of 68% from 2013 level.

We saw strong growth in oil and NGL volumes through the quarter with an average rate of 104,000 barrels per day up about 79% versus Q3 of 2013. Natural gas production was down slightly averaging about 2.2 billion cubic feet per day down by about 19% compared to the third quarter of 2013.

This is a result of our transition to a more balanced commodity portfolio, divestitures, natural declines, planned facility downtime and third-party operational issues and was partially offset by production from Deep Panuke. Further illustrating the enhanced profitability of our business, Encana’s netback excluding hedging during the quarter was $3.60 per Mcfe versus $2.15 per Mcfe in the third quarter of 2013.

There are several factors beyond commodity prices which have contributed to Encana’s enhanced profitability in 2014. A 61% increase in liquids volumes year-to-date results in about $568 million increase in revenues versus the first nine months of 2013.

We also continue to see a significant reduction in our normalized cost. Year-to-date we have achieved cost savings of about $145 million, a direct result of the implementation of our new strategy.

Removing the impact of long-term incentives restructuring charges, foreign exchange and one-time cost, administrative costs were down by approximately $30 million compared to the first nine months of 2013. Upstream operating costs excluding the impact of LTIs, foreign exchange, and one-time costs were down about $45 million and capital costs were down about $70 million.

These cost reductions are largely the result of realigning our workforce to be more consistent with our strategic focus as well as operational efficiencies achieved in both growth and base production assets. Our focus on increasing efficiencies began over a year-ago and we’ve not done yet.

We continue to focus on leveraging technology and technical expertise across our business and we continue to actively seek ways to reduce cost, improve efficiencies, strengthening cash flow and maximize margins. Maintaining balance sheet strength is a key component of our strategy and scorecard.

Encana’s balance sheet at the end of the third quarter was significantly stronger than it’s been in recent history, due not only to the cash proceeds received from recent divestitures, but also because we’re no longer out-spending our cash flow. In fact, we expect to generate free cash flow of about $500 million in 2014.

We ended the third quarter with about $7 billion of cash and cash equivalents, the majority of which we intend to use to fund our acquisition of Athlon Energy and we have about $4.1 billion of undrawn bank lines committed until 2018. So we have tremendous financial flexibility.

Included in our cash balance at the end of Q3 with a proceeds received during the quarter from the sale of our remaining investment in PrairieSky Royalty Ltd. These proceeds are reported under investing activities in the consolidated statement of cash flows and are separate from the proceeds received from our other significant divestitures disclosed in our A&D activity.

Debt to debt adjusted cash flow was 1.7x at the end of the quarter, compared to 2.4x at the end and debt at the end of the Q3 and debt to debt adjusted capitalization was 26% compared to 36% at year-end. Including the impact of our planned acquisition of Athlon Energy, we see 2015 debt to debt adjusted cash flow to be in the 1.5x range.

We also expect this metric to decline in subsequent years, given the cash flow growth we expect from our growth assets. We are currently working through our 2015 capital plans.

And as we determine the magnitude of our capital growth in 2015, we’re committed to aligning the increasing capital with expected increase in cash flow. We are much more resilient in having options in our portfolio to respond to market conditions and prices with our continued commitment to aligning capital investment with cash flow.

Our flexibility to choose where to invest within our portfolio will keep the balance sheet strong. We have posted on our Web site this morning an update to our 2014 corporate guidance.

This update includes the impact of all A&D activity closed to date including the disposition of our Bighorn assets, the secondary offering of our remaining interest in PrairieSky Royalty Ltd. and the sale of our power business.

It also includes the expected impact of the acquisition of Athlon Energy, which we expect to close on November 13. This guidance does not include any impact for the sale of our Clearwater CBM assets which is expected to close during the first quarter of 2015.

Our total cash flow range has decreased slightly versus July guidance to $3.2 billion to $3.3 billion, largely as a result of the asset sales that closed during the quarter. We do still expect to generate significantly more cash through this year than the $2.4 billion to $2.5 billion that was presented in our original 2014 guidance provided last December.

The increase is largely due to the strong first quarter gas prices, the cash flow we expect to receive from our Eagle Ford assets, and the operational efficiency. Our 2014 capital investment at $2.5 billion to $2.6 billion has also come down from our July guidance levels of $2.7 billion to $2.8 billion.

About two-thirds of the reduced capital is due to improved efficiencies and the remaining period is attributable to scope change. We still expect to generate significant free cash flow in 2014 of approximately $500 million in excess of planned capital expenditures and expected dividend payments.

On the cost side, our guidance for operating expense remains unchanged. Transportation and processing expense increased to $1.43 per Mcfe from a $1.40 per Mcfe and administrative expenses has increased slightly both reflecting the drop in production due to divestitures.

We have also increased our per unit DD&A expense to $1.55 to a $1.60 per Mcfe from a $1.50 per Mcfe in our previous 2014 guidance, due largely to the anticipated Athlon acquisition. The mid-point of our revised guidance projects about 87,000 barrels per day of total oil and NGL production in 2014, about a 20% increase compared to our original 2014 guidance provided last December.

With respect to the puts and takes for our revised oil and NGL production guidance, we expect the Eagle Ford acquisition to contribute roughly 23,000 barrels per day on an annualized basis while divestitures that closed as of September 30, will result in a loss of about 9,000 barrels per day on an annualized basis. Adjusting for the impact of all A&D activity closed to date as well as the expected contribution from Athlon Energy assets, total liquids production in the fourth quarter of this year is expected to average between 102,000 and 107,000 barrels per day.

For natural gas production, we’re projecting an annual average of about 2.3 Bcf to 2.4 Bcf per day, about a 13% decrease midpoint to midpoint against our vision of 2014 guidance. This decrease is primarily due to the annualized impact of asset sales and dispose, year-to-date as well as the reduced expectation for production from Deep Panuke that Doug referenced earlier.

As I mentioned, the revised guidance includes the impact of the announced acquisition of Athlon Energy and the production that we expect to generate over the next month and half. Overall, the revised guidance reflects the success of our strategy execution.

Compared to our original 2014 guidance, cash flow was higher by about $800 million and the natural gas production that was sold has been replaced with higher margin liquids production. I’ll now turn the call over to Mike Mc McAllister, who will provide our Q3 operational highlights.

Thanks, Sherri, and good morning, everyone. Encana has achieved strong year-to-date operational performance across the portfolio.

Asset performance is inline with or exceeding type curve expectations. Our netbacks excluding hedges for the first nine months of the year are 79% higher compared to the first nine months of 2013.

This is largely a result of transition of our portfolio to a more balanced commodity mix, higher realized commodity prices during the first nine months of the year and cost reductions that we continue to achieve. We continue to see increased efficiencies, lower cycle times, and lower drilling and completion costs companywide.

Our cost structures also continue to improve as teams focus on driving down the costs. Operating costs excluding long-term incentives were about 16% lower year-to-date when compared to the same period in 2013.

We have seen liquids growth in the DJ Basin, San Juan, Duvernay and Montney and this growth is expected to continue in the fourth quarter. Finally, optimization of our base production continues to be a major focus for Encana and we’ve seen some excellent results from the projects that we’ve implemented to date.

Our teams continue to focus on base optimization and cost reduction projects which have yielded significant year-to-date results. The cumulative effect of various cost saving initiatives coupled with production optimization projects across the business have increased Encana’s base production by 7,000 barrels of oil equivalent per day and generated approximately $65 million of operating cash flow year-to-date.

Refrac wells in the Haynesville are performing better than our expectations and we continue to evaluate other opportunities. In the Piceance, we’ve realized savings of $6 million of operating costs by transferring produced water to third-party for their completion operations instead of disposing of it ourselves.

Frac communication mitigation efforts in the DJ Basin and in Montney, that resulted in savings of about $7 million on workover costs. In the Montney, a coordinated schedule of various plant turnarounds and pipeline apportionment [ph] mitigation strategies that resulted in cost savings of about $10 million.

The strong performance of our base business underscores our focus on profitability and enables us to accelerate the execution of strategic initiatives. The results that have been achieved year-to-date leave us well positioned to exceed our target 10 -- our targeted 10% improvement from our initial expectation of the 2014 decline rate of 28% to 30%.

Shifting now to the Montney, the successful application of high intensity completion wells piloted in Cutbank Ridge have been implemented across other areas of Montney with great results. In Cutbank Ridge eight wells brought on stream in Q3 are producing at a 100% above our prior type curve, with average initial production rates between 12 million to 14 million cubic feet per day.

The most recent well received 12 to 23 in Cutbank, had initial production of 13 million cubic feet per day and 340 barrels per day of liquids with condensate compromising -- comprising, I should say, 93% of the liquids. In Gordondale we brought 17 oil wells online in Q3, increasing oil production by 60% over Q2 to more than 6,000 barrels per day.

Most recent Gordondale Open Hole Packer and reduced inter frac spacing well had a 30 day IP initial rate of 1,000 barrels of oil equivalent per day with oil representing over 80% of the total volumes. Oil rate was about 125% higher than our oil type curve.

In Pipestone, we’ve been able to reduce our spud to on stream times by about 40% compared to 2013, even though we’re drilling longer horizontal wells. We continue to improve efficiencies on our drilling completion operations and our costs are trending down by 10% to 20%.

Encana continues to make good progress in developing long-term takeaway capacity in Montney. We commissioned -- excuse me, we commissioned the water hub -- the water resource hub in Cutbank in September.

This facility will have positive community impact beyond reducing our operational dependence on surface water. The centralized facility should meet up to 75% of our water requirement and result in conservation of about 16 million barrels of fresh water over the next five years.

We had 65 net wells in Montney year-to-date and currently have four rigs running in the play. Moving now to the Duvernay.

We continue to see significant improvements in our drilling costs and cycle times. Our Q3 drilling costs are 17% lower than in the second quarter this year as we see benefit of resource play hub application and 40% lower than our drilling costs in 2013.

Spud-to-rig release times are 30% lower than in 2013. We are consistently drilling wells under 30 days and we’ve recently rig released the 1 of 3 well in just 24.5 days.

To date this well represents our lowest drilling costs in Duvernay at $3.6 million, a reduction of 50% compared to our 2013 average drilling costs. We are continuing to work on developing long-term takeaway capacity in the Duvernay.

The 15 to 31 plant was commissioned in the third quarter, increasing the processing capacity to 55 million cubic feet per day of natural gas and 10,000 barrels a day of condensate. In July, we started utilizing our access to Alliance pipeline network delivering rich gas to Alliance pipeline in Chicago where our liquids received Chicago pricing.

The 30-day initial rates for our Kaybob and Simonette wells have been very strong with the majority of the wells meeting or exceeding type curve. For example, the 8 of 11 well had an IP30 rate of 2,200 boe per day and its currently flowing at 150% of type curve.

And our 1 of 11 well had an IP30 rate of 1,500 boe per day and its currently flowing at 100% of type curve. Our Q3 completions were delayed approximately 40 days due to water availability, a record dry summer made for good access, that challenged our ability to still look at on schedule.

Completions have begun on two pads, but this delay has impacted Duvernay’s full-year liquids production by approximately 300 barrels per day. Year-to-date Willesden Green in Southern Duvernay, we’ve seen improvements in well performance, but we feel there is room for further improvement before commencing commercial development in this portion of the play.

We intend to continue aggressively developing our acreage in Kaybob and Simonette area. Encana has five rigs currently drilling in the Duvernay Shale and we’ve drilled 19 net wells year-to-date.

Moving on now to the Eagle Ford. Encana has made great strides since acquiring asset in June of this year.

We’ve successfully leveraged our experience and expertise in developing resource plays by focusing on capital efficiency and optimizing well design. Since acquiring the asset we’ve reduced average spud release days by 25%.

By 25% I should say thus lowering drilling costs by almost 25% and lower completion costs by 13%. We are currently restricting production for some of our wells to 800 barrels per day of total fluids in an effort to improve oil recovery of the life of the well.

Our goal is to maximize value from these wells as we continuously monitor our performance. In October, we successfully executed a land swap with EOG Resources, in order to obtain maximum flexibility and operatorship in developing our Eagle Ford assets by increasing the working interest in our net acreage.

This swap allows Encana to operate and control the pace of development on our lands. Current production from the Eagle Ford is about 45,000 boe per day with over 85% of the production being liquids.

In Q3, we effectively stabilized production declines, expected to see production grow during the fourth quarter. On the -- on an annualized basis, the Eagle Ford is expected to average 23,000 boe per day and contribute between $200 million to $250 million of free cash flow in 2014.

The four rigs currently running in the play, and a fifth rig anticipated by mid-December. We have drilled 14 net wells in the Eagle Ford year-to-date and we expect to drill 34 net wells this year.

We are extremely pleased with the addition of Athlon’s Permian assets to our portfolio. Since the announcement of the acquisition, we have been working hard to integrate the company -- the companies with tomorrow's expected close.

We plan to hit the ground running and get quickly up to speed on the assets. Not that the entire Permian leadership team has already been assembled and includes significant Athlon representation.

There are currently four horizontal rigs in the Permian and we plan to bring a fifth horizontal rig in by year-end. Encana is planning to spend $75 million to $95 million in the play for the remainder of the year and drill 25 -- 29 net wells.

The Permian assets are currently producing at an average daily rate of 32,000 barrels of oil equivalent per day and expect these assets to contribute about 4,000 boe per day to our annual guidance with over 85% of the production being liquids. In 2015, we plan to deploy at least $1 billion of capital to the Permian directed primarily at the drill bed.

We expect to have 7 horizontal rigs running by the end of the year 2015 as well as 6 to 8 vertical rigs. We expect 2015 production to average about 50,000 boe per day.

In the DJ Basin, drilling cycle times continue to come down across the play, averaging three days faster than expectations. Section length laterals are averaging less than 10 days.

Spud-to-rig release and 1.5 sectional lateral are averaging 13 days spud-to-rig release. Year-to-date we have successfully drilled 8th 10,000 foot laterals with the best 10,000 foot well being drilled in only 17 days.

We continue to optimize and gain efficiencies in our DJ program and the 2014 year-to-date costs are averaging between $4.5 million and $5 million per well. Encana continues to optimize spacing and completion design in the play.

We're testing, 24 wells per section as well as piloting larger fracs in the Niobrara. We’ve drilled 49 net wells year-to-date and currently have six rigs running in the play.

In the San Juan, we’re advancing commercial development while continuing to delineate the acreage. Peak 2014 production for the San Juan is expected to reach 9,500 boe per day, an increase of 150% from the beginning of the year.

Q4 oil production is expected to double compared to Q3 of this year. As the drilling cycle times continue to improve quarter-over-quarter, we have seen drilling costs in San Juan reduced by 11% compared to 2013 average.

Completion costs have improved by 15% compared to 2013 average, the Alliance site to $2.6 million per well. We are executing low volume nitrogen completion programs, realizing $300,000 or 10% completion cost savings with no impact on well performance.

Well performance continues to meet or exceed expectations with initial production rates between 400 to 500 barrels per day. We continue to pursue other opportunities in the play.

We have drilled 24 net wells year-to-date and currently have three rigs running in the play. In the TMS, we continue to make significant progress in our drilling long laterals, reducing cost and achieving normalized type curve performance.

During the third quarter, we set a new record on the Sabine 12-H2 well with the spud-to-rig release of just 32 days. We’ve also been able to consistently achieve our targeted lateral length with our last eight wells, averaging 7,100 feet.

Well cost continue to improve the play. Year-to-date, drilling and completion costs were 10% to 20% lower than 2013.

We’ve been -- we have -- this has been achieved by advancing completion design improved targeting in the reservoir. The three most recent wells have reached 30-day initial production rates of 1,100 barrels of oil equivalent per day.

Excuse me, oil per day, providing us with the confidence the type curve is repeatable and can be engineered. We’ve drilled 10 net wells year-to-date and we will be running two rigs for the remainder of the year.

Looking ahead to 2015, we will focus on lowering well costs and see three potential outcomes for the play going forward. Firstly, we can choose the vast commercial activity and aggressively develop the asset, or we can decide that the play does not compete for capital on our portfolio and exit our position, or we can choose to advance the commercial activity to develop the asset at a more moderate pace.

The tremendous optionality in our portfolio means that we can take our time in furthering our understanding of the assets, and coming to a decision that best supports the advancement of our strategic objectives. I will now turn the call to, Doug.

Thanks Mike. We continue to deliver strong results in a pivotal or third quarter during which our portfolio transition was significantly accelerated in all of the key milestones we laid out with the introduction of our strategy just one year ago have been achieved.

We expect a strong finish to the year as we continue to build on the momentum we’ve generated so far this year. We’ve maintained a disciplined and focused capital program by directing 84% of our capital to our growth assets against a target -- minimum target of 75%.

We’re hitting our key targets while expecting to spend about 7% less capital have been stated in our July guidance. In Q3 we delivered a 53% increase in pre-hedge upstream operating cash flow compared to the same period in 2013.

We’ve accelerated the development of our high margin growth place by achieving 70% growth in liquids production from our Original 5 Growth areas in Q3 versus the same period in 2013. We also remain on track to advance our appraisal of the TMS and Williston Greene.

We are well on our way to securing mid-stream and takeaway solutions in the Montney and the Duvernay. We remain committed to reducing cost having realized $145 million of cost savings so far this year, and we’re continuously working to improve capital efficiency and optimize our base performance, and very importantly, we’ve maintained a strong balance sheet.

By directing the majority of our capital to growth assets, we expect to continue realizing value as we focus on higher margin production not simply increasing liquids at any cost. Taking into consideration our new Permian lands and using our long-term price outlook of $90 WTI and $4 NYMEX gas price.

Our seven growth assets are expected to generate an average netback of $40 per boe in 2015 compared with $8 per boe from our base production. Our growth assets also have very robust supply cost with many in the $35 to $45 per boe range.

Despite the recent weakness in oil prices, these high quality assets are still generating strong returns thereby reinforcing our strategic decision to focus on growing value versus volumes. We made significant progress there this year in advancing our vision of being a leading North American resource play company.

Encana's portfolio now includes positions in the heart of the Top 2 Canadian resource plays, the Montney and the Duvernay, and the Top 2 U.S. resource plays the Eagle Ford and the Permian.

The accelerated execution of our strategy has placed us in a position of strength. We are building sustainable success from the inside out with a culture built on teamwork, agility and the drive to succeed.

Our team continues to take concrete steps needed to deliver on our growth targets and drive efficiencies into everything we do. We will continue to exercise capital discipline to generate profitable growth as we strive to sustainably grow shareholder value.

We believe that we are well positioned to not only finish the year strong and to carry our momentum into 2015, but to continue delivering on this objective for many years to come. Thank you for listening, and our team is now ready to take your questions.

Yes. Thanks.

Good morning. Few questions for me, they’re mostly operational.

But maybe just to start with the Duvernay, and Mike, I didn’t catch it. Did the two eight-well pads, have those now come online?

Just curious there.

Hi, Greg. Actually not.

It’s actually an eight-well pad and a nine-well pad. We decided to drill a ninth well on one of the pads on 44 actually.

The 44 pad, I should say. No, we were delayed as I mentioned in the call, we were delayed in getting our frac water pit filled, and so we’re just beginning to fracking those pads right now.

Okay. And then would -- is your sense of that timeline would be online before the end of this year?

Is it probably looking like early next year?

Probably looking at early next year to get those pads functioning.

Okay. Great.

Last one on the Duvernay, you guys have been obviously extremely busy, a lot of wells and so forth, not that much data. When can we look forward to the coming out party in the Duvernay next year?

Well, I think we have -- we probably have a conference call here in, it would be in February. So, I would look at that point in time.

I’m looking across at the boss here. Let’s see what he has to say.

Okay.

Yes, Greg, I think, the story on the Duvernay is actually a good one. As I think Mike mentioned in the call, we’ve seen some very strong well performance.

Probably most important -- we’re pleased with that, but as you know our big objective this year was to demonstrate will you get the cost down. And I think probably the thing we’re most excited about is how good the drilling cost will perform.

In fact if you look from the start of the year till now, our most recent well and our best well is actually took half the time to drill the well just back in January, and that shows the progress we’ve made. Due to the availability of water this summer, we’re obviously a bit late on the completions, had some pretty minor impact on the volumes year-to-date.

We’ll see those coming on early in the New Year. But should say we actually don’t expect that problem to happen in the future because we’ve got one water pit completed.

We’ve got four more under way, because we actually fill these pits seasonally, so we shouldn’t expect to see that problem. But I hope in 1Q we can start talking about more -- with well results from these.

We actually have as you know three multi-well pads now. We have two eight-well pads and a nine-well pad.

Okay. Great.

And maybe just to come back to Panuke. Is there any expectation to drill another well there and then does the water encourage in change your -- change your preliminary view with respect to reserves?

Now, it’s a good question, Greg. Maybe just to clarify some points there, I mean our year end reserves at the end of last year on Panuke were 355 Bcf.

I think some people have been quoting much higher numbers, but if you look at our reserves that was little. So I think we produced about 62 Bcf so far.

We’ll obviously have to look at what we think the impact of this early water production is. It’s a bit too early to say.

What we need to do is bring it -- bring the field back up which we’ll be doing over the next several weeks, and we’re doing modeling work to understand the impact. I should stress to the Panuke downtime has impacted gas volumes for the year, but has limited impact on cash flow because over this period where it’s been shut-in, the gas price has been averaging less than $3.

And thanks for that, Doug. Last one for me is, just can you give us an idea where current oil and liquids production rates are running now?

I don’t have that number at my finger tips just now, Greg. I mean if you -- maybe it will help if you remember when we did the call on Athlon, we talked about our exit rate.

I believe we talked about 105 to -- I’ll just get that, 105 to 110 since that time and that incorporated big ones, but it didn’t incorporate PrairieSky which is actually a fairly significant volume because of the consolidation. So you take all of the divestment in fact, so that pulled that number down by about 13,000 barrels a day you drop in Athlon which adds in 14.

So the net-net on A&D is about plus one. And then there is about 4000 barrels a day spread across the Montney, the Duvernay and the DJ.

A lot of that is actually due to -- to actually midstream and takeaway issues and a lot of it is actually C2-C4s [ph] that’s why you’re not seeing much impact on cash flow. So that’s why we actually look at 4Q now, we expect with Athlon in for six weeks that we’ll average somewhere between 102 and 107 in the fourth quarter.

Okay, perfect. Thanks all.

Thank you, and good morning. Just to go back to the Duvernay; what can you tell us about the well design of the one of three well, and then what are you anticipating for completion cost?

And then lastly would you consider that to be a one-off result or is that something you can replicate fairly consistently?

Hi, Menno. Its Mike McAllister here.

Yes, so the measured depth would be about 18,000 feet with TVD on that well being somewhere around 12,000 to 13,000 feet. Running 4-1/2 inch casing, I think what we’re going to be doing going next year our collection casing we’ll be running -- we’re going to be running 5-1/2 to accommodate artificial lift.

But, yes I mean, basically we continue to improve our drill-bit designs and our ability to replicate that. And I think we would give it a pretty good shot and we’ll see that kind of performance going forward.

But, yes very, very encouraged with that result.

Okay. Thanks Mike.

And then maybe a quick one for, Doug. Would you be able to give us any high level thoughts on activity levels in 2015 in an $80 world and ideally by a play, but any high level thoughts would be appreciated?

Yes. And who knows what the world is going to be like?

It’s quite the adventure we’re in right now. But I think for us with the repositioning of our portfolio and as Sherri mentioned with our strategy, what we said is we were broadly going to align capital and cash flow.

We expect to see fairly sizable capital increase next year because our cash flow is growing substantially. We’re in the budget cycle now.

We don’t have the exact numbers yet. Hopefully over the next month or so we’ll land our budget, but I do expect our budget to grow substantially from this year to next year because even in an $80 or $85 oil price world we’ll still see substantial cash flow growth from where we started.

So we don’t have the numbers just yet, but I would expect our activity to grow. And I’d expect you to see the predominance of the activity focused on what we consider as our top four plays.

The Montney, the Duvernay, the Eagle Ford and the Permian.

Perfect. Thanks Doug.

That’s it for me.

You bet.

Good morning. Doug, you’ve said in the past that you felt five major plays was a good aspiration for ECA.

But you now have six solid plays and the TMS has a possibility to become seventh. Has ECAs comfort with operating more liquids plays increased or should we expect some possible portfolio restructuring in 2015?

Well, with the addition of Athlon we’ll end up with -- we, as you said we have seven by the way, we counted but we really think of it as the 4, 2 and 1. So the Top 2 in Canada as we think of the Top 2 in the U.S.

then the DJ and the San Juan which the challenge there has always been about achieving the scale we need to achieve, and then I think as you accurately described we had this option called the TMS which we’ve seen good progress on. But if you look at when we first rolled out the strategy, we talked about being in somewhere around 28 different plays.

We’ve actually, if you include our natural gas economy and power business, I think we’ve exited 11 areas. So we’ve significantly streamlined our portfolio, and that’s partly what's driving a lot of our efficiencies.

It’s interesting -- the discussion today is oil price’s has come off about the focus on efficiency. But our organization has a 1000 fewer employees than it did one year ago today, 25% fewer yet we’re spending the same amount of money and next year we’ll spend more with roughly the same employee base.

So we’re seeing huge improvements in efficiency that are coming from our strategy implementation. The portfolio feels to be in a great place, I mean we have a great mix of oil and natural gas opportunities.

It’s sort of interesting right now as big round rough numbers $5 swing in oil price as the exact did seem to impact our portfolio as $0.50 change in gas price. And as you know even the oil prices, the weaken gas prices have strengthened during that period.

So probably I think the portfolio is in good shape. But I can tell you we’ll always be looking at it, because I think its part of earning a high quality oil and gas company.

But I would be surprised if we had the same level of portfolio change next year than we had this year. It’ll be hard to keep the pace up.

Well that was a great answer. I appreciate that.

Your optionality on the TMS sounds like it revolves on well cost, since your ability to drill and complete strong wells has become consistent and the type curve is holding up. Maybe Mike could add a little color on what further things could be tried to further reduce drilling costs?

Yes, just before Mike jumps in, I think it’s a great read. I mean, hardly enough the TMS may have the highest netback or margin in North America, but it also has some of the higher development cost.

But because of its physical location, because of the fact the production is 95% high quality light oil it ends up with very, very high netbacks in margins. Now it does have some of the higher development cost.

And what we’ve been talking about is the next step here is further cost reductions to make sure it’s not only resilient in $100 world, its resilient in an $80 world. But Mike can probably add some color to that.

Yes, you bet. I mean first and foremost is our ability to drill the well as predictably and with the last eight wells now getting over 7100 foot lateral, very, very encouraged by that.

That’s a key element of getting our cost structure down if you will. And as we’re moving forward we’re drilling single wells now, but as we move forward we’re going to be looking at two or twelve well pad in the TMS using our RPH mode and essentially everywhere that you’ve seen us do this then all our other plays have been able to significantly drive cost down.

So that’s the opportunity for the TMS going forward is really moving into that assembly line mode that we’ve been successfully implementing in our other plays.

Well, thanks Mike. That’s very helpful, and if I could sneak in just one last quick question.

Can we have an activity update on the Haynesville refrac program? Since you guys are behind that activity, a number of other operators have begun refrac or announced the plan to do so.

Yes, I think Mike can add some detail to this. But I guess the point I would stress here is we’re now moving that technology to other parts of our portfolio.

We’re testing it in other places. There’s still some technology development though that needs to happen.

I think our assessment shows that we’re only refracking a portion of the well. And so one of the things we’re debating is, about how fast to go and let the technology evolve.

So go at a more moderate pace as we see that and also test it in new places.

Yes, very encouraged with the results in the Haynesville refract, its kind of first serve, mostly kind of $2 million were taken well from a few mcf a day up to $4 million a day. We’re doing micro seismic on the wells and running some tracers we’ve been able to determine that really, we’re only getting the first 25% of the well bore stimulated from the heel [indiscernible] to say.

So there is an opportunity for further delineation of our refracs fuel stimulating more of the well bore. We’re also looking at refracking candidates in the Eagle Ford and in the Montney as I mentioned.

So, and more to come but very encouraged with the results we’ve seen.

Thanks very much for the detail. I appreciate it.

Good morning, everyone. Most of my questions have been answered.

I just wanted to just get some clarity on your Montney and DJ Basin production outlook for the year. You need to see some pretty strong growth during Q4 to meet the original liquids guidance.

I think Doug you might have said that you’re a bit behind to do takeaway capacity, I think is not the case that you’re not going to meet the original guidance range for those two plays for 2014?

Well in the Montney the -- a couple of things have impacted us there. One is, you may have read earlier in the year that TransCanada had to respond to some regulatory request and have had to be doing some inspection work in other things on some of their pipelines which has impacted some of our production as well as others in the area.

It’s modest, but it has that similar impact. It’s also created some additional transportation cost for us, but that’s all embedded in the numbers.

There has also been a few outages at Fort Saskatchewan and a few other places. So it means we’re a little bit behind as I indicated.

We probably think that that area is probably about 2000 barrels a day less in 4Q. There’s also some things about royalty rates that were a little higher because of the higher pricing also had some impact.

In the DJ, there is a little bit of third party delays. We’ve got some issues to work around planning, mainly that’s around the fact that we have to shut in offset wells when we frac wells, and we didn’t fully account for that in our forecasting.

So we’re making sure we get that problem fixed going forward. And then in the Duvernay, we had an outage at our 531 facility as well as the frac water piece.

So all of that added together is about 4 MBD. The good news is none of it’s about the efficiency or the performance of the wells and some of it’s a midstream takeaway, but that’s what, how it’s going to play out in the fourth quarter.

Great. Thanks, Doug.

And just getting back to the TMS, Mike was there any -- what would you attribute those, I guess the last three wells being over 1100 barrels a day. Is there anything different about those wells?

Is it the geographic location? Or the tonnage of frac sand et cetera?

What would you attribute those strong results to?

I’m going to turn the question over to Dave. But essentially we’re running a hybrid frac [indiscernible] plug and the -- so I think we’ve optimized the completion design on those wells.

But David Hill who is responsible from an appraisal standpoint, I’m going to let David handle the question.

Yes. Thanks Mike.

I think couple of things there is, what we’ve done is through the year focus on lowering the landing zone and what else is contributing to the greater than 1000 barrels a day is hitting our lateral length, that was key for us is consistently drilling out 7100 feet or greater. So hidden our normalized type curves, and we’ve been experimenting with our sand loading.

We’re doing about 500,000 pounds per stage, so high frac intensity there and we’re also doing some optimization and some experimenting with lateral length -- with the lateral length or stage length and the cluster spacing. So those things we’re continuing to optimize and we’re never done.

I think optimization is in real time and continuous and we’re seeing great improvements there.

Great, Dave. So of the, I think 10 wells you drilled year-to-date they don’t all have exactly the same frac design, is that fair or?

Yes, that should add. Its propane [ph] load has been increasing and again we’ve been experimenting with the stage length and the cluster spacing there.

But all our type wells -- all of our wells this year from a normalized basis have been hitting the type curve. So we have been very pleased with that and the drive here was really getting our lateral length consistently drilled and Mike and the team they have done a fantastic job from a drilling perspective.

Great. And one last one on the TMS.

You mentioned earlier going to two to four well pads, is that sort of the maximum allowable under the lease terms or eight-well pads foreseeable in the future as well?

Yes, I think spacing is really getting to that question as how many wells per section and drilling north to south, and how many wells could you get off of the pad. So we can go anywhere, we are doing three to four wells pre section, you can do six to eight wells.

But we haven’t gotten to the design of experiments yet on well spacing. So, that will be some of the things we’ll be looking at into 2015 as we initiate some of the RPH just to see what kind of drilling efficiency we can gain here.

And again Mike and the team have show that play by play, by driving down the well cost, and they look forward to doing that in 2015.

All right, thanks. That’s all for me, folks.

Good morning, guys. Quick question on the -- again on the TMS following-up, based on the discussion going on till now it just seems like, is TMS commercial now?

Should we assume like its commercial on a go forward basis? And then on the second one just trying to understand on the Eagle Ford, I’m just trying to understand how many locations are remaining to figure out what the go trajectory could that be.

Thank you.

Yes, Sameer. I think Mike tried to address the commerciality question earlier in his comments.

And basically what he said was we have three options here. We can move forward and aggressively develop the TMS.

We have another option which is decide we don’t believe in our new portfolio it competes for capital, and that would mean an exit or the third one is, as we’ve discussed on this call is we continue to work to drive down cost to make sure it does compete, and we haven’t made that decision on any of those yet. As I talked about earlier the margin structure here is quite good, but the well costs are higher.

And therefore what that means is the returns are lower, and I think as people mentioned earlier we still see potential to get the cost down and as we looked at our plans for 2015 we’re considering those options and what the possibilities are here. But when we entered the year, if you recall we had several objectives on the TMS.

Number one was to get some time on the type curves, we’ve done that. We wanted to see that the wells would perform and they’re doing that.

As David mentioned all of our wells are performing at or above type curve now. We needed to see predictability and drilling performance.

We think we’ve got that figured out now. And now we need to make sure we have confidences, you’d go to an RPH mode that you can get the cost in a place where they can effectively compete for capital.

But it’s been a good year on what we’ve seen in the TMS, and we’re looking at what we should do with it as we put our 2015 budget together. On the Eagle Ford I think that, its playing out largely like we thought.

We are very pleased with the efficiencies we’ve added. We did think we can do that, and Mike and the team have demonstrated that.

When we picked it up we had one rig running, we’re now at four and we’re quickly headed to five. As you know it at been at eight rigs last year and gone down to one and that had put the asset into production decline.

We’ve now stopped decline and production started to grow again. And as we’re planning next year we’ll see how far it grows.

So, I still think with the sort of expectations we had when we did the acquisition are the same ones we have today, and it’s a place that competes very effectively for capital.

Thank you.

Good morning. Two questions for me, the first one and I may have missed this in the call earlier, but can you talk about what is the corporate decline rate right now given all the various A&D activities?

Yes, we didn’t -- what we talked about on the call was sort of the base decline. But what's happening is that, that’s changing as our portfolio changes.

I don’t carry that number off the top of my head, but our base we talk about 28 and 30, and we talked about reducing that by about 10% this year. As we model out a combination of the rate of capital input in the new mix in the portfolio we’ll see what that does.

But we expect our liquids will grow significantly next year as we deploy capital across the portfolio.

Okay. And then the second question is, can you talk a little bit about the production practices for Panuke.

So should we expect that, is there any opportunity for you to run between 140 and 180 million cubic feet during the winter time then without lower in the summer time, would it be a 100 million cubic feet, 50 million cubic feet a day or is it going to be 140 to 180 flat? Thank you.

Well you can imagine it makes no sense and this has been part of our plan since the beginning as any -- as we have to do anything like planned maintenance, we always plan to do that in the summer time both because of the seasonal pricing structure, but also because operationally it’s easier as well. That’s why we talked about; we had planned maintenance outage scheduled for September this year is why we wouldn’t do that in the winter.

So there’s always going to be some inherent seasonality in there. As we assess the impact of this water we’ll clearly have to look at how we produce and operate it.

But it’s a bit early to say how we’re going to do that just now. I think right now what we need to do is, as we bring it up from display and shut down and now that we’ll have our feed gas compressor online to see how the platform performs and we’ll keep you guys updated as we get new information there.

Great. Thank you very much.

Yes, just some quick ones. And in terms of the Athlon acreage going forward, how much of the drilling activity would be HBP oriented?

Yes, just the way to think about this is the vertical program is really about holding acreage and the horizontal program is about development. So the six to eight vertical rigs are really focused predominantly at holding acreage, and as we ramp up from four to seven horizontals that’s all about development it is how you should think about.

If you remember back when we did the Athlon call we anticipated the vertical drilling to only last about two more years.

Okay. All right.

And what would the split be on CapEx?

I don’t have that number at hand, but roughly the vertical wells I think are about $2 million plus or minus, and the horizontal wells are somewhere around $8 million, but I don’t have that split. We could probably follow-up with you on that.

Okay, that’s fine. With Panuke and the production issue as you mentioned, nothing performance related from say having pulled too hard last winter when you’ve got such great realizations?

No, we actually didn’t produce the field any different last winter than we had planned to produce it. I mean, the drive mechanism in this field, water was always expected obviously and we had a range I think from something like water could arrive anywhere from eight months from start up to 18 or 20.

It obviously hit in the earlier time period and there’s an underlying [indiscernible] and it looks like there’s a tight streak that separates the main pay zone from the [indiscernible] and it look like waters broken through it. But we don’t think it was tied to how we were producing because it was how we expected it to produce.

So we didn’t …

Okay. That’s great.

Last one for me, value versus volumes. You mentioned that its there in the call, you’re not really hedged next year versus where you were this year.

Say oil prices breakdown more; will you be more aggressive on managing for value? And that’s it.

I’m not quite sure I understand the …

Would you slowdown your CapEx or your growth rate versus maintaining an aggressive growth rate if oil prices breakdown further?

Yes, when we rolled out the strategy we said that maintaining a strong balance fee is a priority for us and therefore we intended to broadly as we grew we did broadly keep capital and cash flow in line, and that’s what you’ll see next year. Obviously it’s a bit difficult to predict where prices are headed.

And we’ll use our hedging program actually just to help us manage short-term cash flow and make sure that we don’t have to do things that are value destructive in how we manage our operations. But we invest on our fundamental view not on our hedged view of the world.

So, obviously if the floor fell out of oil price we’d respond to that, and we’re looking at a range of scenarios for next year. This is not an issue about returns; it’s just about an issue of maintaining a strong balance sheet which we intend to do.

Great. Thank you.

Thank you operator, and thank you everyone for joining us this morning on the call. Our conference call is now complete.