Encana Corp. (ticker: ECA) is one of the first E&Ps to report it second quarter results. ECA announced a growth of 25% in its margin from the first to the second quarter of 2017.
Douglas Suttles, President and CEO of Encana, indicated that this was due to the increase in the fraction of oil and condensate in its production mix. The company now expects that its core assets will create additional growth, in the amount of 25-30% in Q4, 2017.
Encana averaged 246,500 BOEPD during Q2, which was 9,200 BOEPD higher than the previous quarter. Liquids production alone averaged 124,900 BPD.
Piceance sale
Encana indicated that the planned sale of its Piceance basin assets—which number approximately 550,000 net acres—to Caerus Oil and Gas for $735 million will allow the company to better balance its liquid-gas production scheme and focus on its core-acreage in the Permian, Eagle Ford, Duvernay and Montney, which will now “dominate the portfolio at over 90% of total company production,” in the words of Sherri Brillon, Encana’s CFO.
In Encana’s core acreage—the Permian, Eagle Ford, Duvernay, and Montney—it is growing its production by 8,000 BOEPD.
Reduction in debt, $5 billion liquidity
Encana said that it had reduced its total debt by $3 billion since the end of 2014, and that it now has approximately $5 billion in liquidity. The increase in liquids production—an increase of 35-40%—grew the company’s margin by $1.44 per BOE.
The company previously indicated that it expected an approximately $8 per BOE margin, with $55 per barrel WTI prices but has since revised its estimates, with an expected $11 per BOE margin with prices below $50 per barrel.
Liquids growth via Montney
Michael McAllister, Encana’s COO, reported that the company’s Montney liquids production was 16,000 BOPD during Q2, approximately 80% of which was condensate, and was priced at approximately 95% WTI. In Q4, 2016, Encana’s Montney liquid mix was 11% and has since grown to 14%.
In order to accomplish its Montney liquids growth, the company has added 41 net wells during 2017 so far, with an expected 65 net wells on stream by the end of 2017. The company expects that it will further increase its liquids mix by doubling its Montney liquids production to over 30,000 BOPD.
Encana calls the Montney “Canada’s Eagle Ford,” because of its increasing potential to produce condensates with economics that compete with the Eagle Ford.
Encana began its presence in the Montney 15 years ago and has since accumulated a 600,000 acre footprint. It pioneered the combination of horizontal drilling and hydraulic fracturing there when it added its first horizontal well in the Montney in 2005.
Encana’s acreage in the Montney sits within the play’s volatile oil window—allowing it to produce condensate at promising rates.
“Developing the cube” in the Permian
Using its new cube development scheme in its Permian acreage, Encana has brought 59 wells to production during 2017—with the average well performance increasing by 25% since 2016. The intent of the cube development is to utilize denser well spacing and simultaneous, full-stack development to minimize communication with depleted reservoirs and to minimizing the potential for offset frac-hits.
The new development method has also reduced drilling and completions costs to under $3.5 million per well.
Source: Encana
Q&A
Q: Doug, the increase from, 20% to 25% to 30% right for the core four. How much of that is coming from the Eagle Ford and can you give us an idea of just what’s happening there?
Doug Suttles, President and CEO: It’s actually coming from across the portfolio. The Eagle Ford is doing is doing quite well and as Mike mentioned in fact, I think we talked about the last two quarters, that’s where we really started piloting these very high intensity completions and have seen great results.
And I think what you’ve seen we’ve also added some inventory here, part of it is further delineating the Austin Chalk and part of it is the stronger wells are pulling wells that we were non-premium into the premium category, but for some time, we’ve talked about the Eagle Ford being plus or minus of 50,000 barrel a day asset, which is still how we think of that, but what we’ve shown is those wells are highly productive and we’re then trying to balance out, making sure we don’t overbuild facilities.
So, as we’ve also mentioned we are basically drilling to fill existing facilities and minimizing new builds to maximize return. So, I think the bigger strategic shape of the asset is largely the same, but it’s actually getting a whole lot more efficient to get to that same outcome.
Q: I was just curious, if you guys are looking to keep spending within cash flow and as of right now having roughly $400 million of cash in the balance sheet, personal or just $700 million or so coming in. What are you guys looking to do with that cash balance–does it go into the ground, does it go to acquisitions debt reductions?
Encana: Yeah. Josh, I think at the moment and of course, we all know we’re still in July and the environment is relatively volatile, but what we’ve said for the time being is that the proceeds are specifically from the Piceance sale we go to the balance sheet, and then what we’re able to do then starting next year, which is the original plan is grow within cash flow.
Q: And it’s always easier to benchmark or test, completion methodology is drilling a single well at a time and then seeing how that compares with the prior well, but in drilling, these big cubes or pads, how are you approaching continuing to test and optimize the completion, are you varying the completion designs within the cube or pad itself across the wells, or is it just that you test one completion design for all those wells in the cube or pad and then wait to time you need to see that and then go and test the different methodology in the next pad or cube?
Doug Suttles: We’re actually trying and evolving the completion design within the cube. So it’s not the completion design is fixed for each cube, and in fact, we’re actually preparing completion design along the wellbore. I think, we talked some of about that fiber optic cable we laid in the Montney well where we actually tried multiple different completion designs in various stages because in that well, we can actually measure and monitor the performance differences by trying that. So I think, this allows us to innovate in real-time on completion design and evolve it quite rapidly.
Analyst Commentary
From KLR Group
Our variance in long-term production guidance relative to Encana has narrowed though our ’21 production outlook remains at least 10% below the company’s expectation
Our ’17 production expectation of ~315 Mboepd is at the midpoint of company guidance (310-320 Mboepd). Thereafter, given comparable capital plans, Encana anticipates achieving production of at least 400 Mboepd in ’19 versus our expectation of ~400 Mboepd and at least 500 Mboepd in ’21 (~50% liquids) versus our expectation of ~440 Mboepd in ’21 (~55% liquids).
After appreciable analysis exchange with Encana, the variance in our production outlook appears attributable to the Montney. The difference relates to the company’s view as to the early production deliverability of Montney wells, which Encana assumes are ~1.5x greater than typical unconventional resource early time deliverability.
Economic rank: (1) Montney Pipestone very rich condensate, (2) Montney Dawson North rich gas, Midland Basin Wolfcamp/Spraberry, (3) Eagle Ford, (4) Simonette North/South Duvernay
Midland Basin – Wolfcamp/Spraberry:
Encana is conducting a five-rig Midland Basin program and plans to drill 135-145 net wells and place 120-130 net wells on line this year. Approximately 60% of the company’s drilling activity is in Midland County, ~25% in Howard County and ~15% in Glasscock County. Additionally, Encana plans to test the Wolfcamp C, Middle Spraberry and Joe Mills. Encana’s development scheme contemplates 450’ to 660’ lateral offsets in a chevron pattern. Midland Basin wells (~8,100’ laterals) cost ~$5 million. Wolfcamp A/B and Lower Spraberry wells in Midland/Upton Counties have produced almost 150 Mboe (~70% oil) the initial six months and should recover ~1,000 Mboe. Lower Spraberry wells in Martin County should recover ~900 Mboe (~75% oil). Wolfcamp A/Lower Spraberry wells in Howard County should recover 800-900 Mboe (~75% oil).
WCSB – Montney:
Encana is conducting a seven-rig Montney program (six rigs in Dawson and one rig in Pipestone) and plans to drill 70-80 net wells and place 60-70 net wells on line this year including 10-12 net Pipestone wells.Montney wells (~9,000’ laterals, up to 2,400 lbs/ft proppant) cost ~$4.5 million. In Dawson North, Montney rich-gas condensate wells have averaged ~1,300 Boepd (~65% gas, ~30% condensate, ~5% NGLs) the first 180 days and should recover ~1,750 Mboe. In Pipestone, Montney very rich-gas condensateoil wells have ~1,750 Boepd (~50% condensate) the first 180 days and recover approximately 1,750 Mboe.
