North American super independent Encana Corp. sharply lowered costs, delivered better wells and strengthened its balance sheet last year, as it prepared for rising growth from 2017 and beyond, CEO Doug Suttles said Thursday.

Production was throttled back across most of Encana’s portfolio during 2016, with the focus instead on improving efficiencies and the balance sheet, Suttles said during a conference call to discuss results. Drilling and completion (D&C) costs fell by almost 30% from 2015, while efficiencies across the business delivered more than $600 million of savings and long-term debt was cut by $1.1 billion. Net debt since the end of 2014 has been reduced by more than half.

“Activity across the North American exploration and production industry has picked up considerably over recent months,” Suttles said. “We have positioned ourselves well to manage the pressures this creates, both on cost and on performance. We largely completed our activity ramp in the fourth quarter of 2016. We have been actively managing the supply chain and we continue to use innovation and technology as a tool to offset inflation.”

With the market improving, the plan for 2017 is to ramp up activity over the course of the year, with core asset production growing “by at least 20% from the fourth quarter of 2016 to the fourth quarter of 2017,” and crude/condensate output rising by about 35%.

Encana “created a powerful launch pad for our five-year growth plan,” over the course of 2016, the CEO said. “We carried considerable momentum into 2017. Through innovation and our relentless focus on efficiency and supply chain management, we expect to hold total year/year drilling and completion costs flat despite cost inflation for some services. We expect to significantly increase crude and condensate production throughout the year and deliver strong corporate margin growth.”

Permian Driving Production

Encana, which has close to a dozen projects across North America, today is directing most of its capital to the Permian Basin of West Texas, the Eagle Ford Shale and Canada’s Montney and Duvernay formations. Last year the operator accumulated 10,000 well locations, with the core four providing 74% of total 4Q2016 production of 321,500 boe/d and 72% of 2016’s average of 352,700 boe/d.

Production last year was driven by the Permian, with output climbing 20% from 2015. The company said it is on pace to increase production in West Texas by 50% from 4Q2016 to the end of this year. Two new Midland County wells delivered average 30-day initial production (IP) rates of 1,200 boe/d, while two new Howard County wells averaged 30-day IPs of about 1,200 boe/d. In the final quarter, average normalized D&C costs fell to $5 million/well, with average full-year costs 30% below 2015.

“We continue to identify well performance drivers and in 2017, we’ll be focused on testing items such as increasing early sand concentrations and our pump schedules with modifications to stage and cluster spacing,” COO Mike McAllister said.

During 2Q2016, Encana brought onstream the first 14 wells from the Rob Davidson pad in Midland County. “We have now returned to this pad, while those first 14 wells continue to produce, we’re drilling an additional 19 wells. This will bring us to 33 wells from a single location. This is the largest multiple pad in the Permian to date,” McAllister said.

“Above ground, this means improving D&C efficiencies and increased utilization of existing facilities. Below ground, it’s the first full-scale high density development in the basin. These 33 wells are across multiple stack zones in Spraberry and Wolfcamp A and Wolfcamp B.”

Encana plans to spend about $800 million this year in the Permian, all in Texas, using a five-rig program. About 135-145 horizontal wells are planned at an average D&C cost of $5 million/well. Roughly two-thirds of the wells are to be drilled in Midland, Martin and Upton counties, and the remainder split between Howard and Glasscock counties, McAllister said.

Eagle Ford Delineation Escalates

Since the start of this year, Encana also has boosted activity in the Eagle Ford and already has added 50 well locations to the portfolio. Three new wells delivered average 90-day IPs of 1,450/boe. The newest Austin Chalk well in the Upper Eagle Ford, delivered a 30-day IP of 1,000 boe/d. Average 2016 normalized D&C costs were 23% lower than in 2015. This year 10-15 Austin Chalk wells are planned.

In the Montney, which Encana considers one of the top natural gas fields on the planet, the company is borrowing from previous, successful well designs to improve performance. Although development was slowed last year, plans are to ramp up late in 2017, Suttles said. A new well drilled in the Montney during 4Q2016 delivered a 50% productivity improvement by applying a completion design similar to one pioneered in the Eagle Ford 12 weeks earlier. Average normalized D&C costs during 4Q2016 were $4.4 million/well, while average full-year costs were about 25% lower than in 2015.

Activity is set to increase in the Cutbank Ridge area of the Montney before two midstream processing plants begin operating later this year. Construction for both plants remains on schedule and under budget, Suttles said. Total 2016 liquids production increased by 6% from 2015. This year the focus is to remain on liquids, with the program expected to deliver an average 85 bbl/MMcf. Plans are to more than double liquids output from the end of 2016 through 2017, with condensate making up 85% of the growth.

In the Duvernay, production increased through the 10-29 processing facility that was brought online in mid-2016. Two new wells in the oil window delivered 60-day IPs of about 1,500 boe/d with nearly 1,000 b/d of condensate. Encana also grew total 2016 production in the Duvernay by 86% from 2015, while average D&C costs fell by 45%.

McAllister talked about how Encana is working to control its destiny in North America’s oil and gas fields.

“One of the important topics in our industry right now is how increasing activity levels will impact returns and margins” for producers, he told analysts. ” We believe that these impacts won’t be felt uniformly by all producers. In many ways, we have been working on this issue for years by building an organization and culture that is relentless about driving efficiency to create value. Last July, we identified that incremental industry activity was going to be a risk to our costs in 2017. We spent an entire day with our top 40 leaders working on generating ideas to position ourselves to excel in that environment.

“First off, we elected to avoid the risk of ramping up activity in early 2017 by building up to our full-year rig level before year-end. This gave us an advantage in securing services and materials in a lower activity environment. We control 75% of our capital spending through our centralized supply chain team. This small team is embedded in our operations organization and the staff with expert professionals who have the commercial skills to understand markets and how to best procure goods and services.

“This means our drilling completions teams can focus on what they do best, drilling and completing wells. We also manage the supply chain by self-sourcing the key consumables in our D&C operations like sand, water, chemicals, casing and drilling mud. This gives us better pricing and improves our security of supply for those consumables.”

Pinch-Point Identification

Using its understanding of the North American market, management identifies “the pinch points for specific services in specific regions,” McAllister said. For example, Encana has locked in a fracture spread in the red-hot Permian for 2017, and it has an option to lock in a second. It also has a pricing agreement for sand negotiated in 2015 that extends to 2020.

“We’re having success reducing our amount of consumables in our operations,” said the COO. “As an example in the Permian, we’re also increasing the amount of produced water that we reuse in our fracture jobs from 25% up to 40%. By recycling produced water, we’re also saving on operating costs, because we don’t have to pay to dispose all the water. Sourcing water and transporting it to pipe, then recycling it “is saving us approximately $1 per barrel in the Permian, a clear example of how we can make better wells for lower costs.”

Natural gas production, still the biggest share of Encana’s output, averaged 1,276 MMcf/d in 4Q2016, versus year-ago output of 1,571 MMcf/d. Canadian gas volumes fell to 905 MMcf/d from 1,001 MMcf/d, while U.S. volumes were down at 371 MMcf/d from 570 MMcf/d. Oil and natural gas liquids production averaged 108,900 b/d in the final quarter, about 35% of the mix, from year-ago output of 145,000/d. Liquids volumes are forecast to make up 40% of total company output by year’s end.

Using Canadian protocols, the Calgary-based independent replaced 326% of 2016 output on a proved plus probable reserves basis after royalties. On a U.S. Securities and Exchange Commission basis, which uses trailing commodity prices over 12 months, Encana replaced 175% of its 2016 production.

Encana reported a net loss of $281 million (minus 29 cents/share) in 4Q2016, versus a year-ago loss of $612 million (minus 72 cents). Revenue fell by 20% year/year to $822 million. Net losses in 2016 totaled $944 million (minus $1.07/share), which included $1.4 billion in writedowns, while revenue was off 34% from 2015.

Capital expenditures this year are set at $1.6-1.8 billion, with total production estimated at 320,000-330,000 boe/d. Total liquids volumes are expected to average 125,000-130,000 b/d, with natural gas production of 1,150-1,200 MMcf/d. The 2017 capital program is to be funded with cash flow and cash on hand, with a corporate margin forecast of more than $10/boe.

At the end of January Encana had hedged 79,000 b/d of expected 2017 crude/condensate production at an average price of $53.56/bbl. In addition, the company has hedged about 860 MMcf/d of expected 2017 gas production at an average price of $3.13/Mcf.

Long-term debt totaled $4.2 billion at the end of 2016, and net debt was about $3.4 billion. Encana had about $5.3 billion of liquidity made up of $4.5 billion in available credit facilities and cash and cash equivalents of $834 million on its balance sheet, compared with cash and cash equivalents of $271 million at year-end 2015.