Since commodity prices plummeted in mid-2014, oil and gas producer’s operating costs have declined substantially over the last three years. Driven out of necessity, this achievement reflects a combination of the significant strides in reducing producers’ capital costs, lower service costs resulting from reduced industry activity, and pricing concessions from service providers.
As the graph below shows, average operating costs for a group of companies with at least 85 per cent of their production in Canada have declined from a high of $14.81 per barrel of oil equivalent (boe) in the first quarter of 2014 to a low of $10.37 in the last quarter of 2016.
Capital Cost Reductions
The efforts of producers to find sustainable improvements in their own approach to capital costs are a significant part of the decrease in operating costs. Six of the top cost saving trends include focuses on:
Achieving low-cost status is really about choice, says Darren Gee, president and CEO of Peyto Exploration & Development Corp. Low cost producers are returns-driven companies and don’t spend a dollar unless they can generate a very high rate of return on that dollar.
On an annual basis, Peyto’s operating costs decreased in 2016 to $1.50 per boe, down 14 per cent from $1.73 in 2015. The company has maintained a leading position on operating costs by selectively and efficiently investing capital at periods in the cycle when costs are at their lowest, which then yield a superior return. And by maintaining low cash costs over the entire production life, it ensures returns are maximized regardless of commodity price volatility.
Producers are also driving costs lower by focusing on low-risk operations. Low cost operators tend to avoid exploration activity or plays with higher risk.
In 2016, excluding experimental wells, producers rig released only 254 exploratory wells, the lowest count in at least three decades, according to data tracked by the Daily Oil Bulletin. By comparison, in the mid-2000s, producers drilled 5,000-6,000 exploratory wells per year.
In recent years, however, producers have concentrated on lower-risk development work. Last year, producers drilled 3,827 development wells (again excluding experimental wells), about 15 times the number of experimental wells rig released. While there are fewer big, new oil and gas finds, a manufacturing approach to development provides overall costs reductions.
Owning and Controlling the Value Chain
Low cost producers want to own and control as much of the value chain as they possibly can and typically own their own facilities.
Tourmaline Oil Corp., as an example, says its investments in processing facilities in 2014 and 2015 have reduced the volume of gas flowing to third-party facilities, also contributing to the reduction in operating expenses on a per-boe basis.
These efforts helped the company achieve record low operating costs in 2016 of $3.31 per boe versus its original 2016 operating cost guidance of $4.25 per boe, and down from $4.37 in 2015 and $4.67 in 2014.
Leveraging Technology and Enhancing Execution
Companies — from juniors to senior producers — are also doing a good job of leveraging technology and enhancing execution to offset cost pressures.
Tourmaline says its drill and complete capital costs have been reduced by 30 per cent since Q1 2015.
A further 15 per cent reduction was achieved with the 2H 2016 E&P program. The company estimates that 60-65 per cent of drilling cost reductions and 50 per cent of completion cost reductions are performance based. These cost reductions drive a step change in capital efficiency and underlying E&P play economics.
Canadian Natural Resources Limited says its drilling has also become more efficient. “[At] Septimus, we’re 10 per cent faster than we were a year ago. So … by having the same crews working for us, day after day, we’re seeing those efficiencies,” Tim McKay, chief operating officer of Canadian Natural, told the company’s Q4 2016 conference call in early March.
Lower cost producers typically are pure-play operators, or have a limited number of plays. They know what they do well and stick to it.
Advantage Oil & Gas, another low-cost producer, opted to go all-in on the Montney several years ago. Over time, other assets were sold and debt was paid down substantially.
“By selling the other assets, we reduced and got rid of a lot of the high-cost assets. As we continued to develop Glacier [Montney], because it was our one property, one very focused area, from a G&A standpoint alone, we cut costs and took the company from about 180 employees to 26, and that’s where we are today,” says Andy Mah, president and CEO of Advantage.
Strong Hedge Programs
Low-cost producers typically enter hedging programs to ensure production against market volatility.
Advantage’s hedging program has been a key part of its drive to become a low-cost producer. Protecting the balance sheet is vital. “If we were going to make a business decision here, we know we couldn’t afford not to have a minimum level of cash flow protected so we could reinvest,” says Mah.
Peyto’s Gee is also a proponent of strong hedge programs.
“Because low-cost producers have the confidence in what they’ve built, they’re able to forward sell,” he says. “They’re able to take advantage of future prices; they’re able to lock in at the future strip.”
Margin Pressures on Service Companies Continue
Operating costs have also declined (particularly since 2015) due to lower service costs resulting from producers demanded pricing concessions from service providers. Mark Salkeld, president and CEO of the Petroleum Services Association of Canada (PSAC), says that while pricing improved somewhat over the winter, service companies are still doing more giving than taking.
Adding pressure is that cost inflation is hitting the oilfield services (OFS) sector, particularly due to labour shortages, which can only be addressed by increasing compensation. Costs have also increased this past drilling season for fuel, frac sand and fluids.
“All I know is that our customers are hard-pressed to give anything back,” Salkeld says, although he acknowledges some oilfield service provider / client negotiations are proving to be more realistic and productive in terms of addressing the current realities facing the service sector.
“There are relationships out there where the customers are letting the services increase their rates. They know they’ve had a good strong relationship through the downturn. They know the cost savings that they’ve enjoyed, for the most part on the backs of the service providers, through the supply chain and some through innovation,” Salkeld says.
“But it was lowering invoices which meant us laying off people, lowering wages, racking equipment and cutting back on benefits and bonuses. And the producers are enjoying good margins because of that, for the most part, I would be so bold as to say.”
Eye on Saskatchewan
Reduced costs can largely relate to the types of wells and areas companies are developing.
Last fall, when Scotia Waterous Inc. compared 55 U.S. and Canadian oil plays, it found six Saskatchewan oil plays were in the top 10 in North America when ranked by profit / investment ratio (PIR), with all six plays breaking even at a WTI oil price of US$40 a bbl and some breaking even at US$35.
Frobisher/Alida oil in southeast Saskatchewan ranked second by profit/investment ratio, and the southeast Saskatchewan Ratcliffe play ranked third.
Southeast Saskatchewan Viewfield Bakken oil, southwest Saskatchewan Upper Shaunavon oil and southwest Saskatchewan Viking oil ranked sixth, seventh and eighth, respectively. Meanwhile, Southeast Saskatchewan Border Midale oil had the 10th-best profit/investment ratio of the 55 plays.
All of these plays are relatively shallow and cheap to drill compared to some of the deep shale plays. It obviously helps that all six are oil plays. In addition, the two top-ranking Saskatchewan oil plays on the list — the Frobisher and the Ratcliffe — are conventional Mississippian plays that don’t require fracture stimulation.
Saskatchewan’s appeal has been evident in recent data for new well permitting. Operators in the province licensed 1,007 new wells in the first three months of 2017 compared to 341 in the first quarter a year ago. By comparison, 1,183 new permits were issued in Alberta in Q1 2017.
Ed Dancsok, Saskatchewan’s assistant deputy minister and petroleum and natural gas development senior strategic lead in the ministry of the economy, says the break-even benefits of doing business in Saskatchewan are about more than royalties.
“It is about the low-cost drilling opportunities we have. Most of the province is farmland east. It is easily accessible, good infrastructure, good support regulatory-wise from the government, and it is also about the fiscal regime we offer industry — drilling incentives for horizontal wells, incentives for [EOR], as well as the regulatory framework that just allows for an ease of operations in Saskatchewan.”
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