Under a new helmsman for the first time in 12 years, Calgary-based Enerplus has experienced a fresh jolt of life with Ian Dundas as a chief executive officer who sees hope in the company’s new frontiers.
Once embedded in the Western Canada Sedimentary Basin, with 75 percent of its business derived from the region’s conventional natural gas, Enerplus now rates the Bakken and Three Forks plays in North Dakota as its largest project, with the U.S. Marcellus shale play as a prime growth driver.
As Canada’s gas sector struggles to keep its head above water, Enerplus has tipped its investment balance decisively to oil.
“The company has transformed itself,” said Dundas. “We are not the company we once were.”
Although the Canadian gas sector is far from down and out, a “pure gas play without any liquids in Alberta is going to be challenged,” he told the Financial Post.
To underscore its change of direction, Enerplus unloaded 33,300 acres in Western Canada’s Montney formation last year, pocketing C$130 million from a return of C$3,900 per acre in an area that offers “significant scope and scale” as an eventual dry gas play, Dundas said.
Goal to build on success
For Enerplus the immediate goal is to build on its success in 2013, when it added 8,000 barrels of oil equivalent per day to production, reaching 90,000 boe per day and targeting 98,000 boe per day for 2014.
Its proved plus probable, 2P, reserves were also raised by 60 million boe to 406 million boe.
For 2013 “we delivered on our objectives of improving on our cost structures,” said Dundas, noting that finding and development costs were improved by 50 percent year-over-year to C$11.28 per boe.
“We delivered very attractive on-stream efficiencies, beating our internal targets and showing meaningful improvement from 2012 and 2011.
“We also advanced our strategic objective of continuing to consolidate our portfolio around four core areas. That involved buying strategically where we saw opportunities and rationalizing non-core properties, both undeveloped acreage and producing properties,” he said.
In particular, North Dakota achieved “significant improvement in our capital structures, associated with improvements in productivity,” Dundas said.
“Our initial productivity from wells in the Bakken and Three Forks improved almost 50 percent from 2012,” he said.
Given how investors viewed Enerplus and its financial prospects about a year ago, Dundas suggested the promised financial change “really showed up” in 2013, based on operational performance and “what it meant to our payouts, the sustainability of our growth and the affordability of that growth.”
Gas sector retooling
What Dundas referred to as the transformation of Enerplus was nothing short of essential in a gas sector that has forced Canadian companies to retool and reinvent themselves in the face of a dramatic shrinkage of demand for their product as shale gas has swamped U.S. markets.
Those companies have been broadsided by the collapse of natural gas prices from double digits to below US$2 per million British thermal units in the space of two years, although benchmark AECO prices did climb back above US$4 during the peak winter-heating season.
RBC Capital Markets has given no reason for renewed optimism by forecasting AECO prices of US$3.58 this year and US$3.74 in 2015.
Rather than bemoaning its fate, Enerplus promoted 12-year veteran Dundas to the CEO’s office last year when Gord Kerr stepped down after steering what had been an energy trust through a painful transformation into a dividend-paying intermediate-size producer.
He was already operating at peak speed when he occupied the top rung, intent on delivering sustainable, profitable growth and income to investors by focusing on top tier resource plays and mature assets with low decline.
Capital budget up
The capital budget for 2014 has been set at C$760 million, up almost C$80 million from last year, C$300 million-C$325 million earmarked for the North Dakota assets, including drilling, completion and tie-in of 20 net wells, seven of them testing downspacing in the area.
The company said it has started drilling into the lower benches of the Three Forks, to test the productivity of those zones.
The operated Bakken/Three Forks position includes 145 net future drilling locations, with light oil expected to account for 25 percent of Enerplus’ 2014 production and Williston Basin output projected at 28,000 a boe per day - 20 percent from Sleeping Giant and 80 percent from Fort Berthold.
Enerplus estimates its 2P reserves in the Williston at 131 million boe, 105 million boe of which are in 73,000 net acres of Fort Berthold.
The company is counting on production growth of 33 percent this year in Fort Berthold to 22,000 boe per day, after achieving self-funded status last year and with hopes high that it will generate free cash flow this year.
In 2013, 400 percent of Fort Berthold production was replaced, adding 24.9 million boe at an F&D cost of US$19.74 per boe. A 2P reserves report has indentified 98 net future drilling sites.
The play has about seven years of inventory and a 2P recovery factor of 15 percent, while downspacing holds the promise of 150 net additional locations and another seven years of inventory.
Capital efficiencies in Fort Berthold made a sharp drop to US$12.30/boe in 2013 from US$19.80 in 2012, while production rose 50 percent to almost 38,000 boe per day, while well costs dipped to US$12.10 from US$13.10.
Little takeaway concern
Enerplus has little concern about takeaway capacity from North Dakota and Montana, estimating combined rail and pipeline capacity out of the Bakken is 1.4 million barrels per day, about 25 percent over current production.
In the Marcellus, Enerplus said production continues to surpass expectations, with output this year targeted at 120 million-140 million cubic feet per day, up 37 percent from 2012 from 2P reserves of 601 billion cubic feet, which surged by 168 percent in 2013.
In Alberta’s core-growth Deep Basin, Enerplus has about 450 potential net future drilling locations in the liquids-rich Duvernay and Wilrich plays, with Wilrich offering 2P reserves of 61.6 billion cubic feet from 60,000 net acres and drilling costs dropping 40 percent since 2011 to almost C$4 million per well.
The Willesden Green in the Duvernay Shale includes 85,000 net acres (with a 100 percent working interest) accumulated over the past three years at C$750 per acre.
The company said “core analysis from vertical tests supports a range of free condensate yields across a significant portion of the acreage.”
The last of the core operations are the company’s waterfloods in Alberta and Saskatchewan, which have an estimated 160 future drilling locations, 2P reserves of 87 million boe, original oil in place of 1.3 billion boe and final quarter output last year of 17,000 boe per day.
