For Canada’s bruised and battered upstream companies there is no escaping talk these days about their chances of fending off takeover bids.
Some may be inclined to wait for an acquisitor with bulging pockets to knock at the door.
Others like Legacy Oil + Gas, a leading player in the Saskatchewan Bakken, are taking the high road.
Bryan Gould, chief executive officer of acquisition-minded Aspenleaf Energy, said companies weighed down by debt, struggling with low market credibility and lacking access to capital are getting squeezed.
He said that no matter how good their asset portfolios are, there are few companies that can avoid an overriding question.
They are all faced with trying to determine “whether there is light at the end of the tunnel and how far out it is. Maybe there is great upside and greater value, but it’s a long ways off and there are a lot of hurdles between here and there.”
Legacy, rather than dwelling on the unknowns, is playing to its strengths.
Capital discipline
Having grown from 300 barrels of oil equivalent per day to what it hopes will be an exit rate this year of 27,300 boe per day (with a large chunk dependent on its trail-blazing contributions to waterflood recovery methods in Saskatchewan’s Midale play) it is outwardly brimming with confidence.
Chief Executive Officer Trent Yanko said his company is focusing on capital preservation and maintaining liquidity under reduced cash flows by shrinking discretionary spending and high grading opportunities.
He said that since fall 2013, Legacy has closely watched over its capital spending by living within and, since last year, underspending cash flow that has had the “positive effect of reducing our debt-to-cash flow ratio to 1.5 times or less.”
In addition, two takeovers last year of privately owned Corinthian Exploration and Highrock Energy (with combined production of 4,800 boe per day) have placed Legacy in a “position of strength to begin ramping up our growth profile through a combination of cost control,” Yanko said.
He said the acquisitions were primarily driven by the “upside” opportunity presented by the location of the assets, their associated drilling inventory and the “very high netback light oil which fits in perfectly with our strategy.”
As well the acquired companies came with “very little debt” which in turn reduced Legacy’s debt-to-cash flow, he said, adding: “So it was a very good strategy to pursue and we’d look at doing it again. We’re always primarily focused on our organic drilling program.”
Fracks and waterfloods
In the forefront of Legacy’s growth prospects is its Midale reservoir which offers a “new twist on an old play” that had produced in Saskatchewan and North Dakota for about 60 years, Yanko said.
“We’ve been able to go into areas of the reservoir that hadn’t produced very well with either a conventional vertical well or a conventional horizontal well” and applied the company’s expertise on innovation and multi-stage fracturing of horizontal wells to turn uneconomic wells into “very highly economic” producers, boosting the Midale output from 300 bpd to 7,500 bpd, he said.
Over three years, Legacy has had “superior well results,” increasing drilling locations from six wells to 350 and raised that target to about 500 from two new pool discoveries in 2014, he said.
“From an inventory standpoint we could dwarf any of our competitors and our expertise is allowing us to generate some stellar economics,” Yanko said.
On the waterflood front, Legacy has managed to utilize its skills to double recovery factors from many of its reservoirs, establishing a “very cost-effective, low-risk way of adding reserves and reducing the decline profile,” while applying the technique to resource-style plays it has fracked in the past, he said.
The end result is that Legacy believes it has “found a great way of adding a lot of value and extending the life of the company,” Yanko said.
2015 spending
On the cautious side, Legacy has set a capital budget for 2015 of C$238 million, down 40 percent in organic capital spending year-over-year, with 87 percent allocated to drilling, completions, equipping and waterfloods, targeting 94 gross (74.5 net) wells. Topping the list of plays is Taylorton/Pinto in Saskatchewan, which has a C$100 million budget, while Steelman will get C$37 million. It is currently awaiting approval for second waterfloods in both Saskatchewan and North Dakota.
The company has total current borrowing capacity of C$1.03 billion, including C$225 million of unsecured term debt that does not expire until 2017.
Legacy said that based on industry research and analysis over the past 40 years world oil prices “have generally averaged at or near the worldwide cost of reserves replacement” which is currently estimated at US$90 per barrel of West Texas Intermediate.
The company said it “expects oil prices to eventually return” to the US$90 level, but, setting that aside, it is prepared to use its high operating netbacks and high quality inventory to function through a “period of lower and volatile prices, preserving capital in anticipation of an eventual return to historical average prices.”
A major revival in industry activity in Alaska’s Cook Inlet basin is turning a pending shortfall of gas for Southcentral utilities into a gas surplus, with contracted gas supplies from the basin extending several years into the future. But how much gas now remains to be developed in the basin? And how long might gas supplies from the basin last?
In a Feb. 14 meeting of the Commonwealth North Energy Action Coalition in Anchorage Paul Decker, acting director of Alaska’s Division of Oil and Gas, reviewed the current state of knowledge of gas resources in the basin and the impact of the upsurge in exploration and development on production forecasts.
Two studies
During the gloomy days of pending gas shortages the division conducted two studies of Cook Inlet gas resources. The first of these studies, completed in 2009, used production and geologic data from Cook Inlet gas fields to assess how far into the future the gas fields might support the continuing utility gas demand in Southcentral Alaska of some 90 billion cubic feet per year. The second study, completed in 2011, considered the economic feasibility of the projections made in 2009. Now, a few years later, it is possible to compare what has happened in terms of gas production with what those reports suggested might be possible.
In the 2009 study, an assessment of the production decline from existing gas wells showed that, in the absence of any further gas field development, production would soon have fallen short of utility gas demand, Decker said. However, the use of gas reservoir pressure trends to assess how much gas might be produced from existing gas reservoirs, assuming the drilling of new development wells to access that gas, demonstrated that the gas shortfall could be deferred somewhat. A geologic analysis of well data to extrapolate the likely extent of gas-bearing horizons in four of the larger gas fields suggested further potential for development drilling in existing field reservoirs. That pointed to the possibility of meeting the 90 bcf per year gas demand target out to 2018 or 2019. However, factoring in further potential pay zones with a 50 percent likelihood of development success extended that time horizon to around 2027 or 2028, Decker said.
Economic analysis
Recognizing the extensive investment that would be needed to push Cook Inlet gas production out into the future, the division’s 2011 study applied a series of economic variables to various production scenarios, using a statistical technique to derive a probability distribution for possible future production profiles. The analysts found that production of the required 90 bcf of gas per year appeared economically feasible until at least around 2018 or 2020, and that gas exploration success would likely move that time horizon well into the future. In 2013 the division reviewed the results of its earlier work, estimating that 1.1 trillion cubic feet of gas remained in the 28 known fields around the basin. At that point, about 8 tcf of gas had already been produced from the basin, Decker said.
Recent developments in the Cook Inlet basin have tended to support the conclusions of the division’s studies, with new utility gas supply contracts now lined up through around 2018 or 2019, Decker said.
Hilcorp impact
A prime driver behind the recent uptick in Cook Inlet activity has been Hilcorp Energy, the company that in 2011 and 2012 took over the oil and gas fields formerly owned by Chevron and Marathon.
Hilcorp has “absolutely transformed the commercial landscape for gas in the basin,” Decker said.
In addition, a new gas storage facility, the Cook Inlet Natural Gas Storage Alaska facility near the city of Kenai, has stabilized seasonal gas production by enabling the storage of surplus summer production for use in the winter, when demand is high. And in 2012 Buccaneer Energy brought the new Kenai Loop gas field on line on the Kenai Peninsula, Decker said.
Since the upsurge in Cook Inlet activity began, 75 new wells have been drilled in the basin, with 22 of these wells being exploration wells; 36 of the wells have been gas wells, Decker said. Well workovers and other forms of production enhancement have resulted in gas reserve additions of some 3 percent, he said. And new knowledge gleaned from new development drilling has caused the division to increase its gas resource estimate for the seven largest gas fields by 440 bcf, he said.
New exploration
Meantime, active exploration in the Cook Inlet basin is starting to bear fruit. Furie Operating Alaska has been moving ahead with its offshore Kitchen Lights field. A Kitchen Lights appraisal well demonstrated the existence of 29 gas-bearing horizons in the field. And, while verified reserves figures for the field remain confidential, initial plans for the field envisions the production of 80 million cubic feet per day of gas, Decker said.
Offshore the southern Kenai Peninsula, drilling by Buccaneer in the Cosmopolitan prospect found a significant gas resource at relatively shallow levels. BlueCrest Energy, the company that now operates Cosmopolitan, wants to transfer the rights to the gas resource to WesPac Midstream, a company interested in building a small liquefied natural gas facility for the supply of gas to Fairbanks in the Alaska Interior. WesPac’s development plan envisages two small offshore monopod platforms and up to 12 wells, Decker said.
Decker commented that significant gas exploration potential remains in the Cook Inlet basin, although future gas discoveries may involve relatively small, subtle underground gas traps, rather than the large geologic structures that characterize the gas fields that have been discovered in the past. The U.S. Geological Survey has estimated that there may be about 19 tcf of undiscovered gas in the basin, he said.
Future demand
But, as a major gas line from the North Slope also becomes a future possibility, what might be the potential future gas demand in Southcentral Alaska? In addition to the local utility demand, there are an LNG plant that ConocoPhillips operates at reduced capacity on the Kenai Peninsula and a nearby mothballed fertilizer plant, owned by Agrium. Japanese company Resource Energy Inc. has proposed constructing an LNG plant for exporting LNG to Japan; WesPac has its LNG plant proposal; and there is a future possibility of supplying Cook Inlet gas by pipeline to the planned Donlin Gold mine in western Alaska. The total demand from all of these projects, if all were to fully come on line, would amount to about 275 bcf per day, a figure that suggests a need for some prioritization in determining what is implemented, Decker said.
However, the potential economic viability of Cook Inlet gas and the resurgence in the Cook Inlet gas industry bode well for the local economy in the Cook Inlet region. Future unknowns include price comparisons between Cook Inlet gas and North Slope gas delivered to Southcentral, if the North Slope gas line is built. People need to make sure that, whatever happens, as much gas as possible is produced from the Cook Inlet, Decker said.
