Opportunity knocks in energy industry crisis, say lawyers

With the price of oil sinking to lows not seen in years, the oil & gas industry continues to play defence. But in crisis, opportunity knocks for clients

“There are good opportunities in a crisis. So don’t waste them.”

Those may be the most optimistic words about the current state of the Canadian oil and gas industry to seep out of the gloom of 2015.

They come from Chip Johnston, a partner in Stikeman Elliott LLP’s Corporate Group in Calgary. A blunt vet of the Canadian oil patch, Johnston laments the fretful drop in oil and gas prices and the resulting bashing of profits and massive lay-offs in his home province. According to widely reported figures out by Stats Can’s national Labour Force Study Survey on Jan. 29, Alberta’s net job losses (not specified by job sector) in 2015 were 19,600.

“I think the opportunity for innovation is pretty big right now for everybody” in the industry, says Johnston. “I think that thinking has been disrupted and that causes people to look at things in a different way. And that leads to innovation, which results in greater productivity down the road.”

At the beginning of 2015, West Texas Intermediate Crude fetched US$52.72 a barrel. By February 2016 it traded in the US$33 range. Oil hasn’t been that low since June 2002 and only bottomed to $43.90 in February 2009 during the depths of the global financial crisis, according to the U.S. Energy Information Administration.

Who would dare predict where it will go in 2016? Grab one expert and he or she will suggest we may hit $20 oil as over-production and slowing demand continue. Grab another and you’ll hear hopeful talk there might be a recovery towards the $60s or even $70s towards the end of 2016.

 

Certain uncertainty

All that’s certain, at the moment, is that the Saudi-led OPEC effort to flood the world with oil in an effort to reduce competition and drown out marginal producers, mainly in North America, has initiated tectonic shifts in the Canadian and US energy sector. There was one sigh of relief for the oil patch in wild rose country: On Jan. 29, Alberta’s NDP Premier, Rachel Notley, announced she would accept a royalty review panel recommendation to maintain the existing royalty structure for the province’s oilsands sector. Saying that with oil prices regularly dipping below $30 per barrel, leaving Alberta “in a precarious and somewhat struggling situation,” the NDP would also keep the current royalty rates for wells drilled before 2017 in place another decade. For wells drilled after 2017, the new regime will preserve existing rates of return at the outset and simplify calculations with a flat five per cent royalty rate until drilling costs are recovered, when the rate will increase.

Still, coupled with the new NDP government in Alberta, a new Liberal government in Ottawa, and new climate-change agreements in Paris and Alberta designed to both cap and put a price on carbon emissions fossil fuels at the producer and consumer level, and these days shell-shocked 1,000-yard stares are commonplace in the Canadian energy patch.

“I have tried to stop reading the papers, because every time I read it is unbelievably bad news,” says Derek Flaman, an energy lawyer and partner at Torys LLP in Calgary. Yet, like a car accident, it’s hard to turn away from the scene.

Saudi Arabia and its OPEC allies began using unlimited oil and gas production to attack North America’s energy in November of 2014. There have been casualties: In its latest report, last October, the Conference Board of Canada estimated Canada’s oil extraction industry would suffer pre-tax losses of $2.1 billion in 2015. That compares to a $6-billion profit in 2014. (The board suggested things would improve in 2016, for what that’s worth.)

Capital expenditures intended for new projects or current assets have been slashed everywhere. Many majors have taken razors to their capexes for 2016. Cenovus Energy cut its spending budget 19 per cent, down to about $1.4 billion from between $1.8 to $1.9 billion. Encana cut its 2016 capex more than 25 per cent, shaving down to about $1.5 billion.

Lorne Carson, a partner in the Calgary office of Osler, Hoskin & Harcourt LLP who focuses on project development and finance in oil and gas, is seeing increased renegotiation of credit agreements and financial covenants, the maturity terms on loans, and the conversions of unsecured or subordinate debt into equity as lenders try to help brighten the balance sheets of borrowers. These can be tough negotiations for clients and their lawyers as well. “It’s not the same as where you do a new financing and you have a closing dinner,” Carson says with a subdued laugh. “They can be a bit more tense. But it is business that needs to be done.”

 

Playing defence

The industry as a whole is playing defence, with a growing number of companies trying to ward off insolvencies and buffer themselves against continued low pricing, says Carson. “Basically what companies do in harder times is they look at selling non-core assets where they can raise money, pay down debt.” They may use some of it to keep capital programs going ahead.

Most mid-sized and larger players are not facing insolvency. But they are selling off non-core assets – often midstream assets such as gas processing facilities or pipelines – to rebalance their books. Husky Energy Inc. President and CEO Asim Ghosh, declaring the oil and gas industry is in “unchartered territory,” announced late last year that Husky was in discussions to sell some pipeline assets and oil-storage facilities in the prairies to “unlock value” and pay down debt. It was also considering selling royalty assets producing 2,000 barrels of oil equivalent per day (BOE/D).

Those are two approaches echoing through the Canadian energy sector, especially in the west. And, while merger and acquisition activity largely came to a halt beginning in the summer of 2015, save a few notable exceptions (Crescent Point Energy’s acquisition of Legacy Oil and Gas for $1.53 billion and Suncor’s at first hostile all-stock $4.3-billion bid for Canadian Oil Sands that ended on a friendlier note on Jan. 19 when the companies announced a $6.6 billion agreement), there are intimations that in 2016 there’ll be more M&A. “Certainly the pressure for companies to sell is increasing,” says Donald Greenfield in Calgary. “And it’s increasing work for restructuring and insolvency lawyers.”

 

Mind the valuation gap

Greenfield, co-leader of Bennett Jones LLP’s Energy Practice Group, has nearly 40 years’ experience in Canadian and international LNG and oil sands development. He says one challenge faced by clients as commodity prices sink and they ponder selling off assets or royalties as revenues fall are the valuation gaps. “Sellers think their assets are worth X in a rising oil price scenario — in other words it can’t stay low for much longer. Whereas buyers don’t know if the bottom has been hit. Even if it has, how long is it going to last?”

But the gap appears to have “narrowed a little bit” as desperation rises, says Carson. “We are starting to see more transactions occur on the non-core asset sales. And that has been mainly because sellers lowered the price they are willing to accept” as oil went into the $30s.

While few outright bankruptcies have yet to hit the Canadian energy sector, some juniors have been extinguished by continued weak commodities prices. Two days before Christmas, Calgary-based junior Shoreline Energy Corp filed for bankruptcy after a failed merger attempt and selling assets to satisfy secured creditors. Greenfield mentions Spyglass Resources Corp. as a recent casualty. A better scenario than bankruptcy and receivership, he notes, is to file for protection under the Companies’ Creditors Arrangement Act (CCAA). That allows companies to keep creditors at bay and restructure for a period of time while they continue to run their business under a court-appointed monitor. Both Connacher Oil and Gas Ltd. and Laricina Energy Ltd. in Alberta took that route.

“Companies with a lot of bank debt are going to be seeing their banks write down the lending value of their reserves, and seeing their borrowing limits cut back,” predicts Greenfield. That would presumably force them to do things to raise cash, such as selling non-core assets. “Or worse, core assets,” he adds. Greenfield also sees the pool of oil & gas juniors and exploration and production (E&P) companies shrinking even more this year. That worries him: Traditionally, the juniors have fostered much of the innovation in the sector.

 

Bending for royalties

The other defensive theme is selling royalty assets. Primarily, stresses Janice Buckingham in Calgary, who chairs Osler’s Oil & Gas Practice, the royalty deals being done are not by companies in great financial distress. Instead, they’re companies trying to monetize interests that are no longer core assets. The money raised may be used to pay down debt or reinvest in their highest margin operations.

In June of this year, for example, the Ontario Teachers’ Pension Plan paid $3.3 billion for Cenovus Energy’s Heritage Royalty Limited Partnership, a portfolio of oil and gas royalties on nearly five-million acres of land in western Canada. That land generates royalty revenue from other companies, which drill and produce oil and gas on it. In a statement at the time of the sale, Cenovus CEO Brian Ferguson stated the proceeds “will strengthen our balance sheet and provide us with greater resilience during these uncertain times as well as the flexibility to invest in organic projects with strong returns.”

“As much as we wanted to hope there would be a short-term price recovery,” Buckingham says, “the lower-for-longer price mentality has been accepted by companies. So we’re looking at different scenarios in order to maintain profitability in the hopes prices do recover — because they always do. And when prices recover, they will be well positioned.”

 

Private equity

Speaking of well positioned, sniffing for opportunity are cash-rich private-equity firms, not to mention Canadian pension funds. They’re looking for companies with reasonable balance sheets and proven assets, but whose valuations have become cheaper as their stock prices plummet in concert with commodity prices. But could the shockingly low oil prices and some gut-wrenching forecasts of even US$20 crude in 2016 scare off even private equity, regardless of attractive valuations? Though he’s occasionally wondered that, Flaman doesn’t think so. He has represented some of the largest private-equity firms in the world, including US firms Blackstone Group and Kohlberg Kravis Roberts & Co. (KKR) as they’ve sought interests in Canadian energy assets in recent years.

In conversations with those PE clients, says Flaman, “They actually don’t take that Chicken Little the-sky-is-falling view. They take the view these things work in cycles. You look back at the last cycle around the financial crisis in 2009 and 2010, and the headlines were the world is ending.

“In a nutshell,” he continues, “when commodity prices are low, well-capitalized PE firms, as a general statement, like to take advantage of that environment and acquire quality assets.” He sees that activity ramping up in 2016, with both American PE firms and smaller Canadian ones such as ARC Financial Corp. and Azimuth Capital Management seeking quality assets. So far, the bulk of PE interest has been focused on midstream assets such as transportation systems and pipeline facilities, oil and gas storage or processing plants.

PE firms generally aim to recoup a return on their investments via a liquidity event in five to seven years. They’ll either privately sell a company or asset, or take a company public with an IPO and sell equity in it through the stock market.

But, says Neville Jugnauth – Flaman’s colleague and a fellow partner at Torys in Calgary – until the dust is settled on such issues as the Alberta Royalty Review, the province’s Climate Leadership Program and the Paris agreement on climate change, PE firms may hold back on triggering deals in the Canadian energy sector.

 

From Paris to Alberta

The Paris agreement, signed December 12th, won’t become legally binding unless at least 55 countries representing 50 per cent of global greenhouse gas (GHG) emissions ratify it in New York in April. It calls on signatories to curb aggregate emissions sufficiently to hold the increase in the global average temperature to below 2°C above pre-industrial levels and to pursue efforts to limit the temperature increase to 1.5°C.

Shortly before the Paris conference, on November 22, Alberta’s new NDP Premier, Rachel Notley, announced the Climate Leadership Plan. The sweeping carbon-reduction plan includes a new economy-wide carbon tax starting at $20 per tonne in 2017 (the rate was previously $15) and increasing up to $30 a tonne the following year. The plan would also phase out coal-generated electricity in Alberta by 2030 and cap GHG emissions from the oil sands sector at 100 megatonnes from its current estimated output of 70 megatonnes.

The NDP promised the $3 billion or so raised annually by the plan will stay in Alberta, with some money spent on technologies to further fight climate change. That includes development of renewable energy and green infrastructure. Some funds would also be used to help lower-income households deal with the resulting increased transportation and heating costs through a rebate program.

Notley says the new climate regulations will remedy Alberta’s reputation for producing “dirty oil” and thus improve market access for Alberta crude abroad. In public at least, several major oil-industry leaders, including Canadian Natural Resources Chairman Murray Edwards and the Canadian Association of Petroleum Producers (CAPP), applauded the climate plan, saying it would spur growth in the Alberta oil and gas industry. CAPP predicted that as cleaner-burning natural gas plants replaced coal plants, they would increase natural gas demand in the province by about 1.5 billion cubic feet per day. Under the 2015 royalty regime, that would generate $140 million per year in new revenue for Alberta because natural gas royalties are much higher than those on coal.

Though the anxiety over Alberta’s oil and gas royalty structure has thankfully passed, the prospect of further climate-related regulation changes, not to mention the prospect of more oil flooding the markets from Iran and now the US (which recently lifted its 40-year ban on exporting its own crude abroad), has industry experts questioning Alberta’s competitiveness on the global energy front. With the Trudeau government praising both the Paris agreement and Alberta’s climate plan (though it has expressed concerns about job losses in the Canadian energy sector) but yet to enunciate a federal energy strategy, “it’s the perfect storm,” says Flaman. That storm intensified Jan. 27 when the Trudeau government announced new regulatory hurdles that will add, for instance, nine months to the review time for TransCanada Corporation’s $15.7 billion Energy East Pipeline and more time to other projects. The Liberals, while saying they aren’t trying to shut down the energy industry, said they needed to restore public faith in the assessment process and increase consultations with First Nations.

In speaking with his clients and industry veterans, Flaman frets that all the factors – from low prices on oil to higher prices on carbon emissions – have already begun pushing investment and oil and gas production out of Alberta. “Why would you invest in Alberta when you can invest in Saskatchewan or BC, or even Texas and the US, where you don’t have the same infrastructure and pipeline issues you see here in Canada?” Or, for that matter, he adds, when you can invest outside of Alberta and enjoy better royalty treatment (at least at present) and, generally, less onerous environmental regulations.

At Bennett Jones, Greenfield says his clients wanted the royalty structure to be simpler and to recognize and reward the cost of new technological development. At least they got that. But worries abound, he says, referring to a recent survey of upstream oil and gas executives on investment perceptions of Alberta by the Fraser Institute. It found that an increase of Alberta’s corporate tax rate to 12 per cent from 10 per cent, along with concern over the royalty review and the Climate Leadership Plan, had led to a dramatic 25 per cent increase in negative perceptions.

The authors wrote in their report: “These negative shifts may not bode well for Alberta given that the province’s immediate geographical competitors remain attractive as jurisdictions in which to invest, or are improving.” They pointed out Saskatchewan as a strong competitor that could steal development and investment away from Alberta.

Greenfield and other lawyers interviewed say they’re already seeing evidence producers deferring investment in Alberta, or, worse, of so-called “carbon leakage” — the industry term for business migrating from one jurisdiction to another. Last November, for instance, Encana CEO Doug Suttles said his company was deferring investment in a gas plant in Alberta’s Duvernay formation until after the royalty review and legislation surrounding carbon-pricing and GHG emissions has been completed.

Yet not everyone fears carbon leakage will vacuum investment and jobs out of Alberta and deposit them in places such as Saskatchewan, North Dakota or Texas. In Sarah Powell’s estimation, as Alberta phases out coal and caps emissions on the oil sands, investment in renewable energy will grow significantly. Powell, a Toronto partner in Davies Ward Phillips & Vineberg LLP’s Environmental, Aboriginal and Energy practices, is one of Canada’s leading environmental lawyers. She’s worked extensively with industry and government in such areas as hydro and wind energy.

While she acknowledges that initially some investment may trickle out of Alberta, she says, “I don’t see carbon leakage as possible. The world is changing and the world is going to put a price on carbon. So whether you have operations in North Dakota or Saskatchewan, there’s going to be a price on carbon. You are not going to be able to sit in Saskatchewan with your head in the sand, no pun intended, and say we won’t go that route. There will be a price imposed upon you.”

Alberta, she says, has finally responded to that shift. And Ontario, she adds, is proof a province can quickly switch its energy needs from one source to another. In 2009, Ontario’s government passed its highly controversial Green Energy Act, designed to support and expand renewable energy development. “There were a lot of skeptics about whether or not the private sector would, one, respond, and two, whether that response would be bankable,” recalls Powell. “By bankable, I mean would they be able to get the huge amount of financing they needed from lenders to build out the wind and solar projects they were proposing to do?”

Although this was happening in a capital-constrained environment as the world plunged into the global financial crisis, “the investment community was willing to come in,” says Powell. Though conceding there is still much criticism about how Ontario moved toward renewable energy, Powell says the province proved a massive shift is possible. In Alberta, she predicts, renewables are going to “mushroom” as the province replaces coal power.

 

Bright spots

Not every region of Canada’s oil and gas industry is whimpering. In the Atlantic provinces’ offshore industry, especially in Newfoundland, companies are striving to cut costs, but there have been few job losses due to low oil.

Canada’s east coast oil play has a number of features distinguishing it from its western counterparts, says Alexander (Sandy) MacDonald, Managing Partner at Cox & Palmer in St. John’s, Nfld. There are no small independent and junior operators in the region at all. There’s less environmental resistance to new projects, and, because tankers, not pipelines, are used to transport crude, no new and politically sensitive infrastructure needs to be built to access more markets both inside and outside the US.

Offshore development, like Alberta’s oil sands, is extremely capital-intensive. Development planning entails very long lead times. A conventional drilling program in western Canada can take 18 months from start to finish. An offshore development, excluding the exploration phase, can easily take eight to 10 years. “So no one now is making investment decisions today based on current oil prices,” says MacDonald. The majors – companies like BP, Statoil, Husky, Chevron and Exxon – which are developing offshore projects off the east coast, “tend to discount the short-term fluctuations in price,” explains MacDonald. Instead, they are basing their development and investment decisions on oil price forecasts three or more years down the road.

While oil companies are loath to disclose the forecasts they’re basing new development on, a successful sale of offshore leases in October by the Newfoundland government led to more than $1.2 billion in work commitments and increased optimism in the Atlantic sector.

Meanwhile, the picture for liquid natural gas (LNG) development in British Columbia is less rosy. Just two years ago, BC Premier Christy Clark boasted that LNG development would create tens of thousands of jobs and lead to a $100-billion prosperity fund for the province’s future. But that was when natural gas was fetching a peak of US$18 per million British thermal units (MMBTU) in Asia, while it was worth just two or three dollars (US) in Canada. That spread made LNG development in Canada attractive. There are now 20 BC LNG proposals awaiting final investment decisions in the province. But few, if any, are likely to go ahead.

As oversupply has come from new development in countries such as Qatar and Australia, the price of LNG in Asia has fallen to the US$7 range. Forecasts for 2016‒2017 peg it at $4 to $5 MMBTU. By some expert estimates, the break-even point for BC LNG is $12 MMBTU. “You’ve got to think the risk bias is negative rather than positive,” for LNG development in BC, admits Johnston. “Pricing is so terrible, it will be very difficult for an executive team to push the button on major [LNG] commitments.”

Still, Johnston still sees BC LNG being developed in time. “I think eventually that supply comes on, the world needs it. Natural gas is a big way of solving some of the carbon issues for people.”

His optimistic streak regarding the western Canadian industry surfaces again: He says there are still plenty of professionally managed energy investment dollars in private-equity firms and in the Canadian pension fund community looking for entry points to invest in Canadian oil and gas. And while the current crisis has shaken excellent talent out of jobs, many are reorganizing themselves into new start-ups and are looking to raise capital privately or publicly to acquire their own assets. They might not get the money just now, says Johnston, “but it will come again.”

In the past two years, as oil and gas prices tanked, “some companies stayed crisp and frosty, but a lot didn’t,” remarks Johnston. “But this is an opportunity to refresh all of that and create an even stronger industry than we had before.”