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For the thousands of new entrants into the oilfield services (OFS) industry in the past 15 years - both workers and companies – if you didn’t know what senior secured lending covenants were a year ago, you sure do now. Whether your vehicle has been repossessed, your company is surviving on covenant waivers, or you or one of your competitors have been forced into receivership, OFS is getting a crash course on the downside of credit, banks and borrowing. Lenders want their money back and the oil price collapse has crippled your ability to make the necessary payments. Who knew when you signed that loan agreement things would deteriorate to this point?
As the Canadian oilpatch enters its second year of very tough times, much has been written about debt and the problems associated with carrying too much of it. Whether exploration and production (E&P) or OFS, publicly traded companies considered over-levered have had their share values clobbered. A growing number of companies are being forced into receivership because their lenders have determined meaningful capital recovery the old fashioned way (make the principal and interest payments) is hopeless. Some borrowers offside on their lending covenants are on their third or fourth round of relief through forbearance letters or equivalent, something parties on both sides of the transaction hoped would no longer be a problem in 2016. While the rules governing how borrowers and lenders ought to interact with each other have been around for decades, in the current market not everyone is exactly sure what to do next.
Many new borrowers are enduring a painful education on the legal implications of the lending documents they signed. Hidden in the small print and legalese is the fact that when the loan was accepted - whether a capital lease or senior secured credit facility - either your assets or your company are technically not yours until the debt obligations are repaid in full. When you can no longer make principal or interest payments, you no longer have any legal claim to the collateral, whatever that may be. Depending on what you borrow and the terms and conditions, for private owner / operators it could be your life’s work. Few, if any, figured their investment and sweat equity could one day be worth nothing when they signed the loan papers.
Lenders, on the other hand, have been forced by market circumstances to redefine flexibility. The rapid and mono-directional decline of upstream oil and gas revenue, cash flow, liquidity and asset values has all but overwhelmed suppliers of debt capital. Macroeconomic conditions have deteriorated much more quickly than either borrowers or lenders have been able to adapt to. Instead of flexing their muscles and exercising their security to recover their capital, Canada’s six largest banks, for example, are more inclined to focus on explaining how only a small percentage of their total asset base (remember your liability is your lender’s asset) is exposed to the oil and gas industry.
Reams have been written about public companies violating their lending covenants and the lengths to which their lenders have gone to keep their client companies alive. Forced or negotiated asset sales and equity issues to pay down debt are common. Better to try to make the current situation work if possible than face certain losses in the case of forced liquidation. Nobody who employed debt capital markets to grow their company in the past had any idea some of the current lending terms were available.
Canada’s big six banks have been kicking the can down the road for over a year. Finally, in the first reporting quarter ended January 1, 2016 the Bank of Montreal, Royal Bank of Canada, Toronto Dominion Bank, Scotiabank, Toronto Dominion Bank, Canadian Imperial Bank of Commerce and the National Bank jacked up their loan loss provisions while providing detailed disclosure of the extent of their oil and gas loans. Big numbers.
In total, these six Canadian banks have committed loans of $49.8 billion, not all in Canada. OFS is in there for $5.6 billion. According to a March 2 Bloomberg Brief on bankruptcy, these six banks had undrawn credit facilities that brought the total to as high as $107 billion, as well as a total provision for Non-Performing Loans (NPL) in the quarter of $259 million. The amount is significantly higher than the $215 million total for the six banks for the entire fiscal year, ended October 31, 2015. This is surely because oil markets and the health of the industry has continued to deteriorate since that time. News reports caution a growing number of oil and gas based companies are on so-called “credit watch.” Because of current oil and gas prices and low OFS activity, the next round of loan covenants tests will surely increase the amount of debt in the NPL category.
Many comparisons have been made between the current downturn and the 1980's. When it comes to debt, the 21st century looks rock solid. In his excellent and exhaustively researched 1983 book
Other People’s Money-The Banks, the Government and Dome (Petroleum Ltd.), author Peter Foster noted four Canadian banks – CIBC, TD, BMO and RBC - had combined exposure of $3.1 billion to Dome Petroleum Ltd. in 1982, nearly half of Dome’s $6.7 billion in debt. Corrected for inflation in 2015 dollars, using Statistics Canada Consumer Price Index Data, this is equivalent to $7.3 billion and $16 billion respectively. For the four banks this is about 25% of current total E&P loans outstanding; just to one company! Back in the 1980's two Alberta banks – Canadian Commercial Bank and Northland Bank – went broke because of their bad energy loans and the impact the downturn had on the entire Alberta economy.
So, although borrowers may be in trouble this year, it doesn’t appear they will be taking any of the chartered banks down with them. That said, bank loans are only a fraction of the total debt carried by the Canadian oilpatch. There are lots of equipment leases and subordinated, interest-only (for now) bonds not listed in these figures.
The number one question for OFS managers and operators is whether or not their lender is going to classify their debt as a NPL. When the loan is no longer on the books of the parent company as an asset, the loans and / or credit manager treats the file differently. Definitions of NPL vary but the International Monetary Fund’s is clear: “A loan is nonperforming when payments of interest and principal are past due by 90 days or more, or least 90 days of interest payments have been capitalized, refinanced or delayed by agreement, or payments are less than 90 days overdue but there are other good reasons to doubt that payments will be made in full.”
Many borrowers have received a hall pass on their principal payments in the past year through covenant waivers. But personal experience (your writer has seen some tough days at the office since buying his first oilpatch-related business in 1979) is the demeanor of the lender changes sharply when the borrower can no longer pay interest. That means the company is bleeding cash and is going out of business as the balance sheet and collateral base supporting the loan deteriorates. With no overall oil price or activity turnaround on the horizon (based on public announcements, spending plans on E&P CAPEX in 2016 will be substantially lower than in 2015), lenders are faced with making the unpleasant decisions they have avoided for a year.
Even a recovery will not get the total pie for OFS back to where it was. If oil were to return to US$100 tomorrow no greenfield oilsands construction will take place until issues around export pipelines accessing tidewater are resolved. Once the current oilsands projects are completed, this will leave a $15 billion-per-year cavity in future capital expenditures, some 20% of total business. Even if WTI rose to US$50 or US$60 a barrel later this year, the activity and spending to support all OFS companies which were thriving in 2014 will not be there.
Cheap debt capital is a wonderful thing so long as it can be serviced. E&P companies borrowed extensively to keep drilling and spending. OFS borrowed aggressively to build new generation rigs and service equipment and add capacity. But the ability of any company to borrow is based on their capacity to repay, defined in the simplest terms as free cash from operations. Even if commodity prices and business were to pick up tomorrow, the ability of clients and suppliers to borrow will be harshly curtailed because of their trailing cash flow.
This is why lenders have OFS in such a precarious position. There is the issue of servicing and repaying current debt, plus the reality that debt capital required to exploit the recovery (working capital, refurbishing parked or scavenged equipment), when it comes, will be restricted.
Many analysts who don’t understand how this business actually works claim the moment oil prices rise high enough, the light tight oil drillers in Canada and the U.S. will go right back to work and re-flood the market with more supply. Not likely, certainly not in the short term. There will be a continuation of the current industry-wide cash flow and credit crunch which will impair the speed of the recovery if and when it takes place.
There is said to be lots of capital on the sidelines looking for deals. OFS owners and managers up against a debt wall should consider finding some.
The trade terms are “wet barrels” and “dry barrels.” Wet barrels are real oil. Dry barrels are future markets oil. Trading activity in dry barrels for WTI crude has been off the charts recently. On February 10, 2016, the Chicago Mercantile Exchange (CME) issued a press release indicating on February 9 it traded an all-time record 1,603,771 WTI contracts, each of which account for 1,000 barrels. So that day the CME traded 1.604 billion barrels of WTI crude. The previous record was 1,595,710 contracts on December 8, 2015, or 1.596 billion barrels.
This is an astonishing figure given total North American crude oil production on any given day is about 9 million barrels (b/d) in the U.S. and 4 million in Canada. At 13 million barrels total, and assuming all North American crude is classified as WTI (it is not, but it is priced off WTI) this means on some days futures markets trade more than 100 times as many dry barrels as wet barrels for the same product.
For the week ended February 26, 2016, the CME traded over 3 billion barrels in WTI contracts, nearly three times the amount of Brent Crude traded on the ICE exchange, even though much more of the world’s crude is subject to Brent pricing. At 3 billion dry barrels traded per week, this is about 33 times actual wet barrel production for North America.
Since the negotiations of the end of international economic sanctions were announce last July, oil traders and commentators have used the pending return of Iranian oil exports to flooded global markets as an excuse to further depress the price. Six weeks after sanctions were lifted, not much has happened and may not happen anytime soon.
A March 3 Bloomberg Business article was titled, “Iran’s Oil Market Return Not Yet Fulfilling Grand Promises.” It stated only about one-third of the promised immediate 500,000 b/d increase in output was being shipped to markets. The problem is the physical condition of existing production facilities and international banking arrangements and settlements. Goldman Sachs now believes Iran will add only 285,000 b/d to its export output in 2016, far short of the million b/d touted by Iranians and crude short sellers.
A Reuters news story on March 5 headlined, “Iran says European banks reluctant to resume transactions.” Here, Iran complained about the speed at which the international finance community was resuming normal business relationships so it asked in the International Monetary Fund to intervene.
Against the backdrop of Iran allegedly trying to return to business as usual and attract western investment capital, on March 8 Reuters reported, “Iran’s Revolutionary Guards conduct ballistic missile test.” In this article, Iran demonstrated it had the ability to fire home-made missiles as far as 700 kilometers. The first demonstration of Iran’s military missile might last October resulted in the U.S. introducing new economic sanctions on that country until it demonstrated it was truly not a threat to peace in the Middle East, and the end of the economic sanctions and oil exports was not going to just provide more cash to make trouble.
Reuters reported the commander of Iran’s Islamic Revolutionary Guard Corps wrote on its website, “Our main enemies are imposing new sanctions on Iran to weaken our missile capabilities… But they should know that the children of the Iranian nation in the Revolutionary Guards and other armed forces refuse to bow to their excessive demands.”
This is the problem, according to Reuters. The March 3 article about slow international monetary settlements read, “But some U.S. sanctions remain, and U.S. banks remain prohibited from doing business with Iran directly and indirectly because Washington still accuses Iran of ‘supporting terrorism’. That has deterred European institutions, which fear they could face U.S. legal problems if they re-establish banking links.”
Not all Iranians are firing missiles. Others are trying to open the country to new international oil investment. Iran is attempting to release 18 blocks of oil and gas producing areas later this month to global bidders. While Iran’s reserves are enormous and its ultimate crude production significant, getting this oil to market is proving to be a bit more complicated than past news reports have indicated. This bodes well for the current oil price recovery.
As discussed above, some OFS companies will be short of working capital to exploit opportunities when the recovery comes. Pressure pumper Canyon Services Group Inc. won’t be one of them. Analysis John Bereznicki reported March 8 Canyon exited 2015 with net debt of about $65.6 million. Canyon announced a “bought deal” equity financing on March 8 which could eliminate virtually all of this. Canyon is selling $55 million worth of stock at $4.40 a share but the over-allotment (if sold) could raise the net total to $63.3 million, leaving the company almost debt-free.
The use of proceeds will be to pay down bank debt and to have dry powder on its balance sheet to exploit opportunities as they arise.
Canyon’s trading history has reflected the cyclical OFS industry. It closed March 8 on the Toronto Stock Exchange at $4.24 per share. The 52-week high / low has been $9.03 and $2.85 respectively. In the past 10 years the stock traded as low as about $1 in 2009 and hit an all-time high of $20 on July 3, 2014. Investors knowing when to buy and when to sell can make a fortune playing cyclical OFS equities.
Peyto Exploration & Development Corp., Canada’s number three driller on March 7 (but only 7 rigs), hopes to drill the same number of wells in 2016 but spend about $100 million less in the process. In
Calgary Herald article on March 2, Peyto figured this would be accomplished through pricing and efficiency.
CEO President and CEO Darren Gee said about 80% of the projected cost savings will come from lower drilling and completion expenses, but not necessarily lower unit product or services prices. Yee said, “We could run into the problem where margins the service companies are getting are so thin they throw in the towel. That would actually result in our costs going up. The hope is that we’re not the only guy that will be busy this year.”
The article explained the advantages of being active in one area west of Edson, thus ensuring access to the most experienced personnel who get to go home after work. The Herald wrote, “That helps limit the costly mistakes occasionally made by less competent service hires.” The service industry has argued for years the best way to drill and complete cheaper wells is not necessarily through lower prices but operational efficiency.
Peyto expects to exit 2016 producing between 108,000 and 113,000 barrels of oil equivalent (boe) per day. The company ended 2015 producing 97,000 boe/day, over 90% of its natural gas.
Canadian Natural Resources Limited (CNRL) is still committed to investing about $2 billion to complete two phases of expansion at its Horizon oilsands mine by the end of the next year. This will add about 125,000 b/d of incremental output. This commitment follows the announcement by CNRL that is was cutting back total 2016 spending by as much as $1 billion this year, from a previously estimated $4.5 to $5 billion to the range of $3.5 to $3.9 billion.
As the industry focuses on the price of oil, folks don’t talk much about natural gas these days. But it remains an important component of Canada’s hydrocarbon production mix. ARC Financial Corp. reports gas will account for an estimated 2.4 million boe/day equivalent of 34% Canada’s estimated 7 million boe/day of total output from bitumen, conventional oil, natural gas liquids and natural gas. Gas matters.
Which is why the current pricing hurts. AECO spot gas closed at only C$1.29 per mcf on March 7, C$0.74 or 72% below its Henry Hub U.S. equivalent. A
Financial Post article March 1 quoted FirstEnergy Capital Corp. commodities analyst Martin King who said, “With too much gas in Western Canada, we believe prices will deteriorate to under C$1.00 per mcf and could well persist near this level for a few months.”
The problem is the re-arrangement of North American gas markets because of the massive Marcellus shale gas discovery in the northeast U.S. and the very warm winter in western Canada and the western U.S., the last big markets for Canadian gas. King called current gas storage levels in western Canada at this time of year “insane”, the highest since 1998. “There is an outside chance that the net cumulative withdrawal of gas from Alberta storage could be close to zero this heating season, an unprecedented event in the history of North American natural gas storage,” King wrote in a research note to clients.
Typically, gas producers sell into storage in the summer months, then when winter increases gas demand, storage is drawn down.
However, more analysts are looking for a natural gas price swing later this year as drilling for gas declines across North America while LNG exports from U.S. ports has begun. National Bank Financial analysist Brian Milne was quoted in the
Calgary Herald as saying, “Current fundamentals are likely not sustainable and we have visibility towards potential for a material re-set of supply / demand and pricing over the next six to 12 months.” Production across North America could see gas production decline by eight billion cubic feet per day, which would change the situation significantly.
As the Quebec government and environment protesters continue to put obstacles in front of the trans-Canadian Energy East pipeline project to Saint John, New Brunswick, imports of foreign oil to supply central and eastern Canada grew by 16% to an average of 736,000 b/d last year according to the National Energy Board.
Supplies came from Saudi Arabia, Nigeria, Algeria and, increasingly, the U.S. American oil imports rose by 400% to 400,000 b/d in 2015 compared to only 100,000 b/d in prior years. Saudi Arabia accounted for 11.4% of daily imports or nearly 84,000 b/d.
At the average closing price for synthetic and Edmonton light crude of C$52.04 on March 7, replacing all this imported oil with Canadian crude would move nearly $14 billion a year into the pockets of western producers from international crude suppliers.
Low oil and now natural gas prices continue to have their toll in North American drilling activity. In North Dakota, the rig count is less than one-third of 2015 levels and absolutely brutal compared to 2014, 2013 and 2012. The Baker Hughes count of rigs drilling for oil in the U.S. continues to fall and now sits at the lowest level since December of 2009.
Canada is faring somewhat better but there is a disproportionate amount of the activity being big rigs drilling in northwest Alberta and northeast B.C. Of the top 10 operators on March 7 operating 53 or nearly 50% of the 107 active rigs, eight were operating in the northern regions running rigs with depth capacities rated to 3,051 metres or more. Part of Canada’s activity is based on the winter drilling season. The County of Grande Prairie 1 reports no major road bans as of March 8. While the daytime highs are above freezing, there is a good frost every night, which is maintaining winter access conditions for now.
FOR FURTHER INFORMATION ON OILFIELD SERVICES CONTACT:David Yager, National Leader, Oilfield Services
Client Groups:Oil ＆ Gas
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