We understand the specialized markets in which you operate and provide tailored solutions to meet your unique business needs.
Our comprehensive suite of business services combines industry expertise, market knowledge and professional insights.
MNP is a leading national accounting, tax and business consulting firm in Canada.
Suite 2000, 330 5th Ave. S.W.
MNP careers are Different by Design. As an entrepreneurial firm, we truly believe there are no limits to where your career can go.
By now thousands of oilfield service (OFS) owners and managers (yes there is that many!) across the Western Canadian Sedimentary Basin (WCSB) have realized 2015 is going to be a long and difficult year. Oil prices are half of what they were in June. Gas prices are down by 25% (see below). The only oil companies that haven’t announced spending cuts are the few that are still figuring it out. As customers cut programs, they are also demanding price cuts for goods and services. In a market like this, the only thing OFS operators cannot do is nothing.
Here’s a list of things to consider to help your company manage in tough times and possibly emerge from this downturn as a leaner and more efficient organization.
Tell Your Staff What’s Going On
Getting through this slump will be a team effort so you’ll need your team on your side. The job market is shrinking fast so your staff will be ready for some “tough love” (although they may not know it yet). Don’t be alarmist but be honest: this is no time to ask for a raise. The objective is to get through the downturn with the company intact while preserving the greatest number of jobs. Elicit the support of everyone to help cut costs wherever possible. Align their success with the company’s success.
Slash Discretionary Spending
Be merciless in determining what you can live without. Lead by example. Then review all expense accounts, employee use of company vehicles (non-assigned), travel, club memberships, capital expenditures and repairs that can be deferred, close unprofitable or marginal service locations and abandon marginal and service lines. You’ll be pleasantly surprised at what you can live without when you have to.
Advise Your Lenders of Your Situation and Plan
All lenders hate surprises. If you tell them things are great and there are no problems anticipated, your account manager won’t believe you. Your lenders don’t want your assets or your company. All they want is their money back to avoid a loan loss, and they’ll work with you way longer than they’ll admit if you’re forthright and show them you have a strategy to pay them back. If you don’t have a plan, make one up in a hurry.
Retool for Price Cuts
Oilfield service companies cannot succeed unless their customers succeed. There is no history of OFS being profitable when clients are not. With much lower commodity prices, the only way E&P companies can compensate is by spending less, which is impossible long-term because they go out of business - or by reducing costs on what they must spend. If the capital cost is too high operators cannot invest the money. Talk honestly to your customers. “No” is the wrong answer. “How” is the right answer. Oil companies know they cannot succeed by bankrupting their vendors. But before you agree to lower prices, ask if your client’s staff is taking the same pay cuts they are asking you to take. Fair is fair.
Consider Pay Cuts and Job Sharing
In the 2009 slump many oilfield service companies cut wages for managers and staff to preserve jobs. This works in a downturn because all your competitors are in the same boat and your employees have nowhere else to go unless they leave the industry. Management must lead by example. If the top dogs make bigger proportionate sacrifices, everyone will fall into line. The staff will not be happy but they will still be working. Many others won’t. Retool base and bonus compensation to reward success, not activity. Promises to return everyone to higher income levels as soon as the company recovers must be made, then kept.
Field service and operations personnel are the lifeblood of OFS companies. In good times organizations can become top heavy. The objective should be to keep the greatest percentage of your skilled and trained revenue-generating personnel possible while examining all levels of non-revenue generating management to maximize efficiency. The primary criterion for who stays and who goes must be performance, not seniority.
Know Your Job Delivery Costs
$100 a barrel can cover a lot of mistakes. As you reduce prices, extracting the maximum possible margin from every job or product sold becomes essential. You must know and control direct costs. If your operating staff and team are really efficient in controlling expenses and doing every job right the first time, you can actually make the same amount (or even more) money at lower end-user prices. Fuel prices are down and labour is under control (see above). You might find some pleasant surprises emerging from doing less work better.
One proven way to preserve shareholders’ equity (your investment) in a slump is consolidation with competitors. The objective is to spread the non revenue-generating costs, like management and administration, across a larger revenue basis. In times like these the industry as a whole must reduce the number of CEOs per barrel of oil produced. Clients want to do more work with fewer and larger vendors anyway. Put your ego on the shelf and find a way to a preserve your investment by owning less of a larger organization that has a fighting chance of being in good shape to exploit the recovery when it comes.
Run Credit Checks Before Saying Yes
In times like this, available cash for oil companies (the lifeblood of OFS) gets hit three ways: lower revenue from existing production, reduced credit facilities because of lower reserve valuations and tight capital markets to raise money. Some operators have already defaulted on their debts. If they can’t pay the bank they sure can’t pay you. When the phone rings or the order comes in, don’t move until you know you’re going to get paid. And when. Having to lay out the cash for the job or product, then discovering in 90 days or more you can’t collect is a surefire way to exacerbate your financial challenges.
In 2009, I was the chairman and CEO of a medium-sized, TSX-listed oilfield service company. Revenue in 2008 was $114 million and in 2009 it was $82 million. Ouch. EBITDA plummeted from $10.4 million in 2008 to $0.8 million to 2009. The company went from over 900 employees to about 625. We defaulted on our senior debt covenants but our banker stayed with us. Every strategy above was employed, except the merger, and we lived to fight another day. The company emerged stronger and more profitable than previously thought possible, with a more motivated and dedicated team. The company was sold in 2012 for over six times what it traded at during the bottom of the 2009 slump.
Getting accurate facts on what will happen to shale oil production and future drilling in the U.S. in light of current prices is difficult. Many producers and investment banks try to put on a brave face and brag about efficiency and cost control, while the reality is the entire shale oil phenomenon took place during a period of much higher prices.
Arthur Berman is a respected U.S. geologist and shale oil analyst, holding several titles including Director of the Association for the Study of Peak Oil & Gas USA. In a January 4 interview with oilprice.com, Berman offered the following.
We’ve read a lot of silly articles since oil prices started falling about how U.S. shale plays can breakeven at whatever the latest, lowest price of oil happens to be. Doesn’t anyone realize that the investment banks that do the research behind these articles have a vested interest in making people believe that the companies they’ve put billions of dollars into won’t go broke because prices have fallen? This is total propaganda.
We’ve done real work to determine the EUR (estimated ultimate recovery) of all the wells in the core of the Bakken Shale play, for example. It’s about 450,000 barrels of oil equivalent per well counting gas. When we take the costs and realized oil and gas prices that the companies involved provide to the Securities and Exchange Commission in their 10-Qs, we get a break-even WTI price of $80-85/barrel. Bakken economics are at least as good or better than the Eagle Ford and Permian so this is a fairly representative price range for break-even oil prices.
But smart people don’t invest in things that break-even. I mean, why should I take a risk to make no money on an energy company when I can invest in a variable annuity or a REIT that has almost no risk that will pay me a reasonable margin?
Oil prices need to be around $90 to attract investment capital. So, are companies OK at current oil prices? Hell no! They are dying at these prices. That’s the truth based on real data. The crap that we read that companies are fine at $60/barrel is just that. They get to those prices by excluding important costs like everything except drilling and completion. Why does anyone believe this stuff?
If you somehow don’t believe or understand EURs and 10-Qs, just get on Google Finance and look at third quarter financial data for the companies that say they are doing fine at low oil prices.
Continental Resources is the biggest player in the Bakken. Their free cash flow—cash from operating activities minus capital expenditures—was -$1.1 billion in the third- quarter of 2014. That means that they spent over $1 billion over they made. Their debt was 120% of equity. That means that if they sold everything they own, they couldn’t pay off all their debt. That was at $93 oil prices.
“And they say that they will be fine at $60 oil prices? Are you kidding? People need to wake up and click on Google Finance to see that I am right. Capital costs, by the way, don’t begin to reflect all of their costs like overhead, debt service, taxes, or operating costs so the true situation is really a lot worse.
“So, how do I see the shale landscape changing in the U.S. given the current oil price slump? It was pretty awful before the price slump so it can only get worse. The real question is “when will people stop giving these companies money?” When the drilling slows down and production drops—which won’t happen until at least mid-2016—we will see the truth about the U.S. shale plays. They only work at high oil prices. Period."
Last year, thanks to reduced drilling and the so-called polar vortex, it looked like the really bad years for natural gas were behind us. There were price spikes and shortages and major drawdowns in inventory. It was thought there was a new basement for gas prices at materially higher prices than the past few years. Forecasters figured the historically low levels of natural gas storage reservoirs could not possibly be filled before the onset of the 2014 / 2015 winter heating season.
Well, it’s cold and Henry Hub gas is trading below US$3 per mmBtu, over 25% below the monthly average trading price for the past 24 months as reported by the U.S. Energy Information Administration. This is less than half the average price was in February last year. While there’s still time for more cold weather in North America this winter, gas prices are more bad news heaped on top of the financial misery created by the oil price collapse.
In a December 20, 2104 article in the Globe and Mail’s Report on Business, the following facts emerged. First Energy has reported Canadian gas production was up to 14.5 billion cubic feet per day, compared with 13.4 bcf/day last December. Gas production has increased significantly even though supposedly nobody is drilling for it. This isn’t entirely true as operators prove up reserves in northeast B.C. and northwest Alberta in anticipation of potential LNG exports and significant quantities of gas is produced associated with targeted natural gas liquids in zone, like the Montney, Duvernay and others.
Meanwhile, the phenomenal production from the Marcellus Shale continues to grow. That region will exit 2014 producing some 14 bcf/day, up from 1 bcf/day only six years ago. That shale gas play has managed to produce as much gas on a daily basis as all of Canada in a small fraction of the time.
The outgoing CEO of Alberta Investment Management Corp. (AIMCO) Leo de Bever says oilsands operators and the province must figure out ways to significantly reduce development and production costs to stay in this huge and critical business in the new world of lower oil prices. AIMCO manages Alberta’s $80 billion public sector pension fund and is an active investor in oil and gas producing and service companies in Alberta and abroad.
In an Edmonton Journal article in early December, de Bever said “You can’t do it in 12 months. It will take two, three or four years if you work very hard. You could probably survive with the stuff that’s already operating because the marginal cost is still low enough. But for any new projects, I don’t see anything making any sense if oil stays at US$65 or $70 a barrel.”
Many oilsands projects have been delayed or deferred in recent months, such as Total E&P Canada and Suncor Energy’s Jocelyn mine project. The only major greenfield development underway at present is Suncor’s Fort Hills oilsands mine. Several projects are suspended and under regulatory review because they are too deep to mine but too shallow to use high pressure steam. An increasing number of smaller oilsands operators are unable to raise capital or are reviewing “strategic alternatives,” the investment industry term for “what do we do now?”
Speaking on the world’s current oversupply of crude oil, de Bever said “That doesn’t help (Alberta) if you want to produce another million barrels a day. For that you need new technology. My sense is we have to move from being a relatively high-cost producer to at least average, and probably a below-average cost producer. I think if we set our minds to it we could probably get some of this on line within three or four years.”
Oilsands investment - actual and planned - has been a huge driver of Alberta’s economy for decades. Recent reports by the Canadian Energy Research Institute and the Canadian Association of Petroleum Producers have indicated that if all projects contemplated by oilsands operators were built and if all the major new pipelines to carry this production to new markets were available, oilsands production could double and then triple in the next 20 years. This would create massive economic opportunities for the country, workers, oil producers and governments at all levels.
The problem is two critical assumptions in the models – that the projects would proceed and pipelines would actually be constructed – aren’t looking particularly promising at the present time. Those forecasts were produced before the OPEC decision not to restrain production on November 27 which resulted in world oil prices falling further than previously thought.
What does this mean for the many oilfield service companies that have thrived providing goods and services to the go-go oilsands development machine in the past 15 years? The following chart explains the challenge of where we’ve been; the best way to fully understand where we’re going.
In the past 15 years oilsands capital spending has increased by a factor of 12 on an annual basis, from $2 billion a year to over $25 billion for the past three years. When you consider capital spending on conventional oil and gas has stayed relatively steady at $35 billion since 2005 (barring the big correction during the recession of 2009), another way to look at this is Canada has created a second parallel oilfield services industry in the past 10 years which, measured by spending, is about two-thirds the size of the OFS sector that took Canada nearly 60 years to develop.
Oilsands development has been plagued by several problems over the past decade: high labour costs, reduced productivity and major cost over-runs. This has been covered by patient investors and high oil prices. Here’s a snapshot of a few of the big projects and the problem Leo de Bever has highlighted in the current oil pricing environment.
* Latest estimate for North West Upgrader, not the actual completed cost
But what works for oilsands developers nowadays are not major greenfield projects like the four listed above, but “brownfield” expansions of existing developments in order to achieve greater economies of scale from the most expensive part of the project, the central processing facilities. Canadian Natural Resources Limited is continuing to expand its Horizon oilsands project, while Imperial Oil / Esso has just completed phase two of its Kearl Lake oilsands mine operation.
After 15 years of steady and profitable growth, OFS operators supplying the oilsands are going to face a much different market going forward. There will be continuous pressure from developers to cut costs and increase productivity. Some relief on the labour side will be good for everyone in the upstream oil and gas industry, from conventional oil and gas to pending liquefied natural gas projects.
Unless, of course, it’s your job they’re talking about.
The Alberta Energy Regulator indicates there are 84,904 inactive wells in the province compared with 186,237 active (producing, injection, observation, and disposal) wells. A December 3 Daily Oil Bulletin article reported that 10 years ago the figures were 46,709 inactive and 137,287 active wells. The AER defines an inactive well as one that has not reported any activity in the prior 12 months.
Of the current inactive well inventory, 47%, or about 37,000, of wells owned by 900 licensees are considered non-compliant under AER Directive 13. This is the AER regulation which defines the characteristics of a wellbore classified as suspended.
The number of suspended wells has piled up over the years. Many oilfield service operators have tried to position themselves as specialists in well abandonments and make a few bucks from what will be one last visit to a given wellbore after its commercial usefulness has expired.
While all oil and gas producers make varying attempts to be good corporate citizens and stay on top of their environmental cleanup, wellbore abandonment and site reclamation obligations, given a choice, any oil executive would rather drill than abandon a well, considering a company’s finite cash resources.
The other issue is cost, which is often uncertain. Once an abandonment file is open with the regulator, the owner must stick with it until it is completed. While the budget to plug and abandon a well may only be a few hundred thousand dollars, the owner doesn’t really know the true state of the wellbore until work commences. This includes issues such as cement bond integrity and ensuring there is no inter-zonal communication of groundwater behind the casing. Routine wellbore abandonments can turn into major projects if the owner has to perforate and squeeze cement behind the casing to ensure the hole around the casing is properly sealed. Surface contamination of older producing sites is not fully known until a reclamation certificate is received. The rules on what is acceptable get more stringent every year.
Other owners figure keeping the well alive by maintaining the annual lease payments may prove to be a good investment. For example, there are a lot of suspended natural gas wells. Should the price rise dramatically, it could be economic to invest in a work over and put them back on stream. Another unknown is new technology. If some new method, tool or process comes along to extract more oil or gas from a reservoir previously thought depleted, it would be a shame to have paid to abandon that well permanently in the recent past.
In an industry that may struggle to drill 10,000 new wells next year, the idea that there is service work available abandoning at least some of the 85,000 suspended wells looks promising to OFS operators. But the owner has to have the money and the commitment.
That’s why the well abandonment business has never actually been as robust a revenue stream as it appeared to be for the service sector for many years.
In the cyclical oilpatch, it doesn’t rain… it pours! More bad news on December 19 when the Calgary Herald reported Alberta land sales for new drilling and development rights in 2014 were only $489 million, the lowest level since 2002 when $477 million was spent. This compares to a whopping $3.5 billion in 2011 when producers were tying up the rights to develop the Duvernay tight oil and gas play. The Alberta government took in $2.4 billion in 2010 and $1.1 billion in 2012. Last year the figure was $680 million.
In Saskatchewan the government collected $198 million in 2014, three times the 2013 total and the seventh best year on record. In 2008 operators spent $1.1 billion in that province when they were staking out the Bakken tight oil play.
In B.C. the Crown took in $383 million in 2014, the highest amount since it raised $844 million in 2010. The province’s best year was also 2008, when E&P companies were obtaining the rights to develop the Horn River and Montney plays and spent $2.7 billion.
Drilling rights sales matter to oilfield services operators because they are precursors of future drilling and investment.
There are parts of the oilfield services industry that are not impacted as much as others when commodity prices decline. One is midstream operators, companies that own and operate contract oil and gas processing facilities in the field. In the old days, oil companies used to build, own and operate their own gathering facilities, natural gas plants, oil batteries and shipping and storage facilities. Over the years many have divested themselves of these assets to free up capital for exploration and development. Some of the players in this space include Altagas Utilities and Keyera Corp., to name but two.
On December 22, 2014, a new player entered the marketplace: Veresen Midstream Limited Partnership, a JV between pipeline operator Veresen Inc. and investment firm Kohlberg Kravis Roberts & Co. L.P., better known as private equity firm KKR. The first deal was the $412 million acquisition from Encana Corp. of gas pipeline and processing facilities in the Montney region in the Cutbank Ridge area near Dawson Creek. The other owner of these assets was Cutbank Dawson Gas Resources Ltd., a unit of Mitsubishi Corporation, Encana’s equity partner in certain assets in the region.
Veresen Midstream also agreed to develop up to $5 billion for Encana and Cutbank Dawson Gas in the future under a 30-year fee for service agreement.
Calgary-based Newalta Corp. is going to focus its growth closer to home in the next few years after announcing on December 23, 2014, it was selling its industrial waste handling and disposal assets in Ontario and Quebec to a private equity firm for $300 million. This included a battery recycling plant and solid waste landfill. Newalta will use the proceeds to pay down debt and focus on its core oil and gas waste handling and disposal services in western Canada, where it compete with companies like Secure Energy Services Inc. and Tervita Corp. (formerly Canadian Crude Separators).
Newalta’s stock rose immediately after the announcement.
International upstream research outfit Wood Mackenzie has determined there are some $59 billion in energy projects in Canada delayed or cancelled due to low oil prices and the squeezed economics of continued development. According to a January 2 Financial Post article, this “collapse” of capital investment scheduled for the next three years is beginning to look a lot like that last big downturn of 2009. Some $100 billion in planned heavy oil upgrader projects alone were never built.
Wood Mackenzie figures $12 billion worth of projects will be deferred in 2015, $20 billion in 2016 and $27 billion in 2017 if current prices persist. That would prevent some 650,000 b/d of incremental production from coming on stream. This includes a decision by Husky Energy in December to delay a final decision on its $2.8 billion White Rose project offshore Newfoundland and Chevron’s announcement that it would suspend plans to drill in the Canadian Arctic. This is in addition to oilsands projects operated by Total, Suncor and Statoil that were already deferred in 2014, prior to oil prices collapsing.
Projects currently under construction that will be on stream by 2017 include Suncor Energy’s $13.5 billion, 165,000 barrel per day Fort Hill project; Canadian Oil Sands Ltd’s $3.9 billion, 100,000 b/d Mildred Lake replacement mine; Imperial Oil’s 110,000 b/d Kearl Lake Phase 2, ConocoPhillsips Canada’s 109,000 b/d Surmount Phase 2 project and Royal Dutch Shell PLC’s 100,000 b/d Jackpine Mine expansion.
These projects will increase bitumen production in Canada by a combined 584,000 b/d, a 25% gain from current oilsands production levels.
Client Groups:Oilfield Services
Suite 2000, 330 5th Ave. S.W.
Find an office near me