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After OPEC abandoned production quotas at its November 27, 2014 meeting, oil prices were in a freefall. After averaging US $97.98 a barrel in 2014, WTI traded on January 5 last year at US$50.05 a barrel, the lowest price since the spring of 2009. Exploration and production (E&P) companies began 2015 by demanding and receiving significant price reductions. Capital spending programs were being cancelled. Oil prices and the oilpatch in general were in state of rapid decline, with the bottom unknown. How could things possibly be worse?
But however awful things looked as 2015 began, the idea this industry would have not yet tagged bottom a full year later was not a commonly held view. This writer, like so many others, certainly called this wrong.
Nevertheless, not all the analysis was as wrong as the timing of an oil price recovery. How to manage a service company through a downturn doesn’t change. OFS companies just don’t drive the bus in this business. They are takers of the capital and operating expenditures of their clients. When business declines, the best OFS managers can do is run their own operations with the objective of maintaining a positive cash flow on whatever business comes in the door.
Following are MNP’s suggestions for OFS operators from a year ago and how relevant that advice looks after what proved to be a full year of deteriorating business conditions.
“Getting through this slump will be a team effort so you’ll need your team on your side. The job marketis shrinking fast so your staff will be ready for some “tough love” (although they may not know it yet).”
The thinking here was it was time for OFS managers to start explaining to their staff exactly who worked for who. This followed several years of operating in what was clearly an employee’s marketplace, characterized by ever-increasing wages and benefits with employers rewarded by poor productivity and questionable loyalty. The staff wasn’t ready for tough love in the first week of January 2015, but by spring breakup everyone had the situation figured out.
"Be merciless in determining what you can live without. Lead by example. Then review all non-essential management and staff, expense accounts, employee use of company vehicles (non-assigned), travel, club memberships, capital expenditures and repairs that can be deferred, and close unprofitable or marginal service locations.”
Judging by the layoffs, thin lunch crowds at the Petroleum Club most weekdays, rising hotel vacancy rates, empty airplanes and the cancellation of many corporate Christmas parties, everybody in the oilpatch got the message as the year progressed.
“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.”
The prescient words in this paragraph are, “they’ll work with you way longer then they’ll admit…” Debt capital providers to OFS have been extraordinarily flexible in trying to find ways to work with their clients to get their money back at some point. But increasingly, those without a plan or strategy have been sent to special credit or had their loans called.
“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 or by reducing costs on what they must spend.”
In the early stages of forced price reductions, the reaction by OFS was universally hostile. But as the year progressed, two events occurred: E&Ps realized they were getting the lowest possible prices and focused their cost cutting efforts internally, while OFS began to appreciate their clients didn’t have any money either, thus making complaining futile.
“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.”
This is not something anybody really wants to do, but necessity the mother of invention. Wages across the board were way too high for anything but $100 oil and adjustments had to be made. With oil trading at one third of that amount today, wages are still too high. But as the year progressed, companies wanting to emerge from the slump intact got with the program and made the painful but necessary workforce compensation adjustments.
“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 high level of corporate layoffs in head offices across Western Canada demonstrates owners and managers came to this conclusion. OFS companies still need good people to do the work and not doing good work in this market is particularly risky.
“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 base, effectively reducing the CEOs per barrel of production or dollar of revenue.”
“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.”
Surprisingly, bad debts among E&P clients is not as bad as it has been in past slumps. This is because the oil companies spending money today are for the most part larger and better capitalized than the myriad of small junior producers which used to account for a larger portion of the business.
But regardless of which companies get through this mess and at some point resume more normal business operations – simply defined as revenue exceeding expenses – they will most likely run their businesses differently than in the past.
With oil losing about a sixth of its value in the first seven trading days of 2016, it is clear this commodity is trading on bad news, not fundamentals. The situation in China, a strong U.S. dollar and a steady stream of seemingly credible research reports calling for crude to fall further have all but surrendered futures markets to short-sellers. They will drive the price down until they think they will lose money. With no positive news on oil prices the basement is unknown.
The most bearish but realistic comment thus far has come from Standard Chartered Bank which said, “We think oil prices could fall as low as $10 a barrel before most of the money managers in the market conceded that matters had gone too far.”
In terms of going too far, Edward Morse, well-known oil analyst for Citigroup, said in Calgary January 11, “The $20 number is something you have to talk about. When you’ve seen a $10 price slide and WTI is trading just slightly above $30, the likelihood (of $20) is fairly great. Clearly markets cannot maintain a price at below the $30 level for very long. The question is how much longer”. Morse was one of the few who had predicted oil might reach $20 a barrel in February of 2014.
Simply put, traders will drive down the price for short-term profit until something or someone forces them to stop. With everyone piling on to the fear-based “lower forever” thinking currently gripping oil markets, Standard Chartered may, regrettably, be correct.
But even the current price is stupid low compared to the cost of being in this business and therefore cannot last for long.
When a nuclear monitoring accord between Iran and the Western powers which had introduced and enforced economic sanctions moved towards fruition last year, Iran immediately began telling the world exactly how much additional oil it would be producing and when. Millions of barrels were said to be sitting in tankers ready to deliver crude to markets. Production could rise by 500,000 barrels a day almost immediately after sanctions were lifted, rising to a million barrels a day within six months. Western companies were invited to Tehran to discuss joint opportunities to exploit Iran’s massive but dilapidated oilfields. Iran was going to regain its rightful place as a major force in world oil markets.
That was about $20 a barrel ago and an illuminating article in
oilprice.com on January 10 points out how much Iran’s messaging has changed in the few weeks since the December 4 OPEC meeting. That was when the abandonment of official production quotas and enforcement sent crude prices to a lower level than most would have imagined a year ago. Iran started the year with official announcements on how that country would “shape its export strategy to avoid exacerbating pressure on crude prices.”
The article tracked how oil prices had actually begun to stabilize in the second quarter of 2015 until it became clear in the third quarter an agreement with Iran to remove international economic sanctions would actually materialize. Fueled by Iran’s bullish statements of its incremental production capacity, markets concluded whatever progress was being made in rebalancing oil markets through an increase in demand, reduction in American light tight oil production and reduced capital expenditures globally would be reversed if and when Iran was permitted to start flooding already oversupplied world crude markets with more oil. The price began to slide in July and for the most part continued to do so for the next six months. When WTI dipped below US$30 a barrel on January 12 it was below half of its value last June.
Further, the article explains those interested in investing in Iran will probably have to share revenue with the country and a local partner before recovering costs and earning a profit. At $100 a barrel, Iran’s massive low-cost oilfields would yield an economic bonanza. At $50 a barrel the arrangement might, after stiff negotiations, still work. At $30 a barrel, even in Iran the pie is unlikely large enough to satisfy the economic requirements of all stakeholders.
In the meantime, Iran seems unable to quit demonstrating to the rest of the world it is a force to be reckoned with, despite its weakened financial capabilities. The Iranian pronouncement it would accelerate the manufacture of ballistic missiles, regardless of the removal of sanctions surrounding its nuclear activities, has again raised concerns in the White House. Iran’s friend in Washington, outgoing President Barack Obama, will be gone later this year. Meanwhile, there are reports from the U.S. capital that new sanctions related to Iran’s missile program are being considered.
In terms of Iran’s impact on world crude markets, the recent statements from Iran should be considered good news. But it is currently being overwhelmed by the torrent of bad news from so many other sources.
One of the projects the Petroleum Services Association of Canada (PSAC) has pursued in the past five years has been to develop economic studies that illustrate the depth of the supply chain required to keep the oil and gas industry operating in Canada. The PSAC numbers always raise eyebrows because they are much larger than many policy analysts and regulators have seen before. The direct suppliers are considered oilfield services. But as past government policy blunders such as Ottawa’s National Energy Program and Alberta’s New Royalty Framework have proven, how far an E&P company spending dollar travels in the economy is still not well understood. PSAC in its research has gone further down the supply chain. Following is yet another example of the total impact of this massive industry on the Canadian economy.
On January 6, the
Edmonton Journal carried a story on how the vacancy rate was plummeting across Alberta because of low oil prices. The article pointed out how in 2014 it was almost impossible to get a hotel room without significant advance notice in places like Peace River and Fort McMurray. However, due to major cutbacks on oilsands development (including the sudden cancellation of Shell’s Carmon Creek project east of Peace River), hotels in those communities have gone from riches to rags. One hotel operator with investments in both communities says business is down 50 percent. The company has cut staff and revenue per room is down 13 percent, an indication of increased competition in the market. Calgary, once the top-performing hotel market Canada, is now in the middle of the pack, or below, compared to other cities across the country.
Other industries not normally associated with oilfield services yet are directly impacted by the level of spending and investment in the oil patch include airlines, investment banking and financial services, vehicle sales, new housing construction and commercial building construction.
In a separate article in the
Financial Post January 12, it was speculated the downturn in oil and other commodity prices, which is causing a major capital spending reductions across the country with ripple effects through the entire domestic supply chain, would cause the bank of Canada to lower interest rates by 25 basis points as soon as next week.
Kick me when I’m down. On January 11, Canada’s black and blue oil patch was treated to the news the government of British Columbia was unable to support the expansion of the decades-old TransMountain pipeline from Alberta’s oil fields to Burnaby because the project did not yet meet B.C.’s five basic conditions for approval. Of all the projects in the hopper to help deliver growing oilsands production to tidewater, this pipeline was considered to face the least resistance because it was an expansion of the line that has safely carried oil to the West coast since 1953.
The conditions are not new but they do represent the complexity and unworkable nature of pipeline construction projects in the 21st century. The agency responsible, Ottawa’s National Energy Board, has historically reviewed such projects on technical, safety and economic grounds. Was it too close to a school playground and was it good for the country? Full stop.
B.C.’s conditions include marine oil spill cleanup, Aboriginal participation and economic benefits to that province. Kinder Morgan will not own or operate the tankers which will fill up at the end of the pipeline, making compliance with the oil spill cleanup provisions risky and perhaps impossible. Kinder Morgan has no responsibility for unsettled Aboriginal land claim issues that arise when opportunities to raise them emerge during pipeline approval hearings. Outside of paying property and corporate taxes for its facilities and operations and employing the people required to operate the pipeline, Kinder Morgan does not own the oil, either, thus its capacity to ensure significant economic benefits to B.C. is very limited.
Getting a pipeline approved will require the joint cooperation of multiple stakeholders including the federal government. While the new Alberta government says it supports the TransMountain expansion and Ottawa has not specifically rejected it, previous discussions between the Alberta government, the federal government and B.C. over Northern Gateway seemed to create more friction than solutions.
That said, the NEB approved Northern Gateway and may yet approve TransMountain. Unfortunately, that doesn’t mean much nowadays.
Two leading, home-grown Canadian E&P companies have been forced to announce significant capital spending reductions 2016 as a result of the continued deterioration in commodity prices. They include Seven Generations Energy Ltd. and Crescent Point Energy Corp. The total spending cuts are in the range of $500 million, which is a lot of money in the current market environment. If prices improve, it is likely the two companies will spend more money.
On January 11, the two companies alone were operating 30 rigs, nearly 13% of the total rigs operating in western Canada, according to data from JuneWarren Nickles Rig Locator.
Active drilling rigs in Canada is up slightly from a week ago thanks to the winter drilling season but is a fraction of what it has been in the past two years. Percentage wise, however, Canada is seeing significantly lower declines than North Dakota or the United States on a simple year-over-year basis. However, if commodity prices continue to fall it is unlikely there will be any improvement in Canada over the rest of the first quarter winter drilling season.
Canadian Active Rig Count
U.S. Active Rig Count Drilling for Oil
North Dakota Drilling Activity
FOR FURTHER INFORMATION ON OILFIELD SERVICES CONTACT: David Yager, National Leader, Calgary - Direct 403 648 4188 Cellular 403 461 8566
Client Groups:Oil ＆ Gas
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