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Necessity is the mother of invention and in the year ended December 31, 2015, adapting to a rapidly shrinking market was absolutely necessary for oilfield service (OFS) companies to survive. When OFS players fold or disappear, for whatever reason it always makes the news. What is discussed less often is who survived the continuously contracting OFS market of 2015 and how they did it. Because no matter how bad business looks at the present time or the near future, it is useful to at least occasionally notice the glass is half full.
It is in this spirit of determined survival we examine the financial performance of 25 diversified Canadian OFS companies last year. There are numerous different businesses supporting multiple sectors of the upstream oil and gas industry. These companies had revenues ranging from $60 million to $1.8 billion, from comparatively small businesses to huge. Most had some sort of presence in markets outside of Canada, while five had meaningful revenue diversification outside of the oilpatch.
The financial performance of publicly traded OFS operators is analyzed continuously. The data is sliced and diced and presented in many ways. But most analysts focus on how much money these companies make, a key driver of value.
At MNP, we take a different approach, which is to focus on how OFS companies make money. Where the rubber hits the road for OFS is the margin between what companies can charge the client versus the direct expenses, or cost of goods sold (COGS). This is the primary measure of pricing power or pricing pressure and the company’s ability to operate effectively, control costs or adapt to changing market conditions.
The following chart ranks success by each company’s ability to grow, maintain or slow the decline of the gross margin on revenue — sales less direct expenses or COGS. These are the direct variable and direct fixed costs incurred to generate revenue. This most often includes field labor, fuel, expendables, repairs, subsistence, cash cost of product sold, maintaining field service locations, field administration and transportation (including field vehicles). Some companies include depreciation and amortization in direct expenses and disclose it elsewhere, while others report it as a separate line item on the financial statements. Therefore, to normalize the comparative gross margins for companies that include it in direct expenses, depreciation and amortization have been deducted thus increasing gross margin from what the companies publicly reported.
Gross margin does not include corporate fixed costs commonly called SG&A or sales, general and administrative expenses. SG&A is the fixed cost a company spends to run the organization, whether there is any revenue or not. Nor does gross margin including other expenses such as financing costs, foreign exchange or asset value restatements.
Source: Company reports SEDAR
Abbreviations: Mfg, Manufacturing; Svc, Services; Prod, Production; Enviro, Environmental
1 – Company reports depreciation and amortization in cost of goods sold so this has been deducted from direct expenses for accurate comparison with companies who report depreciation and amortization as a line item elsewhere on their financial statements.
2 – Company reports material business and operations outside of Canada.
3 – Company reports revenue diversification into non-petroleum business sectors.
Color coding reflects margin maintenance success: green for increasing or holding year over year margin loss below 2%; yellow for holding margin loss below 6%, red for margin loss 7% or more.
Unfortunately, 2016 has started off even worse than last year. Due to continued low commodity prices and the expiration of higher priced commodity hedges (which sustained cash flow), E&P companies are continuing to reduce capital spending in 2016. While crude oil is showing some signs of potential recovery, natural gas prices in Canada are severely depressed because of high storage levels and competition from U.S. sources like the Marcellus shale in historic markets such as eastern Canada. With spring break-up underway, there is no indication OFS business will improve in the short term. A meaningful oil price increase could change the outlook in the second half of the year.
However, the above figures certainly demonstrate OFS operators will do what they must when they must to sustain their businesses and the viability of operations. As awful as it looks, the ability of these companies to hold their average gross margin loss to only 4%, when as nearly one-third of their business disappeared, due to lower capital spending and severe client pricing pressure is a testament to the skill and determination of these companies, their executives and their management teams.
That doesn’t mean the operational adjustments made in 2015 are sustainable. Margins were held because workers with no options took pay cuts; repairs and maintenance investments were delayed on equipment that was parked, and vendors in the supply chain were ground down to rates that won’t stand the test of time.
If and when E&P companies want to go back to work, they will have to pay more. That said, the foregoing data indicates at least there will be somebody there to answer the phone when they call.
In January 2015 this newsletter boldly predicted a recovery in oil prices in the third quarter of 2015 because high decline rates for light tight oil (LTO or shale) production in the U.S. would cause a 1 million barrels per day (b/d) reduction in world oil supply later that year.
The theory was right but the dates were all wrong. In fact, based upon several years of aggressive drilling and the lag time for completion and tie-in, U.S. oil production kept rising. Using statistics from the Energy Information Administration (EIA) American, crude output rose nearly 500,000 b/d from 9.18 million b/d (monthly average) in January of last year to the peak of nearly 9.6 million b/d in June of 2015. But it has been declining since as the following chart will demonstrate.
The above information shows average monthly U.S. crude oil production from the first time it exceeded 9 million b/d in November of 2014 through to its peak of 9.6 million b/d in June 2015 to the output in the first week of April 2016, back to 9 million b/d. Output has declined 600,000 b/d in about nine months. Due to the massive reduction in the U.S. rig count drilling for oil (1,609 in October of 2014 versus only 354 on April 8, 2016) one can expect this trend to continue. In its April outlook, the EIA estimates average quarterly U.S. crude and liquids production will fall 1.1 million b/d from Q4 2015 to Q4 2016 and a further 160,000 b/d through to Q4 2017.
The EIA data indicates the U.S. will exit 2016 with oil output about 1.4 million b/d below its peak last year. This will make a material contribution towards stabilizing global crude oil supply and demand and is the reason an increasing number of analysts are becoming more confident about oil price increases in the second half of the year.
Better late than never. As famous Houston-based analyst Henry Groppe, 89, has supposedly said, he’s never been wrong about an oil price or production forecast. It has always been a question of timing.
EIA data reporting goes back 33 years ago to January 1983 when U.S. oil output was 8.6 million b/d. The peak within the reported EIA data was May of 1985 when production hit 8.995 million b/d after a decade of furious drilling caused by the oil price boom of 1973 to 1985. Thereafter, American production began to decline until it hit bottom at only 3.901 million b/d for the week ended October 7, 2005. This is a drop of 5 million b/d over 22 years. That U.S. oil production would fall that much while demand continued to grow created significant market opportunities for other producers from around the world. A major beneficiary was Canada.
But what happened in the next nine years provided the fundamental change in global oil markets which caused the price collapse of late 2014, the repercussions of which the world’s oilpatch is enduring today. From the trough of October 2005, the U.S would add over the next 10 years 5.6 million b/d of daily crude output. The only countries in the world to ever produce over 5.6 million b/d of oil are the U.S., Russia and Saudi Arabia. And for the U.S. this was
Fortunately for oil producers and unfortunately for oil consumers, this isn’t likely to happen again. While technology and geology have proven U.S. LTO output is real in terms of barrels produced, the economics are not there, nor will they ever be. There cannot be a subject under the general titles of business or finance about which more rubbish has been written than that of the alleged sustainability of U.S. LTO production based on factors such as the efficiency and / or productivity of drilling rigs or focusing on the “sweet spots” of various LTO plays (This assumes E&Ps willingly drilled the garbage first at higher costs than necessary because oil prices were high).
In the March 14-29, 2016 edition of
Businessweek there was an article about the end of the LTO boom in Oklahoma. According to the author, in the period 2011 to 2014, four major LTO drillers – Devon Energy, Chesapeake Resources, SandRidge Energy and Continental Energy - “…outspent cash flow by a combined US$36.8 billion.” These four companies alone “…were spending US$2 drilling for every US$1 they earned selling oil and gas.” Faced with first year decline rates in the range of 60% to 70%, the article said, “To sustain the growth investors demanded, companies had to drill fast enough to offset those declines. That phenomenon is called the Red Queen, after the character in
Through The Looking Glass who tells Alice, ‘It takes all the running you can do, to keep in the same place’.”
Even if the price of oil rises – which we all hope it will – the ability of U.S. E&P companies to return to the field to resume LTO drilling without the support of third party capital providers remains in question.
Obviously the massive downturn in U.S. and Canadian LTO drilling has been devastating for OFS on both sides of the border. But the good news is to stay in this business, E&P must keep drilling. At some point the price will go high enough so that the better financed operators with the better prospects can return to the field and put some rigs and equipment back to work.
But in the short term, the rise in North American LTO production that helped create the low oil price problem is falling fast and will have a material impact on global crude prices. It is already happening.
In November 2014 when the US$35 billion Halliburton / Baker Hughes deal was announced, it was seen as two of the world’s largest OFS companies showing the rest of the industry how to survive a long slump in oil prices. Halliburton Co. offered to buy all the outstanding shares of Baker Hughes Inc. with a combination of cash and shares. Included in the deal was a US$3.5 billion break fee (10% - normally this is more like 3%) if Halliburton could not close the transaction. The idea was this giant service company would be more efficient for shareholders in a contracted global marketplace than the two companies going head-to-head in many markets and many product and service lines.
Apparently, the combined companies would be too efficient, to the point the combination has raised red flags all over the world. To stave off accusations of restricted competition, Halliburton agreed to hive off numerous business units to whomever might want to buy them. The companies have been extremely careful about behaving like independent organizations even as executives at the top of both organizations have worked feverishly to consummate the marriage. But the merger could not escape the attention of competition regulators in multiple jurisdictions.
The first to complain about the combination were clients like Total SA in Europe and Chevron Corporation in Brazil. While the market share and pricing power of a combined Halliburton and Baker Hughes would likely not be an issue in well-served OFS markets like North America, this is not the case all over the world. The bigger operation would have the power to affect pricing in certain markets. Acting in his company’s own interests, Total CEO Patrick Pouyanne told an energy conference in New Orleans in March, “Obviously when you have less competition in service providers, I’m not in favour.” When questioned about his comments Pouyanne replied, “I’m doing my job.”
Nearly 18 months after it was first announced, the deal is truly in question after the U.S. Department of Justice revealed April 6 it would turn to the courts to prevent the merger. Its reasoning is it would give the combined company too much pricing leverage in the OFS market, thus making it anti-competitive. Adding to the problem is, despite the efforts by Halliburton to sell off divisions to satisfy regulators, the downturn has prevented buyers of larger OFS assets or product lines from the merged company from offering adequate valuations relative to what they are being priced at within the combined entity. Trade publications report logical acquirers of divisions, products or business units like Weatherford International Ltd. don’t have the financial muscle nor inclination to make major purchases at the values the sellers would like to see in the current market environment.
Now what? Speculation is rampant that if the deal dies in its current form, this won’t be the end of consolidation opportunities among the world’s largest OFS players. A Bloomberg article April 8 speculated General Electric Co. could be a bidder for Baker Hughes if the deal dies. GE has invested billions in recent years positioning itself as a major supplier in a variety of OFS sectors. While the article never indicated GE was actually contemplating such a move, the company does have the financial muscle to play in the big leagues of OFS.
If the merger fails, it will be interesting to see if Halliburton will actually pay the US$3.5 billion break fee. At December 31, 2015 the company reported cash and cash equivalents on its balance sheet of US$10.1 billion, certainly enough to stroke such a massive cheque. But when the company did everything it could to complete the deal, only to be thwarted by third-party regulators, Halliburton could make the case the failure of the close was not of its doing, and therefore the break fee is not payable.
The North American rig count continues to fall because of diminished cash flow among oil and gas producers caused by low oil and gas prices and the continued expiration of production hedges at higher prices from past years. Canada is experiencing spring break-up, but the year-over-year reduction from 2015 and 2014 demonstrates clearly the problem is greater than road bans. In recent weeks, North Dakota has levelled off at about 30 rigs which is up one from a week ago. The Baker Hughes rig count of U.S. rigs targeting oil has fallen yet again to the lowest levels in over six years.
FOR FURTHER INFORMATION ON OILFIELD SERVICES CONTACT:David Yager, National Leader, Oilfield Services
Client Groups:Oil ＆ Gas
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