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As the new year begins, there have been endless prognostications on what will happen to the price of oil and the subsequent impact upon oilfield service (OFS) activity. The range is somewhere between bad and much worse. OPEC is rudderless, Iran will be adding to the glut and Russian production is at record levels. Light tight oil production is declining in the United States but accurate data is always several months late. Global crude inventories are said to be at record levels, which only adds to the bearish sentiment.
Not a single person who comments on this subject believes there will be a meaningful improvement in crude oil prices anytime soon, “soon” defined as being in the next six months. The most optimistic forecasts are for meaningful price increases in the latter half of the year. In the first quarter some analysts have predicted crude prices could reach new lows which is occurring as this is being written. The commodity trading bears hopelessly outnumber the bulls. Even the well-publicized escalation of tensions between oil producing giants Iran and Saudi Arabia has had no impact on oil prices.
A year ago, this newsletter embarrassed itself by predicting a meaningful oil price recovery by the end of the third quarter of 2015. No such attempt will be made this year. There is, however, another major financial driver besides oil prices which has historically affected exploration and production company (E&P) spending, thus OFS revenue and activity. That is capital inflows to E&P companies through equity, debt or intercompany transfers.
While the greatest source of cash for reinvestment is the sale of existing production, by raising or transferring capital, oil companies can spend more money than they could otherwise. OFS managers rarely pay much attention to where their client’s money comes from so long as the cheque doesn’t bounce. Understanding how factors other than commodity prices can affect OFS revenue opportunities will help managers make better decisions in what appears to be a long and challenging year.
In the early 1980s, the federal government created something called the Petroleum Monitoring Agency or PMA. Until it issued its final report in 1994, the companies which produced some 95% of Canada’s oil and gas were required by law to report their financial activities to the federal government. While this included tracking of foreign ownership and control (a major issue at that time), the PMA annual report also included a macro balance sheet of the entire Canadian E&P sector, including how it was capitalized. This included total levels of debt and equity raised on a year-over-year basis. Using PMA total industry debt figures, one could calculate the change in free cash available for reinvestment if interest rates rose or fell or the impact of major changes in capital markets. No such big picture macro data exists nowadays.
Now the easiest data to analyze the E&P sector as a whole comes courtesy of ARC Financial Corp. which publishes a weekly overview of the Canadian oil and gas economy. ARC reports 15 years of average commodity prices, production, gross production revenue, after-tax cash flow from production and reinvestment in conventional oil and gas and oil sands development. While nowhere near as granular as the old PMA data, it does contain some relevant information on how external capital inflows affect OFS activity.
The blue bar is total revenue for Canadian producers measured by the value received for their oil and gas production, based upon volume and price. The red bar is what ARC calls “after-tax cash flow,” or the amount of money available to spend on capital expenditures, or CAPEX. The major deductions from revenue to determine cash flow are royalties, taxes, fixed costs and production operating costs. The green line is total reinvestment or combined CAPEX on conventional oil and gas and oil sands.
Of note for OFS is the spread between after-tax cash flow and CAPEX. For many years CAPEX was below after-tax cash flow but in recent years it is been above. This spread can affect OFS in either a positive or negative manner.
This chart combines ARC’s reinvestment ratio in purple (left axis) and the average bank prime lending rate for the year in red (red axis). The green line is 100% of cash flow. Of note is in the period 2001 through 2009, the reinvestment ratio of cash flow was below 100%. It hit the lowest level in 2008 when oil and natural gas were both at record high levels. There was more cash coming in the door than producers knew how to intelligently re-invest (see first chart when upstream cash flow hit record levels).
But what OFS should pay attention to is the amount by which reinvestment has exceeded cash flow for the past five years. Besides free cash from existing production, there has been significant capital flowing into the treasuries of E&P companies which has found its way into the pockets and bank accounts of OFS through aggressive capital spending. This is obviously good news for OFS unless, of course, it stops. This is a major cautionary note for 2016.
As has been written in this newsletter before and by many other analysts, the correlation between aggressive spending and historic low interest rates is real, particularly among U.S. light tight oil developers. It is no coincidence that when the reinvestment ratio was at its highest, interest rates were at their lowest. After oil prices collapsed over a year ago, it has been widely reported many U.S. light tight oil developers have financed drilling and development not from cash flow from existing production but from debt, particularly high yield bond markets. This has resulted in much higher levels of OFS activity that would have occurred from cash flow from existing production alone.
This is all great until the music stops and right now the band is out for coffee. The main issue among lenders today is if and how to get their money back and the main issue among borrowers is amended covenants, debt deferral and / or restructuring.
Canadian Oil & Gas Prices by Year: Oil in Barrels, Gas in Barrels of Oil Equivalent
1) Source: Natural Resources Canada average yearly price for Canadian Par Edmonton / Canadian Light Sweet
2) 2015 price 11-month average only to November 30, 2015
3) Barrel of Oil Equivalent: Source: CAPP Statistical Handbook 2001 – 2014, Government of Alberta Energy Update December 2015 to November 27, 2015. Converted to BOE at 6 mcf to 1 barrel
This table shows the average annual oil price in Canadian dollars in the past 15 years and the average price of natural gas on a barrel of oil equivalent (BOE) basis for the same period. The price of natural gas stayed more or less in line with crude oil on a BOE basis until 2007, which was the beginning of the North American shale gas boom, after which an onslaught of cheap new supplies collapsed prices. Since then, the two commodities have diverged with the most extreme differentials occurring in 2011, 2012 and 2013.
Looking at the reinvestment ratios up to 2009, one big reason the industry was able to increase CAPEX without any net capital inflows was because gas was just so profitable, compared to light tight oil or oilsands development.
After the price of gas tanked but oil stayed high, E&Ps changed their investment patterns from gas to oil, tight oil and oil sands. The problem with new oil supplies in North America is they cost more to develop and, in the case of the oil sands, significantly more to operate. Thus, the industry entered a period when significant net cash inflows were essential to maintain investment at high levels. Not all of it came from debt markets. There were intercompany transfers as big operators with downstream or international operations moved capital from one part of the company to another or into Canada from other countries. Equity markets were robust, allowing companies to raise money for CAPEX by selling shares from treasury.
But unlike the period 2001 and 2009, it is clear that for the past five years the oilpatch could not sustain the high levels of CAPEX from internally-generated cash flow alone.
The most cautionary number in all these figures is the estimated reinvestment ratio of 1.72 for 2015. This is a simple mathematical calculation of estimated reinvestment divided by after-tax cash flow. Unlike the fascinating data that used to come from the PMA, ARC provides no detail on where this money is coming from: intercompany transfers, equity or debt. Equity markets were fairly robust in the first half of last year, allowing some companies to strengthen their balance sheets and finance spending. But it is also fair to assume with oil prices on the wrong side of US$40 a barrel and currently falling further, the ability for OFS clients to tap debt and equity markets to keep spending will be materially reduced.
Even if E&P clients are able to negotiate more favorable terms for their debt, the industry’s overextended balance sheets will put a cap on activity — even if oil prices rise. On the producer side, companies will most likely de-lever before they drill should some extra cash come in the door. For OFS, building all the new equipment such as walking rigs and big frac spreads to meet strong client demand has some players in this sector significantly over-levered.
Unfortunately, few if any checked to see if their client’s entire cash stream was sustainable when they placed the equipment order with the fabricator.
The service sector’s determination to protect intellectual property (IP) through patents then defend against infringers – real or imagined – has been growing in recent years. Calgary’s Packers Plus Energy Services Inc. is widely recognized as a leader in development of a simple and reliable multi-stage packer assembly for extended reach horizontal wells. Using ball seats of increasing diameters installed in the production casing and balls of equivalent changing diameters, Packers Plus put a reliable system into the marketplace early in the game and has benefited enormously. There are many different types of multi-stage packer assemblies available today, but that Packers Plus is a pioneer is widely recognized.
The business was so profitable in the early stages and client demand was so high, several other companies began to design, manufacture and market systems using variations of the basic Packers Plus design. While the Packers Plus systems was patented in Canada and the U.S., the true protection of any patent is really not known until it goes before the courts. After a century of developing downhole oil tools and packer systems, the prior art (or evidence an invention is already known) is significant. Regardless, anyone who has worked in the downhole tool patent space realizes two things. One, you can obtain a patent for a new design or system even if prior art exists by incorporating subtle changes, or having the good fortune to have the patent office miss something during review and approval. Two, the strength of the patent will only be proven after an expensive investment in patent infringement litigation and the arduous path from a statement of claim to court.
According to a January 5, 2015
Calgary Herald news story, in July of 2013 Packers Plus filed a statement of claim against Canuck Completions Ltd., arguably one of the smaller providers of multi-stage ball and seat systems in the market at that time. In October of that year, a patent infringement lawsuit was also filed against Essential Energy Services Ltd. for the same crime. Others in the marketplace spent a lot of money researching prior art and concluded (hoped?) the Packers Plus patent filed November of 2001 was invalid because other systems using essentially the same mechanism and process had been in use prior to the Packers Plus patent filling. This would render the patent invalid.
The new story indicated on December 4 the Federal Court of Canada ruled in favor of Packers Plus and slapped Canuck Completions with $7.7 million in fines and penalties. Packers Plus president and CEO Dan Themig told the newspaper this decision laid to rest the “prior art” defense used by the alleged infringers. The court also ordered Canuck to pay $495,000 in costs. Themig said his company held a “family” of 63 patents in the multi-stage packer system space.
Essential, a publically traded company, apparently filed a counterclaim and statement of defense which it described in regulatory filings as being, “based on the premise that the methodology and equipment on which the patent is based has been in use in the oil and natural gas industry prior to the patent’s effective filing date…” This trial is set for February, 2017.
It is a nightmare problem for those in the natural gas storage business, which is huge in North America. A California storage facility near Los Angeles began leaking large volumes of methane a couple of months ago. Owned by Southern California Gas Co., a unit of Sempra Energy, the leak has resulted in the relocation of some 2,000 households. According to a news report in the January 4 edition of
oilprice.com, the operator is resorting to a relief well, which will have to be drilled to about 8,500 feet, to stop the leak, a process which could take three months.
While natural gas storage facilities are common and not generally regarded as a hazard, they are accessed, filled and drained using conventional wellbores. Any wellbore used to access and control gas under pressure bears an implicit mechanical and operational hazard.
One of the new applications of subsurface storage of gas is carbon capture and storage (CCS) whereby carbon dioxide is pumped under pressure into reservoirs with the plan of having it stay there forever. Attempts have been made in Europe to convert depleted natural gas reservoirs into carbon dioxide sequestration reservoirs but these have met with public opposition because of health and safety concerns about the potential of a carbon dioxide leak caused by wellbore or mechanical failure.
News reports do not indicate environmentalists or concerned citizens have connected the dots between the current methane gas storage leak in California and the future potential leak of a CCS facility somewhere else.
Everybody knows the current pullback in global spending on the development of new oil supplies plus a continued increase in demand caused by low prices will result in higher oil prices in the future. It’s not a question of if but when.
Late last year
oilprice.com posted a story about how OPEC figures $10 trillion must be invested in the development of new oil supplies over the next 25 years to ensure the price of oil does not rise above US$100 a barrel before 2040. Although OPEC forecasts lower demand growth for years to come, due to the increasing acceptance and lower costs of non-hydrocarbon energy sources such as wind and solar, the oil cartel nonetheless sees oil demand reaching 110 million barrels per day by 2040, 15 million barrels per day higher than current levels. This is average demand growth of about 1 million barrels per year, plus another 3 to 5 million barrels per year which must be replaced to offset reservoir decline rates.
But at current oil prices, it is estimated 2016 global spending on new oil supplies will be at the lowest level since the 2009 recession. This bodes well for future price increases.
As was reported in this newsletter following December 4 OPEC meeting, the decision by former world oil market-maker Saudi Arabia to abandon its historic role as swing producer and for OPEC to abandon cartel quotas or enforcement was partially due to its power struggle with Iran for control and / or influence in the Middle East.
Recent events indicate this analysis of the conflict was correct. With Saudi Arabia being a massive oil producer and the economic sanctions against Iran being removed, allowing it to resume its historic role as a major producer, this oil production struggle could continue to depress oil prices for some time.
It has been widely reported Saudi Arabia’s determination to sell as much oil as it can at current prices has been an enormous drain on that country’s treasury. However, the country is pitting in for the long haul by introducing significant austerity measures for the first time. Late last year it was announced government spending would be cut by 14%. It also increased the price of gasoline by 50% from a paltry US$0.16 per litre to US$0.24 per litre, still not much by world standards but a significant increase nonetheless.
Early this year, the Saudis executed nearly four dozen political prisoners including a Shiite Muslim cleric popular in Iran. This caused enraged Iranians to the storm the Saudi embassy in Tehran and demand Saudi officials leave the country. Other countries aligned with the Saudis condemned Iran and took action on the diplomatic front. At the same time, the Iranians publicly reinforced the right to build ballistic missiles, something that has caused the U.S. to contemplate new economic sanctions against Iran, even as the current nuclear-based sanctions are in the process of being removed.
While there are many theories on how the rising tensions between Iran and Saudi Arabia will manifest themselves, there is a continued belief the Saudis – with huge cash reserves relative to the Iranians – will use high oil output and low oil prices as an economic weapon to impair Iran’s ability to increase oil production, improve the economy and ramp up military spending.
On the first trading day of 2016, world oil markets responded to the increased Middle East tensions by adding a modest risk premium to the price of oil. But later that day, after analyzing the global oil supply and storage surplus, the price of oil fell and continues to fall. Whatever the issues are between Iran and Saudi Arabia, there is no indication they will have an immediate impact on oil prices without a significant and measurable supply disruption.
The start of the new year has caused a nice bump in the Canadian rig count which, at 207 on January 5, is the highest level since October 2015. On a year-over-year basis, it is down less, percentage wise, than drilling activity in North Dakota or oil drilling in the U.S. However, Canadian activity is seasonal, with more rigs drilling during the winter period because of reduced remote access costs.
Canadian Active Rig Count
U.S. Active Rig Count Drilling for Oil
Source: Baker-Hughes Rotary Rig Count December 31, 2015
North Dakota Active Rig Count January 5, 2016
Source: North Dakota Department of Mines & Resources
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