OIL SERVICE'S CAP
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 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.
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.
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Libya’s oil production increased steeply to the current level of 850,000 b/d from a low point in August 2016 of below 300,000 b/d. Production surpassed 1 million b/d in July.
- Revenue of $7.9 billion increased 6% sequentially - Pretax operating income of $1.1 billion increased 11% sequentially - GAAP EPS, including Cameron integration-related charges of $0.03 per share, was $0.39 - EPS, excluding Cameron integration-related charges, was $0.42 - Cash flow from operations was $1.9 billion; free cash flow was $1.1 billion
“The combination of GE Oil & Gas and Baker Hughes closed on July 3, and we are pleased with our progress during our first operating quarter. Despite the continuing challenging environment, we delivered solid orders growth and secured important wins from customers, advanced existing projects and enhanced our technology offerings in the quarter. We also achieved key integration milestones and made significant progress working as a combined company. I am now more convinced than ever that we combined the right companies at the right time,” said Lorenzo Simonelli, BHGE chairman and chief executive officer.
U.S. Rig Count is up 360 rigs from last year's count of 553, with oil rigs up 293, gas rigs up 69, and miscellaneous rigs down 2 to 2. Canada Rig Count is up 59 rigs from last year's count of 143, with oil rigs up 38 and gas rigs up 21.