Is the Oilpatch Recovery Already Over? What’s Happening Now? Read it HERE – David Yager – Yager Management

 

 

 

 

 

David Yager – Yager Management Ltd.

Oilfield Service Management Consulting – Oil & Gas Writer – Energy Policy Analyst

June 28, 2017

In the investment business they call it the “dead cat bounce”. Share values hit bottom and appear to rise and recover but soon return to their low levels. Like a dead cat dropped from a significant height, stock values appear to rebound but not much and not for long.

And as WTI again trades on the wrong side of US$43 a barrel as it did on June 21, the anxiety level of everyone in the oil and gas industry rose significantly. Is the recovery already over?  It barely got started! The mid-day low was US$42.05, the lowest price since WTI closed at US$41.75 on August 10, 2016.

In the past four weeks WTI has lost 20% of its value, the official definition of a bear market. US$10 a barrel is about Cdn$13 at current exchange rates. For a country producing some 4.5 million barrels of oil and liquids daily, that works out to $58 million a day or $21 billion if it stayed at that level for a year.  The old saying goes, “A billion here, a billion there, next thing you know you’re talking real money”. Ouch!!

Should this price (or a lower one) stick around, people have already run the math. On June 22, the Financial Post carried an article detailing the potential carnage. ARC Energy Research Institute has for years produced a marvelous weekly macroeconomic model of Canada’s upstream oil and gas industry based on commodity prices, production volumes, operating costs and free cash flow available for reinvestment in capital expenditures. Free cash is the number one source of capital for growth which is augmented with debt, equity or both depending on the company’s balance sheet, investor enthusiasm and capital markets.

Jackie Forrest, ARC’s director of research, told the newspaper that if WTI stayed at US$43 instead of US$53 for a year, capital spending from producing cash flow would shrink from an anticipated $44 billion to only $23 billion, a $21 billion reduction. This would put us back at the same levels as 2016, the dreadful year so many thought was behind us. Forrest said, “You would see about half as much drilling and activity associated with oil and gas if prices stay in this range over the course of 12 months. There is a scenario that oil prices do stay in this level and it’s something that companies have to be thinking about; can they survive these type of prices?”

So what happened?

In November of last year OPEC and Russia agreed to pull 1.8 million b/d off the market effective January 1, 2017. This was greeted enthusiastically by commodity traders and WTI responded in advance, trading above US$50 a barrel in mid-October. It did the same thing for a few days in June. Before that WTI hadn’t seen the sunny side of US$50 a barrel since July of 2015. With WTI trading as low as US$26.19 on February 11, 2016, the price of oil had doubled from its multi-year historic low. This was a massive improvement. Once the OPEC cutbacks were announced WTI stayed above US$50 a barrel until mid-March.

Then OPEC announced another meeting for May and telegraphed to markets the cuts might be extended well beyond the end of the year. This caused crude to jump again and its stayed around US$50 a barrel until late May. The agreement would run well into 2018. OPEC bragged about very high compliance with the cuts. OPEC claimed there was 100% participation while other reports indicated it was 110%. The message to markets was this is well managed and global oil markets are under repair heading for balance.

With prices higher, cashflow from production jumped as did spending plans. Sooner or later oil companies must resume reserve replacement or they go out of business. With service prices low because of overcapacity, people went back to work. The pricing wasn’t great for service providers but it sure beat a yard full of parked equipment and idle employees. Equity markets opened up allowing numerous oil companies and their suppliers to rebuild their balance sheets.

At the same time, the U.S. light tight oil (LTO) business kicked back into gear. U.S. production had fallen over 1 million b/d from its 2015 peak to under 8.5 million b/d by October of 2016. But with higher prices, part of a large inventory of drilled but uncompleted wells (DUCs) were put on stream and the rigs went back to work. Baker Hughes reported the number of active land rigs drilling for oil hit a modern era low of 316 on May 27, 2016. By the end of the year this was up to 525 and the last report for June 23 was 758. U.S. LTO is never short of prospects to drill, only cash and economic viability. The new higher oil prices and vastly reduced service costs made a lot of reservoirs economic again.

Production responded. By the of the year U.S. crude production was up 270,000 b/d and the growth continued. The last report from the Energy Information Administration for June 16 was 9.35 million b/d, some 850,000 b/d higher than the low in October of last year. That is approximately half the oil OPEC et al withdrew from the market.

Meanwhile, the on-again, off-again crude production from Libya and Nigeria also increased as production resumed due to unplanned outbreaks of peace and tranquility. Depending on what you read, this accounts roughly for the other half of the OPEC cutbacks.

What traders have been studying is inventory levels in the U.S. and OECD countries. While western countries are likely to publish pretty accurate data on everything to do with oil, reliable information on crude oil production and inventories from the Middle East, Russia, Libya, Nigeria and other countries is hard to find. When OPEC says it is 100% compliant with the output cuts, the world really must take their word for it as there are no transparent regulatory bodies to which OPEC producers report like the Alberta Energy Regulator or the Texas Railroad Commission. Output from many of these countries is calculated by tanker loadings, not actual production data. Even when OPEC compiles crude oil market reports, it relies on western and third-party sources, not its members.

If oil is really being withdrawn from the market at some point it should be reflected in inventory levels in the U.S. and OECD. OPEC has predicted inventory draws over the course of the year as its production cuts take hold. Even with increased output from the U.S., Nigeria and Libya, natural reservoir decline, demand growth and the impact of reduced drilling everywhere in the world except North America should at some point cause stocks to decline. But by June of this year, when oil prices started to fall, there was no evidence from either U.S. or OECD inventories that there was any less oil on the market than when OPEC started this process six months ago. In fact, the inventory data is causing some analysts to believe OPEC is in fact not living up to its announced production cutbacks.

U.S. Oil Inventories

Source: Powerhouse.com U.S. energy research consultancy, Energy Information Administration

Source: ERC Equipoise (ERCE), the UK’s leading employee-owned oil and gas reservoir evaluation firm.

The above charts illustrated the problem. The top chart is the U.S. Even though the U.S. is now exporting oil, total inventories (excluding the Strategic Petroleum Reserve) are higher this year (blue line) than in 2016 (green line). The shaded area is the five-year range and the black dotted line is the average. The spread is about 200 million barrels or about 20%. What complicates matters further everyone believes U.S. production will continue to grow based on the significant increase in drilling.

It is the rest of the world that will move the needle on oil prices. In OECD countries, the same oil storage problem exists although there is modest opportunity for optimism. The brown line is 2017 stocks and the blue line 2016 stocks. There is some measurable progress in that 2017 inventories dipped slightly below 2016 by May.  However, inventories remain about 350 million barrels above the middle of the green shaded five-year range. This is only about 13% above the five-year average but a lot of oil nonetheless.

These inventory charts provide oil traders and speculators with confidence in at least some data when dealing with global oil markets. Surely western countries can be counted upon to accurately measure the volume of a tank. Gotta trust somebody. And when they analyse the information, the conclusion is bearish, not bullish. If oil is really being withheld from the market, why are inventories not declining?

Most analysts looking at all the information have concluded that when all factors are taken into consideration – production, demand, reservoir declines, capital investment in new supplies – the supply/demand curves will indeed cross. But increasingly more are pushing this out into 2018 instead of the last half of 2017 as previously thought. If commodity markets need to see a 550 million barrel decline in U.S. and OECD inventories before it is concluded the oil glut is over, this could take some time. At a 1 million b/d net output decline this will take the better part of 18 months.

But it could work out better than that. Withdraw a net 1 million b/d (assuming peace in Libya and Nigeria is not assured), add in demand growth of 1.4 million b/d and non-replaced reservoir declines of 2 million b/d, it will take only 125 days or about four months to balance the market by reducing inventories by 550 million barrels. When OPEC says markets will rebalance in the last half of the year this is likely the calculation they are performing. And OPEC keeps repeating that oil markets will move into balance before the end of the year based on its current production cuts. Rising production from the U.S., Canada and Brazil will extend this figure, but the lack of investment almost everywhere else in the world will shorten it.

So what does this mean to an industry that, at least for six months, thought it was actually climbing out of a very deep hole?

First, three weeks of low prices do not a year make. On June 27 JWN Rig Locator reported 196 active drilling rigs, a big number for the end of June in any year. A year ago in 2016 there were only 80 rigs drilling on June 28 and 147 on June 30, 2015. Comparatively speaking 2017 is very active for this time of year.

Second, a meaningful part of Canadian production was hedged when prices were higher which will provide some stability to producer cash flow depending on how much was hedged and at what price. This means more cash will be available for investment in the short and medium term than the spot price would indicate.

Third, the Canadian dollar at about US$75 continues to give domestic producers a price lift. This is offset somewhat by crude differentials and transportation costs. But for example, on June 26 WTI closed at US$43.38 while Edmonton Mixed Sweet ended the day at Cdn$53.34, about 25% higher. Blended heavy crude Western Canada Select fetched Cdn$43.89. Not what it was, but crude at these levels will certainly pay all the bills and leave some cash left over for reinvestment.

Natural gas, the forgotten sister in today’s oil-obsessed market, is doing very well in 2017 compared to last year. According to the TMX NGX Alberta Market Price for natural gas, the average monthly price for the first five months of 2016 averaged only $1.68 per gigajoule (GJ). For the same five months in 2017 the average monthly price was $2.68 per GJ, 60% higher. Condensate was selling for Cdn$56.26 on June 26. For operators drilling liquids rich gas wells like in the Montney, the current oil price is a setback but hardly crippling.

That said, US$10 a barrel is big deal in a high cost, mature basin like Canada. Projects work at US$53 that don’t all work at US$43. While nobody is cancelling any major programs yet, if what we see is what we get for oil prices there will be, as ARC as noted, a downward correction in spending. As for service prices, the lower price ensures the focus will be more on practice than profits. When crude prices were higher and customers needed people and equipment, service companies could push through price increases if for no other reason than to hire people to do the work.

It is highly unlikely the rig count will rise with oil prices down 20%. With the drilling rigs, frac spreads and support equipment more or less fully crewed, securing higher prices to garner an acceptable margin will be very difficult if not impossible. What is more likely if oil prices don’t firm up is a gradual erosion of demand for equipment and people until prices rise and economics improve. Hire them back then send them home again? If that happens that hurts everybody. Who will come back next time? It was hard enough to persuade people to return to the ‘patch’ earlier this year.

At this stage, nobody really knows what is going to happen so most analysts do what they do best with the least risk; extrapolate what happened yesterday into the future and report accordingly. Most forecasts work that way. And that picture with sharply lower oil prices is pretty discouraging considering where the industry has been in the past two and a half years.

About David Yager – Yager Management Ltd.

Based in Calgary, Alberta, David Yager is a former oilfield services executive and the principal of Yager Management Ltd. Yager Management provides management consultancy services to the oilfield services industry in a number of areas including M&A, Strategic Planning, Restructuring and Marketing. He has been writing about the upstream oil and gas industry and energy policy and issues since 1979.

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David Yager can be reached at Ph: 403.850.6088 Email: yager@telus.net

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