By Marin Katusa, Chief Energy Investment Strategist
Back in March, I warned that natural-gas reserve writedowns were looming. Last week they arrived.
Encana (T.ECA), Canada's largest gas producer, wrote down the value of its North American assets by US$1.7 billion. Declining valuations for its shale holdings in the United States caused US$1.1 billion of the impairment; shale properties in Canada accounted for the rest. Despite the magnitude of the hit, Encana CEO Randy Eresman warned that further writedowns will probably be needed.
BG Group (L.BG), the third-largest oil and gas producer in the United Kingdom, soon followed suit, writing down its US gas assets by US$1.3 billion. The company's CEO says the company will now focus on opportunities to export liquefied natural gas (LNG), a coded way of saying that the company doesn't see much potential for profit in simply providing more gas to the North-American market in the coming years.
Houston-based Noble Energy (N.NBL) also recorded impairment charges, writing down the value of its US gas assets by US$73 million because of lower natural-gas prices and warning that additional writedowns may be necessary. Other companies arrived at the writedown table earlier: in May Exco Resources (N:XCO) reported a US$276 million writedown on its assets, and Quicksilver Resources (N.KWK) wrote down US$63 million.
Several other producers are expected to write down the values of their natural gas assets when they announce quarterly results later this week, including a first writedown from Ultra Petroleum (N.UPL) and a second downgrade from Exco.
Yet natural-gas prices have been doing relatively well in recent weeks. What gives – why are these massive impairment charges hitting the sector now? And will these hits slow the sector's seeming recovery?
This Dispatch aims to answer those two questions.
To understand why impairment charges are hitting the natural-gas sector now, we have to first investigate how gas projects are valued. Gas projects are valued based on their reserves. A "reserve" is an estimate of the volume of gas at the project that can be extracted economically. Gas is only economic if it can be sold for more than it costs to get it out of the ground, so reserve volumes depend on the price of gas. When the price of gas falls, high-cost reservoirs often become uneconomic.
As a generality, shale gas is fairly expensive to produce. High-powered drills are needed to punch through these tight rock formations and then fracture the rocks repeatedly. Specialized equipment of that sort is expensive to operate. The tighter the formation, the harder and more expensive it is to extract the gas.
As the following chart shows, more than half of America's shale gas basins are uneconomic at the current spot price. While you ponder that, consider also that hot weather has buoyed natural-gas prices over the last month, an effect that won't last. When the heat wave ends and gas prices settle back, the Henry Hub spot price could easily return to US$2.50 per MMBtu or below, which would render all but three of the twenty shale basins spread across the United States uneconomic.
(Click on image to enlarge)
The only basins that remain economic at US$2.50 per MMBtu gas are those that produce lots of natural-gas liquids (NGLs) as a byproduct. Natural gas is primarily methane, the smallest hydrocarbon, while NGLs are bigger hydrocarbons like propane, butane, pentane, hexane, and so on. These heavier hydrocarbons each carry a nice price, so by selling them off separately a gas producer can cover some of its production costs and effectively produce natural gas for less. Some wells in the Eagle Ford Shale basin produce so much NGL that the natural gas is effectively free.
Natural gas prices have been falling for some time now, but reserve writedowns are a lagging effect. One reason for the lag is that companies do not reassess their gas reserves every day – they do it quarterly or yearly. Another reason is that companies do not use the spot price in their reserve calculations. Instead they usually use long-term price estimates, which respond slowly to changes in the spot price.
Today, however, we have come to it. Companies are reassessing their reserves and, in the face of a spot price that was cut in half between July 2011 and July 2012, they are being forced to acknowledge that the long-term outlook for natural-gas pricing is not rosy.
Encana just acknowledged that fact, to the tune of $1.7 billion. It was not the first company to write down the value of its reserves and it certainly won't be the last, because natural gas prices are stuck between a rock and a hard place. For as long as prices remain stuck there, the sector will continue to take a beating.
The second question I said we would answer in this Dispatch is whether these massive reserve writedowns will hurt a sector that seems to be picking up speed.
Since hitting a ten-year low of just US$1.902 per MMBtu in April, the natural-gas spot price in North America has recovered to above US$3. At the same time, the enormous glut in America's natural gas stockpiles has shrunk. In March, US gas stocks were 54% above the five-year average. Today stockpiles sit at 3.2 trillion cubic feet (TCF), which is only 15% more than the five-year average. These two developments would seem to indicate the early days of a natural-gas sector recovery… but, like a mirage, all is not as it first seems.
Sure, the price of natural gas is up 50% in three months. Two forces worked together to make that happen. The first is that, when gas prices fell below US$3 per MMBtu at the beginning of the year, producers cut back on output. As I showed above, most producers simply cannot turn a profit at those prices. Rather than lose money on every cubic foot of gas produced from their fields, producers stopped putting new wells into production, saving their reserves until prices improve.
The second is that hot weather across the continent boosted power demand, and gas-fired power plants are built precisely for peak demand scenarios like this. As such, utilities have been burning through lots of gas.
It took several months for the combination of production cuts and increased demand to impact the supply glut, but now it has – as I mentioned, supplies are now back to just 15% above the five-year average. However, neither of these forces will last forever.
Natural-gas demand always fluctuates with the seasons. While industrial and business demand for electricity remains fairly consistent throughout the year, homes use a lot more power when temperatures become extreme. In the summer, people turn on air conditioners; in the winter, many homes require heat. As such, increases in natural-gas demand that stem from hot or cold weather are always short-lived.
Most observers are aware of this aspect of the natural-gas picture. However, anyone who is bullish on natural gas in North America has not realized that production cutbacks can be just as changeable as the weather.
Remember, natural-gas producers responded to falling prices by cutting back on output. In general, this meant that they continued to produce from operating wells but stopped putting new wells into production. To make an important distinction, this doesn't mean that they stopped drilling new wells – it just means they stopped putting them into production. The result: there are tens of thousands of wells across North America that have been drilled, fractured, and capped.
This army of shadow wells could be put into production within days. The companies that own these wells will do just that, if natural-gas prices climb enough to make their projects economic... and the resulting flood of production would quickly hammer prices back down again.
This is the reality of North America's mass of shale gas discoveries. Whether or not they are economic to tap at current prices, the fact is that North America's shale basins hold immense volumes of natural gas.
(Click on image to enlarge)
With almost 300 trillion cubic feet of natural gas sitting in wait, North-American gas prices will struggle for years to come. Every time prices start to climb, another company will grab the opportunity to complete some of its production-ready wells, and the added production will push prices back down again.
The only solution is to dramatically increase natural-gas demand. There are a few avenues available to accomplish this, such as transforming North America's transport trucks to run on natural gas and building liquefaction facilities to enable producers to export their product as LNG, but these initiatives will take years to materialize.
Until then, the shale-gas phenomenon will continue to weigh down gas prices – and gas companies – in North America.
I mentioned above that gas companies use long-term price estimates in their reserve calculations. Those forecasts cover a pretty broad range, as each company has its own idea of where natural-gas prices are heading. However, it's safe to say that most are still pretty darn high relative to today's prices – and more important, relative to the reality of North America's bloated gas supplies.
For example, I mentioned that BG Group wrote down its US gas assets by US$1.3 billion. That writedown came after BG cut its long-term US natural gas price estimate to US$4.25 per MMBtu from US$5. Whether US$4.25 per MMBtu is an accurate long-term price forecast only time will tell, but I would hazard that it is at the high end of prices for the coming years. Yet many companies are still using price estimates of US$5 per MMBtu or higher, which means there are lots of writedowns yet to come.
One of the biggest will come from BHP Billiton (N.BHP). In May the energy giant indicated that it was considering taking impairments on the value its US shale-gas assets. BHP acquired most of those assets just last year when it dropped $20 billion on US gas projects, spending US$4.75 billion to buy shale projects from Chesapeake Energy and acquiring Petrohawk Energy for US$15.1 billion.
How things can change in a year. In 2011 the Henry Hub natural-gas spot price averaged US$3.996 per MMBtu. So far in 2012, it has averaged US$2.42 per MMBtu. That pricing downshift has investors bracing for BHP to slash $5 to $10 billion off the book value of those gas assets soon.
BHP is not the only foreign energy major to invest in North-American shale gas assets that are shedding value. Norway's Statoil (STO), China's CNOOC (CEO), and Talisman Energy (N.TLM) have also invested significantly in shale assets over the last two years. None have yet taken impairment charges on these assets.
Of course, low natural-gas prices are also hurting company revenues directly. Lower profits at Exxon Mobil (N.XOM) and Royal Dutch Shell (N.RDS.A), for example, were driven by declining oil and gas prices. With Exxon, profits from its US gas wells tumbled 53% during the second quarter to US$678 million even as its domestic gas output increased 1.4% from a year earlier. Shell said its second-quarter earnings fell 13% to $5.7 billion and said a 52% drop in realized natural-gas prices was a major factor.
Exxon CEO Rex Tillerson remarked recently that energy companies were "all losing our shirts" thanks to low gas prices. The admission was a marked departure for the energy major, which has long maintained that its low production costs keep it immune to the effects of lower gas prices.
The thing is, low production costs don't help if natural-gas prices are even lower. The colossal natural-gas reservoirs that have been unlocked in recent years are pressing down on North-American gas prices with a weight that will take years to work off. With every little price gain, a ream of shadow wells stands ready to start churning out gas, adding enough supply to knock prices back down again.
Like a truckload of stolen Picasso paintings, North America's shale gas is incredibly valuable yet impossible to sell. A resource is only valuable if it can be extracted from the ground and sold at a premium to the cost of production. Most of the vast deposits of shale gas in North America do not meet that bar, and with trillions of cubic feet of supply weighing it down, the bar is not going to budge for some time.
The writedowns we are seeing today are just the beginning. As months pass and natural-gas prices remain depressed, one company after another will be forced to accept the reality of a long-term gas downturn. They will revise their price forecasts and take massive impairments on the values of their assets.
Investors will flee as company valuations drop. For companies with all their eggs in the shale-gas basket, the writedowns could well take the company down. Banks may reduce lines of credit extended to gas companies as the value of their collateral slides, further weakening a struggling sector.
It is a situation rife with pitfalls. However, there will also be compelling opportunities for those armed with patience and the right information (for example, there's one industry that operates in the sector that will do well regardless of natural gas prices). North America may be drowning in natural gas, but other countries are facing the opposite problem: a dire need to secure natural-gas supplies for their futures. With an eye to future LNG exports, gas-needy nations from Japan to the United Kingdom are on the hunt for cheap North-American gas reserves.
These takeovers will add some much-needed bounce to a sagging sector. As an investor, you'll only bounce if your money is in exactly the right place.
China Fuels Oil Production (Wall Street Journal)
China's state-owned oil companies are on the hunt for foreign reserves, and their bids for struggling energy companies worldwide are opening up production that might not otherwise happen. The recent bid of $15 billion from China National Offshore Oil Corporation (CNOOC) for Canadian oil-sands producer Nexen added to the more than $50 billion in overseas oil and gas deals completed by Chinese companies since 2009, and those are in addition to tens of billions of dollars in loan-for-oil programs in Venezuela, Brazil, Kazakhstan, and elsewhere. In many cases, China's oil companies have targeted struggling and underfunded operations, leading several analysts to conclude that projects are being developed that wouldn't be if China wasn't in the game.
OPEC Oil Output Drops as Sanctions Hit Iran (Globe and Mail)
OPEC oil output fell further from its four-year high in July as US and European sanctions cut supply from Iran to the lowest in more than two decades. Supply from the 12-member Organization of Petroleum Exporting Countries averaged 31.18 million barrels per day (bpd) in July, down from 31.63 million bpd in June. The 450,000-bpd decline erased most of the surplus in global supply and results from a decline in Iranian output to just 2.8 million bpd, compared to its pre-sanctions level of 4.4 million bpd.
BP Plans a Return to the Oil Patch (Globe and Mail)
Asian firms may be the ones currently spending billions in the oil sands, but the new head of BP has a message: don't count out the British. BP is on the hunt for more asset around Fort McMurray after shedding all of its Canadian operations in its massive asset selloff following the Deepwater Horizon disaster. The new head of Canadian operations for the British company believes "there is no greater giant field than the oil sands," and she is determined to grab part of that field for BP.
Turkey's Oil Diplomacy with Iraqi Kurds (Financial Times)
Six road tankers carrying oil to a coastal port wouldn't usually be newsworthy, but six Turkish tankers carrying crude from the Kurdish-controlled region of northern Iraq to a Turkish port – that is news. The trucks carried crude extracted by companies operating in northern Iraq in defiance of the central government. Turkish energy minister Taner Yildiz says his nation will encourage the cross-border trade. This trade flourished before the 2003 US invasion of Iraq and was allowed to continue until 2007, when Iraq's central government protested the activity as part of its conflict with the Kurdish Regional Government (KRG). The KRG has governed the northern region for twenty years, but Baghdad maintains that all of Iraq's mineral resources remain the property of the central government.