My colleague Byron King, who joined me in attendance at the ASPO – USA conference, wrote about Dave Hughes’ presentation on Canadian tar sands in ‘2006 Boston ASPO: The Canadian Tar Sands.’ For the purposes of this article, the conclusions of Mr. Hughes’ presentation on North American natural gas production are more relevant. Hughes, a senior official with the Geological Survey of Canada, has decades of experience on the front lines of a developing unconventional natural gas resource: coalbed methane in Alberta.
As Mr. Hughes stated at the beginning of his presentation, he reminds us that he is “speaking as a concerned geoscientist that happens to have spent more than 30 years studying energy in Canada and the world, as opposed to an official statement on behalf of the Canadian government.” It pays to listen to what Hughes has to say about the long-term prospects for unconventional natural gas production.
It’s estimated that unconventional gas production now comprises about 40% of total U.S. production. But it’s important to remember that this type of production requires far higher levels of drilling activity compared with conventional production. These statistics from the EIA are worth 1,000 words. Seeing these blue and yellow charts side by side communicates something rather significant about the size of new gas wells: They are getting smaller and more capital-intensive:
It appears that the blue chart, or drilling activity, must keep growing to offset the very rapid natural production decline rates we see in natural gas. (As a vapor, natural gas is far more “permeable” than oil, so the gas trapped in the source rock is able to flow to the well bore far faster than crude oil.)
Many are under the impression that Canada has limitless natural gas resources and will bail out the forecast U.S. shortage. Though Canada has an agreement under NAFTA to sell a fixed proportion of its gas to the U.S., this will not take priority over its own sovereign interest. The U.S. should not count on further growth in Canadian gas imports:
Drilling down to the detail on coalbed methane production, Hughes included a slide outlining the assumptions that Canada’s National Energy Board (NEB) is making in its future supply estimates. Here are the main points from the slide:
1. WCSB (Western Canadian Sedimentary Basin in Alberta) drilling rates will grow somewhat from the record levels of 2004.
2. Initial productivity of new wells will decline slightly from current levels. WCSB initial productivity has declined from an average 600 mcf/day in 1998 to 280 mcf/day in 2004. This trend may accelerate due to the increasingly larger proportion of 75-125 mcf/day coalbed methane wells.
3. Decline rates in new wells will remain at current levels. Average first-year decline rates have increased from 26% in 1990 to 39% in 2001 — this trend may continue in the future.
4. The overall decline rate of the WCSB has increased from 13% in 1992 to 20% in 2004 – this means 3.3 bcf/day of production must be replaced each year to keep production flat — production appears to have peaked in 2002 and been roughly flat since then. NEB (October 2005) expects production to increase by 2% through 2007, mainly because of coalbed methane.
The bottom line in all of this analysis is that the natural gas supply scenario looking out over the next few years is likely to be worse than CERA forecasts, and CERA is known for often being too optimistic. Dave Hughes summed up his expectation for natural gas production in the following e-mail reply (emphasis added):
“The U.S. lower 48 had its most recent peak in natural gas production in mid-2001. This is clearly evident in EIA production data — I’m not sure where CERA got the 1994 peak — there is no evidence of it in the data I’ve looked at.
“In terms of unconventional gas, although EIA classifies large volumes of gas ‘unconventional’ due to tax regimes, coalbed methane contributed about 8.5% to U.S. production in 2005, more than half of it from the San Juan Basin in Colorado and New Mexico, which has very unique geological characteristics that so far have not been replicated elsewhere.
“The U.S. should count on reduced exports from Canada. They will not remain flat, and they certainly won’t be increased.”
Exploration and production companies: profile of Chespeake
For guidance on the most likely trend of future natural gas prices, I find it useful to pay attention to the growth strategy of the world’s best-managed oil and gas exploration and production (E&P) companies. They put more than their reputations on the line. Many hold huge portions of their net worth in company stock. I’ve come across no E&P CEO that holds more in company stock than Chesapeake Energy’s Aubrey McClendon.
A Nov. 6 article in The Wall Street Journal discussed the rapid evolution of Chesapeake. How was Chesapeake able to expand natural gas production so rapidly in the U.S., where total production has been stagnant for years?
Chesapeake has been a very aggressive acquirer of both drilling leases and smaller E&P companies, and has chosen the right areas in which to invest capital. Half of the company’s growth over the past five years has been organic, or “through the drill bit,” with the other half coming from acquisitions. Chesapeake now accounts for about 3% of total U.S. natural gas production, with this share likely to grow by double digits over the next several years:
Notice that in 2001, Chesapeake’s base gas production was contracting at an 18% annual rate, but has been improved to 9%. The blue area of this chart is what the revenue trend of a North American gas-focused E&P company would look like if it decided to enter “harvest mode” and not reinvest its profits into drilling and acquisitions.
CEO McClendon has spearheaded the company’s effort to shift its portfolio of reserves toward unconventional gas basins. But this aggressiveness is tempered with savvy use of natural gas futures contracts. Chesapeake’s balance sheet is basically a concentrated “long” position in natural gas, so by periodically selling short natural gas futures, the company can lock in current spot prices for gas that may not be produced until a year or so into the future. The WSJ article explains, with my comments interspersed (emphasis added):
“Recently, Chesapeake locked in agreements amid relatively high prices. Through the first nine months of 2006, Chesapeake sold $2.53 billion of gas and also made $833 million from gas hedging operations, according to company financial reports. Until recently, it had contracts covering 80% of next year’s planned gas production, far more than any comparably sized energy company.
“When prices dipped last month, Chesapeake took advantage. It unwound commitments to sell its own gas in the future by snapping up other expected gas production at relatively low prices. Chesapeake will pocket the difference. The move lowered Chesapeake’s coverage to 59% but in the process generated a $540 million profit. Now that prices have risen again, Chesapeake could buy a new set of hedges to cover its own production, but says it hasn’t yet made a decision.
“Since bottoming out in early 1999, Chesapeake has used its hedge strategy to become one of the largest U.S. natural gas producers. Back then, the company produced about 369 million cubic feet of gas a day — enough to supply homes in metropolitan Philadelphia — and generated a $33.3 million profit the entire year. Today, Chesapeake produces 1.6 billion cubic feet of gas daily, about enough to keep heated New York, Chicago, and Seattle, as well as their suburbs. Through the first three quarters of the year, it made a profit of $1.53 billion. The company’s stock has also risen fast, along with those of other energy companies, and in the past five years has more than quadrupled.”
So management’s decision to actively employ price hedging has allowed it to embark on aggressive acquisition and drilling plans without taking on too much risk. The primary risk of any E&P company is exposing itself to the incredible short-term volatility of natural gas prices. Think of it as a hedge fund that truly hedges its position, rather than engaging in leveraged speculation, like Amaranth Advisors, the fund that blew up in September. It’s crucial to understand the difference between the two strategies. Chesapeake stock represents a fairly low-risk way to “go long” on future natural gas prices without the stomach-churning volatility of futures trading:
“Mr. McClendon says Chesapeake’s hedging means it has relatively predictable profits, which in turn allow it to pursue acquisitions and maintain drilling programs regardless of market movements.
“Chesapeake has more rigs drilling new wells than any other company in North America. It has made more than 50 deals in the past four years, spending more than $10 billion to gobble up smaller gas producers. Last month, Chesapeake agreed to acquire closely held Dale Resources for about $200 million, its ninth deal of the year.
“Chesapeake started life as a typical energy company, subject to market whims. Soon after a dismal 1993 initial public offering of stock, Chesapeake shares started soaring. Mr. McClendon wowed investors by talking about the potential for using new drilling techniques to unlock previously untouchable gassy rocks. ”
So unconventional gas was considered a great growth market nearly 15 years ago. It’s not something that was on the drawing board only a couple of years ago, so the engineering and economics of unconventional gas production are already well defined. The conditions necessary to continue expanding this type of gas production are high long-term gas prices, the availability of plenty of drilling rigs, and reasonably priced fracturing technology. The first of these conditions, high prices, was not in place for most of the 1990s:
“In late 1994, Occidental Petroleum announced it had made a gas discovery in central Louisiana. Chesapeake raced in, offering cash and royalty payments to landowners in exchange for drilling leases. Chesapeake ultimately spent $179 million to lease more than 1 million acres in central and southeastern Louisiana…
“By early 1997, a few Wall Street analysts were raising questions about the Louisiana investment. At the time, Art Smith, chief executive of energy consultant John S. Herold Inc., noted that Chesapeake’s estimates for how much gas would be found in Louisiana ‘seem quite aggressive.’
“Getting gas out of the Louisiana wells turned out to be difficult. A few performed, but most were abysmal. In four months of 1997, the company drilled 10 wells at a total cost of $43 million. The wells found 500 million cubic feet of gas, worth about $1.1 million at prevailing prices.
“Chesapeake’s stock plunged. By July 1998, its board of directors put the company up for sale, yet no one made a serious offer. Global energy prices were slumping. Chesapeake’s stock dropped to 75 cents in 1999, from a high of $34.13 three years earlier — an extraordinary slide for a company with proven assets.”
Chesapeake had a near-death experience in 1999 after becoming too aggressive investing for a high-price gas environment that had not yet arrived. As gas prices rebounded sharply over the next few years, the stock recovered and the company implemented its “land grab” strategy very early on.
Now Chesapeake has about a 10-year drilling inventory on acreage that as it is drilled over time has the potential to triple the company’s current proved reserves. No other large independent E&P company will come close to the kind of organic growth that Chesapeake will deliver over the next 10 years. In a stagnant North American natural gas supply environment, this will lead the stock market to assign CHK stock an industry-leading earnings multiple.
Factors affecting Exploration and Development costs
However, there is one scenario that could keep a lid on the returns Chesapeake provides to its shareholders. Right now, finding and development costs are only in the range of $2-3 per thousand cubic feet in most unconventional gas basins. Many will look at this figure and conclude that the free market will direct a surge of capital investment into new gas production, considering that the profits and incentives are so high with spot gas prices in the $6-8 range.
But we must remember that finding and development costs are dynamic, and certainly trend higher over time as 1) more fiat dollars circulate through the economy, and 2) the more expensive, hard-to-find oil and gas becomes a larger share of total production.
The single greatest variable in finding and development costs is the average “dayrate” charged by available rigs. Right now, the rig fleet is working at close to full capacity, so drillers have considerable power to negotiate higher prices and earn higher profits. Dayrates have already surged dramatically, yet there is potential for them to increase even further and remain in the current range longer than the market currently anticipates.
Won’t the free market prompt entrepreneurs to greatly expand the rig fleet to benefit from high dayrates? Certainly, but there are serious bottlenecks in the supply line, so it will proceed at a slow pace. The order backlog for highly engineered rig equipment has surged over the past few years, accelerating in recent quarters — even through the third quarter, as energy prices fell sharply.
Newly built rigs may be coming online at the fastest pace in years, but hundreds of rigs are in need of refurbishment, earning poor dayrates in the simplest drilling jobs. Expect to see a divergence in the performance of the contract drilling companies. Those companies that had the foresight to position their fleet for difficult, expensive drilling jobs will outperform. As Dave Hughes’ slides show, the North American rig count must continue to grow in order to feed more drilling-intense unconventional natural gas extraction.
In the December issue of Strategic Investment, I wrote about a company with a dominant position in the business of supplying and refurbishing the global drilling rig fleet. This company has great earnings visibility, tremendous operating leverage, and is on the right side of a multiyear investment trend that will work directly in its favor.
E&P Companies Must Choose: Grow or Contract
Continued tightness in the rig market will weigh increasingly on E&P companies like Chesapeake. Most have been earning super-normal profit margins over the past couple of years. The economics of drilling aggressively remain compelling, so most E&P companies that have the option of renewing their rig contracts have done so in recent months. Rig counts remains right near this summer’s highs.
Over the long run, it seems that North American gas-focused E&P company executives will face a choice between two general scenarios:
1. Choose to pass on expensive rig leases that will maintain profit margins, but suffer a gradual contraction in production volumes as the production at existing properties depletes, or
2. Pay up for expensive rig leases, take a temporary hit to profit margins, but position the company to grow production volumes in a long-lasting, highly profitable gas price environment.
The decision that results in the greatest returns for shareholders will be determined by the next decade’s average natural gas price. If gas prices trend gradually higher, which I think is the most likely outcome, the additional profits from expanding production will more than offset higher rig lease costs. If prices trend lower, companies that are less aggressive on acquiring rig leases will maintain higher profit margins and likely return more cash to shareholders.
But here’s the kicker for Chesapeake: The company built up a wholly owned drilling and oil field services subsidiary near the bottom of the investment cycle. McClendon and his team have a very impressive track record of timely decisions, and they spent the past year reshuffling and expanding the size and capabilities of their land rig fleet. After being tossed about by the whims of the spot natural gas market of the late 1990s, the company has emerged stronger than ever and now practically controls its own destiny in a market in which the long-term fundamentals have shifted decidedly in its favor.
I’ll take the analysis of Mr. Hughes and the corporate strategy of Mr. McClendon over CERA’s long-term hydrocarbon supply estimates any day of the week. In your investments, remember to focus on what is, rather than what can be in a perfect world. Human beings are prone to being driven by fear and greed.
There is nothing quite like the fear that spreads when a perceived shortage of natural resources gets worse. Otherwise rational economic analysis takes a back seat to the motivation to hoard. This is what the supply environment will be like on the backside of Hubbert’s Peak, whether it occurs next year or 20 years from now.
By Dan Amoss, CFA for Whiskey and Gunpowder
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