The European financial turmoil is roiling global debt, equity and currency markets. These markets in turn are impacting commodity markets and creating significant near-term volatility. There doesn't appear to be much direction evident in commodity markets other than their reaction to global events. Weekly changes in crude oil inventories and natural gas injection volumes keep prices bouncing around. West Texas Intermediate crude oil seems to be bouncing between $80 and $90 per barrel, although a leading oil trader says the price action has established a pattern of lower highs and lower lows leading him to sell crude oil futures every time they rise and buy them when they fall until that trade doesn't work.
The picture for natural gas prices appears less clear. A larger than expected injection of natural gas into storage was reported the week before last while a smaller than anticipated injection last week has kept prices unsettled. Natural gas in storage remains below year-ago levels and about in the middle of the five-year range. The weekly volatility reflects changes in weather and perceptions of industrial demand trends. Increased concerns about future economic growth, as highlighted by the International Monetary Fund's reduced forecasts for U.S. and global economic growth in 2011 and 2012. These reduced economic growth estimates suggest the key to any recovery in natural gas prices in the near term will depend on falling supply growth rather than a demand increase.
We are approaching the end of the third quarter when E&P company managements will report their operational and financial results to the outside world and the start of the budgeting season when companies set their spending plans and operational expectations for 2012. Wall Street has begun to try to get a fix on the view of management toward the key issues that will drive capital spending next year. These issues relate to the outlook for commodity prices and production growth, and importantly their operating costs and capital spending requirements. As managements sort through these issues, some may be questioning their ability to continue playing the game as they have for the past few years.
If you remember, U.S. E&P companies have been obsessed with capturing as much land as possible in the gas shale plays. With this land grab came drilling and production obligations that are driving capital spending. For many companies, the ability to finance this game in the face of weak gas prices and rising drilling and completion costs outran cash flow generation forcing them to hedge future gas production, enter joint ventures and tap capital markets. Hedging often forced companies to be aggressive whenever futures prices rose. According to traders we have talked with, this phenomenon continues. The greater challenge comes from companies' ability to find new joint venture partners and tap capital markets. Until this summer it appeared investors had an insatiable appetite to fund companies involved in shale plays. The love affair may be changing, and with it may come pressure to cut spending.
Encana, a Canadian-based E&P company, has indicated it plans to cut back its spending directed toward dry natural gas development and that it will sell assets such as its production and acreage in the Barnett Shale in order to fund its future spending needs. With the prospect of lower crude oil prices, and in turn natural gas liquids prices, even those E&P companies that pivoted toward liquids-rich shale plays and away from dry gas plays as gas prices remained weak are facing a possible squeeze on their cash flows. Rising drilling and completion costs are further straining budget projections. If a management has been properly focusing its drilling efforts for the past few years on the sweet spots in its shale acreage, the risk of losing acreage because of failure to drill leases shouldn't carry as much of a penalty now as it might have in the past.
A report from broker Bernstein Research focused on the costs, capital spending and financing condition for a large group of E&P companies. We have borrowed several of their charts, not as a comment on individual companies but rather to point out the challenges this industry faces and their possible implications. Costs for E&P companies are starting to rise, which signals a profit margin squeeze. While some managers might say that their DD&A expense is less meaningful because it is not a cash expense, we believe that if one only focuses on the production cost segment of this chart he will see a relatively steady upward trend commencing in 1Q2009. The climb in this cost component in the past three quarters has been at a much sharper rate, which is a concern.
There is a difference in the cash costs of large versus small E&P companies, not a surprising trend, but the important thing to observe is the increase in the trend over the past few quarters for both groups. Larger E&P companies are better positioned to push back on the oilfield service industry's price increases, and we fully expect that to occur.
With rising operating costs E&Ps are faced with having to cut back their spending somewhere unless they believe they can fund higher spending through tapping capital markets or finding new partners. Based on the data Bernstein analyzed, the large E&Ps have done a better job of controlling their capital spending versus their operating cash flows. Smaller companies have been less disciplined, but that probably reflects optimistic managements grasping for the brass ring of rapid asset and production growth. In certain environments, a strategy of relying on Wall Street to fund spending, while risky, may prove to be the ticket to building a small company into a large one. On the other hand, a risky expansion strategy can lead to a corporate disaster. We believe that if capital discipline isn't returned to this industry, there will be disasters, the important question is how many?
When Bernstein did its analysis of second quarter 2011 company capital spending versus cash flow, it found only 10 of 43 companies or 23%, had adhered to conservative principles. Last spring those companies might have been faulted by Wall Street for being too risk-adverse, but given the current economic and financial environment they are probably being touted as heroes. If financial conditions deteriorate further, they may be singled out as survivors.
While it is not evident yet that Wall Street is abandoning the E&P industry, as demonstrated by the annualized pace of capital-raising activity this year, the prospect of stagnant gas prices and squeezed profit margins is not conducive for an industry to be welcomed with open arms by investors. Companies that have demonstrated capital discipline are financially strong with less need to tap Wall Street and are positioned to capitalize on any turmoil in the E&P industry.
A recent presentation by the director of research of BENTEK Energy predicted that with a normal winter, his firm expects we will end this winter with a continued imbalance in natural gas supply and demand of 0.7 billion cubic feet per day (Bcf/d). Since it expects close to the same volume of gas to be in storage as last winter, BENTEK believes current futures prices for the first months of the upcoming winter season are lower than what will be generated in the spot market by supply and demand trends, but they also believe that futures prices are too high for the ending winter months. The volume of gas shale production growth continues to confound market analysts seeking a stop to production growth.
An interesting point about the future gas market came in response to a question during the BENTEK presentation about the impact of hurricanes on Gulf of Mexico production and the growing importance of gas shales on supply. BENTEK has concluded that the impact of the 2005 hurricanes (Katrina and Rita) pushed Henry Hub natural gas prices up by $4-$6 per thousand cubic feet (Mcf) to $13. Today, BENTEK estimates a similar hurricane event would only move gas prices up by $1-$1.50/Mcf. This dramatic difference is due to the fact that since 2005 Gulf of Mexico production has fallen by 42% while onshore production has climbed by 38%. This development may signal that in the future, while Gulf of Mexico hurricanes will continue to be news and human safety events, they will have less of an impact on commodity prices. This is another unintended benefit from the gas shale revolution.
While investors are awaiting E&P company executive pronouncements about flattening or reductions in 2012 capital spending, analysts are focused on trends in the drilling business as an indicator of when production growth may slow and even begin falling.
The U.S. drilling rig count was in a steady uptrend from the early 2000s until the start of the financial crisis and resulting recession. Crude oil prices bottomed in early 2009 and began recovering. The pace of recovery was sharply faster than the pre-crisis rig count growth rate. That growth seemed to slow at the end of 2009, and even flattened in the last half of 2010, but then accelerated in 2011. That acceleration was largely driven by the shift to crude oil and liquids-rich shale plays as crude oil prices soared in response to the civil unrest in the Middle East and North Africa.
The shift between drilling for natural gas and crude oil is best shown by the chart below. It shows how non-Gulf of Mexico gas-oriented drilling actually declined in late 2010 and early 2011. The shift hasn't helped the gas supply picture because there are significant volumes of associated gas produced in liquids-rich plays and even with crude oil wells.
In our attempts to forecast how natural gas supply might grow, we have used the mix in the rig count (gas- and oil-oriented) to apply to the count of rigs drilling horizontal, directional and vertical wells. Presumably rigs targeting natural gas should be more productive than those targeting liquids-rich plays. The chart in Exhibit 12 shows non-Gulf of Mexico rigs drilling for natural gas by category of rig type. What the chart shows is that since the end of 2004 there has been a steady narrowing of the count of non-vertical gas rigs and horizontal gas rigs. In and of itself, this is not a revolutionary point, but it can help explain gas production trend changes based on shifts in drilling rigs.
If we look at what has happened to these two rig counts under this methodology since the beginning of 2011 we find an interesting pattern. Until recently, the peak in both rig counts was in late February. Since then, the two counts declined until mid August for horizontal rigs and the week before last for non-vertical rigs. For the last five weeks (through 9/16/11) horizontal gas-oriented rigs were at
or above their February peak, despite the shift toward more liquids plays. Only in the very last week did the number of rigs drilling non-vertical gas wells go above their late February peak. Given this rig count performance, one would conclude that gas production will continue to grow. It is possible that the production growth rate may slow as older shale well productivity falls, but that is not assured. Also, gas supply will be impacted by the completion of previously drilled-but-uncompleted wells, which appears to be happening as the service industry adds hydraulic fracturing horsepower to their fleets. We also hear that the number of fracture stages in newly drilled wells is not increasing, or at least at their historical pace.
This fall may be a tougher time for the energy business than anyone anticipated merely 30-60 days ago. The economic growth outlook remains cloudy. The unity of the European Economic Community and the solvency of certain members remain unclear. The political struggle in the U.S. will be ramping up creating greater uncertainty about future economic and tax policies. Unsettled capital markets will increasingly become risk adverse and thus less willing to provide funds to companies with less than rock-solid outlooks. Producers of commodities will fall into the risky category, although commodities themselves may retain some of their safe-haven qualities, albeit at lower prices. That safety support should hold oil and gas prices sufficiently high that instead of a 2008-2009 energy market, it may look more like the May–September 2002 period when the rig count was essentially unchanged but the Philadelphia Oil Service Stock Index (OSX) fell by about 35%. Living through that period was trying, but that environment offered many attractively-priced energy stocks, assuming one had a long-term horizon.
G. Allen Brooks works as the Managing Director at Parks Paton Hoepfl & Brown. Reprinted with permission of PPH & B.
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