In early June, US natural gas prices surged to a new 2011 high, up about 20 percent from their nadir in March. Natural gas prices have rallied significantly since mid-May–a stark contrast to the sharp decline in key US and international crude oil benchmarks.
But over the past two and a half years crude oil prices have consistently outperformed natural gas. In fact, the ratio of West Texas Intermediate (WTI) crude oil prices to the price of natural gas hit a record high in March, when the price of a barrel of oil was more than 25 times the cost of one million British thermal units (MMBTU) of natural gas. That’s more than double the 10-year average ratio of less than 10-to-1.
The recent uptick in US natural gas prices has prompted some commentators to speculate that the commodity had finally turned the corner, a move that would begin to normalize the relationship between oil and natural gas prices.
Although the long-term outlook for natural gas demand is strong, this recent move doesn’t mark the beginning of a durable recovery in US gas prices. I expect the amount of nonatural gas in storage to remain elevated for much of 2011, which should ensure that prices sink to $4 per MMBTU this fall. Investors should focus on names with exposure to oil production and companies that sell equipment and services to natural gas producers.
Investors must distinguish between the North American gas market and the global market for liquefied natural gas (LNG). Although I’m bearish on the near-term prospects for North American natural gas prices, international LNG markets remain one of my top investing themes in The Energy Strategist.
Bearish on North American Natural Gas Prices
Check out this graph of the 12-month strip for natural gas futures that trades on the New York Mercantile Exchange (NYMEX).
An average of the next 12 months’ worth of natural gas futures contracts, the 12-month strip better represents the long-term pricing environment for natural gas than the spot price or the price of the near-month futures contract.
Demand for natural gas hinges on seasonal factors. For example, natural gas prices tend to pick up during the winter, when demand for heating reduces the amount of gas in storage. Hurricane-related shut-ins and damage in the Gulf of Mexico also can cause a short-lived uptick in natural gas prices. The 12-month strip smoothes out these distortions.
US natural gas prices collapsed in late 2008 and early 2009, stung by the financial crisis and Great Recession. But unlike oil and other commodities, natural gas prices have rebounded only slightly from its 2009 low. The 12-month strip has spiked in both directions but has generally traded between $4 per MMBTU and $6 per MMBTU. The recent rally in gas prices is within this trading range.
This uptick in gas prices doesn’t reflect a durable change in fundamentals; rather, hot summer weather has prompted households and businesses across the US to fire up their air conditioners.
Cooling degree days (CDD) are calculated by taking the mean temperature on a given day and subtracting 65 degrees Fahrenheit. For example, if the mean temperature on a given day was 90 degrees Fahrenheit, the CDD would be 25 degrees.
This graph depicts total cumulative CDDs for 2011 relative to the 10-year maximum, the 10-year minimum and the 10-year average. On this basis, 2011 has been the hottest year since 2002. Also note that cumulative CDDs have picked up sharply since late may, thanks to record-setting temperatures in cities such as New York and Washington, DC.
Hot weather prompts households and businesses to run their air-conditioners for longer periods, increasing demand for electricity. In turn, power companies burn more natural gas to keep up with electricity demand.
The National Oceanographic and Atmospheric Association’s (NOAA) summer forecast calls for higher-than-average temperatures for much of southern third of the US; natural gas demand could remain elevated over the next few months.
Nevertheless, this uptick in demand won’t overcome the main challenge facing natural gas prices: excess supply. A surge in natural gas production from unconventional fields such as the Haynesville and Marcellus shale have overwhelmed US demand for the commodity and elevated storage levels. Check out the graph below.
Source: Energy Information Administration
The boldfaced purple line tracks the amount of stored natural gas on a weekly basis. For comparison, the graph also includes historical high and low storage levels, as well as the five-year average.
The natural gas storage cycle is highly seasonal. Demand for gas tends to increase from November to March–the coldest months of the year–reducing storage levels. The amount of natural gas in storage picks up during injection season, which lasts from late March to November. During the summer’s hottest months, the amount of gas in storage sometimes builds at a slower rate because of heavy air-conditioner use. However, significant inventory drawdowns are unusual during the summer.
US gas in storage has remained elevated thus far in 2011, save for a brief period toward the end of the winter heating season. In fact, gas injection season started earlier than usual this year.
Over the past 10 weeks, the US added about 575 billion cubic feet (bcf) of natural gas to its storage facilities–less than the five-year average of about 650 bcf. But consider the case of 2002, the hottest summer of the past decade. In that year, the US injected only 540 bcf into storage over the same 10-week period; adjusted for weather conditions, US gas in storage is building at a pace that’s slightly above average. Remember, in 2002 US shale gas production was negligible, whereas in 2011 output from unconventional fields is booming.
Despite depressed natural gas prices, US producers continue to ramp up output. Check out this graph tracking the US gas-directed rig count, a measure of the total number of drilling rigs targeting natural gas in the US.
During the financial crisis and Great Recession, the gas-directed rig count plummeted from around 1,600 rigs at its 2008 apogee to a low of slightly less than 700. Producers cut back drilling in response to plummeting gas prices.
Although natural gas prices have remained depressed, the number of rigs drilling for natural gas has soared, topping out at almost 1,000 in 2010. This apparent loss of discipline stems from several factors. During the 2007-08 land rush, producers leased acreage under contracts requiring them to drill commercially viable wells within a certain period. To avoid forfeiting their leasehold, producers were forced to drill aggressively despite the weak pricing environment.
Many shale fields also produce natural gas liquids (NGL) such as propane, butane and ethane. These hydrocarbons tend to command higher prices, improving economics in NGL-rich fields such as the Eagle Ford shale in south Texas. Many producers have shifted their capital spending to emphasize NGL-rich plays; the associated natural gas effectively has become an afterthought for many operators. Meanwhile, the glut of natural gas continues to grow.
The number of rigs drilling for natural gas has declined to slightly less than 900 over the past 12 months–a less than 10 percent decline. This pullback hasn’t curtailed natural gas production in the Lower 48, which hit a record high 68 bcf per day in March.
And the US gas-directed rig count doesn’t fully capture the extent to which output could expand.
This graph tracks the number of active US rigs that can sink horizontal wells, a drilling technique that’s essential to unlocking the oil, NGLs and natural gas trapped in the nation’s shale plays.
Although this proxy for unconventional drilling activity also tumbled in late 2008 and early 2009, more than 1,000 rigs capable of sinking horizontal wells now operate in the US–that’s more than triple the levels of two years ago.
The overall natural gas directed rig count may be in decline, but a higher percentage of these drilling crews are installing horizontal wells in the Haynesville Shale and other unconventional plays. As these horizontal wells typically produce higher quantities of gas over a much shorter period of time, natural gas output has increased despite the lower rig count.
In addition, the Bakken Shale and parts of the Eagle Ford contain primarily oil, but these fields also contain significant quantities of natural gas. Some rigs that technically target oil may also produce associated natural gas.
Against this backdrop, natural gas prices should remain within their current trading range. Hot weather could push natural gas prices higher in the near term, while the inevitable scare about a hurricane damaging critical infrastructure along the Gulf Coast could also cause prices to spike in August and September. None of these short-term events would reverse the bearish fundamentals weighing on natural gas prices.
Subscribers often ask about potential upside catalysts for US natural gas prices, including plans to export LNG, regulations that would impose limits on hydraulic fracturing, and proposed legislation that would promote the use of natural gas as a transportation fuel.
On May 20, 2011, the US Dept of Energy granted Cheniere Energy (AMEX: LNG) permission to export as much as 2.2 bcf of LNG per year, a super-cooled form of natural gas that can be easily transported via specialized tankers to any country with import (regasification) terminals.
Although the Kenai LNG port in Alaska is the nation’s sole export terminal, the US is home to several import facilities. Built before the shale gas revolution transformed the US market, these liquefaction terminals operate at a fraction of their capacity because the country no longer needs to import LNG.
Cheniere Energy’s stock popped after the Dept of Energy approved the company’s export application, rallying almost 50 percent in only a few days. This news does not affect my outlook for US LNG exports or US natural gas prices.
The company may have some of the regulatory approvals in hand–the Federal Energy Regulatory Commission has yet to approve the site plan officially–but adding liquefaction capacity to the company’s Sabine Pass import terminal will require substantial investments of time and capital. With a projected cost of at least $6 billion, such an endeavor could prove out of reach for Cheniere Energy, a firm with a market capitalization of less than $600 million and almost $3 billion of debt on its balance sheet.
The company may be able to borrow the money if management secures oil-indexed contracts to supply LNG to utilities in Japan, China, South Korea and Taiwan–markets that historically have offered the best pricing environment.
Given the distance involved and the liquefaction fees Cheniere Energy plans to charge, these contracts are by no means a sure thing. Even if the company manages to secure funding, the liquefaction facility will take five years to build. In other words, a bidirectional Sabine Pass won’t affect the US natural gas market until mid-decade.
Readers often ask about legislative proposals that would encourage the use of natural gas as a transportation fuel. According to this plan, commercial trucking firms would receive a subsidy to convert their existing fleets to run on natural gas or buy new trucks.
Such a proposal makes sense: Natural gas burns cleaner that gasoline and diesel, costs less and is readily available. President Obama, key Congressional Republicans and business T. Boone Pickens have endorsed efforts to encourage the use of natural gas in the transportation sector. Thus far, Congress has failed to pass such a bill. With a major election cycle looming in 2012 and an ongoing battle over the federal debt, a comprehensive energy package won’t be proposed anytime soon.
Readers also ask whether regulators might placed restrictions on hydraulic fracturing, a technology that’s critical to extracting oil and natural gas from unconventional fields. New York and other states have imposed limits on hydraulic fracturing, but none of the states are important natural gas producers. Adverse regulation is less of a risk in Texas, Louisiana and other states in which the energy industry has a long history of creating jobs.
Investors shouldn’t expect federal regulators to crack down on hydraulic fracturing–such a move would be political suicide, particularly with a major election on the horizon. The Obama administration quickly backed away from tighter regulations of drilling activity in the US Gulf of Mexico for the same reason.
For a detailed look at recent state and federal discussions about hydraulic fracturing, check out this outstanding piece my friend and MLP Profits co-editor Roger Conrad penned for Investing Daily.
Although the outlook for North American natural gas prices remains grim, investors have plenty of opportunities to profit from the shale gas revolution.
For one, the US needs to build out the pipeline, processing and storage capacity needed to support booming unconventional oil, gas and NGL production. Companies that own and operate these midstream assets enjoy reliable cash flow that doesn’t depend on natural gas prices.
And most of our favorite midstream energy companies are organized as high-yield, tax-advantaged master limited partnerships (MLP). The average MLP yields 6 percent, though some of our favorites yield almost 10 percent. Our top picks are growing their quarterly payouts at the fastest pace in years. For details about our favorite MLPs, sign up for a free trial subscription of MLP Profits.
Bullish on International LNG
Despite the weakness in US natural gas prices, rising demand continues to drive natural gas prices in international markets. Check out this graph of the 12-month strip for natural gas futures that trade on the Intercontinental Exchange (ICE).
As you can see, ICE-traded natural gas goes for almost two times the price US natural gas fetches on the NYMEX.
And many countries in Continental Europe buy much of their natural gas from Russia at prices that are indexed to Brent crude oil. With Brent trading well above USD110 per barrel right now, oil-indexed gas costs are even higher than the price of gas on the ICE exchange.
As I explained in the June 1, 2011 issue of The Energy Strategist, Less Uncertainty for Nuclear Power, the spike in European electricity and gas prices over the past few months stems from Germany’s decision to close eight of its nuclear power plants. Germany’s wind and solar power capacity won’t be able to make up for the lost baseload power, forcing the country to increase its reliance on imported electricity. (See my free blog post, Alternative Energy is no Alternative.) This will further strain European electricity grids, raising the likelihood of power outages. With this summer shaping up to be a scorcher, such an outage could prove deadly to the elderly and other at-risk populations.
At any rate, natural gas-fired plants represent Germany’s only realistic intermediate-term option to offset lost nuclear power capacity. For details on my favorite plays on rising LNG demand in Europe and Asia, register for a free trial of The Energy Strategist.
Investors interested in my quick takes on various economic and market-related trends can follow me on Twitter. I usually send out a tweet when I’m scheduled to appear on various radio or television shows and when I post commentary free commentrary on Investing Daily, Cocktail Stocks or other websites.
City by the Bay
Elliott Gue is thrilled to be returning to San Francisco this year and invites you to join him at The MoneyShow, August 10-12, 2011, at the San Francisco Marriott Marquis Hotel. Be there as recommendations and advice are revealed for how to best position your portfolio for profit–in 2011 and beyond. As this new era of investing unfolds, smart investors know it’s imperative to stay informed and educated. The MoneyShow is your one-stop resource for the most comprehensive education, efficient research, and valuable advice. Don’t miss out…register FREE today and be sure to mention Priority code 022447!