Is It Possible to Have Sub $4/Mcf Gas for Five Years?
by G. Allen Brooks, Managing Director
Parks Paton Hoepfl & Brown
Rigzone
Tuesday, August 04, 2009
Two weeks ago we attended a presentation at the Petroleum Club where Jim Simpson of BENTEK Energy, LLC, a natural gas oriented analytics firm, presented his case for sub $4 per thousand cubic feet (Mcf) natural gas prices through 2010. His audience at the Houston Producers Forum consisted of 160 energy and financial executives. Following his presentation and in response to the first question from the audience, he dismissed the likelihood this distressed price scenario would last for 10 years as low gas prices did throughout the 1990s, but he did say it was possible the low price could last five years.
If that answer wasn't depressing enough, he responded to the second question about the impact of Exxon's Horn River gas discoveries in Canada on the U.S. market by saying he could not rule out the possibility of sub $3/Mcf natural gas prices for a period of time. Following the second question no one in the audience ventured another - possibly out of fear that they would be bidding down the estimate of future gas prices. Stop while you're ahead seemed to be the mantra. As the moderator thanked the presenter, the shell-shocked audience began to drift out of the dining room. The only missing ingredient among the darkness of the room and the dark mood of the audience was a funeral dirge playing in the background.
Is it possible that natural gas prices might never recover to their lofty levels of earlier this year (five years is virtually a lifetime for most investors)? On the other hand, one can rightly ask: What does Mr. Simpson know? His is only a forecast and we know the spotty record of energy price forecasters. He did, however, bring some telling data and insights that must be considered, but in the end a forecast is a forecast and it depends on critical assumptions, one being that current market conditions and company actions continue as they have in the past, assumptions that become suspect when dealing with energy markets.
In light of the surge in unconventional natural gas production and weak demand fundamentals, natural gas prices have been depressed throughout 2009 despite crude oil prices rallying back to almost half of their historic high of last July. Mr. Simpson's analysis examined changes in natural gas supply and demand and how successful development of the new unconventional gas-shale resources has created a significant oversupply that is depressing current gas prices. Part of the problem plaguing natural gas as Mr. Simpson pointed out is geography - the location of new gas supplies and gas consuming markets given transportation capacity limitations for moving the growing supply volumes.
Mr. Simpson explained the problem with a chart showing the total capacity of all pipelines out of the Southeast/Gulf Coast region that has been fixed at 23 Bcf/d for a number of years. He then showed how net pipeline outflows have grown over time trimming the unutilized capacity each winter season. The production flows were defined as regional production plus inbound flows from other basins plus storage withdrawals and LNG imports minus intraregional gas demand and storage injections. From the winter of 2005-6 to last winter, the nominal surplus pipeline capacity has shrunk from 7.5 Bcf/d to 3.5 Bcf/d, or by more than half. As gas shale production in this region and/or LNG shipments continues to increase, we can expect a further shrinking of available pipeline capacity putting the brakes on supply growth. Will those brakes limit western gas inflows to the region, LNG shipments or gas-shale production growth?
In a nutshell, Mr. Simpson's analysis is that falling natural gas demand coupled with rising gas supplies have placed gas producers in a box. The box is caused by a lack of adequate long-haul pipeline capacity in the geographic region spanning from East Texas to the Texas Gulf Coast and across Louisiana to Mississippi (an area referred to as an "I"). This capacity constraint restricts more costly gas supplies located west of the pipelines' terminus points because the market is adequately served by cheaper gas volumes. Not only are more expensive western gas supplies fighting cheaper shale-gas production for access to the long-haul pipelines and the consumer markets in the Northeast, Midwest and Southeast regions of the country, but they also are competing with Gulf of Mexico gas and liquefied natural gas (LNG) supplies arriving from overseas markets.
Compounding the gas producers' problem is that current natural gas prices are below finding and development costs for many of the traditional western gas basins, making it difficult for them to compete for markets. Gas-shale basins have evolved into real estate and engineering plays in contrast to exploration plays. The ubiquitous nature of natural gas shales in this country has reduced the need for exploration; witness the collapse of the open-hole wireline logging market in the United States. The key for gas-shale profitability is to assemble as much prime acreage (that which possesses the thickest gas seams that can be easily exploited) and figure out how to drill, complete and produce the wells at the lowest cost.
Another advantage for many of the gas shales is that they are located either within the pipeline "I" or immediately adjacent. This gives them a location advantage and reduces the transportation cost. In addition, some of newly developing gas-shale plays are situated east of the pipeline terminus points allowing them access as the lines move north or east. At the root of the supply problem, however, is that the gas-shale wells are proving to be highly prolific resulting in low gas costs, even below currently weak gas prices, which further encourages their development. The growth of unconventional gas supplies is slowly displacing conventional natural gas production in this country.
Producers of unconventional gas supplies have been successful in reducing meaningfully their finding and development cost in recent months. Some of the cost savings have come from the oversupply of oilfield equipment and services that has contributed to lower service company prices, while continued technological improvements in accessing and extracting the gas from these challenging formations have also contributed.
We have used several of the slides from Mr. Simpson's presentation to further explain his argument. In addition, we have updated one critical slide he used to demonstrate the impact of development efficiencies for gas-shale producers. The key assumption in Mr. Simpson's analysis is the fall in natural gas demand, which he estimates has shrunk by 1.9 billion cubic feet per day (Bcf/d). The recession-induced consumption declines among industrial and commercial customers and reduced gas use by residential users was offset somewhat by higher natural gas use to generate electricity.
On the supply side, Canadian natural gas imports into the U.S. are off by approximately 1.4 Bcf/d, while LNG imports are higher by 0.3 Bcf/d. Mr. Simpson estimates that domestic natural gas production is higher by 2.0 Bcf/d, which is consistent with most other estimates. The net increase in gas supplies of 0.9 Bcf/d, when combined with the 1.9 Bcf/d demand fall, means the gap between gas supply and gas demand has grown to 2.8 Bcf/d. That gap represents approximately 4.5% of annual natural gas consumption based on 2008's total consumption of 23.2 trillion cubic feet, or roughly 63.6 Bcf/d. Can this gap be closed?
In Mr. Simpson's estimation closing this gap will prove difficult. The challenge is due to the rapidly growing output from gas-shale basins, which is driven by their low development costs. Mr. Simpson argues that based on data his firm has access to, which is essentially daily production flows into pipelines, despite the significant drop in gasdirected drilling, production has not fallen off commensurately. We have re-created the essence of a slide Mr. Simpson used that showed the total U.S. rig count versus production, which he defined as gross gas withdrawals. One difference is that we elected to use the Baker Hughes gas-directed rig count rather than the total rig count. If we simply used the Energy Information Administration's (EIA) data on monthly gross gas withdrawals, our daily numbers came out much higher than on Mr. Simpson's slide. We then removed the volume of gas the EIA says is used for repressuring fields. Since that data is published with a long lag time, we calculated the average daily re-injected volumes for 2006 and 2007 and applied this average to the gross withdrawal estimates. When we plotted the results, our gross gas withdrawal estimates for 2009 showed more volatility than Mr. Simpson's chart.
One might argue the recent monthly gross gas withdrawal declines reflect production responses to the dramatic decline in gas drilling we have experienced so far this year. Others might see the monthly fluctuations as too modest to assume a trend change and thus argue that gas production is essentially flat. This was Mr. Simpson's argument, and he said he based his conclusion on data his firm gets daily. Since we don't have access to his data, or know exactly where it comes from, we cannot explain the discrepancy between the two charts. What we can say about our chart is that if production has begun a downturn, it required a huge drop in the gas-directed drilling to move the needle. Of course, it is possible the monthly data variations are the result of producers shutting-in gas production due to low prices.
There were two other aspects to Mr. Simpson's analysis about the lack of production response to the falling rig count. First was the drilling efficiency improvement impact on production growth. Secondly, the improved economics for gas-shale wells due to lower total development expenditures versus increased total production. Fewer wells and greater initial production, even with higher well costs, has translated into improved economics.
To demonstrate his point, Mr. Simpson showed a slide with data on drilling and production in the Fayetteville gas shale formation taken from the 10-Q reports of Southwestern Energy Company (SWNNYSE) for the first quarter of 2007, the first quarter of 2008 and the fourth quarter of 2008. We have updated the data through the first quarter of 2009, which not only further supported Mr. Simpson's observations, but also added some additional insight. A crucial point in the Southwestern Energy data is the dramatic reduction in the time required to drill the wells even as their average lateral length increased. Additionally, the wells are showing progressively greater average production during their first 30 days of operation.
The improved drilling performance has slowed the pace of cost increases for these Fayetteville wells. With dramatic improvement in initial production additions per rig per year, the improving profitability of these gas shale wells is clear and helps explain why producers such as Southwestern Energy are inclined to continue drilling these highly profitable wells.
When one examines the data for the 30-day average production rate per well and the IP additions per rig per year, there was a noticeable decline between the fourth quarter of 2008 and the first quarter of 2009. Southwestern Energy explained this quarterly variance as due to the delay in the expansion of the Boardwalk Pipeline that caused the company to develop a backlog of finished wells that could not be hooked up upon completion. When the pipeline expansion was completed, Southwestern Energy commenced hooking up the backlogged-wells based on the wells' productive volumes. Therefore, the 2007 fourth quarter benefitted from more high-flow-rate wells beginning production as some lower-volume producing wells drilled in the quarter were shifted into 2009 for hookup.
To demonstrate this point, Southwestern Energy detailed its monthly well performance. The initial production for wells hooked up in January and February 2009 was around 2,800 MMcf/d in contrast to the March production rate that was in excess of 3,300 Mmcf/d and the estimated rate in April (based on data for the first half of the month) of nearly 3,800 Mmcf/d. When one annualizes the production gains it becomes clear that the historic trend in initial well productivity and the IP additions per rig per year would have continued had wells been hooked up as they completed during the fourth quarter of 2008 and the first quarter of 2009, rather than being shifted around.
The main message from Mr. Simpson's analysis is that the efficiency performance of gas-shale producers will keep them drilling and producing. The net impact is that their development costs are falling and, in many cases, are below current spot gas prices and certainly below the prices suggested by the forward strip for natural gas prices. These trends will continue to put pressure on the more costly western gas basins, especially when it comes to seeking pipeline access. Add into this mix the potential for additional LNG volumes at what can be very low prices and more Canadian gas imports as a result of that country's storage capacity rapidly filling, we could see more downward pressure on natural gas prices.
Countering the negative forecast for natural gas prices, the analysts at Bernstein Research recently issued a report arguing that the base production of U.S. natural gas is declining at an annual pace of 30% in 2009. They believe that if the U.S. gas rig count remains flat for the balance of this year, gas production from December 2008 to December 2009 will be down by 10.5%, implying in their view a switch from an oversupply of 1-2 Bcf/d to an undersupply of 4-5 Bcf/d. Since they believe gas supply will decline sharply in the summer months, they expect gas prices to rise during the second half of 2009.
The firm's analysis is based on measuring the increase in the annual decline rate for natural gas wells and the contribution to production from new well drilling. The challenge in any analysis of the natural gas market is to understand the contribution from the unconventional gas shales. The Bernstein analysis begins with the EIA's chart showing the relative contribution to total natural gas supply in the U.S. from conventional onshore, unconventional onshore and offshore gas production. The growing contribution from onshore unconventional supplies is clear.
When production is examined on an annual basis it becomes clear that the domestic gas industry is facing an accelerating decline rate. This means gas producers must either drill more wells per year, assuming they continue to find the same size producing wells, or they need to find wells with greater production. Therein lays the great attraction with the gas-shale reservoirs around the country.
Next they demonstrated that gas supply in the U.S. has become a real-time drilling issue. The chart showing the percentage of gas produced from wells drilled in the previous three years clearly demonstrates that conclusion. In fact, the last two years show a sharp increase in the trend reflecting the explosion in gas-shale drilling and production.
Equally important to understand about gas-shale production is not only its significant initial well production but also its rapid depletion. As the Bernstein analysis shows, non-horizontal gas wells tend to have about 45% decline rate in the first year while horizontal wells experience about a 62% rate, based on the data for 2007 and 2008. This means gas producers are on a sharply upward sloping treadmill of drilling if they wish to sustain let alone increase production.
In order to estimate how much additional gas supply can come from drilling this year, the Bernstein analysts examined the contribution to 2007 gas supply additions by the type of well drilled. What their analysis showed was that vertical wells drilled the bulk of all gas wells drilled that year and added the greatest share of volume. What is noticeable about the data, however, is the relative contribution per well by the various wells drilled. Offshore wells added the most gas supply per well by a wide margin, but both horizontal and directional onshore wells contributed more than twice that of vertical onshore wells.
Using the 2007 gas volume contributions by well type, the Bernstein analysts then moved on to see how much additional gas supply could come from drilling activity this year. They assumed there would be no change to the current rig count for the balance of the year. They did assume that because of the industry downturn, rigs drilling this year would be more efficient and better prospects would be drilled. This led them to assume an increase in the wells per rig that would be drilled and in the average December contribution per new well. Based on those assumptions and analysis below, the Bernstein analysts calculate that there will be a 10.5% reduction in production between December 2007 and December 2009.
We have one issue with the Bernstein analysis: why do horizontal land rigs and wells not experience the same improvements as the vertical and directional categories? If we grant horizontal the same improvement total December volumes are 58.05 Bcf/d, or only down 1.3% from the December 2007 volumes. That one change in assumptions makes a huge change in the conclusion.
The issue of the gas futures price trend recently has been highlighted by a growing debate over whether greater controls should be placed on the futures trading market in an effort to restrain "speculators" from driving prices higher. While the possibility of tighter regulations in the commodity futures market is mostly focused on crude oil, any changes in the regulation of traders will impact all U.S. commodity markets.
The U.S. Natural Gas Fund (UNG-NYSE), a mutual fund that enables individuals to invest in natural gas futures, has been
questioned about its role in accentuating gas futures price moves due to its size. In a recent 8-K filing, UNG produced a chart showing the funds' growth, i.e., increase in futures contracts held as natural gas futures prices have fallen. UNG is using this chart to help dispel government attempts to put more restrictive limits on the number of futures contracts that traders, i.e., the fund, can hold.
The larger issue raised by UNG's price and holdings chart is whether the fund has actually supported natural gas prices at higher levels than they would have traded absent the fund buying activity. One clearly sees that the dive in natural gas prices seemed to stop when the fund began to expand and gas prices have moved higher and stabilized as the fund grew even more. There is little doubt that natural gas has become identified as the best fuel to bridge the transition in energy eras for the United States from one dominated by "dirty" fuels to one marked by "cleaner" fuels so it is reasonable to expect increased investor interest.
So far this year, the disparity between the price-to-energy-value of crude oil to natural gas has been volatile, but for much of the year it has been above the average of the past 15 years. Today the disparity is at an all-time high. In expectation of increased demand for natural gas and the extreme price disparity, investors have embraced the "natural gas trade" - buy natural gas futures and sell crude oil futures. The heightened investor interest in this trade explains much of the UNG fund's growth this year. Intuitively the growth of the fund has supported natural gas futures prices at higher levels than supply/demand fundamentals would support.
Natural gas pricing this year may have sent the wrong signals to the E&P companies who were making decisions about drilling gas wells. There might have been a swifter and deeper gas-directed rig count fall-off this spring if gas prices had fallen faster and farther than they did. At current prices, producers drilling in most gas-shale basins are still making money. It would not have been the case if prices were lower. As a result, we may have entered an extended period of natural gas oversupply from sustained drilling despite low prices.
This realization may be behind comments by oilfield service company CEOs on their second quarter earnings conference calls about the pace of the industry recovery. Dave Lesar, Halliburton Companies' (HAL-NYSE) CEO characterized it this way, "Due to continued weakness in natural-gas demand ... we believe it is unlikely that there will be a meaningful recovery in natural gas prices and, consequently, drilling activity for the remainder of the year."
Our own view is that natural gas is in an extended period of low prices driven by a combination of weak gas demand due to the anemic economic recovery and continued gas supply growth from domestic production, Canadian imports and additional LNG deliveries. Like Mr. Simpson, we don't believe this will be a decadelong experience. Could it last five years? Possibly, but then again, no one knows. Absent a greater cutback in drilling and a more rapid falloff in production than we are currently seeing or a sharp upturn in gas-consumption, the domestic natural gas market may be in for an extended depressing period.
Posted by Arthur Caldicott on 27 Aug 2009