ZT:The Gas Crisis of 2011

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The Gas Crisis of 2011
by Bill Powers
Editor, Powers Energy Investor
January 6, 2010

Excerpted from issue 8 with detailed data by basin summarized

One of the favorite phrases of fellow Chicago financial analyst Don Coxe is along the lines of “the most money is not made from investing in front page stories but rather investing in page 16 stories that are on their way to the front page.” After writing about America’s coming gas deliverability problem in a previous issue, I discovered that if domestic production continues to decline in conventional natural gas producing basins, imports from Canada continue to dwindle and LNG imports remain at the subdued levels, production from unconventional gas producing basins will not be sufficient to keep US supplies even close to current levels. Production declines from both Canada and conventional basins in the US as well as several unconventional basins are being masked by a weak economy, a glut of gas in storage from last year’s drilling orgy and gas from a few shale plays whose economics are extremely poor at today’s prices.

Predicting the timing of when US gas supplies will go into severe deficit vies a vie demand and cause a significant and sustained natural gas price spike to occur is very difficult. Timing is affected by a host of factors such as the vagaries of economic activity, the weather and uneconomic production. Its occurrence, however, is imminent. I see this scenario happening by the middle of 2011. I believe 19 months should provide sufficient time for this past year’s collapse in natural gas directed drilling to have an impact on supply.

I came to the conclusion that we are headed for a severe supply deficit after I examined the production profiles of the major conventional and unconventional fields in the US and Canada. By June of 2011, only 19 months from now, we are on pace to suffer a reduction in US gas supply of approximately 8.5 billion cubic feet per day (bcf/d) – approximately 13% of US supply. In this article I will discuss the changes in major producing areas in the US and examine the impact a continued fall in Canadian natural gas production will have on US supplies. Additionally, I will also address the insignificant impact current LNG imports are having on US supply and their likely future impact on supply.

While oil focused producers are the darlings of the investment community today, I believe gas weighted producers will also have their day in the sun. Investors with a longer-time horizon should consider keeping gas weighted companies on their radar screens. One of my Model Portfolio members, which has a huge inventory of economic drilling locations, is an excellent example of a firm I believe will build large amounts of shareholder value as they develop their drilling locations into a higher gas price environment.

Areas of Production Growth

Fayetteville Shale
The Fayetteville shale is one of the four large shale plays that have shown explosive growth over the last five years. While the growth of natural gas production in the Fayetteville has been nothing short of phenomenal over the last five years, we are already seeing a slowdown in growth.

Despite Southwestern Energy’s efforts to drive down well costs through continuous improvements in drilling and fracturing and its commitment to participating in 575 wells this year, the law of large numbers is catching up with the Fayetteville Shale [note: SWN is the most active driller and largest land holder in the Fayetteville Shale]. With over 1,000 wells drilled into the play already and the high decline nature of horizontal wells, the rate of production growth will slow over the next several years before the play reaches an ultimate peak of 3 bcf/d in 2012/2013. Based on the drilling of approximately 900 wells by Southwestern and other operators in the play over the next 19 months, I expect the Fayetteville to contribute 2.25 bcf/d to US gas supply in June of 2011.

Haynesville Shale

Estimating current production from the Haynesville Shale is far more difficult since the State of Louisiana does not break down production statistics on a field-by-field basis, rather by onshore and offshore production. Therefore, to come up with an estimate of current Haynesville production, I examined the Q3 2009 earnings releases of the largest operators in the play.

While the Haynesville will be the main focus area for several large independent operators such as Chesapeake Energy and PetroHawk Energy, these companies as well as their smaller peers are likely to cut back spending plans in the Haynesville due to balance sheet constraints.

The flush production and steep decline of the typical Haynesville well makes the price received during the first year of production extremely important in determining the lifetime economics of the well. At today’s gas prices and a relatively flat strip price, it would take nearly eight years for a Haynesville well to pay out. Putting high-rate, very high decline, $8 million Haynesville wells into production when spot gas prices are less than $3.50 per thousand cubic feet (mcf) is essentially financial suicide. Given that most Haynesville operators have reduced hedges in place for 2010 and limited balance sheet flexibility, I expect to see a slowdown in the rate of growth of activity in the play.

Despite these obstacles, the desire of Haynesville operators to show growth at any cost to Wall Street analysts will keep production flowing at an unsustainably high rate for now. I believe that the Haynesville Shale will be producing approximately 2 bcf/d by June 2011.

Marcellus Shale

Similar to the State of Louisiana, the Commonwealth of Pennsylvania does not break gas production down by field. Therefore, I relied on Q3 2009 financial statements to get a tally of where Marcellus Shale production currently stands.

The Marcellus Shale is the best example of an emerging shale play that has massive potential reserves but equally large developmental obstacles. As discussed in the October 1, 2009 issue of the Powers Energy Investor, initial estimates of the reserves contained in the Marcellus range from 50 and 300 trillion cubic feet, possibly more if some of the more optimistic estimates are to be believed. However, the difficult topography of western Pennsylvania, water rights issues as well as lack of gathering systems will restrain the growth of the Marcellus.

As an aside, in December 2007, I was at an industry conference in a very snowy Pittsburgh where I listened to a representative of Range Resources discuss how his company was fully committed to the Marcellus and was putting the full resources of the company into its development. Given all of the company’s efforts and money put into the Marcellus and their continuous promotion of the play, I find it very odd that Range Resources has not been able to achieve more than 80 million cubic feet per day (mmcf/d) of production two years later. Therefore, based on the slow ramp up of production from the Marcellus, I expect the play to be producing approximately 500 mmcf/d in June 2011.
The Woodford Shale

The Woodford shale came to the forefront as a prospective shale play approximately five years ago when Barnett Shale pioneer Devon Energy and Newfield Exploration applied many of the techniques used to unlock the Barnett Shale to this 500,000 acre prospective area in south central Oklahoma. With the understanding that every shale play is different, the two companies, along with a host of smaller operators, set out to determine the optimal methods for drilling and completing Woodford shale wells while continuously driving down total costs. While operators in the play have been able to drive down wells costs, raise initial production (IP) rates and expected ultimate recoveries, they have not been able to achieve the economics enjoyed by operators in other shale plays such as the Haynesville and the Barnett. Given that the estimated break even costs of the Woodford are $7.00 per mcf, this has caused an exodus of operators such as Devon Energy from the play.

Due to the high decline rates of the Woodford and the decline in drilling activity in the play, I expect production to grow to approximately 550 mmcf/d by June 2011.

Eagleford Shale

The Eagleford is the most recent shale play to go into commercial development. The play is located in south Texas and contains approximately 500,000 acres. Due to its very modest break-even costs, the play is quickly gaining industry attention. Because of the early stage nature of the play, I expect the Eagleford to grow quickly over the next couple of years.

While listening to the conference calls of both Anadarko and El Paso, it became apparent that the management teams of both companies believe that the early results from Eagleford are encouraging; however it is still in its early days. I take this to mean that operators in the play are still defining the sweet spot and expect wide variation in drilling results. Despite the potential for significant disparities in drilling results, I expect gas production from the Eagleford shale to reach approximately 200 mmcf/d by June 2011.

Cana Woodford

The Cana Woodford is a very new shale play in western Oklahoma that is being pioneered by Devon Energy. According to the company’s Q3 2009 conference call, the company has acquired 109,000 net acres and has applied nearly the same techniques in its original Woodford play to achieved 53 mmcf/d. DVN mentioned on its conference call that it is moving one rig from its Barnett Shale project and one from its original Woodford play to ramp up activity in the Cana Woodford. The only other operator that I have found to be active in the Cana Woodford play at this time is Questar Energy. Questar has a one rig program beginning in 2010. I believe production will increase to approximately 150 mmcf/d by June 2011 given the favorable economics of the Cana Woodford.

Granite Wash

The Granite Wash play of the Texas Panhandle and western Oklahoma is a tight sand gas reservoir that occurs in thick, stacked sequences of sands, siltstones and shales up to 3,500 feet thick (Source: Oil and Gas Investor, August 14, 2009). The Granite Wash sequence occurs at approximately 11,000 to 12,000 feet. Operators in the area have used both vertical and horizontal wells, which are multi-stage fractured and cost approximately $7 million each to drill and complete. While the Granite Wash is still in the early stages of development, operators in the play have been met with a significant amount of success. For example, Newfield Exploration’s first seven wells in the area have averaged 22 million cubic feet equivalent per day (mmcfe/d) according to a news release dated July 22, 2009. It should be noted that a significant portion of Granite Wash production can be comprised of natural gas liquids or oil.

The early success of the Granite Wash has attracted the largest unconventional gas operators to the play and seems to be attracting new entrants on a daily basis.

Given the high liquids content of Granite Wash production, I am probably overstating current natural gas production from the play. However, for the purpose of this exercise, I am trying to be generous but realistic in my estimates of current production. Since the economics of the play are so robust given today’s high liquids prices, production from the play should increase significantly over the coming years. I expect production from the Granite Wash to be approximately 500 mmcf/d in June 2011.

The Pinedale Anticline

The final area of growing production over the next 19 months is the Pinedale Anticline of southwest Wyoming. The Pinedale Anticline is approximately 90 square miles into which approximately 1,000 wells have been drilled over the past decade. (Source: Ultra Petroleum) Most production from the field comes from the Lance formation, which is interspersed throughout several different intervals. Similar to other tight sand plays, the Pinedale’s economics were unlocked once operators discovered the technique to fracture several distinct pay intervals simultaneously. According to a recent presentation by Ultra, the Pinedale currently produces approximately 1.2 bcf/d.

Based on the increasing pipeline capacity that is coming onstream in the Rockies over the next two years and the very low cost nature of Pinedale wells, I expect the area to grow production to approximately 1.8 bcf/d by June 2011.

Areas of Production Stagnation

After researching every major producing basin for this article, I uncovered four unconventional gas plays, areas that were previously the focus of heavy industry activity where production has reached a plateau or has begun a gradual decline.


While there are many other natural gas plays that have plateaued or are in gradual decline due to the maturity of the play or lack of drilling at today’s low prices, the main four were once thought to be part of an unconventional gas revolution that would supply abundant gas for decades. However, no matter how revolutionary the technology, the laws of physics catch up with every field. Production declines eventually set in and the consequences can be severe.

Areas of Declining Production

In my efforts to quantify the declines in natural gas production for the largest sources of US supply, I was able to find very good data sources at the state and federal level. To provide some background on my predictions for production in June 2011, I will provide several months of production history to show the production decline trend that is accelerating in nearly every case.

Piceance Basin

Similar to many unconventional gas plays, this tight sand gas play was the subject of intense development until the beginning of 2009. The Piceance Basin, centered in Garfield County, Colorado, was home to one of the most intense drilling booms North America has ever seen. The ramp up in gas production from the county was truly spectacular. However, the production decline from the area has been equally breathtaking. Drilling in Garfield County has virtually come to a standstill due to today’s lower gas prices and tougher environmental regulations for the Colorado’s exploration and production (E&P) industry. This situation, combined with the very high decline rate of Piceance Basin gas wells, will likely drop Piceance Basin production by 800 mmcf/d between now and by June 2011. [For readers who are historians of the Canadian natural gas industry, the production ramp up and dramatic fall in gas production from the Piceance Basin reminds me of what occurred at the Ladyfern field in British Columbia. I will discuss the “Ladyferning” of US shale basins in a future issue of my publication.]

District Four of Texas

The Texas Railroad Commission, the keeper of all oil and gas data for the State of Texas, has divided the state in 10 districts. District Four encompasses several counties along the Gulf Coast in the far southern reaches of the state. It is here where dozens of E&P companies have successfully exploited the gas rich Frio, Vicksburg and Wilcox in addition to other formations. These three main formations, on which primarily vertical wells were used, all contain excellent permeability and high pressures. This combination allows gas to flow to a wellbore at very rapid initial rates. However, the conventional gas formations of the Frio, Vicksburg and Wilcox all have extremely high decline rates. Additionally, due to the maturity of District Four, the remaining targets have become progressively smaller over the years. This has greatly reduced drilling activity in the District since the beginning of the year, despite a large drop in drilling costs.

With the migration of rigs away from higher-cost traditional natural gas plays such as those found in District Four, I expect drilling in the area to continue to decline. Therefore, I expect production to fall approximately 1 bcf/d by June 2011.

District Six of Texas

Texas District Six is one of the most densely drilled areas of the world given that the area is home to the massive east Texas oil discoveries of the early 20th century and in more recent decades, drilling has focused on several tight sand intervals such as the Cotton Valley and Bossier. During the past two years, there have been efforts by several operators to determine the prospective nature of the area for Haynesville Shale production. To date, the Haynesville has proven very difficult for operators and most have chosen to focus their attention on the better defined portion of the play in northeastern Louisiana. With over 30,000 natural gas wells drilled in District Six over the last six years, there has been a significant spike in gas production.

The aftermath of the Cotton Valley drilling boom in District Six is already having a major impact on production. With a significant drop off in drilling activity, the production decline of the last year is only going to get worse. Similar to District 4, I expect production in District 6 to decline by 1 bcf/d by June 2011.

Barnett Shale

The Barnett Shale is the largest onshore natural gas field in the US and has been the focal point for the development of the shale gas industry in the US. Many of the techniques that were first developed to exploit the Barnett have been applied to other shale gas basins with varying degrees of success. Many of the operators in the Barnett Shale aggressively drilled up their positions over the past few years and are now left with lesser quality acreage that will only provide economic returns at significantly higher natural gas prices. Today’s low gas prices have caused operators such as Devon Energy and Carrizo Oil and Gas to delay completing Barnett Shale wells which has further depressed production. After the exodus of nearly 150 drilling rigs from the Barnett over the past year, there is little doubt that the granddaddy of all shale plays is headed for a steep fall in production. The sharp ramp up in production from the Barnett over the last six years will lead to a continued slide in production over the next several years.

Given the steep decline curve of recent vintage Barnett Shale wells and the large exodus of drilling rigs from the area, I expect gas production from the area to drop 2 bcf/d by June 2011.

Gulf of Mexico

Gulf of Mexico (GOM) natural gas production has been in a freefall during the last seven years. A nearly 20 year low in the GOM rig count ensures that declines will continue. At today’s gas prices, there is very little drilling for natural gas in the GOM and operators are having difficulty justifying the building of infrastructure to bring recent discoveries ashore. Despite the record gas prices over the last ten years, production in US federal waters has dropped by nearly half.

The only reason for the slight uptick in 2009 was flush production being put through newly repaired pipelines that were damaged during the 2008 hurricane season. Offshore wells, especially gas wells, are high pressure, high decline wells. Constant development of new wells is required to keep offshore production from heading into a violent downward spiral. The low gas price environment of the past year has put offshore production on exactly this trajectory. I expect GOM production to fall by 3 bcf/d by June 2011.

Powder River Basin CBM

The Powder River Basin (PRB) coal bed methane (CBM) play is the second largest CBM play in the country behind the massive San Juan field. However, unlike the San Juan, wells in the PRB are far less productive, each averages approximately 300 mmcf/d and produce significantly more water. The cost of water disposal is the issue that will force the shut-in of many marginally productive wells in the basin. According to the Wyoming Oil and Gas Commission there are 11,783 shut-in PRB wells as of April 1, 2009, up from 8,700 in August 2008. Given the low natural gas prices in the Rockies, I am confident that the number of shut-in PRB CBM wells now exceeds 13,000. This situation will only get worse until operators in the PRB are confident in a sustained rally in natural gas prices since it can take several months to pump the water off a shut-in well before it will return to its previous level of production.

Due to the time-delayed nature of CBM production, wells typically initially produce significant amounts of water and small amounts of natural gas and the water/gas ratio eventually reverses, production in the PRB has been resilient thus far. However, once last year’s drilling boom fades and the impact of well shut-ins set in, production will trend downwards.

Based on a near shut down of CBM drilling in the PRB and an increasing amount of shut-in wells, I expect CBM production in the basin to decline by approximately 200 mmcf/d by June 2011.

Canadian Imports

A recent research report by FirstEnergy analyst Martin King dated November 12, 2009 discussed the reasons natural gas production in the Western Canadian Sedimentary Basin (WCSB), which includes Saskatchewan, Alberta and British Columbia, is now moving towards blow down mode. Mr. King describes the situation in the WCSB as follows:

“Given the very slow pace of drilling, we see gas production in the basin slowly trending toward a ‘blow down mode’ in which production trends to the underlying declining rate near 20%.”

This winter’s drilling season, which began in late November when the ground froze and will extend until spring break-up in March, is likely to be a complete washout for natural gas drilling. With most Canadian operators solely focused on drilling on potential oil wells this winter, we are certain to see WCSB natural gas production decline at an increasingly rapid rate.

Similar to the shale gas plays in the US, British Columbia’s Horn River Basin shale play and the Montney shale play have received a great deal of industry attention as the industry’s greatest hope to reverse several years of declining production in the WCSB. However, according to Mr. King’s research, which is based on various pipeline postings, natural gas production in British Columbia has declined from 2.76 bcf/d in October 2008 to 2.46 bcf/d in October 2009. The decline in conventional BC natural gas production is more than offsetting production growth in BC’s emerging shale plays.

Without the ability to keep domestic production stable, Canadian natural gas exports are nearly certain to collapse over the next 19 months. I expect Canada’s exports to drop to approximately 150 bcf a month by June 2011 or by approximately 4 bcf/d over the next 19 months.

LNG Imports

I find it interesting that many of the analysts who are now touting ever increasing production from shale gas, previously predicted that we would by now, be flooded by LNG arriving on the shores of the US. With over 10 bcf of re-gasification capacity now available and less than 1 bcf/d of LNG imports due to mostly low gas prices in the US compared to elsewhere in the world, facility operators find themselves in a very difficult position. With additional liquefaction capacity coming online over the next 18 months, there is a small window for US operators to lock in contracts if they are of the opinion gas will make a strong rebound in the near future. Despite the growth in the liquefaction capacity, re-gasification capacity is growing even faster. Increased demand from new LNG importers such as China, India, the UK, Argentina, Uruguay, Brazil to name only a few, will ensure that US imports stay at nominal levels for years to come.

Conclusion

Now that we have looked at all of the major sources of US natural supply, let’s examine where total supply is likely headed over the next 19 months.

Areas of Supply Growth

Play
Production change

Fayetteville Shale
+1.1 bcf/d

Haynesville Shale
+1.08 bcf/d

Marcellus Shale
+220 mmcf/d

Woodford Shale
+108 mmcf/d

Cana Woodford
+97 mmcf/d

Eagleford Shale
+134 mmcf/d

Granite Wash
+155 mmcf/d

Pinedale Anticline
+600 mmcf/d

Total
+3.494 bcf/d


Considering that the above seven natural gas plays employ close to 70% of the approximately 750 natural gas directed rigs currently running, there is unlikely to be other areas of significant production growth in the US.

Areas of Supply Declines

Area
Change in Production

Piceance Basin
-800 mmcf/d

District Four of Tx.
-1 bcf/d

District Six of Tx.
-1 bcf/d

Barnett Shale
-2 bcf/d

Gulf of Mexico
-3 bcf/d

PRB CBM
-200 mmcf/d

Canadian Imports
-4 bcf/d

Total
-12 bcf/d


Based on my analysis of the major producing basins which I have highlighted above, I believe we will see a net decline of US natural gas supplies of approximately 8.5 bcf/d.

Short of the world going into a severe depression sometime during 2010, the coming drop in US natural gas supplies will put unrelenting upward pressure on natural gas prices when the market realizes the magnitude of supply deficit. When this will happen is unknowable. However, investors can position themselves ahead of time. Several of the companies in my Model Portfolio are gas weighted and are well positioned to take advantage of the upcoming change in the economics of natural gas.

rabishh

GOOD ， thanks