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Natural Gas: Where Endless Money Went to Die

Wednesday, June 20, 2012 at 4:17PM

The fiasco that is playing out in the natural gas industry doesn’t happen often in a free market, and when it does happen, it’s usually short—and brutal for all involved: namely, prices that are way below production costs. In most industries, hedging strategies might get market participants through the period, while unhedged production, a money-losing activity, gets slashed. If it lasts long enough, it causes a shakeout where less efficient or poorly capitalized producers, and their investors, get wiped out. It’s all part of the capitalist system that weeds out weaker elements through occasional sweeps of creative destruction.

As shortages crop up on the horizon, prices return to sustainable levels, and occasionally spike to once again unsustainable levels. For the survivors, or for lucky new entrants, the next step in the cycle has begun.

Alas, thanks to the Fed’s zero-interest-rate policy and the trillions it has handed over to its cronies since late 2008, the sweeps of creative destruction have broken down. Instead, boundless sums of money have been searching for a place to go, and they’re chasing yield when there is none, and so they’re taking risks, any kind of risks, in their vain battle to come out ahead. The result is a stunning misallocation of capital to the tune of tens of billions of dollars to an economic activity—drilling for dry natural gas—that has been highly unprofitable for years. It’s where money has gone to die. What’s left is debt, and wells that will never produce enough to make their investors whole. For that whole debacle, read…. Capital Destruction in Natural Gas.

But the money has dried up. And drilling for natural gas is collapsing. Last week, there were only 562 rigs drilling for dry natural gas—the lowest number since September 1999. A dizzying downward trajectory:


Producers, if at all possible, are switching to drilling for oil and natural gas liquids (priced like oil), still a profitable activity. Thus, capital is now being channeled to where it can make money. Drilling for dry natural gas will continue to decline as the long delayed sweep of creative destruction is scouring the industry.

The largest producer, ExxonMobil, given its monumental size and worldwide focus on oil, will weather the fallout just fine. But the second largest producer, Chesapeake Energy, is struggling. It’s trying to dump assets to raise cash to deal with its mountain of decomposing debt. Other producers that haven’t diversified away from dry natural gas are in a similar quandary. And at current prices, it’s going to be bloody.

At $2.53 per million Btu at the Henry Hub, the price of natural gas is up 33% from the April low of $1.90 per million Btu—a number not seen in a decade. But even if it doubled, it would still be below the cost of production. And if it tripled, it might still be below the cost of production for most producers. That’s how mispriced the commodity has become.

Misallocation of capital, and the resulting overproduction, is only part of the problem. The other part of the problem is horizontal fracking itself—a drilling method that extracts gas from shale formations. With nasty economics. It’s an expensive method. And once drilled, the well suffers from steep decline rates; after a year or a year-and-a-half, only 10% of the original production might still come to the surface.

The breakeven price for natural gas under these conditions—and it differs from well to well—is still partially theoretical since horizontally fracked wells have not yet gone through their entire lifecycle. Here is a detailed discussion and pricing model. The short answer: over $8 per million Btu. Even if that number is off, at the current price of $2.53 per million Btu, the industry is still near its point of maximum pain.

There are consequences. Power generators, having switched massively from coal to natural gas, are driving up demand. And production has finally seen a bend, a small one, in the curve that had set new highs month after month. Now, it’s declining. There is a lag between dropping rig count and production. The rig count estimates how many new wells are being drilled. Even if it dropped to zero next week, production would not immediately be impacted because the current wells would continue to produce. Production would then taper off as a function of decline rates per well—and in fracked wells, that lag is expressed in months, not years.

While the US doesn’t yet have LNG terminals to liquefy and export natural gas—in the global markets, LNG fetches mouthwatering prices between $10 and $15 per million Btu—it does have a pipeline to Mexico. According to BENTEK Energy (via the EIA), pipeline exports to Mexico hit 1,867 million cubic feet per day, a record in the seven plus years that BENTEK has been tracking it (by comparison, Chesapeake Energy produces about 2,575 MMcf/day).


Rising demand and exports are slamming into declining production. What was a record amount of natural gas in storage is coming down rapidly. Fears that storage would reach capacity towards the end of the injection period in the fall, and that natural gas would have to be flared, thus reducing its price to zero, seem ridiculous now. But prices, if they stay in the current ballpark, will continue to demolish producers, drive them away from dry natural gas, and cause financial bloodshed.

Until shortages appear on the horizon. But then, production can’t be ramped up quickly, regardless of what the price might be. Expect a spike and more mayhem, but this time in the other direction.

And oil, which has experienced a phenomenal boom in drilling? In North America, the range of oil qualities and a raft of infrastructure nightmares are wreaking havoc with record price differentials, writes energy expert Marin Katusa in his excellent…. Oil Price Differentials: Caught between the Sands and the Pipelines.


EIA: Horizontal Drilling Boosts Gas Production in Pennsylvania, USA

The U.S. Energy Information Administration (EIA) said in a report that between 2009 and 2011, Pennsylvania’s natural gas production more than quadrupled due to expanded horizontal drilling combined with hydraulic fracturing.

This drilling activity, which is concentrated in shale formations that cover a broad swath of the state, mirrors trends seen in the Barnett shale formation in Texas.

Historically, natural gas exploration and development activity in Pennsylvania was relatively steady, with operators drilling a few thousand conventional (vertical) wells annually. Prior to 2009, these wells produced about 400 to 500 million cubic feet per day of natural gas. With the shift to and increase in horizontal wells, however, Pennsylvania’s natural gas production more than quadrupled since 2009, averaging nearly 3.5 billion cubic feet per day in 2011. Natural gas wells accounted for virtually all (99%) of the horizontal wells started over this period.

Drilling programs in Pennsylvania’s shale formations, like those in other, more established plays such as the Barnett and Eagle Ford in Texas, are migrating to more liquids-rich areas due to the price premium of crude oil and natural gas liquids. The effect of low natural gas prices is apparent in Pennsylvania’s 2012 well count for the first third of the year. From January through April, drilling began on 618 new natural gas wells; over 700 new natural gas wells were started over the same period in 2011. In contrast, 263 new oil and “combination” (oil and natural gas) wells were started in Pennsylvania from January through April 2012, well above the 164 new wells that began drilling during the corresponding period in 2011.


University of Texas Oil Connections


This is a picture of the Santa Rita in the early 1920’s.

In 1883, the year UT was opened, an endowment was established by the state of Texas that donated 2.1 million acres in West Texas to help UT. Not much was expected of the desolate land besides to perhaps develop it for real estate. In the 1920’s curious men acquired drilling permits from UT, hoping to strike it rich. There were in fact huge oil discoveries. Oil from the Permian Basin has generously provided for the UT system. The PUF continues to receive royalties from oil and gas production in West Texas while the AUF, Available University Fund, continues to receive all surface lease income. Surface lease usually entails “grazing and easements for power lines and pipelines.”1

Big Lake Oilfield and Santa Rita #1 Oil Well

In 1919, Rupert P. Ricker started advertising the land given to UT for oil exploration. The UT alum had utilized a law passed two years earlier permitting state land to be chartered for oil exploration. Having trouble making the sale of 431,360 acres, Ricker turned to an army buddy, Frank T. Pickrell. The original price of the permits for the land and other processing fees was approximately $41,136; however Pickrell paid only $2,500 due to the approaching thirty day deadline for Ricker to make the sale. In 1921, Pickrell started making his runs desperately searching for Texas Tea.

Much to his delight, the Santa Rita #1 oil well produced oil on the final day before the permit expired. A group of Catholic women had large investments in the exploration; when they heard all of this, they wanted it called Santa Rita (“Patron of the Impossible”). But on May 25, 1923, Cromwell, with fellow worker Dee Locklin, decided to “shut down the well to keep reports tight while they leased surrounding acreage for themselves.”2

The oil well was a part of the Big Lake Oilfield. By 1926, the oilfield had already contributed $4 million to the PUF. In the beginning, the single oil well was producing around 3,000 barrels of oil daily. Different wells in the field also had success early on; “the No. 9 well’s initial daily production was 1,400 barrels, on June 24, 1924. The No. 10 came in with 1,840 barrels on July 11. But the No. 11, which began producing 3,600 barrels daily on July 31, proved the field’s productivity.”1

The Santa Rita had served its purpose to the UT system in its sixty-seven years. In 1990, the plug was pulled. The Texas State Historical Association had the original Santa Rita #1 rig moved to the UT campus, and it can be seen next to MLK Blvd between Trinity and San Jacinto streets.

Yates Oil Field

is one of the richest oil fields in the United States; it is rated in the top ten for overall production and second for reserves. Much like the Big Lake Oilfield, permits were granted by UT, and in turn, the school received royalties from the drilling in West Texas.

According to the DrillingInfo website, Yates has over 1 billion barrels left in reserves, which is the largest amount of reserves in the entire nation with the exception of the mammoth Prudhoe Bay, Alaska. It continues to produce around 20,000 barrels of oil per day and around 85,000 MCF (thousand cubic feet) of gas daily. In 1998, it was reported that a research team named Golder Associates of Redmond, Washington was attempting to discover ways to maximize production using natural drainage systems. “Very effective gravity drainage, combined with a secondary gas-cap expansion drive is responsible for the estimated ultimate recovery of 50 percent of the original oil in place.”3 The oil field is so well maintained since it contributes so much to the University.



Pioneer drilling buys Go-Coil for $110 mln (San Antonio, TX)


By Mia Lamar

Pioneer Drilling Co. PDC +6.41% has acquired a privately held provider of coiled tubing services for roughly $110 million in cash, a purchase the company said it expects to add to earnings this year.

The purchase of Go-Coil LLC, whose services are aimed at oil and gas exploration and production companies, helps boost Pioneer’s offerings in its production services division, noted Chief Executive Wm. Stacy Locke.

“After studying coiled tubing for the past couple of years, we believe this new service offering has expansion opportunities as well as cross-selling opportunities with our existing business,” Locke said.

Go-Coil operates a fleet of 10 coiled tubing units, seven of which are onshore units. Current operations are located in Louisiana, South Texas, Oklahoma, and Pennsylvania.

Pioneer, which provides contract land drilling services to oil and gas operators, in November reported it swung to a third-quarter profit with help from a 38% jump in revenue.

Shares closed Friday at $9.68 and were inactive in premarket trade. The stock is up 51% in the past three months.


Energy In Depth

Uploaded by EnergyInDepth on Feb 26, 2009
Hydraulic Fracturing — Is It Safe?

Robin Millican

Less than a decade ago, natural gas prices in the United States were among the highest in the world. However, in the last five years, domestic natural gas reserves have grown 30 percent due to technological advances in the use of hydraulic fracturing,[1] a drilling method that is coupled with directional drilling to access underground reservoirs of oil and gas. This technological breakthrough had an immediate impact on natural gas prices, causing them to plummet and remain low to the present time.

Despite this important stride toward future U.S. energy security, hydraulic fracturing has come under attack. As the newest cause célèbre of fossil fuel foes, hydraulic fracturing was notably featured in the 2010 movie Gasland, which dramatized the allegation that hydraulic fracturing had been the cause of groundwater contamination. Understandably, these reports have caused much public consternation, and have prompted both regulators and legislators to contemplate whether hydraulic fracturing should be subject to additional federal regulation. But are they accurate?

What is hydraulic fracturing?

While the controversy over hydraulic fracturing is new, hydraulic fracturing itself is not. First used in 1947, hydraulic fracturing has been employed in more than a million wells to extract more than 7 billion barrels of oil and 600 trillion feet of natural gas from deep underground shale formations.[2] Geologists have long known that shale rock formations contain large amounts of natural gas and oil, but the fossil fuel resources were trapped in layers of rock and could not easily be extracted.

During the initial phase of the fracturing operation, a well is drilled vertically underground to a point past the deepest aquifer containing fresh groundwater. At this stage, the operator inserts steel surface casing down the length of the drilled hole, then pumps in cement to create a barrier of cement and steel between the groundwater and the well bore. The well is then drilled further down into the underground shale formation, where the operator detonates charges in order to create spaces in rock pores to release oil and gas. To create additional fissures, fracturing fluids are injected into the formation at high pressure, which contain additives such as sand to keep the fissures open and the hydrocarbons flowing.

Additionally, horizontal drilling provides more exposure within a formation than a vertical well—six to eight horizontal wells drilled from only one well pad can produce the same volume as sixteen vertical wells. This use of multi-well pads significantly reduces the overall infrastructure needed for an operation, such as access roads, pipelines routes, and production facilities, thereby minimizing disturbances to the habitat and impacts to the public.  The figure below demonstrates how horizontal drilling is employed:


Is it safe for groundwater resources?

Two studies conducted by the Environmental Protection Agency (EPA) and the Ground Water Protection Council (GWPC)—the national association of state ground water and underground injection agencies whose mission is to promote the protection and conservation of ground water—found that there have been no confirmed incidents of groundwater contamination from hydraulic fracturing.[3] This is particularly noteworthy in consideration of the fact that approximately one million wells have been hydraulically fractured in the United States.[4] Furthermore, according to the Interstate Oil and Gas Compact Commission (IOGCC)—the multi-state governmental agency representing states’ oil and gas interests—each IOGCC member state has confirmed that there has not been a case of groundwater contamination where hydraulic fracturing was attributed to be the cause.[5]

Despite this, much ado has been made regarding the use of hydraulic fracturing fluids and their potential to contaminate groundwater. Fracturing fluids consist predominately of water and sand—98 percent or more in a typical fracturing solution—while the rest is made up of high-viscosity chemical additives designed to maximize the effectiveness of the fracture job.[6] Many of the additives consist of common household compounds, and while you certainly wouldn’t want to go out of your way to drink them, the EPA concluded in a 2004 study that the additives are not considered harmful to human life or the environment in the capacity they are used.[7] Additionally, the formula for each fracturing fluid used in a drilling operation must, by mandate of the Occupational Safety and Health Administration, be disclosed at each drilling site, and a coalition of state groundwater and oil and gas regulators recently launched the Frac Focus Chemical Disclosure Registry to allow companies to voluntarily disclose the content of fracturing fluids used at individual well sites. Within 10 days of the site’s launch, 32 companies disclosed chemicals used at 388 wells.[8] For a table of common additives, please see:

Furthermore, stringent state and federal regulations on well design and construction ensure that fracturing fluid additives do not migrate upward into active or treatable water reservoirs. As aforementioned, groundwater is protected during the process of hydraulic fracturing by steel and cement casing that is installed when the well is first drilled to isolate groundwater resources. Operators have a further interest in ensuring that fractures are sufficiently well removed from underground water resources, as the penetration of a water table above a formation could render the oil and gas resources unusable.

After a fracturing job has been completed, the majority of fracturing fluids are recovered from the well and recycled in a closed system for future use. Surface disposals of fracturing fluid are subject to the federal Clean Water Act, requiring treatment for any potentially harmful substances prior to discharge, or the federal Safe Drinking Water Act if disposed in an oil and gas injection well.[9]

How much shale gas do we have?

The U.S. has an abundant amount of natural gas. The Energy Information Administration estimates that the U.S. has in excess of 2,119 trillion cubic feet (Tcf) of technically recoverable natural gas,[10] enough to power the U.S. for 88 years at current rates of consumption. Unconventional resources, like shale gas, account for 60 percent of the onshore recoverable resources,[11] representing an enormous advancement in the United States’ future energy outlook. In fact, half of the gas consumed today was produced from wells drilled within the last 3.5 years.

Most of the natural gas consumed in the United States is produced domestically—approximately 89 percent in 2010[12]—and much of this supply comes from Texas, Wyoming, and Oklahoma.[13] However, shale gas is present in many of the lower 48 states, in shale plays or basins.  The map below shows the approximate geographic locations of major producing or prospective gas shales:

Source: Ground Water Protection Council, Modern Shale Gas Development in the United States: A Primer

The economic impact of this vast resource cannot be understated. In 2008, after breakthroughs in hydraulic fracturing yielded access to unconventional gas deposits, the wellhead price of natural gas plummeted from nearly $8 per thousand cubic feet to $3.67 per thousand cubic feet.[14] In 2009, the United States was the world’s largest natural gas producer,[15] and of the 24.1 Tcf of natural gas that Americans consumed in 2010, just 2.6 Tcf, or 11 percent, was provided from net imports.[16]

In addition to keeping prices low for American consumers—who get 24 percent of their electricity from natural gas[17]—increased domestic production also creates jobs and generates royalties for residents, cities, and school districts. For example, a recent study estimates that in 2009, the development of the Marcellus Shale created 44,000 new jobs in Pennsylvania, and added $389 million in state and local revenue, over $1 billion in federal tax revenue, and almost $4 billion in value added to the state’s economy.[18]

Who should regulate?

In its study “State Oil and Gas Regulations Designed to Protect Water

Resources,” the GWPC found that all oil and gas producing states currently have regulations in place to provide protection for water resources during oil and gas exploration and production.[19] Enacting national regulations for these activities would not only be duplicative and costly for states to implement, it would indicate a fundamental disregard for states’ expertise in managing their own natural resources. Common sense dictates that states, with field operations, are in a better position to evaluate the hazards of a drilling operation than federal agencies whose operations are removed from the circumstance.

This is not to say that no federal regulations apply to hydraulic fracturing. Operations are subject to a number of federal statutes, including the Clean Water Act, Safe Drinking Water Act, the National Environmental Policy Act, and the Emergency Planning and Community Right-to-Know Act.[20]


Recent attempts to portray hydraulic fracturing as a dangerous, unregulated practice are misleading at best. When done within the set parameters of the numerous state and federal regulations that govern safe drilling practices, hydraulic fracturing has the potential to provide the United States with an abundant supply of clean-burning natural gas for years to come. Rather than trying to reinvent the wheel with new federal mandates, regulators should defer to states who can tailor and apply regulations to suit their specific circumstances.

Policy decisions on hydraulic fracturing will have significant ramifications for our future energy security. According to the National Petroleum Council, up to 80 percent of natural gas wells drilled in the next decade will require hydraulic fracturing;[21] one can only imagine the bureaucratic nightmare that would ensue upon granting the federal government with even more oversight of each operation. Indeed, the notion that the federal government would need to regulate on a well-to-well basis seems all the more incredible when juxtaposed with the industry’s excellent safety record. As aforementioned, there has not been a single confirmed incident of groundwater contamination arising from hydraulic fracturing since the practice began in 1947.

Instead of bringing an already well-regulated practice under the yoke of the EPA, the federal government should refocus its efforts upon maintaining access to affordable, domestically produced energy. In a time of rising gasoline and food prices, American families cannot shoulder a hit on another essential commodity—nor should they be expected to.

Original Article

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