Shale Gas Is Not a Game Changer – It is Simply Another Period in a Long Running Game

I am going to make a few large, unlinked generalizations and provide a rather long winded introduction to an interesting assessment of the potential for shale gas to change the gas game from its volatile history of price peaks and valleys to one of decades worth of low priced gas. If you are short on time, you might want to scroll down near the bottom of this article. If you have a bit more time and are willing to accept a broad brush approach to a complicated subject, read on.

One of the features of the world energy market from about early 2000 until mid 2008 was a reasonably steady increase in the market price for natural gas. A big driver of that price increase was the cumulative effect of more than a decade in which nearly every new controllable power plant was a Brayton cycle gas turbine – either simple or combined cycle – which are limited to burning hydrocarbon fuels that had essentially no ash content and no machinery damaging contaminants like sulfur or vanadium.

There are many valid technical reasons why gas turbines cost less than other heat engine options like Rankine cycle steam plants or diesel engines. Brayton cycle machines require a lot less material input than Rankine cycle steam machines because they are designed to use combustion gases directly and eject those gases into the atmosphere. There is no need for high pressure, leak proof heat transfer piping, no need for fuel handling equipment that crushes solid matter, and less need for capital intensive systems to provide cooling water. In a simple Brayton cycle machine, the exhaust gas carries away the waste heat; from a heat engine cycle perspective, the atmosphere is the heat sink.

Since the fuels that burn cleanly enough to run through high speed turbines without causing mechanical damage produce rather innocuous residues, natural gas burning machines gained support from people concerned about air and water pollution. They became the easy choice when the premium quality fuels that they needed were available at a low cost because the supply was slightly larger than the existing demand.

The big risk in the dash to gas was the possibility that fuel prices would not remain low and well behaved. There are fixed and well known relationships between the amount of heat in the input fuel and the amount of electrical power that can be produced. In the bulk fuel business, buyers and sellers know that the real product that they are trading is not measured in volume or mass, but in units of heat.

With natural gas and distillate fuel oil – the only available alternative if the machine is a gas turbine – the cost of a unit of heat is often very close to the market price of the equivalent amount of electricity. Gas traders talk about the “spark spread” as the margin between the two. When fuel prices climb, they approach the point at which there is no longer any margin and it no longer pays to operate machines that require premium fuels.

The people that operate electric power plants understand the risks associated with using a fuel whose prices often vary wildly as the major input in producing electricity, a product that customers expect to be available all of the time at a reasonably predictable price. The business leaders who chose to build gas fired plants worked diligently to shift the business model to put the fuel price risk onto the customers through innovations like the fuel adjustment surcharge or the reverse auctions used in deregulated markets where the highest cost producers required to supply demand set the market prices for all suppliers.

As power suppliers built and operated more and more gas turbines, demand for gas increased enough to use up the excess supply that had been available throughout most of the 1990s. The tightening balance between supply and demand increased prices. Gas extraction companies slowly started to increase their exploration and production budgets as they made more profits and as they saw the increasing price trends.

Wellhead prices are what producers get for their gas before transportation charges

Production did not increase as fast as demand, however, so the market was balanced by higher prices, which destroyed some of the demand from customers. People turned down their home heating thermostats, but a more important effect was when large scale industrial and chemical customers either shut down or moved their operations to places with far lower natural gas prices. The high prices encouraged innovations like horizontal drilling and hydraulic fracturing – especially in areas where there was an already developed, nearby infrastructure for gathering, processing and transporting gas to market.

As a stockholder in one of the biggest domestic players in natural gas exploration and extraction, I did a lot of reading about the optimism in the gas industry. There is nothing like selling a high demand commodity at a price that is significantly above the cost of finding and moving it to market to make investors happy. Marketers for the company did all they could to encourage continued development of more and more gas burning power plants because they were the customers that were the least worried about price increases – they simply passed the costs to their electricity customers. In some cases, the marketers for the company actually paid for advertising campaigns in partnership with mainstream environmental groups to tar a competitor.

The happy times in the gas game ended rather abruptly when the economic crisis hit. There may be a time when people who really want to understand all of the influences that led to that crisis look to the massive transfers of wealth from nearly everyone to a very small group of energy producers as a contributing factor, but, for now, everyone blames greedy bankers and homeowners who bought more home than they could afford. I personally suspect that high energy prices soaked up some of the income that could have helped to pay the mortgage and I also suspect that the job losses as a result of manufacturers seeking lower energy costs made another contribution.

Regardless of what actually caused the crisis, the economic slowdown caused a dramatic reduction in energy demand. The first suppliers to be pushed out, not surprisingly, were the high cost suppliers required at the margin when
times were good. Suddenly there was more natural gas in the market than customers needed, so prices fell and kept falling. At the bottom of the market, gas was selling for less than $3.00 per million BTU, less than 1/4th of the price in June of 2008.

The imbalance was increased by the effect of new production wells that had been completed during the times when prices seemed to be on a continuous upward trend. Once a gas well has been completed, it is difficult to shut it in without damaging it, so supplies from the new wells competed for customers by selling at prices just high enough to cover the operational costs with delayed payback of capital.

The game still continues however. Gas suppliers know that the key to their future prosperity is to build markets to the point were demand again exceeds supply for as long as possible. That is the situation that leads to sustained pricing power for suppliers. Gas marketers know that power plants that burn gas are rather price insensitive customers that will remain in place even as the prices go up. They are doing all they can to encourage power companies to delay plans to build reliable capacity that uses competitive fuels like coal or uranium.

One of their current marketing techniques is a steady drumbeat of optimism about gas produced from tight formations of shale. People in the oil and gas business have known about the gas content of shale for well over a century – the first natural gas that supplied a US city was drilled into a shale formation. However, they have also known that it takes a lot of effort, technology and capital to reliably extract that energy. They also know that even in shale, there are some formations that are better than others and that not all of the resource base can ever be developed, no matter how high the market prices get.

Of course, there are plenty of people who will rightfully question my knowledge and expertise in extracting natural gas. I have never been in that business and really only know what I can get out of books and articles. I want to share an informal assessment that I recently received from a man with a long and impressive resume in the oil and gas industry.

September 15, 2010

The shale gas enigma is this:

Small companies recognized the promotion potential of shale gas and acquired land leases. Initial results from drilling are reported with great fanfare. This attracts interest from larger companies who don’t move as fast but have lots of money. They farm in to the lands and they have to drill earning wells to retain the leases. Alternately they buy out the smaller company, but they still have to drill on the leases to retain them..

Shale gas wells drilled with long horizontal legs and massively fractured can be prolific producers, the key is the rate of decline and the stabilized long term producing rate which may be 1/10 or less of the initial rate. To sustain high gas deliverability new wells have to be drilled on a continuous basis.

Meanwhile the prolific production has to be sold or stored and this is depressing the price of gas. Shale gas wells are very expensive to drill. Completion requires vast quantities of water and sand for the fracturing to extract gas from the shale. The water that comes back when the gas is produced is a somewhat less pure state than when it went in as it picks up the dissolved minerals in the connate water. The gas price required to support shale gas production on a sustained basis surely must be more than the current $4.00/mcf.

As with all resources, gas bearing shales are not created equal – to be effective producers the shale must be brittle enough to fracture and hard enough so that the frac sand is able to keep the fractures open. Each area is different.

Resource estimates of gas in place in shales are meaningless and misleading as only a fraction of the gas in the areas that are geologically favorable will actually be producible. (This is why we shut the Canadian Gas Potential Committee down – we did not have the engineering skill set and access to data required to generate legitimate producible gas estimates for shale gas in Canada.)

The Barnett Shale play in Texas has the longest producing history of any play that has been developed using horizontal drilling technology and massive hydraulic fracturing. In 2009 Arthur Berman reported that there almost 12,000 gas wells producing from the Barnett shale (World Oil). Actual results from these well are far below the published expectations of operators. Berman cautions that the newer shale gas plays – Haynesville, Marcellus etc. ¬– are unlikely to meet the expectations of the promoters.

In contrast, it is not so long ago that Coalbed Methane was the “flavour of the month” and it was to be the resource game changer. Where is it now? A significant but small portion of US gas production is from coal and the volumes are declining

An investor weighing the decision to build a new power plant would have to consider if a 20-30 year supply of natural gas could be contracted. Will gas be available and at what price. Alternately a nuclear plant could be considered, but this would face massive environmental objections. The investor would sigh and check the numbers and decide to use a coal-fired plant where there are few limits on the massive disposal of coal ash waste and few technical challenges.

In summary, shale gas will become a significant component of North American gas supply where it hopefully will offset the declining supply from existing conventional and unconventional gas resources. It is not a “game changer” and it will not generate a large consistent supply of low cost gas..

Robert A Meneley
Vancouver, BC
Canada

Robert Meneley started out in geology as a summer student riding packhorses south of Grand Prairie in 1955. Following graduation from the University of Saskatchewan in 1958 he joined Imperial Oil Limited and worked as a surface and subsurface geologist throughout northern Canada and the Eastcoast Offshore with some short international stints.

After leaving Imperial in 1972 he became a consultant for a year before joining Panarctic Oils Ltd. as Vice President of Exploration at the peak of high Arctic exploration activity. In 1976 he moved to Petro-Canada to head their domestic and international exploration operations during the hyperactive years from 1976 to 1984. He continued his Panarctic connection as a director and member of the executive committee of Panarctic.

Late in 1984 Bob returned to his consulting practice where he has worked on a wide variety of hydrocarbon assessment projects in Canada and in the International arena, particularly in South America. From 1993 through 2009 Bob volunteered on the Canadian Gas Potential Committee until that committee was disbanded.

He has been directly involved in all aspects of Frontier resource assessment.

Bob was inducted into the Canadian Petroleum Hall of Fame in 2004. He retired from the petroleum business in 2010.

In addition to his professional experience, he has the following formal qualifications:

Master of Science (Geology) – University of Saskatchewan. 1958.
Bachelor of Science in Geological Engineering – University of Saskatchewan. 1956
Registered Professional Engineer and Professional Geologist (Alberta)
Member – Canadian Society of Petroleum Geologists
Member – American Association of Petroleum Geologists