U?nited States shale-gas production is a game-changer for every aspect of the natural gas industry—changing supply, usage, price and transmission flow patterns and midstream infrastructure needs.

“Investment in gas pipeline infrastructure has grown significantly in recent years because of shale-gas exploitation,” says Damien Gaul, staff economist of the U.S. Energy Information Administration (EIA). “We have seen numerous gas pipelines come onstream to provide an outlet for Haynesville, Barnett and Fayetteville production. Next up is the Marcellus shale, where there will be expansions of numerous interstate pipelines.”

Gaul adds, “Enhanced infrastructure and new production in non-traditional producing parts of the country, such as the Northeast, have had an impact on basis spreads between regions. Weather notwithstanding, the difference between the Henry Hub price and prices in the Northeast, for example, has been reduced.”

The additional U.S. gas resource has caused a decline in the need for the U.S. to import more Canadian-produced gas, or for foreign-supplied liquefied natural gas (LNG), Gaul says.

“In 2010, net imports were at their lowest level in at least a decade. Furthermore, it looks like LNG imports will not be necessary on such a large scale as previously thought.”

In fact, U.S. imports from Canada are expected to decline by 4% to 6% during the next two years, he says. “The possibility of the U.S. exporting LNG is very real because of differences in prices across the world. The Department of Energy is currently reviewing applications by industry participants.”

Shale gas has reversed the downward gas-production trend and spurred infrastructure investment, particularly gathering lines, to get supply from new sources connected to existing pipelines. The Interstate Gas Association of America (INGAA), the trade association for pipeline companies, now says that its projections, made in 2009, for investments in pipeline, storage and other midstream infrastructure to average $6 billion to $10 billion annually through 2030 are “conservative.”

Transmission flows

Shale-gas plays have blurred traditional distinctions between producing and consuming regions and altered transmission directional flows due to their widespread locations. Also, concerns have been raised about whether working-gas storage will be adequate to sustain the spike in gas production.

Just a few years ago, shale-gas production barely appeared on the industry’s radar. By the end of 2009, it accounted for 14% of U.S. gas production. From 2000 to the end of 2010, shale-gas production had increased fourteen-fold. Nearly 25% of gas production now comes from shale gas and the EIA predicts that it will account for 24% by 2011. By 2035, that could grow to 45%. Overall, Lower 48 gas production will rise about 20% from 2010 levels, the agency predicts.

Even more significant, the EIA nearly doubled its projection of technically recoverable unproved shale-gas resources in 2011, raising it to 827 trillion cubic feet (Tcf), from 447 trillion. The EIA says its revision stems from the availability of additional information as more drilling activity takes place in existing and new shale plays.

Meanwhile, in 2010, U.S. gas consumption was just under 24 Tcf while total U.S. natural gas production from conventional and unconventional sources was 21.57 Tcf, just short of the 1973 record production of 21.73 Tcf, the EIA reports.

Yet, the agency expects that total gas production in the U.S. will be nearly flat (only increasing by 0.47%) in 2011, as some producers slow production rates due to slumping prices. In 2012, total U.S. gas production will increase another 1% as prices, prompted by higher demand, improve.

“Clearly, the significant shift in the location of North American natural gas supply that we’re witnessing with the shale-gas boom will have an effect on natural gas transmission pipelines and patterns of flow,” says Catherine Landry, director of communications for INGAA and the INGAA Foundation.

“Significant transmission pipeline infrastructure was constructed during the past five years of the last decade and the majority of this was so-called ‘supply-push’ pipelines intended to deliver new gas supplies to liquid pooling points where it could obtain a competitive price.

“It also is true that the abundance of North American gas supply and the shift in the location of supply have begun to change flow patterns, which, not surprisingly, affects natural gas transmission pipelines,” she says.

In recognition of how quickly supply patterns and transmission flows are changing the market, the INGAA Foundation has commissioned an update of its 2009 infrastructure study to capture how these trends are affecting the need for gas pipelines, Landry says. That updated study probably will be published in late spring.

“I think it would be safe to say that the infrastructure study from 2009 will be proven to have been quite conservative in light of the changes of the market, particularly the dramatic increase in shale-gas resources,” Landry says.

The conservative 2009 INGAA Foundation study predicted a range of investment from $133 billion to $210 billion in infrastructure during the next 20 years (between $1 billion and $10 billion per year), primarily to attach increased gas production from shale basins and tight sands to the existing pipeline network. According to the study, by 2030 the U.S. and Canada will need some 15,000 to 26,000 miles of new gathering pipelines, between 29,000 to 62,000 miles of additional transmission lines, and 370 billion to 600 billion cubic feet (Bcf) of additional storage capacity to accommodate market requirements. A majority of storage additions would be high-deliverability salt-cavern facilities, which would essentially double current capacity.

Shifting concerns

Considering the natural gas industry’s history, shale gas’ shift from being considered an afterthought to its current role as a driving force is remarkable. Just as significant is the fact that its potential is deemed vast enough for companies to seriously propose its export from the Lower 48.

Before shale gas emerged as a major source of supply, the U.S. was increasingly concerned about rising gas imports. For many years, the U.S. relied on growing imports from Canada to meet demand growth. By the end of the 1990s, concerns increased regarding Canada’s ability to grow its exports sufficiently to meet anticipated U.S. demand. As a result, planners shifted their focus to importing LNG, which was anticipated to be the source that would balance the U.S. natural gas market.

The Federal Energy Regulatory Commission (FERC) also has been studying shifts in transmission patterns, projects and additional needs. FERC’s Office of Enforcement, in an Energy Market Assessment report released in October 2010, stated, “A geographical shift in natural gas production is changing the utilization of the nation’s pipeline infrastructure. This is apparent in the Northeast, where imports of Canadian gas have dropped.”

According to the report, western Canadian gas is being replaced by cheaper sources, including from the new Rockies Express Pipeline (REX) and Northeast production led by growth from the Marcellus shale. Also, Marcellus production and Rockies supply are beginning to compete successfully against traditional Gulf Coast supply.

Due to these shifts and other factors, a considerable amount of new pipeline capacity has been added in the Northeast. According to FERC, much of the new pipeline capacity in the area is targeted at improving shale-gas access to markets. Since the beginning of spring 2010, the industry has added 345 million cubic feet (MMcf) of gas per day of new pipeline capacity in the West and 2.5 billion cubic feet (Bcf) in the Gulf and Southeast. Another 3.5 Bcf was added in the West and 5.3 Bcf in the Gulf and Southeast before the end of winter 2011.

FERC’s study concludes that the U.S. “is closer than ever before to being a single natural gas market with congestion limited to a few markets for a few periods during the year, because important expansions and extensions of gas transmission capacity have reduced the volatility of the price of gas delivered to the market.”

Since 2000, FERC has certified 26 major projects, as well as many smaller projects, that collectively brought 16,093 miles of new interstate gas transmission lines and 113.6 Bcf per day of capacity to the market.

In contrast, since 2000, only nine high-voltage (345 kV or greater) interstate transmission lines have been built, totaling 682 miles.

Challenges ahead

Yet, challenges to the booming supply of U.S. gas lie ahead. Rapid development of gas resources over the course of the past several years has exceeded the pace of demand growth, leading to extremely high storage levels in 2009 and 2010 and prompting concerns that working-gas storage may reach capacity this fall.

Storage-capacity additions will help relieve some of the stress, but only 154 Bcf of new capacity was added by the end of 2010 and future storage projects remain speculative, particularly in light of collapsing future-price strips and tightening basis differentials. Currently, working-gas storage capacity is about 4,049 Bcf.

Also, the long-term viability of shale-gas production faces skeptics who want to see longer track records of success in more shale plays before committing to energy strategies that assume an immense role for shale production.

As a final challenge, shale gas is increasingly targeted by environmentalists, citing concerns over water usage, disposal issues, fears about possible groundwater contamination and concerns about the long-term effects of hydraulic fracturing.

Further, according to the EIA, “There is considerable uncertainty about the amounts of recoverable shale gas in both developed and undeveloped areas. Well characteristics and productivity vary widely not only across different plays but within individual plays. Initial production rates can vary by as much as a factor of 10 across a formation, and the productivity of adjacent gas wells can differ by as much as a factor of two or three. Many shale formations, such as the Marcellus shale, are so large that only a small portion of the entire formation has been intensively production-tested. Environmental considerations, particularly in the area of water usage, lend additional uncertainty.”

For now, the EIA estimates that shale gas in existing plays can be profitably produced at prices under $7 per thousand cubic feet. Its projection for prices for 2011, however, is $4.10 per thousand cubic feet, rising to $4.58 in 2012—prices that challenge the economics in some shales.

Imports and exports

The bright spot on the Canadian supply and demand horizon is a significant increase in Canadian natural gas demand, which will partially help offset the otherwise bearish outlook for Canadian gas prices.

The increase in Canada’s domestic consumption is due to its focus on oil-sands developments in Alberta, which use gas to power electricity needed for production, and on power generation, as gas displaces coal-fired utility power plants.

Although Canadian legislators have long dreamed of an Alaskan gas pipeline to be constructed to bring gas from the North Slope to Lower 48 markets via interconnects with Canadian pipelines, competing proposals seem to have stalled as the projects haven’t been able to secure shipper commitments. In its 2010 outlook, the EIA predicted that such a pipeline would be in service by 2023. Yet, in its 2011 outlook, the EIA now says it does not anticipate that to be true. Specifically, an Alaskan gas pipeline doesn’t appear to be financially feasible at this time due to increased capital-cost assumptions and lower gas wellhead prices.

Also, LNG import and export traffic may be affected due to the recent disasters in Japan. On the one hand, Japan may soon seek to increase LNG imports for electric generation to offset the loss of the nuclear power facilities that have been partially or fully destroyed after the recent earthquake and tsunami. On the other hand, short- and midterm power demand may decrease, lessening LNG imports, as industries pause operations to rebuild damaged facilities and as nationals and expatriates alike flee the island nation until infrastructure and a healthy environment can be restored.

Japan’s neighbor was also affected, indicated by recent reports from China stating that it is rethinking its nuclear strategy. The government has put several new nuclear-power facility projects on hold while it reviews safety procedures and building codes. For some time, China has sought to decrease its coal-fired power plants, and may increasingly turn to gas as a safe, clean fuel in the interim.

In the U.S., Japan’s reactor crisis has renewed anxiety about nuclear power and is likely to drive regulators to re-evaluate nuclear plant design and safety, although only two of the nearly three dozen nuclear plants that were proposed in the mid-2000s remain on track to be built, mostly due to high construction costs and low electric prices. Today, 104 commercial reactors supply about 20% of U.S. electricity.

On the U.S. gas-export front, two proposals have been announced to build export capabilities at existing import facilities and to be in service by 2015. Freeport LNG Development LP wants to export up to 1.4 Bcf equivalent per day of LNG from its terminal some 55 miles south of Houston. Cheniere Energy Partners LP proposes to export up to 803 Bcf equivalent per year from its Sabine Pass facility.

The Sabine Pass and Freeport projects have the advantage of being near some of the fastest-growing gas plays on the continent. They are each positioned between the Haynesville, Barnett and Eagle Ford shales. Producers in these plays are facing growing competition in their traditional markets due to the growth of the Marcellus shale in the Northeast, as well as recent pipeline expansions (e.g. Rockies Express).

Yet, the American Public Gas Association (APGA), a trade group representing municipally owned gas distribution utilities, is opposed to plans to export gas produced from the Lower 48 states. APGA has asked FERC to reject LNG export proposals, claiming that such shipments could destabilize U.S. gas prices and threaten energy security.

“FERC owes a duty to the American people to insure that U.S. energy markets function efficiently, not a duty to try to invigorate a global market for natural gas by encouraging imports of domestically produced gas,” APGA wrote to FERC in March.

“Since international markets are often less liquid, less transparent and less competitive, divided by national boundaries, and natural gas commodity prices are often indexed to crude oil, it is far more likely that exporting natural gas from the U.S. would tie domestic commodity prices to international fluctuations rather than tame the international market.”

Also, Industrial Energy Consumers of America has expressed opposition, arguing that exports would raise prices, hurt manufacturing and threaten energy independence.

Canada is considering exporting LNG to Asian markets, and might flip projects that were initially designed as import facilities to become export facilities. Canadian producers are eager to find markets for anticipated shale-gas production from the Horn River Basin region in British Columbia. Apache Canada Ltd. and EOG Resources Canada Inc. want to export LNG to Asia-Pacific markets via an export facility proposed in Kitimat, British Columbia, about 400 miles northeast of Vancouver. Canada’s National Energy Board (NEB) has scheduled a public hearing on June 7 to consider that proposal.

The NEB reports that shale-gas production and potential in North America is “both a challenge and an opportunity” for Canada. In the short-term, U.S. shale production cut the demand for Canadian gas. But, long-term, Canada is confident that it too can produce significant volumes of shale gas for interested world markets.

According to the NEB, “Investment in unconventional natural gas in Canada has increased significantly in recent years. The NEB is starting to assess the new unconventional resources in the country on a play-by-play basis as sufficient data becomes available. The first play to be assessed will be the Horn River Basin shale-gas resource, which will be done in a joint effort with the British Columbia Ministry of Energy & Petroleum Resources.”

Carol Freedenthal, a principal for Jofree Corp. and a long-time energy analyst who has seen industry ups and downs, supply and demand imbalances, and over-hyped trends and rhetoric, says, “No question, the shale gas will change flows and needs for pipeline infrastructure. It already has changed LNG requirements and will continue to impact natural gas pricing.

“There is a social impact, since much of the Marcellus gas is coming from population-rich areas, something different than drilling in the wilderness of Texas or Oklahoma. There are some serious regulatory concerns, or obstacles, as some people will do anything to stop fossil fuels. Still, the potential for shale-gas development is immense, and the industry is just beginning to grasp all of its effects.”