Increasing supply options and stagnant demand spell low gas prices

Fuel switching to gas for electrical generation will try to keep the market afloat as more shale gas and LNG come onstream.

Leonard Parent, Contributing Editor

Our universe of natural gas supply alternatives is growing. When we drill a lot of gas wells, we can usually count on bringing a lot of gas to the wellhead, and 2009 was no exception. Proved gas reserves in the US are estimated to have reached 250 Tcf at year-end 2009, with more to come. The operating word is shale; the adjective, big-time. But shale gas is not without problems that could put the brakes on future growth, such as waste disposal, water quality and other political issues.

North American gas demand is virtually flat, and has been for quite a while. Improved efficiency at the burner tip helped keep demand in check for the last few years, and the economic downturn sealed the deal. Assuming that proved reserves will continue to grow faster than demand, the outlook is for more of the same low wellhead prices.

SUPPLY SIDE

There are two primary ways to view gas supply: potential resources and proved reserves. Potential resources represent what we think is “out there” but can’t quite pin down. The mission of the Potential Gas Committee (PGC) is to try to guess where the potential resources might be and put a number to them. Then there’s proved reserves, the kind of supply that we can and do take to the bank, to borrow money on the strength of the estimate.

At year-end 2008, proved reserves of dry natural gas in the Lower 48 stood at 245 Tcf, up 2.9% from year-end 2007, according to the US Energy Information Administration (EIA). When you add the Potential Gas Committee’s estimate of potential resources, 1,836 Tcf at year-end 2008, with EIA’s proved reserves, we get a total resource estimate of 2,081 Tcf as of year-end 2008. That’s a lot of gas when you compare it with annual production, which has stood between 22 Tcf and 26 Tcf for most of the past two decades. At those rates, there’s enough gas to last the US nearly a century. I estimate that remaining proved reserves stood at about 250 Tcf at year-end 2009.

The PGC’s potential resource estimate at year-end 2008 represents an increase of 542 Tcf over the committee’s previous evaluation at year-end 2006. The committee noted in its report that shale gas accounts for 616 Tcf, or 34% of the 2008 total.

Shale gas. New reserves added in 2007 were 26.6 Tcf, the biggest increase (read shale gas) in the 32 years that EIA has published reserve estimates. The size of the increase was largely due to unprecedented shale gas development, primarily in Texas, Oklahoma, Louisiana and Arkansas. Of the 33 Tcf of proved shale gas reserves at year-end 2008, nearly 29 Tcf are located in these states. Pipeline operators are following close behind the drillers, and pipeline construction in the Southwest is proceeding apace to get the gas from the wellhead into the system. According to an EIA report published in September 2009, pipeline additions and expansions in the Southwest were scheduled to add 19.864 Bcfd of capacity last year, with an additional 20 Bcfd proposed for 2010–2011, Fig. 1.

Fig. 1. Major potential natural gas pipeline expansions for 2009–2011, as of May 2009.

Although pipeline construction in the West is expected to be limited in the next few years, there is still El Paso’s Ruby 680 pipeline, which will move Rockies gas westward to a terminus near Malin, Oregon, where it will interconnect with pipelines moving gas up and down the West Coast. Another proposed westward-bound pipeline, Sunstone—a consortium of Williams LLC, TransCanada and Sempra—would construct 601 mi of 42-in. pipeline from Opal, Wyoming, to an interconnect with an existing pipeline near Stanfield, Oregon.

One of the biggest pipeline projects under development is the Rockies Express Pipeline, which will connect with more than 25 intrastate and interstate pipelines transporting gas from the Gulf and Mid-Continent regions.

About 9 Bcfd of capacity scheduled in the Northeast for 2009–2011 would bring Marcellus Shale gas into the system. The Marcellus, with production in New York, Ohio, Pennsylvania and West Virginia, is a little late getting into the game, but when it ramps up, it will be a major player down the road.

One downside to shale is the problem of water disposal. Hydraulic fracturing of a typical shale gas well involves the disposal of a whole lot of used water containing sand and chemicals. It has to go somewhere. Pennsylvania residents have raised concerns about hydraulic fracturing chemicals getting into their water wells, and New York City’s Mayor Michael Bloomberg wants the legislature to prohibit shale gas development in the city’s watershed area, which is a big piece of southeastern New York. Unless all the parties involved can work out their differences, the projections for Marcellus Shale development may be downsized.

Canada is also getting into the shale act. Shale gas in the Fort Nelson area of northern British Columbia is being developed rapidly, to the extent that an LNG liquefaction plant in British Columbia is being planned to move the gas to a better market overseas.

Apache Canada recently agreed to acquire 51% of the planned export terminal, called Kitimat LNG, as well as 51% of the facility’s capacity. Kitimat received environmental approval from the provincial government in December 2008 and from the federal government in January 2009. The first LNG shipments are expected in 2014. Kitimat would be linked to western Canada’s gas-producing regions via the proposed Pacific Trail Pipeline, a C$1.1 billion, 300-mile project originating at Summit Lake, British Columbia.

CBM. Then there’s coalbed methane reserves, most prominently out west, in Colorado, New Mexico and Wyoming. These three states account for about three-fourths of coalbed methane proved reserves and production in 2008. It was coalbed methane development that got the Rockies Express Pipeline up and running, but recent years have seen production down somewhat, while CBM drilling has fallen off a cliff.

In Wyoming, where the volume of reserves had grown rapidly in recent years and production is still growing, the remaining reserve number was down by about 1 Tcf at year-end 2008 from the previous year, and in all likelihood there was another decrease last year.

Most of Canada’s coalbed methane is in the province of Alberta, which has also seen falling activity in recent years. In 2009, the provincial Energy Resources Conservation Board approved 1,041 new CBM permits, barely half the 2008 total of 2,031 and about one-third of the record 3,106 in 2005.

LNG. On a worldwide basis, LNG is big and getting bigger, with more sources being developed. It could happen that shale would play a key role in that development. More tankers are plying the high seas, and regasification terminal construction is going on big time.

The three pieces of the LNG business—liquefaction, transportation and regasification—are usually operated by different entities. For example, gas on the high seas is a fungible commodity that can be delivered to any one of a number of regas terminals scattered around the Atlantic and Pacific Basins. The US and Canada import LNG at a number of regas plants from Texas to Massachusetts to Nova Scotia, with more to come on the US West Coast. It’s an exciting time for the players moving 3-Tcf shiploads anywhere in the world, able to divert destinations instantaneously when the price is right.

The outlook is for US LNG imports to increase this year to about 600 Bcf. The largest pipeline projects completed in the Northeast during 2008 were LNG-related. Dominion increased pipeline capacity from the Cove Point LNG terminal in southern Maryland to pipeline interconnects in Virginia and Pennsylvania. Suez LNG completed a pipeline project to support its Neptune LNG offshore port, 10 mi offshore Gloucester, Massachusetts. Neptune will have send-out capacity of 750 MMcfd. Building long-haul capacity into the region has proven difficult, in part because of opposition from local communities and environmental organizations.

LNG will continue to build market in the US when players can negotiate a firm long-term contract, such as would support a new power plant.

PRICES

There are a lot of players in the price game: producers, marketers, pipelines and buyers, just to name a few. As gas moves from the first wellhead meter to gathering system meters, pipeline meters, utility meters and, finally, user meters, the challenge is to deal with “unaccounted-for losses” along the way. Producers make deals with buyers via the flexibility of pipeline interconnects, pipelines offer discounts to build capacity utilization, and marketers put deals together on a daily, weekly or monthly basis. Delivered prices are a composite of the charges made by all the players who get involved in each deal. In some locations, it is even possible for individual homeowners to make deals with marketers, who can go back to their suppliers and press for price breaks.

Prices were hammered in 2009 as shale gas came on the market, and there’s little expectation for that situation to change anytime soon. The outlook is for higher prices this winter, dropping back as heating demand falls off. The range of indices we experienced in 2009 will likely be repeated this year, with wellhead prices starting at close to $6/MMBtu at the height of the winter season, then slipping back to the range of $3–$4/MMBtu by mid-summer. There’s a lot of low-priced gas that will come to the wellhead soon from Texas to Pennsylvania.

DEMAND

A look at EIA’s natural gas consumption numbers (Fig. 2) tells us that gas consumption first peaked at 22 Tcf in 1972 and dropped to a low of 16.2 Tcf in 1986, when high prices for new supplies hit the market and users started figuring out how to use less. But then, in the late 1990s, came a recovery to the earlier level, and consumption has been bumping along at 22 Tcf, plus or minus, ever since. Technology has done great things for gas supply, but we tend to forget that technology has also done great things for gas users, mainly by finding ways to improve the thermal efficiency of gas utilization, be it the home gas furnace popular in the colder climes or more efficient gas utilization in combined-cycle electricity generation. Gas for electrical generation is forecast to be the principal growth market for the foreseeable future.

Fig. 2. US gas consumption by year, 1949–2008.

In spite of the fact that real GDP has grown at an average annual rate of 2.5% and the population has grown at 0.9% annually, the EIA’s 2010 outlook projects natural gas consumption to grow at just 0.2% annually, actually at a lesser rate than either coal or liquid petroleum consumption. That works out to a little more than 100 Bcf per year of incremental demand, on the average.

It was not a very good year for gas demand in 2009. If it hadn’t been for electrical generation, it would have been a bummer. Low natural gas prices, relative to coal, contributed substantially to fuel switching for baseload generation. Once the winter heating load demand is behind us, it is expected that low gas prices will result in even more fuel switching to gas. Slow growth is the name of the game.

DOWN THE ROAD

The Alaska pipeline is once again on the back burner, after generating a lot of buzz in 2008. Neither BP and ConocoPhillips’ Denali pipeline nor the rival TransCanada project (which the North Slope’s third major operator, ExxonMobil, joined last year) are expected to see an in-service date before 2023. The thing to keep in mind here is that the Alaska pipeline has been 10 years or more away since the early 1980s.

Gas from hydrates has fallen off the screen since gas from shale has made such a big entry onto the supply stage. Given that the North American gas resource picture is so strong, gas from hydrates is likely to continue as a laboratory experiment for the foreseeable future. The thing that has made hydrates worth investigation is the sheer worldwide magnitude of the resource. If and when natural gas can be produced economically from hydrates, the game will be changed forever, with gas supply far in excess of energy demand.