Gas price stagnation will drag down drilling, production in near term

Leonard Parent, Contributing Editor

A year and a half after they crashed from $13/Mcf highs in mid-2008, it seems that high gas prices are history. In July 2008 The Gas Price Index reported its monthly index to be 1,225. Last month’s index was 402, down to less than a third of the peak of June 2008.

According to the US Energy Information Administration, 10 years ago, the US natural gas proved reserve base had a reserve life of 9.3 years. The reserve life index (RLI) is measured by dividing the volume of proved reserves by the current rate of production. RLI had been dwindling over the years and had become a source of concern among most gas supply people. But by year-end 2009, the most recent measurement date available, the picture had changed considerably. The EIA estimate of technically recoverable shale gas resources more than doubled that year, from 347 Tcf to 827 Tcf, and the RLI was in the neighborhood of 13 years, with expectations of further increases as shale production ramps up in an increasing number of resource plays. Besides the continuous identification of new shale plays, technology has made a big difference, with advances in reservoir characterization, horizontal well construction and multistage fracturing leading the way.

The gas pipeline from Alaska is history, at least for the time being. With gas prices being what they are, the astronomical cost of such a project, and the glut of gas from shales, the last thing the Midwest needs is additional gas supply from Alaska. The proposed pipeline from the McKenzie Delta to serve markets in the provinces, on the other hand, has cleared Canadian regulatory hurdles, and may well be in service by 2020.

Non-hydrocarbon renewables and natural gas are the fastest-growing fuels used to generate electricity, but coal remains the dominant fuel because of the large amount of existing coal-fired capacity. However, gas is playing a growing role due to lower prices and capital construction costs that make it more attractive than coal. EIA forecasts the share of generation from gas to increase from 22% in 2009 to 25% in 2035.

PRICES

The annual average gas wellhead price is expected to remain under $5/Mcf through 2022, as shale gas production offsets declines from more traditional sources. Looking way ahead, the EIA has pegged the Henry Hub spot price at $6.35/Mcf (in 2009 dollars) in 2035.

Henry Hub averaged $4.25/MMBtu during December, an increase of 54 cents from November’s price of $3.71/MMBtu. EIA forecasts higher production during the first half of 2011 compared with the same period last year, implying a moderate decline in spot prices, to a low of $3.73/MMBtu in June. After that, the price is forecast to climb to $4.61 in December, for a 2011 average of $4.02, which is $0.37 lower than the 2010 average. Beyond that, a projected decline in production in 2011 and an increase in gas consumption in 2012 are expected to contribute to strengthening prices late this year and into next.

Region to region, prices may climb or slip from that projection depending on where shale gas output comes online. If you are in the Permian Basin, $4.20/MMBtu is probably a good number for now. Going further west into the Rockies, you might need to knock a nickel off that,
down to $4.15. At the hubs in Texas and Louisiana, $4.40–$4.50 is a good starting point. Along the Gulf Coast, the numbers will be pretty much the same. At the business end of the pipelines in
the Northeast market, the outlook is for prices to be in the $9–$10 range.

SUPPLY

Total marketed gas production increased significantly in 2010, by 4.1%. Declines in production from Alaska and the Gulf of Mexico were offset by a 2.9-Bcfd increase in Lower 48 production (read “shale”). EIA expects average total production to fall by 0.3% in 2011, due to a falling gas-directed rig count brought on by lower prices. Even as the total US rig count surges upward with improving economic conditions, we’re seeing a large-scale shift of rigs from gas-directed drilling (formerly about 80% of the total) toward oil, which may account for the majority of working rigs by the end of this year. EIA is of a mind that gas drilling activity will decline this year because of low prices. But on the flip side, look for higher prices down the road as the shale gale moderates.

Shale gas development has opened a previously unthinkable window of opportunity for gas exports from the US. The notion of converting LNG import terminals to export facilities has caught on. LNG has already been shipped from terminals at Sabine Pass, Louisiana, and Freeport, Texas, to markets across the Pacific.

The drop in gas prices began to impact development plans as operators started late in 2009 to shift investments toward the development of shale gas plays in areas with a higher yield of natural gas liquids and crude oil—such as portions of the Marcellus Shale in southwest Pennsylvania and West Virginia, and the Eagle Ford Shale in South Texas. The addition of higher priced crude oil, condensate and NGL production improves project economics considerably compared with the more “traditional” dry gas shales like the Barnett.

RESERVES

In 2009, total wet gas discoveries of 47.6 Tcf represented the seventh consecutive yearly increase and were by far the highest level of discoveries in the 33 years EIA has published proved reserve estimates. Included in the total proved reserves column is more than 18 Tcf of coalbed methane, down slightly from previous years. A while back, coalbed methane was a bright spot in the outlook for gas resource development, but it’s largely been overtaken by shale gas. Part of the difference is that with shale, technology improvements can make much more of a difference in how much gas can be produced from a single location.

For the Marcellus players, bringing more gas to the wellhead at lower cost and in close proximity to the East Coast market will make it harder for producers of western conventional gas supplies to stay in the game.

Natural gas from shale represented 21% of US reserves in 2009, with the majority coming from six major shale areas, the largest of which is the Barnett in Texas. “Shale gas development drove an 11% increase in US natural gas proved reserves last year, to their highest level since 1971, demonstrating the growing importance of shale gas in meeting both current and projected energy needs,” EIA Administrator Richard Newell said in a press release, adding, “Louisiana, Arkansas, Texas, Oklahoma and Pennsylvania were the leading states in adding new proved reserves of shale gas during 2009.”

Louisiana’s net increase of 9.2 Tcf owed primarily to development of the Haynesville Shale. Both Arkansas (Fayetteville Shale) and Pennsylvania (Marcellus Shale) nearly doubled their reserves. It is worth noting that these increases occurred despite a 32% decline in the wellhead prices used to assess economic viability.

In an early release overview of EIA’s Annual Energy Outlook 2011, the technically recoverable, unproved shale gas resource is 827 Tcf, 480 Tcf larger than in the AEO 2010 reference case, reflecting the utilization, through improved technology, of additional information that has become available from more drilling in new and existing shale plays. This explosion of shale gas resources creates a problem for conventional gas producers that have relied on higher prices to make a go of it.

Recent and projected monthly natural gas Henry Hub spot prices.

STORAGE AND DEMAND

Storage capacity is a vital element in the gas business infrastructure. Working gas capacity in the US has been holding close to 4 Tcf for quite some time, and more capacity appears to be on the way. As of mid-year last year, the Federal Energy Regulatory Commission announced 11 projects (155 Bcf of working gas capacity) awaiting approval, and four more in the pre-filing stage. It’s quite likely that not all projects will come to pass now that we are supply-long. The main issue is location. Given the ongoing development of shale gas in different parts of the country, storage operators will be watching the shale action closely. Location will depend a lot on value, markets and pipelines with available or planned capacity.

Turning to the demand picture, power plant operators will choose natural gas when the price is right. The big question mark for electrical generation is whether the government succeeds in putting a price on greenhouse gas emissions. That outlook looked fairly certain a year ago, with a climate change bill having passed the House of Representatives, but with that bill having failed in the Senate and a new Republican majority in the House, the only way for the Obama administration to achieve emissions control is through the Environmental Protection Agency, a move Congress can be expected to fight tooth and nail.

Overall, industrial demand has already begun to recover from the “Great Recession,” and is expected to continue building from 7.3 Tcf in 2009 to 9.4 Tcf in 2020. You can’t have everything, though. In the near term, EIA expects total gas consumption to decline by 0.9% in 2011, driven largely by a projected drop of 2.7% in residential and commercial consumption. This forecast is partly a result of an estimated 1.3% fewer heating degree-days during the winter months this year compared with last year. Even in the electrical power sector, gas consumption is forecast to fall this year by about 1% because of the return to near-normal summer weather compared with the very warm summer last year; cooling degree-days are forecast to fall by 16%. Only the industrial sector is expected to see consumption rise in 2011, by 1.1%, because of the 1.2% increase in the natural-gas-weighted industrial production index.

CAPACITY

EIA expects gross pipeline imports of 8.6 Bcfd in 2011, a decrease of 4.3%. Canadian gas will become less competitive as new US pipelines and increased Lower 48 production with lower transport costs displace imports.

Projected LNG imports average 1.1 Bcfd for 2011, a 4.7% decrease from 2010. High domestic production, high inventories and low US prices relative to European and Asian markets should continue to discourage LNG imports into North America.