March 20, 2013

While Jim is away on vacation, other members of the TBA Investment Committee will write the market comment.  Today’s comment is from Paul Mecray.

What in the world is happening to natural gas?  A year ago, current contracts were selling at $2.10/mcf.  Today prices are up 88% to $3.95 with the 2014 “strip” now at $4.20.  In the same time frame, West Texas Intermediate (domestic) crude quotations have fallen 10% to $94/bbl.  I will try to explain this stunning recovery by addressing current and projected Lower 48 supply versus demand and conclude with both a three year forecast and even longer-term projections about natural gas markets.

Given prices averaging $3.50/mcf over the past year, very few dry gas projects have been economic, leading to a 57% drop in the domestic gas rig count from a peak of 940 in October 2011 to just 405 today.  Were one to exclude those working in wet gas regions (wells being drilled for natural gas liquids), the collapse would be even worse.  Overall production, however, can lag the rig count by over one year as it takes time to get permits, construct compressor stations and complete gathering pipeline infrastructure.  As a consequence, 2012 dry gas production actually rose 4% to 64.4 Bcfd and current estimates have 2013 down only 1% to 63.7 B.  Why?  Despite far fewer wells being drilled, hookups in such major shale basins as the Haynesville, Fayetteville and Marcellus are coming online, enough to nearly offset the sharp first year decline rates from new wells (averaging 70%).  Looking forward, and assuming relatively few new dry gas project startups, but more previously-drilled fields being completed, it would seem logical to assume flattish production in 2014 and 2015 with the largest variables being weather and new associated gas being extracted from such actively-drilled oilier shales as the Eagle Ford, Wattenberg and Bakken.

It has been a remarkable five years for shale gas.  Representing just 5% of domestic volumes in 2007, this product of sophisticated directional drilling and hydraulic fracturing is now about 32% of supply with that percentage rising rapidly as traditional gas well drilling has almost disappeared.

The winter, which ended today, has been closer to normal than the past two years.  As a result, I expect storage to end March near 1.9 Tcf, well below the 2.5 T a year ago.  This can be attributed to much more than heating degree days, however, with the most positive year-on-year variable being greater consumption by electric utilities at the expense of coal.  That market represented 39% of 2012 consumption and was up 20% from the prior year.  By contrast, industrial (30% of demand) rose only 2%; residential (18% of demand) fell 12% due to fewer heating and cooling degree days; and commercial (13% of demand) was down 8%. 

Projecting future gas prices requires numerous assumptions beyond weather and storage.  It also involves geological analysis (which shales will be productive), operating cost projections, availability of transportation (pipeline construction), local environmental acceptance or rejection, and an industry tendency to act with greater uniformity than facts often support.  By this I mean a consensus view that “we can’t make money drilling for less than $4.50/mcf at the wellhead.”  This may be true on a national average but it varies widely from under $3.50 in parts of Susquehanna County PA to over $5.50 in the Louisiana Haynesville.  Likewise, the presence or absence of high value NGLs (ethane, propane and butane) can make wet gas shales in Southwestern PA economic at even $3.00/mcf.

As noted previously, the largest short-term variable for gas demand is the capture of electric generation markets from bituminous coal.  Compared to two years ago, it is estimated that 30MM tons of coal fired demand has been shut down or switched (adding 1.5 Bcfd of natural gas consumption) with another 1.2 Bcfd from new plant construction.  Yet another 0.5 B comes from nuclear plant shutdowns.  Going forward, I expect little to no new coal fired capacity additions but more markets captured from coal as stricter EPA regulations make it economic to shut down older plants rather than meet costly new emission standards.  The rate at which natural gas replaces coal, however, will still be a factor of relative costs with most observers believing $4.50/mcf makes the cost of coal vs. gas relatively comparable.  There is considerable price sensitivity here.  Industry experts believe there will be another 2 Bcfd converted this year at $3.75/mcf but much more were prices to average $3.25 or less.

Longer term, one should expect an acceleration in natural gas demand, not just as utility fuel, but also meaningfully in both industrial and residential markets.  Given prices well below those in other industrialized markets, energy intensive industries have considerable incentive to expand in the United States, actually closing facilities in the Far East, Caribbean, Europe and Middle East to relocate back to their domestic markets.  While difficult to quantify, this should create a possible 5% annual growth in demand for the sector that represents 30% of total US consumption.  One only needs to talk to East Coast homeowners to also see a major incentive to switch from heating oil to natural gas.  The average savings of up to 50% makes this a true “no brainer” and will create renewed growth in parts of the US for the 18% of gas serving residential markets.

So what might be incremental demand for natural gas in the next five years? From a base of 64 Bcfd, and assuming 2 Bcfd new LNG exports, one can envision demand of 80 B by 2017, for growth of about 4.3%/year.

 Looking even further down the road, one can identify even more significant new markets for natural gas.  The aforementioned demand for LNG may be the largest but, here, US gas must compete on the world stage with exports from Australia, Qatar, East Africa, Israel and Canada.  While there is near certainty that two export liquefaction plants will be authorized on the US Gulf Coast, my analysis suggests that few, if any, others will be approved.  Transportation, however, will become a potentially larger market in the years after 2020.  It already makes sense to convert small truck or bus fleets from either gasoline or diesel power to compressed natural gas.  The lower fuel cost implies that any fleet that “comes home” at night (where refueling is available) should consider conversion.  We have a perfect example here in Lower Merion Township PA where the whole school bus fleet is run on CNG.  Likewise, several city taxi fleets, UPS and FedEx are at various stages of testing conversions.

Yet another new market may be railroad locomotives.  In a presentation last week at an industry conference, Burlington Northern Santa Fe announced a pilot project to test locomotives using LNG, not CNG!  In cooperation with both Caterpillar and General Electric, locomotives are being converted from diesel and will be tested in the coming year.  Canadian National has also confirmed such a study and believes a decision could be reached as early as next year on relative economics.

Beyond LNG as an export fuel, CNG for truck/bus fleets and LNG for locomotives, the next great market may be heavy over-the-road trucks.  I attended a debate on the merits of such conversion last month with participants clearly in disagreement about the relative merits.  It is not yet clear whether a CNG truck will have as much power as those using diesel in mountain driving and, of course, there remains the need to have natural gas fueling stations nationwide.  Nonetheless, I would not rule out major conversions in the coming decade.

To summarize, we have a near revolution occurring in the natural gas industry.  Supplies will be plentiful to meet any projected demand in the next five to ten years but, at current marginal costs, it will require a national average of at least $4.50/mcf to produce a rate of investment return comparable to drilling oily shales.  Likewise, that is about where coal would remain competitive, in effect capping prices in that same range.  The implications for many US industries are very positive, however, with particular beneficiaries being oilfield services, energy-intensive manufacturing, electric utilities, petrochemical manufacturing, homeowners, and transportation – just to name a few.

Paul M. Mecray 610-260-2227

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