The 72 Bcf natural gas storage injection reported yesterday by the U.S. Energy Information Administration (EIA) provides the final confirmation that the injection season this year is essentially a non-event. The report came in 5 Bcf below the 77 Bcf consensus (0.7 Bcf/d bullish surprise), and largely offset the three in a row bearish surprises of the preceding weeks. Assuming four "big" injection weeks remaining in this season, an exit storage level above 4.0 Tcf looks increasingly improbable (4.0 Tcf would be approximately in line with last year once storage capacity additions are taken into account). In a separate report released the day before yesterday, EIA estimates the end of October storage level at 3.903 Tcf.
Storage at the end of 2013 injection season is the next structural boundary condition for natural gas. Therefore it is time to turn full attention to the medium-term supply and demand fundamentals.
Natural Gas 2013 Outlook
At this point, the outlook for 2013 appears almost as uneventful as the 2012 injection season. The supply and demand seem to have come in an equilibrium which may be here to stay for some time, with little growth or decline on both sides of the equation. Moreover, current price level appears to reflect this equilibrium, and significant deviations, while possible, are likely to be relatively short-lived.
The declining gas-directed rig count has been the cornerstone of the thesis that the ensuing production roll-over would cause a sharp rally in natural gas prices. The anticipated supply response to the curtailed drilling still remains … well, anticipated. Signs of a production decline have so far been missing from both the EIA 914 data (latest available is July) and weekly storage injection statistics, and likely for a good reason. In my earlier notes, I have argued that, contrary to common belief, the current gas rig count (437 as reported by Baker Hughes last Friday) is in fact fairly close to what is needed to maintain the U.S. natural gas production "flattish" during the next 12 months (taking into consideration the vast well backlog and infrastructure-restricted production). While shallow declines in the U.S. production may start showing in the data in the next few months (production reflects the rig count with a one-to-three month lag), the ample storage level at the beginning of the winter season leaves plenty of time for operators to take corrective action by adding rigs throughout the year so that storage is full again next November. The threat to the existing supply/demand balance from the production declines seems overstated.
On the other hand, there appears to be no threat from a production increase either. While the recent rally in the futures prices makes natural gas drilling within sweet spots profitable again, any increase in production in response to the improving drilling economics will take at least two quarters to materialize. Indeed, a typical shale well, if spud today, would likely reach peak initial production in January. With both the January contract and 2013 average trading above $4 (graph at the end of this note), operators in many cases have the ability to lock in, through hedging, returns on incremental dry gas wells above their cost of capital. However, with very few exceptions (such as the infrastructure constrained Marcellus), those returns are not compelling enough to cause a rig hiring stampede. It is very likely that companies will defer making rig commitments until after 2013 budgets are finalized (November-December) and additional hedges have been layered in, even if gas prices continued to move up in the meantime. As a result, the lead time to a production increase (time to authorize capital spending, hire rigs, mobilize the supply chain, drill, complete, connect and "clean out" wells) will likely exceed six months.
On the demand side, weather and power use are the only two significant variables. EIA is projecting a flat year-on-year demand for 2013 assuming weather pattern returning to "normal."
On the price side, a significant ($0.50-$1.00 per MMBtu) further upward move in the futures curve will very likely cause an avalanche of hedging activity by operators and increase the certainty of a strong ramp-up in drilling activity several months from now. In addition to creating price resistance from the high-volume selling as well as reduced power demand, this would create a concern regarding a new wave of over-drilling. These factors should help put a cap on the gas price. (The important argument I am relying upon here is that at $5/MMBtu Nymex operators will see very compelling returns from sweet spots in multiple dry and wet gas plays.)
On the other hand, a significant drop in gas prices from current levels ($0.50-$1.00 per MMBtu) will likely be perceived by the market, which appears sensitized to the imminent production decline, as a dangerous disincentive to the drilling activity that would delay the needed ramp up in the rig count and, because of the lead times discussed above, increase the risk of next year's storage "deficit" (i.e., exit at below 4 Tcf). While such concern may ultimately prove without merit, a price decline is nonetheless unlikely until the prevalent perception that production is about to roll over changes.
In summary, there is no empirical evidence so far that supply is falling behind demand due to the reduced rig count. Arguably, current level of drilling activity, in combination with gradual additions to the active rigs throughout the next year, should allow the natural gas industry to both meet demand and fully refill storage. Fundamentally, it appears that no additional price stimulus or tightening is required at the moment, from the current $4 level. Both the pace of drilling activity and price of natural gas appear to be within the "Goldilocks" (not too high, not too low) range, and may remain there as we go into 2013.
EIA Short-Term Energy Forecast
The U.S. Energy Information Administration yesterday published its updated short-term energy forecast. The EIA projects total natural gas consumption to remain essentially flat in 2013, with declines in the electric generation demand (-10.4%) offset by increases in residential (+11.5%), commercial (+10.3%), and industrial consumption. 2013 consumption in the power sector next year is still expected to be about 1.9 Bcf/d higher than 2011 levels.
EIA expects some small declines in production in the coming months, related to recent drops in the rig count. However, EIA forecasts that total marketed production will still grow by 0.4 Bcf/d in 2013 (after increasing by 2.6 Bcf/d in 2012), as the reduction in drilling activity is offset by growth in liquids‐rich from areas such as the Eagle Ford and wet areas of the Marcellus Shale, and associated gas from the growth in domestic crude oil production.
EIA expects little change in pipeline gross imports from Canada and gross exports to Mexico in 2013. Liquefied natural gas (LNG) imports are expected to fall by about one‐half in 2012 from the year before. EIA expects that an average of about 0.5 Bcf/d will arrive in the United States (mainly at the Elba Island terminal in Georgia and the Everett terminal in New England) both in 2012 and 2013, either to fulfill long‐term contract obligations or to take advantage of temporarily high local prices due to cold snaps and disruptions.
On the price side, EIA expects the Henry Hub natural gas price will average $2.71 per MMBtu in 2012 and $3.35 per MMBtu in 2013. EIA noted that natural gas futures prices for January 2013 delivery (for the five‐day period ending October 4, 2012) averaged $3.84 per MMBtu. Current options and futures prices imply that market participants place the lower and upper bounds for the 95‐percent confidence interval for January 2013 contracts at $2.77 per MMBtu and $5.31 per MMBtu, respectively. At this time last year, the January 2012 natural gas futures contract averaged $4.10 per MMBtu and the corresponding lower and upper limits of the 95‐percent confidence interval were $3.10 per MMBtu and $5.40 per MMBtu.
Storage Statistics Summary - Week of October 4, 2012
Natural gas storage surplus relative to last year shrank by another 36 Bcf last week, according to the EIA. The pace of injection into storage remains lower than during the same period last year (although the differential has been contracting). Using a rolling three-week average to reduce the impact of short-term fluctuations, the weekly year-on-year differential in the injection rate was 27 Bcf/week or 3.9 Bcf/d.
According to EIA, as of October 5, working gas in storage was 3,725 Bcf. Stocks are 236 Bcf higher than last year at this time, and 269 Bcf above the five-year average of 3,456 Bcf. The surplus relative to the five-year average was 67 Bcf in the East Region, 42 Bcf in the West Region, and 160 Bcf in the Producing Region.
The futures curve continues to provide economic incentive to operators to drill in most productive dry gas sweet spots, whereas "Tier II" areas are, at best, marginal from a return perspective.