The latest natural gas EIA Weekly Storage Report reported a draw of 18 Bcf for the week ended Nov. 9, 2012. Based on the weather forecasts, there won't be any more injections into storage this fall. Storage peaked with last week's report at 3,929 Bcf, which is well below current storage capacity estimated by the EIA to be over 4.2 Bcf. As noted in the article "Natural Gas Storage Fears Not Supported By Data," by the time the summer ended there was little chance of running out of storage for natural gas even if all coal to gas switching ended in September. Calls for natural gas prices to fall to zero have proven false, and investors in natural gas ETFs like the United States Natural Gas Fund (UNG) and the United States 12-Month Natural Gas Fund (UNL) have benefited from holding those positions after the pricing collapse last spring. The question is: Where are natural gas prices headed from here?
The biggest determinant of natural gas usage is always weather. Last winter's fourth-warmest temperature on record, combined with excessive drilling because of past hedges and efforts to hold acreage by production, is what created the huge storage glut. But now, according to the EIA, storage is only 71 Bcf higher than last year and within 100 Bcf of the last three mid-November reports. This means the storage glut is basically gone and natural gas prices will be driven by weather and 2013 production. So far this winter looks like it is starting out a little cooler than normal, but it is still too early to know what kind of winter we will have. However, we are getting a much clearer picture of 2013 production based on company third-quarter operation reports.
The nation's largest lower-48 U.S. natural gas producer Exxon (XOM) has already moved its rigs out of the dry natural gas fields and its third-quarter natural gas production declined 4% sequentially from the second quarter. Chesapeake (CHK), the second-largest producer but by far the largest driller due to all of its joint venture partners, announced that third-quarter natural gas production grew over 9% sequentially in the third quarter from the second quarter. However, it also announced natural gas production peaked in the third quarter and is now in decline. Chesapeake has dropped from 81 rigs drilling for dry natural gas in January to nine rigs drilling for natural gas now. Five of its rigs are in the Marcellus, two in the Barnett, and two in the Haynesville. For those expecting the Marcellus to grow exponentially, it should be noted Chesapeake is the largest lease holder in the Marcellus. Chesapeake announced it expects total company-wide natural gas production to decline 7% overall in 2013 vs. 2012.
EOG Resources (EOG) announced its capital budget for dry natural gas would fall from $700 million in 2012 to $100 million in 2013, and that its total natural gas production would decline by 10% in 2013 vs. 2012. Encana (ECA), the third-largest natural gas producer, announced it anticipates 2013 natural gas production will be flat with 2012. Top 10 producers Conoco Phillips (COP), BP (BP), and Chevron (CVX) have also shifted to liquids drilling just like Exxon and all saw their natural gas production in the third quarter decline from year-ago levels. The fourth-largest producer, Anadarko Petroleum (APC), said during its third-quarter conference call that outside of the Marcellus, it would need to see natural gas prices north of $5 per mcf to commit capital back to the other dry natural gas fields.
The bottom line is that production is set to drop in 2013 vs. 2012 -- but by how much? Probably the best rough initial estimate would be to assume the overall market will mirror its largest producer Chesapeake's decline curve of approximately 7% with some declining more and some less. 2012 total natural gas production will probably come in between 24 Tcf and 25 Tcf. A 7% total decline would mean a production drop of 1.7 Tcf of natural gas.
Last winter saw a storage draw of only 1.3 Tcf of natural gas creating the storage glut. But the previous four winters saw an average storage draw of 2.2 Tcf. Assuming a more normal winter draw of 2.2 Tcf, natural gas storage would be expected to drop over the winter down to 1.7 Tcf. Then, assuming the normal 2.2 Tcf resupply of storage over the spring, summer, and fall, natural gas would return to the 3.8 Tcf to 3.9 Tcf storage range. However, if supply drops by 1.7 Tcf, then storage could end up in the low 2 Tcf range, creating a potential storage crisis for the 2013-14 winter whereby we could run out of enough natural gas in storage to meet heating demand. Obviously this is unlikely to happen because the natural gas market would adjust to encourage supply just like it adjusted to discourage supply this year. But it takes time to permit a well, secure a rig, and then secure a completion rig to produce a natural gas well. Any movement of rigs back to the dry natural gas fields would have to occur by spring to have any kind of meaningful impact on storage for the fall of 2013. In this scenario, natural gas prices would have to trade above $5 per mcf before the end of winter to encourage production from companies like Anadarko Petroleum.
If this winter is a cold one, then a return to natural gas drilling this spring may not be enough to avert a storage disaster in the fall. In this case, prices for natural gas would have to rise high enough to encourage power companies and manufacturers that have the capacity to generate power from either oil or natural gas to switch to oil. The traditional energy conversion ratio is 5.8 mcf of natural gas to one barrel of oil. For a user of natural gas to prefer oil, then natural gas has to be more expensive per mcf than 5.8 times a barrel of oil. WTI is $85, but Brent oil is $107. Many oil users on the East Coast and West Coast do not have access to oil priced at WTI. In this case, based on current oil prices, natural gas would have to trade above $18.50 per mcf to encourage fuel switching out of natural gas to oil. For those who think this cannot happen, natural gas traded below $2 this spring to encourage not only coal to gas switching, but also to encourage natural gas producers to cap wells. This is the scenario described in the article "A Colder-Than-Normal Winter Could Throw Natural Gas Into Backwardation."
The last time natural gas prices rose to levels to encourage a switch to oil was after Hurricane Katrina. The colder this winter is and the longer natural gas prices stay under $5 per mcf, then the higher the probability that the natural gas market will have to drive gas to oil switching to prevent a storage disaster ahead of the 2013 winter. This would be very bullish for natural gas producers like Ultra Petroleum (UPL), Crimson Exploration (CXPO), Sandridge (SD), and Devon Energy (DVN).