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Time to Pay the Fiddler; Crude Storage Issues to Support Natural Gas Prices

March 18, 2015 | By Charles Nevle

Storage for crude oil has been getting a lot of press recently and for good reason. The reason oil prices have been in a virtual free fall over the past several months is because of the mismatch between crude oil supply and crude oil demand. Namely, the U.S. on a net basis is producing and still importing more product than our current demand structure can support. Since the opportunity to move U.S. born crude in the form of exports are still not allowed, the sole balancing item for an oversupplied and somewhat politically captive market is storage. The problem is that even though crude prices have dropped dramatically which have ultimately rippled across board room tables and into the drilling services sector, the crude market continues to be worse off now and not better from an over-supply perspective.

In a nutshell, crude oil production has unrelentingly continued to rise as evidenced by the recent EIA data (3/11/15) which showed U.S. crude production up to 9.336 million barrels per day (mb/d). Refinery demand has decreased, imports have backed off only slightly which has all resulted in crude oil inventories rising to an unprecedented level. The chart below shows these dynamics over the period from August 2014 to March 2015. Late last summer, crude was still priced at over $100/bbl while this spring crude has been looking to retest new lows.

Barrels per Day

This would all be academic except for the fact that domestic storage capacity is finite. The market conceivably cannot continue to infinitely build crude inventory, though what those ultimate levels actually are is still somewhat debatable. What is not up for consideration is that we really are aggressively adding to inventories each week and operators are finding that less and less open capacity remains available. Many in the market are of the belief that a reckoning is at hand where capacity limits will now fundamentally begin to force prices substantially lower requiring the market to balance in some shape, form or fashion.

We have had high crude inventory issues in the past. Between 2011 and the summer of 2013 as crude production growth was getting into full swing, we saw Cushing crude inventory rise to levels where we are currently. The implicit financial implications that followed that event resulted in WTI discounting substantially from Brent. However, the specific difference that separates the two periods is that during the earlier point in time there was still significant storage capacity elsewhere in the U.S. but the problem was getting crude from Cushing to those other storage regions, primarily in the Gulf Coast. As you might expect this caused the spread between WTI and Gulf Coast crude arbitrage markers to widen further which resulted in market forces correcting this element by adding new transport capacity between the regions came online crude rushed from Cushing to the Gulf Coast and the spread collapsed.

The difference this time around is that not only are inventories high at Cushing, they are high throughout the U.S. and no new pipeline is going to make a significant difference. Well, that is unless you consider allowing a pipeline of crude to the rest of the world via the legalization of exports. Also, as you might expect, the price spreads between WTI and the Gulf Coast are much tamer now than back in the 2011-2013 time frame.

Cushing Barrels


LLS-WTI Spread

Currently two facts are evident. The U.S. cannot and therefore will not be exporting crude anytime soon. Also, of the remaining imports still coming to U.S. ports, they consist of the heavier crude types necessary to satisfy specific refinery demand and therefore are unable to be substituted in the near term by the abundant growing light crude volumes in the U.S. That leaves two mechanisms which individually or a combination of the two are left to balance the market during this window and they are; “Increasing Refinery Runs” and/or “Reducing Domestic Production”. However, the ability to increase refinery runs before April is limited due to the abundance of scheduled refinery downtime resulting from regular seasonal maintenance. So, what this of course leaves to balance the market is production.

In a scenario where storage limitations did force crude oil production to ramp down quickly one question that arises, given the abundance of associated gas production from many of the shale oil plays, is what would happen to natural gas production associated with these same U.S. shale oil plays? In other words, if say crude oil production had to quickly ramp how much natural gas production would that take off the market?

To answer the question of how much associated gas would be impacted by a rapid pull back in crude oil production first takes understanding where the oil production would likely decline. There are a number of factors that would come into play in such a situation including break even economics at the wellhead, potential detrimental impacts to wells of shutting in, regional storage considerations, along of course with a whole host of issues specific to individual producers. Based on our high level analysis, the areas most likely to experience production pull backs are the Bakken and Eagle Ford.

As of the end of 2014 we estimate that the Eagle Ford play produced 1.4 mb/d while the Bakken produced approximately 1.1 mb/d, so collectively 2.5 mb/d for both regions, or approximately 27% of lower 48 U.S. crude production. From a natural gas perspective, we estimate Eagle Ford produced 5.4 Bcf/d and Bakken 1.4 Bcf/d as of the end of 2014 collectively representing 9.4% of lower 48 dry gas production.

Using the above information we can compute a rough estimate for the natural gas volume associated with each million barrels of oil production in each region. For the Eagle Ford this turns out to be 3.9 Bcf/d for each mb/d of oil and in the Bakken 1.3 Bcf/d for each mb/d of oil.

What this tells gives us is a good estimate to use when understanding what the implications for a quick pullback in oil production could mean for the natural gas market. So, if one expects that 0.5 mb/d will need to be taken off the market and this will be split evenly between Eagle Ford and Bakken, our estimation of gas volumes that would be taken off as a result is just under 1 Bcf/d of gas from Eagle Ford and 0.3 Bcf/d from Bakken.

Finally, one would expect that if 1.3 Bcf/d of gas production were removed from the market that natural gas prices would experience upward pressure, especially in this case in the regions of South Texas and perhaps the MidCon.

Aside from the specific, and arguably rough estimates for the numerical impact on gas production of an inventory imposed steep crude oil price reduction and resulting production curtailment, it is our perspective that this would very likely lead to lower gas production resulting in stronger natural gas prices.

In the meantime, we will be watching the crude inventory numbers along with the myriad of other data points that impact this market and doing our best to tell you our perspective on what these numbers could mean to you.

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